WEC Energy (WEC) 10-K 28 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2016	Jan. 31, 2017	Jun. 30, 2016
Document and 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-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding (actual number of shares)		315,587,523
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 20.6

Consolidated Income Statements

Consolidated Income Statements - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Operating revenues	$ 7,472.3	$ 5,926.1	$ 4,997.1
Cost of sales	2,647.4	2,240.1	2,259.4
Other operation and maintenance	2,185.5	1,709.3	1,112.4
Depreciation and amortization	762.6	561.8	391.4
Property and revenue taxes	194.7	164.4	121.8
Total operating expenses	5,790.2	4,675.6	3,885
Operating Income	1,682.1	1,250.5	1,112.1
Equity in earnings of transmission affiliate	146.5	96.1	66
Other income, net	80.8	58.9	13.4
Interest expense	402.7	331.4	240.3
Other expense	(175.4)	(176.4)	(160.9)
Income before income taxes	1,506.7	1,074.1	951.2
Income tax expense	566.5	433.8	361.7
Net income	940.2	640.3	589.5
Preferred stock dividends of subsidiary	1.2	1.8	1.2
Net income attributed to common shareholders	$ 939	$ 638.5	$ 588.3
Earnings Per Share (Basic)
Earnings per common share (basic) (in dollars per share)	$ 2.98	$ 2.36	$ 2.61
Earnings Per Share (Diluted)
Earnings per common share (diluted) (in dollars per share)	$ 2.96	$ 2.34	$ 2.59
Weighted Average Common Shares Outstanding (Basic)
Basic (in shares)	315.6	271.1	225.6
Weighted Average Common Shares Outstanding (Diluted)
Diluted (in shares)	316.9	272.7	227.5

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Net income	$ 940.2	$ 640.3	$ 589.5
Derivatives accounted for as cash flow hedges
Gains on settlement, net of tax of $7.6	0	11.4	0
Reclassification of gains to net income, net of tax	(1.3)	(0.8)	0
Cash flow hedges, net	(1.3)	10.6	0
Defined benefit plans
Pension and OPEB costs arising during the period, net of tax of $0.1 and $(4.2), respectively	(0.8)	(6.3)	0
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax	0.4	0	0
Defined benefit plans, net	(0.4)	(6.3)	0
Other comprehensive (loss) income, net of tax	(1.7)	4.3	0
Comprehensive income	938.5	644.6	589.5
Preferred stock dividends of subsidiary	1.2	1.8	1.2
Comprehensive income attributed to common shareholders	$ 937.3	$ 642.8	$ 588.3

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income (Parentheticals) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Derivatives accounted for as cash flow hedges
Gains on settlement, tax		$ 7.6
Defined benefit plans
Pension and OPEB costs arising during the period, tax	$ 0.1	$ (4.2)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 37.5	$ 49.8
Accounts receivable and unbilled revenues, net of reserves of $108.0 and $113.3, respectively	1,241.7	1,028.6
Materials, supplies and inventories	587.6	687
Assets held for sale	0	96.8
Prepayments	204.4	285.8
Other	97.5	58.8
Current assets	2,168.7	2,206.8
Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $8,214.6 and $7,919.1, respectively	19,915.5	19,189.7
Regulatory assets	3,087.9	3,064.6
Equity investment in transmission affiliate	1,443.9	1,380.9
Goodwill	3,046.2	3,023.5
Other	461	489.7
Long-term assets	27,954.5	27,148.4
Total assets	30,123.2	29,355.2
Current liabilities
Short-term debt	860.2	1,095
Current portion of long-term debt	157.2	157.7
Accounts payable	861.5	815.4
Accrued payroll and benefits	163.8	169.7
Other	388.9	471.2
Current liabilities	2,431.6	2,709
Long-term liabilities
Long-term debt	9,158.2	9,124.1
Deferred income taxes	5,146.6	4,622.3
Deferred revenue, net	566.2	579.4
Regulatory liabilities	1,563.8	1,392.2
Environmental remediation liabilities	633.6	628.2
Pension and other postretirement benefit obligations	498.6	543.1
Other	1,164.4	1,071.7
Long-term liabilities	18,731.4	17,961
Commitments and Contingencies (Note 18)
Common shareholders' equity
Common stock - $0.01 par value; 325,000,000 shares authorized; 315,614,941 and 315,683,496 shares outstanding, respectively	3.2	3.2
Additional paid in capital	4,309.8	4,347.2
Retained earnings	4,613.9	4,299.8
Accumulated other comprehensive income	2.9	4.6
Common shareholders' equity	8,929.8	8,654.8
Preferred stock of subsidiary	30.4	30.4
Total liabilities and equity	$ 30,123.2	$ 29,355.2

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Accounts receivable and unbilled revenues, reserves	$ 108	$ 113.3
Property, plant, and equipment, accumulated depreciation	$ 8,214.6	$ 7,919.1
Common stock, par value	$ 0.01
Common stock, shares authorized	325,000,000
Common stock, shares outstanding	315,614,941	315,683,496

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating activities
Net income	$ 940.2	$ 640.3	$ 589.5
Reconciliation to cash provided by operating activities
Depreciation and amortization	762.6	583.5	417
Deferred income taxes and investment tax credits, net	493.8	418.7	328.1
Contributions and payments related to pension and OPEB plans	(28.7)	(121)	(13.9)
Equity income in transmission affiliate, net of distributions	(46.6)	(11)	(8.5)
Change in -
Accounts receivable and unbilled revenues	(180.7)	84	80.7
Materials, supplies, and inventories	100	(69.4)	(71.2)
Other current assets	103.1	(27.2)	(13.9)
Accounts payable	34.4	(9.3)	23.7
Other current liabilities	(20.8)	14.1	(45.3)
Other, net	(53.8)	(209.1)	(87.3)
Net cash provided by operating activities	2,103.5	1,293.6	1,198.9
Investing Activities
Capital expenditures	(1,423.7)	(1,266.2)	(761.2)
Business acquisition, net of cash acquired	0	(1,329.9)	0
Cash acquired from business acquisition	156.3
Capital contributions to transmission affiliate	(42.3)	(8.7)	(13.1)
Proceeds from the sale of assets and businesses	166.3	28.9	13.9
Withdrawal of restricted cash from Rabbi Trust for qualifying payments	26.6	1.4	0
Other, net	3	57	3.6
Net cash used in investing activities	(1,270.1)	(2,517.5)	(756.8)
Financing Activities
Exercise of stock options	41.6	30.1	50.3
Purchase of common stock	(108)	(74.7)	(123.2)
Dividends paid on common stock	(624.9)	(455.4)	(352)
Redemption of WPS preferred stock	0	(52.7)	0
Issuance of long-term debt	400	2,150	250
Retirement of long-term debt	(306)	(529.6)	(324.3)
Change in short-term debt	(234.8)	163	80.2
Other, net	(13.6)	(18.9)	12.8
Net cash (used in) provided by financing activities	(845.7)	1,211.8	(406.2)
Net change in cash and cash equivalents	(12.3)	(12.1)	35.9
Cash and cash equivalents at beginning of year	49.8	61.9	26
Cash and cash equivalents at end of year	$ 37.5	$ 49.8	$ 61.9

Consolidated Statements of Equi

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
Balance at Dec. 31, 2013	$ 4,263.4	$ 4,233	$ 2.3	$ 349.7	$ 3,880.7	$ 0.3	$ 30.4
Equity
Net income attributed to common shareholders	588.3	588.3	0	0	588.3	0	0
Other comprehensive income (loss)	0
Common stock dividends	(352)	(352)	0	0	(352)	0	0
Exercise of stock options	50.3	50.3	0	50.3	0	0	0
Purchase of common stock	(123.2)	(123.2)	0	(123.2)	0	0	0
Stock-based compensation and other	23.3	23.3	0	23.3	0	0	0
Balance at Dec. 31, 2014	4,450.1	4,419.7	2.3	300.1	4,117	0.3	30.4
Equity
Net income attributed to common shareholders	638.5	638.5	0	0	638.5	0	0
Other comprehensive income (loss)	4.3	4.3	0	0	0	4.3	0
Common stock dividends	(455.4)	(455.4)	0	0	(455.4)	0	0
Exercise of stock options	30.1	30.1	0	30.1	0	0	0
Issuance of common stock for the acquisition of Integrys	4,072.9	4,072.9	0.9	4,072	0	0	0
Purchase of common stock	(74.7)	(74.7)	0	(74.7)	0	0	0
Addition of WPS preferred stock	51.1	0	0	0	0	0	51.1
Redemption of WPS preferred stock	(52.7)	(1.6)	0	(1.6)	0	0	(51.1)
Stock-based compensation and other	21	21	0	21.3	(0.3)	0	0
Balance at Dec. 31, 2015	8,685.2	8,654.8	3.2	4,347.2	4,299.8	4.6	30.4
Equity
Net income attributed to common shareholders	939	939	0	0	939	0	0
Other comprehensive income (loss)	(1.7)	(1.7)	0	0	0	(1.7)	0
Common stock dividends	(624.9)	(624.9)	0	0	(624.9)	0	0
Exercise of stock options	41.6	41.6	0	41.6	0	0	0
Purchase of common stock	(108)	(108)	0	(108)	0	0	0
Stock-based compensation and other	29	29	0	29	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

Consolidated Statements of Equ9

Consolidated Statements of Equity (Parenthetical) - $ / shares	3 Months Ended				12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Stockholders' Equity [Abstract]
Dividends per share (in dollars per share)	$ 0.4950	$ 0.4950	$ 0.4950	$ 0.4950	$ 1.98	$ 1.74	$ 1.56

Consolidated Statements of Capi

Consolidated Statements of Capitalization - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Common equity	$ 8,960.2	$ 8,685.2
Preferred stock of subsidiary	30.4	30.4
Obligations under capital leases	29.6	59.9
Total	9,352	9,314.6
Integrys acquisition fair value adjustment	33.3	41.1
Unamortized debt issuance costs	(38.1)	(37.8)
Unamortized discount, net and other	31.8	36.1
Total long-term debt, including current portion	9,315.4	9,281.8
Current portion of long-term debt and capital lease obligations	(157.2)	(157.7)
Total long-term debt	9,158.2	9,124.1
Total long-term capitalization	$ 18,118.4	$ 17,809.3
WEC Senior Notes due June 15, 2018 [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.65%
WEC Senior Notes due June 15, 2020 [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.45%
WEC Senior Notes due June 15, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.55%
Notes (unsecured), 6.20% due 2033 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.20%
Junior Notes (unsecured), 6.25% due 2067 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.25%
Debentures (unsecured), 1.70% due 2018 [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.70%
Debentures (unsecured), 4.25% due 2019 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.25%
Debentures (unsecured) 2.95% due 2021 [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.95%
Wis Elec Debenture due June 1, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.10%
Debentures (unsecured), 6-1/2% due 2028 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debentures (unsecured), 5.625% due 2033 [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.625%
Debentures (unsecured), 5.70% due 2036 [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.70%
Debentures (unsecured), 3.65% due 2042 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.65%
Debentures (unsecured), 4.25% due 2044 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.25%
Wis Elec Debenture due December 15, 2045 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.30%
Debentures (unsecured), 6-7/8% due 2095 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.875%
Long Term Debt 5.65 Percent Series, Due 2017 [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.65%
Long Term Debt 1.65% Series, Due 2018 [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.65%
Long Term Debt 6.08 Percent Series, Due 2028 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.08%
Long Term Debt 5.55 Percent Series, Due 2036 [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.55%
Long Term Debt 3.671% Series, Year Due, 2042 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.671%
Long Term debt 4.752% Series, Year Due 2044 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.752%
Wis Gas Debenture due September 30, 2025 [Member] [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.53%
Debentures (unsecured), 5.90% due 2035 [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.90%
Debentures (unsecured), 3.71% due 2046 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.71%
Fixed First and Refunding Mortgage XX Series 2.21 Percent Bonds, Due 2016 [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.21%
Fixed First and Refunding Mortgage TT Series 8 Percent Bonds, Due 2018 [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.00%
Fixed First and Refunding Mortgage UU Series 4.63 Percent Bonds, Due 2019 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.63%
Fixed First and Refunding Mortgage VV Series 3.900 Percent Bonds, Due 2030 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.90%
Fixed First and Refunding Mortgage WW Series 1.875 Percent Bonds, Due 2033 [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.875%
First and Refunding Mortgage Bonds, Series ZZ, 4.0% bonds due 2033 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.00%
Fixed First and Refunding Mortgage RR Series 4.3 Percent Bonds, Due 2035 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.30%
Fixed First and Refunding Mortgage YY Series 3.98 Percent Bonds Due 2042 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.98%
First and Refunding Mortgage Bonds, Series AAA, 3.96% bonds due 2043 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.96%
First and Refunding Mortgage Bonds, Series BBB, 4.21% bonds due 2044 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.21%
Bonds, Series CCC, 3.65%, due 2046 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.65%
Bonds, Series DDD, 3.65%, due 2046 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.65%
First Mortgage Bonds P Series 3.43 Percent Bonds [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.43%
First Mortgage Series Q, 3.96% bonds due 2043 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.96%
Notes (secured, nonrecourse), 4.91% due 2015-2030 [Member] [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.91%
Notes (secured, nonrecourse), 5.209% due 2015-2030 [Member] [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.209%
Notes (secured, nonrecourse), 4.673% due 2015-2031 [Member] [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.673%
Notes (secured, nonrecourse), 6.00% due 2015-2033 [Member] [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.00%
Notes (secured, nonrecourse), 6.09% due 2030-2040 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.09%
Notes (secured, nonrecourse), 5.848% due 2031-2041 [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.848%
Notes (unsecured), 6.94% due 2028 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.94%
Unsecured Senior Notes 8 Percent, Due 2016 [Member]
Debt Instrument, Interest Rate, Stated Percentage	8.00%
Unsecured Senior Notes 4.17 Percent, Due 2020 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.17%
TEG Junior Subordinated Notes, 6.11% due 2066 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.05%	6.11%
TEG Junior Subordinated Notes, 6.00% due 2073 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.00%
Notes (secured, nonrecourse), 4.81% effective rate due 2030 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.81%
WEC Energy Group
Common equity	$ 8,929.8	$ 8,654.8
WEC Energy Group | WEC Senior Notes due June 15, 2018 [Member]
Long-Term debt, Unsecured	300	300
WEC Energy Group | WEC Senior Notes due June 15, 2020 [Member]
Long-Term debt, Unsecured	400	400
WEC Energy Group | WEC Senior Notes due June 15, 2025 [Member]
Long-Term debt, Unsecured	$ 500	500
WEC Energy Group | Notes (unsecured), 6.20% due 2033 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.20%
Long-Term debt, Unsecured	$ 200	200
WEC Energy Group | Junior Notes (unsecured), 6.25% due 2067 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.25%
Long-Term debt, Unsecured	$ 500	500
WE | Debentures (unsecured), 1.70% due 2018 [Member]
Long-Term debt, Unsecured	250	250
WE | Debentures (unsecured), 4.25% due 2019 [Member]
Long-Term debt, Unsecured	250	250
WE | Debentures (unsecured) 2.95% due 2021 [Member]
Long-Term debt, Unsecured	300	300
WE | Wis Elec Debenture due June 1, 2025 [Member]
Long-Term debt, Unsecured	250	250
WE | Debentures (unsecured), 6-1/2% due 2028 [Member]
Long-Term debt, Unsecured	150	150
WE | Debentures (unsecured), 5.625% due 2033 [Member]
Long-Term debt, Unsecured	335	335
WE | Debentures (unsecured), 5.70% due 2036 [Member]
Long-Term debt, Unsecured	300	300
WE | Debentures (unsecured), 3.65% due 2042 [Member]
Long-Term debt, Unsecured	250	250
WE | Debentures (unsecured), 4.25% due 2044 [Member]
Long-Term debt, Unsecured	250	250
WE | Wis Elec Debenture due December 15, 2045 [Member]
Long-Term debt, Unsecured	250	250
WE | Debentures (unsecured), 6-7/8% due 2095 [Member]
Long-Term debt, Unsecured	100	100
WG | Wis Gas Debenture due September 30, 2025 [Member] [Member]
Long-Term debt, Unsecured	200	200
WG | Debentures (unsecured), 5.90% due 2035 [Member]
Long-Term debt, Unsecured	90	90
WG | Debentures (unsecured), 3.71% due 2046 [Member]
Long-Term debt, Unsecured	200	0
WPS | Long Term Debt 5.65 Percent Series, Due 2017 [Member]
Long-Term debt, Unsecured	125	125
WPS | Long Term Debt 1.65% Series, Due 2018 [Member]
Long-Term debt, Unsecured	250	250
WPS | Long Term Debt 6.08 Percent Series, Due 2028 [Member]
Long-Term debt, Unsecured	50	50
WPS | Long Term Debt 5.55 Percent Series, Due 2036 [Member]
Long-Term debt, Unsecured	125	125
WPS | Long Term Debt 3.671% Series, Year Due, 2042 [Member]
Long-Term debt, Unsecured	300	300
WPS | Long Term debt 4.752% Series, Year Due 2044 [Member]
Long-Term debt, Unsecured	450	450
PGL | Fixed First and Refunding Mortgage XX Series 2.21 Percent Bonds, Due 2016 [Member]
Long-Term debt, Secured	0	50
PGL | Fixed First and Refunding Mortgage TT Series 8 Percent Bonds, Due 2018 [Member]
Long-Term debt, Secured	5	5
PGL | Fixed First and Refunding Mortgage UU Series 4.63 Percent Bonds, Due 2019 [Member]
Long-Term debt, Secured	75	75
PGL | Fixed First and Refunding Mortgage VV Series 3.900 Percent Bonds, Due 2030 [Member]
Long-Term debt, Secured	50	50
PGL | Fixed First and Refunding Mortgage WW Series 1.875 Percent Bonds, Due 2033 [Member]
Long-Term debt, Secured	50	50
PGL | First and Refunding Mortgage Bonds, Series ZZ, 4.0% bonds due 2033 [Member]
Long-Term debt, Secured	50	50
PGL | Fixed First and Refunding Mortgage RR Series 4.3 Percent Bonds, Due 2035 [Member]
Long-Term debt, Secured	0	50
PGL | Fixed First and Refunding Mortgage YY Series 3.98 Percent Bonds Due 2042 [Member]
Long-Term debt, Secured	100	100
PGL | First and Refunding Mortgage Bonds, Series AAA, 3.96% bonds due 2043 [Member]
Long-Term debt, Secured	220	220
PGL | First and Refunding Mortgage Bonds, Series BBB, 4.21% bonds due 2044 [Member]
Long-Term debt, Secured	200	200
PGL | Bonds, Series CCC, 3.65%, due 2046 [Member]
Long-Term debt, Secured	50	0
PGL | Bonds, Series DDD, 3.65%, due 2046 [Member]
Long-Term debt, Secured	150	0
NSG | First Mortgage Bonds P Series 3.43 Percent Bonds [Member]
Long-Term debt, Secured	28	28
NSG | First Mortgage Series Q, 3.96% bonds due 2043 [Member]
Long-Term debt, Secured	$ 54	54
We Power | Notes (secured, nonrecourse), 4.91% due 2015-2030 [Member] [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.91%
Long-Term debt, Secured	$ 106.7	112.1
We Power | Notes (secured, nonrecourse), 5.209% due 2015-2030 [Member] [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.209%
Long-Term debt, Secured	$ 204.8	215
We Power | Notes (secured, nonrecourse), 4.673% due 2015-2031 [Member] [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.673%
Long-Term debt, Secured	$ 170.9	178.3
We Power | Notes (secured, nonrecourse), 6.00% due 2015-2033 [Member] [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.00%
Long-Term debt, Secured	$ 126.1	130.5
We Power | Notes (secured, nonrecourse), 6.09% due 2030-2040 [Member]
Long-Term debt, Secured	275	275
We Power | Notes (secured, nonrecourse), 5.848% due 2031-2041 [Member]
Long-Term debt, Secured	215	215
WECC | Notes (unsecured), 6.94% due 2028 [Member]
Long-Term debt, Unsecured	50	50
Integrys Holding Inc | Unsecured Senior Notes 8 Percent, Due 2016 [Member]
Long-Term debt, Unsecured	0	50
Integrys Holding Inc | Unsecured Senior Notes 4.17 Percent, Due 2020 [Member]
Long-Term debt, Unsecured	250	250
Integrys Holding Inc | TEG Junior Subordinated Notes, 6.11% due 2066 [Member]
Long-Term debt, Unsecured	$ 114.9	269.8
Integrys Holding Inc | TEG Junior Subordinated Notes, 6.00% due 2073 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.00%
Long-Term debt, Unsecured	$ 400	400
Bostco | Notes (secured, nonrecourse), 4.81% effective rate due 2030 [Member]
Long-Term debt, Secured	2	2
Total Common Shareholders' Equity
Common equity	$ 8,929.8	$ 8,654.8

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a) General Information —On June 29, 2015, Wisconsin Energy Corporation acquired Integrys and changed its name to WEC Energy Group, Inc. WEC Energy Group serves approximately 1.6 million electric customers and 2.8 million natural gas customers, and it owns approximately 60% of ATC. See Note 2, Acquisitions, for more information on this acquisition. As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, statements of equity, and statements of capitalization, unless otherwise noted. Our financial statements include the accounts of WEC Energy Group, a diversified energy holding company, and the accounts of our subsidiaries in the following reportable segments: • Wisconsin segment – Consists of WE, WG, and WPS, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin. WE's electric and WPS's electric and natural gas operations in the state of Michigan are also included in this segment. • Illinois segment – Consists of PGL and NSG, which are engaged primarily in the distribution of natural gas in Illinois. • Other states segment – Consists of MERC and MGU, which are engaged primarily in the distribution of natural gas in Minnesota and Michigan, respectively. • Electric transmission segment – Consists of our approximate 60% ownership interest in ATC, a federally regulated electric transmission company. • We Power segment – Consists of We Power, which is principally engaged in the ownership of electric power generating facilities for long-term lease to WE. • Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, WECC, WBS, PDL, Wisvest and ITF. The sale of ITF was completed in the first quarter of 2016. In the second quarter of 2016, we sold certain assets of Wisvest. See Note 3, Dispositions, for more information on these sales. Our financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly Owned Facilities, for more information . The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates. (b) Balance Sheet Presentation — To be consistent with the current year presentation, we changed our December 31, 2015 balance sheet from a utility format to a traditional format. This change revised the order of certain balance sheet line items, but it did not result in any change to the classification of amounts between line items. (c) Cash and Cash Equivalents —Cash and cash equivalents include marketable debt securities with an original maturity of three months or less. (d) Revenues and Customer Receivables —We recognize revenues related to the sale of energy on the accrual basis and include estimated amounts for services provided but not yet billed to customers. We present revenues net of pass-through taxes on the income statements. Below is a summary of the significant mechanisms our utility subsidiaries had in place that allowed them to recover or refund changes in prudently incurred costs from rate case-approved amounts: • Fuel and purchased power costs were recovered from customers on a one-for-one basis by our Wisconsin wholesale electric operations and our Michigan retail electric operations. • Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. Our electric utilities monitor the deferral of under-collected costs to ensure that it does not cause them to earn a greater ROE than authorized by the PSCW. • WE received payments from MISO under an SSR agreement for its PIPP units through February 1, 2015. We recorded revenue for these payments to recover costs for operating and maintaining these units. See Note 22, Regulatory Environment , for more information. • The rates for all of our natural gas utilities included one-for-one recovery mechanisms for natural gas commodity costs. We defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. • The rates of PGL and NSG included riders for cost recovery of both environmental cleanup costs and energy conservation and management program costs. • MERC's rates included a conservation improvement program rider for cost recovery of energy conservation and management program costs as well as a financial incentive for meeting energy savings goals. • The rates of PGL and NSG, and the residential rates of WE and WG, included riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. • The rates of PGL, NSG, MERC, and MGU included decoupling mechanisms. These mechanisms differ by state and allow utilities to recover or refund differences between actual and authorized margins. MGU's decoupling mechanism was discontinued after December 31, 2015. See Note 22, Regulatory Environment, for more information . • PGL's rates included a cost recovery mechanism for SMP costs. Revenues are also impacted by other accounting policies related to PGL's natural gas hub and our electric utilities' participation in the MISO Energy Markets. Amounts collected from PGL's wholesale customers that use the natural gas hub are credited to natural gas costs, resulting in a reduction to retail customers' charges for natural gas and services. Our electric utilities sell and purchase power in the MISO Energy Markets, which operate under both day-ahead and real-time markets. We record energy transactions in the MISO Energy Markets on a net basis for each hour. If our electric utilities were a net seller in a particular hour, the net amount was reported as operating revenues. If our electric utilities were a net purchaser in a particular hour, the net amount was recorded as cost of sales on our income statements. We provide regulated electric service to customers in Wisconsin and Michigan and regulated natural gas service to customers in Wisconsin, Illinois, Minnesota, and Michigan. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Credit risk exposure at WE, WG, PGL, and NSG is mitigated by their recovery mechanisms for uncollectible expense discussed above. As a result, we did not have any significant concentrations of credit risk at December 31, 2016 . In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2016 . (e) Materials, Supplies, and Inventories — Our inventory as of December 31 consisted of: (in millions) 2016 2015 Natural gas in storage $ 223.1 $ 284.1 Materials and supplies 206.5 219.2 Fossil fuel 158.0 183.7 Total $ 587.6 $ 687.0 PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. Inventories stated on a LIFO basis represented approximately 18% of total inventories at December 31, 2016 and 2015 . The estimated replacement cost of natural gas in inventory at December 31, 2016 and 2015 , exceeded the LIFO cost by $92.9 million and $15.2 million , respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $3.63 at December 31, 2016 , and $2.48 at December 31, 2015 . Substantially all other natural gas in storage, materials and supplies, and fossil fuel inventories are recorded using the weighted-average cost method of accounting. (f) Investments Held in Rabbi Trust — Integrys has a rabbi trust that is 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 trust holds investments that are classified as trading securities for accounting purposes. As we do not intend to sell the investments in the near term, they are included in other long-term assets on our balance sheets. The net unrealized gains and losses included in earnings related to the investments held at the end of the period were not significant for the years ended December 31, 2016 and 2015. (g) Regulatory Assets and Liabilities —The economic effects of regulation can result in regulated companies recording costs and revenues that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future revenues associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts that are collected in rates for future costs. Recovery or refund of regulatory assets and liabilities is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to which they relate. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the reporting period the determination is made. See Note 6, Regulatory Assets and Liabilities, for more information . (h) Property, Plant, and Equipment — We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below: Annual Utility Composite Depreciation Rates 2016 2015 2014 WE 3.00% 3.01% 2.93% WPS * 2.58% 1.30% N/A WG 2.34% 2.36% 2.69% PGL * 3.31% 1.67% N/A NSG * 2.44% 1.22% N/A MERC * 2.53% 1.26% N/A MGU * 2.63% 1.32% N/A * The rates shown for 2015 are for a partial year as a result of the acquisition of Integrys. The full year rate would be approximately double the rate shown. We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2 and 10 to 55 years for ER 1 and ER 2. We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement. (i) Allowance for Funds Used During Construction — AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC – Debt) used during plant construction, and a return on stockholders' capital (AFUDC – Equity) used for construction purposes. AFUDC – Debt is recorded as a reduction of interest expense, and AFUDC – Equity is recorded in other income, net. The majority of AFUDC is recorded at WE, WPS, and WG. Approximately 50% of WE's, WPS's, and WG's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. The AFUDC calculation for WBS uses the WPS AFUDC retail rate, while the other utilities AFUDC rates are determined by their respective state commissions, each with specific requirements. Based on these requirements, the other utilities and WBS did not record significant AFUDC for 2016 , 2015 , or 2014 . Average AFUDC rates are shown below: 2016 Average AFUDC Retail Rate Average AFUDC Wholesale Rate WE 8.45% 2.73% WPS 7.72% 3.00% WG 8.33% N/A Our regulated utilities recorded the following AFUDC for the years ended December 31: (in millions) 2016 2015 2014 AFUDC – Debt $ 10.9 $ 8.6 $ 2.3 AFUDC – Equity $ 25.1 $ 20.1 $ 5.6 (j) Asset Impairment —Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. Intangible assets with definite lives are reviewed for impairment on a quarterly basis. Other long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset. Due to the acquisition of Integrys, we changed the date of our annual goodwill impairment test from August 31 to July 1. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value. See Note 10, Goodwill, for more information . The carrying amounts of cost and equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts, if a fair value assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value. (k) Deferred Revenue — As part of the construction of We Power's electric generating units, we capitalized interest during construction. As allowed under the lease agreements, we were able to collect the carrying costs during the construction of these generating units from our utility customers. The carrying costs that we collected during construction have been recorded as deferred revenue on our balance sheets and we are amortizing the deferred carrying costs to revenue over the individual lease terms. (l) Asset Retirement Obligations —We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted to their present values each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated retirement costs. For our regulated entities, we recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 9, Asset Retirement Obligations, for more information . (m) Environmental Remediation Costs —We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 9, Asset Retirement Obligations, for more information regarding coal combustion product landfill sites and Note 18, Commitments and Contingencies , for more information regarding manufactured gas plant sites. We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation. Our utilities have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the applicable state Commission's approval. We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion product landfill sites. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year. (n) Income Taxes —We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense. Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We file a consolidated Federal income tax return. Accordingly, we allocate Federal current tax expense benefits and credits to our subsidiaries based on their separate tax computations. See Note 15, Income Taxes, for more information . We recognize interest and penalties accrued, related to unrecognized tax benefits, in income tax expense in our income statements. (o) Guarantees — We follow the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. See Note 16, Guarantees, for more information . (p) Employee Benefits —The costs of pension and OPEB are expensed over the periods during which employees render service. These costs are allocated among our subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the utilities' net periodic benefit cost calculated under GAAP. See Note 17, Employee Benefits, for more information . (q) Stock-Based Compensation — In accordance with the shareholder approved Omnibus Stock Incentive Plan, we provide long-term incentives through our equity interests to our non-employee directors, officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in common stock, cash, or a combination thereof. The number of shares of common stock authorized for issuance under the plan is 34.3 million . We recognize stock-based compensation expense on a straight-line basis over the requisite service period. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period based on our estimate of the final expected value of the awards. Stock Options We grant non-qualified stock options that vest on a cliff-basis after a three -year period. The exercise price of a stock option under the plan cannot be less than 100% of our common stock's fair market value on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of our common stock on the date of the grant. Options may not be exercised within six months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of the grant. Our stock options are classified as equity awards. The fair value of our stock options was calculated using a binomial option-pricing model. The following table shows the estimated fair value per stock option granted along with the weighted-average assumptions used in the valuation models: 2016 2015 2014 Non-qualified stock options granted 794,764 516,475 899,500 Estimated fair value per non-qualified stock option $ 5.14 $ 5.29 $ 4.18 Assumptions used to value the options: Risk-free interest rate 0.4% – 2.2% 0.1% – 2.1% 0.1% – 3.0% Dividend yield 4.0 % 3.7 % 3.8 % Expected volatility 18.1 % 18.0 % 18.0 % Expected life (years) 6.1 5.8 5.8 The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on our current dividend rate and historical stock prices. Expected volatility and expected life assumptions were based on our historical experience. Restricted Shares Restricted shares have a three -year vesting period, and generally, one-third of the award vests on each anniversary of the grant date. Our restricted shares are classified as equity awards. Performance Units Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on our total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over a three -year period, and beginning in 2017, other performance metrics as determined by the Compensation Committee. Under the terms of the award, participants may earn between 0% and 175% of the performance unit award, as adjusted pursuant to the terms of the plan. All grants are settled in cash and are accounted for as liability awards accordingly. Stock-based compensation costs are recorded over the three -year performance period. See Note 11, Common Equity, for more information on our stock-based compensation plans. (r) Earnings Per Share — We compute basic earnings per share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. The calculation of diluted earnings per share for the years ended December 31, 2016 and 2015 excluded 181,709 and 516,475 stock options, respectively, that had an anti-dilutive effect. There were no securities that had an anti-dilutive effect for the year ended December 31, 2014. (s) Fair Value Measurements —Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. Derivatives were transferred between levels of the fair value hierarchy primarily due to observable pricing becoming available. We recognize transfers at their value as of the end of the reporting period. Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a dividend discount model. The fair value of our long-term debt is estimated based upon the quoted market value for the same issue, similar issues, or upon the quoted market prices of United States Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows. The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy. See Note 19, Fair Value Measurements, for more information . (t) Derivative Instruments —We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators. We record derivative instruments on our balance sheets as assets or liabilities 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. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Realized gains and losses on derivative instruments are primarily recorded in cost of sales on the income statements. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows. Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current liabilities. See Note 20, Derivative Instruments, for more information . (u) Customer Deposits and Credit Balances —When utility customers apply for new service, they may be required to provide a deposit for the service. Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within current liabilities on our balance sheets.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
ACQUISITIONS	ACQUISITIONS Acquisition of Integrys On June 29, 2015, Wisconsin Energy Corporation acquired 100% of the outstanding common shares of Integrys and changed its name to WEC Energy Group, Inc. Integrys is a provider of regulated natural gas and electricity, as well as nonregulated renewable energy products and services. Integrys also provided CNG products and services prior to the sale of ITF in the first quarter of 2016. Integrys holds a 34% interest in ATC, a for-profit transmission company regulated by the FERC. The acquisition of Integrys has provided increased scale, operating efficiencies, and the potential for long-term cost savings through a combination of lower capital and operating costs. Purchase Price Pursuant to the Merger Agreement, Integrys’s shareholders received 1.128 shares of Wisconsin Energy Corporation common stock and $18.58 in cash per share of Integrys common stock. The total consideration transferred was based on the closing price of Wisconsin Energy Corporation common stock on June 29, 2015, and was calculated as follows: Consideration Paid (in millions, except per share amounts) Stock Cash Total Integrys common shares outstanding at June 29, 2015 79,963,091 79,963,091 Exchange ratio 1.128 Wisconsin Energy Corporation shares issued for Integrys shares * 90,187,884 Closing price of Wisconsin Energy Corporation common shares on June 29, 2015 $45.16 Fair value of common stock issued $ 4,072.9 $ 4,072.9 Cash paid per share of Integrys shares outstanding $18.58 Fair value of cash paid for Integrys shares * $ 1,486.2 $ 1,486.2 Consideration attributable to settlement of equity awards, net of tax $ 24.0 $ 24.0 Total purchase price $ 4,072.9 $ 1,510.2 $ 5,583.1 * Fractional shares of 10,483 totaling $0.5 million were paid in cash. All Integrys unvested stock-based compensation awards became fully vested upon the close of the acquisition and were either paid to award recipients in cash, or the value of the awards was deferred into a deferred compensation plan. In addition, all vested but unexercised Integrys stock options were paid in cash. In accordance with accounting guidance for business combinations, the acceleration of the vesting was recorded as an acquisition-related expense. Allocation of Purchase Price The Integrys assets acquired and liabilities assumed were measured at estimated fair value in accordance with the accounting guidance under the Business Combinations Topic in the FASB ASC. Substantially all of Integrys's operations are subject to the rate-setting authority of federal and state regulatory commissions. These operations are accounted for following the accounting guidance under the Regulated Operations Topic of the FASB ASC. The underlying assets and liabilities of ATC are also regulated by the FERC. Integrys's assets and liabilities that are subject to rate-setting provisions provide revenues derived from costs, including a return on investment of assets less liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the pro forma financial information, reflect any adjustments related to these amounts. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. The goodwill reflects the value paid for the increased scale and efficiencies as a result of the combination. The goodwill recognized is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to goodwill. See Note 10, Goodwill , for the allocation of goodwill to our reportable segments. During the first six months of 2016, adjustments were made to the estimated fair values of the assets acquired and liabilities assumed, primarily in connection with the sale of ITF and reserves recorded for likely settlements of certain legal and regulatory matters. The table below shows the final allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition: (in millions) Current assets $ 1,060.1 Property, plant, and equipment, net 7,107.4 Goodwill 2,604.3 Other long-term assets * 2,830.5 Current liabilities (1,320.7 ) Long-term debt (2,943.6 ) Other long-term liabilities (3,703.8 ) Preferred stock of subsidiary (51.1 ) Total purchase price $ 5,583.1 * Includes equity method goodwill related to Integrys's investment in ATC. See Note 4, Investment in American Transmission Company, for more information . In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments, which requires that an acquirer recognize and disclose adjustments to provisional amounts that are identified during an acquisition measurement period in the reporting period in which the adjustment amounts are determined. ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. Early adoption was permitted for any interim and annual financial statements that had not yet been issued. We early adopted ASU 2015-16 in the fourth quarter of 2015. Adoption had no impact on our financial statements. Conditions of Approval The acquisition was subject to the approvals of various government agencies, including the FERC, Federal Communications Commission, PSCW, ICC, MPSC, and MPUC. Approvals were obtained from all agencies subject to several conditions. The PSCW order includes the following conditions: • WE and WG are each subject to an earnings sharing mechanism for three years beginning January 1, 2016. Under the earnings sharing mechanisms, if either company earns above its authorized return, 50% of the first 50 basis points of additional utility earnings will be shared with customers. For WE, the additional utility earnings will be used to reduce the company’s transmission escrow. For WG, additional utility earnings will be used to reduce the costs of the Western Gas Lateral that would otherwise be included in rates. All utility earnings above the first 50 basis points will be used to reduce the transmission escrow for WE and reduce the costs of the Western Gas Lateral that would otherwise be included in rates for WG. For the year ended December 31, 2016, WE and WG recorded a combined $24.4 million of expense related to these earnings sharing mechanisms. • Any future electric generation projects affecting Wisconsin ratepayers submitted by us or our subsidiaries will first consider the extent to which existing intercompany resources can meet energy and capacity needs. In September 2015, WPS and WE filed a joint integrated resource plan with the PSCW for their combined loads, which indicated that no new generation is currently needed. The ICC order includes a base rate freeze for PGL and NSG effective for two years after the close of the acquisition. This base rate freeze does not impact PGL's or NSG's ability to adjust rates through various riders or GCRMs. We do not believe that the conditions set forth in the various regulatory orders approving the acquisition will have a material impact on our operations or financial results. Pro Forma Information The following unaudited pro forma financial information reflects the consolidated results and amortization of purchase price adjustments as if the acquisition had taken place on January 1, 2014. The unaudited pro forma financial information is presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or our future consolidated results. The pro forma financial information does not reflect any potential cost savings from operating efficiencies resulting from the acquisition and does not include certain acquisition-related costs. Year Ended December 31 (in millions, except per share amounts) 2015 2014 Unaudited pro forma financial information Operating revenues $ 7,727.1 $ 9,135.4 Net income attributed to common shareholders $ 873.5 $ 869.9 Earnings per share (Basic) $ 2.77 $ 2.76 Earnings per share (Diluted) $ 2.75 $ 2.74 Impact of Acquisition As a result of the acquisition, our ownership of ATC increased to approximately 60% . We have made commitments with respect to our voting rights of the combined ownership of ATC, which are included as enforceable conditions in the FERC and PSCW orders approving the acquisition. Under GAAP, these commitments do not allow for the consolidation of ATC in our financial statements and the 60% ownership is accounted for as an equity method investment subsequent to the close of the acquisition. See Note 4, Investment in American Transmission Company, for more information . In connection with the acquisition, WEC Energy Group and its subsidiaries recorded pre-tax acquisition costs of $3.5 million , $107.6 million , and $12.5 million during 2016, 2015, and 2014, respectively. These costs consisted of employee-related expenses, professional fees, and other miscellaneous costs. They are primarily recorded in the other operation and maintenance line item on the income statements. Included in the 2015 acquisition costs was $24.9 million of severance expense that resulted from employee reductions related to the post-acquisition integration. Severance expense incurred during 2016 was not significant. The 2015 severance expense was recorded in the following segments: (in millions) Year ended December 31, 2015 Wisconsin $ 11.1 Illinois 0.9 Other states 0.1 Corporate and other 12.8 Total severance expense $ 24.9 Severance payments of $7.5 million and $16.9 million were made during 2016 and 2015, respectively. The severance accruals on our our balance sheets were not significant at December 31, 2016 and 2015. Our revenues for the year ended December 31, 2015 include revenues attributable to Integrys of $1,416.8 million . Included in our net income for the year ended December 31, 2015, is net income attributable to Integrys of $65.9 million . Acquisition of a Natural Gas Storage Facility in Michigan In January 2017, we signed an agreement for the acquisition of a natural gas storage facility in Michigan for $225 million that would provide approximately one-third of the storage needs for our Wisconsin natural gas utilities. In addition, we expect to incur approximately $5 million of acquisition related costs. A request has been filed with the PSCW for a declaratory ruling related to the recovery of this investment. PSCW approval and closing of this transaction are expected to occur by the third quarter of 2017.

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
DISPOSITIONS	DISPOSITIONS Wisconsin Segment Sale of Milwaukee County Power Plant In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $10.9 million ( $6.5 million after tax), which was included in other operation and maintenance on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations of this plant remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. Corporate and Other Segment Sale of Certain Assets of Wisvest In April 2016, as part of the MCPP sale transaction, we sold the chilled water generation and distribution assets of Wisvest, which are used to provide chilled water services to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $19.6 million ( $11.8 million after tax), which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. Sale of Integrys Transportation Fuels Through a series of transactions in the fourth quarter of 2015 and the first quarter of 2016, we sold ITF, a provider of CNG fueling services and a single-source provider of CNG fueling facility design, construction, operation, and maintenance. There was no gain or loss recorded on the sales, as ITF's assets and liabilities were adjusted to fair value through purchase accounting. The sale of ITF met the criteria to qualify as held for sale at December 31, 2015, but did not meet the requirements to qualify as a discontinued operation. The results of operations of ITF remained in continuing operations through the sale date as the sale of ITF did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. The pre-tax profit or loss of this component was not material through the sale date in 2016. The following table shows the carrying values of the major classes of assets and liabilities included as held for sale on our balance sheet at December 31: (in millions) 2015 Accounts receivable and unbilled revenues $ 34.9 Materials, supplies, and inventories 18.4 Other current assets 2.6 Property, plant, and equipment 37.2 Other long-term assets 3.7 Total assets $ 96.8 Accounts payable $ 12.9 Accrued payroll and benefits 2.4 Other current liabilities 4.5 Pension and OPEB obligations 1.2 Other long-term liabilities 0.6 Total liabilities * $ 21.6 * Included in other current liabilities on our balance sheet.

Investment in American Transmis

Investment in American Transmission Company	12 Months Ended
	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
INVESTMENT IN AMERICAN TRANSMISSION COMPANY	INVESTMENT IN AMERICAN TRANSMISSION COMPANY Due to the acquisition of Integrys, our ownership of ATC increased from 26.2% to approximately 60% . ATC is a for-profit, transmission-only company regulated by the FERC and certain state regulatory commissions. We have one representative on ATC's ten -member board of directors. Each member of the board has only one vote. Due to voting requirements, no individual board member has more than 10% of the voting control. The following table shows changes to our investment in ATC during the years ended December 31: (in millions) 2016 2015 2014 Balance at beginning of period $ 1,380.9 $ 424.1 $ 402.7 Add: Earnings from equity method investment 146.5 96.1 66.0 Add: Capital contributions 42.3 8.7 13.1 Add: Acquisition of Integrys's investment in ATC (1.0 ) 541.5 — Add: Equity method goodwill from the acquisition of Integrys (1) 10.4 395.8 — Less: Distributions 135.1 (2) 85.1 57.5 Less: Other 0.1 0.2 0.2 Balance at end of period $ 1,443.9 $ 1,380.9 $ 424.1 (1) Represents the purchase price allocated to Integrys's investment in ATC in excess of the recorded value. (2) Of this amount, $35.2 million was recorded as a receivable at December 31, 2016. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which are reimbursed by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service. The following table summarizes our significant related party transactions with ATC during the years ended December 31: (in millions) 2016 2015 2014 Charges to ATC for services and construction $ 18.5 $ 15.4 $ 8.1 Charges from ATC for network transmission services 357.3 289.2 231.4 As of December 31, 2016 and 2015 , our balance sheets included the following receivables and payables related to ATC: (in millions) 2016 2015 Accounts receivable Services provided to ATC $ 2.2 $ 1.0 Accounts payable Services received from ATC 28.7 28.3 Summarized financial data for ATC is included in the tables below: (in millions) 2016 2015 2014 Income statement data Revenues $ 650.8 $ 615.8 $ 635.0 Operating expenses 322.5 319.3 307.4 Other expense 95.5 96.1 88.9 Net income $ 232.8 $ 200.4 $ 238.7 (in millions) December 31, 2016 December 31, 2015 Balance sheet data Current assets $ 75.8 $ 80.5 Noncurrent assets 4,312.9 3,948.3 Total assets $ 4,388.7 $ 4,028.8 Current liabilities $ 495.1 $ 330.3 Long-term debt 1,865.3 1,790.7 Other noncurrent liabilities 271.5 245.0 Shareholders' equity 1,756.8 1,662.8 Total liabilities and shareholders' equity $ 4,388.7 $ 4,028.8

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION (in millions) 2016 2015 2014 Cash (paid) for interest, net of amount capitalized $ (411.9 ) $ (329.6 ) $ (241.4 ) Cash received (paid) for income taxes, net 39.7 (9.3 ) (22.0 ) Significant non-cash transactions: Accounts payable related to construction costs 170.1 177.1 1.8 Restricted cash used to purchase investments held in the rabbi trust 59.2 60.2 — Amortization of deferred revenue 24.7 39.9 55.7 Note receivable received related to the sale of AMP Trillium* — 12.0 — Capital assets received related to the sale of AMP Trillium * — 6.3 — * ITF owned a 30% interest in AMP. See Note 3, Dispositions, for more information on the sale of ITF. At December 31, 2016 and 2015 , restricted cash of $33.6 million and $118.4 million , respectively, was recorded within other long-term assets on our balance sheets. The majority of this amount was held in the Integrys rabbi trust and represents a portion of the required funding that was triggered by the announcement of the Integrys acquisition. Withdrawals of restricted cash from the rabbi trust for qualifying payments are shown as an investing activity on the statements of cash flows. Decreases in restricted cash due to the purchase of restricted investments held in the rabbi trust are reflected as non-cash transactions on the statements of cash flows and are included in the table above.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory assets and liabilities	REGULATORY ASSETS AND LIABILITIES The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2016 2015 See Note Regulatory assets (1) (2) Unrecognized pension and OPEB costs (3) $ 1,252.1 $ 1,306.4 17 Environmental remediation costs (4) 702.7 697.0 18 Income tax related items (5) 285.1 248.3 Electric transmission costs 234.1 191.5 22 SSR 188.1 86.1 22 AROs 179.2 173.0 9 We Power generation (6) 54.1 45.4 Energy efficiency programs (7) 36.7 48.7 Derivatives 17.9 70.4 1(t) Other, net 188.3 234.9 Total regulatory assets $ 3,138.3 $ 3,101.7 Balance Sheet Presentation Current assets (8) $ 50.4 $ 37.1 Regulatory assets 3,087.9 3,064.6 Total regulatory assets $ 3,138.3 $ 3,101.7 (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 the table. (2) As of December 31, 2016 , we had $32.7 million of regulatory assets not earning a return and $204.0 million of regulatory assets earning a return based on short-term interest rates. The regulatory assets not earning a return relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures. (3) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We are authorized recovery of this regulatory asset over the average remaining service life of each plan. (4) As of December 31, 2016 , we had not yet made cash expenditures for $633.6 million of these environmental remediation costs. (5) Represents adjustments related to deferred income taxes, which are recovered in rates as the temporary differences that generated the income tax benefit reverse. (6) Represents amounts recoverable from customers related to WE's costs of the generating units leased from We Power, including subsequent capital additions. (7) Represents amounts recoverable from customers related to programs at the utilities designed to meet energy efficiency standards. (8) Short-term regulatory assets are recorded in accounts receivable and unbilled revenues on our balance sheets. The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2016 2015 See Note Regulatory liabilities Removal costs (1) $ 1,262.7 $ 1,209.6 Mines deferral (2) 70.2 31.6 Energy costs refundable through rate adjustments (3) 88.7 76.9 Unrecognized pension and OPEB costs (4) 63.0 26.3 17 Derivatives 41.1 12.6 1(t) Uncollectible expense (5) 36.1 31.8 Other, net 35.4 37.2 Total regulatory liabilities $ 1,597.2 $ 1,426.0 Balance Sheet Presentation Other current liabilities $ 33.4 $ 33.8 Regulatory liabilities 1,563.8 1,392.2 Total regulatory liabilities $ 1,597.2 $ 1,426.0 (1) Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment. (2) Represents the deferral of revenues less the associated cost of sales related to sales to the mines, which were not included in the 2015 rate order. We intend to request that this deferral be applied for the benefit of Wisconsin retail electric customers in a future rate proceeding. (3) Represents energy costs that will be refunded to customers in the future. (4) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan. (5) Represents amounts refundable to customers related to our uncollectible expense tracking mechanisms and riders. These mechanisms allow us to recover or refund the difference between actual uncollectible write-offs and the amounts recovered in rates.

Property, Plant, and Equipment

Property, Plant, and Equipment	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT, AND EQUIPMENT Property, plant, and equipment consisted of the following utility and non-utility and other assets at December 31: (in millions) 2016 2015 Utility property, plant, and equipment $ 24,185.1 $ 22,803.7 Less: Accumulated depreciation 7,609.7 7,358.2 Net 16,575.4 15,445.5 CWIP 320.0 672.7 Net utility property, plant, and equipment 16,895.4 16,118.2 Non-utility and other property, plant, and equipment 3,520.3 3,482.2 Less: Accumulated depreciation 604.9 560.9 Net 2,915.4 2,921.3 CWIP 104.7 150.2 Net non-utility and other property, plant, and equipment 3,020.1 3,071.5 Total property, plant, and equipment $ 19,915.5 $ 19,189.7

Jointly Owned Facilities

Jointly Owned Facilities	12 Months Ended
	Dec. 31, 2016
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]
Jointly Owned Facilities	JOINTLY OWNED FACILITIES We Power and WPS hold joint ownership interests in certain electric generating facilities. They are entitled to their share of generating capability and output of each facility equal to their respective ownership interest. They pay their ownership share of additional construction costs and have supplied their own financing for all jointly owned projects. We Power and WPS record their proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. We Power leases its ownership interest in ER 1 and ER 2 to WE, and WE operates these units. WE and WPS record their respective share of fuel inventory purchases and operating expenses, unless specific agreements have been executed to limit their maximum exposure to additional costs. WE's and WPS's proportionate share of direct expenses for the joint operation of these plants is recorded in operating expenses in the income statements. Information related to jointly owned facilities at December 31, 2016 was as follows: We Power WPS (in millions, except for percentages and MWs) Elm Road Generating Station Units 1 and 2 Weston Unit 4 Columbia Energy Center Units 1 and 2 (2) Edgewater Unit 4 Ownership 83.34 % 70.0 % 31.8 % 31.8 % Share of rated capacity (MWs) (1) 1,056.8 373.5 334.4 98.0 In-service date 2010 and 2011 2008 1975 and 1978 1969 Property, plant, and equipment $ 2,430.8 $ 596.3 $ 417.9 $ 45.8 Accumulated depreciation $ (331.5 ) $ (170.3 ) $ (128.3 ) $ (31.7 ) CWIP $ 9.4 $ 0.2 $ 41.2 $ 0.1 (1) Based on expected capacity ratings for summer 2017 . The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. (2) Columbia Energy Center (Columbia) is jointly owned by Wisconsin Power and Light (WPL), Madison Gas and Electric (MGE), and WPS. In October 2016, WPL received an order from the PSCW approving amendments to the Columbia joint operating agreement between the parties allowing WPS and MGE to forgo certain capital expenditures at Columbia. As a result, WPL will incur these capital expenditures in exchange for a proportional increase in its ownership share of Columbia. Based upon the additional capital expenditures WPL expects to incur through June 1, 2020, WPS's ownership interest would decrease to 27.5% .

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS Our utilities have recorded AROs primarily for the removal of natural gas distribution mains and service pipes (including asbestos and polychlorinated biphenyls [PCBs]); asbestos abatement at certain generation and substation facilities, office buildings, and service centers; the removal and dismantlement of generation facilities; the dismantling of wind generation projects; the disposal of PCB-contaminated transformers; the closure of fly-ash landfills at certain generation facilities; and the removal of above ground storage tanks. Regulatory assets and liabilities are established by our utilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators. AROs have also been recorded by PDL for the removal of solar equipment components. On our balance sheets, AROs are recorded within other long-term liabilities. The following table shows changes to our AROs during the years ended December 31: (in millions) 2016 2015 2014 Balance as of January 1 $ 571.2 $ 43.6 $ 42.3 Integrys subsidiaries — 491.0 — Accretion 28.3 14.5 2.4 Additions and revisions to estimated cash flows — 35.5 * — Liabilities settled (41.8 ) (13.4 ) (1.1 ) Balance as of December 31 $ 557.7 $ 571.2 $ 43.6 * During 2015, an ARO of $16.1 million was recorded for fly-ash landfills located at generation facilities owned by WE and WPS. An ARO of $9.0 million was also recorded during 2015 for the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule passed by the EPA in April 2015. In addition, AROs increased $10.4 million in 2015 due to revisions made to estimated cash flows primarily for changes in the weighted average cost to retire natural gas distribution pipe at PGL and NSG.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2016
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 years ended December 31, 2016 and 2015 : Wisconsin Illinois Other States Total (in millions) 2016 2015 2016 2015 2016 2015 2016 2015 Goodwill balance as of January 1 $ 2,109.5 $ 441.9 $ 731.2 $ — $ 182.8 $ — $ 3,023.5 $ 441.9 Adjustment to Integrys purchase price allocation (5.2 ) — 27.5 — 0.4 — 22.7 — Acquisition of Integrys — 1,667.6 — 731.2 — 182.8 — 2,581.6 Goodwill balance as of December 31 * $ 2,104.3 $ 2,109.5 $ 758.7 $ 731.2 $ 183.2 $ 182.8 $ 3,046.2 $ 3,023.5 * We had no accumulated impairment losses related to our goodwill as of December 31, 2016 . Due to the acquisition of Integrys, we changed the date of our annual goodwill impairment test from August 31 to July 1. In the third quarter of 2016, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2016. No impairments resulted from these tests.

Common Equity

Common Equity	12 Months Ended
	Dec. 31, 2016
Stockholders' Equity Note [Abstract]
COMMON EQUITY	COMMON EQUITY Stock-Based Compensation Plans The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit for the years ended December 31: (in millions) 2016 2015 2014 Stock options $ 3.5 $ 3.3 $ 3.7 Restricted stock 5.8 7.0 2.8 Performance units 8.7 13.0 15.4 Stock-based compensation expense $ 18.0 $ 23.3 $ 21.9 Related tax benefit $ 7.2 $ 9.3 $ 8.8 Stock-based compensation costs capitalized during 2016 , 2015 , and 2014 were not significant. Stock Options The following is a summary of our stock option activity during 2016 : Stock Options Number of Options Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life (in years) Aggregate Intrinsic Value (in millions) Outstanding as of January 1, 2016 5,984,664 $ 33.47 Granted 794,764 $ 52.15 Exercised (1,644,353 ) $ 25.30 Forfeited (12,300 ) $ 52.98 Outstanding as of December 31, 2016 5,122,775 $ 38.95 6.0 $ 100.9 Exercisable as of December 31, 2016 3,710,836 $ 35.38 5.2 $ 86.4 The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2016 . This is calculated as the difference between our closing stock price on December 31, 2016 , and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2016 , 2015 , and 2014 was $55.4 million , $36.1 million , and $50.5 million , respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $22.2 million , $14.5 million , and $19.9 million , respectively. As of December 31, 2016 , the total unrecognized compensation cost related to unvested stock options was not significant. During the first quarter of 2017 , the Compensation Committee awarded 552,215 non-qualified stock options with a weighted-average exercise price of $58.31 and a weighted-average grant date fair value of $7.45 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation. Restricted Shares The following restricted stock activity occurred during 2016 : Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding as of January 1, 2016 229,018 $ 46.78 Granted 146,941 $ 53.69 Released (141,224 ) $ 46.14 Forfeited (14,689 ) $ 54.39 Outstanding as of December 31, 2016 220,046 $ 51.30 The intrinsic value of restricted stock released was $7.7 million , $3.7 million , and $2.7 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $3.1 million , $1.3 million , and $1.0 million , respectively. As of December 31, 2016 , approximately $5.1 million of unrecognized compensation cost related to restricted stock was expected to be recognized over the next 1.9 years on a weighted-average basis. During the first quarter of 2017 , the Compensation Committee awarded 82,622 restricted shares to certain of our directors, officers, and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $58.10 per share. Performance Units In 2016 , 2015 , and 2014 , the Compensation Committee awarded 297,305 ; 195,365 ; and 233,735 performance units, respectively, to officers and other key employees under the WEC Energy Group Performance Unit Plan. Performance units with an intrinsic value of $19.1 million , $13.2 million , and $14.8 million were settled during 2016 , 2015 , and 2014 , respectively. The actual tax benefit realized for the tax deductions from the distribution of performance units for the same years was approximately $6.8 million , $4.8 million , and $5.3 million , respectively. As of December 31, 2016 , approximately $10.2 million of unrecognized compensation cost related to performance units was expected to be recognized over the next 1.4 years on a weighted-average basis. During the first quarter of 2017 , we settled performance units with an intrinsic value of $6.1 million . The actual tax benefit realized from the distribution of these awards was $1.8 million . In January 2017, the Compensation Committee also awarded 237,650 performance units to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation. Restrictions Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries and our non-utility subsidiary, We Power. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of MGU, are prohibited from loaning funds to us, either directly or indirectly. In accordance with their most recent rate orders, WE, WG, and WPS may not pay common dividends above the test year forecasted amounts reflected in their respective rate cases, if it would cause their average common equity ratio, on a financial basis, to fall below their authorized levels of 51% , 49.5% , and 51% , respectively. A return of capital in excess of the test year amount can be paid by each company at the end of the year provided that their respective average common equity ratios do not fall below the authorized levels. WE may not pay common dividends to us under WE's Restated Articles of Incorporation if any dividends on its outstanding preferred stock have not been paid. In addition, pursuant to the terms of WE's 3.60% Serial Preferred Stock, WE's ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if its common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20% , respectively. NSG's long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock. WEC Energy Group and Integrys have the option to defer interest payments on their junior subordinated notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which they defer interest payments, they may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, their respective common stock. See Note 13, Short-Term Debt and Lines of Credit , for discussion of certain financial covenants related to short-term debt obligations. As of December 31, 2016 , the restricted net assets of consolidated and unconsolidated subsidiaries and our equity in undistributed earnings of investees accounted for by the equity method totaled approximately $6.3 billion . This amount exceeds 25% of our consolidated net assets as of December 31, 2016. We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future. Share Repurchase Program We have instructed our independent agents to purchase shares on the open market to fulfill obligations under various stock-based employee benefit and compensations plans and to provide shares to participants in our dividend reinvestment and stock purchase plan. As a result, no new shares of common stock were issued in 2016, 2015, or 2014, other than for the Integrys acquisition. See Note 2, Acquisitions, for more information . In December 2013, our Board of Directors authorized a share repurchase program for the purchase of up to $300.0 million of our common stock through open market purchases or privately negotiated transactions from January 1, 2014, through the end of 2017. On June 22, 2014, in connection with entering into the Merger Agreement, the Board of Directors terminated this share repurchase program. The following table identifies shares purchased during the year ended December 31 : 2016 2015 2014 (in millions) Shares Cost Shares Cost Shares Cost Under share repurchase programs — $ — — $ — 0.4 $ 18.6 To fulfill exercised stock options and restricted stock awards 1.8 108.0 1.5 74.7 2.3 104.6 Total 1.8 $ 108.0 1.5 $ 74.7 $ 2.7 $ 123.2 Common Stock Dividends During the year ended December 31, 2016 , our Board of Directors declared common stock dividends which are summarized below: Date Declared Date Payable Per Share Period January 21, 2016 March 1, 2016 $0.4950 First quarter April 21, 2016 June 1, 2016 $0.4950 Second quarter July 21, 2016 September 1, 2016 $0.4950 Third quarter October 20, 2016 December 1, 2016 $0.4950 Fourth quarter On January 19, 2017, our Board of Directors increased our quarterly dividend to $0.52 per share effective with the first quarter of 2017 dividend payment, which equates to an annual dividend of $2.08 per share. In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65 - 70% of earnings.

Preferred Stock

Preferred Stock	12 Months Ended
	Dec. 31, 2016
Class of Stock Disclosures [Abstract]
PREFERRED STOCK	PREFERRED STOCK The following table shows preferred stock authorized and outstanding at December 31, 2016 and 2015 : (in millions, except share and per share amounts) Shares Authorized Shares Outstanding Redemption Price Per Share Total WEC Energy Group $.01 par value Preferred Stock 15,000,000 — — $ — WE $100 par value, Six Per Cent. Preferred Stock 45,000 44,498 — 4.4 $100 par value, Serial Preferred Stock 2,286,500 3.60% Series 260,000 $ 101 26.0 $25 par value, Serial Preferred Stock 5,000,000 — — — WPS $100 par value, Preferred Stock 1,000,000 — — — PGL $100 par value, Cumulative Preferred Stock 430,000 — — — NSG $100 par value, Cumulative Preferred Stock 160,000 — — — Total $ 30.4

Short-Term Debt and Lines of Cr

Short-Term Debt and Lines of Credit	12 Months Ended
	Dec. 31, 2016
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 as of December 31: (in millions, except percentages) 2016 2015 Commercial paper Amount outstanding at December 31 $ 860.2 $ 1,095.0 Average interest rate on amounts outstanding at December 31 0.96 % 0.68 % Our average amount of commercial paper borrowings based on daily outstanding balances during 2016 , was $882.3 million with a weighted-average interest rate during the period of 0.66% . WEC Energy Group, WE, WPS, WG, and PGL have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require them to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70.0% , 65.0% , 65.0% , 65.0% , and 65.0% , respectively. As of December 31, 2016, all companies were in compliance with their respective ratio. As of December 31, 2016 , we had $1,620.7 million of available capacity under our bank back-up credit facilities and $860.2 million of commercial paper outstanding that was supported by the credit facilities. The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities as of December 31 : (in millions) Maturity 2016 WEC Energy Group December 2020 $ 1,050.0 WE December 2020 500.0 WPS December 2020 250.0 WG December 2020 350.0 PGL December 2020 350.0 Total short-term credit capacity $ 2,500.0 Less: Letters of credit issued inside credit facilities $ 19.1 Commercial paper outstanding 860.2 Available capacity under existing agreements $ 1,620.7 Each of these facilities has a renewal provision for two one-year extensions, subject to lender approval. The bank back-up credit facilities contain customary covenants, including certain limitations on the respective companies' ability to sell assets. The credit facilities also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults, and change of control. In addition, pursuant to the terms of our credit agreement, we must ensure that certain of our subsidiaries comply with several of the covenants contained therein.

Long-Term Debt and Capital Leas

Long-Term Debt and Capital Lease Obligations	12 Months Ended
	Dec. 31, 2016
Long-term Debt and Capital Lease Obligations [Abstract]
LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS	LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS See our statements of capitalization for details on our long-term debt. Wisconsin Gas LLC In September 2016, WG issued $200.0 million of 3.71% Debentures due September 30, 2046. The net proceeds were used to repay short-term debt. The Peoples Gas Light and Coke Company In December 2016, PGL issued $150.0 million of 3.65% Series DDD Bonds due December 15, 2046. The net proceeds were used for general corporate purposes, including capital expenditures and the refinancing of short-term debt. In November 2016, PGL issued $50.0 million of 3.65% Series CCC Bonds due December 15, 2046. The net proceeds were used to repay at maturity PGL's $50.0 million aggregate principal amount outstanding of 2.21% First and Refunding Mortgage Bonds, Series XX. In June 2016, PGL issued commercial paper to redeem at par, its $50.0 million of 4.30% Series RR First and Refunding Mortgage Bonds that were due in 2035. W.E. Power, LLC During 2017, $5.6 million of We Power's outstanding $106.7 million of 4.91% secured notes will mature. As a result, this balance was included in the current portion of long-term debt on our balance sheet at December 31, 2016. During 2017, $4.6 million of We Power's outstanding $126.1 million of 6.00% secured notes will mature. As a result, this balance was included in the current portion of long-term debt on our balance sheet at December 31, 2016. During 2017, $10.8 million of We Power's outstanding $204.8 million of 5.209% secured notes will mature. As a result, this balance was included in the current portion of long-term debt on our balance sheet at December 31, 2016. During 2017, $8.5 million of We Power's outstanding $170.9 million of 4.673% secured notes will mature. As a result, this balance was included in the current portion of long-term debt on our balance sheet at December 31, 2016. Integrys Holding, Inc. In June 2016, Integrys's $50.0 million of 8.00% unsecured senior notes matured and were repaid with contributions from WEC Energy Group, which were funded by commercial paper issued by WEC Energy Group. In February 2016, Integrys repurchased and retired $154.9 million aggregate principal amount of its 6.11% Junior Notes for a purchase price of $128.6 million , plus accrued and unpaid interest, through a modified “dutch auction” tender offer. The gain associated with this repurchase was included in other income, net on our income statement. In connection with this transaction, Integrys issued approximately $66.4 million of additional common stock to WEC Energy Group in satisfaction of its obligations under a replacement capital covenant relating to the 6.11% Junior Notes. Effective December 1, 2016, the remaining $114.9 million aggregate principal amount of the 6.11% Junior Notes bears interest at the three-month London Interbank Offered Rate (LIBOR) plus 2.12% and will reset quarterly. Bonds and Notes The following table shows the future maturities of our long-term debt outstanding (excluding obligations under capital leases) as of December 31, 2016: (in millions) Payments 2017 $ 154.5 2018 836.1 2019 357.7 2020 684.4 2021 336.2 Thereafter 6,953.5 Total $ 9,322.4 We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense. As of December 31, 2016, WE was the obligor under a series of tax-exempt pollution control refunding bonds with an outstanding principal amount of $80.0 million . In August 2009, WE terminated a letter of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. WE purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2016, the repurchased bonds were still outstanding, but were not reported in our long-term debt since they were held by WE. Depending on market conditions and other factors, WE may change the method used to determine the interest rate on this bond series and have it remarketed to third parties. A related bond series that had an outstanding principal amount of $67.0 million matured on August 1, 2016. In connection with our outstanding 2007 6.25% Series A Junior Subordinated Notes ( 6.25% Junior Notes), we executed a Replacement Capital Covenant dated May 11, 2007 (RCC), which we amended on June 29, 2015, for the benefit of persons that buy, hold, or sell a specified series of our long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease, or purchase, and that our subsidiaries may not purchase, any 6.25% Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, we have received a specified amount of proceeds from the sale of qualifying securities. Effective May 2017, the $500 million of 6.25% Junior Notes will bear interest at the three-month LIBOR plus 211.25 basis points and will reset quarterly. In connection with Integrys’s outstanding 6.11% Junior Notes, Integrys executed a Replacement Capital Covenant dated December 1, 2006, as replaced by a new Replacement Capital Covenant on December 1, 2010 (Integrys RCC) for the benefit of persons that buy, hold, or sell a specified series of its long-term indebtedness (covered debt). Integrys’s 4.17% Senior Notes due November 1, 2020, have been designated as the covered debt under the Integrys RCC. The Integrys RCC provides that Integrys may not redeem, defease, or purchase, and that its subsidiaries may not purchase, any 6.11% Junior Notes on or before December 1, 2036, unless, subject to certain limitations described in the Integrys RCC, Integrys has received a specified amount of proceeds from the sale of qualifying securities. Effective August 2023, Integrys's $400.0 million of 2013 6.00% Junior Subordinated Notes due 2073 will bear interest at the three-month LIBOR plus 322 basis points and will reset quarterly. Certain long-term debt obligations contain financial and other covenants. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations. Obligations Under Capital Leases In 1997, WE entered into a 25 -year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MW of firm capacity from a natural gas-fired cogeneration facility, includes zero minimum energy requirements. When the contract expires in 2022, WE may, at its option and with proper notice, renew for another 10 years or purchase the generating facility at fair value or allow the contract to expire. We account for this contract as a capital lease and recorded the leased facility and corresponding obligation under the capital lease at the estimated fair value of the plant's electric generating facilities. We are amortizing the leased facility on a straight-line basis over the original 25 -year term of the contract. We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as cost of sales on our income statements. We paid a total of $37.6 million and $36.2 million in lease payments during 2016 and 2015 , respectively. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our balance sheets. Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to approximately $78.5 million during 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $29.6 million as of December 31, 2016 , and will decrease to zero over the remaining life of the contract. The following is a summary of our capitalized leased facilities as of December 31: (in millions) 2016 2015 Long-term power purchase commitment $ 140.3 $ 140.3 Accumulated amortization (109.5 ) (103.9 ) Total leased facilities $ 30.8 $ 36.4 Future minimum lease payments under our capital lease and the present value of our net minimum lease payments as of December 31, 2016 are as follows: (in millions) Payments 2017 $ 13.9 2018 14.7 2019 15.5 2020 16.4 2021 17.2 Thereafter 7.6 Total minimum lease payments 85.3 Less: Estimated executory costs (39.9 ) Net minimum lease payments 45.4 Less: Interest (15.8 ) Present value of net minimum lease payments 29.6 Less: Due currently (2.7 ) Long-term obligations under capital lease $ 26.9

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Income Tax Expense The following table is a summary of income tax expense for the years ended December 31: (in millions) 2016 2015 2014 Current tax expense $ 72.7 $ 15.1 $ 33.6 Deferred income taxes, net 498.7 420.4 329.2 Investment tax credit, net (4.9 ) (1.7 ) (1.1 ) Total income tax expense $ 566.5 $ 433.8 $ 361.7 Statutory Rate Reconciliation The provision for income taxes for each of the years ended December 31 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: 2016 2015 2014 Effective Effective Effective (in millions) Amount Tax Rate Amount Tax Rate Amount Tax Rate Expected tax at statutory federal tax rates $ 526.4 35.0 % $ 375.5 35.0 % $ 332.5 35.0 % State income taxes net of federal tax benefit 72.8 4.8 % 73.1 6.8 % 50.5 5.3 % Production tax credits (15.7 ) (1.1 )% (17.4 ) (1.6 )% (17.4 ) (1.8 )% AFUDC – Equity (8.8 ) (0.6 )% (7.1 ) (0.7 )% (1.9 ) (0.2 )% Investment tax credit restored (4.9 ) (0.3 )% (1.7 ) (0.2 )% (1.1 ) (0.2 )% Other, net (3.3 ) (0.2 )% 11.4 1.1 % (0.9 ) (0.1 )% Total income tax expense $ 566.5 37.6 % $ 433.8 40.4 % $ 361.7 38.0 % Deferred Income Tax Assets and Liabilities The components of deferred income taxes as of December 31 are as follows: (in millions) 2016 2015 Deferred tax assets Future tax benefits $ 430.4 $ 382.8 Employee benefits and compensation 222.0 229.9 Deferred revenues 207.2 219.9 Property-related 54.5 59.5 Other 230.6 177.1 Total deferred tax assets 1,144.7 1,069.2 Valuation allowance (15.0 ) (17.1 ) Net deferred tax assets $ 1,129.7 $ 1,052.1 Deferred tax liabilities Property-related $ 4,979.3 $ 4,451.5 Investment in transmission affiliate 476.9 420.4 Employee benefits and compensation 401.6 428.9 Deferred transmission costs 93.1 76.7 Other 325.4 296.9 Total deferred tax liabilities 6,276.3 5,674.4 Deferred tax liability, net $ 5,146.6 $ 4,622.3 Consistent with rate-making treatment, deferred taxes in the table above are offset for temporary differences that have related regulatory assets and liabilities. The components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2016 and 2015 are summarized in the tables below: 2016 (in millions) Gross Value Deferred Tax Effect Valuation Allowance Earliest Year of Expiration Future tax benefits as of December 31, 2016 Federal net operating loss $ 407.6 $ 142.7 $ — 2031 Federal foreign tax credit — 13.5 (13.5 ) 2017 Other federal tax credit — 241.1 — 2025 Charitable contribution 9.4 4.0 (1.5 ) 2016 State net operating loss 482.6 24.3 — 2024 State tax credit — 4.8 — 2016 Balance as of December 31, 2016 $ 899.6 $ 430.4 $ (15.0 ) 2015 (in millions) Gross Value Deferred Tax Effect Valuation Allowance Earliest Year of Expiration Future tax benefits as of December 31, 2015 Federal net operating loss $ 412.3 $ 144.3 $ — 2031 Federal foreign tax credit — 15.2 (15.2 ) 2017 Other federal tax credit — 207.8 — 2025 Charitable contribution 4.7 1.9 (1.9 ) 2016 State net operating loss 185.9 9.3 — 2024 State tax credit — 4.3 — 2016 Balance as of December 31, 2015 $ 602.9 $ 382.8 $ (17.1 ) Valuation allowances of $15.0 million have been established for certain tax benefit carryforwards obtained in the Integrys acquisition based on our projected ability to realize such benefits by offsetting future tax liabilities. This is primarily the result of the extension of bonus depreciation. Realization is dependent on generating sufficient tax liabilities prior to expiration of the tax benefit carryforwards. Unrecognized Tax Benefits We previously adopted accounting guidance related to uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: (in millions) 2016 2015 Balance as of January 1 $ 9.5 $ 7.2 Acquired legacy Integrys unrecognized tax benefits — 3.6 Additions for tax positions of prior years 6.7 0.3 Additions based on tax positions related to the current year 1.1 0.2 Reductions for tax positions of prior years (1.0 ) (1.1 ) Reductions due to statute of limitations (1.8 ) — Settlements during the period — (0.7 ) Balance as of December 31 $ 14.5 $ 9.5 The amount of unrecognized tax benefits as of December 31, 2016 and 2015, excludes deferred tax assets related to uncertainty in income taxes of $6.6 million and $6.2 million , respectively. As of December 31, 2016 and 2015, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was $7.9 million and $2.2 million , respectively. We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2016 , 2015, and 2014, we recognized $0.2 million , zero , and $0.3 million of accrued interest in our income statements, respectively. For the years ended December 31, 2016 , 2015 , and 2014 , we recognized no penalties in our income statements. For the year ended December 31, 2016 , we had $0.8 million of interest accrued and no penalties accrued on our balance sheets. For the year ended December 31, 2015 , we had $0.7 million of interest accrued and $0.1 million of penalties accrued on our balance sheets. We do not anticipate any significant increases or decreases in the total amounts of unrecognized tax benefits within the next 12 months. We file income tax returns in the United States federal jurisdiction and state tax returns based on income in our major state operating jurisdictions of Wisconsin, Illinois, Michigan, and Minnesota. We also file tax returns in other state and local jurisdictions with varying statutes of limitations. As of December 31, 2016, we were subject to examination by state or local tax authorities for the 2011 through 2016 tax years in our major state operating jurisdictions as follows: Jurisdiction Years Federal 2013–2016 Illinois 2013–2016 Michigan 2012–2016 Minnesota 2014–2016 Wisconsin 2011–2016

Guarantees

Guarantees	12 Months Ended
	Dec. 31, 2016
Guarantees [Abstract]
GUARANTEES	GUARANTEES The following table shows our outstanding guarantees: Total Amounts Committed Expiration (in millions) at December 31, 2016 Less Than 1 Year 1 to 3 Years Over 3 Years Guarantees Standby letters of credit (1) $ 29.4 $ 27.9 $ 1.5 $ — Surety bonds (2) 10.9 10.3 0.6 — Other guarantees (3) 7.6 0.5 — 7.1 Total guarantees $ 47.9 $ 38.7 $ 2.1 $ 7.1 (1) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets. (2) Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets. (3) Consists of $7.6 million related to other indemnifications, for which a liability of $7.1 million related to workers compensation coverage was recorded on our balance sheets.

Employee Benefits

Employee Benefits	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
EMPLOYEE BENEFITS	EMPLOYEE BENEFITS Pension and Other Postretirement Employee Benefits We and our subsidiaries have defined benefit pension plans that cover substantially all of our employees, as well as several unfunded nonqualified retirement plans. In addition, we and our subsidiaries offer multiple OPEB plans to employees. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred. Generally, former Wisconsin Energy Corporation employees who started with the company after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. New Wisconsin Energy Corporation management employees hired after December 31, 2014 receive a 6% annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans. For former Integrys employees, the defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. These employees receive an annual company contribution to their 401(k) savings plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year. We use a year-end measurement date to measure the funded status of all of our pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of our pension and OPEB plans qualify as a regulatory asset. The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets: Pension Costs OPEB Costs (in millions) 2016 2015 2016 2015 Change in benefit obligation Obligation at January 1 $ 3,083.0 $ 1,505.5 $ 842.0 $ 397.7 Obligation assumed from acquisition — 1,594.0 — 493.0 Service cost 45.4 30.4 26.1 20.7 Interest cost 130.8 94.3 37.0 26.7 Participant contributions — — 16.4 12.7 Plan amendments (3.0 ) — (18.9 ) — Actuarial loss (gain) 71.7 14.6 (36.5 ) (74.0 ) Benefit payments (269.1 ) (156.0 ) (49.1 ) (36.2 ) Federal subsidy on benefits paid N/A N/A 1.4 1.6 Plan curtailment — 0.2 — (0.2 ) Obligation at December 31 $ 3,058.8 $ 3,083.0 $ 818.4 $ 842.0 Change in fair value of plan assets Fair value at January 1 $ 2,755.1 $ 1,444.6 $ 749.8 $ 333.5 Assets received from acquisition — 1,420.9 — 442.1 Actual return on plan assets 199.4 (62.1 ) 51.5 (15.6 ) Employer contributions 23.8 107.7 4.9 13.3 Participant contributions — — 16.4 12.7 Benefit payments (269.1 ) (156.0 ) (49.1 ) (36.2 ) Fair value at December 31 $ 2,709.2 $ 2,755.1 $ 773.5 $ 749.8 Funded status at December 31 $ (349.6 ) $ (327.9 ) $ (44.9 ) $ (92.2 ) The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows: Pension Costs OPEB Costs (in millions) 2016 2015 2016 2015 Other long-term assets $ 74.4 $ 74.1 $ 29.7 $ 50.1 Pension and OPEB obligations * 424.0 402.0 74.6 142.3 Total net liabilities $ (349.6 ) $ (327.9 ) $ (44.9 ) $ (92.2 ) * Includes $0.8 million of pension and $0.4 million of OPEB obligations classified as liabilities held for sale as of December 31, 2015. These amounts are included in other current liabilities on our balance sheets. The accumulated benefit obligation for all defined benefit pension plans was $2,939.9 million and $2,936.4 million as of December 31, 2016, and 2015 , respectively. The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2016 2015 Projected benefit obligation $ 1,667.0 $ 1,706.6 Accumulated benefit obligation 1,549.5 1,560.5 Fair value of plan assets 1,242.9 1,304.6 The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31: Pension Costs OPEB Costs (in millions) 2016 2015 2016 2015 Accumulated other comprehensive loss (pre-tax) (1) Net actuarial loss (gain) $ 12.0 $ 11.4 $ (1.0 ) $ (0.6 ) Total $ 12.0 $ 11.4 $ (1.0 ) $ (0.6 ) Net regulatory assets (2) Net actuarial loss $ 1,240.7 $ 798.1 $ 25.8 $ 23.7 Prior service costs (credits) 10.5 4.7 (87.9 ) (3.3 ) Total $ 1,251.2 $ 802.8 $ (62.1 ) $ 20.4 (1) Amounts related to the nonregulated entities are included in accumulated other comprehensive loss. (2) Amounts related to the utilities and WBS are recorded as net regulatory assets or liabilities. The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2017: (in millions) Pension Costs OPEB Costs Net actuarial loss $ 87.2 $ 5.8 Prior service costs (credits) 3.0 (11.2 ) Total 2017 – estimated amortization $ 90.2 $ (5.4 ) The components of net periodic benefit cost (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows: Pension Costs OPEB Costs (in millions) 2016 2015 2014 2016 2015 2014 Service cost $ 45.4 $ 30.4 $ 10.1 $ 26.1 $ 20.7 $ 8.5 Interest cost 130.8 94.3 68.1 37.0 26.7 17.8 Expected return on plan assets (195.9 ) (155.6 ) (98.6 ) (52.7 ) (39.6 ) (23.7 ) Plan settlement 16.5 — — — — — Plan curtailment — (0.3 ) — — — — Amortization of prior service cost (credit) 3.4 2.2 2.1 (9.4 ) (6.4 ) (1.8 ) Amortization of net actuarial loss 82.9 68.5 36.7 8.5 3.9 1.2 Net periodic benefit cost $ 83.1 $ 39.5 $ 18.4 $ 9.5 $ 5.3 $ 2.0 The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension OPEB 2016 2015 2016 2015 Discount rate 4.16% 4.46% 4.14% 4.38% Rate of compensation increase 3.60% 4.00% N/A N/A Assumed medical cost trend rate N/A N/A 7.00% 7.50% Ultimate trend rate N/A N/A 5.00% 5.00% Year ultimate trend rate is reached N/A N/A 2021 2021 The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Costs 2016 2015 2014 Discount rate 4.35% 4.11% 5.00% Expected return on plan assets 7.12% 7.37% 7.25% Rate of compensation increase 3.75% 4.00% 4.00% OPEB Costs 2016 2015 2014 Discount rate 4.38% 4.09% 4.95% Expected return on plan assets 7.25% 7.54% 7.50% Assumed medical cost trend rate (Pre 65/Post 65) 7.50% 7.50% 7.50% Ultimate trend rate 5.00% 5.00% 5.00% Year ultimate trend rate is reached 2021 2021 2021 We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund. For 2017 , the expected return on assets assumption is 7.11% for the pension plans and 7.25% for the OPEB plans. Assumed health care cost trend rates have a significant effect on the amounts reported by us for health care plans. For the year ended December 31, 2016 , a one-percentage-point change in assumed health care cost trend rates would have had the following effects: (in millions) 1% Increase 1% Decrease Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $ 8.5 $ (6.9 ) Effect on health care component of the accumulated postretirement benefit obligations 49.6 (39.5 ) Plan Assets Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees. The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. The Wisconsin Energy Corporation pension trust target asset allocations are 35% equity investments, 55% fixed income investments, and 10% private equity and real estate investments. The Integrys pension trust target asset allocation is 60% equity investments and 40% fixed income investments. The Wisconsin Energy Corporation OPEB trusts' target asset allocations are 60% equity investments and 40% fixed income investments. The two largest OPEB trusts for Integrys have target asset allocations of 50% equity investments and 50% fixed income, and 45% equity investments and 55% fixed income, respectively. Equity securities include investments in large-cap, mid-cap, and small-cap companies primarily located in the United States. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and United States Treasuries. Pension and OPEB plan investments are recorded at fair value. See Note 1(s), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used. Following our adoption of ASU 2015-07 on January 1, 2016, the assets that are not subject to leveling are investments that are valued using the net asset value per share (or its equivalent) practical expedient. We have applied this approach retrospectively to the 2015 table for comparability. The following tables provide the fair values of our investments by asset class: December 31, 2016 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ 3.7 $ 58.0 $ — $ 61.7 $ 28.8 $ 3.4 $ — $ 32.2 Equity securities: United States Equity 273.9 0.1 — 274.0 34.3 — — 34.3 International Equity 54.1 0.6 — 54.7 3.5 0.2 — 3.7 Fixed income securities: * United States Bonds — 861.3 0.8 862.1 — 137.9 — 137.9 International Bonds — 75.9 — 75.9 — 8.8 — 8.8 Private Equity and Real Estate — — 14.6 14.6 — — 1.3 1.3 $ 331.7 $ 995.9 $ 15.4 $ 1,343.0 $ 66.6 $ 150.3 $ 1.3 $ 218.2 Investments measured at net asset value $ 1,366.2 $ 555.3 Total $ 331.7 $ 995.9 $ 15.4 $ 2,709.2 $ 66.6 $ 150.3 $ 1.3 $ 773.5 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2015 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ 17.0 $ 29.6 $ — $ 46.6 $ 10.5 $ 1.0 $ — $ 11.5 Equity securities: United States Equity 132.6 3.4 — 136.0 24.6 0.1 — 24.7 International Equity 103.9 — — 103.9 21.4 — — 21.4 Fixed income securities: * United States Bonds 11.4 797.3 — 808.7 0.3 122.0 — 122.3 International Bonds — 80.3 — 80.3 — 8.1 — 8.1 Private Equity and Real Estate — — 5.5 5.5 — — 0.4 0.4 $ 264.9 $ 910.6 $ 5.5 $ 1,181.0 $ 56.8 $ 131.2 $ 0.4 $ 188.4 Investments measured at net asset value $ 1,574.1 $ 561.4 Total $ 264.9 $ 910.6 $ 5.5 $ 2,755.1 $ 56.8 $ 131.2 $ 0.4 $ 749.8 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. The following tables set forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy: Private Equity and Real Estate United States Bonds (in millions) Pension OPEB Pension Beginning balance at January 1, 2016 $ 5.5 $ 0.4 $ — Realized and unrealized gains 0.5 0.1 — Purchases 8.6 0.8 0.8 Ending balance at December 31, 2016 $ 14.6 $ 1.3 $ 0.8 Private Equity and Real Estate (in millions) Pension OPEB Beginning balance at January 1, 2015 $ — $ — Purchases 5.5 0.4 Ending balance at December 31, 2015 $ 5.5 $ 0.4 Cash Flows In January 2017, we contributed $100.0 million to the pension plans. We expect to contribute an additional $13.2 million to the pension plans and $0.1 million to the OPEB plans in 2017 , dependent upon various factors affecting us, including our liquidity position and possible tax law changes. The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB: (in millions) Pension Costs OPEB Costs 2017 $ 215.7 $ 41.8 2018 217.1 49.6 2019 226.5 49.0 2020 233.1 50.9 2021 230.0 53.1 2022-2026 1,031.5 278.5 Savings Plans We sponsor 401(k) savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. Certain employees participate in a defined contribution pension plan, in which amounts are contributed to the employee's savings plan account based on the employee's wages, age, and years of service. Total costs incurred under all of these plans were $44.3 million in 2016, $48.0 million in 2015, and $14.2 million in 2014.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
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, operating leases, environmental matters, and enforcement and litigation matters. Unconditional Purchase Obligations We routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our natural gas utilities have obligations to distribute and sell natural gas to their customers, and our electric utilities have obligations to distribute and sell electricity to their customers. The utilities expect to recover costs related to these obligations in future customer rates. The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2016 , including those of our subsidiaries. Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2017 2018 2019 2020 2021 Later Years Electric utility: Nuclear 2033 $ 9,599.8 $ 415.3 $ 420.1 $ 445.4 $ 475.1 $ 501.1 $ 7,342.8 Purchased power 2027 693.3 111.3 75.9 66.2 66.3 63.9 309.7 Coal supply and transportation 2019 455.0 269.4 140.3 45.3 — — — Natural gas utility supply and transportation 2028 1,229.4 341.7 285.5 237.5 159.7 78.6 126.4 Total $ 11,977.5 $ 1,137.7 $ 921.8 $ 794.4 $ 701.1 $ 643.6 $ 7,778.9 Operating Leases We lease property, plant, and equipment under various terms. The operating leases generally require us to pay property taxes, insurance premiums, and maintenance costs associated with the leased property. Many of our leases contain one of the following options upon the end of the lease term: (a) purchase the property at the current fair market value, or (b) exercise a renewal option, as set forth in the lease agreement. Rental expense attributable to operating leases was $15.1 million , $12.7 million , and $4.8 million in 2016 , 2015 , and 2014 , respectively. Future minimum payments under noncancelable operating leases are payable as follows: Year Ending December 31 Payments (in millions) 2017 $ 9.9 2018 8.8 2019 5.9 2020 5.3 2021 5.5 Later years 60.1 Total $ 95.5 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 SO 2 , NOx, fine particulates, mercury, and GHGs; water discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites. We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including: • the development of additional sources of renewable electric energy supply; • the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems; • the addition of emission control equipment to existing facilities to comply with ambient air quality standards and federal clean air rules; • the protection of wetlands and waterways, threatened and endangered species, and cultural resources associated with utility construction projects; • the retirement of old coal-fired power plants and conversion to modern, efficient, natural gas generation and super-critical pulverized coal generation; • the beneficial use of ash and other products from coal-fired and biomass generating units; and • the remediation of former manufactured gas plant sites. Air Quality Cross-State Air Pollution Rule In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of NOx and SO 2 that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation and trading plan. After several lawsuits and related appeals, in October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. The emissions budgets of Phase I of the rule applied in 2015 and 2016, while the Phase II emissions budgets discussed below apply to 2017 and beyond. In December 2015, the EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS and issued the final rule in September 2016. Starting in 2017, this rule requires reductions in the ozone season (May 1 through September 30) NOx emissions from power plants in 23 states in the eastern United States, including Wisconsin. The EPA updated Phase II CSAPR NOx ozone season budgets for electric generating units in the affected states. In the final rule, the EPA significantly increased the NOx ozone season budget from the proposed rule for Wisconsin starting in 2017. We believe we are well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule. Sulfur Dioxide National Ambient Air Quality Standards The EPA issued a revised 1-Hour SO 2 NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard. The final rule affords state agencies some latitude in rule implementation. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area. In March 2015, a federal court entered a consent decree between the EPA and the Sierra Club and others agreeing to specific actions related to implementing the revised standard for areas containing large sources emitting above a certain threshold level of SO 2 . The consent decree required the EPA to complete attainment designations for certain areas with large sources by no later than July 2016. SO 2 emissions from PIPP are above the consent decree emission threshold, which means that the Marquette area required action earlier than would otherwise have been required under the revised NAAQS. However, we were able to show through modeling that the area should be designated as attainment. In July 2016, the EPA finalized its recommendation and published a notice in the Federal Register designating Marquette County, Michigan as unclassified/attainment, effective September 2016. In June 2016, we provided modeling to the WDNR that shows the area around the Weston Power Plant to be in compliance. Based upon the submittal, the WDNR provided final modeling to the EPA demonstrating the area around the Weston Power Plant to be in compliance. We expect that the EPA will consider the WDNR's recommendation and finalize its recommended designation in August 2017, for finalization by the end of 2017. We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation. 8-Hour Ozone National Ambient Air Quality Standards The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released the final rule, which lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. For nonattainment areas, the state of Wisconsin will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020 and are in the process of reviewing and determining potential impacts resulting from this rule. We believe we are well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule. Mercury and Other Hazardous Air Pollutants In December 2011, the EPA issued the final MATS rule, which imposed stringent limitations on emissions of mercury and other hazardous air pollutants from coal and oil-fired electric generating units beginning in April 2015. In addition, both Wisconsin and Michigan have state mercury rules that require a 90% reduction of mercury; however, these rules are not in effect as long as MATS is in place. In June 2015, the Supreme Court ruled on a challenge to the MATS rule and remanded the case back to the D.C. Circuit Court of Appeals, ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule remains in effect until the D.C. Circuit Court of Appeals takes action on the EPA's April 2016 updated cost evaluation. We believe that the WE and WPS fleets are well positioned to comply with the final MATS rule and do not expect to incur any significant additional costs to comply with this regulation. The addition of a dry sorbent injection system for further control of mercury and acid gases at PIPP was placed into service in March 2016, allowing PIPP to be in compliance with MATS. Construction and testing of the ReACT TM multi-pollutant control system at Weston Unit 3 is complete, and the unit is currently in compliance with both MATS and the WPS Consent Decree emission requirements. Climate Change In 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the final rule for existing fossil-fueled generating units, numerous states (including Wisconsin and Michigan), trade associations, and private parties filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the Clean Power Plan until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. In addition, in February 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan. The D.C. Circuit Court of Appeals heard the case in September 2016. The final rule for existing fossil-fueled generating units seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39% , respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction. The building blocks used by the EPA to determine each state's emission reduction requirements include a combination of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources. We continue to evaluate possible reduction opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions, given the uncertain future of the Clean Power Plan and current fuel and technology markets. Our evaluation to date indicates that the Clean Power Plan, as well as current fuel markets and advances in technology, are not expected to result in significant additional compliance costs, including capital expenditures, but could impact how we operate our existing fossil-fueled power plants and biomass facility. However, the timelines for the 2022 through 2029 interim goals and the 2030 final goal for states, as well as all other aspects of the rule, likely will be changed due to the stay and subsequent legal proceedings. With the new Federal Executive Administration as of January 2017, the Clean Power Plan, or its successor, could be significantly changed from the final rule of October 2015. Notwithstanding the potential changes to the Clean Power Plan, addressing climate change is an integral component of our strategic planning process. We continue to reshape our portfolio of electric generation facilities with investments that will improve our environmental performance, including reduced GHG intensity of our operating fleet. As the regulation of GHG emissions takes shape, our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO 2 emissions by approximately 40% below 2005 levels by 2030. We continue to evaluate numerous options in order to meet our CO 2 reduction goal, such as increased utilization of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation. Draft Federal Plan and Model Trading Rules (Model Rules) were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for reconsideration of the EPA's final standards for existing, as well as for new, modified, and reconstructed generating units. A petition for reconsideration of the EPA's final standards for existing generating units was also submitted jointly by the Wisconsin utilities. Among other things, the petitions narrowly asked the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's CO 2 equivalent reduction goal by about 10% . In May 2016, the EPA denied the state of Wisconsin's petition for reconsideration related to new, modified, and reconstructed generating units, except that the EPA deferred the portion related to the treatment of biomass. The EPA has not issued decisions yet regarding the above referenced petitions for reconsideration of the final EPA standards for existing generating units. In December 2016, the EPA withdrew the draft Model Rules and accompanying draft documents from the review process and made working drafts available to the public. They are not final documents, are not signed by the Administrator, and will not be published in the Federal Register. The EPA’s docket will remain open, with the potential for completing the agency’s work on these materials and finalizing them at a later date. We are required to report our CO 2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2015 , we reported aggregated CO 2 equivalent emissions of approximately 31.0 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO 2 equivalent emissions of approximately 29.6 million metric tonnes to the EPA for 2016 . The level of CO 2 and other GHG emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO. We are also required to report CO 2 equivalent amounts related to the natural gas that our natural gas utilities distribute and sell. For 2015 , we reported aggregated CO 2 equivalent emissions of approximately 27.2 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO 2 equivalent emissions of approximately 26.7 million metric tonnes to the EPA for 2016 . Water Quality Clean Water Act Cooling Water Intake Structure Rule In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake). The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities. Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for Pulliam Units 7 and 8 and Weston Unit 2, satisfy the IM BTA requirements. We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNR BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit. BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for Pulliam Units 7 and 8, Weston Units 2 through 4, PWGS, Pleasant Prairie Power Plant, PIPP, and OC 5 through OC 8. During 2017 and 2018, we will continue to complete studies and evaluate options to address the EM BTA requirements at our plants. With the exception of Pleasant Prairie Power Plant and Weston Units 3 and 4 (which all have existing cooling towers that meet EM BTA requirements) and VAPP, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. Based on discussions with the MDEQ, if we provide information about unit retirements with our next National Pollutant Discharge Elimination System permit application and then submit a signed certification by August 2017 stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived. Entrainment studies are currently being conducted at Pulliam Units 7 and 8 and were recently completed at PIPP. See UMERC discussion in Note 22, Regulatory Environment , regarding the potential retirement of PIPP. We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation. Steam Electric Effluent Guidelines The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin and Michigan. This rule is being litigated in the United States Court of Appeals for the Fifth Circuit and may result in changes to the discharge requirements. The WDNR and MDEQ will continue to modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years . We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment will require additional zero liquid discharge or other advanced treatment capital improvements for the Oak Creek site and Pleasant Prairie facilities. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications will be required at OC 7, OC 8, the Pleasant Prairie units, Pulliam Units 7 and 8, and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $80 million to $110 million for these advanced treatment and bottom ash transport systems. A similar system would be required at PIPP if we were not expecting to retire the plant. See UMERC discussion in Note 22, Regulatory Environment , regarding the potential retirement of PIPP. Land Quality Manufactured Gas Plant Remediation We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure. In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below. The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites. We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31: (in millions) 2016 2015 Regulatory assets $ 702.7 $ 697.0 Reserves for future remediation 633.4 628.0 Renewables, Efficiency, and Conservation Wisconsin Legislation In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. WE and WPS have achieved renewable energy percentages of 8.27% and 9.74% , respectively, and met their compliance requirements by constructing various wind parks, a biomass facility, and by also relying on renewable energy purchases. WE and WPS continue to review their renewable energy portfolios and acquire cost-effective renewables as needed to meet their requirements on an ongoing basis. The PSCW administers the renewable program related to Act 141, and each utility funds the program based on 1.2% of its annual operating revenues. Michigan Legislation In 2008, Michigan enacted Act 295, which required 10% of the state's energy to come from renewables by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. In December 2016, Michigan revised this legislation with Act 342, which requires additional renewable energy requirements beyond 2015. The new legislation retains the 10% renewable energy portfolio requirement for years 2016 through 2018, increases the requirement to 12.5% for years 2019 through 2020, and increases the requirement to 15.0% for 2021. WE and WPS were in compliance with these requirements as of December 31, 2016 . The revised legislation continues to allow recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective. 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. Paris Generating Station Units 1 and 4 Construction Permit In December 2013, Act 91 was signed into law in Wisconsin, creating a process by which the EPA and WDNR were able to revise the regulations and emissions rates applicable to Paris Generating Station Units 1 and 4. Act 91, along with a new construction permit, allowed those units to restart after a temporary outage. In October 2014, the Sierra Club filed for a contested case hearing with the WDNR challenging this permit. In February 2013, the Sierra Club also filed for a contested case hearing with the WDNR in connection with the administrative order issued in this matter, which was granted. The Sierra Club has withdrawn the contested case hearing request, thereby concluding this matter. Consent Decrees Wisconsin Public Service Corporation Consent Decree – Weston and Pulliam In November 2009, the EPA issued a NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013. The final Consent Decree includes: • the installation of emission control technology, including ReACT™ on Weston 3, • changed operating conditions (including refueling, repowering, and/or retirement of units), • limitations on plant emissions, • beneficial environmental projects totaling $6.0 million , and • a civil penalty of $1.2 million . The Consent Decree also contains requirements to refuel, repower, and/or retire certain Weston and Pulliam units. Effective June 1, 2015, WPS retired Weston Unit 1 and Pulliam Units 5 and 6. In March 2016, WPS submitted a proposed revision to the EPA to update requirements reflecting the conversion of Weston Unit 2 from coal to natural gas fuel, and also proposed revisions to the list of beneficial environmental projects required by the Consent Decree. These proposed revisions were approved by the EPA in May 2016. The revisions to the environmental projects are not expected to materially impact the overall costs noted above. WPS received approval from the PSCW in its 2015 rate order to defer and amortize the undepreciated book value of the retired plant related to Weston Unit 1 and Pulliam Units 5 and 6 starting June 1, 2015, and concluding by 2023. Therefore, in June 2015, WPS recorded a regulatory asset of $11.5 million for the undepreciated book value. In addition, WPS received approval from the PSCW in its rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. Also, in May 2010, WPS received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of December 31, 2016 . It is unknown whether the Sierra Club will take further action in the future. Joint Ownership Power Plants Consent Decree – Columbia and Edgewater In December 2009, the EPA issued a NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, along with Wisconsin Power and Light, Madison Gas and Electric, and WE entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. WE paid an immaterial portion of the assessed penalty but has no further obligations under the Consent Decree. The final Consent Decree includes: • the installation of emission control technology, including scrubbers at the Columbia plant, • changed operating conditions (including refueling, repowering, and/or retirement of units), • limitations on plant emissions, • beneficial environmental projects, with WPS's portion totaling $1.3 million , and • WPS's portion of a civil penalty and legal fees totaling $0.4 million . The Consent Decree contains a requirement to, among other things, refuel, repower, or retire Edgewater Unit 4, of which WPS is a joint owner, by no later than December 31, 2018. In the first quarter of 2015, management of the joint owners recommended that Edgewater Unit 4 be retired in December 2018. However, a final decision on how to address the requirement for this unit has not yet been made by the joint owners, as early retirement is contingent on various operational and market factors, and other alternatives to retirement are still available.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS 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: December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 10.1 $ 24.2 $ — $ 34.3 Petroleum products contracts 0.2 — — 0.2 FTRs — — 5.1 5.1 Coal contracts — 2.0 — 2.0 Total derivative assets $ 10.3 $ 26.2 $ 5.1 $ 41.6 Investments held in rabbi trust $ 103.9 $ — $ — $ 103.9 Derivative liabilities Natural gas contracts $ 0.2 $ 0.2 $ — $ 0.4 Petroleum products contracts 0.1 — — 0.1 Coal contracts — 1.9 — 1.9 Total derivative liabilities $ 0.3 $ 2.1 $ — $ 2.4 December 31, 2015 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.6 $ 1.5 $ — $ 3.1 Petroleum products contracts 1.2 — — 1.2 FTRs — — 3.6 3.6 Coal contracts — 2.0 — 2.0 Total derivative assets $ 2.8 $ 3.5 $ 3.6 $ 9.9 Investments held in rabbi trust $ 39.8 $ — $ — $ 39.8 Derivative liabilities Natural gas contracts $ 16.5 $ 25.3 $ — $ 41.8 Petroleum products contracts 4.9 — — 4.9 Coal contracts — 12.3 — 12.3 Total derivative liabilities $ 21.4 $ 37.6 $ — $ 59.0 The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets. See Note 20, Derivative Instruments, for more information . The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31 : (in millions) 2016 2015 2014 Balance at the beginning of the period $ 3.6 $ 7.0 $ 3.5 Realized and unrealized (losses) gains (0.2 ) 1.3 — Purchases 15.2 3.9 15.6 Sales (0.2 ) (0.1 ) — Settlements (13.3 ) (11.9 ) (12.1 ) Acquisition of Integrys — (1.3 ) — Transfers out of level 3 — 4.7 — Balance at the end of the period $ 5.1 $ 3.6 $ 7.0 Unrealized gains and losses on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through cost of sales on the income statements. Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that are not recorded at fair value at December 31 : 2016 2015 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 28.8 $ 30.4 $ 27.3 Long-term debt, including current portion * $ 9,285.8 $ 9,818.2 $ 9,221.9 $ 9,681.0 * The carrying amount of long-term debt excludes capital lease obligations of $29.6 million and $59.9 million at December 31, 2016 and December 31, 2015 , respectively.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS The following table shows our derivative assets and derivative liabilities: December 31, 2016 December 31, 2015 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 31.4 $ 0.4 $ 2.6 $ 38.5 Petroleum products contracts 0.2 0.1 0.9 3.8 FTRs 5.1 — 3.6 — Coal contracts 1.5 1.4 1.7 6.7 Total other current $ 38.2 $ 1.9 $ 8.8 $ 49.0 Other long-term Natural gas contracts $ 2.9 $ — $ 0.5 $ 3.3 Petroleum products contracts — — 0.3 1.1 Coal contracts 0.5 0.5 0.3 5.6 Total other long-term $ 3.4 $ 0.5 $ 1.1 $ 10.0 Total $ 41.6 $ 2.4 $ 9.9 $ 59.0 Our estimated notional sales volumes and realized gains (losses) were as follows: December 31, 2016 December 31, 2015 December 31, 2014 (in millions) Volume Gains (Losses) Volume Gains (Losses) Volume Gains Natural gas contracts 151.1 Dth $ (59.6 ) 86.2 Dth $ (50.5 ) 40.5 Dth $ 7.3 Petroleum products contracts 14.7 gallons (3.2 ) 7.8 gallons (1.9 ) 9.2 gallons 0.5 FTRs 33.7 MWh 13.3 27.3 MWh 6.7 26.1 MWh 12.7 Total $ (49.5 ) $ (45.7 ) $ 20.5 The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2016 December 31, 2015 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 41.6 $ 2.4 $ 9.9 $ 59.0 Gross amount not offset on the balance sheet * (4.9 ) (0.5 ) (3.0 ) (22.5 ) Net amount $ 36.7 $ 1.9 $ 6.9 $ 36.5 * Includes cash collateral received of $4.4 million at December 31, 2016, and cash collateral posted of $19.5 million at December 31, 2015 . At December 31, 2016 and 2015 , we had posted cash collateral of $16.4 million and $42.3 million , respectively, in our margin accounts. At December 31, 2016, we had also received cash collateral of $4.4 million in our margin accounts. We had not received any cash collateral at December 31, 2015 . Certain of our derivative and non-derivative commodity instruments contain provisions that could require "adequate assurance" in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a net liability position at December 31, 2016 and 2015 was $0.2 million and $23.8 million , respectively. At December 31, 2016 and 2015, we had not posted any cash collateral related to the credit risk-related contingent features of these commodity instruments. If all of the credit risk-related contingent features contained in derivative instruments in a net liability position had been triggered at December 31, 2016, we would not have been required to post any collateral. At December 31, 2015 , we would have been required to post collateral of $18.0 million . During 2015, we settled several forward interest rate swap agreements entered into to mitigate interest risk associated with the issuance of $1.2 billion of long-term debt related to the acquisition of Integrys. As these agreements qualified for cash flow hedging accounting treatment, the proceeds of $19.0 million received upon settlement of these agreements were deferred in accumulated other comprehensive income and are being amortized as a decrease to interest expense over the periods in which the interest costs are recognized in earnings. During 2016 , we reclassified $2.2 million of forward interest rate swap agreement settlements deferred in accumulated other comprehensive income as a reduction to interest expense. We estimate that during the next twelve months, $2.2 million will be reclassified from accumulated other comprehensive income as a reduction to interest expense.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2016
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis. This ASU focuses on the consolidation analysis for companies that are required to evaluate whether they should consolidate certain legal entities. It emphasizes the risk of loss when determining a controlling financial interest and amends the guidance for assessing how related party relationships affect the consolidation analysis of variable interest entities. We adopted the standard upon its effective date in the first quarter of 2016, and our adoption resulted in no changes to our disclosures or financial statement presentation. The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities. We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance. American Transmission Company We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a variable interest entity but that consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. We account for ATC as an equity method investment. See Note 4, Investment in American Transmission Company, for more information . The significant assets and liabilities related to ATC recorded on our balance sheets included our equity investment and accounts payable. At December 31, 2016 , and 2015 , our equity investment was $1,443.9 million and $1,380.9 million , respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $28.7 million and $28.3 million of accounts payable due to ATC at December 31, 2016 , and 2015 , respectively, for network transmission services. Purchased Power Agreement We have identified a purchased power agreement that represents a variable interest. This agreement is for 236 MW of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately five years . We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the purchased power agreement. We have approximately $85.3 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 years ended December 31, 2016 , 2015 , and 2014 , were $54.2 million , $53.6 million , and $53.0 million , respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

Regulatory Environment

Regulatory Environment	12 Months Ended
	Dec. 31, 2016
Regulated Operations [Abstract]
REGULATORY ENVIRONMENT	REGULATORY ENVIRONMENT Wisconsin Electric Power Company 2015 Wisconsin Rate Order In May 2014, WE applied to the PSCW for a biennial review of costs and rates. In December 2014, the PSCW approved the following rate adjustments, effective January 1, 2015: • A net bill increase related to non-fuel costs for WE's retail electric customers of approximately $2.7 million ( 0.1% ) in 2015. This amount reflected WE's receipt of SSR payments from MISO that were higher than WE anticipated when it filed its rate request in May 2014, as well as an offset of $26.6 million related to a refund of prior fuel costs and the remainder of the proceeds from a Treasury Grant that WE received in connection with its biomass facility. The majority of this $26.6 million was returned to customers in the form of bill credits in 2015. • A rate increase for WE's retail electric customers of $26.6 million ( 0.9% ) in 2016 related to the expiration of the bill credits provided to customers in 2015. • A rate decrease of $13.9 million ( -0.5% ) in 2015 related to a forecasted decrease in fuel costs. • A rate decrease of $10.7 million ( -2.4% ) for WE's natural gas customers in 2015, with no rate adjustment in 2016. • A rate increase of approximately $0.5 million ( 2.0% ) for WE's Downtown Milwaukee (Valley) steam utility customers in 2015, with no rate adjustment in 2016. • A rate increase of approximately $1.2 million ( 7.3% ) for WE's Milwaukee County steam utility customers in 2015, with no rate adjustment in 2016. As a result of the sale of the MCPP, WE no longer has any Milwaukee County steam utility customers. See Note 3, Dispositions, for more information about the sale of the MCPP. The authorized ROE for WE was set at 10.2% , and its common equity component remained at an average of 51% . The PSCW order reaffirmed the deferral of WE's transmission costs, and it verified that 2015 and 2016 fuel costs should continue to be monitored using a 2% tolerance window. The PSCW approved a change in rate design for WE, which included higher fixed charges to better match the related fixed costs of providing service. The PSCW order also authorized escrow accounting for SSR revenues because of the uncertainty of the actual revenues WE will receive under the PIPP SSR agreements. Under escrow accounting, WE records SSR revenues of $90.7 million a year. If actual SSR payments from MISO exceed $90.7 million a year, the difference is deferred and returned to customers, with interest, in a future rate case. If actual SSR payments from MISO are less than $90.7 million a year, the difference is deferred and will be recovered from customers with interest, in a future rate case. In January 2015, certain parties appealed a portion of the PSCW's final decision adopting WE's specific rate design changes, including new charges for customer-owned generation within its service territory. The Dane County Circuit Court, in its November 2015 order, ruled that there was not enough evidence provided in WE's rate case to support a demand charge for customer-owned generation. As a result, this demand charge did not take effect on January 1, 2016. No other rates approved by the PSCW in the rate case were impacted by the Dane County Circuit Court order. Earnings Sharing Agreement In May 2015, the PSCW approved the acquisition of Integrys subject to the condition of an earnings sharing mechanism for WE. See Note 2, Acquisitions, for more information on this earnings sharing mechanism. 2013 Wisconsin Rate Order In March 2012, WE initiated a rate proceeding with the PSCW. In December 2012, the PSCW approved the following rate adjustments, effective January 1, 2013: • A net bill increase related to non-fuel costs for WE's retail electric customers of approximately $70.0 million ( 2.6% ) in 2013. This amount reflected an offset of approximately $63.0 million ( 2.3% ) for bill credits related to the proceeds of the Treasury Grant, including associated tax benefits. Absent this offset, the retail electric rate increase for non-fuel costs was approximately $133.0 million ( 4.8% ) in 2013. • An electric rate increase for WE's electric customers of approximately $28.0 million ( 1.0% ) in 2014, and a $45.0 million ( -1.6% ) reduction in bill credits. • Recovery of a forecasted increase in fuel costs of approximately $44.0 million ( 1.6% ) in 2013. • A rate decrease of approximately $8.0 million ( -1.9% ) for WE's natural gas customers in 2013, with no rate adjustment in 2014. The WE rates reflected a $6.4 million reduction in bad debt expense. • An increase of approximately $1.3 million ( 6.0% ) for WE's Downtown Milwaukee (Valley) steam utility customers in 2013 and another $1.3 million ( 6.0% ) in 2014. • An increase of approximately $1.0 million ( 7.0% ) in 2013 and $1.0 million ( 6.0% ) in 2014 for WE's Milwaukee County steam utility customers. Based on the PSCW order, the authorized ROE for WE remained at 10.4% . In addition, the PSCW approved escrow accounting treatment for the Treasury Grant. The PSCW also determined the construction costs for the ERGS units were prudently incurred, and it approved the recovery of the majority of these costs in rates. Wisconsin Gas LLC 2015 Wisconsin Rate Order In May 2014, WG applied to the PSCW for a biennial review of costs and rates. In December 2014, the PSCW approved rate increases of $17.1 million ( 2.6% ) in 2015 and $21.4 million ( 3.2% ) in 2016 for WG's natural gas customers. These rate adjustments were effective January 1, 2015. The authorized ROE for WG was set at 10.3% . The PSCW also authorized an increase in WG's common equity component to an average of 49.5% . Earnings Sharing Agreement In May 2015, the PSCW approved the acquisition of Integrys subject to the condition of an earnings sharing mechanism for WG . See Note 2, Acquisitions, for more information on this earnings sharing mechanism. 2013 Wisconsin Rate Order In March 2012, WG initiated a rate proceeding with the PSCW. In December 2012, the PSCW approved a rate decrease of approximately $34.0 million ( -5.5% ) for WG’s natural gas customers in 2013, with no rate adjustment in 2014. The WG rates reflected a $43.8 million reduction in bad debt expense. The rate adjustments were effective January 1, 2013, and the authorized ROE for WG remained at 10.5% . Wisconsin Public Service Corporation 2016 Wisconsin Rate Order In April 2015, WPS initiated a rate proceeding with the PSCW. In December 2015, the PSCW issued a final written order for WPS, effective January 1, 2016. The order, which reflects a 10.0% ROE and a common equity component average of 51.0% , authorized a net retail electric rate decrease of $7.9 million ( -0.8% ) and a net retail natural gas rate decrease of $6.2 million ( -2.1% ). The decrease in retail electric rates was due to lower monitored fuel costs in 2016 compared to 2015. Absent the adjustment for electric fuel costs, WPS would have realized an electric rate increase. Based on the order, the PSCW allowed WPS to escrow ATC and MISO network transmission expenses through 2016. In addition, future SSR payments will continue to be escrowed until a future rate proceeding. The order directed WPS to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates. In addition, the PSCW approved a deferral for ReACT™, which required WPS to defer the revenue requirement of ReACT™ costs above the authorized $275.0 million level through 2016. Fuel costs will continue to be monitored using a 2% tolerance window. In March 2016, WPS requested extensions from the PSCW through 2017 for the deferral of the revenue requirement of ReACT™ costs above the authorized $275.0 million level as well as escrow accounting of ATC and MISO network transmission expenses. In April 2016, WPS also requested to extend through 2017 the previously approved deferral of the revenue requirement difference between the Real Time Market Pricing and the standard tariffed rates for any of WPS's current large commercial and industrial customers who entered into a service agreement with WPS under Real Time Market Pricing prior to April 15, 2016. These requests were approved by the PSCW in June 2016. The amounts deferred related to these items as of December 31, 2016 , were not material. 2015 Wisconsin Rate Order In April 2014, WPS initiated a rate proceeding with the PSCW. In December 2014, the PSCW issued a final written order for WPS, effective January 1, 2015. It authorized a net retail electric rate increase of $24.6 million and a net retail natural gas rate decrease of $15.4 million , reflecting a 10.20% ROE. The order authorized a common equity component average of 50.28% . The PSCW approved a change in rate design for WPS, which included higher fixed charges to better match the related fixed costs of providing service. In addition, the order continued to exclude a decoupling mechanism that was terminated beginning January 1, 2014. The primary driver of the increase in retail electric rates was higher costs of fuel for electric generation of approximately $42.0 million . In addition, 2015 rates included approximately $9.0 million of lower refunds to customers related to decoupling over-collections. In 2015 rates, WPS refunded approximately $4.0 million to customers related to 2013 decoupling over-collections compared with refunding approximately $13.0 million to customers in 2014 rates related to 2012 decoupling over-collections. Absent these adjustments for electric fuel costs and decoupling refunds, WPS would have realized an electric rate decrease. In addition, WPS received approval from the PSCW to defer and amortize the undepreciated book value associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. See Note 18, Commitments and Contingencies, for more information . The PSCW allowed WPS to escrow ATC and MISO network transmission expenses for 2015 and 2016. As a result, WPS deferred as a regulatory asset the difference between actual transmission expenses and those included in rates until a future rate proceeding. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a 2% tolerance window. The retail natural gas rate decrease was driven by the approximate $16.0 million year-over-year negative impact of decoupling refunds to and collections from customers. In 2015 rates, WPS refunded approximately $8.0 million to customers related to 2013 decoupling over-collections compared with recovering approximately $8.0 million from customers in 2014 rates related to 2012 decoupling under-collections. Absent the adjustment for decoupling refunds to and collections from customers, WPS would have realized a retail natural gas rate increase. 2015 Michigan Rate Order In October 2014, WPS initiated a rate proceeding with the MPSC. In April 2015, the MPSC issued a final written order for WPS, effective April 24, 2015, approving a settlement agreement. The order authorized a retail electric rate increase of $4.0 million to be implemented over three years to recover costs for the 2013 acquisition of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generation plants. The rates reflected a 10.2% ROE and a common equity component average of 50.48% . The increase reflected the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflected the deferral of Weston Unit 3 ReACT™ environmental project costs. On the second anniversary of the order, WPS will discontinue the deferral of Fox Energy Center costs and will begin amortizing this deferral along with the deferral associated with the termination of a tolling agreement related to the Fox Energy Center. WPS also received approval from the MPSC to defer and amortize the undepreciated book value of the retired plant associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. As a result of the formation of UMERC, WPS transferred the deferrals mentioned above, as well as its customers and property, plant, and equipment located in the Upper Peninsula of Michigan to the new utility, effective January 1, 2017. Therefore, the terms and conditions of this rate order are now applicable to UMERC. UMERC will not seek an increase to legacy WPS retail electric base rates that would become effective prior to January 1, 2018. The Peoples Gas Light and Coke Company and North Shore Gas Company Base Rate Freeze In June 2015, the ICC approved the acquisition of Integrys subject to the condition that PGL and NSG will not seek increases of their base rates that would become effective earlier than two years after the close of the acquisition. Illinois Investigations In March 2015, the ICC opened a docket, naming PGL as respondent, to investigate the veracity of certain allegations included in anonymous letters that the ICC staff received regarding PGL's SMP. This matter is still pending. In December 2015, the ICC ordered a series of stakeholder workshops to evaluate PGL's SMP. This ICC action did not impact PGL's ongoing work to modernize and maintain the safety of its natural gas distribution system, but it instead provided the ICC with an opportunity to analyze long-term elements of the program through the stakeholder workshops. The workshops commenced in January 2016 and were completed in March 2016. The ICC staff submitted a report on the workshop process in May 2016. In July 2016, the ICC initiated a proceeding to review, among other things, the planning, reporting, and monitoring of the program, including what the target end date for the program should be. This proceeding is expected to result in a final order by the ICC in 2017. We are currently unable to determine what, if any, long-term impact there will be on PGL's SMP. 2015 Illinois Rate Order In February 2014, PGL and NSG initiated a rate proceeding with the ICC. In January 2015, the ICC issued a final written order for PGL and NSG, effective January 28, 2015. The order authorized a retail natural gas rate increase of $74.8 million for PGL and $3.7 million for NSG. In February 2015, the ICC issued an amendatory order that revised the increases to $71.1 million for PGL and $3.5 million for NSG, effective February 26, 2015, to reflect the extension of bonus depreciation in 2014. The rates for PGL reflected a 9.05% ROE and a common equity component average of 50.33% . The rates for NSG reflected a 9.05% ROE and a common equity component average of 50.48% . The rate order allowed PGL and NSG to continue the use of their decoupling mechanisms and uncollectible expense true-up mechanisms. In addition, PGL recovers a return on certain investments and depreciation expense through the Qualifying Infrastructure Plant rider, and accordingly, such costs are not subject to PGL's rate order. PGL's Qualifying Infrastructure Plant rider allows for the recovery of costs incurred related to investments in qualifying infrastructure plant. This rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudence. No schedule has been set for the 2015 reconciliation. The ALJ has placed the 2014 reconciliation on stay, pending resolution of several open matters related to PGL's SMP. Although schedules have not been set for the reconciliations, discovery has continued for both the 2014 and 2015 reconciliations. As of December 31, 2016 , there can be no assurance that all costs incurred under the Qualifying Infrastructure Plant rider will be recoverable. Minnesota Energy Resources Corporation 2016 Minnesota Rate Case In September 2015, MERC initiated a rate proceeding with the MPUC. In October 2016, the MPUC issued a final written order for MERC, which is expected to be effective in the first quarter of 2017. The order authorized a retail natural gas rate increase of $6.8 million ( 3.0% ). The rates reflect a 9.11% ROE and a common equity component average of 50.32% . The order approved MERC's request to continue the use of its currently authorized decoupling mechanism for another three years . The final approved rate increase was lower than the interim rates collected from customers during 2016. Therefore, as of December 31, 2016 , we estimate that $3.0 million will be refunded to MERC's customers during 2017. 2015 Minnesota Rate Case In September 2013, MERC initiated a rate proceeding with the MPUC. In October 2014, the MPUC issued a final written order for MERC, effective April 1, 2015. The order authorized a retail natural gas rate increase of $7.6 million . The rates reflected a 9.35% ROE and a common equity component average of 50.31% . The order approved a deferral of customer billing system costs, for which recovery was requested in MERC's 2016 rate case. A decoupling mechanism with a 10% cap remains in effect for MERC's residential and small commercial and industrial customers. The final approved rate increase was lower than the interim rates collected from customers during 2014. Therefore, MERC refunded $4.7 million to customers in 2015. Michigan Gas Utilities Corporation 2016 Michigan Rate Order In June 2015, MGU initiated a rate proceeding with the MPSC. In December 2015, the MPSC issued a final written order, approving a settlement agreement for MGU. The order, which reflects a 9.9% ROE and a common equity component average of 52.0% , authorized a retail natural gas rate increase of $3.4 million ( 2.4% ), effective January 1, 2016. Based on the settlement agreement, MGU discontinued the use of its decoupling mechanism after December 31, 2015. In addition, since bonus depreciation was in effect in 2016, MGU established a regulatory liability for the resulting cost savings and must refund the liability in its next general rate case. Upper Michigan Energy Resources Corporation In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan and it became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets previously held by WE and WPS located in the Upper Peninsula of Michigan. In August 2016, we entered into an agreement with the Tilden Mining Company (Tilden) under which it will purchase electric power from UMERC for its iron ore mine for 20 years The agreement also calls for UMERC to construct and operate approximately 180 MW of natural gas-fired generation located in the Upper Peninsula of Michigan. On January 30, 2017, UMERC filed an application with the MPSC for a certificate of necessity to begin construction of the proposed generation. The estimated cost of this project is approximately $265 million ( $275 million with AFUDC), 50% of which is expected to be recovered from Tilden, with the remaining 50% expected to be recovered from utility customers located in the Upper Peninsula of Michigan. Subject to regulatory approval of both the agreement with Tilden and the construction of the proposed generation, the new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. Tilden will remain a customer of WE until this new generation begins commercial operation.

Other Income, net

Other Income, net	12 Months Ended
	Dec. 31, 2016
Other Income, net [Abstract]
Other Income and Other Expense Disclosure [Text Block]	OTHER INCOME, NET Total other income, net was as follows for the years ended December 31 : (in millions) 2016 2015 2014 AFUDC – Equity $ 25.1 $ 20.1 $ 5.6 Gain on repurchase of notes 23.6 — — Gain on asset sales 19.6 22.9 7.5 Other, net 12.5 15.9 0.3 Other income, net $ 80.8 $ 58.9 $ 13.4

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
SEGMENT INFORMATION	SEGMENT INFORMATION At December 31, 2016 , we reported six segments, which are described below. • The Wisconsin segment includes the electric and natural gas utility operations of WE, WG, and WPS, including WE's and WPS's electric and natural gas operations in the state of Michigan that were transferred to UMERC effective January 1, 2017. • The Illinois segment includes the natural gas utility and non-utility operations of PGL and NSG. • The other states segment includes the natural gas utility and non-utility operations of MERC and MGU. • The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. • The We Power segment includes our nonregulated entity that owns and leases generating facilities to WE. • The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark, Bostco, Wisvest, WECC, WBS, PDL, and ITF. The sale of ITF was completed in the first quarter of 2016. In the second quarter of 2016, we sold certain assets of Wisvest. See Note 3, Dispositions, for more information on these sales. All of our operations and assets are located within the United States. The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2016 , 2015 , and 2014 . Regulated Operations 2016 (in millions) Wisconsin Illinois Other States Electric Transmission Total Regulated Operations We Power Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated External revenues $ 5,805.4 $ 1,242.2 $ 376.5 $ — $ 7,424.1 $ 24.9 $ 23.3 $ — $ 7,472.3 Intersegment revenues 0.3 — — — 0.3 423.3 — (423.6 ) — Other operation and maintenance 2,025.4 485.1 110.1 — 2,620.6 4.3 (15.8 ) (423.6 ) 2,185.5 Depreciation and amortization 496.6 134.0 21.1 — 651.7 68.3 42.6 — 762.6 Operating income (loss) 1,027.0 239.6 49.9 — 1,316.5 375.6 (10.0 ) — 1,682.1 Equity in earnings of transmission affiliate — — — 146.5 146.5 — — — 146.5 Interest expense 180.9 38.9 8.5 — 228.3 62.1 120.9 (8.6 ) 402.7 Capital expenditures 910.9 293.2 59.5 — 1,263.6 62.3 97.8 — 1,423.7 Total assets * 21,730.7 5,714.6 995.1 1,476.9 29,917.3 2,777.1 778.0 (3,349.2 ) 30,123.2 * Total assets at December 31, 2016 reflect an elimination of $2,029.5 million for all lease activity between We Power and WE. Regulated Operations 2015 (in millions) Wisconsin Illinois Other States Electric Transmission Total Regulated Operations We Power Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated External revenues $ 5,186.1 $ 503.4 $ 149.3 $ — $ 5,838.8 $ 40.0 $ 47.3 $ — $ 5,926.1 Intersegment revenues 5.0 — — — 5.0 405.2 — (410.2 ) — Other operation and maintenance 1,741.0 219.6 50.0 — 2,010.6 4.3 103.7 (409.3 ) 1,709.3 Depreciation and amortization 408.6 63.3 10.0 — 481.9 67.5 12.4 — 561.8 Operating income (loss) 884.2 78.1 6.0 — 968.3 373.4 (91.2 ) — 1,250.5 Equity in earnings of transmission affiliate — — — 96.1 96.1 — — — 96.1 Interest expense 157.1 19.9 5.1 — 182.1 63.4 91.0 (5.1 ) 331.4 Capital expenditures 950.3 194.4 34.7 — 1,179.4 53.4 33.4 — 1,266.2 Total assets * 21,113.5 5,462.9 918.0 1,381.0 28,875.4 2,779.0 1,132.5 (3,431.7 ) 29,355.2 * Total assets at December 31, 2015 reflect an elimination of $2,105.3 million for all lease activity between We Power and WE. Regulated Operations 2014 (in millions) Wisconsin Illinois Other States Electric Transmission Total Regulated Operations We Power Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated External revenues $ 4,932.1 $ — $ — $ — $ 4,932.1 $ 55.7 $ 9.3 $ — $ 4,997.1 Intersegment revenues 9.2 — — — 9.2 383.4 — (392.6 ) — Other operation and maintenance 1,462.7 — — — 1,462.7 4.4 33.0 (387.7 ) 1,112.4 Depreciation and amortization 323.2 — — — 323.2 66.7 1.5 — 391.4 Operating income (loss) 770.2 — — — 770.2 368.0 (26.1 ) — 1,112.1 Equity in earnings of transmission affiliate — — — 66.0 66.0 — — — 66.0 Interest expense 127.6 — — — 127.6 64.6 48.8 (0.7 ) 240.3 Capital expenditures 715.0 — — — 715.0 41.0 5.2 — 761.2 Total assets * 14,403.8 — — 424.1 14,827.9 2,789.9 253.3 (2,966.1 ) 14,905.0 * Total assets at December 31, 2014 reflect an elimination of $2,172.9 million for all lease activity between We Power and WE.

QUARTERLY FINANCIAL INFORMATION

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information (unaudited)	QUARTERLY FINANCIAL INFORMATION (Unaudited) (in millions, except per share amounts) First Quarter Second Quarter Third Quarter Fourth Quarter Total 2016 Operating revenues $ 2,194.8 $ 1,602.0 $ 1,712.5 $ 1,963.0 $ 7,472.3 Operating income 589.3 332.1 399.0 361.7 1,682.1 Net income attributed to common shareholders 346.2 181.4 217.0 194.4 939.0 Earnings per share * Basic $ 1.10 $ 0.57 $ 0.69 $ 0.62 $ 2.98 Diluted 1.09 0.57 0.68 0.61 2.96 2015 Operating revenues $ 1,387.9 $ 991.2 $ 1,698.7 $ 1,848.3 $ 5,926.1 Operating income 358.8 165.8 345.7 380.2 1,250.5 Net income attributed to common shareholders 195.8 80.9 182.5 179.3 638.5 Earnings per share * Basic $ 0.87 $ 0.36 $ 0.58 $ 0.57 $ 2.36 Diluted 0.86 0.35 0.58 0.57 2.34 * Earnings per share for the individual quarters do not total the year ended earnings per share amount because of changes to the average number of shares outstanding and changes in incremental issuable shares throughout the year. Due to various factors, including the acquisition of Integrys on June 29, 2015, the quarterly results of operations are not necessarily comparable.

New Accounting Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
RECENT ACCOUNTING PRONOUNCEMENTS	NEW ACCOUNTING PRONOUNCEMENTS Revenue Recognition In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers. We intend to adopt this standard for interim and annual periods beginning January 1, 2018, as required, and plan to use the modified retrospective method of adoption. This method will result in a cumulative-effect adjustment that will be recorded on the balance sheet as of the beginning of 2018, as if the standard had always been in effect. Disclosures in 2018 will include a reconciliation of results under the new revenue guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods. We are currently reviewing our contracts with customers and related financial disclosures to evaluate the impact of the amended guidance on our existing revenue recognition policies and procedures. We consider tariff sales at our regulated utilities, excluding the revenue component related to alternative revenue programs, to be in the scope of the new standard. We have evaluated the nature of these revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition for such sales. However, in our evaluation, we are also monitoring unresolved implementation issues for our industry, including the impacts of the new guidance on our ability to recognize revenue for certain contracts where collectability is uncertain and the accounting for contributions in aid of construction (CIAC). We currently account for CIAC funds received from customers and/or developers outside of revenue, as a reduction to property, plant, and equipment. The final resolution of these issues could impact our current accounting policies and revenue recognition. Classification and Measurement of Financial Instruments In January 2016, the FASB issued ASU 2016-01, Classification and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We are currently assessing the effects this guidance may have on our financial statements. Leases In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. We are currently assessing the effects this guidance may have on our financial statements. Stock-Based Compensation In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Under this ASU, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement, the tax effects of exercised or vested awards are treated as discrete items in the reporting period in which they occur, and excess tax benefits are recognized in the current period regardless of whether the benefit reduces taxes payable. On the cash flow statement, excess tax benefits are classified along with other income tax cash flows as an operating activity, and cash paid by an employer when directly withholding shares for tax purposes is classified as a financing activity. We adopted this guidance effective January 1, 2017, and do not believe it will have a significant impact on our financial statements. Financial Instruments Credit Losses In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements. Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, and will be applied using a retrospective transition method. There are eight main provisions of this ASU for which current GAAP either is unclear or does not include specific guidance. We are currently assessing the effects this guidance may have on our financial statements. Restricted Cash In November 2016, the FASB issued ASU 2016-18, Restricted Cash. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Under this ASU, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-the period and end-of-the period total amounts shown on the statements of cash flows. We do not believe the adoption of this guidance will have a significant impact on our financial statements.

Schedule I - Condensed Parent C

Schedule I - Condensed Parent Company Financial Statements	12 Months Ended
	Dec. 31, 2016
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS	SCHEDULE I – CONDENSED PARENT COMPANY FINANCIAL STATEMENTS WEC ENERGY GROUP, INC. (PARENT COMPANY ONLY) A. INCOME STATEMENTS Year Ended December 31 (in millions) 2016 2015 2014 Operating expenses $ 7.0 $ 42.2 $ 26.8 Equity in earnings of subsidiaries 996.5 695.7 635.0 Other income, net 2.7 23.2 2.8 Interest expense 90.0 71.2 53.1 Income before income taxes 902.2 605.5 557.9 Income tax benefit 36.8 33.0 30.4 Net income attributed to common shareholders $ 939.0 $ 638.5 $ 588.3 The accompanying Notes to Condensed Parent Company Financial Statements are an integral part of these financial statements. B. STATEMENTS OF COMPREHENSIVE INCOME Year Ended December 31 (in millions) 2016 2015 2014 Net income attributed to common shareholders $ 939.0 $ 638.5 $ 588.3 Other comprehensive (loss) income, net of tax Derivatives accounted for as cash flow hedges Gains on settlement, net of tax of $7.6 — 11.4 — Reclassification of gains to net income, net of tax (1.3 ) (0.8 ) — Cash flow hedges, net (1.3 ) 10.6 — Defined benefit plans Pension and OPEB costs arising during the period, net of tax (1.0 ) (1.5 ) — Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax 0.3 — — Defined benefit plans, net (0.7 ) (1.5 ) — Other comprehensive income (loss) from subsidiaries, net of tax 0.3 (4.8 ) — Other comprehensive (loss) income, net of tax (1.7 ) 4.3 — Comprehensive income attributed to common shareholders $ 937.3 $ 642.8 $ 588.3 The accompanying Notes to Condensed Parent Company Financial Statements are an integral part of these financial statements. C. BALANCE SHEETS At December 31 (in millions) 2016 2015 Assets Current assets Cash and cash equivalents $ 1.2 $ 1.3 Accounts receivable from related parties 1.8 13.2 Notes receivable from related parties 76.4 123.2 Prepaid taxes 47.6 — Other 0.5 2.2 Current assets 127.5 139.9 Long-term assets Investments in subsidiaries 11,155.4 10,792.6 Other 134.7 254.0 Long-term assets 11,290.1 11,046.6 Total assets $ 11,417.6 $ 11,186.5 Liabilities and Equity Current liabilities Short-term debt $ 321.8 $ 307.9 Accounts payable to related parties 3.2 1.7 Notes payable to related parties 241.3 119.0 Accrued taxes — 75.6 Other 10.3 17.5 Current liabilities 576.6 521.7 Long-term liabilities Long-term debt 1,890.0 1,887.2 Other 21.2 122.8 Long-term liabilities 1,911.2 2,010.0 Common shareholders' equity 8,929.8 8,654.8 Total liabilities and equity $ 11,417.6 $ 11,186.5 The accompanying notes to Condensed Parent Company Financial Statements are an integral part of these financial statements. D. STATEMENTS OF CASH FLOWS Year Ended December 31 (in millions) 2016 2015 2014 Operating activities Net income attributed to common shareholders $ 939.0 $ 638.5 $ 588.3 Reconciliation to cash provided by operating activities Equity in earnings of subsidiaries (996.5 ) (695.7 ) (635.0 ) Dividends from subsidiaries 734.4 538.8 720.0 Deferred income taxes 23.2 30.9 60.1 Change in – Prepaid taxes (47.6 ) — — Other current assets 13.0 (9.3 ) (0.3 ) Accrued taxes (75.6 ) 175.7 4.1 Other current liabilities (5.6 ) (3.2 ) 5.1 Other, net 6.3 (18.4 ) (8.1 ) Net cash provided by operating activities 590.6 657.3 734.2 Investing activities Business acquisition — (1,486.2 ) — Capital contributions to subsidiaries (55.8 ) (135.3 ) (225.5 ) Short-term notes receivable from related parties, net 46.8 (91.0 ) — Purchase of subsidiary's common stock (66.4 ) — — Proceeds from the sale of assets and businesses — 20.8 — Other, net (0.4 ) (0.1 ) 5.0 Net cash used in investing activities (75.8 ) (1,691.8 ) (220.5 ) Financing activities Exercise of stock options 41.6 30.1 50.3 Purchase of common stock (108.0 ) (74.7 ) (123.2 ) Dividends paid on common stock (624.9 ) (455.4 ) (352.0 ) Issuance of long-term debt — 1,200.0 — Change in short-term debt 13.9 307.9 (72.0 ) Short-term notes payable to related parties, net 162.3 1.8 3.5 Other, net 0.2 (11.2 ) 16.7 Net cash (used in) provided by financing activities (514.9 ) 998.5 (476.7 ) Net change in cash and cash equivalents (0.1 ) (36.0 ) 37.0 Cash and cash equivalents at beginning of year 1.3 37.3 0.3 Cash and cash equivalents at end of year $ 1.2 $ 1.3 $ 37.3 The accompanying Notes to Condensed Parent Company Financial Statements are an integral part of these financial statements. SCHEDULE I – CONDENSED PARENT COMPANY FINANCIAL STATEMENTS WEC ENERGY GROUP, INC. (PARENT COMPANY ONLY) E. NOTES TO PARENT COMPANY FINANCIAL STATEMENTS NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES For Parent Company only presentation, investments in subsidiaries are accounted for using the equity method. The condensed Parent Company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of WEC Energy Group, Inc. appearing in this Annual Report on Form 10-K. NOTE 2—CASH DIVIDENDS RECEIVED FROM SUBSIDIARIES Dividends received from our subsidiaries during the years ended December 31 were as follows: (in millions) 2016 2015 2014 WE $ 455.0 $ 240.0 $ 390.0 WG 75.0 30.0 33.0 We Power 197.9 262.8 297.0 ATC Holding LLC 6.5 6.0 — Total $ 734.4 $ 538.8 $ 720.0 NOTE 3—LONG-TERM DEBT The following table shows the future maturities of our long-term debt outstanding as of December 31, 2016 : (in millions) 2018 $ 300.0 2020 400.0 Thereafter 1,200.0 Total $ 1,900.0 WECC is our subsidiary and has $50.0 million of long-term notes outstanding. In a Support Agreement between WECC and us, we agreed to make sufficient liquid asset contributions to WECC to permit WECC to service its debt obligations as they become due. The following table shows the financial instruments included on our balance sheets that are not recorded at fair value as of December 31 : 2016 2015 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt $ 1,890.0 $ 1,906.1 $ 1,887.2 $ 1,900.7 The carrying value of cash and cash equivalents, accounts receivable, short-term notes receivable, accounts payable, and short-term borrowings approximates fair value due to the short-term nature of these instruments. The fair value of our long-term debt is estimated based upon the quoted market value for the same issue, similar issues, or upon the quoted market prices of United States Treasury issues having a similar term to maturity, adjusted for our bond rating and the present value of future cash flows. NOTE 4—SUPPLEMENTAL CASH FLOW INFORMATION (in millions) 2016 2015 2014 Cash (paid) for interest $ (89.6 ) $ (68.8 ) $ (44.4 ) Cash (paid) received for income taxes, net (62.9 ) 242.9 95.1 During 2016, we settled a $40.0 million short-term note payable to our subsidiary, Wisvest, through a non-cash capital contribution. NOTE 5—SHORT-TERM NOTES RECEIVABLE FROM RELATED PARTIES The following table shows our outstanding short-term notes receivable from related parties as of December 31: (in millions) 2016 2015 Integrys $ 42.0 $ 95.1 Bostco 18.5 19.6 Wispark 15.9 8.5 Total $ 76.4 $ 123.2 NOTE 6—SHORT-TERM NOTES PAYABLE TO RELATED PARTIES The following table shows our outstanding short-term notes payable to related parties as of December 31: (in millions) 2016 2015 WBS $ 131.1 $ — WECC 109.3 108.4 Wisvest 0.9 10.6 Total $ 241.3 $ 119.0

Schedule II - Valuation and Qua

Schedule II - Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2016
Valuation and Qualifying Accounts [Abstract]
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS	SCHEDULE II WEC ENERGY GROUP, INC. VALUATION AND QUALIFYING ACCOUNTS Allowance for Doubtful Accounts (in millions) Balance at Beginning of Period Acquisitions of Businesses Expense (1) Deferral Net Write-offs (2) Balance at End of Period December 31, 2016 $ 113.3 $ — $ 87.4 $ (5.9 ) $ (86.8 ) $ 108.0 December 31, 2015 74.5 54.3 56.7 8.2 (80.4 ) 113.3 December 31, 2014 61.0 — 49.8 18.4 (54.7 ) 74.5 (1) Net of recoveries. (2) Represents amounts written off to the reserve, net of adjustments to regulatory assets.

Summary of Significant Accoun39

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Nature Of Operations [Policy Text Block]	On June 29, 2015, Wisconsin Energy Corporation acquired Integrys and changed its name to WEC Energy Group, Inc. WEC Energy Group serves approximately 1.6 million electric customers and 2.8 million natural gas customers, and it owns approximately 60% of ATC.
Consolidation	As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, statements of equity, and statements of capitalization, unless otherwise noted.
Segment reporting	Our financial statements include the accounts of WEC Energy Group, a diversified energy holding company, and the accounts of our subsidiaries in the following reportable segments: • Wisconsin segment – Consists of WE, WG, and WPS, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin. WE's electric and WPS's electric and natural gas operations in the state of Michigan are also included in this segment. • Illinois segment – Consists of PGL and NSG, which are engaged primarily in the distribution of natural gas in Illinois. • Other states segment – Consists of MERC and MGU, which are engaged primarily in the distribution of natural gas in Minnesota and Michigan, respectively. • Electric transmission segment – Consists of our approximate 60% ownership interest in ATC, a federally regulated electric transmission company. • We Power segment – Consists of We Power, which is principally engaged in the ownership of electric power generating facilities for long-term lease to WE. • Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, WECC, WBS, PDL, Wisvest and ITF. The sale of ITF was completed in the first quarter of 2016. In the second quarter of 2016, we sold certain assets of Wisvest. See Note 3, Dispositions, for more information on these sales.
Use of estimates	We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.
Balance sheet presentation	To be consistent with the current year presentation, we changed our December 31, 2015 balance sheet from a utility format to a traditional format. This change revised the order of certain balance sheet line items, but it did not result in any change to the classification of amounts between line items.
Cash and cash equivalents	Cash and cash equivalents include marketable debt securities with an original maturity of three months or less.
Revenue and customer receivables	We recognize revenues related to the sale of energy on the accrual basis and include estimated amounts for services provided but not yet billed to customers. We present revenues net of pass-through taxes on the income statements. Below is a summary of the significant mechanisms our utility subsidiaries had in place that allowed them to recover or refund changes in prudently incurred costs from rate case-approved amounts: • Fuel and purchased power costs were recovered from customers on a one-for-one basis by our Wisconsin wholesale electric operations and our Michigan retail electric operations. • Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. Our electric utilities monitor the deferral of under-collected costs to ensure that it does not cause them to earn a greater ROE than authorized by the PSCW. • WE received payments from MISO under an SSR agreement for its PIPP units through February 1, 2015. We recorded revenue for these payments to recover costs for operating and maintaining these units. See Note 22, Regulatory Environment , for more information. • The rates for all of our natural gas utilities included one-for-one recovery mechanisms for natural gas commodity costs. We defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. • The rates of PGL and NSG included riders for cost recovery of both environmental cleanup costs and energy conservation and management program costs. • MERC's rates included a conservation improvement program rider for cost recovery of energy conservation and management program costs as well as a financial incentive for meeting energy savings goals. • The rates of PGL and NSG, and the residential rates of WE and WG, included riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. • The rates of PGL, NSG, MERC, and MGU included decoupling mechanisms. These mechanisms differ by state and allow utilities to recover or refund differences between actual and authorized margins. MGU's decoupling mechanism was discontinued after December 31, 2015. See Note 22, Regulatory Environment, for more information . • PGL's rates included a cost recovery mechanism for SMP costs. Revenues are also impacted by other accounting policies related to PGL's natural gas hub and our electric utilities' participation in the MISO Energy Markets. Amounts collected from PGL's wholesale customers that use the natural gas hub are credited to natural gas costs, resulting in a reduction to retail customers' charges for natural gas and services. Our electric utilities sell and purchase power in the MISO Energy Markets, which operate under both day-ahead and real-time markets. We record energy transactions in the MISO Energy Markets on a net basis for each hour. If our electric utilities were a net seller in a particular hour, the net amount was reported as operating revenues. If our electric utilities were a net purchaser in a particular hour, the net amount was recorded as cost of sales on our income statements. We provide regulated electric service to customers in Wisconsin and Michigan and regulated natural gas service to customers in Wisconsin, Illinois, Minnesota, and Michigan. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Credit risk exposure at WE, WG, PGL, and NSG is mitigated by their recovery mechanisms for uncollectible expense discussed above. As a result, we did not have any significant concentrations of credit risk at December 31, 2016 . In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2016 .
Materials, supplies and inventories	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. Inventories stated on a LIFO basis represented approximately 18% of total inventories at December 31, 2016 and 2015 . The estimated replacement cost of natural gas in inventory at December 31, 2016 and 2015 , exceeded the LIFO cost by $92.9 million and $15.2 million , respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $3.63 at December 31, 2016 , and $2.48 at December 31, 2015 . Substantially all other natural gas in storage, materials and supplies, and fossil fuel inventories are recorded using the weighted-average cost method of accounting.
Investments held in rabbi trust	Integrys has a rabbi trust that is 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 trust holds investments that are classified as trading securities for accounting purposes. As we do not intend to sell the investments in the near term, they are included in other long-term assets on our balance sheets. The net unrealized gains and losses included in earnings related to the investments held at the end of the period were not significant for the years ended December 31, 2016 and 2015.
Regulatory accounting	The economic effects of regulation can result in regulated companies recording costs and revenues that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future revenues associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts that are collected in rates for future costs. Recovery or refund of regulatory assets and liabilities is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to which they relate. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the reporting period the determination is made. See Note 6, Regulatory Assets and Liabilities, for more information .
Property, plant, and equipment	We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below: Annual Utility Composite Depreciation Rates 2016 2015 2014 WE 3.00% 3.01% 2.93% WPS * 2.58% 1.30% N/A WG 2.34% 2.36% 2.69% PGL * 3.31% 1.67% N/A NSG * 2.44% 1.22% N/A MERC * 2.53% 1.26% N/A MGU * 2.63% 1.32% N/A * The rates shown for 2015 are for a partial year as a result of the acquisition of Integrys. The full year rate would be approximately double the rate shown. We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2 and 10 to 55 years for ER 1 and ER 2. We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.
AFUDC	AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC – Debt) used during plant construction, and a return on stockholders' capital (AFUDC – Equity) used for construction purposes. AFUDC – Debt is recorded as a reduction of interest expense, and AFUDC – Equity is recorded in other income, net. The majority of AFUDC is recorded at WE, WPS, and WG. Approximately 50% of WE's, WPS's, and WG's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. The AFUDC calculation for WBS uses the WPS AFUDC retail rate, while the other utilities AFUDC rates are determined by their respective state commissions, each with specific requirements. Based on these requirements, the other utilities and WBS did not record significant AFUDC for 2016 , 2015 , or 2014 . Average AFUDC rates are shown below: 2016 Average AFUDC Retail Rate Average AFUDC Wholesale Rate WE 8.45% 2.73% WPS 7.72% 3.00% WG 8.33% N/A
Impairment of long lived assets	Other long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.
Impairment, cost and equity method investments	Our financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly Owned Facilities, for more information . The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. The carrying amounts of cost and equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts, if a fair value assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value.
Goodwill	Due to the acquisition of Integrys, we changed the date of our annual goodwill impairment test from August 31 to July 1. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value. Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. Intangible assets with definite lives are reviewed for impairment on a quarterly basis. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.
Capitalized interest and carrying costs non regulated energy	As part of the construction of We Power's electric generating units, we capitalized interest during construction. As allowed under the lease agreements, we were able to collect the carrying costs during the construction of these generating units from our utility customers. The carrying costs that we collected during construction have been recorded as deferred revenue on our balance sheets and we are amortizing the deferred carrying costs to revenue over the individual lease terms.
Asset retirement obligations	We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted to their present values each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated retirement costs. For our regulated entities, we recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 9, Asset Retirement Obligations, for more information .
Environmental remediation costs	We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 9, Asset Retirement Obligations, for more information regarding coal combustion product landfill sites and Note 18, Commitments and Contingencies , for more information regarding manufactured gas plant sites. We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation. Our utilities have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the applicable state Commission's approval. We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion product landfill sites. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.
Income taxes	We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense. Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We file a consolidated Federal income tax return. Accordingly, we allocate Federal current tax expense benefits and credits to our subsidiaries based on their separate tax computations. See Note 15, Income Taxes, for more information . We recognize interest and penalties accrued, related to unrecognized tax benefits, in income tax expense in our income statements.
Guarantees	We follow the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee.
Employee benefits	The costs of pension and OPEB are expensed over the periods during which employees render service. These costs are allocated among our subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the utilities' net periodic benefit cost calculated under GAAP. See Note 17, Employee Benefits, for more information .
Stock-based compensation	In accordance with the shareholder approved Omnibus Stock Incentive Plan, we provide long-term incentives through our equity interests to our non-employee directors, officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in common stock, cash, or a combination thereof. The number of shares of common stock authorized for issuance under the plan is 34.3 million . We recognize stock-based compensation expense on a straight-line basis over the requisite service period. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period based on our estimate of the final expected value of the awards. Stock Options We grant non-qualified stock options that vest on a cliff-basis after a three -year period. The exercise price of a stock option under the plan cannot be less than 100% of our common stock's fair market value on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of our common stock on the date of the grant. Options may not be exercised within six months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of the grant. Our stock options are classified as equity awards. The fair value of our stock options was calculated using a binomial option-pricing model. The following table shows the estimated fair value per stock option granted along with the weighted-average assumptions used in the valuation models: 2016 2015 2014 Non-qualified stock options granted 794,764 516,475 899,500 Estimated fair value per non-qualified stock option $ 5.14 $ 5.29 $ 4.18 Assumptions used to value the options: Risk-free interest rate 0.4% – 2.2% 0.1% – 2.1% 0.1% – 3.0% Dividend yield 4.0 % 3.7 % 3.8 % Expected volatility 18.1 % 18.0 % 18.0 % Expected life (years) 6.1 5.8 5.8 The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on our current dividend rate and historical stock prices. Expected volatility and expected life assumptions were based on our historical experience. Restricted Shares Restricted shares have a three -year vesting period, and generally, one-third of the award vests on each anniversary of the grant date. Our restricted shares are classified as equity awards. Performance Units Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on our total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over a three -year period, and beginning in 2017, other performance metrics as determined by the Compensation Committee. Under the terms of the award, participants may earn between 0% and 175% of the performance unit award, as adjusted pursuant to the terms of the plan. All grants are settled in cash and are accounted for as liability awards accordingly. Stock-based compensation costs are recorded over the three -year performance period.
Earnings per share	We compute basic earnings per share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. The calculation of diluted earnings per share for the years ended December 31, 2016 and 2015 excluded 181,709 and 516,475 stock options, respectively, that had an anti-dilutive effect. There were no securities that had an anti-dilutive effect for the year ended December 31, 2014.
Fair value measurements	Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. Derivatives were transferred between levels of the fair value hierarchy primarily due to observable pricing becoming available. We recognize transfers at their value as of the end of the reporting period. Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a dividend discount model. The fair value of our long-term debt is estimated based upon the quoted market value for the same issue, similar issues, or upon the quoted market prices of United States Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows. The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.
Derivative instruments	We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators. We record derivative instruments on our balance sheets as assets or liabilities 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. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Realized gains and losses on derivative instruments are primarily recorded in cost of sales on the income statements. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows. Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current liabilities.
Customer deposits and credit balances	When utility customers apply for new service, they may be required to provide a deposit for the service. Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within current liabilities on our balance sheets.

Summary of Significant Accoun40

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Schedule of inventory	Our inventory as of December 31 consisted of: (in millions) 2016 2015 Natural gas in storage $ 223.1 $ 284.1 Materials and supplies 206.5 219.2 Fossil fuel 158.0 183.7 Total $ 587.6 $ 687.0
Schedule of annual utility composite depreciation rates	Annual utility composite depreciation rates are shown below: Annual Utility Composite Depreciation Rates 2016 2015 2014 WE 3.00% 3.01% 2.93% WPS * 2.58% 1.30% N/A WG 2.34% 2.36% 2.69% PGL * 3.31% 1.67% N/A NSG * 2.44% 1.22% N/A MERC * 2.53% 1.26% N/A MGU * 2.63% 1.32% N/A * The rates shown for 2015 are for a partial year as a result of the acquisition of Integrys. The full year rate would be approximately double the rate shown.
Schedule Of public utilities allowance for funds used during construction	Average AFUDC rates are shown below: 2016 Average AFUDC Retail Rate Average AFUDC Wholesale Rate WE 8.45% 2.73% WPS 7.72% 3.00% WG 8.33% N/A
Allowance for funds used during construction	Our regulated utilities recorded the following AFUDC for the years ended December 31: (in millions) 2016 2015 2014 AFUDC – Debt $ 10.9 $ 8.6 $ 2.3 AFUDC – Equity $ 25.1 $ 20.1 $ 5.6
Schedule of assumptions used to estimate the fair value of stock options granted	The following table shows the estimated fair value per stock option granted along with the weighted-average assumptions used in the valuation models: 2016 2015 2014 Non-qualified stock options granted 794,764 516,475 899,500 Estimated fair value per non-qualified stock option $ 5.14 $ 5.29 $ 4.18 Assumptions used to value the options: Risk-free interest rate 0.4% – 2.2% 0.1% – 2.1% 0.1% – 3.0% Dividend yield 4.0 % 3.7 % 3.8 % Expected volatility 18.1 % 18.0 % 18.0 % Expected life (years) 6.1 5.8 5.8

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Consideration transferred	The total consideration transferred was based on the closing price of Wisconsin Energy Corporation common stock on June 29, 2015, and was calculated as follows: Consideration Paid (in millions, except per share amounts) Stock Cash Total Integrys common shares outstanding at June 29, 2015 79,963,091 79,963,091 Exchange ratio 1.128 Wisconsin Energy Corporation shares issued for Integrys shares * 90,187,884 Closing price of Wisconsin Energy Corporation common shares on June 29, 2015 $45.16 Fair value of common stock issued $ 4,072.9 $ 4,072.9 Cash paid per share of Integrys shares outstanding $18.58 Fair value of cash paid for Integrys shares * $ 1,486.2 $ 1,486.2 Consideration attributable to settlement of equity awards, net of tax $ 24.0 $ 24.0 Total purchase price $ 4,072.9 $ 1,510.2 $ 5,583.1 * Fractional shares of 10,483 totaling $0.5 million were paid in cash.
Allocation of purchase price	The table below shows the final allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition: (in millions) Current assets $ 1,060.1 Property, plant, and equipment, net 7,107.4 Goodwill 2,604.3 Other long-term assets * 2,830.5 Current liabilities (1,320.7 ) Long-term debt (2,943.6 ) Other long-term liabilities (3,703.8 ) Preferred stock of subsidiary (51.1 ) Total purchase price $ 5,583.1 * Includes equity method goodwill related to Integrys's investment in ATC. See Note 4, Investment in American Transmission Company, for more information .
Pro Forma Information	The following unaudited pro forma financial information reflects the consolidated results and amortization of purchase price adjustments as if the acquisition had taken place on January 1, 2014. The unaudited pro forma financial information is presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or our future consolidated results. The pro forma financial information does not reflect any potential cost savings from operating efficiencies resulting from the acquisition and does not include certain acquisition-related costs. Year Ended December 31 (in millions, except per share amounts) 2015 2014 Unaudited pro forma financial information Operating revenues $ 7,727.1 $ 9,135.4 Net income attributed to common shareholders $ 873.5 $ 869.9 Earnings per share (Basic) $ 2.77 $ 2.76 Earnings per share (Diluted) $ 2.75 $ 2.74
Severance expense by segment	The 2015 severance expense was recorded in the following segments: (in millions) Year ended December 31, 2015 Wisconsin $ 11.1 Illinois 0.9 Other states 0.1 Corporate and other 12.8 Total severance expense $ 24.9

Dispositions (Tables)

Dispositions (Tables)	12 Months Ended
	Dec. 31, 2016
Corporate and Other | ITF
Dispositions
Schedule of assets and liabilities included as held for sale	The following table shows the carrying values of the major classes of assets and liabilities included as held for sale on our balance sheet at December 31: (in millions) 2015 Accounts receivable and unbilled revenues $ 34.9 Materials, supplies, and inventories 18.4 Other current assets 2.6 Property, plant, and equipment 37.2 Other long-term assets 3.7 Total assets $ 96.8 Accounts payable $ 12.9 Accrued payroll and benefits 2.4 Other current liabilities 4.5 Pension and OPEB obligations 1.2 Other long-term liabilities 0.6 Total liabilities * $ 21.6 * Included in other current liabilities on our balance sheet.

Investment in American Transm43

Investment in American Transmission Company (Tables) - ATC	12 Months Ended
	Dec. 31, 2016
Investment in ATC
Schedule of changes to our investment in ATC	The following table shows changes to our investment in ATC during the years ended December 31: (in millions) 2016 2015 2014 Balance at beginning of period $ 1,380.9 $ 424.1 $ 402.7 Add: Earnings from equity method investment 146.5 96.1 66.0 Add: Capital contributions 42.3 8.7 13.1 Add: Acquisition of Integrys's investment in ATC (1.0 ) 541.5 — Add: Equity method goodwill from the acquisition of Integrys (1) 10.4 395.8 — Less: Distributions 135.1 (2) 85.1 57.5 Less: Other 0.1 0.2 0.2 Balance at end of period $ 1,443.9 $ 1,380.9 $ 424.1 (1) Represents the purchase price allocated to Integrys's investment in ATC in excess of the recorded value. (2) Of this amount, $35.2 million was recorded as a receivable at December 31, 2016.
Schedule of significant transactions with ATC	The following table summarizes our significant related party transactions with ATC during the years ended December 31: (in millions) 2016 2015 2014 Charges to ATC for services and construction $ 18.5 $ 15.4 $ 8.1 Charges from ATC for network transmission services 357.3 289.2 231.4
Schedule of receivables and payables with ATC	As of December 31, 2016 and 2015 , our balance sheets included the following receivables and payables related to ATC: (in millions) 2016 2015 Accounts receivable Services provided to ATC $ 2.2 $ 1.0 Accounts payable Services received from ATC 28.7 28.3
Schedule of summarized income statement data for ATC	Summarized financial data for ATC is included in the tables below: (in millions) 2016 2015 2014 Income statement data Revenues $ 650.8 $ 615.8 $ 635.0 Operating expenses 322.5 319.3 307.4 Other expense 95.5 96.1 88.9 Net income $ 232.8 $ 200.4 $ 238.7
Schedule of summarized balance sheet data for ATC	(in millions) December 31, 2016 December 31, 2015 Balance sheet data Current assets $ 75.8 $ 80.5 Noncurrent assets 4,312.9 3,948.3 Total assets $ 4,388.7 $ 4,028.8 Current liabilities $ 495.1 $ 330.3 Long-term debt 1,865.3 1,790.7 Other noncurrent liabilities 271.5 245.0 Shareholders' equity 1,756.8 1,662.8 Total liabilities and shareholders' equity $ 4,388.7 $ 4,028.8

Supplemental Cash Flow Inform44

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	(in millions) 2016 2015 2014 Cash (paid) for interest, net of amount capitalized $ (411.9 ) $ (329.6 ) $ (241.4 ) Cash received (paid) for income taxes, net 39.7 (9.3 ) (22.0 ) Significant non-cash transactions: Accounts payable related to construction costs 170.1 177.1 1.8 Restricted cash used to purchase investments held in the rabbi trust 59.2 60.2 — Amortization of deferred revenue 24.7 39.9 55.7 Note receivable received related to the sale of AMP Trillium* — 12.0 — Capital assets received related to the sale of AMP Trillium * — 6.3 — * ITF owned a 30% interest in AMP. See Note 3, Dispositions, for more information on the sale of ITF.

Regulatory Assets and Liabili45

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets	The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2016 2015 See Note Regulatory assets (1) (2) Unrecognized pension and OPEB costs (3) $ 1,252.1 $ 1,306.4 17 Environmental remediation costs (4) 702.7 697.0 18 Income tax related items (5) 285.1 248.3 Electric transmission costs 234.1 191.5 22 SSR 188.1 86.1 22 AROs 179.2 173.0 9 We Power generation (6) 54.1 45.4 Energy efficiency programs (7) 36.7 48.7 Derivatives 17.9 70.4 1(t) Other, net 188.3 234.9 Total regulatory assets $ 3,138.3 $ 3,101.7 Balance Sheet Presentation Current assets (8) $ 50.4 $ 37.1 Regulatory assets 3,087.9 3,064.6 Total regulatory assets $ 3,138.3 $ 3,101.7 (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 the table. (2) As of December 31, 2016 , we had $32.7 million of regulatory assets not earning a return and $204.0 million of regulatory assets earning a return based on short-term interest rates. The regulatory assets not earning a return relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures. (3) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We are authorized recovery of this regulatory asset over the average remaining service life of each plan. (4) As of December 31, 2016 , we had not yet made cash expenditures for $633.6 million of these environmental remediation costs. (5) Represents adjustments related to deferred income taxes, which are recovered in rates as the temporary differences that generated the income tax benefit reverse. (6) Represents amounts recoverable from customers related to WE's costs of the generating units leased from We Power, including subsequent capital additions. (7) Represents amounts recoverable from customers related to programs at the utilities designed to meet energy efficiency standards. (8) Short-term regulatory assets are recorded in accounts receivable and unbilled revenues on our balance sheets.
Schedule of Regulatory Liabilities	The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2016 2015 See Note Regulatory liabilities Removal costs (1) $ 1,262.7 $ 1,209.6 Mines deferral (2) 70.2 31.6 Energy costs refundable through rate adjustments (3) 88.7 76.9 Unrecognized pension and OPEB costs (4) 63.0 26.3 17 Derivatives 41.1 12.6 1(t) Uncollectible expense (5) 36.1 31.8 Other, net 35.4 37.2 Total regulatory liabilities $ 1,597.2 $ 1,426.0 Balance Sheet Presentation Other current liabilities $ 33.4 $ 33.8 Regulatory liabilities 1,563.8 1,392.2 Total regulatory liabilities $ 1,597.2 $ 1,426.0 (1) Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment. (2) Represents the deferral of revenues less the associated cost of sales related to sales to the mines, which were not included in the 2015 rate order. We intend to request that this deferral be applied for the benefit of Wisconsin retail electric customers in a future rate proceeding. (3) Represents energy costs that will be refunded to customers in the future. (4) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan. (5) Represents amounts refundable to customers related to our uncollectible expense tracking mechanisms and riders. These mechanisms allow us to recover or refund the difference between actual uncollectible write-offs and the amounts recovered in rates.

Property, Plant, and Equipment

Property, Plant, and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	Property, plant, and equipment consisted of the following utility and non-utility and other assets at December 31: (in millions) 2016 2015 Utility property, plant, and equipment $ 24,185.1 $ 22,803.7 Less: Accumulated depreciation 7,609.7 7,358.2 Net 16,575.4 15,445.5 CWIP 320.0 672.7 Net utility property, plant, and equipment 16,895.4 16,118.2 Non-utility and other property, plant, and equipment 3,520.3 3,482.2 Less: Accumulated depreciation 604.9 560.9 Net 2,915.4 2,921.3 CWIP 104.7 150.2 Net non-utility and other property, plant, and equipment 3,020.1 3,071.5 Total property, plant, and equipment $ 19,915.5 $ 19,189.7

Jointly Owned Facilities (Table

Jointly Owned Facilities (Tables)	12 Months Ended
	Dec. 31, 2016
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]
Schedule of Jointly Owned Plants	Information related to jointly owned facilities at December 31, 2016 was as follows: We Power WPS (in millions, except for percentages and MWs) Elm Road Generating Station Units 1 and 2 Weston Unit 4 Columbia Energy Center Units 1 and 2 (2) Edgewater Unit 4 Ownership 83.34 % 70.0 % 31.8 % 31.8 % Share of rated capacity (MWs) (1) 1,056.8 373.5 334.4 98.0 In-service date 2010 and 2011 2008 1975 and 1978 1969 Property, plant, and equipment $ 2,430.8 $ 596.3 $ 417.9 $ 45.8 Accumulated depreciation $ (331.5 ) $ (170.3 ) $ (128.3 ) $ (31.7 ) CWIP $ 9.4 $ 0.2 $ 41.2 $ 0.1 (1) Based on expected capacity ratings for summer 2017 . The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. (2) Columbia Energy Center (Columbia) is jointly owned by Wisconsin Power and Light (WPL), Madison Gas and Electric (MGE), and WPS. In October 2016, WPL received an order from the PSCW approving amendments to the Columbia joint operating agreement between the parties allowing WPS and MGE to forgo certain capital expenditures at Columbia. As a result, WPL will incur these capital expenditures in exchange for a proportional increase in its ownership share of Columbia. Based upon the additional capital expenditures WPL expects to incur through June 1, 2020, WPS's ownership interest would decrease to 27.5% .

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule of changes to asset retirement obligations	The following table shows changes to our AROs during the years ended December 31: (in millions) 2016 2015 2014 Balance as of January 1 $ 571.2 $ 43.6 $ 42.3 Integrys subsidiaries — 491.0 — Accretion 28.3 14.5 2.4 Additions and revisions to estimated cash flows — 35.5 * — Liabilities settled (41.8 ) (13.4 ) (1.1 ) Balance as of December 31 $ 557.7 $ 571.2 $ 43.6 * During 2015, an ARO of $16.1 million was recorded for fly-ash landfills located at generation facilities owned by WE and WPS. An ARO of $9.0 million was also recorded during 2015 for the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule passed by the EPA in April 2015. In addition, AROs increased $10.4 million in 2015 due to revisions made to estimated cash flows primarily for changes in the weighted average cost to retire natural gas distribution pipe at PGL and NSG.

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of changes to goodwill balances by segment	The following table shows changes to our goodwill balances by segment during the years ended December 31, 2016 and 2015 : Wisconsin Illinois Other States Total (in millions) 2016 2015 2016 2015 2016 2015 2016 2015 Goodwill balance as of January 1 $ 2,109.5 $ 441.9 $ 731.2 $ — $ 182.8 $ — $ 3,023.5 $ 441.9 Adjustment to Integrys purchase price allocation (5.2 ) — 27.5 — 0.4 — 22.7 — Acquisition of Integrys — 1,667.6 — 731.2 — 182.8 — 2,581.6 Goodwill balance as of December 31 * $ 2,104.3 $ 2,109.5 $ 758.7 $ 731.2 $ 183.2 $ 182.8 $ 3,046.2 $ 3,023.5 * We had no accumulated impairment losses related to our goodwill as of December 31, 2016 .

Common Equity (Tables)

Common Equity (Tables)	12 Months Ended
	Dec. 31, 2016
Stockholders' Equity Note [Abstract]
Schedule of stock-based compensation expense and related deferred tax benefit recognized in income	The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit for the years ended December 31: (in millions) 2016 2015 2014 Stock options $ 3.5 $ 3.3 $ 3.7 Restricted stock 5.8 7.0 2.8 Performance units 8.7 13.0 15.4 Stock-based compensation expense $ 18.0 $ 23.3 $ 21.9 Related tax benefit $ 7.2 $ 9.3 $ 8.8
Schedule of stock option activity	The following is a summary of our stock option activity during 2016 : Stock Options Number of Options Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life (in years) Aggregate Intrinsic Value (in millions) Outstanding as of January 1, 2016 5,984,664 $ 33.47 Granted 794,764 $ 52.15 Exercised (1,644,353 ) $ 25.30 Forfeited (12,300 ) $ 52.98 Outstanding as of December 31, 2016 5,122,775 $ 38.95 6.0 $ 100.9 Exercisable as of December 31, 2016 3,710,836 $ 35.38 5.2 $ 86.4
Schedule of restricted stock activity	The following restricted stock activity occurred during 2016 : Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding as of January 1, 2016 229,018 $ 46.78 Granted 146,941 $ 53.69 Released (141,224 ) $ 46.14 Forfeited (14,689 ) $ 54.39 Outstanding as of December 31, 2016 220,046 $ 51.30
Schedule of shares repurchased	The following table identifies shares purchased during the year ended December 31 : 2016 2015 2014 (in millions) Shares Cost Shares Cost Shares Cost Under share repurchase programs — $ — — $ — 0.4 $ 18.6 To fulfill exercised stock options and restricted stock awards 1.8 108.0 1.5 74.7 2.3 104.6 Total 1.8 $ 108.0 1.5 $ 74.7 $ 2.7 $ 123.2
Schedule of dividends declared	During the year ended December 31, 2016 , our Board of Directors declared common stock dividends which are summarized below: Date Declared Date Payable Per Share Period January 21, 2016 March 1, 2016 $0.4950 First quarter April 21, 2016 June 1, 2016 $0.4950 Second quarter July 21, 2016 September 1, 2016 $0.4950 Third quarter October 20, 2016 December 1, 2016 $0.4950 Fourth quarter

Preferred Stock (Tables)

Preferred Stock (Tables)	12 Months Ended
	Dec. 31, 2016
Class of Stock Disclosures [Abstract]
Schedule of stock by class	The following table shows preferred stock authorized and outstanding at December 31, 2016 and 2015 : (in millions, except share and per share amounts) Shares Authorized Shares Outstanding Redemption Price Per Share Total WEC Energy Group $.01 par value Preferred Stock 15,000,000 — — $ — WE $100 par value, Six Per Cent. Preferred Stock 45,000 44,498 — 4.4 $100 par value, Serial Preferred Stock 2,286,500 3.60% Series 260,000 $ 101 26.0 $25 par value, Serial Preferred Stock 5,000,000 — — — WPS $100 par value, Preferred Stock 1,000,000 — — — PGL $100 par value, Cumulative Preferred Stock 430,000 — — — NSG $100 par value, Cumulative Preferred Stock 160,000 — — — Total $ 30.4

Short-Term Debt and Lines of 52

Short-Term Debt and Lines of Credit (Tables)	12 Months Ended
	Dec. 31, 2016
Short-term Debt [Abstract]
Short-term notes payable balances and their corresponding weighted-average interest rates	The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31: (in millions, except percentages) 2016 2015 Commercial paper Amount outstanding at December 31 $ 860.2 $ 1,095.0 Average interest rate on amounts outstanding at December 31 0.96 % 0.68 %
Schedule of revolving credit facilities	The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities as of December 31 : (in millions) Maturity 2016 WEC Energy Group December 2020 $ 1,050.0 WE December 2020 500.0 WPS December 2020 250.0 WG December 2020 350.0 PGL December 2020 350.0 Total short-term credit capacity $ 2,500.0 Less: Letters of credit issued inside credit facilities $ 19.1 Commercial paper outstanding 860.2 Available capacity under existing agreements $ 1,620.7

Long-Term Debt and Capital Le53

Long-Term Debt and Capital Lease Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Long-term Debt and Capital Lease Obligations [Abstract]
Long-term debt outstanding maturities and sinking fund requirements	The following table shows the future maturities of our long-term debt outstanding (excluding obligations under capital leases) as of December 31, 2016: (in millions) Payments 2017 $ 154.5 2018 836.1 2019 357.7 2020 684.4 2021 336.2 Thereafter 6,953.5 Total $ 9,322.4
Summary of capitalized leased facilities	The following is a summary of our capitalized leased facilities as of December 31: (in millions) 2016 2015 Long-term power purchase commitment $ 140.3 $ 140.3 Accumulated amortization (109.5 ) (103.9 ) Total leased facilities $ 30.8 $ 36.4
Future minimum lease payments under capital lease and present value of net minimum lease payments	Future minimum lease payments under our capital lease and the present value of our net minimum lease payments as of December 31, 2016 are as follows: (in millions) Payments 2017 $ 13.9 2018 14.7 2019 15.5 2020 16.4 2021 17.2 Thereafter 7.6 Total minimum lease payments 85.3 Less: Estimated executory costs (39.9 ) Net minimum lease payments 45.4 Less: Interest (15.8 ) Present value of net minimum lease payments 29.6 Less: Due currently (2.7 ) Long-term obligations under capital lease $ 26.9

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Summary of income tax expense	The following table is a summary of income tax expense for the years ended December 31: (in millions) 2016 2015 2014 Current tax expense $ 72.7 $ 15.1 $ 33.6 Deferred income taxes, net 498.7 420.4 329.2 Investment tax credit, net (4.9 ) (1.7 ) (1.1 ) Total income tax expense $ 566.5 $ 433.8 $ 361.7
Schedule of Components of Income Tax Expense (Benefit)	The provision for income taxes for each of the years ended December 31 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: 2016 2015 2014 Effective Effective Effective (in millions) Amount Tax Rate Amount Tax Rate Amount Tax Rate Expected tax at statutory federal tax rates $ 526.4 35.0 % $ 375.5 35.0 % $ 332.5 35.0 % State income taxes net of federal tax benefit 72.8 4.8 % 73.1 6.8 % 50.5 5.3 % Production tax credits (15.7 ) (1.1 )% (17.4 ) (1.6 )% (17.4 ) (1.8 )% AFUDC – Equity (8.8 ) (0.6 )% (7.1 ) (0.7 )% (1.9 ) (0.2 )% Investment tax credit restored (4.9 ) (0.3 )% (1.7 ) (0.2 )% (1.1 ) (0.2 )% Other, net (3.3 ) (0.2 )% 11.4 1.1 % (0.9 ) (0.1 )% Total income tax expense $ 566.5 37.6 % $ 433.8 40.4 % $ 361.7 38.0 %
Components of deferred income taxes classified as net current assets and net long-term liabilities	The components of deferred income taxes as of December 31 are as follows: (in millions) 2016 2015 Deferred tax assets Future tax benefits $ 430.4 $ 382.8 Employee benefits and compensation 222.0 229.9 Deferred revenues 207.2 219.9 Property-related 54.5 59.5 Other 230.6 177.1 Total deferred tax assets 1,144.7 1,069.2 Valuation allowance (15.0 ) (17.1 ) Net deferred tax assets $ 1,129.7 $ 1,052.1 Deferred tax liabilities Property-related $ 4,979.3 $ 4,451.5 Investment in transmission affiliate 476.9 420.4 Employee benefits and compensation 401.6 428.9 Deferred transmission costs 93.1 76.7 Other 325.4 296.9 Total deferred tax liabilities 6,276.3 5,674.4 Deferred tax liability, net $ 5,146.6 $ 4,622.3
Components of deferred tax assets associated with federal and state tax benefit carryforwards	The components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2016 and 2015 are summarized in the tables below: 2016 (in millions) Gross Value Deferred Tax Effect Valuation Allowance Earliest Year of Expiration Future tax benefits as of December 31, 2016 Federal net operating loss $ 407.6 $ 142.7 $ — 2031 Federal foreign tax credit — 13.5 (13.5 ) 2017 Other federal tax credit — 241.1 — 2025 Charitable contribution 9.4 4.0 (1.5 ) 2016 State net operating loss 482.6 24.3 — 2024 State tax credit — 4.8 — 2016 Balance as of December 31, 2016 $ 899.6 $ 430.4 $ (15.0 ) 2015 (in millions) Gross Value Deferred Tax Effect Valuation Allowance Earliest Year of Expiration Future tax benefits as of December 31, 2015 Federal net operating loss $ 412.3 $ 144.3 $ — 2031 Federal foreign tax credit — 15.2 (15.2 ) 2017 Other federal tax credit — 207.8 — 2025 Charitable contribution 4.7 1.9 (1.9 ) 2016 State net operating loss 185.9 9.3 — 2024 State tax credit — 4.3 — 2016 Balance as of December 31, 2015 $ 602.9 $ 382.8 $ (17.1 )
Reconciliation of the beginning and ending amount of unrecognized tax benefits	We previously adopted accounting guidance related to uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: (in millions) 2016 2015 Balance as of January 1 $ 9.5 $ 7.2 Acquired legacy Integrys unrecognized tax benefits — 3.6 Additions for tax positions of prior years 6.7 0.3 Additions based on tax positions related to the current year 1.1 0.2 Reductions for tax positions of prior years (1.0 ) (1.1 ) Reductions due to statute of limitations (1.8 ) — Settlements during the period — (0.7 ) Balance as of December 31 $ 14.5 $ 9.5
Summary of income tax examinations	As of December 31, 2016, we were subject to examination by state or local tax authorities for the 2011 through 2016 tax years in our major state operating jurisdictions as follows: Jurisdiction Years Federal 2013–2016 Illinois 2013–2016 Michigan 2012–2016 Minnesota 2014–2016 Wisconsin 2011–2016

Guarantees (Tables)

Guarantees (Tables)	12 Months Ended
	Dec. 31, 2016
Guarantees [Abstract]
Schedule of outstanding guarantees	The following table shows our outstanding guarantees: Total Amounts Committed Expiration (in millions) at December 31, 2016 Less Than 1 Year 1 to 3 Years Over 3 Years Guarantees Standby letters of credit (1) $ 29.4 $ 27.9 $ 1.5 $ — Surety bonds (2) 10.9 10.3 0.6 — Other guarantees (3) 7.6 0.5 — 7.1 Total guarantees $ 47.9 $ 38.7 $ 2.1 $ 7.1 (1) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets. (2) Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets. (3) Consists of $7.6 million related to other indemnifications, for which a liability of $7.1 million related to workers compensation coverage was recorded on our balance sheets.

Employee Benefits (Tables)

Employee Benefits (Tables)	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Reconciliation of the changes in the plans' benefit obligations and fair value of assets	The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets: Pension Costs OPEB Costs (in millions) 2016 2015 2016 2015 Change in benefit obligation Obligation at January 1 $ 3,083.0 $ 1,505.5 $ 842.0 $ 397.7 Obligation assumed from acquisition — 1,594.0 — 493.0 Service cost 45.4 30.4 26.1 20.7 Interest cost 130.8 94.3 37.0 26.7 Participant contributions — — 16.4 12.7 Plan amendments (3.0 ) — (18.9 ) — Actuarial loss (gain) 71.7 14.6 (36.5 ) (74.0 ) Benefit payments (269.1 ) (156.0 ) (49.1 ) (36.2 ) Federal subsidy on benefits paid N/A N/A 1.4 1.6 Plan curtailment — 0.2 — (0.2 ) Obligation at December 31 $ 3,058.8 $ 3,083.0 $ 818.4 $ 842.0 Change in fair value of plan assets Fair value at January 1 $ 2,755.1 $ 1,444.6 $ 749.8 $ 333.5 Assets received from acquisition — 1,420.9 — 442.1 Actual return on plan assets 199.4 (62.1 ) 51.5 (15.6 ) Employer contributions 23.8 107.7 4.9 13.3 Participant contributions — — 16.4 12.7 Benefit payments (269.1 ) (156.0 ) (49.1 ) (36.2 ) Fair value at December 31 $ 2,709.2 $ 2,755.1 $ 773.5 $ 749.8 Funded status at December 31 $ (349.6 ) $ (327.9 ) $ (44.9 ) $ (92.2 )
Amounts recognized on the balance sheets at December 31 related to the funded status of the benefit plans	The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows: Pension Costs OPEB Costs (in millions) 2016 2015 2016 2015 Other long-term assets $ 74.4 $ 74.1 $ 29.7 $ 50.1 Pension and OPEB obligations * 424.0 402.0 74.6 142.3 Total net liabilities $ (349.6 ) $ (327.9 ) $ (44.9 ) $ (92.2 ) * Includes $0.8 million of pension and $0.4 million of OPEB obligations classified as liabilities held for sale as of December 31, 2015. These amounts are included in other current liabilities on our balance sheets.
Information for pension plans with an accumulated benefit obligation in excess of plan assets	The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2016 2015 Projected benefit obligation $ 1,667.0 $ 1,706.6 Accumulated benefit obligation 1,549.5 1,560.5 Fair value of plan assets 1,242.9 1,304.6
Amounts that had not yet been recognized in the entity's net periodic benefit cost	The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31: Pension Costs OPEB Costs (in millions) 2016 2015 2016 2015 Accumulated other comprehensive loss (pre-tax) (1) Net actuarial loss (gain) $ 12.0 $ 11.4 $ (1.0 ) $ (0.6 ) Total $ 12.0 $ 11.4 $ (1.0 ) $ (0.6 ) Net regulatory assets (2) Net actuarial loss $ 1,240.7 $ 798.1 $ 25.8 $ 23.7 Prior service costs (credits) 10.5 4.7 (87.9 ) (3.3 ) Total $ 1,251.2 $ 802.8 $ (62.1 ) $ 20.4 (1) Amounts related to the nonregulated entities are included in accumulated other comprehensive loss. (2) Amounts related to the utilities and WBS are recorded as net regulatory assets or liabilities.
Estimated amounts that will be amortized into net periodic benefit cost	The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2017: (in millions) Pension Costs OPEB Costs Net actuarial loss $ 87.2 $ 5.8 Prior service costs (credits) 3.0 (11.2 ) Total 2017 – estimated amortization $ 90.2 $ (5.4 )
Schedule of the components of net periodic benefit cost	The components of net periodic benefit cost (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows: Pension Costs OPEB Costs (in millions) 2016 2015 2014 2016 2015 2014 Service cost $ 45.4 $ 30.4 $ 10.1 $ 26.1 $ 20.7 $ 8.5 Interest cost 130.8 94.3 68.1 37.0 26.7 17.8 Expected return on plan assets (195.9 ) (155.6 ) (98.6 ) (52.7 ) (39.6 ) (23.7 ) Plan settlement 16.5 — — — — — Plan curtailment — (0.3 ) — — — — Amortization of prior service cost (credit) 3.4 2.2 2.1 (9.4 ) (6.4 ) (1.8 ) Amortization of net actuarial loss 82.9 68.5 36.7 8.5 3.9 1.2 Net periodic benefit cost $ 83.1 $ 39.5 $ 18.4 $ 9.5 $ 5.3 $ 2.0
Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost for the plans	The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension OPEB 2016 2015 2016 2015 Discount rate 4.16% 4.46% 4.14% 4.38% Rate of compensation increase 3.60% 4.00% N/A N/A Assumed medical cost trend rate N/A N/A 7.00% 7.50% Ultimate trend rate N/A N/A 5.00% 5.00% Year ultimate trend rate is reached N/A N/A 2021 2021 The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Costs 2016 2015 2014 Discount rate 4.35% 4.11% 5.00% Expected return on plan assets 7.12% 7.37% 7.25% Rate of compensation increase 3.75% 4.00% 4.00% OPEB Costs 2016 2015 2014 Discount rate 4.38% 4.09% 4.95% Expected return on plan assets 7.25% 7.54% 7.50% Assumed medical cost trend rate (Pre 65/Post 65) 7.50% 7.50% 7.50% Ultimate trend rate 5.00% 5.00% 5.00% Year ultimate trend rate is reached 2021 2021 2021
Effects of a one-percentage-point change in assumed health care cost trend rates	For the year ended December 31, 2016 , a one-percentage-point change in assumed health care cost trend rates would have had the following effects: (in millions) 1% Increase 1% Decrease Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $ 8.5 $ (6.9 ) Effect on health care component of the accumulated postretirement benefit obligations 49.6 (39.5 )
Investments recorded at fair value, by asset class	The following tables provide the fair values of our investments by asset class: December 31, 2016 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ 3.7 $ 58.0 $ — $ 61.7 $ 28.8 $ 3.4 $ — $ 32.2 Equity securities: United States Equity 273.9 0.1 — 274.0 34.3 — — 34.3 International Equity 54.1 0.6 — 54.7 3.5 0.2 — 3.7 Fixed income securities: * United States Bonds — 861.3 0.8 862.1 — 137.9 — 137.9 International Bonds — 75.9 — 75.9 — 8.8 — 8.8 Private Equity and Real Estate — — 14.6 14.6 — — 1.3 1.3 $ 331.7 $ 995.9 $ 15.4 $ 1,343.0 $ 66.6 $ 150.3 $ 1.3 $ 218.2 Investments measured at net asset value $ 1,366.2 $ 555.3 Total $ 331.7 $ 995.9 $ 15.4 $ 2,709.2 $ 66.6 $ 150.3 $ 1.3 $ 773.5 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2015 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ 17.0 $ 29.6 $ — $ 46.6 $ 10.5 $ 1.0 $ — $ 11.5 Equity securities: United States Equity 132.6 3.4 — 136.0 24.6 0.1 — 24.7 International Equity 103.9 — — 103.9 21.4 — — 21.4 Fixed income securities: * United States Bonds 11.4 797.3 — 808.7 0.3 122.0 — 122.3 International Bonds — 80.3 — 80.3 — 8.1 — 8.1 Private Equity and Real Estate — — 5.5 5.5 — — 0.4 0.4 $ 264.9 $ 910.6 $ 5.5 $ 1,181.0 $ 56.8 $ 131.2 $ 0.4 $ 188.4 Investments measured at net asset value $ 1,574.1 $ 561.4 Total $ 264.9 $ 910.6 $ 5.5 $ 2,755.1 $ 56.8 $ 131.2 $ 0.4 $ 749.8 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.
Reconciliation of changes in the fair value of pension assets categorized as Level 3 measurements	The following tables set forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy: Private Equity and Real Estate United States Bonds (in millions) Pension OPEB Pension Beginning balance at January 1, 2016 $ 5.5 $ 0.4 $ — Realized and unrealized gains 0.5 0.1 — Purchases 8.6 0.8 0.8 Ending balance at December 31, 2016 $ 14.6 $ 1.3 $ 0.8 Private Equity and Real Estate (in millions) Pension OPEB Beginning balance at January 1, 2015 $ — $ — Purchases 5.5 0.4 Ending balance at December 31, 2015 $ 5.5 $ 0.4
Schedule of expected future benefit payments	The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB: (in millions) Pension Costs OPEB Costs 2017 $ 215.7 $ 41.8 2018 217.1 49.6 2019 226.5 49.0 2020 233.1 50.9 2021 230.0 53.1 2022-2026 1,031.5 278.5

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of minimum future commitments related to purchase obligations	The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2016 , including those of our subsidiaries. Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2017 2018 2019 2020 2021 Later Years Electric utility: Nuclear 2033 $ 9,599.8 $ 415.3 $ 420.1 $ 445.4 $ 475.1 $ 501.1 $ 7,342.8 Purchased power 2027 693.3 111.3 75.9 66.2 66.3 63.9 309.7 Coal supply and transportation 2019 455.0 269.4 140.3 45.3 — — — Natural gas utility supply and transportation 2028 1,229.4 341.7 285.5 237.5 159.7 78.6 126.4 Total $ 11,977.5 $ 1,137.7 $ 921.8 $ 794.4 $ 701.1 $ 643.6 $ 7,778.9
Schedule of minimum future payments under noncancelable operating leases	Future minimum payments under noncancelable operating leases are payable as follows: Year Ending December 31 Payments (in millions) 2017 $ 9.9 2018 8.8 2019 5.9 2020 5.3 2021 5.5 Later years 60.1 Total $ 95.5
Schedule of regulatory assets and reserves related to manufactured gas plants	We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31: (in millions) 2016 2015 Regulatory assets $ 702.7 $ 697.0 Reserves for future remediation 633.4 628.0

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
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: December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 10.1 $ 24.2 $ — $ 34.3 Petroleum products contracts 0.2 — — 0.2 FTRs — — 5.1 5.1 Coal contracts — 2.0 — 2.0 Total derivative assets $ 10.3 $ 26.2 $ 5.1 $ 41.6 Investments held in rabbi trust $ 103.9 $ — $ — $ 103.9 Derivative liabilities Natural gas contracts $ 0.2 $ 0.2 $ — $ 0.4 Petroleum products contracts 0.1 — — 0.1 Coal contracts — 1.9 — 1.9 Total derivative liabilities $ 0.3 $ 2.1 $ — $ 2.4 December 31, 2015 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.6 $ 1.5 $ — $ 3.1 Petroleum products contracts 1.2 — — 1.2 FTRs — — 3.6 3.6 Coal contracts — 2.0 — 2.0 Total derivative assets $ 2.8 $ 3.5 $ 3.6 $ 9.9 Investments held in rabbi trust $ 39.8 $ — $ — $ 39.8 Derivative liabilities Natural gas contracts $ 16.5 $ 25.3 $ — $ 41.8 Petroleum products contracts 4.9 — — 4.9 Coal contracts — 12.3 — 12.3 Total derivative liabilities $ 21.4 $ 37.6 $ — $ 59.0
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 at December 31 : (in millions) 2016 2015 2014 Balance at the beginning of the period $ 3.6 $ 7.0 $ 3.5 Realized and unrealized (losses) gains (0.2 ) 1.3 — Purchases 15.2 3.9 15.6 Sales (0.2 ) (0.1 ) — Settlements (13.3 ) (11.9 ) (12.1 ) Acquisition of Integrys — (1.3 ) — Transfers out of level 3 — 4.7 — Balance at the end of the period $ 5.1 $ 3.6 $ 7.0
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 at December 31 : 2016 2015 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 28.8 $ 30.4 $ 27.3 Long-term debt, including current portion * $ 9,285.8 $ 9,818.2 $ 9,221.9 $ 9,681.0 * The carrying amount of long-term debt excludes capital lease obligations of $29.6 million and $59.9 million at December 31, 2016 and December 31, 2015 , respectively.

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets and liabilities	The following table shows our derivative assets and derivative liabilities: December 31, 2016 December 31, 2015 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 31.4 $ 0.4 $ 2.6 $ 38.5 Petroleum products contracts 0.2 0.1 0.9 3.8 FTRs 5.1 — 3.6 — Coal contracts 1.5 1.4 1.7 6.7 Total other current $ 38.2 $ 1.9 $ 8.8 $ 49.0 Other long-term Natural gas contracts $ 2.9 $ — $ 0.5 $ 3.3 Petroleum products contracts — — 0.3 1.1 Coal contracts 0.5 0.5 0.3 5.6 Total other long-term $ 3.4 $ 0.5 $ 1.1 $ 10.0 Total $ 41.6 $ 2.4 $ 9.9 $ 59.0
Estimated notional volumes and realized gain (losses)	Our estimated notional sales volumes and realized gains (losses) were as follows: December 31, 2016 December 31, 2015 December 31, 2014 (in millions) Volume Gains (Losses) Volume Gains (Losses) Volume Gains Natural gas contracts 151.1 Dth $ (59.6 ) 86.2 Dth $ (50.5 ) 40.5 Dth $ 7.3 Petroleum products contracts 14.7 gallons (3.2 ) 7.8 gallons (1.9 ) 9.2 gallons 0.5 FTRs 33.7 MWh 13.3 27.3 MWh 6.7 26.1 MWh 12.7 Total $ (49.5 ) $ (45.7 ) $ 20.5
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: December 31, 2016 December 31, 2015 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 41.6 $ 2.4 $ 9.9 $ 59.0 Gross amount not offset on the balance sheet * (4.9 ) (0.5 ) (3.0 ) (22.5 ) Net amount $ 36.7 $ 1.9 $ 6.9 $ 36.5 * Includes cash collateral received of $4.4 million at December 31, 2016, and cash collateral posted of $19.5 million at December 31, 2015 .

Other Income, net (Tables)

Other Income, net (Tables)	12 Months Ended
	Dec. 31, 2016
Other Income, net [Abstract]
Schedule of Other Nonoperating Income (Expense) [Table Text Block]	Total other income, net was as follows for the years ended December 31 : (in millions) 2016 2015 2014 AFUDC – Equity $ 25.1 $ 20.1 $ 5.6 Gain on repurchase of notes 23.6 — — Gain on asset sales 19.6 22.9 7.5 Other, net 12.5 15.9 0.3 Other income, net $ 80.8 $ 58.9 $ 13.4

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Schedule of information concerning our reportable segments	The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2016 , 2015 , and 2014 . Regulated Operations 2016 (in millions) Wisconsin Illinois Other States Electric Transmission Total Regulated Operations We Power Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated External revenues $ 5,805.4 $ 1,242.2 $ 376.5 $ — $ 7,424.1 $ 24.9 $ 23.3 $ — $ 7,472.3 Intersegment revenues 0.3 — — — 0.3 423.3 — (423.6 ) — Other operation and maintenance 2,025.4 485.1 110.1 — 2,620.6 4.3 (15.8 ) (423.6 ) 2,185.5 Depreciation and amortization 496.6 134.0 21.1 — 651.7 68.3 42.6 — 762.6 Operating income (loss) 1,027.0 239.6 49.9 — 1,316.5 375.6 (10.0 ) — 1,682.1 Equity in earnings of transmission affiliate — — — 146.5 146.5 — — — 146.5 Interest expense 180.9 38.9 8.5 — 228.3 62.1 120.9 (8.6 ) 402.7 Capital expenditures 910.9 293.2 59.5 — 1,263.6 62.3 97.8 — 1,423.7 Total assets * 21,730.7 5,714.6 995.1 1,476.9 29,917.3 2,777.1 778.0 (3,349.2 ) 30,123.2 * Total assets at December 31, 2016 reflect an elimination of $2,029.5 million for all lease activity between We Power and WE. Regulated Operations 2015 (in millions) Wisconsin Illinois Other States Electric Transmission Total Regulated Operations We Power Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated External revenues $ 5,186.1 $ 503.4 $ 149.3 $ — $ 5,838.8 $ 40.0 $ 47.3 $ — $ 5,926.1 Intersegment revenues 5.0 — — — 5.0 405.2 — (410.2 ) — Other operation and maintenance 1,741.0 219.6 50.0 — 2,010.6 4.3 103.7 (409.3 ) 1,709.3 Depreciation and amortization 408.6 63.3 10.0 — 481.9 67.5 12.4 — 561.8 Operating income (loss) 884.2 78.1 6.0 — 968.3 373.4 (91.2 ) — 1,250.5 Equity in earnings of transmission affiliate — — — 96.1 96.1 — — — 96.1 Interest expense 157.1 19.9 5.1 — 182.1 63.4 91.0 (5.1 ) 331.4 Capital expenditures 950.3 194.4 34.7 — 1,179.4 53.4 33.4 — 1,266.2 Total assets * 21,113.5 5,462.9 918.0 1,381.0 28,875.4 2,779.0 1,132.5 (3,431.7 ) 29,355.2 * Total assets at December 31, 2015 reflect an elimination of $2,105.3 million for all lease activity between We Power and WE. Regulated Operations 2014 (in millions) Wisconsin Illinois Other States Electric Transmission Total Regulated Operations We Power Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated External revenues $ 4,932.1 $ — $ — $ — $ 4,932.1 $ 55.7 $ 9.3 $ — $ 4,997.1 Intersegment revenues 9.2 — — — 9.2 383.4 — (392.6 ) — Other operation and maintenance 1,462.7 — — — 1,462.7 4.4 33.0 (387.7 ) 1,112.4 Depreciation and amortization 323.2 — — — 323.2 66.7 1.5 — 391.4 Operating income (loss) 770.2 — — — 770.2 368.0 (26.1 ) — 1,112.1 Equity in earnings of transmission affiliate — — — 66.0 66.0 — — — 66.0 Interest expense 127.6 — — — 127.6 64.6 48.8 (0.7 ) 240.3 Capital expenditures 715.0 — — — 715.0 41.0 5.2 — 761.2 Total assets * 14,403.8 — — 424.1 14,827.9 2,789.9 253.3 (2,966.1 ) 14,905.0 * Total assets at December 31, 2014 reflect an elimination of $2,172.9 million for all lease activity between We Power and WE.

QUARTERLY FINANCIAL INFORMATI62

QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information (unaudited)	(in millions, except per share amounts) First Quarter Second Quarter Third Quarter Fourth Quarter Total 2016 Operating revenues $ 2,194.8 $ 1,602.0 $ 1,712.5 $ 1,963.0 $ 7,472.3 Operating income 589.3 332.1 399.0 361.7 1,682.1 Net income attributed to common shareholders 346.2 181.4 217.0 194.4 939.0 Earnings per share * Basic $ 1.10 $ 0.57 $ 0.69 $ 0.62 $ 2.98 Diluted 1.09 0.57 0.68 0.61 2.96 2015 Operating revenues $ 1,387.9 $ 991.2 $ 1,698.7 $ 1,848.3 $ 5,926.1 Operating income 358.8 165.8 345.7 380.2 1,250.5 Net income attributed to common shareholders 195.8 80.9 182.5 179.3 638.5 Earnings per share * Basic $ 0.87 $ 0.36 $ 0.58 $ 0.57 $ 2.36 Diluted 0.86 0.35 0.58 0.57 2.34 * Earnings per share for the individual quarters do not total the year ended earnings per share amount because of changes to the average number of shares outstanding and changes in incremental issuable shares throughout the year.

Summary of Significant Accoun63

Summary of Significant Accounting Policies General Information (Details)	Dec. 31, 2016	Jun. 29, 2015
Electric
Product Information
Number of customers	1,600,000
Natural gas
Product Information
Number of customers	2,800,000
ATC
Product Information
Equity method investment, ownership interest (as a percent)	60.00%	26.20%

Summary of Significant Accoun64

Summary of Significant Accounting Policies Cash and Cash Equivalents (Details)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Maximum term of original maturity to classify instrument as cash equivalent	3 months

Summary of Significant Accoun65

Summary of Significant Accounting Policies Revenues and Customer Receivables (Details)	12 Months Ended
	Dec. 31, 2016customer
Revenues from external customers
Percent fuel costs can vary from the rate case approved costs before deferral is required	2.00%
Customer concentration risk
Revenues from external customers
Number of customers that account for more than 10% of revenues	0
Threshold percentage of revenues from major customers	10.00%

Summary of Significant Accoun66

Summary of Significant Accounting Policies Materials, Supplies, and Inventories (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)$ / Dekatherm	Dec. 31, 2015USD ($)$ / Dekatherm
Inventory
Natural gas in storage	$ 223.1	$ 284.1
Materials and supplies	206.5	219.2
Fossil fuel	158	183.7
Total	$ 587.6	$ 687
Percentage of LIFO inventory	18.00%	18.00%
PGL and NSG
Inventory
Excess of replacement or current costs over stated LIFO value	$ 92.9	$ 15.2
Natural gas price benchmark | $ / Dekatherm	3.63	2.48

Summary of Significant Accoun67

Summary of Significant Accounting Policies Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
PWGS | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful life	10 years
PWGS | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful life	45 years
ERGS | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful life	10 years
ERGS | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful life	55 years
Software | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful life	3 years
Software | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful life	15 years
WE
Public Utility, Property, Plant and Equipment [Line Items]
Annual utility composite depreciation rate (as a percent)	3.00%	3.01%	2.93%
WPS
Public Utility, Property, Plant and Equipment [Line Items]
Annual utility composite depreciation rate (as a percent)	2.58%	1.30%
WG
Public Utility, Property, Plant and Equipment [Line Items]
Annual utility composite depreciation rate (as a percent)	2.34%	2.36%	2.69%
PGL
Public Utility, Property, Plant and Equipment [Line Items]
Annual utility composite depreciation rate (as a percent)	3.31%	1.67%
NSG
Public Utility, Property, Plant and Equipment [Line Items]
Annual utility composite depreciation rate (as a percent)	2.44%	1.22%
MERC
Public Utility, Property, Plant and Equipment [Line Items]
Annual utility composite depreciation rate (as a percent)	2.53%	1.26%
MGU
Public Utility, Property, Plant and Equipment [Line Items]
Annual utility composite depreciation rate (as a percent)	2.63%	1.32%

Summary of Significant Accoun68

Summary of Significant Accounting Policies AFUDC (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Allowance for Funds Used During Construction
AFUDC - Debt	$ 10.9	$ 8.6	$ 2.3
AFUDC - Equity	$ 25.1	$ 20.1	$ 5.6
WE
Allowance for Funds Used During Construction
Percentage of retail jurisdictional construction work in progress expenditure subject to public utilities allowance for funds used during construction calculation	50.00%
Retail operations | WE
Allowance for Funds Used During Construction
Interest rate on accrued AFUDC	8.45%
Retail operations | WPS
Allowance for Funds Used During Construction
Interest rate on accrued AFUDC	7.72%
Retail operations | WG
Allowance for Funds Used During Construction
Interest rate on accrued AFUDC	8.33%
Wholesale operations | WE
Allowance for Funds Used During Construction
Interest rate on accrued AFUDC	2.73%
Wholesale operations | WPS
Allowance for Funds Used During Construction
Interest rate on accrued AFUDC	3.00%

Summary of Significant Accoun69

Summary of Significant Accounting Policies Stock-Based Compensation (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized for issuance	34,300,000
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	3 years
Minimum exercise price of stock option as a percent of common stock fair value on the grant date	100.00%
Period after the grant date during which stock options can't be exercised (in months)	6 months
Maximum term of awards (in years)	10 years
Non-qualified stock options granted (in shares)	794,764	516,475	899,500
Estimated fair value per non-qualified stock option (in dollars per share)	$ 5.14	$ 5.29	$ 4.18
Risk-free interest rate, minimum (as a percent)	0.40%	0.10%	0.10%
Risk-free interest rate, maximum (as a percent)	2.20%	2.10%	3.00%
Dividend yield (as a percent)	4.00%	3.70%	3.80%
Expected volatility (as a percent)	18.10%	18.00%	18.00%
Expected life (in years)	6 years 1 month	5 years 10 months	5 years 10 months
Restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	3 years
Percentage to vest each year after grant date	33.00%
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	3 years
Performance units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance units, payout ratio (as a percent)	0.00%
Performance units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance units, payout ratio (as a percent)	175.00%

Summary of Significant Accoun70

Summary of Significant Accounting Policies Earnings Per Share (Details) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	181,709	516,475	0

Acquisitions - Consideration Tr

Acquisitions - Consideration Transferred for Integrys Acquisition (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended
	Jun. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Jun. 29, 2015
Business Acquisition [Line Items]
Integrys common shares outstanding at June 29, 2015		315,614,941	315,683,496
ATC
Business Acquisition [Line Items]
Equity interest in ATC				60.00%
Integrys
Business Acquisition [Line Items]
Percentage of Integrys common shares acquired				100.00%
Integrys common shares outstanding at June 29, 2015				79,963,091
Exchange ratio	1.128
Wisconsin Energy Corporation shares issued for Integrys shares	90,187,884
Closing price of Wisconsin Energy Corporation common shares on June 29, 2015				$ 45.16
Fair value of common stock issued				$ 4,072.9
Cash paid per share of Integrys shares outstanding	$ 18.58
Fair value of cash paid for Integrys shares				1,486.2
Consideration attributable to settlement of equity awards, net of tax				24
Total cash consideration paid for acquisition				$ 1,510.2
Total purchase price	$ 5,583.1
Number of Wisconsin Energy Corporation fractional shares that were paid in cash				10,483
Dollar value of Wisconsin Energy Corporation fractional shares paid in cash				$ 0.5
Integrys | ATC
Business Acquisition [Line Items]
Equity interest in ATC		34.00%

Acquisitions - Purchase Price A

Acquisitions - Purchase Price Allocation for Integrys Acquisition (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Jun. 29, 2015
Assets acquired
Goodwill		$ 0	$ 2,581.6
Integrys
Business Acquisition [Line Items]
Deferred taxes related to goodwill		0
Assets acquired
Current assets				$ 1,060.1
Property, plant, and equipment, net				7,107.4
Goodwill	$ 2,604.3
Other long-term assets				2,830.5
Liabilities assumed
Current liabilities				(1,320.7)
Long-term debt				(2,943.6)
Other long-term liabilities				(3,703.8)
Preferred stock of subsidiary				$ (51.1)
Total purchase price	$ 5,583.1
Accounting Standards Update 2015-16
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Impact of adoption of ASU 2015-16		$ 0

Acquisitions - Approval Conditi

Acquisitions - Approval Conditions for Integrys Acquisition (Details) - Integrys - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2016	Jun. 29, 2015
Earnings sharing mechanisms
Business Acquisition [Line Items]
Expense for earnings sharing mechanisms		$ 24.4
WE
Business Acquisition [Line Items]
Duration of earnings cap condition imposed by the PSCW (in years)	3 years
Percentage of first 50 basis points to be shared with customers			50.00%
ROE in excess of authorized amount (as a percent)			0.50%
WG
Business Acquisition [Line Items]
Duration of earnings cap condition imposed by the PSCW (in years)	3 years
Percentage of first 50 basis points to be shared with customers			50.00%
ROE in excess of authorized amount (as a percent)			0.50%
PGL
Business Acquisition [Line Items]
Duration of base rate freeze condition imposed by the ICC (in years)	2 years
NSG
Business Acquisition [Line Items]
Duration of base rate freeze condition imposed by the ICC (in years)	2 years

Acquisitions - Pro Forma Financ

Acquisitions - Pro Forma Financial Information for Integrys Acquisition (Details) - Integrys - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Operating Revenues	$ 7,727.1	$ 9,135.4
Net income attributed to common shareholders	$ 873.5	$ 869.9
Earnings per share (Basic)	$ 2.77	$ 2.76
Earnings per share (Diluted)	$ 2.75	$ 2.74

Acquisitions - Impacts of Integ

Acquisitions - Impacts of Integrys Acquisition (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jun. 29, 2015
ATC
Business Combinations [Abstract]
Equity interest in ATC				60.00%
Integrys
Business Acquisition [Line Items]
Acquisition costs	$ 3.5	$ 107.6	$ 12.5
Severance expense		24.9
Severance payments	$ 7.5	16.9
Revenue attributable to Integrys		1,416.8
Net income attributable to Integrys		65.9
Integrys | ATC
Business Combinations [Abstract]
Equity interest in ATC	34.00%
Integrys | Wisconsin
Business Acquisition [Line Items]
Severance expense		11.1
Integrys | Illinois
Business Acquisition [Line Items]
Severance expense		0.9
Integrys | Other States
Business Acquisition [Line Items]
Severance expense		0.1
Integrys | Corporate and Other
Business Acquisition [Line Items]
Severance expense		$ 12.8

Acquisitions - Natural Gas Stor

Acquisitions - Natural Gas Storage Facility in Michigan (Details) - Natural gas storage facility in Michigan - Subsequent event - USD ($) $ in Millions	Jan. 01, 2017	Jan. 31, 2017
Business Acquisition [Line Items]
Total purchase price	$ 225
Expected acquisition costs		$ 5
Percentage of storage needs provided		33.00%

Dispositions (Details)

Dispositions (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Dispositions
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal			$ 19.6	$ 22.9	$ 7.5
Wisconsin | WE
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]
DisposalGroupNotDiscontinuedOperationsAftertaxGainLossOnDisposal	$ 6.5
Corporate and Other | Wisvest [Member]
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]
DisposalGroupNotDiscontinuedOperationsAftertaxGainLossOnDisposal	11.8
Corporate and Other | ITF
Dispositions
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		$ 0
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]
Accounts receivable and unbilled revenues				37.2
Materials, supplies, and inventories				34.9
Other current assets				18.4
Property, plant, and equipment				2.6
Other long-term assets				3.7
Total assets				96.8
Accounts payable				12.9
Accrued payroll and benefits				2.4
Other current liabilities				4.5
Pension and OPEB obligations				1.2
Other long-term liabilities				0.6
Total liabilities				$ 21.6
Operating Expense [Member] | Wisconsin | WE
Dispositions
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal	10.9
Other Income [Member] | Corporate and Other | Wisvest [Member]
Dispositions
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal	$ 19.6

Investment in American Transm78

Investment in American Transmission Company - Changes to Investment in ATC (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)membervote	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jun. 29, 2015
Changes to investment in ATC
Equity in earnings of transmission affiliate	$ 146.5	$ 96.1	$ 66
Capital contributions	$ 42.3	8.7	13.1
ATC
Investment in ATC
Equity interest in ATC	60.00%			26.20%
Number of representatives on ATC's board of directors | member	1
Total number of members serving on ATC's board of directors | member	10
Number of votes that can be placed by each member on ATC's board of directors | vote	1
Number of members on ATC's board of directors with more than 10% voting control | member	0
Maximum voting control of any member on ATC's board of directors	10.00%
Changes to investment in ATC
Investment in ATC, balance at beginning of period	$ 1,380.9	424.1	402.7
Equity in earnings of transmission affiliate	146.5	96.1	66
Capital contributions	42.3	8.7	13.1
Acquisition of Integrys's investment in ATC	(1)	541.5	0
Equity method goodwill from the acquisition of Integrys	10.4	395.8	0
Distributions	135.1	85.1	57.5
Other	0.1	0.2	0.2
Investment in ATC, balance at end of period	1,443.9	$ 1,380.9	$ 424.1
Dividends not received
Dividends Receivable	$ 35.2

Investment in American Transm79

Investment in American Transmission Company - Transactions with ATC (Details) - ATC - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Investment in ATC
Charges to ATC for services and construction	$ 18.5	$ 15.4	$ 8.1
Charges from ATC for network transmission services	357.3	289.2	$ 231.4
Accounts receivable for services provided to ATC	2.2	1
Accounts payable for services received from ATC	$ 28.7	$ 28.3

Investment in American Transm80

Investment in American Transmission Company - ATC Summarized Financial Data (Details) - ATC - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income statement data
Revenues	$ 650.8	$ 615.8	$ 635
Operating expenses	322.5	319.3	307.4
Other expense	95.5	96.1	88.9
Net income	232.8	200.4	$ 238.7
Balance sheet data
Current assets	75.8	80.5
Noncurrent assets	4,312.9	3,948.3
Total assets	4,388.7	4,028.8
Current liabilities	495.1	330.3
Long-term debt	1,865.3	1,790.7
Other noncurrent liabilities	271.5	245
Shareholders' equity	1,756.8	1,662.8
Total liabilities and shareholders' equity	$ 4,388.7	$ 4,028.8

Supplemental Cash Flow Inform81

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Cash (paid) for interest, net of amount capitalized	$ (411.9)	$ (329.6)	$ (241.4)
Cash received for income taxes, net	39.7
Cash (paid) for income taxes, net		(9.3)	(22)
Accounts payable related to construction costs	170.1	177.1	1.8
Restricted cash used to purchase investments held in the rabbi trust	59.2	60.2	0
Restricted cash	33.6	118.4
Amortization of deferred revenue	24.7	39.9	55.7
AMP Trillium LLC [Member]
Related Party Transaction [Line Items]
Note reveivable received related to the sale of AMP Trillium	0	12	0
Capital assets received related to the sale of AMP Trillium	$ 0	$ 6.3	$ 0
Equity method investment, ownership interest (as a percent)		30.00%

Regulatory Assets and Liabili82

Regulatory Assets and Liabilities - Regulatory Assets (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets
Current assets	$ 50.4	$ 37.1
Regulatory assets	3,087.9	3,064.6
Total Regulatory Assets	3,138.3	3,101.7
Other Disclosures
Regulatory assets not earning a return	32.7
Regulatory assets earnings return based on short-term interest rates	204
Environmental remediation liabilities	633.6	628.2
Unrecognized pension and OPEB costs
Regulatory Assets
Total Regulatory Assets	1,252.1	1,306.4
Environmental remediation costs
Regulatory Assets
Total Regulatory Assets	702.7	697
Other Disclosures
Environmental remediation liabilities	633.6
Income tax related items
Regulatory Assets
Total Regulatory Assets	285.1	248.3
Electric transmission costs
Regulatory Assets
Total Regulatory Assets	234.1	191.5
SSR
Regulatory Assets
Total Regulatory Assets	188.1	86.1
AROs
Regulatory Assets
Total Regulatory Assets	179.2	173
We Power generation
Regulatory Assets
Total Regulatory Assets	54.1	45.4
Energy efficiency programs
Regulatory Assets
Total Regulatory Assets	36.7	48.7
Derivatives
Regulatory Assets
Total Regulatory Assets	17.9	70.4
Other, net
Regulatory Assets
Total Regulatory Assets	$ 188.3	$ 234.9

Regulatory Assets and Liabili83

Regulatory Assets and Liabilities - Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Regulatory Liabilities
Other current liabilities	$ 33.4	$ 33.8
Regulatory liabilities	1,563.8	1,392.2
Total regulatory liabilities	1,597.2	1,426
Removal costs
Regulatory Liabilities
Total regulatory liabilities	1,262.7	1,209.6
Mines deferral
Regulatory Liabilities
Total regulatory liabilities	70.2	31.6
Energy costs refundable through rate adjustments
Regulatory Liabilities
Total regulatory liabilities	88.7	76.9
Unrecognized pension and OPEB costs
Regulatory Liabilities
Total regulatory liabilities	63	26.3
Derivatives
Regulatory Liabilities
Total regulatory liabilities	41.1	12.6
Uncollectible expense
Regulatory Liabilities
Total regulatory liabilities	36.1	31.8
Other, net
Regulatory Liabilities
Total regulatory liabilities	$ 35.4	$ 37.2

Property, Plant, and Equipmen84

Property, Plant, and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Accumulated depreciation	$ 8,214.6	$ 7,919.1
Net property, plant, and equipment	19,915.5	19,189.7
Utility operations
Property, Plant and Equipment [Line Items]
Property, plant, and equipment	24,185.1	22,803.7
Accumulated depreciation	7,609.7	7,358.2
Net	16,575.4	15,445.5
CWIP	320	672.7
Net property, plant, and equipment	16,895.4	16,118.2
Nonutility operations
Property, Plant and Equipment [Line Items]
Property, plant, and equipment	3,520.3	3,482.2
Accumulated depreciation	604.9	560.9
Net	2,915.4	2,921.3
CWIP	104.7	150.2
Net property, plant, and equipment	$ 3,020.1	$ 3,071.5

Jointly Owned Facilities (Detai

Jointly Owned Facilities (Details) $ in Millions	Dec. 31, 2016USD ($)MW
Oak Creek Expansion Units 1 and 2 | We Power
Jointly Owned Electric Generating Facilities
Ownership (as a percentage)	83.34%
Share of rated capacity (MWs) (1) | MW	1,056.8
Property, plant, and equipment	$ 2,430.8
Accumulated depreciation	(331.5)
Construction Work in Progress	$ 9.4
Weston 4 | WPS
Jointly Owned Electric Generating Facilities
Ownership (as a percentage)	70.00%
Share of rated capacity (MWs) (1) | MW	373.5
Property, plant, and equipment	$ 596.3
Accumulated depreciation	(170.3)
Construction Work in Progress	$ 0.2
Columbia Energy Center Units 1 and 2 | WPS
Jointly Owned Electric Generating Facilities
Future Ownership Interest of Columbia	27.50%
Ownership (as a percentage)	31.80%
Share of rated capacity (MWs) (1) | MW	334.4
Property, plant, and equipment	$ 417.9
Accumulated depreciation	(128.3)
Construction Work in Progress	$ 41.2
Edgewater Unit 4 | WPS
Jointly Owned Electric Generating Facilities
Ownership (as a percentage)	31.80%
Share of rated capacity (MWs) (1) | MW	98
Property, plant, and equipment	$ 45.8
Accumulated depreciation	(31.7)
Construction Work in Progress	$ 0.1

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Changes to asset retirement obligations
Balance as of January 1	$ 571.2	$ 43.6	$ 42.3
Integrys subsidiaries	0	491	0
Accretion	28.3	14.5	2.4
Additions and revisions to estimated cash flows	0	35.5	0
Liabilities settled	(41.8)	(13.4)	(1.1)
Balance as of December 31	557.7	$ 571.2	$ 43.6
ARO increase due to revisions made to estimated cash flows	10.4
Fly-ash landfills
Changes to asset retirement obligations
ARO additions	16.1
Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule
Changes to asset retirement obligations
ARO additions	$ 9

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Goodwill
Accumulated impairment losses	$ 0
Goodwill impairment loss	0
Changes to goodwill balances by segment
Goodwill balance as of January 1	3,023.5	$ 441.9
Adjustment to Integrys purchase price allocation	22.7	0
Acquisition of Integrys	0	2,581.6
Goodwill balance as of December 31	3,046.2	3,023.5
Wisconsin
Changes to goodwill balances by segment
Goodwill balance as of January 1	2,109.5	441.9
Adjustment to Integrys purchase price allocation	(5.2)	0
Acquisition of Integrys	0	1,667.6
Goodwill balance as of December 31	2,104.3	2,109.5
Illinois
Changes to goodwill balances by segment
Goodwill balance as of January 1	731.2	0
Adjustment to Integrys purchase price allocation	27.5	0
Acquisition of Integrys	0	731.2
Goodwill balance as of December 31	758.7	731.2
Other States
Changes to goodwill balances by segment
Goodwill balance as of January 1	182.8	0
Adjustment to Integrys purchase price allocation	0.4	0
Acquisition of Integrys	0	182.8
Goodwill balance as of December 31	$ 183.2	$ 182.8

Common Equity - Stock-Based Com

Common Equity - Stock-Based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 18	$ 23.3	$ 21.9
Related Tax Benefit	7.2	9.3	8.8
Stock options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	3.5	3.3	3.7
Restricted stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	5.8	7	2.8
Performance units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 8.7	$ 13	$ 15.4

Common Equity - Stock Options (

Common Equity - Stock Options (Details) - Stock options - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Options Activity [Roll Forward]
Outstanding, shares, beginning balance	5,122,775	5,984,664
Granted, shares		794,764	516,475	899,500
Exercised, shares		(1,644,353)
Forfeited, shares		(12,300)
Outstanding, shares, ending balance		5,122,775	5,984,664
Options - Weighted Average Exercise Price
Outstanding, Weighted-Average Exercise Price, Beginning	$ 38.95	$ 33.47
Granted, Weighted-Average Exercise Price		52.15
Exercised, Weighted-Average Exercise Price		25.30
Forfeited, Weighted-Average Exercise Price		52.98
Outstanding, Weighted-Average Exercise Price, Ending		$ 38.95	$ 33.47
Options - Additional Disclosures
Outstanding, Weighted-Average Remaining Contractual Life (Years)		6 years
Outstanding, Aggregate Intrinsic Value		$ 100.9
Exercisable, shares		3,710,836
Exercisable, Weighted-Average Exercise Price		$ 35.38
Exercisable, Weighted-Average Remaining Contractual Life (Years)		5 years 2 months
Exercisable, Aggregate Intrinsic Value		$ 86.4
Intrinsic value of options exercised		55.4	$ 36.1	$ 50.5
Actual tax benefit realized for the tax deductions		$ 22.2	$ 14.5	$ 19.9
Estimated fair value per non-qualified stock option (in dollars per share)		$ 5.14	$ 5.29	$ 4.18
Subsequent event
Options Activity [Roll Forward]
Granted, shares	552,215
Options - Weighted Average Exercise Price
Granted, Weighted-Average Exercise Price	$ 58.31
Options - Additional Disclosures
Estimated fair value per non-qualified stock option (in dollars per share)	$ 7.45

Common Equity - Restricted Shar

Common Equity - Restricted Shares (Details) - Restricted stock - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted Stock Activity [Roll Forward]
Outstanding, shares, beginning of period	220,046	229,018
Granted, shares		146,941
Released, shares		(141,224)
Forfeited, shares		(14,689)
Outstanding, shares, end of period		220,046	229,018
Restricted Stock Weighted-Average Grant Date Fair Value
Outstanding, weighted-average grant date fair value, beginning of period	$ 51.30	$ 46.78
Granted, weighted-average grant date fair value		53.69
Released, weighted-average grant date fair value		46.14
Forfeited, weighted-average grant date fair value		54.39
Outstanding, weighted-average grant date fair value, end of period		$ 51.30	$ 46.78
Restricted Stock - Additional Disclosures
Intrinsic value of released restricted shares		$ 7.7	$ 3.7	$ 2.7
Actual tax benefit realized for the tax deductions		3.1	$ 1.3	$ 1
Compensation cost not yet recognized		$ 5.1
Weighted-average period over which unrecognized compensation cost is expected to be recognized		1 year 11 months
Subsequent event
Restricted Stock Activity [Roll Forward]
Granted, shares	82,622
Restricted Stock Weighted-Average Grant Date Fair Value
Granted, weighted-average grant date fair value	$ 58.10

Common Equity - Performance Uni

Common Equity - Performance Units (Details) - Performance units - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, shares		297,305	195,365	233,735
Intrinsic value of settled performance units		$ 19.1	$ 13.2	$ 14.8
Actual tax benefit realized for the tax deductions		6.8	$ 4.8	$ 5.3
Compensation cost not yet recognized		$ 10.2
Weighted-average period over which unrecognized compensation cost is expected to be recognized		1 year 5 months
Subsequent event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, shares	237,650
Intrinsic value of settled performance units	$ 6.1
Actual tax benefit realized for the tax deductions	$ 1.8

Common Equity - Dividend Restri

Common Equity - Dividend Restrictions (Details) $ in Billions	12 Months Ended
	Dec. 31, 2016USD ($)period	Dec. 31, 2015
Dividend Payment Restrictions [Line Items]
Junior notes minimum interest deferral payment period (in periods) | period	1
Junior notes maximum interest payment deferral period (in years)	10 years
Restricted net assets of subsidiaries and undistributed earnings of equity method investments | $	$ 6.3
Percentage of restricted net assets of subsidiaries and equity method investments that triggers dividend restriction disclosures	25.00%
WE | Serial preferred stock, 3.60% series redeemable
Dividend Payment Restrictions [Line Items]
Preferred Stock, dividend rate (as a percent)	3.60%	3.60%
WE | Serial preferred stock, 3.60% series redeemable | Common stock equity to total capitalization is less than 25%
Dividend Payment Restrictions [Line Items]
Percentage of net income for which dividends can be declared	75.00%
WE | Serial preferred stock, 3.60% series redeemable | Common stock equity to total capitalization is less than 20%
Dividend Payment Restrictions [Line Items]
Percentage of net income for which dividends can be declared	50.00%
WE | Minimum | Public Service Commission of Wisconsin
Dividend Payment Restrictions [Line Items]
Common equity ratio required to be maintained (as a percent)	51.00%
WE | Maximum | Serial preferred stock, 3.60% series redeemable | Common stock equity to total capitalization is less than 25%
Dividend Payment Restrictions [Line Items]
Percentage of common equity to total capitalization required to be maintained	25.00%
WE | Maximum | Serial preferred stock, 3.60% series redeemable | Common stock equity to total capitalization is less than 20%
Dividend Payment Restrictions [Line Items]
Percentage of common equity to total capitalization required to be maintained	20.00%
WG | Minimum | Public Service Commission of Wisconsin
Dividend Payment Restrictions [Line Items]
Common equity ratio required to be maintained (as a percent)	49.50%
WPS | Minimum | Public Service Commission of Wisconsin
Dividend Payment Restrictions [Line Items]
Common equity ratio required to be maintained (as a percent)	51.00%

Common Equity - Share Repurchas

Common Equity - Share Repurchase Program (Details) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 01, 2013
Class of Stock [Line Items]
Common stock issued, Shares	0	0	0
Stock Repurchased During Period, Shares	1.8	1.5	2.7
Stock Repurchased During Period, Value	$ 108	$ 74.7	$ 123.2
Share Repurchase Plan, 2013
Class of Stock [Line Items]
Stock Repurchase Program, Authorized Amount, Value				$ 300
Stock Repurchased During Period, Shares	0	0	0.4
Stock Repurchased During Period, Value	$ 0	$ 0	$ 18.6
Share Repurchases to Fulfill Exercised Stock Options and Restricted Stock Awards
Class of Stock [Line Items]
Stock Repurchased During Period, Shares	1.8	1.5	2.3
Stock Repurchased During Period, Value	$ 108	$ 74.7	$ 104.6

Common Equity - Common Stock Di

Common Equity - Common Stock Dividends (Details) - $ / shares	1 Months Ended	3 Months Ended				12 Months Ended
	Jan. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Dividends Paid and Payable [Line Items]
Common Stock, Dividends, Per Share, Declared		$ 0.4950	$ 0.4950	$ 0.4950	$ 0.4950	$ 1.98	$ 1.74	$ 1.56
Subsequent event
Dividends Paid and Payable [Line Items]
Common Stock, Dividends, Per Share, Declared	$ 0.52
Annualized dividend	$ 2.08
Minimum | Subsequent event
Dividends Paid and Payable [Line Items]
Target dividend payout ratio (as a percent)	65.00%
Maximum | Subsequent event
Dividends Paid and Payable [Line Items]
Target dividend payout ratio (as a percent)	70.00%

Preferred Stock (Details)

Preferred Stock (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Preferred Stock, Value, Issued	$ 30.4	$ 30.4
WEC Energy Group | $.01 pare value preferred stock
Class of Stock [Line Items]
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	15,000,000	15,000,000
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Value, Issued	$ 0	$ 0
WE | Six per cent. preferred stock
Class of Stock [Line Items]
Preferred Stock, Par or Stated Value Per Share	$ 100	$ 100
Preferred Stock, Dividend Rate, Percentage	6.00%	6.00%
Preferred Stock, Shares Authorized	45,000	45,000
Preferred Stock, Shares Outstanding	44,498	44,498
Preferred Stock, Redemption Price Per Share	$ 0	$ 0
Preferred Stock, Value, Issued	$ 4.4	$ 4.4
WE | Serial preferred stock, $100 par value; authorized 2,286,500 shares
Class of Stock [Line Items]
Preferred Stock, Par or Stated Value Per Share	$ 100	$ 100
Preferred Stock, Shares Authorized	2,286,500	2,286,500
WE | Serial preferred stock, 3.60% series redeemable
Class of Stock [Line Items]
Preferred Stock, Par or Stated Value Per Share	$ 100	$ 100
Preferred Stock, Dividend Rate, Percentage	3.60%	3.60%
Preferred Stock, Shares Outstanding	260,000	260,000
Preferred Stock, Redemption Price Per Share	$ 101	$ 101
Preferred Stock, Value, Issued	$ 26	$ 26
WE | Serial preferred stock, $25 par value; authorized 5,000,000 shares; none outstanding
Class of Stock [Line Items]
Preferred Stock, Par or Stated Value Per Share	$ 25	$ 25
Preferred Stock, Shares Authorized	5,000,000	5,000,000
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Value, Issued	$ 0	$ 0
WPS | $100 par value, preferred stock WPS
Class of Stock [Line Items]
Preferred Stock, Par or Stated Value Per Share	$ 100	$ 100
Preferred Stock, Shares Authorized	1,000,000	1,000,000
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Value, Issued	$ 0	$ 0
PGL | $100 par value, cumulative preferred stock PGL
Class of Stock [Line Items]
Preferred Stock, Par or Stated Value Per Share	$ 100	$ 100
Preferred Stock, Shares Authorized	430,000	430,000
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Value, Issued	$ 0	$ 0
NSG | $100 par value, cumulative preferred stock NSG
Class of Stock [Line Items]
Preferred Stock, Par or Stated Value Per Share	$ 100	$ 100
Preferred Stock, Shares Authorized	160,000	160,000
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Value, Issued	$ 0	$ 0

Short-Term Debt and Lines of 96

Short-Term Debt and Lines of Credit - Outstanding Amounts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Short-term Debt [Line Items]
Commercial Paper	$ 860.2	$ 1,095
WEC Energy Group
Short-term Debt [Line Items]
Commercial Paper	$ 321.8	$ 307.9
Maximum Debt to Capitalization Ratio	70.00%
WE
Short-term Debt [Line Items]
Maximum Debt to Capitalization Ratio	65.00%
WPS
Short-term Debt [Line Items]
Maximum Debt to Capitalization Ratio	65.00%
WG
Short-term Debt [Line Items]
Maximum Debt to Capitalization Ratio	65.00%
PGL
Short-term Debt [Line Items]
Maximum Debt to Capitalization Ratio	65.00%
Commercial Paper
Short-term Debt [Line Items]
Commercial Paper	$ 860.2
Average interest rate on amount outstanding	0.96%	0.68%
Average amount outstanding during the year	$ 882.3
Weighted Average interest rate during the year	0.66%

Short-Term Debt and Lines of 97

Short-Term Debt and Lines of Credit - Credit Facilities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)extension	Dec. 31, 2015USD ($)
Line of Credit Facility [Line Items]
Short-term credit capacity	$ 2,500
Letters of Credit Issued Inside Credit Facilities	19.1
Commercial Paper	860.2	$ 1,095
Available capacity under existing agreements	1,620.7
WEC Energy Group
Line of Credit Facility [Line Items]
Commercial Paper	321.8	$ 307.9
WEC Energy Group | Credit facility maturing December 2020
Line of Credit Facility [Line Items]
Short-term credit capacity	$ 1,050
Number of extensions available on a credit facility | extension	2
Length of credit facility extension	1 year
WE | Credit facility maturing December 2020
Line of Credit Facility [Line Items]
Short-term credit capacity	$ 500
Number of extensions available on a credit facility | extension	2
Length of credit facility extension	1 year
WPS | Credit facility maturing December 2016
Line of Credit Facility [Line Items]
Short-term credit capacity	$ 250
Number of extensions available on a credit facility | extension	2
Length of credit facility extension	1 year
WG | Credit facility maturing December 2020
Line of Credit Facility [Line Items]
Short-term credit capacity	$ 350
Number of extensions available on a credit facility | extension	2
Length of credit facility extension	1 year
PGL | Credit facility maturing December 2020
Line of Credit Facility [Line Items]
Short-term credit capacity	$ 350
Number of extensions available on a credit facility | extension	2
Length of credit facility extension	1 year
Commercial Paper
Line of Credit Facility [Line Items]
Commercial Paper	$ 860.2

Long-Term Debt and Capital Le98

Long-Term Debt and Capital Lease Obligations - Long-term Debt (Details) - USD ($) $ in Millions	1 Months Ended					12 Months Ended
	Dec. 31, 2016	Nov. 30, 2016	Sep. 30, 2016	Jun. 30, 2016	Feb. 29, 2016	Dec. 31, 2016	Nov. 01, 2016	Oct. 01, 2016	Sep. 01, 2016	Aug. 01, 2016	Jun. 01, 2016	Feb. 01, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-term Pollution Control Bond	$ 80					$ 80				$ 67
Common Stock, Value, Issued	3.2					3.2							$ 3.2
Future maturities of our long-term debt outstanding
2,017	154.5					154.5
2,018	836.1					836.1
2,019	357.7					357.7
2,020	684.4					684.4
2,021	336.2					336.2
Thereafter	6,953.5					6,953.5
Total	$ 9,322.4					$ 9,322.4
PGL Fixed First and Refunding Mortgage XX Series 2.21 Percent Bonds, Due 2016
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	2.21%					2.21%
PGL Fixed First and Refunding Mortgage RR Series 4.3 Percent Bonds, Due 2035
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	4.30%					4.30%
We Power Notes (secured, nonrecourse), 4.91% due 2015-2030
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	4.91%					4.91%
We Power Notes (secured, nonrecourse), 6.00% due 2015-2033
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	6.00%					6.00%
We Power Notes (secured, nonrecourse), 5.209% due 2015-2030
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	5.209%					5.209%
We Power Notes (secured, nonrecourse), 4.673% due 2015-2031
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	4.673%					4.673%
TEG Unsecured Senior Notes 8 Percent, Due 2016
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	8.00%					8.00%
TEG Junior Subordinated Notes, 6.11% due 2066
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	3.05%					3.05%							6.11%
Debt Instrument, Basis Spread on Variable Rate						2.12%
TEG Unsecured Senior Notes 4.17 Percent, Due 2020
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	4.17%					4.17%
WEC Notes (unsecured), 6.20% due 2033
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	6.20%					6.20%
WEC Junior Notes (unsecured), 6.25% due 2067
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	6.25%					6.25%
Debt Instrument, Basis Spread on Variable Rate						2.1125%
TEG Junior Subordinated Notes, 6.00% due 2073 [Member]
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	6.00%					6.00%
WG | WG Debentures, 3.71% due 2046
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate									3.71%
Proceeds from Issuance of Debt			$ 200
PGL | PGL 3.65% Series DDD Bonds due 2046 [Member]
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate								3.65%
Proceeds from Issuance of Debt	$ 150
PGL | PGL 3.65% Series CCC Bonds due 2046 [Member]
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate							3.65%
Proceeds from Issuance of Debt		$ 50
PGL | PGL Fixed First and Refunding Mortgage XX Series 2.21 Percent Bonds, Due 2016
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate							2.21%
Extinguishment of Debt, Amount		$ 50
PGL | PGL Fixed First and Refunding Mortgage RR Series 4.3 Percent Bonds, Due 2035
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate											4.30%
Extinguishment of Debt, Amount				$ 50
We Power | We Power Notes (secured, nonrecourse), 4.91% due 2015-2030
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	4.91%					4.91%
Long-term Debt, Gross	$ 106.7					$ 106.7
Long-term Debt, Current Maturities	$ 5.6					$ 5.6
We Power | We Power Notes (secured, nonrecourse), 6.00% due 2015-2033
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	6.00%					6.00%
Long-term Debt, Gross	$ 126.1					$ 126.1
Long-term Debt, Current Maturities	$ 4.6					$ 4.6
We Power | We Power Notes (secured, nonrecourse), 5.209% due 2015-2030
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	5.209%					5.209%
Long-term Debt, Gross	$ 204.8					$ 204.8
Long-term Debt, Current Maturities	$ 10.8					$ 10.8
We Power | We Power Notes (secured, nonrecourse), 4.673% due 2015-2031
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	4.673%					4.673%
Long-term Debt, Gross	$ 170.9					$ 170.9
Long-term Debt, Current Maturities	8.5					8.5
Integrys Holding Inc
Debt Disclosure [Abstract]
Common Stock, Value, Issued												$ 66.4
Integrys Holding Inc | TEG Unsecured Senior Notes 8 Percent, Due 2016
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate											8.00%
Unsecured Long-term Debt, Noncurrent	0					0							$ 50
Extinguishment of Debt, Amount				$ 50
Integrys Holding Inc | TEG Junior Subordinated Notes, 6.11% due 2066
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate												6.11%
Unsecured Long-term Debt, Noncurrent	114.9					$ 114.9							269.8
Debt Instrument, Basis Spread on Variable Rate						2.12%
Debt Instrument, Repurchase Amount												$ 128.6
Long-term Debt, Gross	114.9					$ 114.9
Extinguishment of Debt, Amount					$ 154.9
Integrys Holding Inc | TEG Unsecured Senior Notes 4.17 Percent, Due 2020
Debt Disclosure [Abstract]
Unsecured Long-term Debt, Noncurrent	$ 250					$ 250							250
Integrys Holding Inc | TEG Junior Subordinated Notes, 6.00% due 2073 [Member]
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	6.00%					6.00%
Unsecured Long-term Debt, Noncurrent	$ 400					$ 400							400
Long-term Debt, Gross	400					400
WEC Energy Group
Future maturities of our long-term debt outstanding
2,018	300					300
2,020	400					400
Thereafter	1,200					1,200
Total	$ 1,900					$ 1,900
WEC Energy Group | WEC Notes (unsecured), 6.20% due 2033
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	6.20%					6.20%
Unsecured Long-term Debt, Noncurrent	$ 200					$ 200							200
WEC Energy Group | WEC Junior Notes (unsecured), 6.25% due 2067
Debt Disclosure [Abstract]
Debt instrument interest rate stated percentage rate	6.25%					6.25%
Unsecured Long-term Debt, Noncurrent	$ 500					$ 500							$ 500

Long-Tern Debt and Capital Leas

Long-Tern Debt and Capital Lease Obligations - Capital Lease Obligations (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MegawattNumber_of_derivative_instruments_held	Dec. 31, 2015USD ($)
Capital Lease Obligations (Textuals)
Period of power purchse contract with an unaffiliated independent power producer	25 years
Power capacity under capital lease | Megawatt	236
Minimum energy requirement in gas-fired cogeneration facility | Number_of_derivative_instruments_held	0
Power purchase contract expected future renewable period	10 years
repayments of long-term capital lease obligations	$ 37.6	$ 36.2
Increase in regulatory asset due to minimum lease payment	78.5
Regulatory Asset Value At End Of Life Of Contract	0
Obligations under capital leases	29.6	59.9
Capital Lease Obligation At End Of Life Of Contract	0
Summary of capitalized leased facilities
Long-term power purchase commitment	140.3	140.3
Accumulated amortization	(109.5)	(103.9)
Total leased facilities	30.8	$ 36.4
Future minimum lease payments under capital lease and present value of net minimum lease payments
2,017	13.9
2,018	14.7
2,019	15.5
2,020	16.4
2,021	17.2
Thereafter	7.6
Total minimum lease payments	85.3
Less: Estimated Executory Costs	(39.9)
Capital Leases Future Minimum Payments Due, Less Executory Costs	45.4
Less: Interest	(15.8)
Present value of net minimum lease payments	29.6
Less: Due currently	(2.7)
Long-term obligations under capital lease	$ 26.9

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summary of income tax expense
Current tax expense (benefit)	$ 72.7	$ 15.1	$ 33.6
Deferred income taxes	498.7	420.4	329.2
Investment tax credit, net	(4.9)	(1.7)	(1.1)
Total income tax expense, amount	566.5	433.8	361.7
Reconciliation of the beginning and ending amount of unrecognized tax benefits
Balance, January 1	9.5	7.2
Acquired legacy Integrys tax assets	0	(3.6)
Additions for tax positions of prior years	6.7	0.3
Additions based on tax positions related to the current year	1.1	0.2
Reductions for tax positions of prior years	(1)	(1.1)
Reductions due to statute of limitations	(1.8)	0
Settlements during the period	0	(0.7)
Balance, December 31	14.5	9.5	7.2
Income Taxes
Deferred tax assets, uncertainty in income taxes	6.6	6.2
Net amount of unrecognized tax benefits having impact on the effective tax rate for continuing operations	7.9	2.2
Accrued interest in the consolidated income statements	0.2	0	0.3
Accrued penalties in the consolidated income statements	0	0	$ 0
Accrued interest on the consolidated balance sheets	0.8	0.7
Accrued penalties on the consolidated balance sheets	$ 0	$ 0.1

Income Taxes Statutory Rate Rec

Income Taxes Statutory Rate Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Expected tax at statutory federal tax rates, amount	$ 526.4	$ 375.5	$ 332.5
State income taxes net of federal tax benefit, amount	72.8	73.1	50.5
Production tax credits, amount	(15.7)	(17.4)	(17.4)
AFUDC - Equity, amount	(8.8)	(7.1)	(1.9)
Investment tax credit restored, amount	(4.9)	(1.7)	(1.1)
Other, net, Amount	3.3	(11.4)	0.9
Total income tax expense, amount	$ 566.5	$ 433.8	$ 361.7
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Expected tax at statutory federal tax rates, effective tax rate	35.00%	35.00%	35.00%
State income taxes net of federal tax benefit, effective tax rate	4.80%	6.80%	5.30%
Production tax credits, effective tax rate	(1.10%)	(1.60%)	(1.80%)
AFUDC - Equity, effective tax rate	(0.60%)	(0.70%)	(0.20%)
Investment tax credit restored, Effective Tax Rate	(0.30%)	(0.20%)	(0.20%)
Other, net, Effective Tax Rate	(0.20%)	1.10%	(0.10%)
Total Income Tax Expense, Effective Tax Rate	37.60%	40.40%	38.00%

Income Taxes Components of net

Income Taxes Components of net deferred tax assets (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Income taxes
Balance carryforwards, gross value	$ 899.6	$ 602.9
Deferred tax assets, future tax benefits	430.4	382.8
Deferred Tax Assets, Valuation Allowance	15	17.1
Charitable contribution
Income taxes
Charitable contributions, gross value	9.4	4.7
Deferred tax asset, charitable contribution	4	1.9
Deferred Tax Assets, Valuation Allowance	1.5	1.9
Domestic tax authority
Income taxes
Operating loss carryforwards, gross value	407.6	412.3
Tax credit carryforward, amount	0	0
Deferred tax assets, federal net operating loss	142.7	144.3
Deferred tax assets, tax credit carryforwards	241.1	207.8
Operating loss carryforwards, valuation allowance	0	0
Tax credit carryforward, valuation allowance	0	0
Foreign tax authority
Income taxes
Tax credit carryforward, amount	0	0
Deferred tax asset, federal foreign tax credit	13.5	15.2
Tax credit carryforward, valuation allowance	13.5	15.2
State and local jurisdiction
Income taxes
Operating loss carryforwards, gross value	482.6	185.9
Tax credit carryforward, amount	0	0
Deferred tax assets, tax credit carryforwards	4.8	4.3
Deferred tax asset, state net operating loss	24.3	9.3
Operating loss carryforwards, valuation allowance	0	0
Tax credit carryforward, valuation allowance	$ 0	$ 0

Income Taxes Components of Defe

Income Taxes Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Non-current
Future tax benefits	$ 430.4	$ 382.8
Employee benefits and compensation	222	229.9
Deferred revenues	207.2	219.9
Property-related	54.5	59.5
Other	230.6	177.1
Total deferred tax assets	1,144.7	1,069.2
Valuation allowance	(15)	(17.1)
Net deferred tax assets	1,129.7	1,052.1
Non-current
Property-related	4,979.3	4,451.5
Investment in transmission affiliate	476.9	420.4
Employee benefits and compensation	401.6	428.9
Deferred transmission costs	93.1	76.7
Other	325.4	296.9
Total deferred tax liabilities	6,276.3	5,674.4
Deferred tax liability, net	$ 5,146.6	$ 4,622.3

Guarantees (Details)

Guarantees (Details) $ in Millions	Dec. 31, 2016USD ($)
Guarantor Obligations
Total guarantees	$ 47.9
Guarantees expiring in less than one year	38.7
Guarantees expiring within one to three years	2.1
Guarantees with expiration over three years	7.1
Standby letters of credit
Guarantor Obligations
Total guarantees	29.4
Guarantees expiring in less than one year	27.9
Guarantees expiring within one to three years	1.5
Guarantees with expiration over three years	0
Surety bonds
Guarantor Obligations
Total guarantees	10.9
Guarantees expiring in less than one year	10.3
Guarantees expiring within one to three years	0.6
Guarantees with expiration over three years	0
Other guarantees
Guarantor Obligations
Total guarantees	7.6
Guarantees expiring in less than one year	0.5
Guarantees expiring within one to three years	0
Guarantees with expiration over three years	7.1
Other indemnification
Guarantor Obligations
Total guarantees	7.6
Liability related to workers compensation coverage	$ 7.1

Employee Benefits - Change in B

Employee Benefits - Change in Benefit Obligations and Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Mar. 31, 2015
Defined Benefit Plans
New 401k Contribution for new hires				6.00%
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Long-term liabilities	$ 498.6	$ 543.1
Pension Benefits
Change in benefit obligation
Obligation at January 1	3,083	1,505.5
Obligation assumed from acquisition	0	1,594
Service cost	45.4	30.4	$ 10.1
Interest cost	130.8	94.3	68.1
Participant contributions	0	0
Plan amendments	(3)	0
Actuarial loss (gain)	71.7	14.6
Benefit payments	(269.1)	(156)
Plan curtailments	0	0.2
Obligation at December 31	3,058.8	3,083	1,505.5
Change in fair value of plan assets
Beginning balance at January 1	2,755.1	1,444.6
Assets received from acquisition	0	1,420.9
Actual return on plan assets	199.4	(62.1)
Employer contributions	23.8	107.7
Participant contributions	0	0
Benefit payments	(269.1)	(156)
Ending balance at December 31	2,709.2	2,755.1	1,444.6
Funded status at December 31	(349.6)	(327.9)
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Long-term assets	74.4	74.1
Long-term liabilities	424	402
Total net liabilities	(349.6)	(327.9)
Benefit obligations held for sale		0.8
Accumulated benefit obligation	2,939.9	2,936.4
Information for pension plans with an accumulated benefit obligation in excess of plan assets
Projected benefit obligation	1,667	1,706.6
Accumulated benefit obligation	1,549.5	1,560.5
Fair value of plan assets	1,242.9	1,304.6
OPEB
Change in benefit obligation
Obligation at January 1	842	397.7
Obligation assumed from acquisition	0	493
Service cost	26.1	20.7	8.5
Interest cost	37	26.7	17.8
Participant contributions	16.4	12.7
Plan amendments	(18.9)	0
Actuarial loss (gain)	(36.5)	(74)
Benefit payments	(49.1)	(36.2)
Federal subsidy on benefits paid	1.4	1.6
Plan curtailments	0	(0.2)
Obligation at December 31	818.4	842	397.7
Change in fair value of plan assets
Beginning balance at January 1	749.8	333.5
Assets received from acquisition	0	442.1
Actual return on plan assets	51.5	(15.6)
Employer contributions	4.9	13.3
Participant contributions	16.4	12.7
Benefit payments	(49.1)	(36.2)
Ending balance at December 31	773.5	749.8	$ 333.5
Funded status at December 31	(44.9)	(92.2)
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Long-term assets	29.7	50.1
Long-term liabilities	74.6	142.3
Total net liabilities	$ (44.9)	(92.2)
Benefit obligations held for sale		$ 0.4

Employee Benefits - Net Periodi

Employee Benefits - Net Periodic Benefit Cost (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Net regulatory assets
Net actuarial loss	$ 1,240.7	$ 798.1
Prior service cost (credit)	10.5	4.7
Total	1,251.2	802.8
Net actuarial loss	87.2
Prior service costs (credits)	3
Total 2017 - estimated amortization	90.2
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)
Service cost	45.4	30.4	$ 10.1
Interest cost	130.8	94.3	68.1
Expected return on plan assets	(195.9)	(155.6)	(98.6)
Plan settlement	16.5	0	0
Plan curtailment	0	(0.3)	0
Amortization of prior service cost (credit)	3.4	2.2	2.1
Amortization of net actuarial loss	82.9	68.5	36.7
Net periodic benefit cost	83.1	39.5	18.4
OPEB
Net regulatory assets
Net actuarial loss	25.8	23.7
Prior service cost (credit)	(87.9)	(3.3)
Total	(62.1)	20.4
Net actuarial loss	5.8
Prior service costs (credits)	(11.2)
Total 2017 - estimated amortization	(5.4)
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)
Service cost	26.1	20.7	8.5
Interest cost	37	26.7	17.8
Expected return on plan assets	(52.7)	(39.6)	(23.7)
Plan settlement	0	0	0
Plan curtailment	0	0	0
Amortization of prior service cost (credit)	(9.4)	(6.4)	(1.8)
Amortization of net actuarial loss	8.5	3.9	1.2
Net periodic benefit cost	9.5	5.3	$ 2
Nonutility operations | Pension Benefits
Employee Benefit Plans
Net actuarial loss (gain)	12	11.4
Total	12	11.4
Nonutility operations | OPEB
Employee Benefit Plans
Net actuarial loss (gain)	(1)	(0.6)
Total	$ (1)	$ (0.6)

Employee Benefits - Assumptions

Employee Benefits - Assumptions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Weighted average assumptions used
Discount rate	4.16%	4.46%
Rate of compensation increase	3.60%	4.00%
Discount rate	4.35%	4.11%	5.00%
Expected return on plan assets	7.12%	7.37%	7.25%
Rate of compensation increase	3.75%	4.00%	4.00%
Expected return on assets during next fiscal year	7.11%
OPEB
Weighted average assumptions used
Discount rate	4.14%	4.38%
Assumed medical cost trend rate (as a percent)	7.00%	7.50%
Ultimate trend rate (as a percent)	5.00%	5.00%
Year ultimate trend rate is reached	2,021	2,021
Discount rate	4.38%	4.09%	4.95%
Expected return on plan assets	7.25%	7.54%	7.50%
Expected return on assets during next fiscal year	7.25%
Effects of a one-percentage-point change in assumed health care cost trend rates
Effect of one-percentage-point increase on total of service and interest cost components of net periodic postretirement health care benefit cost	$ 8.5
Effect of one-percentage-point decrease on total of service and interest cost components of net periodic postretirement health care benefit cost	(6.9)
Effect of one-percentage-point increase on the health care component of the accumulated postretirement benefit obligation	49.6
Effect of one-percentage-point decrease on the health care component of the accumulated postretirement benefit obligation	$ (39.5)
OPEB | Maximum
Weighted average assumptions used
Assumed medical cost trend rate (as a percent)	7.50%	7.50%	7.50%
Ultimate trend rate (as a percent)	5.00%	5.00%	5.00%
Year ultimate trend rate is reached	2,021	2,021	2,021
Wisconsin Energy | Pension Benefits | Equity securities:
Target asset allocations
Target asset allocations (as a percent)	35.00%
Wisconsin Energy | Pension Benefits | Fixed income securities:
Target asset allocations
Target asset allocations (as a percent)	55.00%
Wisconsin Energy | Pension Benefits | Private equity funds
Target asset allocations
Target asset allocations (as a percent)	10.00%
Wisconsin Energy | OPEB | Equity securities:
Target asset allocations
Target asset allocations (as a percent)	60.00%
Wisconsin Energy | OPEB | Fixed income securities:
Target asset allocations
Target asset allocations (as a percent)	40.00%
Integrys Holding Inc | Pension Benefits | Equity securities:
Target asset allocations
Target asset allocations (as a percent)	60.00%
Integrys Holding Inc | Pension Benefits | Fixed income securities:
Target asset allocations
Target asset allocations (as a percent)	40.00%
Integrys Holding Inc | OPEB | Equity securities:
Target asset allocations
Target asset allocations (as a percent)	45.00%
Integrys Holding Inc | OPEB | Equity securities: | Maximum
Target asset allocations
Target asset allocations (as a percent)	50.00%
Integrys Holding Inc | OPEB | Fixed income securities:
Target asset allocations
Target asset allocations (as a percent)	50.00%
Integrys Holding Inc | OPEB | Fixed income securities: | Maximum
Target asset allocations
Target asset allocations (as a percent)	55.00%

Employee Benefits - Pension and

Employee Benefits - Pension and Post Retirement Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets		$ 8.1
Pension Plan Assets
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	$ 2,709.2	2,755.1	$ 1,444.6
Fair value of plan assets subject to levelling	1,343	1,181
Pension Plan Assets | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	61.7	46.6
Pension Plan Assets | United states equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	274	136
Pension Plan Assets | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	54.7	103.9
Pension Plan Assets | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	862.1	808.7
Pension Plan Assets | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	75.9	80.3
Pension Plan Assets | Private Placement
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	14.6	5.5
Pension Plan Assets | Investments measured at net asset value
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	1,366.2	1,574.1
Pension Plan Assets | Level 1
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	331.7	264.9
Pension Plan Assets | Level 1 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	3.7	17
Pension Plan Assets | Level 1 | United states equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	273.9	132.6
Pension Plan Assets | Level 1 | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	54.1	103.9
Pension Plan Assets | Level 1 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	11.4
Pension Plan Assets | Level 1 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plan Assets | Level 1 | Private Placement
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plan Assets | Level 2
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	995.9	910.6
Pension Plan Assets | Level 2 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	58	29.6
Pension Plan Assets | Level 2 | United states equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0.1	3.4
Pension Plan Assets | Level 2 | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0.6	0
Pension Plan Assets | Level 2 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	861.3	797.3
Pension Plan Assets | Level 2 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	75.9	80.3
Pension Plan Assets | Level 2 | Private Placement
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plan Assets | Level 3
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	15.4	5.5
Pension Plan Assets | Level 3 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plan Assets | Level 3 | United states equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plan Assets | Level 3 | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plan Assets | Level 3 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0.8	0
Pension Plan Assets | Level 3 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plan Assets | Level 3 | Private Placement
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	14.6	5.5	0
OPEB Plan Assets
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	773.5	749.8	333.5
Fair value of plan assets subject to levelling	218.2	188.4
OPEB Plan Assets | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	32.2	11.5
OPEB Plan Assets | United states equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	34.3	24.7
OPEB Plan Assets | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	3.7	21.4
OPEB Plan Assets | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	137.9	122.3
OPEB Plan Assets | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	8.8
OPEB Plan Assets | Private Placement
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	1.3	0.4
OPEB Plan Assets | Investments measured at net asset value
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	555.3	561.4
OPEB Plan Assets | Level 1
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	66.6	56.8
OPEB Plan Assets | Level 1 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	28.8	10.5
OPEB Plan Assets | Level 1 | United states equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	34.3	24.6
OPEB Plan Assets | Level 1 | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	3.5	21.4
OPEB Plan Assets | Level 1 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0.3
OPEB Plan Assets | Level 1 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
OPEB Plan Assets | Level 1 | Private Placement
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
OPEB Plan Assets | Level 2
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	150.3	131.2
OPEB Plan Assets | Level 2 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	3.4	1
OPEB Plan Assets | Level 2 | United states equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0.1
OPEB Plan Assets | Level 2 | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0.2	0
OPEB Plan Assets | Level 2 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	137.9	122
OPEB Plan Assets | Level 2 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	8.8	8.1
OPEB Plan Assets | Level 2 | Private Placement
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
OPEB Plan Assets | Level 3
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	1.3	0.4
OPEB Plan Assets | Level 3 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
OPEB Plan Assets | Level 3 | United states equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
OPEB Plan Assets | Level 3 | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
OPEB Plan Assets | Level 3 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
OPEB Plan Assets | Level 3 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
OPEB Plan Assets | Level 3 | Private Placement
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	$ 1.3	$ 0.4	$ 0

Employee Benefits - Changes in

Employee Benefits - Changes in the Fair Value of Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	$ 2,755.1	$ 1,444.6
Realized and unrealized gains	199.4	(62.1)
Ending balance at December 31	2,709.2	2,755.1
Pension Benefits | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	5.5
Ending balance at December 31	15.4	5.5
Pension Benefits | Private Placement
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	5.5
Ending balance at December 31	14.6	5.5
Pension Benefits | Private Placement | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	5.5	0
Realized and unrealized gains	0.5
Purchases	8.6	5.5
Ending balance at December 31	14.6	5.5
Pension Benefits | United States bonds
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	808.7
Ending balance at December 31	862.1	808.7
Pension Benefits | United States bonds | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	0
Realized and unrealized gains	0
Purchases	0.8
Ending balance at December 31	0.8	0
OPEB
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	749.8	333.5
Realized and unrealized gains	51.5	(15.6)
Ending balance at December 31	773.5	749.8
OPEB | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	0.4
Ending balance at December 31	1.3	0.4
OPEB | Private Placement
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	0.4
Ending balance at December 31	1.3	0.4
OPEB | Private Placement | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	0.4	0
Realized and unrealized gains	0.1
Purchases	0.8	0.4
Ending balance at December 31	1.3	0.4
OPEB | United States bonds
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	122.3
Ending balance at December 31	137.9	122.3
OPEB | United States bonds | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	0
Ending balance at December 31	$ 0	$ 0

Employee Benefits - Defined Con

Employee Benefits - Defined Contribution Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Mar. 31, 2015
Defined Contribution Benefit Plans
Total costs incurred for defined contribution benefit plans	$ 44.3	$ 48	$ 14.2
New 401k Contribution for new hires				6.00%
Pension Benefits
Employee Benefit Plans
Expected contributions to the plans during the next fiscal year	100
Expected payments, reflecting expected future service
2,017	215.7
2,018	217.1
2,019	226.5
2,020	233.1
2,021	230
2022 through 2026	1,031.5
OPEB
Employee Benefit Plans
Expected contributions to the plans during the next fiscal year	0.1
Expected payments, reflecting expected future service
2,017	41.8
2,018	49.6
2,019	49
2,020	50.9
2,021	53.1
2022 through 2026	$ 278.5

Commitments and Contingencies -

Commitments and Contingencies - Unconditional Purchase Obligations (Details) $ in Millions	Dec. 31, 2016USD ($)
Minimum future commitments for purchase obligations
Total Amounts Committed	$ 11,977.5
2,017	1,137.7
2,018	921.8
2,019	794.4
2,020	701.1
2,021	643.6
Later Years	7,778.9
Nuclear | Electric
Minimum future commitments for purchase obligations
Total Amounts Committed	9,599.8
2,017	415.3
2,018	420.1
2,019	445.4
2,020	475.1
2,021	501.1
Later Years	7,342.8
Purchased power | Electric
Minimum future commitments for purchase obligations
Total Amounts Committed	693.3
2,017	111.3
2,018	75.9
2,019	66.2
2,020	66.3
2,021	63.9
Later Years	309.7
Coal supply and transportation | Electric
Minimum future commitments for purchase obligations
Total Amounts Committed	455
2,017	269.4
2,018	140.3
2,019	45.3
2,020	0
2,021	0
Later Years	0
Natural gas utility supply and transportation | Natural gas
Minimum future commitments for purchase obligations
Total Amounts Committed	1,229.4
2,017	341.7
2,018	285.5
2,019	237.5
2,020	159.7
2,021	78.6
Later Years	$ 126.4

Commitments and Contingencie112

Commitments and Contingencies - Operating Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Leases [Abstract]
Rental expense attributable to operating leases	$ 15.1	$ 12.7	$ 4.8
Minimum future payments under noncancelable operating leases
2,017	9.9
2,018	8.8
2,019	5.9
2,020	5.3
2,021	5.5
Later years	60.1
Total	$ 95.5

Commitments and Contingencie113

Commitments and Contingencies - Environmental Matters (Details) T in Millions, $ in Millions	1 Months Ended						12 Months Ended
	Sep. 30, 2016	Jan. 31, 2016	Dec. 31, 2015USD ($)	Aug. 31, 2014	Jun. 30, 2013USD ($)	Mar. 31, 2013USD ($)	Dec. 31, 2016USD ($)T	Dec. 31, 2015USD ($)T	Jun. 01, 2015USD ($)
Electric | Cross-State Air Pollution Rule
Air Quality
Number Of States Impacted By Cross State Air Pollution Rule	23
Electric | Mercury and Other Hazardous Air Pollutants
Air Quality
Percentage mercury emission reduction							90.00%
Electric | Climate Change
Air Quality
Percentage greenhouse gas emission reduction nationwide								32.00%
Interim requirement greenhouse gas emissions reductions								0.667
Percentage carbon dioxide emission reduction company goal							40.00%
Carbon dioxide emissions | T							29.6	31
Electric | Clean Water Act Cooling Water Intake Structure Rule
Water Quality
Number of compliance options available to meet standard				7
Electric | Steam Electric Effluent Guidelines
Water Quality
Renewal period of facility permits		5 years
Electric | Steam Electric Effluent Guidelines | Minimum
Water Quality
Expected environmental costs to achieve required emission reductions							$ 80
Electric | Steam Electric Effluent Guidelines | Maximum
Water Quality
Expected environmental costs to achieve required emission reductions							$ 110
Electric | Weston and Pulliam Consent Decree | WPS
Consent Decrees
Beneficial environmental project amount						$ 6
Civil penalty						$ 1.2
Regulatory asset for undepreciated book value of retired plants									$ 11.5
Electric | Joint Ownership Power Plants Consent Decree - Columbia and Edgewater | WPS
Consent Decrees
Beneficial environmental project amount					$ 1.3
Civil penalty					$ 0.4
Natural gas | Climate Change
Air Quality
Carbon dioxide emissions | T							26.7	27.2
Natural gas | Manufactured Gas Plant Remediation
Manufactured Gas Plant Remediation
Regulatory assets recorded for remediation of manufactured gas plant sites			$ 697				$ 702.7	$ 697
Reserves recorded for remediation of manufactured gas plant sites			$ 628				$ 633.4	$ 628
WISCONSIN | Electric | Climate Change
Air Quality
Percentage greenhouse gas emission reduction state								41.00%
Percentage greenhouse gas emission reduction for retirement of a nuclear plant			10.00%
WISCONSIN | Electric | Renewables, Efficiency, and Conservation
Renewables, Efficiency, and Conservation
Percent renewable energy portfolio requirement for years 2016 through 2018							10.00%
Percent of annual operating revenues							1.20%
Percentage renewable portfolio requirement for years 2019 through 2020							12.50%
Percentage renewable portfolio requirement for 2021							15.00%
WISCONSIN | Electric | Renewables, Efficiency, and Conservation | WE
Renewables, Efficiency, and Conservation
Renewable energy percent required							8.27%
WISCONSIN | Electric | Renewables, Efficiency, and Conservation | WPS
Renewables, Efficiency, and Conservation
Renewable energy percent required							9.74%
MICHIGAN | Electric | Climate Change
Air Quality
Percentage greenhouse gas emission reduction state								39.00%
MICHIGAN | Electric | Renewables, Efficiency, and Conservation
Renewables, Efficiency, and Conservation
Percent renewable energy portfolio requirement for years 2016 through 2018							10.00%
MICHIGAN | Electric | Renewables, Efficiency, and Conservation | Maximum
Renewables, Efficiency, and Conservation
Energy optimization target							1.00%

Fair Value Measurements - Asse

Fair Value Measurements - Assets and liabilities measured on a recurring basis (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Assets
Derivative asset	$ 41.6	$ 9.9
Liabilities
Derivative liability	2.4	59
Fair value measurements on a recurring basis
Assets
Derivative asset	41.6	9.9
Investment in exchange-traded funds	103.9	39.8
Liabilities
Derivative liability	2.4	59
Fair value measurements on a recurring basis | Level 1
Assets
Derivative asset	10.3	2.8
Investment in exchange-traded funds	103.9	39.8
Liabilities
Derivative liability	0.3	21.4
Fair value measurements on a recurring basis | Level 2
Assets
Derivative asset	26.2	3.5
Investment in exchange-traded funds	0	0
Liabilities
Derivative liability	2.1	37.6
Fair value measurements on a recurring basis | Level 3
Assets
Derivative asset	5.1	3.6
Investment in exchange-traded funds	0	0
Liabilities
Derivative liability	0	0
Fair value measurements on a recurring basis | Natural gas contracts
Assets
Derivative asset	34.3	3.1
Liabilities
Derivative liability	0.4	41.8
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative asset	10.1	1.6
Liabilities
Derivative liability	0.2	16.5
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative asset	24.2	1.5
Liabilities
Derivative liability	0.2	25.3
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	0.2	1.2
Liabilities
Derivative liability	0.1	4.9
Fair value measurements on a recurring basis | Petroleum products contracts | Level 1
Assets
Derivative asset	0.2	1.2
Liabilities
Derivative liability	0.1	4.9
Fair value measurements on a recurring basis | Petroleum products contracts | Level 2
Assets
Derivative asset	0	0
Liabilities
Derivative liability	0	0
Fair value measurements on a recurring basis | Petroleum products contracts | Level 3
Assets
Derivative asset	0	0
Liabilities
Derivative liability	0	0
Fair value measurements on a recurring basis | FTRs
Assets
Derivative asset	5.1	3.6
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	5.1	3.6
Fair value measurements on a recurring basis | Coal contracts
Assets
Derivative asset	2	2
Liabilities
Derivative liability	1.9	12.3
Fair value measurements on a recurring basis | Coal contracts | Level 1
Assets
Derivative asset	0	0
Liabilities
Derivative liability	0	0
Fair value measurements on a recurring basis | Coal contracts | Level 2
Assets
Derivative asset	2	2
Liabilities
Derivative liability	1.9	12.3
Fair value measurements on a recurring basis | Coal contracts | Level 3
Assets
Derivative asset	0	0
Liabilities
Derivative liability	$ 0	$ 0

Fair Value Measurements - Level

Fair Value Measurements - Level 3 Reconciliation (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at the beginning of the period	$ 3,600,000	$ 7,000,000	$ 3,500,000
Realized and unrealized gains (losses)	(200,000)	1,300,000	0
Purchases	15,200,000	3,900,000	15,600,000
Sales	(200,000)	(100,000)	0
Settlements	(13,300,000)	(11,900,000)	(12,100,000)
Acquisition of Integrys	0	(1,300,000)	0
Transfers out of level 3	0	4,700,000	0
Balance at the end of period	5,100,000	3,600,000	7,000,000
Unrealizes gains and losses on level 3 derivatives included in earnings	$ 0	$ 0	$ 0

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Financial Instruments
Preferred stock	$ 30.4	$ 30.4
Total capital lease obligation	29.6	59.9
Carrying amount
Financial Instruments
Preferred stock	30.4	30.4
Long-term debt, including current portion	9,285.8	9,221.9
Total capital lease obligation	29.6	59.9
Fair value
Financial Instruments
Preferred stock	28.8	27.3
Long-term debt, including current portion	$ 9,818.2	$ 9,681

Derivative Instruments - Deriva

Derivative Instruments - Derivative assets and liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative Asset [Abstract]
Other current derivative asset	$ 38.2	$ 8.8
Other long-term derivative assets	3.4	1.1
Derivative asset	41.6	9.9
Derivative Liability [Abstract]
Other current derivative liabilities	1.9	49
Other long-term derivative Iiabilities	0.5	10
Derivative liability	2.4	59
Natural gas contracts
Derivative Asset [Abstract]
Other current derivative asset	31.4	2.6
Other long-term derivative assets	2.9	0.5
Derivative Liability [Abstract]
Other current derivative liabilities	0.4	38.5
Other long-term derivative Iiabilities	0	3.3
Petroleum products contracts
Derivative Asset [Abstract]
Other current derivative asset	0.2	0.9
Other long-term derivative assets	0	0.3
Derivative Liability [Abstract]
Other current derivative liabilities	0.1	3.8
Other long-term derivative Iiabilities	0	1.1
FTRs
Derivative Asset [Abstract]
Other current derivative asset	5.1	3.6
Derivative Liability [Abstract]
Other current derivative liabilities	0	0
Coal contracts
Derivative Asset [Abstract]
Other current derivative asset	1.5	1.7
Other long-term derivative assets	0.5	0.3
Derivative Liability [Abstract]
Other current derivative liabilities	1.4	6.7
Other long-term derivative Iiabilities	$ 0.5	$ 5.6

Derivative Instruments Derivati

Derivative Instruments Derivative Instruments - Gains (Losses) and Notional Volumes (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MWhMMBTUgal	Dec. 31, 2015USD ($)MWhMMBTUgal	Dec. 31, 2014USD ($)MWhMMBTUgal
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ (49.5)	$ (45.7)	$ 20.5
Natural gas contracts
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ (59.6)	$ (50.5)	$ 7.3
Notional Volumes
Notional sales volumes (Dth or MWh) | MMBTU	151.1	86.2	40.5
Petroleum products contracts
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ (3.2)	$ (1.9)	$ 0.5
Notional Volumes
Notional sales volumes (gallons) | gal	14.7	7.8	9.2
FTRs
Realized Gain (Loss) on Derivatives, Net
Gains (Losses)	$ 13.3	$ 6.7	$ 12.7
Notional Volumes
Notional sales volumes (Dth or MWh) | MWh	33.7	27.3	26.1

Derivative Instruments - Balanc

Derivative Instruments - Balance Sheeet Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Cash collateral
Collateral in margin accounts	$ 16.4	$ 42.3
Collateral received	4.4
Offsetting Derivative Assets
Gross amount recognized on the balance sheet	41.6	9.9
Gross amount not offset on the balance sheet	4.9	3
Derivative Asset	36.7	6.9
Cash collateral received	4.4
Offsetting Derivative Liabilities
Gross amount recognized on balance sheet	2.4	59
Gross amount not offset on the balance sheet	0.5	22.5
Derivative Liability	1.9	36.5
Cash collateral posted		19.5
Derivative, Credit Risk Related Contingent Features [Abstract]
Aggregate fair value of derivative instruments with credit risk-related contingent features that were in a liability position	$ 0.2	23.8
Collateral that would have been required		$ 18

Derivative Instruments Deriv120

Derivative Instruments Derivative Instruments - Cash Flow Hedges (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Interest Rate Cash Flow Hedges
Total debt	$ 9,322.4
Hedged Item	19
Reclassified from accumulated OCI into income	2.2
Reclassification within next 12 months	2.2
Total senior notes issued in June 2015
Interest Rate Cash Flow Hedges
Total debt	$ 1,200

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016USD ($)	Dec. 31, 2016USD ($)MW	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
ATC
Variable interest entities
Equity method investment, ownership interest (as a percent)		60.00%
Equity investment in ATC		$ 1,443.9	$ 1,380.9
Accounts payable to related parties		$ 28.7	28.3
Purchased power agreement
Variable interest entities
Firm capacity from purchased power agreement (in megawatts) | MW		236
Minimum energy requirements over remaining term of purchased power agreement (in megawatts) | MW		0
Remaining term of purchased power agreement (in years)		5 years
Residual guarantee associated with purchased power agreement		$ 0
Required payments over remaining term of purchased power agreement		85.3
Total capacity and lease payments under purchased power agreement		$ 54.2	$ 53.6	$ 53
Accounting Standards Update 2015-02
Variable interest entities
Changes to disclosures and financial statement presentation	$ 0

Regulatory Environment (Details

Regulatory Environment (Details) $ in Millions

1 Months Ended

12 Months Ended

Oct. 31, 2016USD ($)

Aug. 31, 2016USD ($)MW

Mar. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Nov. 30, 2015

Jun. 30, 2015

Apr. 30, 2015USD ($)

Feb. 28, 2015USD ($)

Jan. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Oct. 31, 2014USD ($)

Dec. 31, 2012USD ($)

Dec. 31, 2016USD ($)

Regulatory environment

Percent fuel costs can vary from the rate case approved costs before deferral is required

2.00%

WE | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Electric rates

Regulatory environment

Approved annual rate increase (decrease)

$ 26.6

Approved annual rate increase (decrease), percentage

0.90%

WE | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Natural gas rates

Regulatory environment

Approved annual rate increase (decrease)

$ 0

WE | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Steam rates | Downtown Milwaukee (Valley) steam customers

Regulatory environment

Approved annual rate increase (decrease)

0

WE | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Steam rates | Milwaukee County steam customers

Regulatory environment

Approved annual rate increase (decrease)

$ 0

WE | Public Service Commission of Wisconsin (PSCW) | 2015 Rates

Regulatory environment

Approved return on equity (as a percent)

10.20%

Approved common equity component average (as a percent)

51.00%

WE | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Electric rates

Regulatory environment

Refund related to prior fuel costs and the proceeds of a Treasury Grant

$ 26.6

Percent fuel costs can vary from the rate case approved costs before deferral is required

2.00%

SSR revenues

$ 90.7

Number of other rates impacted by the Dane County Circuit Court order

0

WE | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Electric rates | Non-fuel costs

Regulatory environment

Approved annual rate increase (decrease)

$ 2.7

Approved annual rate increase (decrease), percentage

0.10%

WE | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Electric rates | Fuel costs

Regulatory environment

Approved annual rate increase (decrease)

$ (13.9)

Approved annual rate increase (decrease), percentage

(0.50%)

WE | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Natural gas rates

Regulatory environment

Approved annual rate increase (decrease)

$ (10.7)

Approved annual rate increase (decrease), percentage

(2.40%)

WE | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Steam rates | Downtown Milwaukee (Valley) steam customers

Regulatory environment

Approved annual rate increase (decrease)

$ 0.5

Approved annual rate increase (decrease), percentage

2.00%

WE | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Steam rates | Milwaukee County steam customers

Regulatory environment

Approved annual rate increase (decrease)

$ 1.2

Approved annual rate increase (decrease), percentage

7.30%

WE | Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Electric rates

Regulatory environment

Approved annual rate increase (decrease)

$ 28

Approved annual rate increase (decrease), percentage

1.00%

Approved reduction in bill credits

$ 45

Approved reduction in bill credits, percentage

(1.60%)

WE | Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Natural gas rates

Regulatory environment

Approved annual rate increase (decrease)

$ 0

WE | Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Steam rates | Downtown Milwaukee (Valley) steam customers

Regulatory environment

Approved annual rate increase (decrease)

$ 1.3

Approved annual rate increase (decrease), percentage

6.00%

WE | Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Steam rates | Milwaukee County steam customers

Regulatory environment

Approved annual rate increase (decrease)

$ 1

Approved annual rate increase (decrease), percentage

6.00%

WE | Public Service Commission of Wisconsin (PSCW) | 2013 Rates

Regulatory environment

Approved return on equity (as a percent)

10.40%

WE | Public Service Commission of Wisconsin (PSCW) | 2013 Rates | Electric rates

Regulatory environment

Refund related to proceeds of a Treasury Grant

$ 63

Refund related to proceeds of a Treasury Grant, percentage

2.30%

WE | Public Service Commission of Wisconsin (PSCW) | 2013 Rates | Electric rates | Non-fuel costs

Regulatory environment

Approved annual rate increase (decrease)

$ 70

Approved annual rate increase (decrease), percentage

2.60%

Approved annual rate increase, excluding Treasury Grant

$ 133

Approved annural rate increase percentage, excluding Treasury Grant

4.80%

WE | Public Service Commission of Wisconsin (PSCW) | 2013 Rates | Electric rates | Fuel costs

Regulatory environment

Approved annual rate increase (decrease)

$ 44

Approved annual rate increase (decrease), percentage

1.60%

WE | Public Service Commission of Wisconsin (PSCW) | 2013 Rates | Natural gas rates

Regulatory environment

Approved annual rate increase (decrease)

$ (8)

Approved annual rate increase (decrease), percentage

(1.90%)

WE | Public Service Commission of Wisconsin (PSCW) | 2013 Rates | Natural gas rates | Bad debt expense

Regulatory environment

Approved annual rate increase (decrease)

$ (6.4)

WE | Public Service Commission of Wisconsin (PSCW) | 2013 Rates | Steam rates | Downtown Milwaukee (Valley) steam customers

Regulatory environment

Approved annual rate increase (decrease)

$ 1.3

Approved annual rate increase (decrease), percentage

6.00%

WE | Public Service Commission of Wisconsin (PSCW) | 2013 Rates | Steam rates | Milwaukee County steam customers

Regulatory environment

Approved annual rate increase (decrease)

$ 1

Approved annual rate increase (decrease), percentage

7.00%

WG | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Natural gas rates

Regulatory environment

Approved annual rate increase (decrease)

$ 21.4

Approved annual rate increase (decrease), percentage

3.20%

WG | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Natural gas rates

Regulatory environment

Approved annual rate increase (decrease)

$ 17.1

Approved annual rate increase (decrease), percentage

2.60%

Approved return on equity (as a percent)

10.30%

Approved common equity component average (as a percent)

49.50%

WG | Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Natural gas rates

Regulatory environment

Approved annual rate increase (decrease)

$ 0

WG | Public Service Commission of Wisconsin (PSCW) | 2013 Rates | Natural gas rates

Regulatory environment

Approved annual rate increase (decrease)

$ (34)

Approved annual rate increase (decrease), percentage

(5.50%)

Approved return on equity (as a percent)

10.50%

WG | Public Service Commission of Wisconsin (PSCW) | 2013 Rates | Natural gas rates | Bad debt expense

Regulatory environment

Approved annual rate increase (decrease)

$ (43.8)

WPS | Public Service Commission of Wisconsin (PSCW) | 2016 Rates

Regulatory environment

Approved return on equity (as a percent)

10.00%

Approved common equity component average (as a percent)

51.00%

WPS | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Electric rates

Regulatory environment

Approved annual rate increase (decrease)

$ (7.9)

Approved annual rate increase (decrease), percentage

(0.80%)

Percent fuel costs can vary from the rate case approved costs before deferral is required

2.00%

Authorized revenue requirement for ReACT

$ 275

$ 275

WPS | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Natural gas rates

Regulatory environment

Approved annual rate increase (decrease)

$ (6.2)

Approved annual rate increase (decrease), percentage

(2.10%)

WPS | Public Service Commission of Wisconsin (PSCW) | 2015 Rates

Regulatory environment

Approved return on equity (as a percent)

10.20%

Approved common equity component average (as a percent)

50.28%

WPS | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Electric rates

Regulatory environment

Approved annual rate increase (decrease)

$ 24.6

Percent fuel costs can vary from the rate case approved costs before deferral is required

2.00%

Increase in cost of fuel for electric generation

$ 42

Year-over-year positive (negative) change in decoupling refunded to or collected from customers

9

Customer recoveries (refunds) related to decoupling

(4)

WPS | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Natural gas rates

Regulatory environment

Approved annual rate increase (decrease)

(15.4)

Year-over-year positive (negative) change in decoupling refunded to or collected from customers

(16)

Customer recoveries (refunds) related to decoupling

(8)

WPS | Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Electric rates

Regulatory environment

Customer recoveries (refunds) related to decoupling

(13)

WPS | Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Natural gas rates

Regulatory environment

Customer recoveries (refunds) related to decoupling

$ 8

WPS | Michigan Public Service Commission (MPSC) | 2015 Rates | Electric rates

Regulatory environment

Approved annual rate increase (decrease)

$ 4

Approved return on equity (as a percent)

10.20%

Approved common equity component average (as a percent)

50.48%

Period of rate implementation

3 years

PGL and NSG | Illinois Commerce Commission (ICC) | Natural gas rates

Regulatory environment

Period of base rate freeze

2 years

PGL | Illinois Commerce Commission (ICC) | 2015 Rates | Natural gas rates

Regulatory environment

Approved annual rate increase (decrease)

$ 74.8

Approved return on equity (as a percent)

9.05%

Approved common equity component average (as a percent)

50.33%

Amended approved annual rate increase (decrease)

$ 71.1

NSG | Illinois Commerce Commission (ICC) | 2015 Rates | Natural gas rates

Regulatory environment

Approved annual rate increase (decrease)

$ 3.7

Approved return on equity (as a percent)

9.05%

Approved common equity component average (as a percent)

50.48%

Amended approved annual rate increase (decrease)

$ 3.5

MERC | Minnesota Public Utilities Commission (MPUC) | 2016 Rates | Natural gas rates

Regulatory environment

Approved annual rate increase (decrease)

$ 6.8

Approved annual rate increase (decrease), percentage

3.00%

Approved return on equity (as a percent)

9.11%

Approved common equity component average (as a percent)

50.32%

Number of years decoupling mechanism approved for

3 years

Interim rates to be refunded to customers

$ 3

MERC | Minnesota Public Utilities Commission (MPUC) | 2015 Rates | Natural gas rates

Regulatory environment

Approved annual rate increase (decrease)

$ 7.6

Approved return on equity (as a percent)

9.35%

Approved common equity component average (as a percent)

50.31%

Annual cap for decoupling mechanism (as a percent of rate case approved distribution revenues)

10.00%

Interim rates refunded to customers

$ 4.7

MGU | Michigan Public Service Commission (MPSC) | 2016 Rates | Natural gas rates

Regulatory environment

Approved annual rate increase (decrease)

$ 3.4

Approved annual rate increase (decrease), percentage

2.40%

Approved return on equity (as a percent)

9.90%

Approved common equity component average (as a percent)

52.00%

UMERC

Regulatory environment

Term of Electric Power Purchase Agreement

20 years

Capacity of Natural Gas Generating Facility | MW

180

Cost to construct power plant

$ 265

Cost to construct power plant with AFUDC

$ 275

Estimated portion of power plant cost recovery from Tilden Mines

50.00%

Estimated portion of power plant cost recovery from utility customers

50.00%

Other Income, Net (Details)

Other Income, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Income, net [Abstract]
AFUDC - Equity	$ 25.1	$ 20.1	$ 5.6
Gain on repurchase of notes	23.6	0	0
Gain on asset sales	19.6	22.9	7.5
Other, net	12.5	15.9	0.3
Other income, net	$ 80.8	$ 58.9	$ 13.4

Segment Information (Details)

Segment Information (Details) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)segment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jun. 29, 2015
Segment information
Document Period End Date									Dec. 31, 2016
Number of reportable segments | segment									6
Revenues	$ 1,963	$ 1,712.5	$ 1,602	$ 2,194.8	$ 1,848.3	$ 1,698.7	$ 991.2	$ 1,387.9	$ 7,472.3	$ 5,926.1	$ 4,997.1
Other operation and maintenance									2,185.5	1,709.3	1,112.4
Depreciation and amortization									762.6	561.8	391.4
Operating income (loss)	361.7	$ 399	$ 332.1	$ 589.3	380.2	$ 345.7	$ 165.8	$ 358.8	1,682.1	1,250.5	1,112.1
Equity in earnings of transmission affiliate									146.5	96.1	66
Interest expense									402.7	331.4	240.3
Capital expenditures									1,423.7	1,266.2	761.2
Total assets	30,123.2				29,355.2				30,123.2	29,355.2	14,905
Intersegment revenues
Segment information
Revenues									0	0	0
We Power
Segment information
Revenues									24.9	40	55.7
Other operation and maintenance									4.3	4.3	4.4
Depreciation and amortization									68.3	67.5	66.7
Operating income (loss)									375.6	373.4	368
Equity in earnings of transmission affiliate									0	0	0
Interest expense									62.1	63.4	64.6
Capital expenditures									62.3	53.4	41
Total assets	2,777.1				2,779				2,777.1	2,779	2,789.9
We Power | Intersegment revenues
Segment information
Revenues									423.3	405.2	383.4
Corporate and other
Segment information
Revenues									23.3	47.3	9.3
Other operation and maintenance									(15.8)	103.7	33
Depreciation and amortization									42.6	12.4	1.5
Operating income (loss)									(10)	(91.2)	(26.1)
Equity in earnings of transmission affiliate									0	0	0
Interest expense									120.9	91	48.8
Capital expenditures									97.8	33.4	5.2
Total assets	778				1,132.5				778	1,132.5	253.3
Corporate and other | Intersegment revenues
Segment information
Revenues									0	0	0
Reconciling eliminations
Segment information
Revenues									0	0	0
Other operation and maintenance									(423.6)	(409.3)	(387.7)
Depreciation and amortization									0	0	0
Operating income (loss)									0	0	0
Equity in earnings of transmission affiliate									0	0	0
Interest expense									(8.6)	(5.1)	(0.7)
Capital expenditures									0	0	0
Total assets	(3,349.2)				(3,431.7)				(3,349.2)	(3,431.7)	(2,966.1)
Reconciling eliminations | WE
Segment information
Total assets	2,029.5				2,105.3				2,029.5	2,105.3	2,172.9
Reconciling eliminations | Intersegment revenues
Segment information
Revenues									(423.6)	(410.2)	(392.6)
Regulated operations
Segment information
Revenues									7,424.1	5,838.8	4,932.1
Other operation and maintenance									2,620.6	2,010.6	1,462.7
Depreciation and amortization									651.7	481.9	323.2
Operating income (loss)									1,316.5	968.3	770.2
Equity in earnings of transmission affiliate									146.5	96.1	66
Interest expense									228.3	182.1	127.6
Capital expenditures									1,263.6	1,179.4	715
Total assets	29,917.3				28,875.4				29,917.3	28,875.4	14,827.9
Regulated operations | Intersegment revenues
Segment information
Revenues									0.3	5	9.2
Regulated operations | Wisconsin
Segment information
Revenues									5,805.4	5,186.1	4,932.1
Other operation and maintenance									2,025.4	1,741	1,462.7
Depreciation and amortization									496.6	408.6	323.2
Operating income (loss)									1,027	884.2	770.2
Equity in earnings of transmission affiliate									0	0	0
Interest expense									180.9	157.1	127.6
Capital expenditures									910.9	950.3	715
Total assets	21,730.7				21,113.5				21,730.7	21,113.5	14,403.8
Regulated operations | Wisconsin | Intersegment revenues
Segment information
Revenues									0.3	5	9.2
Regulated operations | Illinois
Segment information
Revenues									1,242.2	503.4	0
Other operation and maintenance									485.1	219.6	0
Depreciation and amortization									134	63.3	0
Operating income (loss)									239.6	78.1	0
Equity in earnings of transmission affiliate									0	0	0
Interest expense									38.9	19.9	0
Capital expenditures									293.2	194.4	0
Total assets	5,714.6				5,462.9				5,714.6	5,462.9	0
Regulated operations | Illinois | Intersegment revenues
Segment information
Revenues									0	0	0
Regulated operations | Other States
Segment information
Revenues									376.5	149.3	0
Other operation and maintenance									110.1	50	0
Depreciation and amortization									21.1	10	0
Operating income (loss)									49.9	6	0
Equity in earnings of transmission affiliate									0	0	0
Interest expense									8.5	5.1	0
Capital expenditures									59.5	34.7	0
Total assets	995.1				918				995.1	918	0
Regulated operations | Other States | Intersegment revenues
Segment information
Revenues									0	0	0
Regulated operations | Electric transmission
Segment information
Revenues									0	0	0
Other operation and maintenance									0	0	0
Depreciation and amortization									0	0	0
Operating income (loss)									0	0	0
Equity in earnings of transmission affiliate									146.5	96.1	66
Interest expense									0	0	0
Capital expenditures									0	0	0
Total assets	$ 1,476.9				$ 1,381				1,476.9	1,381	424.1
Regulated operations | Electric transmission | Intersegment revenues
Segment information
Revenues									$ 0	0	0
ATC
Segment information
Equity method investment, ownership interest (as a percent)	60.00%								60.00%			26.20%
Equity in earnings of transmission affiliate									$ 146.5	$ 96.1	$ 66

QUARTERLY FINANCIAL INFORMAT125

QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 1,963	$ 1,712.5	$ 1,602	$ 2,194.8	$ 1,848.3	$ 1,698.7	$ 991.2	$ 1,387.9	$ 7,472.3	$ 5,926.1	$ 4,997.1
Operating Income (Loss)	361.7	399	332.1	589.3	380.2	345.7	165.8	358.8	1,682.1	1,250.5	1,112.1
Net income attributed to common shareholders	$ 194.4	$ 217	$ 181.4	$ 346.2	$ 179.3	$ 182.5	$ 80.9	$ 195.8	$ 939	$ 638.5	$ 588.3
Earnings Per Share, Basic
Earnings per common share (basic) (in dollars per share)	$ 0.62	$ 0.69	$ 0.57	$ 1.10	$ 0.57	$ 0.58	$ 0.36	$ 0.87	$ 2.98	$ 2.36	$ 2.61
Earnings Per Share (Diluted)
Earnings per common share (diluted) (in dollars per share)	$ 0.61	$ 0.68	$ 0.57	$ 1.09	$ 0.57	$ 0.58	$ 0.35	$ 0.86	$ 2.96	$ 2.34	$ 2.59

Schedule I - Income Statements

Schedule I - Income Statements (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income statements
Equity in earnings of subsidiaries									$ 146.5	$ 96.1	$ 66
Other income, net									80.8	58.9	13.4
Interest expense									402.7	331.4	240.3
Income before income taxes									1,506.7	1,074.1	951.2
Income tax benefit									(566.5)	(433.8)	(361.7)
Net income attributed to common shareholders	$ 194.4	$ 217	$ 181.4	$ 346.2	$ 179.3	$ 182.5	$ 80.9	$ 195.8	939	638.5	588.3
WEC Energy Group
Income statements
Operating expenses									7	42.2	26.8
Equity in earnings of subsidiaries									996.5	695.7	635
Other income, net									2.7	23.2	2.8
Interest expense									90	71.2	53.1
Income before income taxes									902.2	605.5	557.9
Income tax benefit									36.8	33	30.4
Net income attributed to common shareholders									$ 939	$ 638.5	$ 588.3

Schedule I - Statements of Comp

Schedule I - Statements of Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statements of comprehensive income
Net income attributed to common shareholders	$ 194.4	$ 217	$ 181.4	$ 346.2	$ 179.3	$ 182.5	$ 80.9	$ 195.8	$ 939	$ 638.5	$ 588.3
Derivatives accounted for as cash flow hedges
Gains on settlement, net of tax of $7.6									0	11.4	0
Reclassification of gains to net income, net of tax									(1.3)	(0.8)	0
Cash flow hedges, net									(1.3)	10.6	0
Defined benefit plans
Pension and OPEB costs arising during the period, net of tax									(0.8)	(6.3)	0
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax									0.4	0	0
Defined benefit plans, net									(0.4)	(6.3)	0
Other comprehensive (loss) income, net of tax									(1.7)	4.3	0
Comprehensive income attributed to common shareholders									937.3	642.8	588.3
Other comprehensive (loss) income, tax
Gains on settlement, tax										7.6
WEC Energy Group
Statements of comprehensive income
Net income attributed to common shareholders									939	638.5	588.3
Derivatives accounted for as cash flow hedges
Gains on settlement, net of tax of $7.6									0	11.4	0
Reclassification of gains to net income, net of tax									(1.3)	(0.8)	0
Cash flow hedges, net									(1.3)	10.6	0
Defined benefit plans
Pension and OPEB costs arising during the period, net of tax									(1)	(1.5)	0
Amortization of pension and OPEB costs included in net periodic benefit cost, net of tax									0.3	0	0
Defined benefit plans, net									(0.7)	(1.5)	0
Other comprehensive income (loss) from subsidiaries, net of tax									0.3	(4.8)	0
Other comprehensive (loss) income, net of tax									(1.7)	4.3	0
Comprehensive income attributed to common shareholders									$ 937.3	642.8	$ 588.3
Other comprehensive (loss) income, tax
Gains on settlement, tax										$ 7.6

Schedule I - Balance Sheets (De

Schedule I - Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current assets
Cash and cash equivalents	$ 37.5	$ 49.8	$ 61.9	$ 26
Other	97.5	58.8
Current assets	2,168.7	2,206.8
Long-term assets
Other	461	489.7
Long-term assets	27,954.5	27,148.4
Total assets	30,123.2	29,355.2	14,905
Current liabilities
Short-term debt	860.2	1,095
Other	388.9	471.2
Current liabilities	2,431.6	2,709
Long-term liabilities
Long-term debt	9,158.2	9,124.1
Other	1,164.4	1,071.7
Long-term liabilities	18,731.4	17,961
Equity
Common shareholders' equity	8,960.2	8,685.2	4,450.1	4,263.4
Total liabilities and equity	30,123.2	29,355.2
WEC Energy Group
Current assets
Cash and cash equivalents	1.2	1.3	$ 37.3	$ 0.3
Accounts receivable from related parties	1.8	13.2
Notes receivable from related parties	76.4	123.2
Prepaid taxes	47.6	0
Other	0.5	2.2
Current assets	127.5	139.9
Long-term assets
Investments in subsidiaries	11,155.4	10,792.6
Other	134.7	254
Long-term assets	11,290.1	11,046.6
Total assets	11,417.6	11,186.5
Current liabilities
Short-term debt	321.8	307.9
Accounts payable to related parties	3.2	1.7
Notes payable to related parties	241.3	119
Accrued taxes	0	75.6
Other	10.3	17.5
Current liabilities	576.6	521.7
Long-term liabilities
Long-term debt	1,890	1,887.2
Other	21.2	122.8
Long-term liabilities	1,911.2	2,010
Equity
Common shareholders' equity	8,929.8	8,654.8
Total liabilities and equity	$ 11,417.6	$ 11,186.5

Schedule I - Statements of Cash

Schedule I - Statements of Cash Flows (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating activities
Net income attributed to common shareholders	$ 194.4	$ 217	$ 181.4	$ 346.2	$ 179.3	$ 182.5	$ 80.9	$ 195.8	$ 939	$ 638.5	$ 588.3
Reconciliation to cash provided by operating activities
Equity in earnings of subsidiaries									(146.5)	(96.1)	(66)
Deferred income taxes									498.7	420.4	329.2
Change in -
Other current assets									103.1	(27.2)	(13.9)
Other current liabilities									(20.8)	14.1	(45.3)
Other, net									(53.8)	(209.1)	(87.3)
Investing activities
Purchase of subsidiary's common stock									(42.3)	(8.7)	(13.1)
Proceeds from the sale of assets and businesses									166.3	28.9	13.9
Other, net									3	57	3.6
Financing activities
Exercise of stock options									41.6	30.1	50.3
Purchase of common stock									(108)	(74.7)	(123.2)
Dividends paid on common stock									(624.9)	(455.4)	(352)
Issuance of long-term debt									400	2,150	250
Other, net									(13.6)	(18.9)	12.8
Net change in cash and cash equivalents									(12.3)	(12.1)	35.9
Cash and cash equivalents at beginning of year				49.8				61.9	49.8	61.9	26
Cash and cash equivalents at end of year	37.5				49.8				37.5	49.8	61.9
WEC Energy Group
Operating activities
Net income attributed to common shareholders									939	638.5	588.3
Reconciliation to cash provided by operating activities
Equity in earnings of subsidiaries									(996.5)	(695.7)	(635)
Dividends from subsidiaries									734.4	538.8	720
Deferred income taxes									23.2	30.9	60.1
Change in -
Prepaid taxes									(47.6)	0	0
Other current assets									13	(9.3)	(0.3)
Accrued taxes									(75.6)	175.7	4.1
Other current liabilities									(5.6)	(3.2)	5.1
Other, net									6.3	(18.4)	(8.1)
Net cash provided by operating activities									590.6	657.3	734.2
Investing activities
Business acquisition									0	(1,486.2)	0
Capital contributions to subsidiaries									(55.8)	(135.3)	(225.5)
Short-term notes receivable from related parties, net									46.8	(91)	0
Purchase of subsidiary's common stock									(66.4)	0	0
Proceeds from the sale of assets and businesses									0	20.8	0
Other, net									(0.4)	(0.1)	5
Net cash used in investing activities									(75.8)	(1,691.8)	(220.5)
Financing activities
Exercise of stock options									41.6	30.1	50.3
Purchase of common stock									(108)	(74.7)	(123.2)
Dividends paid on common stock									(624.9)	(455.4)	(352)
Issuance of long-term debt									0	1,200	0
Change in short-term debt									13.9	307.9	(72)
Short-term notes payable to related parties, net									162.3	1.8	3.5
Other, net									0.2	(11.2)	16.7
Net cash (used in) provided by financing activities									(514.9)	998.5	(476.7)
Net change in cash and cash equivalents									(0.1)	(36)	37
Cash and cash equivalents at beginning of year				$ 1.3				$ 37.3	1.3	37.3	0.3
Cash and cash equivalents at end of year	$ 1.2				$ 1.3				$ 1.2	$ 1.3	$ 37.3

Schedule I - Cash Dividends Rec

Schedule I - Cash Dividends Received from Subsidiaries (Details) - WEC Energy Group - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Notes to parent company financial statements
Cash dividends received from subsidiaries	$ 734.4	$ 538.8	$ 720
WE
Notes to parent company financial statements
Cash dividends received from subsidiaries	455	240	390
WG
Notes to parent company financial statements
Cash dividends received from subsidiaries	75	30	33
We Power
Notes to parent company financial statements
Cash dividends received from subsidiaries	197.9	262.8	297
ATC Holding LLC
Notes to parent company financial statements
Cash dividends received from subsidiaries	$ 6.5	$ 6	$ 0

Schedule I - Future Maturities

Schedule I - Future Maturities of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Future maturities of long-term debt outstanding
2,018	$ 836.1
2,020	684.4
Thereafter	6,953.5
Total	9,322.4
Long-term notes outstanding	9,158.2	$ 9,124.1
WECC
Future maturities of long-term debt outstanding
Long-term notes outstanding	50
WEC Energy Group
Future maturities of long-term debt outstanding
2,018	300
2,020	400
Thereafter	1,200
Total	1,900
Long-term notes outstanding	$ 1,890	$ 1,887.2

Schedule I - Fair Value of Long

Schedule I - Fair Value of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Carrying amount
Financial instruments
Long-term debt	$ 9,285.8	$ 9,221.9
Fair value
Financial instruments
Long-term debt	9,818.2	9,681
WEC Energy Group | Carrying amount
Financial instruments
Long-term debt	1,890	1,887.2
WEC Energy Group | Fair value
Financial instruments
Long-term debt	$ 1,906.1	$ 1,900.7

Schedule I - Supplemental Cash

Schedule I - Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Notes to parent company financial statements
Cash (paid) received for income taxes, net		$ 9.3	$ 22
WEC Energy Group
Notes to parent company financial statements
Cash (paid) for interest	$ (89.6)	(68.8)	(44.4)
Cash (paid) received for income taxes, net	(62.9)	$ 242.9	$ 95.1
Short-term note payable settled through a non-cash capital contribution	$ 40

Schedule I - Short-Term Notes R

Schedule I - Short-Term Notes Receivable from Related Parties (Details) - WEC Energy Group - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Notes to parent company financial statements
Short-term notes receivable from related parties	$ 76.4	$ 123.2
Integrys
Notes to parent company financial statements
Short-term notes receivable from related parties	42	95.1
Bostco
Notes to parent company financial statements
Short-term notes receivable from related parties	18.5	19.6
Wispark
Notes to parent company financial statements
Short-term notes receivable from related parties	$ 15.9	$ 8.5

Schedule I - Short-Term Notes P

Schedule I - Short-Term Notes Payable to Related Parties (Details) - WEC Energy Group - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Notes to parent company financial statements
Short-term notes payable to related parties	$ 241.3	$ 119
WBS
Notes to parent company financial statements
Short-term notes payable to related parties	131.1	0
WECC
Notes to parent company financial statements
Short-term notes payable to related parties	109.3	108.4
Wisvest
Notes to parent company financial statements
Short-term notes payable to related parties	$ 0.9	$ 10.6

Schedule II - Valuation and 136

Schedule II - Valuation and Qualifying Accounts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Valuation and qualifying accounts
Balance at beginning of period	$ 113.3	$ 74.5	$ 61
Acquisitions of businesses	0	54.3	0
Expense	87.4	56.7	49.8
Deferral	(5.9)	8.2	18.4
Net write-offs	(86.8)	(80.4)	(54.7)
Balance at end of period	$ 108	$ 113.3	$ 74.5