WEC Energy (WEC) 10-Q 2 Nov 18 2018 Q3 Quarterly report Financial data

DOCUMENT AND ENTITY INFORMATION

DOCUMENT AND ENTITY INFORMATION	9 Months Ended
	Sep. 30, 2018shares
Document Entity Information [Abstract]
Entity registrant name	WEC Energy Group, Inc.
Entity central index key	783,325
Current fiscal year end date	--12-31
Entity filer category	Large Accelerated Filer
Document type	10-Q
Document period end date	Sep. 30, 2018
Document fiscal year focus	2,018
Document fiscal period focus	Q3
Amendment flag	false
Entity common stock, shares outstanding	315,526,051
Emerging growth company	false
Small company	false

CONDENSED CONSOLIDATED INCOME S

CONDENSED CONSOLIDATED INCOME STATEMENTS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Statement [Abstract]
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	48.3	149.4	147.9
Total operating expenses	1,341	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	49.2
Interest expense	112	103.8	327.2	310.4
Other expense	(52.2)	(46.8)	(167)	(138.3)
Income before income taxes	250.5	345.4	1,011.6	1,230.8
Income tax expense	17	129.7	156.4	458.8
Net income	233.5	215.7	855.2	772
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 (in dollars per share)	$ 0.74	$ 0.68	$ 2.71	$ 2.44
Diluted (in dollars per share)	$ 0.74	$ 0.68	$ 2.70	$ 2.43
Weighted average common shares outstanding
Basic (in shares)	315.5	315.6	315.5	315.6
Diluted (in shares)	316.9	317.5	316.9	317.5
Dividends per share of common stock (in dollars per share)	$ 0.5525	$ 0.5200	$ 1.6575	$ 1.5600

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Other Comprehensive Income [Abstract]
Net income	$ 233.5	$ 215.7	$ 855.2	$ 772
Derivatives accounted for as cash flow hedges
Net derivative gains, net of tax	0.3	0	0.3	0
Reclassification of net gains to net income, net of tax	(0.4)	(0.4)	(1)	(1)
Cash flow hedges, net	(0.1)	(0.4)	(0.7)	(1)
Defined benefit plans
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	0	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

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
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
Prepayments	137.6	210
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
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	619.9
Long-term assets	30,722.7	29,377
Total assets	32,562.4	31,590.5
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	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

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Accounts receivable and accrued unbilled revenues, reserves	$ 153.7	$ 143.2
Property, plant, and equipment, accumulated depreciation	$ 8,589.3	$ 8,618.5
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	325,000,000	325,000,000
Common stock, shares outstanding	315,526,051	315,574,624

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Operating Activities
Net income	$ 855.2	$ 772
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)	(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)	0
Acquisition of Forward Wind Energy Center	(77.1)	0
Acquisition of Bluewater	0	(226)
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)	(1,565.8)
Financing Activities
Exercise of stock options	13.9	25.6
Purchase of common stock	(42)	(60.6)
Dividends paid on common stock	(523)	(492.4)
Issuance of long-term debt	600	210
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

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Statement of Cash Flows [Abstract]
Restricted cash acquired	$ 4.5	$ 0

CONDENSED CONSOLIDATED STATEM_4

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions	Total	Total Common Shareholders' Equity	Common Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income	Preferred Stock of Subsidiary	Noncontrolling Interest
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative effect adjustment from ASU 2016-09	$ 15.7	$ 15.7	$ 0	$ 0	$ 15.7	$ 0	$ 0	$ 0
Balance at Dec. 31, 2016	8,960.2	8,929.8	3.2	4,309.8	4,613.9	2.9	30.4	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributed to common shareholders	771.1	771.1	0	0	771.1	0	0	0
Other comprehensive loss	(0.5)	(0.5)	0	0	0	(0.5)	0	0
Common stock dividends	(492.4)	(492.4)	0	0	(492.4)	0	0	0
Exercise of stock options	25.6	25.6	0	25.6	0	0	0	0
Purchase of common stock	(60.6)	(60.6)	0	(60.6)	0	0	0	0
Stock-based compensation and other	6.6	6.6	0	6.6	0	0	0	0
Balance at Sep. 30, 2017	9,225.7	9,195.3	3.2	4,281.4	4,908.3	2.4	30.4	0
Balance at Dec. 31, 2017	9,491.8	9,461.4	3.2	4,278.5	5,176.8	2.9	30.4	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributed to common shareholders	854.3	854.3	0	0	854.3	0	0	0
Other comprehensive loss	(0.5)	(0.5)	0	0	0	(0.5)	0	0
Common stock dividends	(523)	(523)	0	0	(523)	0	0	0
Exercise of stock options	13.9	13.9	0	13.9	0	0	0	0
Purchase of common stock	(42)	(42)	0	(42)	0	0	0	0
Acquisition of a noncontrolling interest in subsidiary	37	0	0	0	0	0	0	37
Stock-based compensation and other	11.2	11.2	0	11.2	0	0	0	0
Balance at Sep. 30, 2018	$ 9,842.7	$ 9,775.3	$ 3.2	$ 4,261.6	$ 5,508.1	$ 2.4	$ 30.4	$ 37

GENERAL INFORMATION

GENERAL INFORMATION	9 Months Ended
	Sep. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
GENERAL INFORMATION	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.

ACQUISITIONS

ACQUISITIONS	9 Months Ended
	Sep. 30, 2018
Business Combinations [Abstract]
ACQUISITION	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. 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

DISPOSITION

DISPOSITION	9 Months Ended
	Sep. 30, 2018
Discontinued Operations and Disposal Groups [Abstract]
DISPOSITION	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 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.

OPERATING REVENUES

OPERATING REVENUES	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
OPERATING REVENUES	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. 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 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. 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. 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. 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.

REGULATORY ASSETS AND LIABILITI

REGULATORY ASSETS AND LIABILITIES	9 Months Ended
	Sep. 30, 2018
Regulatory Assets and Liabilities Disclosure [Abstract]
REGULATORY ASSETS AND LIABILITIES	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 . 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 .

PROPERTY, PLANT, AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT	9 Months Ended
	Sep. 30, 2018
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT, AND EQUIPMENT	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 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 .

COMMON EQUITY

COMMON EQUITY	9 Months Ended
	Sep. 30, 2018
Equity [Abstract]
COMMON EQUITY	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.

SHORT-TERM DEBT AND LINES OF CR

SHORT-TERM DEBT AND LINES OF CREDIT	9 Months Ended
	Sep. 30, 2018
Short-term Debt [Abstract]
SHORT-TERM DEBT AND LINES OF CREDIT	SHORT-TERM DEBT AND LINES OF CREDIT The following table shows our short-term borrowings and their corresponding weighted-average interest rates: (in millions, except percentages) 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

LONG TERM DEBT

LONG TERM DEBT	9 Months Ended
	Sep. 30, 2018
Long-term Debt, Unclassified [Abstract]
Long Term Debt	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. 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.

MATERIALS, SUPPLIES, AND INVENT

MATERIALS, SUPPLIES, AND INVENTORIES	9 Months Ended
	Sep. 30, 2018
Inventory Disclosure [Abstract]
MATERIALS, SUPPLIES, AND INVENTORIES	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.

INCOME TAXES

INCOME TAXES	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
INCOME TAXES	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 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.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point 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 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.

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS We use derivatives as part of our risk management program to manage the risks associated with the price volatility of 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. 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 . 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.

GUARANTEES

GUARANTEES	9 Months Ended
	Sep. 30, 2018
Guarantees [Abstract]
GUARANTEES	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.

EMPLOYEE BENEFITS

EMPLOYEE BENEFITS	9 Months Ended
	Sep. 30, 2018
Retirement Benefits [Abstract]
EMPLOYEE BENEFITS	EMPLOYEE BENEFITS The following tables show the components of net periodic pension and OPEB costs for our benefit plans. Pension Costs Three Months Ended 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. 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.

GOODWILL

GOODWILL	9 Months Ended
	Sep. 30, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL	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.

INVESTMENT IN TRANSMISSION AFFI

INVESTMENT IN TRANSMISSION AFFILIATES	9 Months Ended
	Sep. 30, 2018
Equity Method Investments and Joint Ventures [Abstract]
INVESTMENT IN TRANSMISSION AFFILIATES	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 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 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

SEGMENT INFORMATION

SEGMENT INFORMATION	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
SEGMENT INFORMATION	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. 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. 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.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	9 Months Ended
	Sep. 30, 2018
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities. We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance. 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 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.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES We and our subsidiaries have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental matters, and enforcement and litigation matters. Unconditional Purchase Obligations Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of 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. 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 CO 2 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 CO 2 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 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 requiremen ts. 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 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 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.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	9 Months Ended
	Sep. 30, 2018
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	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.

REGULATORY ENVIRONMENT

REGULATORY ENVIRONMENT	9 Months Ended
	Sep. 30, 2018
Regulated Operations [Abstract]
REGULATORY ENVIRONMENT	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. 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. 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. 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.

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS	9 Months Ended
	Sep. 30, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
NEW ACCOUNTING PRONOUNCEMENTS	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. 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.

GENERAL INFORMATION (Policies)

GENERAL INFORMATION (Policies)	9 Months Ended
	Sep. 30, 2018
Disaggregation of Operating Revenues
Revenue Recognition	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.
Revenue Recognition for Alternative Revenue Programs	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.
Accounting Policies [Abstract]
Consolidation	As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, 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.
Basis of Accounting	We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 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.
Fair Value Measurement	Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point 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.
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. 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.
Distributions received from equity method investments	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.
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. 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.
Electric
Disaggregation of Operating Revenues
Revenue Recognition	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.
Natural gas
Disaggregation of Operating Revenues
Revenue Recognition	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.
Other non-utility revenues
Disaggregation of Operating Revenues
Revenue Recognition	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.

ACQUISITIONS (Tables)

ACQUISITIONS (Tables)	9 Months Ended
	Sep. 30, 2018
Bishop Hill III Wind Energy Center
Business Acquisition [Line Items]
Allocation of purchase price	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.
Forward Wind Energy Center Acquisition
Business Acquisition [Line Items]
Allocation of purchase price	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
Bluewater
Business Acquisition [Line Items]
Allocation of purchase price	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

OPERATING REVENUES (Tables)

OPERATING REVENUES (Tables)	9 Months Ended
	Sep. 30, 2018
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	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. 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
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	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
Revenues from contracts with customers | Natural gas
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	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.
Revenues from contracts with customers | Other non-utility revenues
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	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
Other operating revenues
Disaggregation of Operating Revenues
Operating revenues disaggregated by revenue source	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.

REGULATORY ASSETS AND LIABILI_2

REGULATORY ASSETS AND LIABILITIES (Tables)	9 Months Ended
	Sep. 30, 2018
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of regulatory assets	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 .
Schedule of regulatory liabilities	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 .

PROPERTY, PLANT, AND EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT (Tables)	9 Months Ended
	Sep. 30, 2018
Restructuring cost and reserve
Schedule of changes to our severance liability	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

COMMON EQUITY (Tables)

COMMON EQUITY (Tables)	9 Months Ended
	Sep. 30, 2018
Equity [Abstract]
Schedule of stock-based compensation awards granted	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.

SHORT-TERM DEBT AND LINES OF _2

SHORT-TERM DEBT AND LINES OF CREDIT (Tables)	9 Months Ended
	Sep. 30, 2018
Short-term Debt [Abstract]
Schedule of short-term borrowings and weighted-average interest rates	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 %
Schedule of revolving credit facilities and remaining available capacity	The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including 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

MATERIALS, SUPPLIES, AND INVE_2

MATERIALS, SUPPLIES, AND INVENTORIES (Tables)	9 Months Ended
	Sep. 30, 2018
Inventory Disclosure [Abstract]
Schedule of Inventory	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

INCOME TAXES (Tables)

INCOME TAXES (Tables)	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation	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 %

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Fair value of assets and liabilities measured on a recurring basis, categorized by level within the fair value hierarchy	The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: 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 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
Reconciliation of changes in fair value of items categorized as level 3 measurements	The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended 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
Schedule of carrying value and estimated fair value of financial instruments not recorded at fair value	The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: 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.

DERIVATIVE INSTRUMENTS (Tables)

DERIVATIVE INSTRUMENTS (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets and derivative 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.
Estimated notional volumes and realized gain (losses)	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
Offsetting assets and liabilities	The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: 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 .
Amounts related to cash flow hedges recorded in OCI and 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

GUARANTEES (Tables)

GUARANTEES (Tables)	9 Months Ended
	Sep. 30, 2018
Guarantees [Abstract]
Schedule of outstanding 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.

EMPLOYEE BENEFITS (Tables)

EMPLOYEE BENEFITS (Tables)	9 Months Ended
	Sep. 30, 2018
Retirement Benefits [Abstract]
Schedule of net benefit costs	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 )
Schedule of non-service components	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 )

GOODWILL (Tables)

GOODWILL (Tables)	9 Months Ended
	Sep. 30, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of changes to our goodwill balances by segment	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 .

INVESTMENT IN TRANSMISSION AF_2

INVESTMENT IN TRANSMISSION AFFILIATES (Tables)	9 Months Ended
	Sep. 30, 2018
Investment in transmission affiliates
Schedule of changes to our investments in transmission affiliates	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 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.
ATC
Investment in transmission affiliates
Schedule of significant transactions with ATC	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
Schedule of receivables and payables with ATC	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
Schedule of summarized income statement data for ATC	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
Schedule of summarized balance sheet data for ATC	(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

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Financial information of reportable segments	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. 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.

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	9 Months Ended
	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of regulatory assets and reserves related to manufactured gas plant sites	We have established the following regulatory assets and reserves related to manufactured gas plant sites: (in millions) September 30, 2018 December 31, 2017 Regulatory assets $ 680.0 $ 676.6 Reserves for future remediation 617.4 617.2

SUPPLEMENTAL CASH FLOW INFORM_2

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2018
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Schedule of 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.
Reconciliation of cash and cash equivalents and restricted cash	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

GENERAL INFORMATION - GENERAL (

GENERAL INFORMATION - GENERAL (Details) customer in Millions	Sep. 30, 2018customer
Electric
Product information [Line Items]
Number Of Customers	1.6
Natural gas
Product information [Line Items]
Number Of Customers	2.9

GENERAL INFORMATION - INVESTMEN

GENERAL INFORMATION - INVESTMENTS (Details)	Sep. 30, 2018	Aug. 31, 2018
ATC
Schedule of Investments [Line Items]
Equity method investment, ownership interest (as a percent)	60.00%
Bishop Hill III Holdings LLC
Schedule of Investments [Line Items]
Bishop Hill III Holdings LLC's interest in Bishop Hill III Wind Energy Center	100.00%
WEC's ownership interest in Bishop Hill III Wind Energy Center		80.00%

ACQUISITIONS - BISHOP HILL III

ACQUISITIONS - BISHOP HILL III ACQUISITION (Details) - Bishop Hill III Wind Energy Center $ in Millions	1 Months Ended
	Aug. 31, 2018USD ($)MW	Oct. 19, 2018
Business Acquisition [Line Items]
WEC's ownership interest in Bishop Hill III Wind Energy Center	80.00%
Capacity of Bishop Hill III Wind Energy Center | MW	132
Acquisition purchase price	$ 143.5
Restricted cash acquired	$ 4.5
Duration of offtake agreement for the sale of energy produced	22 years
Bonus depreciation percentage	100.00%
Measurement period to complete acquisition purchase price allocation	1 year
Subsequent event
Business Acquisition [Line Items]
Bonus depreciation percentage		100.00%
Additional Ownership Interest in Bishop Hill III Wind Energy Center		10.00%

ACQUISITIONS - BISHOP HILL II_2

ACQUISITIONS - BISHOP HILL III ACQUISITION - PURCHASE PRICE ALLOCATION (Details) - Bishop Hill III Wind Energy Center $ in Millions	1 Months Ended
	Aug. 31, 2018USD ($)
Business Acquisition [Line Items]
Current assets	$ 1.4
Net property, plant, and equipment	189
Other long-term assets	4.5
Current liabilities	(1.6)
Long-term liabilities	(8.3)
Noncontrolling interest	(37)
Total purchase price	$ 148

ACQUISITIONS - UPSTREAM ACQUISI

ACQUISITIONS - UPSTREAM ACQUISITION (Details) - Upstream $ in Millions	1 Months Ended
	Apr. 30, 2018USD ($)MW
Business Acquisition [Line Items]
WEC's ownership interest in Upstream Wind Energy Center	80.00%
Capacity of Upstream Wind Energy Center | MW	202.5
Acquisition purchase price | $	$ 276
Number of years Upstream will receive fixed payment	10 years
Bonus depreciation percentage	100.00%

ACQUISITIONS - FORWARD ACQUISIT

ACQUISITIONS - FORWARD ACQUISITION - CONSIDERATION TRANSFERRED (Details) - Forward Wind Energy Center Acquisition $ in Millions	1 Months Ended
	Apr. 30, 2018USD ($)utility	Apr. 02, 2018wind_turbinesMW
Business Acquisition [Line Items]
Number of utilities along with WPS that entered in an agreement to purchase Forward Wind Energy Center | utility	2
Number of wind turbines at Forward Wind Energy Center | wind_turbines		86
Capacity of Foward Wind Energy Center | MW		129
Purchase price | $	$ 172.9
WPS
Business Acquisition [Line Items]
Number of utilities along with WPS that entered in an agreement to purchase Forward Wind Energy Center | utility	2
Purchase price | $	$ 77.1
WPS's share of Forward Wind Energy Center's purchase price	44.60%
Percentage of Forward Wind Energy Center's output purchased by WPS		44.60%

ACQUISITIONS - FORWARD ACQUIS_2

ACQUISITIONS - FORWARD ACQUISITION - PURCHASE PRICE ALLOCATION (Details) - Forward Wind Energy Center Acquisition - USD ($) $ in Millions	1 Months Ended
	Apr. 30, 2018	Apr. 02, 2018
Business Acquisition [Line Items]
Purchase price	$ 172.9
WPS
Business Acquisition [Line Items]
Current assets		$ 0.2
Net property, plant, and equipment		$ 76.9
Purchase price	$ 77.1

ACQUISITIONS - BLUEWATER ACQUIS

ACQUISITIONS - BLUEWATER ACQUISITION - CONSIDERATION TRANSFERRED (Details) - Bluewater - USD ($) $ in Millions	1 Months Ended
	Jun. 30, 2017	Sep. 30, 2018
Business Acquisition [Line Items]
Purchase price	$ 226
Percentage of current storage needs provided		33.00%
Acquisition related costs	$ 4.9

ACQUISITIONS - BLUEWATER ACQU_2

ACQUISITIONS - BLUEWATER ACQUISITION - PURCHASE PRICE ALLOCATION (Details) - Bluewater $ in Millions	1 Months Ended
	Jun. 30, 2017USD ($)
Business Acquisition [Line Items]
Current assets	$ 2
Net property, plant, and equipment	218.3
Goodwill	6.6
Current liabilities	(0.9)
Total purchase price	$ 226

OPERATING REVENUES - DISAGGREGA

OPERATING REVENUES - DISAGGREGATION OF OPERATING REVENUES BY SEGMENT (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Operating Revenues
Operating revenues	$ 1,643.7	$ 1,657.5	$ 5,602.7	$ 5,593.5
Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,635.7		5,599.3
Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	8		3.4
Total utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,622.1		5,561.1
Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,218.3		3,370.2
Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	403.8		2,190.9
Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	406.5		2,183.9
Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	13.6		38.2
Total Utility Operations
Disaggregation of Operating Revenues
Operating revenues	1,636.8		5,569
Total Utility Operations | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	7.9		2.9
Total Utility Operations | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,628.9		5,566.1
Total Utility Operations | Total utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,624.8		5,554.1
Total Utility Operations | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,218.3		3,370.2
Total Utility Operations | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	406.5		2,183.9
Total Utility Operations | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.1		12
Wisconsin
Disaggregation of Operating Revenues
Operating revenues	1,388.7		4,303.3
Wisconsin | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	3		11.3
Wisconsin | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,385.7		4,292
Wisconsin | Total utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,385.7		4,292
Wisconsin | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,218.3		3,370.2
Wisconsin | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	167.4		921.8
Wisconsin | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0		0
Illinois
Disaggregation of Operating Revenues
Operating revenues	197.9		973.2
Illinois | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	4.6		(1.6)
Illinois | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	193.3		974.8
Illinois | Total utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	193.2		974.6
Illinois | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0		0
Illinois | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	193.2		974.6
Illinois | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0.1		0.2
Other States
Disaggregation of Operating Revenues
Operating revenues	50.2		292.5
Other States | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	0.3		(6.8)
Other States | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	49.9		299.3
Other States | Total utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	45.9		287.5
Other States | Electric | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0		0
Other States | Natural gas | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	45.9		287.5
Other States | Other non-utility revenues | Transferred over time | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	4		11.8
Electric Transmission
Disaggregation of Operating Revenues
Operating revenues	0		0
Electric Transmission | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0		0
Electric Transmission | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	0		0
Electric Transmission | Total utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0		0
Electric Transmission | Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0		0
Electric Transmission | Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0		0
Electric Transmission | Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0		0
Non-Utility Energy Infrastructure
Disaggregation of Operating Revenues
Operating revenues	115.2		350.3
Non-Utility Energy Infrastructure | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	17.9		59.2
Non-Utility Energy Infrastructure | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	97.3		291.1
Non-Utility Energy Infrastructure | Total utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	10		34.9
Non-Utility Energy Infrastructure | Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0		0
Non-Utility Energy Infrastructure | Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	10		34.9
Non-Utility Energy Infrastructure | Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	7.9		24.3
Corporate and Other
Disaggregation of Operating Revenues
Operating revenues	2.4		6.9
Corporate and Other | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2.3		6.4
Corporate and Other | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	0.1		0.5
Corporate and Other | Total utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0		0
Corporate and Other | Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0		0
Corporate and Other | Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0		0
Corporate and Other | Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	2.3		6.4
Reconciling Eliminations
Disaggregation of Operating Revenues
Operating revenues	(110.7)		(323.5)
Reconciling Eliminations | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	(13.4)		(32.4)
Reconciling Eliminations | Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	(97.3)		(291.1)
Reconciling Eliminations | Total utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	(12.7)		(27.9)
Reconciling Eliminations | Electric | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	0		0
Reconciling Eliminations | Natural gas | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	(12.7)		(27.9)
Reconciling Eliminations | Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ (0.7)		$ (4.5)

OPERATING REVENUES - DISAGGRE_2

OPERATING REVENUES - DISAGGREGATION OF ELECTRIC UTILITY OPERATING REVENUES BY CUSTOMER CLASS (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018USD ($)	Sep. 30, 2018USD ($)contractperformance_obligations
Electric
Disaggregation of Operating Revenues
Number of performance obligations | performance_obligations		1
Number of contracts | contract		1
Number of days payment is due		30 days
Electric | Wholesale
Disaggregation of Operating Revenues
Number of performance obligations | performance_obligations		2
Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 1,635.7	$ 5,599.3
Revenues from contracts with customers | Electric
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,218.3	3,370.2
Wisconsin | Revenues from contracts with customers | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,385.7	4,292
Wisconsin | Revenues from contracts with customers | Electric | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,218.3	3,370.2
Wisconsin | Revenues from contracts with customers | Electric | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	465.3	1,243.3
Wisconsin | Revenues from contracts with customers | Electric | Transferred over time | Small commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	388.2	1,072.2
Wisconsin | Revenues from contracts with customers | Electric | Transferred over time | Large commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	249.7	695.2
Wisconsin | Revenues from contracts with customers | Electric | Transferred over time | Other
Disaggregation of Operating Revenues
Revenues from contracts with customers	7.5	22.4
Wisconsin | Revenues from contracts with customers | Electric | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,110.7	3,033.1
Wisconsin | Revenues from contracts with customers | Electric | Transferred over time | Wholesale
Disaggregation of Operating Revenues
Revenues from contracts with customers	62	175.3
Wisconsin | Revenues from contracts with customers | Electric | Transferred over time | Resale
Disaggregation of Operating Revenues
Revenues from contracts with customers	40.7	139.6
Wisconsin | Revenues from contracts with customers | Electric | Transferred over time | Steam
Disaggregation of Operating Revenues
Revenues from contracts with customers	2.7	16.9
Wisconsin | Revenues from contracts with customers | Electric | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 2.2	$ 5.3

OPERATING REVENUES - DISAGGRE_3

OPERATING REVENUES - DISAGGREGATION OF NATURAL GAS UTILITY OPERATING REVENUES BY CUSTOMER CLASS (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018
Natural gas
Disaggregation of Operating Revenues
Number of days payment is due		30 days
Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 1,635.7	$ 5,599.3
Revenues from contracts with customers | Natural gas
Disaggregation of Operating Revenues
Revenues from contracts with customers	403.8	2,190.9
Revenues from contracts with customers | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	406.5	2,183.9
Revenues from contracts with customers | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	204.7	1,346.9
Revenues from contracts with customers | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	77	568.5
Revenues from contracts with customers | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	281.7	1,915.4
Revenues from contracts with customers | Natural gas | Transferred over time | Transport
Disaggregation of Operating Revenues
Revenues from contracts with customers	62.1	248.5
Revenues from contracts with customers | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	62.7	20
Wisconsin | Revenues from contracts with customers | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	1,385.7	4,292
Wisconsin | Revenues from contracts with customers | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	167.4	921.8
Wisconsin | Revenues from contracts with customers | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	71.9	556.7
Wisconsin | Revenues from contracts with customers | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	35	286.4
Wisconsin | Revenues from contracts with customers | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	106.9	843.1
Wisconsin | Revenues from contracts with customers | Natural gas | Transferred over time | Transport
Disaggregation of Operating Revenues
Revenues from contracts with customers	13.9	51.3
Wisconsin | Revenues from contracts with customers | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	46.6	27.4
Illinois | Revenues from contracts with customers | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	193.3	974.8
Illinois | Revenues from contracts with customers | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	193.2	974.6
Illinois | Revenues from contracts with customers | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	112.7	609
Illinois | Revenues from contracts with customers | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	29.4	186.1
Illinois | Revenues from contracts with customers | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	142.1	795.1
Illinois | Revenues from contracts with customers | Natural gas | Transferred over time | Transport
Disaggregation of Operating Revenues
Revenues from contracts with customers	43.3	175.6
Illinois | Revenues from contracts with customers | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	7.8	3.9
Other States | Revenues from contracts with customers | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	49.9	299.3
Other States | Revenues from contracts with customers | Natural gas | Transferred over time
Disaggregation of Operating Revenues
Revenues from contracts with customers	45.9	287.5
Other States | Revenues from contracts with customers | Natural gas | Transferred over time | Residential
Disaggregation of Operating Revenues
Revenues from contracts with customers	20.1	181.2
Other States | Revenues from contracts with customers | Natural gas | Transferred over time | Commercial and industrial
Disaggregation of Operating Revenues
Revenues from contracts with customers	12.6	96
Other States | Revenues from contracts with customers | Natural gas | Transferred over time | Total retail revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	32.7	277.2
Other States | Revenues from contracts with customers | Natural gas | Transferred over time | Transport
Disaggregation of Operating Revenues
Revenues from contracts with customers	4.9	21.6
Other States | Revenues from contracts with customers | Natural gas | Transferred over time | Other utility revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers	$ 8.3	$ (11.3)

OPERATING REVENUES - OTHER NON-

OPERATING REVENUES - OTHER NON-UTILITY OPERATING REVENUES (Details) $ in Millions	1 Months Ended	3 Months Ended	9 Months Ended
	Aug. 31, 2018MW	Sep. 30, 2018USD ($)	Sep. 30, 2018USD ($)
We Power revenues
Disaggregation of Operating Revenues
Revenues amortized from deferred revenue during the period		$ 6.4	$ 19
Appliance service repairs | Maximum
Disaggregation of Operating Revenues
Duration of contract for remaining performance obligations in contract		1 year	1 year
Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers		$ 1,635.7	$ 5,599.3
Other non-utility revenues | Revenues from contracts with customers
Disaggregation of Operating Revenues
Revenues from contracts with customers		13.6	38.2
Other non-utility revenues | Revenues from contracts with customers | We Power revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers		6.4	19
Other non-utility revenues | Revenues from contracts with customers | Distributed renewable solar project revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers		2.3	6.4
Other non-utility revenues | Revenues from contracts with customers | Wind generation revenues
Disaggregation of Operating Revenues
Revenues from contracts with customers		0.8	0.8
Other non-utility revenues | Revenues from contracts with customers | Other
Disaggregation of Operating Revenues
Revenues from contracts with customers		0.1	0.2
Transferred over time | Other non-utility revenues | Revenues from contracts with customers | Appliance service repairs
Disaggregation of Operating Revenues
Revenues from contracts with customers		$ 4	$ 11.8
Bishop Hill III Wind Energy Center
Disaggregation of Operating Revenues
WEC's ownership interest in Bishop Hill III Wind Energy Center	80.00%
Capacity of Bishop Hill III Wind Energy Center | MW	132
Duration of offtake agreement for the sale of energy produced	22 years

OPERATING REVENUES - OTHER OPER

OPERATING REVENUES - OTHER OPERATING REVENUES (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Operating Revenues
Operating revenues	$ 1,643.7	$ 1,657.5	$ 5,602.7	$ 5,593.5
Other operating revenues
Disaggregation of Operating Revenues
Operating revenues	8		3.4
Other operating revenues | Alternative revenues
Disaggregation of Operating Revenues
Operating revenues	(1.9)		(32.2)
Other operating revenues | Late payment charges
Disaggregation of Operating Revenues
Operating revenues	9.4		31.9
Other operating revenues | Leases
Disaggregation of Operating Revenues
Operating revenues	$ 0.5		$ 3.7

REGULATORY ASSETS AND LIABILI_3

REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Regulatory assets
Current assets	$ 30.3	$ 37.2
Regulatory assets	3,643.5	2,803.2
Total regulatory assets	3,673.8	2,840.4
Unrecognized pension and OPEB costs
Regulatory assets
Total regulatory assets	1,071	1,142
Plant retirements
Regulatory assets
Total regulatory assets	778.4	15.1
Environmental remediation costs
Regulatory assets
Total regulatory assets	680	676.6
System support resource
Regulatory assets
Total regulatory assets	315	298.9
Income tax
Regulatory assets
Total regulatory assets	272	15.7
Asset retirement obligations
Regulatory assets
Total regulatory assets	224.1	192.2
Electric transmission costs
Regulatory assets
Total regulatory assets	124	221
We Power generation
Regulatory assets
Total regulatory assets	48.7	71.3
Uncollectible expense
Regulatory assets
Total regulatory assets	39.3	35.1
Energy efficiency programs
Regulatory assets
Total regulatory assets	15.7	24.6
Other, net
Regulatory assets
Total regulatory assets	$ 105.6	$ 147.9

REGULATORY ASSETS AND LIABILI_4

REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Regulatory liabilities
Current liabilities	$ 25.6	$ 41.8
Regulatory liabilities	3,960.3	3,718.6
Total regulatory liabilities	3,985.9	3,760.4
Income tax
Regulatory liabilities
Total regulatory liabilities	2,279.1	2,134.1
Removal costs
Regulatory liabilities
Total regulatory liabilities	1,313.4	1,294.9
Mines deferral
Regulatory liabilities
Total regulatory liabilities	115.4	95.1
Unrecognized pension and OPEB costs
Regulatory liabilities
Total regulatory liabilities	106.5	114.2
Energy efficiency programs
Regulatory liabilities
Total regulatory liabilities	30	21.1
Energy costs refundable through rate adjustments
Regulatory liabilities
Total regulatory liabilities	25.2	42
Uncollectible expense
Regulatory liabilities
Total regulatory liabilities	23.9	24.7
Decoupling
Regulatory liabilities
Total regulatory liabilities	22.8	1.8
Earnings sharing mechanisms
Regulatory liabilities
Total regulatory liabilities	20.6	2.5
Other, net
Regulatory liabilities
Total regulatory liabilities	$ 49	$ 30

PROPERTY, PLANT, AND EQUIPMEN_2

PROPERTY, PLANT, AND EQUIPMENT (Details) $ in Millions	1 Months Ended	9 Months Ended
	Oct. 31, 2017MW	Sep. 30, 2018USD ($)	Dec. 31, 2017USD ($)
Property, plant, and equipment
Cost of removal reserve classified as a regulatory liability		$ 3,985.9	$ 3,760.4
Net book value of plant classified as a regulatory asset		3,673.8	$ 2,840.4
Edgewater Unit 4
Property, plant, and equipment
Plant to be retired, at carrying value		8.3
Cost of removal reserve classified as a regulatory liability		1.9
Net book value of plant classified as a regulatory asset		10.2
Pleasant Prairie power plant
Property, plant, and equipment
Plant to be retired, at carrying value		653.3
Cost of removal reserve classified as a regulatory liability		102.5
Net book value of plant classified as a regulatory asset		755.8
Presque Isle power plant
Property, plant, and equipment
Plant to be retired, at carrying value		186.9
Cost of removal reserve classified as a regulatory liability		10.5
Plant to be retired, net		197.4
Pulliam power plant
Property, plant, and equipment
Plant to be retired, at carrying value		40.8
Cost of removal reserve classified as a regulatory liability		20.3
Plant to be retired, net		61.1
UMERC
Property, plant, and equipment
Capacity of natural gas-fired generation facility (in megawatts) | MW	180
Wisconsin
Changes to severance liability
Severance liability, balance at beginning of period		29.4
Severance payments		(9.5)
Other		(3)
Severance liability, balance at end of period		$ 16.9

COMMON EQUITY - STOCK-BASED COM

COMMON EQUITY - STOCK-BASED COMPENSATION AWARDS GRANTED (Details)	9 Months Ended
	Sep. 30, 2018$ / sharesshares
Stock options
Stock-based Compensation
Stock options granted | shares	710,710
Stock options granted, weighted average exercise price | $ / shares	$ 65.60
Stock options granted, weighted-average grant date fair value | $ / shares	$ 7.71
Restricted shares
Stock-based Compensation
Awards granted | shares	156,340
Restricted shares granted, weighted-average grant date fair value | $ / shares	$ 64.20
Performance units
Stock-based Compensation
Awards granted | shares	217,560

COMMON EQUITY - COMMON STOCK DI

COMMON EQUITY - COMMON STOCK DIVIDENDS (Details) - $ / shares	Dec. 01, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Dividends Payable
Quarterly cash dividend declared (in dollars per share)		$ 0.5525	$ 0.5200	$ 1.6575	$ 1.5600
Subsequent event
Dividends Payable
Quarterly cash dividend declared (in dollars per share)	$ 0.5525

SHORT-TERM DEBT AND LINES OF _3

SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Short-term borrowings
Commercial paper outstanding	$ 1,788.3	$ 1,444.6
Commercial paper
Short-term borrowings
Commercial paper outstanding	$ 1,788.3	$ 1,444.6
Weighted-average interest rate on amounts outstanding	2.35%	1.77%
Average amount outstanding during the period	$ 1,322.4
Weighted-average interest rate during the period	2.20%

SHORT-TERM DEBT AND LINES OF _4

SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Revolving credit facilities
Short-term credit capacity	$ 2,800
Letters of credit issued inside credit facilities	3
Commercial paper outstanding	1,788.3	$ 1,444.6
Available capacity under existing agreements	1,008.7
WEC Energy Group | Credit facility maturing during October 2022
Revolving credit facilities
Short-term credit capacity	1,200
WE | Credit facility maturing during October 2022
Revolving credit facilities
Short-term credit capacity	500
WPS | Credit facility maturing during October 2022
Revolving credit facilities
Short-term credit capacity	350
WG | Credit facility maturing during October 2022
Revolving credit facilities
Short-term credit capacity	400
PGL | Credit facility maturing during October 2022
Revolving credit facilities
Short-term credit capacity	$ 350

LONG TERM DEBT (Details)

LONG TERM DEBT (Details) - USD ($) $ in Millions	Oct. 15, 2018	Sep. 30, 2018
Integrys Holding | Integrys 2006 Junior Notes due 2066
Debt Instrument [Line Items]
Extinguishment of debt		$ 114.9
WE
Debt Instrument [Line Items]
Long-term Pollution Control Bond		$ 80
WE | WE Debentures due 2018
Debt Instrument [Line Items]
Debt instrument stated interest rate percentage		1.70%
Extinguishment of debt		$ 250
Subsequent event | WE | WE 4.30% Debentures due 2048
Debt Instrument [Line Items]
Proceeds from Issuance of Debt	$ 300
Debt instrument stated interest rate percentage	4.30%
Subsequent event | PGL | PGL Series FFF Bonds due 2028
Debt Instrument [Line Items]
Secured commitments	$ 150
Subsequent event | NSG | NSG Series R Bonds due 2028
Debt Instrument [Line Items]
Secured commitments	$ 50
WEC Energy Group | WEC 2007 Junior Notes due 2067
Debt Instrument [Line Items]
Long-term debt outstanding		500
WEC Energy Group | WEC 3.375% Senior Notes due June 15, 2021
Debt Instrument [Line Items]
Proceeds from Issuance of Debt		$ 600
Debt instrument stated interest rate percentage		3.375%
WEC Energy Group | WEC Senior Notes due 2018
Debt Instrument [Line Items]
Debt instrument stated interest rate percentage		1.65%
Extinguishment of debt		$ 300
Interest rate swaps | WEC Energy Group
Debt Instrument [Line Items]
Interest rate swap notional value		$ 250
Interest rate swap fixed interest rate		4.9765%

MATERIALS, SUPPLIES, AND INVE_3

MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Energy Related Inventory
Natural gas in storage	$ 274.4	$ 209
Materials and supplies	227.5	211.2
Fossil fuel	106.6	118.8
Total	608.5	$ 539
LIFO Method Related Items
LIFO Liquidation Balance	$ 0

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Dec. 31, 2017	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Effective Income Tax Rate Reconciliation, Amount
Statutory federal income tax, amount		$ 52.6		$ 212.3
State income taxes net of federal tax benefit, amount		16		63.6
Tax repairs, amount		(35.8)		(83.9)
Federal tax reform, amount		(3.2)		(17.2)
Other, amount		(12.6)		(18.4)
Total income tax expense, amount		$ 17	$ 129.7	$ 156.4	$ 458.8
Effective Income Tax Rate Reconciliation, Percent
Statutory federal income tax, percentage		21.00%		21.00%	35.00%
State income taxes net of federal tax benefit, percentage		6.40%		6.30%
Tax repairs, percentage		(14.30%)		(8.30%)
Federal tax reform, percentage		(1.30%)		(1.70%)
Other, percentage		(5.00%)		(1.80%)
Total income tax expense, percentage		6.80%		15.50%
Measurement period to complete accounting related to Tax Cuts and Jobs Act	1 year

FAIR VALUE MEASUREMENTS - ASSET

FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Assets
Derivative asset	$ 23	$ 12.4
Liabilities
Derivative liability	4.9	11.6
Fair value measurements on a recurring basis
Assets
Derivative asset	23	12.4
Investments held in rabbi trust	115.3	120.7
Liabilities
Derivative liability		11.6
Fair value measurements on a recurring basis | Level 1
Assets
Derivative asset	9.6	3
Investments held in rabbi trust	115.3	120.7
Liabilities
Derivative liability		7
Fair value measurements on a recurring basis | Level 2
Assets
Derivative asset	1.9	5
Investments held in rabbi trust	0	0
Liabilities
Derivative liability		4.6
Fair value measurements on a recurring basis | Level 3
Assets
Derivative asset	11.5	4.4
Investments held in rabbi trust	0	0
Liabilities
Derivative liability		0
Fair value measurements on a recurring basis | Natural gas contracts
Assets
Derivative asset	9.9	5.7
Liabilities
Derivative liability	4.9	10.8
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative asset	9.6	1.8
Liabilities
Derivative liability	3.6	7
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative asset	0.3	3.9
Liabilities
Derivative liability	1.3	3.8
Fair value measurements on a recurring basis | Natural gas contracts | Level 3
Assets
Derivative asset	0	0
Liabilities
Derivative liability	0	0
Fair value measurements on a recurring basis | Petroleum products contracts
Assets
Derivative asset		1.2
Fair value measurements on a recurring basis | Petroleum products contracts | Level 1
Assets
Derivative asset		1.2
Fair value measurements on a recurring basis | Petroleum products contracts | Level 2
Assets
Derivative asset		0
Fair value measurements on a recurring basis | Petroleum products contracts | Level 3
Assets
Derivative asset		0
Fair value measurements on a recurring basis | FTRs
Assets
Derivative asset	11.5	4.4
Fair value measurements on a recurring basis | FTRs | Level 1
Assets
Derivative asset	0	0
Fair value measurements on a recurring basis | FTRs | Level 2
Assets
Derivative asset	0	0
Fair value measurements on a recurring basis | FTRs | Level 3
Assets
Derivative asset	11.5	4.4
Fair value measurements on a recurring basis | Coal contracts
Assets
Derivative asset	0.8	1.1
Liabilities
Derivative liability		0.8
Fair value measurements on a recurring basis | Coal contracts | Level 1
Assets
Derivative asset	0	0
Liabilities
Derivative liability		0
Fair value measurements on a recurring basis | Coal contracts | Level 2
Assets
Derivative asset	0.8	1.1
Liabilities
Derivative liability		0.8
Fair value measurements on a recurring basis | Coal contracts | Level 3
Assets
Derivative asset	0	0
Liabilities
Derivative liability		$ 0
Fair value measurements on a recurring basis | Interest rate swaps
Assets
Derivative asset	0.8
Fair value measurements on a recurring basis | Interest rate swaps | Level 1
Assets
Derivative asset	0
Fair value measurements on a recurring basis | Interest rate swaps | Level 2
Assets
Derivative asset	0.8
Fair value measurements on a recurring basis | Interest rate swaps | Level 3
Assets
Derivative asset	$ 0

FAIR VALUE MEASUREMENTS - UNREA

FAIR VALUE MEASUREMENTS - UNREALIZED GAIN (LOSS) ON INVESTMENTS (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Net unrealized gains included in earnings related to investments held in rabbi trust	$ 7.1	$ 4.4	$ 7.5	$ 12.2

FAIR VALUE MEASUREMENTS - LEVEL

FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Balance at the beginning of the period	$ 16.7	$ 11.8	$ 4.4	$ 5.1
Purchases	0	0	18.4	13.8
Settlements	(5.2)	(4.5)	(11.3)	(11.6)
Balance at the end of period	$ 11.5	$ 7.3	$ 11.5	$ 7.3

FAIR VALUE MEASUREMENTS - FINAN

FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Financial Instruments
Preferred stock	$ 30.4	$ 30.4
Carrying Amount
Financial Instruments
Preferred stock	30.4	30.4
Long-term debt, including current portion	9,464.2	9,561.7
Capital lease obligations	24.2	27
Fair Value
Financial Instruments
Preferred stock	28.3	30.5
Long-term debt, including current portion	$ 9,762.1	$ 10,341.9

DERIVATIVE INSTRUMENTS - DERIVA

DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivative Asset
Other current derivative assets	$ 21.6	$ 11.8
Other long-term derivative assets	1.4	0.6
Derivative asset	23	12.4
Derivative Liability
Other current derivative liabilities	4.5	10
Other long-term derivative liabilities	0.4	1.6
Derivative liability	4.9	11.6
Natural gas contracts
Derivative Asset
Other current derivative assets	9.7	5.6
Other long-term derivative assets	0.2	0.1
Derivative Liability
Other current derivative liabilities	4.5	9.4
Other long-term derivative liabilities	0.4	1.4
Petroleum products contracts
Derivative Asset
Other current derivative assets	0	1.2
Derivative Liability
Other current derivative liabilities	0	0
FTRs
Derivative Asset
Other current derivative assets	11.5	4.4
Derivative Liability
Other current derivative liabilities	0	0
Coal contracts
Derivative Asset
Other current derivative assets	0.4	0.6
Other long-term derivative assets	0.4	0.5
Derivative Liability
Other current derivative liabilities	0	0.6
Other long-term derivative liabilities	0	0.2
Interest rate swaps
Derivative Asset
Other long-term derivative assets	0.8	0
Derivative Liability
Other long-term derivative liabilities	$ 0	$ 0

DERIVATIVE INSTRUMENTS - GAINS

DERIVATIVE INSTRUMENTS - GAINS (LOSSES) AND NOTIONAL VOLUMES (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018USD ($)MWhMMBTUgal	Sep. 30, 2017USD ($)MWhMMBTUgal	Sep. 30, 2018USD ($)MWhMMBTUgal	Sep. 30, 2017USD ($)MWhMMBTUgal
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ 8	$ 1.6	$ 8.9	$ 6.9
Natural gas contracts
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ 0.4	$ (2.1)	$ (7.1)	$ (1.1)
Notional Sales Volumes
Notional sales volumes | MMBTU	36.7	24.9	124.7	84.2
Petroleum products contracts
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ 0.5	$ (0.5)	$ 1.3	$ (1.4)
Notional Sales Volumes
Notional sales volumes (gallons) | gal	1.3	4.4	5.1	14.2
FTRs
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ 7.1	$ 4.2	$ 14.7	$ 9.4
Notional Sales Volumes
Notional sales volumes | MWh	7.9	9.4	22.9	28

DERIVATIVE INSTRUMENTS - BALANC

DERIVATIVE INSTRUMENTS - BALANCE SHEET OFFSETTING (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Cash collateral
Cash collateral in margin account	$ 6.8	$ 16.2
Cash collateral received in margin account	0.1
Offsetting Derivative Assets
Gross amount recognized on the balance sheet	23	12.4
Gross amount not offset on the balance sheet	(3.7)	(4.9)
Net amount	19.3	7.5
Collateral received	0.1
Offsetting Derivative Liabilities
Gross amount recognized on the balance sheet	4.9	11.6
Gross amount not offset on the balance sheet	(3.6)	(9)
Net amount	$ 1.3	2.6
Collateral posted		4.1
Credit Risk Related Contingent Features
Aggregate fair value of all derivative instruments with specific credit risk-related contingent fearures in a net liability position		3.7
Additional collateral that would have been required		$ 2.7

DERIVATIVE INSTRUMENTS - CASH F

DERIVATIVE INSTRUMENTS - CASH FLOW HEDGES (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2015
Derivative [Line Items]
Issuance of long-term debt			$ 600	$ 210
Interest rate swaps
Derivative [Line Items]
Amount of net derivative gain recognized in OCI	$ 0.4	$ 0	0.4	0
Amount of net derivative gain reclassified from accumulated OCI to interest expense	0.2	$ 0.6	1.3	$ 1.7
Amount to be reclassified from accumulated OCI to interest expense	1.6		1.6
WEC Energy Group | WEC 2007 Junior Notes due 2067
Derivative [Line Items]
Long-term debt outstanding	500		500
WEC Energy Group | Total senior note issued in June 2015
Derivative [Line Items]
Issuance of long-term debt					$ 1,200
WEC Energy Group | Interest rate swaps
Derivative [Line Items]
Interest rate swap notional value	$ 250		$ 250
Interest rate swap fixed interest rate	4.9765%		4.9765%
Amount of net derivative gain recognized in OCI					$ 19

GUARANTEES (Details)

GUARANTEES (Details) $ in Millions	Sep. 30, 2018USD ($)
Guarantees
Total guarantees	$ 131.8
Guarantees expiring in less than 1 year	40.7
Guarantees expiring within 1 to 3 years	1.2
Guarantees with expiration over 3 years	89.9
Commodity transactions guarantee
Guarantees
Total guarantees	5.6
Guarantees expiring in less than 1 year	5.6
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	0
Standby letters of credit
Guarantees
Total guarantees	104.2
Guarantees expiring in less than 1 year	25.5
Guarantees expiring within 1 to 3 years	0.2
Guarantees with expiration over 3 years	78.5
Surety bonds
Guarantees
Total guarantees	9.2
Guarantees expiring in less than 1 year	9.1
Guarantees expiring within 1 to 3 years	0.1
Guarantees with expiration over 3 years	0
Other guarantees
Guarantees
Total guarantees	12.8
Guarantees expiring in less than 1 year	0.5
Guarantees expiring within 1 to 3 years	0.9
Guarantees with expiration over 3 years	11.4
Other indemnifications
Guarantees
Total guarantees	12.8
Liability related to workers compensation coverage	$ 11.4

EMPLOYEE BENEFITS-COSTS AND CON

EMPLOYEE BENEFITS-COSTS AND CONTRIBUTIONS (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Components of net periodic benefit cost
Contributions and payments related to pension and OPEB plans			$ 13.8	$ 115.4
Pension Costs
Components of net periodic benefit cost
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 (credit) cost	0.7	0.7	2	2.2
Amortization of net actuarial loss	23.6	21.5	70.6	64.5
Net periodic benefit (credit) cost	15.9	17.7	47.3	52.9
Contributions and payments related to pension and OPEB plans			9.8
Estimated future employer contributions for the remainder of the year	2.8		2.8
Other Postretirement Benefit Costs
Components of net periodic benefit cost
Service cost	5.9	6	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) cost	(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) cost	(5)	$ (1.3)	(15.2)	$ (3.8)
Contributions and payments related to pension and OPEB plans			4
Estimated future employer contributions for the remainder of the year	$ 4.1		$ 4.1

EMPLOYEE BENEFITS-IMPACT OF ADO

EMPLOYEE BENEFITS-IMPACT OF ADOPTION OF ASU 2017-07 (Details) - Accounting Standards Update 2017-07 - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Non-service credit components	$ (7.3)		$ (19.8)
Impact of ASU 2017-07
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Non-service credit components		$ (1.4)		$ (4)

GOODWILL (Details)

GOODWILL (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018USD ($)	Sep. 30, 2018USD ($)
Changes to our goodwill balances by segment
Goodwill balance as of January 1, 2018		$ 3,053.5
Goodwill balance as of September 30, 2018	$ 3,052.8	3,052.8
Accumulated impairment losses	0	0
Amount of impairment from goodwill test	0
Bluewater
Changes to our goodwill balances by segment
Adjustment to Bluewater purchase price allocation		(0.7)
Wisconsin
Changes to our goodwill balances by segment
Goodwill balance as of January 1, 2018		2,104.3
Goodwill balance as of September 30, 2018	2,104.3	2,104.3
Wisconsin | Bluewater
Changes to our goodwill balances by segment
Adjustment to Bluewater purchase price allocation		0
Illinois
Changes to our goodwill balances by segment
Goodwill balance as of January 1, 2018		758.7
Goodwill balance as of September 30, 2018	758.7	758.7
Illinois | Bluewater
Changes to our goodwill balances by segment
Adjustment to Bluewater purchase price allocation		0
Other States
Changes to our goodwill balances by segment
Goodwill balance as of January 1, 2018		183.2
Goodwill balance as of September 30, 2018	183.2	183.2
Other States | Bluewater
Changes to our goodwill balances by segment
Adjustment to Bluewater purchase price allocation		0
Non-Utility Energy Infrastructure
Changes to our goodwill balances by segment
Goodwill balance as of January 1, 2018		7.3
Goodwill balance as of September 30, 2018	$ 6.6	6.6
Non-Utility Energy Infrastructure | Bluewater
Changes to our goodwill balances by segment
Adjustment to Bluewater purchase price allocation		$ (0.7)

INVESTMENT IN TRANSMISSION AF_3

INVESTMENT IN TRANSMISSION AFFILIATES - CHANGES TO INVESTMENTS (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016
Changes to investments in transmission affiliates
Investment in transmission affiliates, balance at beginning of period	$ 1,596.6	$ 1,544	$ 1,553.4	$ 1,443.9
Add: Earnings (loss) from equity method investment	33.7	39.2	95.2	122.9
Add: Capital contributions	11.3	12.8	43.7	63.3
Less: Distributions	27.8	35.2	78.5	69.2
Less: Other	0.1		0.1	0.1
Investment in transmission affiliates, balance at end of period	$ 1,613.7	1,560.8	$ 1,613.7	1,560.8
ATC
Investment in transmission affiliates
Equity method investment, ownership interest (as a percent)	60.00%		60.00%
Changes to investments in transmission affiliates
Investment in transmission affiliates, balance at beginning of period	$ 1,558.4	1,539.5	$ 1,515.8	1,443.9
Add: Earnings (loss) from equity method investment	34.6	40.9	97.8	131.4
Add: Capital contributions	9.1	12.1	39.2	51.3
Less: Distributions	27.8	35.2	78.5	69.2
Less: Other	0.1		0.1	0.1
Investment in transmission affiliates, balance at end of period	1,574.2	1,557.3	1,574.2	1,557.3
Dividends receivable from ATC	$ 27.7		$ 27.7		$ 39.9	$ 35.2
ATC Holdco
Investment in transmission affiliates
Equity method investment, ownership interest (as a percent)	75.00%		75.00%
Changes to investments in transmission affiliates
Investment in transmission affiliates, balance at beginning of period	$ 38.2	4.5	$ 37.6	0
Add: Earnings (loss) from equity method investment	(0.9)	(1.7)	(2.6)	(8.5)
Add: Capital contributions	2.2	0.7	4.5	12
Less: Distributions	0	0	0	0
Less: Other	0		0	0
Investment in transmission affiliates, balance at end of period	$ 39.5	$ 3.5	$ 39.5	$ 3.5

INVESTMENT IN TRANSMISSION AF_4

INVESTMENT IN TRANSMISSION AFFILIATES - RELATED PARTY TRANSACTIONS (Details) - ATC - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Investment in transmission affiliates
Charges to ATC for services and construction	$ 5	$ 4.4	$ 13.7	$ 12.3
Charges from ATC for network transmission services	84.4	87.4	253.5	262
Refund from ATC related to a FERC audit	0	0	22	0
Refund from ATC per FERC ROE order	$ 0	$ 0	$ 0	$ 28.3

INVESTMENT IN TRANSMISSION AF_5

INVESTMENT IN TRANSMISSION AFFILIATES - RELATED PARTY TRANSACTIONS BALANCE SHEET INFORMATION (Details) - ATC - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Investment in transmission affiliates
Accounts receivable for services provided to ATC	$ 2.9	$ 1.5
Dividends receivable from ATC	27.7	39.9	$ 35.2
Accounts payable for services received from ATC	$ 28.1	$ 31.2

INVESTMENT IN TRANSMISSION AF_6

INVESTMENT IN TRANSMISSION AFFILIATES - SUMMARIZED FINANCIAL DATA (Details) - ATC - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Income statement data
Operating revenues	$ 170.4	$ 171.1	$ 501.3	$ 522.4
Operating expenses	87.9	85.3	264.3	251
Other expense, net	27.4	27.2	80.4	78.7
Net income	55.1	$ 58.6	156.6	$ 192.7
Balance sheet data
Current assets	95.3		95.3		$ 87.7
Noncurrent assets	4,857.6		4,857.6		4,598.9
Total assets	4,952.9		4,952.9		4,686.6
Current liabilities	640.6		640.6		767.2
Long-term debt	2,013.9		2,013.9		1,790.6
Other noncurrent liabilities	313.6		313.6		240.3
Shareholders' equity	1,984.8		1,984.8		1,888.5
Total liabilities and shareholders' equity	$ 4,952.9		$ 4,952.9		$ 4,686.6

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)segment	Sep. 30, 2017USD ($)
Segment information
Number of reportable segments | segment			6
Operating revenues	$ 1,643.7	$ 1,657.5	$ 5,602.7	$ 5,593.5
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
Operating income (loss)	302.7	392.2	1,178.6	1,369.1
Equity in earnings of transmission affiliates	33.7	39.2	95.2	122.9
Interest expense	112	103.8	327.2	310.4
Wisconsin
Segment information
Operating revenues	1,388.7		4,303.3
Illinois
Segment information
Operating revenues	197.9		973.2
Other States
Segment information
Operating revenues	50.2		292.5
Electric Transmission
Segment information
Operating revenues	0		0
Other operation and maintenance	0	0	0	0
Depreciation and amortization	0	0	0	0
Operating income (loss)	0	0	0	0
Equity in earnings of transmission affiliates	33.7	39.2	95.2	122.9
Interest expense	0	0	0	0
Non-Utility Energy Infrastructure
Segment information
Operating revenues	115.2		350.3
Other operation and maintenance	3	1.5	9.2	4.6
Depreciation and amortization	19.1	18.2	55.7	53.1
Operating income (loss)	91.6	103.4	277	299.5
Equity in earnings of transmission affiliates	0	0	0	0
Interest expense	15.9	16.2	48	46.7
Corporate and Other
Segment information
Operating revenues	2.4		6.9
Other operation and maintenance	(4.4)	(0.4)	(2.5)	3.5
Depreciation and amortization	7.1	6.3	22.3	18.3
Operating income (loss)	(0.4)	0	(12.3)	(10.1)
Equity in earnings of transmission affiliates	0	0	0	0
Interest expense	32.9	25.4	91.2	81.3
Reconciling Eliminations
Segment information
Other operation and maintenance	(98)	(109)	(295.2)	(330.6)
Depreciation and amortization	0	0	0	0
Operating income (loss)	0	0	0	0
Equity in earnings of transmission affiliates	0	0	0	0
Interest expense	$ (1.3)	0.4	$ (3.2)	(2.5)
ATC | Electric Transmission
Segment information
Equity method investment, ownership interest (as a percent)	60.00%		60.00%
ATC Holdco
Segment information
Equity method investment, ownership interest (as a percent)	75.00%		75.00%
Equity in earnings of transmission affiliates	$ (0.9)	(1.7)	$ (2.6)	(8.5)
ATC Holdco | Electric Transmission
Segment information
Equity method investment, ownership interest (as a percent)	75.00%		75.00%
Bishop Hill III Wind Energy Center | Non-Utility Energy Infrastructure
Segment information
WEC's ownership interest in Bishop Hill III Wind Energy Center	80.00%		80.00%
Total utility revenues
Segment information
Other operation and maintenance	$ 652.5	581	$ 1,891.2	1,779.9
Depreciation and amortization	186.6	176.7	550.1	522.1
Operating income (loss)	211.5	288.8	913.9	1,079.7
Equity in earnings of transmission affiliates	0	0	0	0
Interest expense	64.5	61.8	191.2	184.9
Total utility revenues | Wisconsin
Segment information
Other operation and maintenance	525	460.5	1,495.9	1,385.9
Depreciation and amortization	137.2	131.5	406.9	391.1
Operating income (loss)	201.4	277.5	670.2	829.6
Equity in earnings of transmission affiliates	0	0	0	0
Interest expense	49.6	48.5	147.5	145.4
Total utility revenues | Illinois
Segment information
Other operation and maintenance	104.5	99	320.8	321
Depreciation and amortization	43	38.9	125.7	112.6
Operating income (loss)	15.5	14.3	204.8	214.9
Equity in earnings of transmission affiliates	0	0	0	0
Interest expense	12.8	11	37.4	33
Total utility revenues | Other States
Segment information
Other operation and maintenance	23	21.5	74.5	73
Depreciation and amortization	6.4	6.3	17.5	18.4
Operating income (loss)	(5.4)	(3)	38.9	35.2
Equity in earnings of transmission affiliates	0	0	0	0
Interest expense	2.1	2.3	6.3	6.5
External Revenues
Segment information
Operating revenues	1,643.7	1,657.5	5,602.7	5,593.5
External Revenues | Electric Transmission
Segment information
Operating revenues	0	0	0	0
External Revenues | Non-Utility Energy Infrastructure
Segment information
Operating revenues	4.5	13.6	26.8	26.1
External Revenues | Corporate and Other
Segment information
Operating revenues	2.4	5.6	6.9	11.7
External Revenues | Reconciling Eliminations
Segment information
Operating revenues	0	0	0	0
External Revenues | Total utility revenues
Segment information
Operating revenues	1,636.8	1,638.3	5,569	5,555.7
External Revenues | Total utility revenues | Wisconsin
Segment information
Operating revenues	1,388.7	1,401.3	4,303.3	4,316.6
External Revenues | Total utility revenues | Illinois
Segment information
Operating revenues	197.9	187.2	973.2	965.7
External Revenues | Total utility revenues | Other States
Segment information
Operating revenues	50.2	49.8	292.5	273.4
Intersegment Transactions [Member]
Segment information
Operating revenues	0	0	0	0
Intersegment Transactions [Member] | Electric Transmission
Segment information
Operating revenues	0	0	0	0
Intersegment Transactions [Member] | Non-Utility Energy Infrastructure
Segment information
Operating revenues	110.7	111.6	323.5	333.2
Intersegment Transactions [Member] | Corporate and Other
Segment information
Operating revenues	0	0	0	0
Intersegment Transactions [Member] | Reconciling Eliminations
Segment information
Operating revenues	(110.7)	(111.6)	(323.5)	(333.2)
Intersegment Transactions [Member] | Total utility revenues
Segment information
Operating revenues	0	0	0	0
Intersegment Transactions [Member] | Total utility revenues | Wisconsin
Segment information
Operating revenues	0	0	0	0
Intersegment Transactions [Member] | Total utility revenues | Illinois
Segment information
Operating revenues	0	0	0	0
Intersegment Transactions [Member] | Total utility revenues | Other States
Segment information
Operating revenues	$ 0	$ 0	$ 0	$ 0

VARIABLE INTEREST ENTITIES (Det

VARIABLE INTEREST ENTITIES (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)MW	Sep. 30, 2017USD ($)	Jun. 30, 2018USD ($)	Dec. 31, 2017USD ($)	Jun. 30, 2017USD ($)	Dec. 31, 2016USD ($)
Variable interest entities
Equity investment	$ 1,613.7	$ 1,560.8	$ 1,596.6	$ 1,553.4	$ 1,544	$ 1,443.9
ATC
Variable interest entities
Ownership interest (as a percent)	60.00%
Equity investment	$ 1,574.2			1,515.8
ATC distributions receivable	27.7			39.9
Accounts payable due to ATC	$ 28.1			31.2
ATC Holdco
Variable interest entities
Ownership interest (as a percent)	75.00%
Equity investment	$ 39.5			$ 37.6
Purchased power agreement
Variable interest entities
Firm capacity from purchased power agreement (in megawatts) | MW	236
Minimum energy requirements over remaining term of purchased power agreement (in megawatts) | MW	0
Remaining term of purchased power agreement (in years)	4 years
Residual guarantee associated with purchased power agreement	$ 0
Required payments over remaining term of purchased power agreement	60.4
Total capacity and lease payments	$ 14.1	$ 13.5

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions	Sep. 30, 2018USD ($)
Minimum future commitments for purchase obligations
Purchase obligations	$ 12,034.4

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) $ in Millions	1 Months Ended	9 Months Ended
	Oct. 31, 2014compliance_option	Sep. 30, 2018USD ($)generating_unitsdegreecelsiusMW	Dec. 31, 2017USD ($)
Climate Change | Electric
Air quality
Company goal for percentage of carbon dioxide emissions reduction		40.00%
Long-term company goal for percentage of carbon dioxide emissions reduction by 2050		80.00%
Capacity of coal generation expected to be retired by 2020 | MW		1,800
Climate Change | Electric | Maximum
Air quality
Global temperature increases limit | degreecelsius		2
Clean Water Act Cooling Water Intake Structure Rule | Electric
Water quality
Number of compliance options available to meet standard | compliance_option	7
Renewal period for facility permits		5 years
Steam Electric Effluent Limitation Guidelines | Electric
Water quality
Number of generating units of OCPP and ERGS | generating_units		6
Expected cost to achieve required emissions reductions		$ 70
Manufactured Gas Plant Remediation | Natural gas
Manufactured gas plant remediation
Regulatory assets recorded for remediation of manufactured gas plant sites		680	$ 676.6
Reserves recorded for remediation of manufactured gas plant sites		$ 617.4	$ 617.2

SUPPLEMENTAL CASH FLOW INFORM_3

SUPPLEMENTAL CASH FLOW INFORMATION - SUPPLEMENTAL INFORMATION (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Supplemental cash flow information
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	$ 0	$ 7

SUPPLEMENTAL CASH FLOW INFORM_4

SUPPLEMENTAL CASH FLOW INFORMATION - RECONCILIATION OF CASH AND CASH EQUIVALENTS AND RESTRICTED CASH (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Cash and cash equivalents	$ 14.5	$ 38.9	$ 18.1
Restricted cash included in other long term assets	25.7		20.4
Cash, cash equivalents, and restricted cash	$ 40.2	$ 58.6	$ 38.5	$ 72.7

SUPPLEMENTAL CASH FLOW INFORM_5

SUPPLEMENTAL CASH FLOW INFORMATION - ADOPTION OF ACCOUNTING STANDARDS UPDATES (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)Provisions	Sep. 30, 2017USD ($)
Adoption of accounting standards updates
Net cash used in investing activities	$ 1,720	$ 1,565.8
Accounting Standards Update 2016-18 | Impact of ASU 2016-18
Adoption of accounting standards updates
Net cash used in investing activities		13.8
Accounting Standards Update 2016-15
Adoption of accounting standards updates
Number of provisions in ASU 2016-15 | Provisions	8
Impact on financial statements from adoption	$ 0	$ 0

REGULATORY ENVIRONMENT (Details

REGULATORY ENVIRONMENT (Details) $ in Millions	1 Months Ended							3 Months Ended	9 Months Ended
	May 31, 2018USD ($)MWsolar_projects	Mar. 31, 2018USD ($)	Feb. 28, 2018USD ($)Filings	Dec. 31, 2017USD ($)	Nov. 30, 2017USD ($)	Oct. 31, 2017USD ($)	Sep. 30, 2017USD ($)utility	Sep. 30, 2018customerAssurance	Sep. 30, 2018customerchangeAssurance	Sep. 30, 2017
Regulatory environment
Corporate federal tax rate								21.00%	21.00%	35.00%
WE | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Approved return on equity (as a percent)							10.20%
Income Statement impact of flow through of repair related deferred tax liabilities | change									0
WE | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates | Electric rates
Regulatory environment
Percentage of current tax benefit from Tax Cuts and Jobs Act of 2017 to be used to reduce certain regulatory assets	80.00%
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits	20.00%
WE | Michigan Public Service Commission (MPSC)
Regulatory environment
Number of retail electric customers served in Michigan | customer								1	1
WG | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Approved return on equity (as a percent)							10.30%
WPS | Public Service Commission of Wisconsin (PSCW) | Badger Hollow and Two Creeks Solar Farms
Regulatory environment
Number of solar projects in Wisconsin that WPS filed with the PSCW to acquire an interest in | solar_projects	2
WPS total ownership in two solar projects (in megawatts) | MW	200
WPS share of cost for certain solar projects	$ 260
WPS | Public Service Commission of Wisconsin (PSCW) | Badger Hollow Solar Farm
Regulatory environment
WPS individual ownership in a solar farm (in megawatts) | MW	100
WPS | Public Service Commission of Wisconsin (PSCW) | Two Creeks Solar Project
Regulatory environment
WPS individual ownership in a solar farm (in megawatts) | MW	100
WPS | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Approved return on equity (as a percent)							10.00%
Authorized revenue requirement for the ReACT project							$ 275
AFUDC							51
Estimated cost of the ReACT project, excluding AFUDC							$ 342
WPS | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates | Electric rates
Regulatory environment
Percentage of current tax benefit from Tax Cuts and Jobs Act of 2017 to be used to reduce certain regulatory assets	40.00%
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits	60.00%
WE, WG, and WPS | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates
Regulatory environment
Number of utilities with earnings sharing mechanism | utility							3
Return on equity in excess of authorized amount (as a percent)							0.50%
Percentage of first 50 basis points of additional utility earnings shared with customers							50.00%
WE, WG, and WPS | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates | Natural gas rates
Regulatory environment
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits	100.00%
PGL | Illinois Commerce Commission (ICC)
Regulatory environment
Amount of rate base reduction as a result of a settlement			$ 5.4
Amount to be refunded to ratepayers as a result of a settlement			$ 4.7
Amount of assurance that PGL's QIP rider costs will be recoverable | Assurance								0	0
MGU and UMERC | Michigan Public Service Commission (MPSC)
Regulatory environment
Number of filings required related to the Tax Cuts and Jobs Act of 2017 | Filings			3
MERC | Minnesota Public Utilities Commission (MPUC) | 2018 rates | Natural gas rates
Regulatory environment
Requested rate increase						$ 12.6
Requested rate increase (as a percent)						5.05%
Requested return on equity (as a percent)						10.30%
Requested common equity component average (as a percent)						50.90%
Interim rate increase		$ 7			$ 9.5
Interim rate increase, (as a percent)		2.81%			3.78%
Interim rate reduction		$ 2.5
Interim rates return on equity (as a percent)		9.10%
Interim rates common equity component average (as a percent)		50.90%
Utility operations | Tax Cuts And Jobs Act Of 2017
Regulatory environment
Change in deferred taxes from tax legislation				$ 2,450