WEC Energy (WEC) 10-K 26 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2015	Jan. 31, 2016	Jun. 30, 2015
Entity Information [Line Items]
Entity Registrant Name	WEC Energy Group, Inc.
Entity Central Index Key	783,325
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 14.2
Entity Common Stock, Shares Outstanding (actual number of shares)		315,652,119

Consolidated Income Statements

Consolidated Income Statements - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
Operating revenues	$ 5,926.1	$ 4,997.1	$ 4,519
Cost of sales	2,240.1	2,259.4	1,827.1
Other operation and maintenance	1,709.3	1,112.4	1,155
Depreciation and amortization	561.8	391.4	340.1
Property and revenue taxes	164.4	121.8	116.7
Total operating expenses	4,675.6	3,885	3,438.9
Operating Income	1,250.5	1,112.1	1,080.1
Equity earnings from subsidiaries	96.1	66	68.5
Other income, net	58.9	13.4	18.8
Interest expense	331.4	240.3	250.9
Other expense	(176.4)	(160.9)	(163.6)
Income before income taxes	1,074.1	951.2	916.5
Income tax expense	433.8	361.7	337.9
Net income	640.3	589.5	578.6
Preferred stock dividends of subsidiaries	1.8	1.2	1.2
Net income attributed to common shareholders	$ 638.5	$ 588.3	$ 577.4
Earnings Per Share (Basic)
Earnings per common share (basic) (in dollars per share)	$ 2.36	$ 2.61	$ 2.54
Earnings Per Share (Diluted)
Earnings per common share (diluted) (in dollars per share)	$ 2.34	$ 2.59	$ 2.51
Weighted Average Common Shares Outstanding (Basic)
Basic (in shares)	271.1	225.6	227.6
Weighted Average Common Shares Outstanding (Diluted)
Diluted (in shares)	272.7	227.5	229.7

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net income	$ 640.3	$ 589.5	$ 578.6
Derivatives accounted for as cash flow hedges
Gains on settlement, net of tax of $7.6	11.4	0	0
Reclassification of gains to net income, net of tax	(0.8)	0	0
Cash flow hedges, net	10.6	0	0
Defined Benefit Plans
Pension and OPEB costs arising during period, net of tax of $1.0	(6.3)	0	0
Other comprehensive income, net of tax	4.3	0	0
Comprehensive income	644.6	589.5	578.6
Preferred stock dividends of subsidiaries	1.8	1.2	1.2
Comprehensive income attributed to common shareholders	$ 642.8	$ 588.3	$ 577.4

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income (Parentheticals) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Statement of Comprehensive Income [Abstract]
Gain on settlement, tax	$ 7.6
Pension and OPEB costs arising during period, tax	$ 4.2

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment
In service	$ 26,249.5	$ 15,509
Accumulated depreciation	(7,919.1)	(4,485.1)
In service, net	18,330.4	11,023.9
Construction work in progress	822.9	191.8
Leased facilities, net	36.4	42
Net Property, Plant and Equipment	19,189.7	11,257.7
Investments
Equity investment in transmission affiliate	1,380.9	424.1
Other	85.8	32.8
Total Investments	1,466.7	456.9
Current Assets
Cash and cash equivalents	49.8	61.9
Accounts receivable, net of allowance for doubtful accounts of $113.3 and $74.5, respectively	1,028.6	643.4
Materials, supplies and inventories	687	400.6
Assets held for sale	96.8	0
Prepayments	285.8	148.2
Prepaid taxes and other	58.8	38.6
Total current assets	2,206.8	1,292.7
Deferred Charges and Other Assets
Regulatory assets	3,064.6	1,271.2
Goodwill	3,023.5	441.9
Other long-term assets	403.9	184.6
Total deferred charges and other assets	6,492	1,897.7
Total assets	29,355.2	14,905
Capitalization
Common stock - $0.01 par value; 325,000,000 shares authorized; 315,683,496 and 225,517,339 shares outstanding, respectively	3.2	2.3
Additional paid in capital	4,347.2	300.1
Retained earnings	4,299.8	4,117
Accumulated other comprehensive income	4.6	0.3
Preferred of subsidiaries	30.4	30.4
Long-term debt	9,124.1	4,170.7
Total capitalization	17,809.3	8,620.8
Current Liabilities
Current portion of long-term debt	157.7	424.1
Short-term debt	1,095	617.6
Accounts payable	815.4	363.3
Accrued payroll and benefits	169.7	95.1
Other	471.2	168.6
Total current liabilities	2,709	1,668.7
Deferred Credits and Other Liabilities
Regulatory liabilities	1,392.2	830.6
Deferred income taxes	4,622.3	2,664
Deferred revenue, net	579.4	614.1
Pension and other postretirement benefit obligations	543.1	203.8
Environmental remediation	628.2	32.6
Other	1,071.7	270.4
Total deferred credits and other liabilities	$ 8,836.9	$ 4,615.5
Commitments and Contingencies (Note Q)
Total capitalization and liabilities	$ 29,355.2	$ 14,905

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Accounts receivable and unbilled revenues, reserves	$ 113.3	$ 74.5
Common stock, par value	$ 0.01
Common stock, shares authorized	325,000,000
Common stock, shares outstanding	315,683,496	225,517,339

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Activities
Net income	$ 640.3	$ 589.5	$ 578.6
Reconciliation to net cash provided by operating activities
Depreciation and amortization	583.5	417	396
Deferred income taxes and investment tax credits, net	418.7	328.1	312.7
Contributions to pension and OPEB plans	(121)	(13.9)	(22.8)
Change in -
Accounts receivable and unbilled revenues	84	80.7	(162.9)
Materials, supplies, and inventories	(69.4)	(71.2)	31.3
Other current assets	(27.2)	(13.9)	2.8
Accounts payable	(9.3)	23.7	(14.8)
Accrued taxes, net	35.7	(11.4)	36.6
Other current liabilities	(21.6)	(33.9)	(1.5)
Other, net	(220.1)	(95.8)	76.2
Net cash provided by operating activities	1,293.6	1,198.9	1,232.2
Investing Activities
Capital expenditures	(1,266.2)	(761.2)	(725.2)
Business acquisition, net of cash acquired	(1,329.9)	0	0
Cash acquired from business acquisition	156.3
Investment in transmission affiliate	(8.7)	(13.1)	(10.5)
Proceeds from asset sales	28.9	13.9	2.5
Proceeds from cashout of corporate owned life insurance policies	17.3	0	0
Other, net	41.1	3.6	(12.6)
Net cash used in investing activities	(2,517.5)	(756.8)	(745.8)
Financing Activities
Exercise of stock options	30.1	50.3	48.5
Purchase of common stock	(74.7)	(123.2)	(223.4)
Dividends paid on common stock	(455.4)	(352)	(328.9)
Redemption of WPS preferred stock	(52.7)	0	0
Issuance of long-term debt	2,150	250	251
Retirement of long-term debt	(529.6)	(324.3)	(397.2)
Change in short-term debt	163	80.2	142.8
Other, net	(18.9)	12.8	11.2
Net cash provided by (used in) financing activities	1,211.8	(406.2)	(496)
Net change in cash and cash equivalents	(12.1)	35.9	(9.6)
Cash and cash equivalents at beginning of year	61.9	26	35.6
Cash and cash equivalents at end of year	$ 49.8	$ 61.9	$ 26

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 Subsidiaries
Balance at Dec. 31, 2012	$ 4,165.5	$ 4,135.1	$ 2.3	$ 500.3	$ 3,632.2	$ 0.3	$ 30.4
Equity
Net income attributed to common shareholders	577.4	577.4	0	0	577.4	0	0
Other comprehensive income, net of tax	0
Common stock dividends	(328.9)	(328.9)	0	0	(328.9)	0	0
Exercise of stock options	48.5	48.5	0	48.5	0	0	0
Purchase of common stock	(223.4)	(223.4)	0	(223.4)	0	0	0
Stock-based compensation and other	24.3	24.3	0	24.3	0	0	0
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, net of tax	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, net of tax	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

Consolidated Statements of Equ9

Consolidated Statements of Equity (Parenthetical) - $ / shares	Sep. 01, 2015	Jul. 06, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Stockholders' Equity [Abstract]
Dividends per share (in dollars per share)	$ 0.4575	$ 0.4225	$ 1.74	$ 1.56	$ 1.45

Consolidated Statements of Capi

Consolidated Statements of Capitalization - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Shareholders' equity	$ 8,685.2	$ 4,450.1
Preferred of subsidiaries	30.4	30.4
Obligations under capital leases	59.9	84.5
Long-term Debt and Capital Lease Obligations, Including Current Maturities	9,314.6	4,636.9
Integrys Fair Value Adjustment to Long-term Debt	41.1	0
Unamortized Debt Issuance Expense	(37.8)	(15.7)
Unamortized discount, net and other	(36.1)	(26.4)
Debt and Capital Lease Obligations	9,281.8	4,594.8
Long-term debt due currently	(157.7)	(424.1)
Long-term Debt and Capital Lease Obligations	9,124.1	4,170.7
Total Capitalization	$ 17,809.3	8,620.8
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%
Long-Term debt, Unsecured	$ 500
Debentures (unsecured), 6.25% due 2015 [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, Unsecured	$ 100	100
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%
Debentures (unsecured), 5.20% due 2015 [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.20%
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%
Long-Term debt, Unsecured	$ 90	90
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%
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	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
Shareholders' equity	$ 8,654.8	4,419.7
WEC Energy Group | WEC Senior Notes due June 15, 2018 [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.65%
Long-Term debt, Unsecured	$ 300	0
WEC Energy Group | WEC Senior Notes due June 15, 2020 [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.45%
Long-Term debt, Unsecured	$ 400	0
WEC Energy Group | WEC Senior Notes due June 15, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.55%
Long-Term debt, Unsecured	$ 500	0
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
Wisconsin Electric
Long-Term debt, Unsecured	$ 147
Wisconsin Electric | Debentures (unsecured), 6.25% due 2015 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.25%
Long-Term debt, Unsecured	$ 0	250
Wisconsin Electric | Debentures (unsecured), 1.70% due 2018 [Member]
Long-Term debt, Unsecured	250	250
Wisconsin Electric | Debentures (unsecured), 4.25% due 2019 [Member]
Long-Term debt, Unsecured	250	250
Wisconsin Electric | Debentures (unsecured) 2.95% due 2021 [Member]
Long-Term debt, Unsecured	$ 300	300
Wisconsin Electric | Wis Elec Debenture due June 1, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.10%
Long-Term debt, Unsecured	$ 250	0
Wisconsin Electric | Debentures (unsecured), 6-1/2% due 2028 [Member]
Long-Term debt, Unsecured	150	150
Wisconsin Electric | Debentures (unsecured), 5.625% due 2033 [Member]
Long-Term debt, Unsecured	335	335
Wisconsin Electric | Debentures (unsecured), 5.70% due 2036 [Member]
Long-Term debt, Unsecured	300	300
Wisconsin Electric | Debentures (unsecured), 3.65% due 2042 [Member]
Long-Term debt, Unsecured	250	250
Wisconsin Electric | Debentures (unsecured), 4.25% due 2044 [Member]
Long-Term debt, Unsecured	250	250
Wisconsin Electric | Wis Elec Debenture due December 15, 2045 [Member]
Long-Term debt, Unsecured	250	0
Wisconsin Gas LLC | Debentures (unsecured), 5.20% due 2015 [Member]
Long-Term debt, Unsecured	0	125
Wisconsin Gas LLC | Wis Gas Debenture due September 30, 2025 [Member] [Member]
Long-Term debt, Unsecured	200	0
WPS | Long Term Debt 5.65 Percent Series, Due 2017 [Member]
Long-Term debt, Unsecured	125	0
WPS | Long Term Debt 1.65% Series, Due 2018 [Member]
Long-Term debt, Unsecured	250	0
WPS | Long Term Debt 6.08 Percent Series, Due 2028 [Member]
Long-Term debt, Unsecured	50	0
WPS | Long Term Debt 5.55 Percent Series, Due 2036 [Member]
Long-Term debt, Unsecured	125	0
WPS | Long Term Debt 3.671% Series, Year Due, 2042 [Member]
Long-Term debt, Unsecured	300	0
WPS | Long Term debt 4.752% Series, Year Due 2044 [Member]
Long-Term debt, Unsecured	$ 450	0
PGL | Fixed First and Refunding Mortgage XX Series 2.21 Percent Bonds, Due 2016 [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.21%
Long-Term debt, Secured	$ 50	0
PGL | Fixed First and Refunding Mortgage TT Series 8 Percent Bonds, Due 2018 [Member]
Long-Term debt, Secured	5	0
PGL | Fixed First and Refunding Mortgage UU Series 4.63 Percent Bonds, Due 2019 [Member]
Long-Term debt, Secured	75	0
PGL | Fixed First and Refunding Mortgage VV Series 3.900 Percent Bonds, Due 2030 [Member]
Long-Term debt, Secured	50	0
PGL | Fixed First and Refunding Mortgage WW Series 1.875 Percent Bonds, Due 2033 [Member]
Long-Term debt, Secured	50	0
PGL | First and Refunding Mortgage Bonds, Series ZZ, 4.0% bonds due 2033 [Member]
Long-Term debt, Secured	50	0
PGL | Fixed First and Refunding Mortgage RR Series 4.3 Percent Bonds, Due 2035 [Member]
Long-Term debt, Secured	50	0
PGL | Fixed First and Refunding Mortgage YY Series 3.98 Percent Bonds Due 2042 [Member]
Long-Term debt, Secured	100	0
PGL | First and Refunding Mortgage Bonds, Series AAA, 3.96% bonds due 2043 [Member]
Long-Term debt, Secured	220	0
PGL | First and Refunding Mortgage Bonds, Series BBB, 4.21% bonds due 2044 [Member]
Long-Term debt, Secured	200	0
NSG | First Mortgage Bonds P Series 3.43 Percent Bonds [Member]
Long-Term debt, Secured	28	0
NSG | First Mortgage Series Q, 3.96% bonds due 2043 [Member]
Long-Term debt, Secured	$ 54	0
We Power | Notes (secured, nonrecourse), 4.91% due 2015-2030 [Member] [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.91%
Long-Term debt, Secured	$ 112.1	117.2
We Power | Notes (secured, nonrecourse), 5.209% due 2015-2030 [Member] [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.209%
Long-Term debt, Secured	$ 215	223.9
We Power | Notes (secured, nonrecourse), 4.673% due 2015-2031 [Member] [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.673%
Long-Term debt, Secured	$ 178.3	184.7
We Power | Notes (secured, nonrecourse), 6.00% due 2015-2033 [Member] [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.00%
Long-Term debt, Secured	$ 130.5	134.6
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	50	0
Integrys Holding Inc | Unsecured Senior Notes 4.17 Percent, Due 2020 [Member]
Long-Term debt, Unsecured	250	0
Integrys Holding Inc | TEG Junior Subordinated Notes, 6.11% due 2066 [Member]
Long-Term debt, Unsecured	$ 269.8	0
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	0
Bostco LLC | Notes (secured, nonrecourse), 4.81% effective rate due 2030 [Member]
Long-Term debt, Secured	$ 2	$ 2

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
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, Acquisition, 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 Wisconsin Electric, Wisconsin Gas, and WPS, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin. Wisconsin Electric'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 Wisconsin Electric. • Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, Wisvest, WECC, WBS, PDL, and ITF. 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) Reclassifications —On the income statements for the years ended December 31, 2014 and 2013, we reclassified $17.4 million and $48.0 million , respectively, from treasury grant to depreciation and amortization. We also reclassified $1.2 million from interest expense to preferred stock dividends of subsidiaries on the income statements for the years ended December 31, 2014 and 2013. These reclassifications were made to be consistent with the current year presentation on the income statements. During the fourth quarter of 2015, we early implemented ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. As a result, debt issuance costs of $15.7 million , previously reported as other long-term assets, were reclassified to offset long-term debt on the December 31, 2014 balance sheet. We also early implemented ASU 2015-17, Balance Sheet Classification of Deferred Taxes, during the fourth quarter of 2015. Since we adopted this ASU on a retrospective basis, we reclassified current deferred income taxes of $242.7 million , previously reported as a separate component of current assets, to offset long-term deferred income tax liabilities on the December 31, 2014 balance sheet. On the statements of cash flows for the years ended December 31, 2014 and 2013, we reclassified $2.4 million and $4.2 million , respectively, from depreciation and amortization to other operating activities. In addition, we reclassified $13.9 million and $22.8 million of nonqualified pension and OPEB contributions from other operating activities to contributions to pension and OPEB plans on the statements of cash flows for the years ended December 31, 2014 and 2013, respectively. Preferred stock dividends of subsidiaries of $1.2 million were also reclassified from other financing activities to net income on the statements of cash flows for the years ended December 31, 2014 and 2013. These reclassifications were made to be consistent with the current year presentation on the statements of cash flows. During the third quarter of 2015, following the acquisition of Integrys, we reorganized our business segments. All prior period amounts impacted by this change were reclassified to conform to the new presentation. See Note 24, Segment Information, for more information on our business segments. (c) Cash and Cash Equivalents —Cash and cash equivalents include marketable debt securities acquired three months or less from maturity. (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 return on common equity than authorized by the PSCW. • Wisconsin Electric 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 , and Note 23, Michigan Settlement , 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 Wisconsin Electric and Wisconsin Gas, 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 AMRP 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 revenue. 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. ITF accounts for revenues from construction management projects using the percentage of completion method. Revenues are recognized based on the percentage of costs incurred to date compared to the total estimated costs of each contract. This method is used because management considers total costs to be the best available measure of progress on these contracts. See Note 3, Dispositions, for more information . 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 Wisconsin Electric, Wisconsin Gas, 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, 2015 . In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2015 . (e) Materials, Supplies, and Inventories — Our inventory as of December 31 consisted of: (in millions) 2015 2014 Natural gas in storage $ 284.1 $ 124.8 Materials and supplies 219.2 150.2 Fossil fuel 183.7 125.6 Total $ 687.0 $ 400.6 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 Last-in, First-out (LIFO) cost method. Inventories stated on a LIFO basis represented approximately 18.0% of total inventories at December 31, 2015 . The estimated replacement cost of natural gas in inventory at December 31, 2015 , exceeded the LIFO cost by $15.2 million . In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $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. It holds investments that are classified as trading securities for accounting purposes. We do not intend to sell these investments in the near term. They are included in other investments on our balance sheet at December 31, 2015. The net unrealized loss included in earnings related to the investments held at the end of the period was not significant for the year ended December 31, 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 revenue 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 capitalized interest. Utility property also includes AFUDC – Equity. 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 2015 2014 2013 Wisconsin Electric 3.01% 2.93% 2.90% WPS (1) 1.30% N/A N/A Wisconsin Gas 2.36% 2.69% 2.68% PGL (1) 1.67% N/A N/A NSG (1) 1.22% N/A N/A MERC (1) 1.26% N/A N/A MGU (1) 1.32% N/A N/A (1) The rates shown for 2015 are for a partial year as a result of the acquisition of Integrys on June 29, 2015. 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 OC 1 and OC 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 Wisconsin Electric, WPS, and Wisconsin Gas. Approximately 50% of Wisconsin Electric's, WPS's, and Wisconsin Gas's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. For 2015, Wisconsin Electric's average AFUDC retail rate was 8.45% , and its average AFUDC wholesale rate was 1.72% . For the six months ended December 31, 2015, WPS's average AFUDC retail rate was 7.92% and its average AFUDC wholesale rate was 5.04% . For 2015, Wisconsin Gas's average AFUDC retail rate was 8.33% . 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 2015, 2014, or 2013. Our regulated utilities recorded the following AFUDC for the years ended December 31: (in millions) 2015 2014 2013 AFUDC – Debt $ 8.6 $ 2.3 $ 7.7 AFUDC – Equity $ 20.1 $ 5.6 $ 18.3 (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. Our reporting units containing goodwill perform annual goodwill impairment tests during the third quarter of each year. 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 and Other Intangible Assets, 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 the PTF 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 the PTF 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. A 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 AROs are accreted to their present value each period using the credit-adjusted risk-free interest rate associated with the expected settlement dates of the AROs. This rate is determined when the obligation is 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 18, Commitments and Contingencies, for more information . 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 stockholder approved plans, we provide long-term incentives through our equity interests to our outside directors, officers, and other key employees. The plans provide for the granting of stock options, restricted stock awards, performance shares, and other share-based awards. Awards may be paid in common stock, cash, or a combination thereof. We recognize share-based compensation expense on a straight-line basis. Accordingly, for employee awards classified as equity awards, share-based compensation expense is measured based on the grant-date fair value of the award and is recognized as expense ratably over the requisite service period. 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 grant. There were no modifications to the terms of outstanding stock options during the year. 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: 2015 2014 2013 Non-qualified stock options granted 516,475 899,500 1,418,560 Estimated fair value per non-qualified stock option $ 5.29 $ 4.18 $ 3.45 Assumptions used to value the options: Risk-free interest rate 0.1% – 2.1% 0.1% – 3.0% 0.1% – 1.9% Dividend yield 3.7 % 3.8 % 3.7 % Expected volatility 18.0 % 18.0 % 18.0 % Expected forfeiture rate 2.0 % 2.0 % 2.0 % Expected life (years) 5.8 5.8 5.9 The risk-free interest rate is based on the U.S. Treasury interest rate with a term consistent with the expected life of the stock options. Dividend yield, expected volatility, expected forfeiture rate, and expected life assumptions are 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. During the vesting period, restricted share recipients also have voting rights and are entitled to dividends in the same manner as other shareholders. 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 stockholder return (stock price appreciation plus dividends) as compared to the total stockholder return of a peer group of companies over a three-year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance unit award. All grants are settled in cash and are accounted for as liability awards accordingly. We accrue compensation costs over the three-year performance period based on our estimate of the final expected value of the awards. See Note 11, Common Equity, for more information on our share-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 by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. Options to purchase 516,475 shares of common stock with an exercise price of $52.90 were outstanding at December 31, 2015 , but were not included in the computation of diluted earnings per share because they were anti-dilutive. All stock options outstanding during 2014 and 2013 were included in the computation of diluted earnings per share. (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, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a perpetual dividend discount model. The fair value of our long-term debt, including the current portion of long-term debt, but excluding capitalized leases, is estimated based upon the quoted market value for the same issue, similar issues, or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows. We conduct a thorough review of fair value hierarchy classifications on a quarterly basis. 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 an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that

Acquisition

Acquisition	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
ACQUISITION	ACQUISITION On June 29, 2015, Wisconsin Energy Corporation acquired 100% of the outstanding common shares of Integrys and changed its name to WEC Energy Group, Inc. Integrys is a provider of regulated natural gas and electricity, as well as nonregulated renewable energy and CNG products and services. Integrys also held a 34% interest in ATC, a for-profit transmission company regulated by the FERC. The acquisition of Integrys provides increased scale, the potential for long-term cost savings through a combination of lower capital and operating costs, and the potential for operating efficiencies. 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. The fair values of Integrys's assets and liabilities subject to rate-setting provisions provide revenues derived from costs, including a return on investment of assets and 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 and Other Intangible Assets , for the allocation of goodwill to our reportable segments. The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. The allocation is subject to change during the remainder of the measurement period, which ends one year from the acquisition date, as we obtain additional information, including with respect to certain regulatory and legal matters and the expected sale of ITF. (in millions) Current assets $ 1,069.9 Net property, plant, and equipment 7,091.8 Investments * 1,062.5 Goodwill 2,581.6 Deferred charges and other assets, excluding goodwill 1,737.9 Current liabilities, including current maturities of long-term debt (1,293.5 ) Deferred credits and other liabilities (3,668.5 ) Long-term debt (2,947.5 ) 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 is permitted for any interim and annual financial statements that have 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: • Wisconsin Electric and Wisconsin Gas will be subject to an earnings sharing mechanism for three years beginning January 1, 2016. Under the earnings sharing mechanism, 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 Wisconsin Electric, the additional utility earnings will be used to reduce the company’s transmission escrow. For Wisconsin Gas, additional utility earnings will be used to reduce the costs of the Western Gas Lateral. All utility earnings above the first 50 basis points will be used to reduce the transmission escrow for Wisconsin Electric and reduce the costs of the Western Gas Lateral for Wisconsin Gas. • 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 Wisconsin Electric 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 $107.6 million and $12.5 million during 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. No acquisition costs were recorded in 2013. 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 payments of $16.9 million were made during 2015, leaving a severance accrual of $8.0 million on our balance sheet at December 31, 2015 . Severance costs to be incurred after December 31, 2015 are not expected to be material. The severance expense was recorded in the following segments: (in millions) 2015 Wisconsin $ 11.1 Illinois 0.9 Other states 0.1 Corporate and other 12.8 Total severance expense $ 24.9 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 .

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
DISPOSITIONS	DISPOSITIONS Corporate and Other Segment – Pending Sale of Integrys Transportation Fuels In February 2016, we reached an agreement to sell ITF. The sale is scheduled to close in the first quarter of 2016. ITF is a provider of CNG fueling services and a single-source provider of CNG fueling facility design, construction, operation and maintenance. The pending 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 pending sale of ITF does not represent a shift in our corporate strategy and will not have a major effect on our operations and financial results. Therefore, ITF's results of operations remain in continuing operations. The pre-tax profit or loss of this individually significant component was not material for the year ended December 31, 2015. In November 2015, we sold our 30% joint interest in AMP Trillium LLC. This transaction was not significant, and there was no gain recorded on the sale. In addition, in the fourth quarter of 2015, we lowered the fair value of the remaining ITF assets to fair market value, less costs to sell. This fair value adjustment was reflected in the allocation of the purchase price for the acquisition. See Note 2, Acquisition, for more information . 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, 2015
Equity Method Investments and Joint Ventures [Abstract]
INVESTMENT IN AMERICAN TRANSMISSION COMPANY	INVESTMENT IN AMERICAN TRANSMISSION COMPANY Due to the acquisition of Integrys on June 29, 2015, our ownership of ATC increased from 26.2% to approximately 60% . ATC is a for-profit, transmission-only company regulated by the FERC. 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) 2015 2014 2013 Balance at beginning of period $ 424.1 $ 402.7 $ 378.3 Add: Earnings from equity method investment 96.1 66.0 68.5 Add: Capital contributions 8.7 13.1 10.5 Add: Acquisition of Integrys's investment in ATC 541.5 — — Add: Equity method goodwill from the acquisition of Integrys * 395.8 — — Less: Distributions received 85.1 57.5 54.5 Less: Other 0.2 0.2 0.1 Balance at end of period $ 1,380.9 $ 424.1 $ 402.7 * Represents the purchase price allocated to Integrys's investment in ATC in excess of the recorded value. 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 is reimbursed to us 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) 2015 2014 2013 Charges to ATC for services and construction $ 15.4 $ 8.1 $ 9.0 Charges from ATC for network transmission services 289.2 231.4 234.2 As of December 31, 2015 and 2014 , our balance sheets included the following receivables and payables related to ATC: (in millions) 2015 2014 Accounts receivable Services provided to ATC $ 1.0 $ 0.6 Accounts payable Services received from ATC 28.3 19.3 Summarized financial data for ATC is included in the tables below: (in millions) 2015 2014 2013 Income statement data Revenues $ 615.8 $ 635.0 $ 626.3 Operating expenses 319.3 307.4 295.0 Other expense 96.1 88.9 83.7 Net income $ 200.4 $ 238.7 $ 247.6 (in millions) December 31, 2015 December 31, 2014 Balance sheet data Current assets $ 80.5 $ 66.4 Noncurrent assets 3,957.6 3,728.7 Total assets $ 4,038.1 $ 3,795.1 Current liabilities $ 330.3 $ 313.1 Long-term debt 1,800.0 1,701.0 Other noncurrent liabilities 245.0 163.8 Shareholders' equity 1,662.8 1,617.2 Total liabilities and shareholders' equity $ 4,038.1 $ 3,795.1

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION (in millions) 2015 2014 2013 Cash paid for interest, net of amount capitalized $ 329.6 $ 241.1 $ 250.4 Cash paid (received) for income taxes, net of refunds 9.3 22.0 (39.6 ) Significant non-cash transactions: Construction costs funded through accounts payable 177.1 1.8 4.7 Amortization of deferred revenue 39.9 55.7 56.5 Note receivable received related to the sale of AMP Trillium* 12.0 — — Capital assets received related to the sale of AMP Trillium * 6.3 — — * See Note 3, Dispositions, for more information . At December 31, 2015 , restricted cash of $118.4 million was recorded within other long-term assets on our balance sheet. 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.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 See Note Regulatory assets (1) (2) Unrecognized pension and OPEB costs (3) $ 1,306.4 $ 669.1 17 Environmental remediation costs (4) 697.0 45.9 18 Income tax related items (5) 248.3 176.0 Electric transmission costs (6) 191.5 146.0 AROs 173.0 17.6 9 SSR 86.1 — 22 Derivatives 70.4 14.7 1(t) Energy efficiency programs (7) 48.7 58.0 PTF (8) 45.4 66.6 Other, net 234.9 77.3 Total regulatory assets $ 3,101.7 $ 1,271.2 Balance Sheet Presentation Current assets (9) $ 37.1 $ — Regulatory assets 3,064.6 1,271.2 Total regulatory assets $ 3,101.7 $ 1,271.2 (1) Based on prior and current rate treatment, we believe it is probable that our utility subsidiaries will continue to recover from customers the regulatory assets in the table above. (2) As of December 31, 2015 , we had $33.8 million of regulatory assets not earning a return and $136.6 million of regulatory assets earning a return based on short-term interest rates. (3) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. (4) As of December 31, 2015 , we had not yet made cash expenditures for $628.2 million of these environmental remediation costs. The recovery of these costs depends on the timing of the actual expenditures. (5) Adjustments related to deferred income taxes. As the related temporary differences reverse, we prospectively collect taxes from customers for which deferred taxes were recorded in prior years. (6) Represents amounts recoverable from customers related to transmission costs incurred that exceed amounts authorized for recovery in our current rates. (7) Represents amounts recoverable from customers related to programs at the utility subsidiaries designed to meet energy efficiency standards. (8) Represents amounts recoverable from customers related to Wisconsin Electric's costs of the PTF units, including subsequent capital additions. (9) Short-term regulatory assets are recorded in accounts receivable and accrued unbilled revenues on our balance sheets. The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2015 2014 See Note Regulatory liabilities Removal costs (1) $ 1,209.6 $ 741.1 Energy costs refundable through rate adjustments (2) 76.9 18.9 Uncollectible expense (3) 31.8 30.1 Mines deferral (4) 31.6 — Unrecognized pension and OPEB costs (5) 26.3 3.8 17 Other, net 49.8 36.7 Total regulatory liabilities $ 1,426.0 $ 830.6 Balance Sheet Presentation Other current liabilities $ 33.8 $ — Regulatory liabilities 1,392.2 830.6 Total regulatory liabilities $ 1,426.0 $ 830.6 (1) Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment. (2) Represents energy costs that will be refunded to customers in the future. (3) Represents amounts refundable to customers related to our uncollectible expense tracking mechanisms. These mechanisms allow us to recover or refund the difference between actual uncollectible write-offs and the amounts recovered in rates. (4) Represents the deferral of margins from the 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. (5) Represents the unrecognized future OPEB costs resulting from actuarial gains on OPEB plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan.

Property, Plant, and Equipment

Property, Plant, and Equipment	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 Utility property, plant, and equipment $ 22,803.7 $ 12,290.7 Less: Accumulated depreciation 7,358.2 4,044.6 Net 15,445.5 8,246.1 CWIP 672.7 170.1 Net utility property, plant, and equipment 16,118.2 8,416.2 Non-utility and other property, plant, and equipment 3,482.2 3,260.3 Less: Accumulated depreciation 560.9 440.5 Net 2,921.3 2,819.8 CWIP 150.2 21.7 Net non-utility and other property, plant, and equipment 3,071.5 2,841.5 Total property, plant, and equipment $ 19,189.7 $ 11,257.7

Jointly Owned Facilities

Jointly Owned Facilities	12 Months Ended
	Dec. 31, 2015
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 the Oak Creek Expansion units to Wisconsin Electric, and Wisconsin Electric operates these units. Wisconsin Electric 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. Wisconsin Electric'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, 2015 was as follows: We Power WPS (in millions, except for percentages and MWs) Oak Creek Expansion Units 1 and 2 Weston 4 Columbia Energy Center Units 1 and 2 Edgewater Unit 4 Ownership 83.34 % 70.0 % 31.8 % 31.8 % Share of rated capacity (MWs) * 1,056.8 374.5 352.9 96.3 In-service date 2010 and 2011 2008 1975 and 1978 1969 Property, plant, and equipment $ 2,359.6 $ 591.5 $ 404.6 $ 47.6 Accumulated depreciation $ (283.4 ) $ (150.5 ) $ (122.6 ) $ (30.6 ) CWIP $ 35.5 $ 5.9 $ 23.4 $ 0.4 * Based on expected capacity ratings for summer 2016. 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.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
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. The utilities establish regulatory assets and liabilities 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. PDL has AROs recorded 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: (in millions) 2015 2014 2013 Balance as of January 1 $ 43.6 $ 42.3 $ 44.3 Integrys subsidiaries 491.0 — — Accretion 14.5 2.4 2.4 Additions and revisions to estimated cash flows 35.5 * — — Liabilities settled (13.4 ) (1.1 ) (4.4 ) Balance as of December 31 $ 571.2 $ 43.6 $ 42.3 * An ARO of $16.1 million was recorded during 2015 for fly-ash landfills located at generation facilities owned by Wisconsin Electric and WPS. An ARO of $9.0 million was also recorded for the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule passed by the EPA in April 2015. See Note 18, Commitments and Contingencies, for more information on this rule. 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 and Other Intangible A

Goodwill and Other Intangible Assets	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets Disclosure [Text Block]	GOODWILL AND OTHER INTANGIBLE ASSETS 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, 2015 and 2014 : Wisconsin Illinois Other States Total (in millions) 2015 2014 2015 2014 2015 2014 2015 2014 Balance as of January 1 Gross goodwill $ 441.9 $ 441.9 $ — $ — $ — $ — $ 441.9 $ 441.9 Accumulated impairment losses — — — — — — — — Net goodwill as of January 1 441.9 441.9 — — — — 441.9 441.9 Acquisition of Integrys 1,667.6 — 731.2 — 182.8 — 2,581.6 — Balance as of December 31 Gross goodwill 2,109.5 441.9 731.2 — 182.8 — 3,023.5 441.9 Accumulated impairment losses — — — — — — — — Net goodwill as of December 31 $ 2,109.5 $ 441.9 $ 731.2 $ — $ 182.8 $ — $ 3,023.5 $ 441.9 In the third quarter of 2015, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of August 31, 2015. No impairments resulted from these tests. The identifiable intangible assets other than goodwill listed below are part of other long-term assets on our balance sheets. We had no material intangible assets other than goodwill at December 31, 2014. December 31, 2015 (in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Amortized intangible assets (1) $ 16.0 $ (7.8 ) $ 8.2 Unamortized intangible assets (2) 5.7 — 5.7 Total intangible assets $ 21.7 $ (7.8 ) $ 13.9 (1) Primarily relates to contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at WPS's Fox Energy Center. The remaining weighted-average amortization period for our amortized intangible assets at December 31, 2015 , was approximately three years . (2) Consists primarily of a trade name.

Common Equity

Common Equity	12 Months Ended
	Dec. 31, 2015
Stockholders' Equity Note [Abstract]
COMMON EQUITY	COMMON EQUITY Share-Based Compensation Plans The following table summarizes our pre-tax share-based compensation expense and the related tax benefit for the year ended December 31: (in millions) 2015 2014 2013 Stock options $ 3.3 $ 3.7 $ 3.9 Restricted stock 7.0 2.8 2.4 Performance units 13.0 15.4 12.7 Share-based compensation expense $ 23.3 $ 21.9 $ 19.0 Related tax benefit $ 9.3 $ 8.8 $ 7.6 Stock-based compensation capitalized was not significant during 2015 , 2014 , and 2013 . Stock Options The following is a summary of our stock option activity during 2015 : 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, 2015 6,770,194 $ 29.99 Granted 516,475 $ 52.90 Exercised (1,302,005 ) $ 23.09 Outstanding as of December 31, 2015 5,984,664 $ 33.47 5.6 $ 107.6 Exercisable as of December 31, 2015 3,280,334 $ 26.84 3.9 $ 80.3 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, 2015 . This is calculated as the difference between our closing stock price on December 31, 2015 , 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, 2015 , 2014 , and 2013 was $36.1 million , $50.5 million , and $44.5 million , respectively. Cash received from options exercised during the years ended December 31, 2015 , 2014 , and 2013 , was $30.1 million , $50.3 million , and $48.5 million , respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $14.5 million , $19.9 million , and $17.8 million , respectively. At December 31, 2015 , total compensation cost related to non-vested stock options not yet recognized was approximately $1.5 million , which is expected to be recognized over the next 19 months on a weighted-average basis. During the first quarter of 2016 , the Compensation Committee awarded 752,085 non-qualified stock options with a weighted-average exercise price of $51.80 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 2015 : Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding as of January 1, 2015 155,479 $ 38.45 Granted 143,107 $ 51.13 Released (68,429 ) $ 36.95 Forfeited (1,139 ) $ 46.26 Outstanding as of December 31, 2015 229,018 $ 46.78 On July 31, 2015, the Compensation Committee awarded certain of our officers and other employees an aggregate of 82,943 shares of restricted stock for the key role each played in our acquisition of Integrys. The restricted stock vests in three equal installments on January 29, 2016, January 31, 2017, and July 31, 2018. The intrinsic value of restricted stock released was $3.7 million , $2.7 million , and $4.0 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $1.3 million , $1.0 million , and $1.3 million , respectively. As of December 31, 2015 , total compensation cost related to restricted stock not yet recognized was approximately $3.1 million , which is expected to be recognized over the next 20 months on a weighted-average basis. During the first quarter of 2016 , the Compensation Committee awarded 113,892 restricted shares to certain of our directors, officers, and other key employees under its normal schedule of awarding long-term incentive compensation. Performance Units In January 2015 , 2014 , and 2013 , the Compensation Committee awarded 195,365 ; 233,735 ; and 239,120 performance units, respectively, to officers and other key employees under the WEC Energy Group Performance Unit Plan. Performance units earned as of December 31, 2015 , 2014 , and 2013 vested and were settled during the first quarter of 2016 , 2015 , and 2014 , and had a total intrinsic value of $13.2 million , $13.2 million , and $14.8 million , respectively. The actual tax benefit realized for the tax deductions from the distribution of performance units for the same years was approximately $4.5 million , $4.8 million , and $5.3 million , respectively. As of December 31, 2015 , total compensation cost related to performance units not yet recognized was approximately $11.8 million , which is expected to be recognized over the next 20 months on a weighted-average basis. During the first quarter of 2016 , the Compensation Committee awarded 283,505 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, Wisconsin Electric, Wisconsin Gas, 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. Wisconsin Electric may not pay common dividends to us under Wisconsin Electric's Restated Articles of Incorporation if any dividends on its outstanding preferred stock have not been paid. In addition, pursuant to the terms of Wisconsin Electric's 3.60% Serial Preferred Stock, Wisconsin Electric'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. Integrys has long-term debt obligations that contain financial and other covenants, including, but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65% . 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. We and Integrys have the option to defer interest payments on our Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our 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, 2015 , 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 $6.2 billion . This amount exceeds 25% of our consolidated net assets as of December 31, 2015 . 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 2015, 2014, or 2013, other than for the Integrys acquisition discussed below. 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 : 2015 2014 2013 (in millions) Shares Cost Shares Cost Shares Cost Under share repurchase programs — $ — 0.4 $ 18.6 3.0 $ 126.0 To fulfill exercised stock options and restricted stock awards 1.5 74.7 2.3 104.6 2.4 97.4 Total 1.5 $ 74.7 2.7 $ 123.2 $ 5.4 $ 223.4 Integrys Acquisition On June 29, 2015, we issued approximately 90.2 million common shares to acquire Integrys. All Integrys unvested stock-based compensation awards became fully vested upon the close of the transaction and were paid to award recipients in cash or deferred into a deferred compensation plan. In addition, all vested but unexercised Integrys stock options were paid in cash. See Note 2, Acquisition, for more information on this acquisition. Common Stock Dividends During the year ended December 31, 2015 , our Board of Directors declared common stock dividends which are summarized below: Date Declared Date Payable Per Share Period January 15, 2015 March 1, 2015 $0.4225 First quarter April 16, 2015 June 1, 2015 $0.4225 Second quarter June 12, 2015 (1) July 6, 2015 (2) $0.2067 45 days through June 28, 2015 June 12, 2015 (1) September 1, 2015 (3) $0.2337 47 days through Aug. 14, 2015 October 15, 2015 December 1, 2015 $0.4575 Fourth quarter (1) Pro rata dividends were declared on June 12, 2015, in anticipation of closing the acquisition of Integrys. (2) The dividend payable on July 6, 2015, was based on a quarterly rate of $0.4225 per share. (3) The dividend payable on September 1, 2015, was based on our new quarterly rate of $0.4575 per share, which represents an 8.3% increase over the prior quarterly rate. Pursuant to the terms of the Merger Agreement, our Board of Directors adopted a new dividend policy.

Preferred Stock

Preferred Stock	12 Months Ended
	Dec. 31, 2015
Class of Stock Disclosures [Abstract]
Preferred Stock [Text Block]	PREFERRED STOCK The following table shows preferred stock authorized and outstanding at December 31, 2015 and 2014 : 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 — — $ — Wisconsin Electric $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 2014 (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 — — $ — Wisconsin Electric $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 — — — Total $ 30.4 On November 13, 2015, WPS redeemed all 511,882 outstanding shares of its five series of preferred stock: (i) 131,916 shares of 5.00% Series; (ii) 29,983 shares of 5.04% Series; (iii) 49,983 shares of 5.08% Series; (iv) 150,000 shares of 6.76% Series; and (v) 150,000 shares of 6.88% Series. The aggregate redemption price was $52.7 million , plus accumulated and unpaid dividends.

Short-Term Debt and Lines of Cr

Short-Term Debt and Lines of Credit	12 Months Ended
	Dec. 31, 2015
Short-term Debt [Abstract]
SHORT-TERM DEBT AND LINES OF CREDIT	SHORT-TERM DEBT AND LINES OF CREDIT Short-term notes payable balances and their corresponding weighted-average interest rates as of December 31 consist of: 2015 2014 (in millions, except percentages) Balance Balance Commercial paper Amount outstanding at December 31 $ 1,095.0 $ 617.6 Average interest rate on amounts outstanding at December 31 0.68 % 0.22 % Average amounts outstanding during the year * 817.8 468.1 * Based on daily outstanding balances during the year. WEC Energy Group, Wisconsin Electric, WPS, Wisconsin Gas, and PGL have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require us 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. All companies are in compliance with their respective ratio. As of December 31, 2015 , we had $1,387.0 million of available capacity under our bank back-up credit facilities and $1,095.0 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 2015 WEC Energy Group December 2020 $ 1,050.0 Wisconsin Electric December 2020 500.0 WPS * December 2016 250.0 Wisconsin Gas 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 $ 18.0 Commercial paper outstanding 1,095.0 Available capacity under existing agreements $ 1,387.0 * WPS plans to request approval from the PSCW to extend the maturity through December 2020. In December 2015, WEC Energy Group, Wisconsin Electric, and Wisconsin Gas amended their credit facilities to extend their expirations to December 2020. At the same time, WPS and PGL terminated their prior credit facilities and entered into new credit facilities. The lenders under the WPS facility have agreed that its maturity can be extended to December 2020, subject to the receipt of PSCW approval. 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, 2015
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. Our outstanding long-term debt, including current maturities as of December 31, 2015 , included approximately $3.0 billion of Integrys debt assumed on June 29, 2015. The amount assumed included $46.2 million of fair value adjustments recorded in connection with purchase accounting, which will be amortized over the estimated remaining life of the debt and will not be a part of future principal payments. See Note 2, Acquisition, for more information regarding the acquisition. WEC Energy Group In June 2015, we issued $300.0 million of 1.65% Senior Notes due June 15, 2018, $400.0 million of 2.45% Senior Notes due June 15, 2020, and $500.0 million of 3.55% Senior Notes due June 15, 2025. The net proceeds were used to pay a portion of the cash consideration for the acquisition of Integrys and related transaction costs, and for general corporate purposes. Wisconsin Electric Power Company In May 2015, Wisconsin Electric issued $250.0 million of 3.10% Debentures due June 1, 2025. The net proceeds were used to repay short-term debt and for general corporate purposes. In November 2015, Wisconsin Electric issued $250.0 million of 4.30% Debentures due December 15, 2045. The proceeds were used to repay short-term debt, to repay a portion of Wisconsin Electric’s $250.0 million of 6.25% Debentures that matured on December 1, 2015, and for working capital and general corporate purposes. Wisconsin Public Service Corporation In November 2015, WPS redeemed all of the remaining $0.1 million aggregate principal amount of First Mortgage Bonds, 7.125% Series due July 1, 2023 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest to the date of redemption. Following the redemption, WPS discharged its mortgage indenture and does not intend to issue additional first mortgage bonds. All of WPS's senior notes outstanding are now senior unsecured obligations and rank equally with all of its other unsecured obligations. In December 2015, WPS's $125.0 million of 6.375% Senior Notes matured, and the outstanding principal balance was repaid. In December 2015, WPS issued $250.0 million of 1.65% Senior Notes due December 4, 2018. The proceeds were used to repay short-term debt incurred to repay all of WPS's $125.0 million of 6.375% Senior Notes at maturity, and for working capital and general corporate purposes. Wisconsin Gas In September 2015, Wisconsin Gas issued $200.0 million of 3.53% Debentures due September 30, 2025. The net proceeds were used to repay short-term debt and for general corporate purposes. In December 2015, Wisconsin Gas's $125.0 million of 5.20% Debentures matured, and the outstanding principal balance was repaid. The Peoples Gas Light and Coke Company In August 2015, the interest rate on PGL's $50.0 million of 2.625% Series WW Bonds was reset. The new interest rate is 1.875% . The new mandatory interest reset date is August 1, 2020. The final maturity of these bonds is February 1, 2033. In November 2016, PGL's 2.21% First and Refunding Mortgage Bonds will mature. As a result, the $50.0 million balance of these bonds was included in the current portion of long-term debt on our balance sheet at December 31, 2015. W.E. Power During 2016, $5.4 million of We Power's outstanding $112.1 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, 2015. During 2016, $4.4 million of We Power's outstanding $130.5 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, 2015. During 2016, $10.2 million of We Power's outstanding $215.0 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, 2015. During 2016, $7.4 million of We Power's outstanding $178.3 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, 2015. Integrys Holding In July 2015, Integrys tendered an offer to repurchase all $55.0 million outstanding of its 8.00% Senior Notes due June 1, 2016, and $5.0 million of this amount was tendered and purchased. The $50.0 million balance of these notes was included in the current portion of long-term debt on our balance sheet at December 31, 2015 . Bonds and Notes The following table shows the future maturities and sinking fund requirements of our long-term debt outstanding (excluding obligations under capital leases) as of December 31, 2015 : (in millions) Payments 2016 $ 127.4 2017 154.5 2018 836.1 2019 357.7 2020 684.4 Thereafter 7,094.6 Total $ 9,254.7 We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense. Wisconsin Electric is the obligor under two series of tax-exempt pollution control refunding bonds in an outstanding principal amount of $147.0 million . In August 2009, Wisconsin Electric terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. Wisconsin Electric purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2015 and 2014 , the repurchased bonds were still outstanding, but were not reported in our consolidated long-term debt or included on our capitalization statements because they are held by Wisconsin Electric. Depending on market conditions and other factors, Wisconsin Electric may change the method used to determine the interest rate on the bonds and have them remarketed to third parties. 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 $500.0 million of 6.25% Junior Notes will bear interest at the three-month London Interbank Offered Rate (LIBOR) plus 211.25 basis points and will reset quarterly. In connection with Integrys’s outstanding 2006 6.11% Junior Subordinated Notes ( 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. 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. Effective December 1, 2016, the remaining $114.9 million aggregate principal amount of the 6.11% Junior Notes will bear interest at the three-month LIBOR rate plus 212 basis points and will reset quarterly. In connection with the transaction, Integrys issued approximately $66.4 million of additional common stock to WEC Energy Group in satisfaction of its obligations under the Integrys RCC. 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 Rate plus 322 basis points and will reset quarterly. Certain long-term debt obligations contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65% . 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, Wisconsin Electric 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 no minimum energy requirements. When the contract expires in 2022 , Wisconsin Electric may, at its option and with proper notice, renew for another ten 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 $36.2 million and $34.9 million in lease payments during 2015 and 2014 , 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 $59.9 million as of December 31, 2015 , 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) 2015 2014 Long-term power purchase commitment $ 140.3 $ 140.3 Accumulated amortization (103.9 ) (98.3 ) Total leased facilities $ 36.4 $ 42.0 Future minimum lease payments under our capital lease and the present value of our net minimum lease payments as of December 31, 2015 are as follows: (in millions) Payments 2016 $ 45.1 2017 13.9 2018 14.7 2019 15.5 2020 16.4 Thereafter 24.9 Total minimum lease payments 130.5 Less: Estimated executory costs (47.4 ) Net minimum lease payments 83.1 Less: Interest (23.2 ) Present value of net minimum lease payments 59.9 Less: Due currently (30.3 ) Long-term obligations under capital lease $ 29.6

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Income Tax Expense The following table is a summary of income tax expense for each of the years ended December 31: (in millions) 2015 2014 2013 Current tax expense $ 15.1 $ 33.6 $ 25.2 Deferred income taxes, net 420.4 329.2 313.8 Investment tax credit, net (1.7 ) (1.1 ) (1.1 ) Total income tax expense $ 433.8 $ 361.7 $ 337.9 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 U.S. statutory federal income tax rate to income before income taxes as a result of the following: 2015 2014 2013 Effective Effective Effective (in millions) Amount Tax Rate Amount Tax Rate Amount Tax Rate Expected tax at statutory federal tax rates $ 375.5 35.0 % $ 332.5 35.0 % $ 320.3 35.0 % State income taxes net of federal tax benefit 73.1 6.8 % 50.5 5.3 % 49.0 5.3 % Production tax credits (17.4 ) (1.6 )% (17.4 ) (1.8 )% (16.7 ) (1.8 )% AFUDC – Equity (7.1 ) (0.7 )% (1.9 ) (0.2 )% (6.4 ) (0.7 )% Investment tax credit restored (1.7 ) (0.2 )% (1.1 ) (0.1 )% (1.1 ) (0.1 )% Treasury grant (1.7 ) (0.2 )% (3.8 ) (0.4 )% (7.4 ) (0.8 )% Other, net 13.1 1.3 % 2.9 0.2 % 0.2 — % Total income tax expense $ 433.8 40.4 % $ 361.7 38.0 % $ 337.9 36.9 % Deferred Income Tax Assets and Liabilities The components of deferred income taxes as of December 31 are as follows: (in millions) 2015 2014 Deferred tax assets Future tax benefits $ 382.8 $ 221.7 Employee benefits and compensation 229.9 111.9 Deferred revenues 219.9 221.3 Property-related 59.5 28.8 Other 177.1 118.4 Total deferred tax assets 1,069.2 702.1 Valuation allowance (17.1 ) — Net deferred tax assets $ 1,052.1 $ 702.1 Deferred tax liabilities Property-related 4,451.5 2,750.4 Employee benefits and compensation 428.9 242.5 Investment in transmission affiliate 420.4 188.6 Deferred transmission costs 76.7 58.5 Other 296.9 126.1 Total deferred tax liabilities 5,674.4 3,366.1 Deferred tax liability, net $ 4,622.3 $ 2,664.0 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, 2015 and 2014 are summarized in the table below: 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 ) 2014 (in millions) Gross Value Deferred Tax Effect Valuation Allowance Earliest Year of Expiration Future tax benefits as of December 31, 2014 Federal net operating loss $ 416.2 $ 145.7 $ — 2029 Federal tax credit — 76.0 — 2029 Balance as of December 31, 2014 $ 416.2 $ 221.7 $ — Valuation allowances of approximately $17.1 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) 2015 2014 Balance as of January 1 $ 7.2 $ 8.4 Acquired legacy Integrys unrecognized tax benefits 3.6 — Additions for tax positions of prior years 0.3 — Additions based on tax positions related to the current year 0.2 — Reductions for tax positions of prior years (1.1 ) (1.2 ) Settlements during the period (0.7 ) — Balance as of December 31 $ 9.5 $ 7.2 The amount of unrecognized tax benefits as of December 31, 2015 and 2014, excludes deferred tax assets related to uncertainty in income taxes of $6.2 million and $7.2 million , respectively. As of December 31, 2015 , our effective tax rate could be affected by recognition of approximately $2.2 million of unrecognized tax benefits. As of December 31, 2014 , there were no unrecognized tax benefits that, if recognized, would impact the effective tax rate. We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the year ended December 31, 2015 , we recognized no accrued interest in our income statements. For the years ended December 31, 2014 and 2013 , we recognized approximately $0.3 million and $0.2 million , respectively, of accrued interest in our income statements. For the years ended December 31, 2015 , 2014 , and 2013 , we recognized no penalties in our income statements. 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. For the year ended December 31, 2014 , we had approximately $0.7 million of interest accrued and no 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, 2015, we were subject to examination by state or local tax authorities for the 2008 through 2015 tax years in our major state operating jurisdictions as follows: Jurisdiction Years Federal 2012–2015 Illinois 2008–2015 Michigan 2008–2015 Minnesota 2011–2015 Wisconsin 2011–2015

Guarantees

Guarantees	12 Months Ended
	Dec. 31, 2015
Guarantees [Abstract]
GUARANTEES	GUARANTEES The following table shows our outstanding guarantees: Total Amounts Committed Expiration (in millions) at December 31, 2015 Less Than 1 Year 1 to 3 Years Over 3 Years Guarantees Guarantees supporting commodity transactions of subsidiaries (1) $ 174.5 $ 95.0 $ — $ 79.5 Standby letters of credit (2) 28.4 18.5 9.7 0.2 Surety bonds (3) 38.6 38.6 — — Other guarantees (4) 70.5 20.6 0.1 49.8 Total guarantees $ 312.0 $ 172.7 $ 9.8 $ 129.5 (1) Consists of (a) $5.0 million and $11.0 million to support the business operations of WBS and PDL, respectively; and (b) $117.6 million , $40.3 million , and $0.6 million related to natural gas supply at MERC, MGU, and ITF, respectively. These amounts are not reflected on our balance sheets. (2) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets. (3) Primarily for the construction and operation of CNG fueling stations by ITF, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets. (4) Consists of (a) $19.1 million to support PDL's future payment obligations related to its distributed solar generation projects, of which $6.6 million is covered by a reciprocal guarantee from a third party; (b) $20.0 million for an interconnection agreement between WPS and ATC; (c) $10.0 million related to the sale of a nonregulated retail marketing business previously owned by Integrys; (d) $11.2 million related to the performance of an operating and maintenance agreement by ITF; and (e) $10.2 million related to other indemnifications. The amounts discussed in items (a), (b) and (d) are not reflected on our balance sheets. An insignificant liability was recorded for item (c) related to the possible imposition of additional miscellaneous gross receipts tax in the event of a change in law or interpretation of the law. In addition, a liability of $9.6 million related to workers compensation coverage was recorded for item (e).

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
EMPLOYEE BENEFIT PLANS	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. Approximately half of the projected benefit obligation for legacy Wisconsin Energy Corporation employees relates to benefits 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) 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) 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) 2015 2014 2015 2014 Change in benefit obligation Obligation at January 1 $ 1,505.5 $ 1,410.2 $ 397.7 $ 362.7 Obligation assumed from acquisition 1,594.0 — 493.0 — Service cost 30.4 10.1 20.7 8.5 Interest cost 94.3 68.1 26.7 17.8 Participant contributions — — 12.7 9.1 Plan amendments — — — (4.6 ) Actuarial loss (gain) 14.6 120.4 (74.0 ) 29.4 Benefit payments (156.0 ) (103.3 ) (36.2 ) (26.4 ) Federal subsidy on benefits paid N/A N/A 1.6 1.2 Plan curtailment 0.2 — (0.2 ) — Obligation at December 31 $ 3,083.0 $ 1,505.5 $ 842.0 $ 397.7 Change in fair value of plan assets Fair Value at January 1 $ 1,444.6 $ 1,451.0 $ 333.5 $ 327.6 Assets received from acquisition 1,420.9 — 442.1 — Actual return on plan assets (62.1 ) 88.5 (15.6 ) 17.7 Employer contributions 107.7 8.4 13.3 5.5 Participant contributions — — 12.7 9.1 Benefit payments (156.0 ) (103.3 ) (36.2 ) (26.4 ) Fair value at December 31 $ 2,755.1 $ 1,444.6 $ 749.8 $ 333.5 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) 2015 2014 2015 2014 Other long-term assets $ 74.1 $ 39.2 $ 50.1 $ 39.5 Pension and other postretirement benefit obligations * 402.0 100.1 142.3 103.7 Total net liabilities $ 327.9 $ 60.9 $ 92.2 $ 64.2 * 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 pension plans was $2,936.4 million and $1,504.6 million as of December 31, 2015 , and 2014 , respectively. The following table shows information for the pension plans for which we have an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2015 2014 Projected benefit obligation $ 1,706.6 $ 100.1 Accumulated benefit obligation 1,560.5 99.8 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) 2015 2014 2015 2014 Accumulated other comprehensive loss (pre-tax) (1) Net actuarial loss (gain) $ 11.4 $ — $ (0.6 ) $ — Total $ 11.4 $ — $ (0.6 ) $ — Net regulatory assets (2) Net actuarial loss $ 798.1 $ 622.7 $ 23.7 $ 44.1 Prior service costs (credits) 4.7 6.8 (3.3 ) (4.6 ) Total $ 802.8 $ 629.5 $ 20.4 $ 39.5 (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 2016: (in millions) Pension Costs OPEB Costs Net actuarial loss $ 41.6 $ 1.9 Prior service costs 1.7 (1.2 ) Total 2016 – estimated amortization $ 43.3 $ 0.7 The components of net periodic benefit cost for the years ended December 31 are as follows: Pension Costs OPEB Costs (in millions) 2015 2014 2013 2015 2014 2013 Service cost $ 30.4 $ 10.1 $ 14.6 $ 20.7 $ 8.5 $ 10.0 Interest cost 94.3 68.1 60.4 26.7 17.8 15.6 Expected return on plan assets (155.6 ) (98.6 ) (95.8 ) (39.6 ) (23.7 ) (21.3 ) Plan curtailment (0.3 ) — — — — — Amortization of prior service cost (credit) 2.2 2.1 2.3 (6.4 ) (1.8 ) (2.0 ) Amortization of net actuarial loss 68.5 36.7 54.5 3.9 1.2 3.7 Settlement charge — — 2.5 — — — Net periodic benefit cost $ 39.5 $ 18.4 $ 38.5 $ 5.3 $ 2.0 $ 6.0 The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension OPEB 2015 2014 2015 2014 Discount rate 4.46% 4.15% 4.38% 4.20% Rate of compensation increase 4.00% 4.00% N/A N/A Assumed medical cost trend rate N/A N/A 7.50% 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 2015 2014 2013 Discount rate 4.11% 5.00% 4.10% Expected return on plan assets 7.37% 7.25% 7.25% Rate of compensation increase 4.0% 4.0% 4.0% OPEB Costs 2015 2014 2013 Discount rate 4.09% 4.95% 4.15% Expected return on plan assets 7.54% 7.50% 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 2016, the expected return on assets assumption is 7.13% 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, 2015, 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 $ 6.5 $ (5.3 ) Effect on health care component of the accumulated postretirement benefit obligations 79.4 (65.9 ) 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. Previously, the Wisconsin Energy Corporation pension trust target allocation was 45% equity investments and 55% fixed income investments. A transition to a target asset allocation of 35% equity investments, 55% fixed income investments, and 10% private equity and real estate investments began in late 2014. The Integrys pension trust target allocation moved from 70% equity investments and 30% fixed income investments in 2014 to 60% equity investments and 40% fixed income investments for 2015. The current OPEB trusts' target asset allocations are 60% equity investments and 40% fixed income investments for Wisconsin Energy Corporation, and 70% equity investments and 30% fixed income investments for Integrys. 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 U.S. 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. The following tables provide the fair values of our investments by asset class: 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 $ 45.8 $ — $ 62.8 $ 9.8 $ 1.3 $ — $ 11.1 Equity securities: U.S. Equity 524.1 291.0 — 815.1 146.4 136.3 — 282.7 International Equity 192.2 351.2 — 543.4 57.2 133.3 — 190.5 Fixed income securities: * U.S. Bonds 53.2 1,019.2 — 1,072.4 122.3 116.1 — 238.4 International Bonds 67.4 140.3 — 207.7 16.0 6.7 — 22.7 Private Equity and Real Estate — — 53.7 53.7 — — 4.4 4.4 Total $ 853.9 $ 1,847.5 $ 53.7 $ 2,755.1 $ 351.7 $ 393.7 $ 4.4 $ 749.8 * This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries. December 31, 2014 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 $ 6.4 $ — $ — $ 6.4 $ 1.4 $ — $ — $ 1.4 Equity securities: U.S. Equity 503.8 — — 503.8 146.0 — — 146.0 International Equity 128.6 29.8 — 158.4 42.2 2.5 — 44.7 Fixed income securities: * U.S. Bonds 42.5 599.3 — 641.8 3.5 112.4 — 115.9 International Bonds 79.3 43.3 — 122.6 17.5 7.0 — 24.5 Private Equity and Real Estate — — 11.6 11.6 — — 1.0 1.0 Total $ 760.6 $ 672.4 $ 11.6 $ 1,444.6 $ 210.6 $ 121.9 $ 1.0 $ 333.5 * This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. 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 (in millions) Pension OPEB Beginning balance at January 1, 2015 $ 11.6 $ 1.0 Realized and unrealized gains (losses) 1.8 0.1 Purchases 51.1 4.2 Liquidations (10.8 ) (0.9 ) Ending balance at December 31, 2015 $ 53.7 $ 4.4 Private Equity and Real Estate (in millions) Pension OPEB Beginning balance at January 1, 2014 $ — $ — Purchases 11.6 1.0 Ending balance at December 31, 2014 $ 11.6 $ 1.0 Cash Flows We expect to contribute $23.8 million to the pension plans and $6.9 million to OPEB plans in 2016, 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 2016 $ 305.7 $ 48.4 2017 215.4 53.4 2018 211.9 52.2 2019 223.2 54.7 2020 224.9 57.1 2021-2025 1,105.2 307.0 Savings Plans We sponsor 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 through an employee stock ownership plan (ESOP) contribution or cash contribution up to certain limits. The ESOPs held 5.5 million shares of our common stock (market value of $280.6 million ) at December 31, 2015. Certain employees participate in a defined contribution pension plan, in which amounts are contributed to an employee's account based on the employee's wages, age, and years of service. Total costs incurred under all of these plans were $48.0 million in 2015 and $14.2 million in both 2014 and 2013.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES We and our subsidiaries have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental remediation, and enforcement and litigation matters. Unconditional Purchase Obligations Energy Related Purchased Power Agreements 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, 2015 , including those of our subsidiaries. Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2016 2017 2018 2019 2020 Later Years Electric utility: Purchased power 2027 $ 811.9 $ 110.1 $ 78.4 $ 74.9 $ 62.1 $ 62.4 $ 424.0 Coal supply and transportation 2019 608.7 310.2 177.4 110.0 11.1 — — Nuclear 2033 10,012.5 412.8 415.3 420.0 445.4 475.1 7,843.9 Natural gas utility supply and transportation 2028 1,244.6 331.6 263.6 200.1 159.3 115.2 174.8 Total $ 12,677.7 $ 1,164.7 $ 934.7 $ 805.0 $ 677.9 $ 652.7 $ 8,442.7 Operating Leases We lease various property, plant, and equipment with various terms in the operating leases. 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 $12.7 million , $4.8 million , and $4.0 million in 2015 , 2014 , and 2013 , respectively. Future minimum payments under noncancelable operating leases are payable as follows: Year Ending December 31 Payments (in millions) 2016 $ 9.8 2017 9.8 2018 9.0 2019 6.2 2020 5.7 Later years 66.6 Total $ 107.1 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 new 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 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 Sulfur Dioxide National Air Ambient 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 latitude in rule implementation. States have the option of modeling or monitoring to show attainment (subject to EPA approval for this selection) and make attainment designation recommendations. If a state chooses modeling and an area does not show attainment, and sources do not agree to reductions by 2017 to allow attainment, the area would be classified as nonattainment. A plan would need to be developed requiring emission reductions to bring the area back into attainment by 2023. Alternatively, if a state opted out of modeling and instead chose to install air quality monitors, and subsequently monitored nonattainment, then it would face a 2026 compliance date. 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 requires the EPA to complete attainment designations for certain areas with large sources by no later than July 2, 2016. SO 2 emissions from PIPP are above the emission threshold, which means that the Marquette area requires action earlier than would otherwise be required under the revised NAAQS. However, we were able to show through modeling that the area should be designated as attainment. Based upon this modeling, the state of Michigan recommended to the EPA that the Marquette area be designated as attainment. We expect that the EPA will act on this recommendation in 2016. We believe our fleet overall is well positioned to meet the new regulation. 8-Hour Ozone National Air Ambient Quality Standards The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released the final rule, which lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. For nonattainment areas, the state will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020 and are in the process of reviewing and determining potential impacts resulting from this rule. Mercury and Other Hazardous Air Pollutants In December 2011, the EPA issued the final MATS rule, which imposes stringent limitations on emissions of mercury and other hazardous air pollutants from coal and oil-fired electric generating units beginning in April 2015. In addition, both Wisconsin and Michigan have state mercury rules that require a 90% reduction of mercury; however, these rules are not in effect as long as MATS is in place. In June 2015, the United States Supreme Court (Supreme Court) ruled on a challenge to the MATS rule and remanded the case back to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals), ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule has been remanded to the EPA to address the Supreme Court decision, but remains in effect while the EPA completes its cost evaluation. Our compliance plans currently include capital projects for PIPP and for WPS's jointly owned plants to achieve the required reductions for MATS. Construction on the addition of a dry sorbent injection system for further control of mercury and acid gases at PIPP is essentially complete and going through final startup and tuning. In addition, construction of the ReACT TM multi-pollutant control system at Weston Unit 3 is complete and startup/commissioning work is underway with an expected in-service date of July 2016. Controls for acid gases and mercury are already in operation at the Pulliam units. In April 2013, Wisconsin Electric received a one year MATS compliance extension from the MDEQ for PIPP through April 2016. Although WPS also received a one year MATS compliance extension from the WDNR for Weston Unit 3 through April 2016, this unit is shut down to complete the construction of the ReACT TM system. 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 as an alternative to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. The final rule for existing fossil generating units seeks to achieve state-specific GHG emission reduction goals by 2030, and requires states to submit plans by September 6, 2016. States submitting initial plans and requesting an extension would be required to submit final plans by September 2018, either alone or in conjunction with other states. States will be required to meet interim goals over the period from 2022 through 2029, and a final goal in 2030, with the goal of reducing 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. 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. Rules for existing, as well as new, modified, and reconstructed generating units became effective in October 2015. A draft Federal Plan and Model Trading Rule 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 review to the EPA of the final standards for existing as well as new, modified, and reconstructed generating units. A petition for review was also submitted jointly by the Wisconsin utilities. The utilities' petition narrowly asks 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% . The state's petition asks for review of a number of aspects of the final rules, including an adjustment to reflect the Kewaunee Power Station retirement. In January 2016, we submitted comments on the draft Federal Plan and Model Trading Rule. Michigan state agencies announced modeling results that suggest that the state will be able to meet existing source requirements until 2025, based on planned coal plant retirements, along with a continuation of state renewable standards and current levels of energy efficiency. A stakeholder process began in the middle of January 2016. Michigan plans to submit an interim plan by September 6, 2016, with a request for a two year extension for submittal of a final plan. We are in the process of reviewing the final rule for existing generating units to determine the potential impacts to our operations. The rule could result in significant additional compliance costs, including capital expenditures, could impact how we operate our existing fossil-fueled power plants and biomass facility, and could have a material adverse impact on our operating costs. In October 2015, following publication of the final rule, 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 on February 9, 2016, the Supreme Court stayed the effectiveness of the rule until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that review is sought, at the Supreme Court. Therefore, it is unlikely that states will move forward on the development of state plans until the litigation is complete. In addition, on February 15, 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. We are required to report our CO 2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2014, Wisconsin Energy Corporation reported aggregated CO 2 equivalent emissions of approximately 23.3 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that WEC Energy Group will report CO 2 equivalent emissions of approximately 31.0 million metric tonnes to the EPA for 2015. 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 2014, Wisconsin Energy Corporation reported aggregated CO 2 equivalent emissions of approximately 10.8 million metric tonnes to the EPA related to our distribution and sale of natural gas. Based upon our preliminary analysis of the data, we estimate that WEC Energy Group will report CO 2 equivalent emissions of approximately 27.1 million metric tonnes to the EPA for 2015. The increase in CO 2 equivalent amounts reported between 2014 and 2015 for the electric generating facilities, as well as the amounts related to the distribution and sale of natural gas, are primarily related to the addition of the Integrys regulated companies, which were acquired on June 29, 2015. Water Quality Clean Water Act Cooling Water Intake Structure Rule In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement and entrainment. The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the Oak Creek expansion units, which were permitted under the rules governing new facilities. Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for VAPP Units 1 and 2, Pulliam Units 7 and 8, and Weston Unit 2, satisfy the IM BTA requirements. For VAPP Unit 2, a project to install fish protection screens to meet the IM BTA standard was completed in October 2015. The same types of screens are scheduled to be installed on VAPP Unit 1 starting in September 2016. 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 proposed intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for Pulliam Units 7 and 8, Weston Units 2 through 4, Port Washington Generating Station, Pleasant Prairie Power Plant, PIPP, and Oak Creek Power Plant Units 5 through 8. During 2016 – 2018, we plan 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. In addition, the rule allows the EM BTA requirements to be waived in cases of pending facility retirements, which we are currently considering for PIPP. Based on discussions with the MDEQ, if we submit a signed certification with our next National Pollutant Discharge Elimination System permit application 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 will commence in January 2016 at PIPP. Steam Electric Effluent Guidelines The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin and Michigan. Unless pending challenges to the final guidelines are successful, the WDNR and MDEQ will modify the state rules and incorporate the new requirements into our facility permits, which are renewed every five years . We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment will likely require additional biological treatment capital improvements for the Oak Creek and Pleasant Prairie facilities. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are also required by the new rule, and modifications will be required at Oak Creek Units 5 and 6, the Pleasant Prairie units, PIPP Units 5 through 9, 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 $70 million to $100 million for these biological treatment and bottom ash transport systems. Valley Power Plant Wisconsin Pollution Discharge Elimination System Permit The WDNR issued a WPDES permit for VAPP that became effective in January 2013. The permit contains several additional requirements including effluent toxicity testing and monitoring for additional parameters (phosphorous, mercury, and ammonia-nitrogen), and a new heat addition limit from the cooling water discharges that all took effect immediately. Other long-term compliance requirements include thermal discharge studies, phosphorous evaluation and feasibility for reduction, mercury minimization planning, and the installation of new cooling water intake fish protection screens. Installation of wedge wire screens for fish protection on the VAPP Unit 2 cooling water intake structure is complete. An identical modification is planned for VAPP Unit 1 in 2016. We are also currently involved in planning to meet the remaining long-term requirements. Land Quality Coal Combustion Residuals Rule In April 2015, the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities final rule was entered into the Federal Register. The final rule regulates the disposal of coal combustion residuals as a non-hazardous waste. We do not expect the compliance costs will be significant because we currently have a program of beneficial utilization for most of our coal combustion products. If needed, we have landfill capacity that meets the rule requirements for our remaining coal combustion product sources. Coal Combustion Product Landfill Sites We aggressively seek environmentally acceptable, beneficial uses for our coal combustion products. However, some coal combustion products have been, and to a small degree continue to be, managed in company-owned, licensed landfills. Some early designed and constructed landfills have at times required some level of monitoring or remediation. Where we have become aware of these conditions, and where necessary, we have worked to define the nature and extent of the impact, if any, and work has been performed to address these conditions. During 2015 , 2014 , and 2013 , landfill remediation expenses were not material. See Note 9, Asset Retirement Obligations, for more information about obligations related to these sites. Renewables, Efficiency, and Conservation Wisconsin Act 141 In 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Under Act 141, Wisconsin Electric and WPS are required to increase their renewable energy percentage to 8.27% and 9.74% , respectively. To comply with these requirements, Wisconsin Electric constructed the Blue Sky Green Field wind park, the Glacier Hills wind park, and the Rothschild biomass facility. WPS constructed the Crane Creek wind park. Wisconsin Electric and WPS also rely on renewable energy purchases to meet their respective renewable portfolio standard commitments. Wisconsin Electric and WPS are in compliance with Act 141's 2015 standard and have entered into agreements for renewable energy credits, that should allow Wisconsin Electric and WPS to remain in compliance through 2022 and 2023, respectively. If market conditions are favorable, Wisconsin Electric and WPS may purchase more renewable energy credits. Act 141 assigned responsibility for the administration of energy efficiency, conservation, and renewable programs to the PSCW and/or contracted third parties. The funding required by Act 141 for 2015 was 1.2% of annual operating revenues of each utility. Michigan Act 295 In 2008, Michigan revised the requirements for renewable energy generation by enacting Act 295. Act 295 requires 10% of the state's energy to come from renewables by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. Wisconsin Electric and WPS are currently in compliance with this requirement. Act 295 specifically calls for current recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective. 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 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, some of these sites are coordinating the investigation and cleanup 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) 2015 2014 Regulatory assets $ 697.0 $ 45.9 Reserves for future remediation 628.0 32.6 The increases in the regulatory assets and reserves are primarily related to balances associated with the Integrys regulated companies, which were acquired on June 29, 2015. See Note 2, Acquisition, for more information . 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 Wisconsin Pollution Discharge Elimination System Permit In November 2014, the WDNR reissued the WPDES permit for the PSGS. We believed that the WDNR imposed unreasonable permit conditions with respect to temperature monitoring, the control of water treatment additive, and phosphorus discharges. To address these permit conditions, Wisconsin Electric filed a petition for a contested case hearing with the WDNR in January 2015. On the same day, Wisconsin Electric also filed a request to be covered by the statewide phosphorus variance to address one of its concerns with the permit. Wisconsin Electric reached an agreement with the WDNR with respect to the permit conditions for temperature monitoring and for restrictions related to the use of a water treatment additive. In March 2015, the WDNR issued a final WPDES permit with agreed upon modifications, and Wisconsin Electric withdrew its petition for a contested case hearing. In July 2015, the Milwaukee County Circuit Court entered a stipulation and Order for Judgment between the WDNR and Wisconsin Department of Justice. This order resolves the litigation by allowing Wisconsin Electric to maintain the ability to apply for and be covered by the statewide phosphorus variance. 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 PSGS Units 1 and 4, allowing those units to restart after a temporary outage related to a construction permit matter with the WDNR. We received an “after the fact” permit from the WDNR, and the units are now available for service. 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 administration order issued in this matter, which was granted. However, a hearing has not yet been scheduled. Valley Power Plant Title V Air Permit In February 2011, the WDNR renewed VAPP's Title V operating permit for five years . In March 2011, the Sierra Club petitioned the EPA for additional reductions and monitoring for particulate matter and revisions to certain applicable requirements. No timeline has been set by the EPA to respond to that petition. In May 2012, the Sierra Club filed a notice of intent to bring suit to force the EPA to issue a response to that petition. We believe that the permit was properly issued and that the plant is in compliance with all applicable regulations and standards. However, if as a result of this proceeding the permit is remanded to the WDNR, the plant will continue to operate under the previous operating permit. Weston Title V Air Permit In August 2013, the WDNR issued the Weston Title V air permit. In September 2013, WPS challenged various requirements in the permit by filing a contested case proceeding with the WDNR and also filed a Petition for Judicial Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also challenged various aspects of the permit. The WDNR granted all parties' requests for contested case proceedings. The Petitions for Judicial Review, by all parties, have been stayed pending the resolution of the contested cases. In February 2014, a new permit change was challenged and added to the case. The ALJ dismissed some of the petition issues relating to the averaging period and monitoring issues. In May 2014, the WDNR issued a Notice of Violation (NOV) alleging that WPS failed to maintain a minimum sorbent feed rate prior to the Continuous Emissions Monitoring System certification and included an issue related to reporting NOx emissions from the Weston Unit 4 auxiliary boiler. In June 2015, the WDNR issued a NOV alleging that WPS failed to comply with mercury reporting requirements related to challenged matters in the 2013 Weston Title V permit. The ALJ denied its request to issue a stay or confirm that a statutory stay applies to the requirements identified in the NOV. The contested case has been stayed for a period of months, and no hearing date has been set. We do not expect these matters to have a material impact on our financial statements. Solvay Coke and Gas Site In August 2004, Wisconsin Electric and Wisconsin Gas were identified as potentially responsible parties at the Solvay Coke and Gas Site located in Milwaukee, Wisconsin. A predecessor company of Wisconsin Electric owned a parcel of property that is within the property boundaries of the site. A predecessor company of Wisconsin Gas had a customer and corporate relationship with the entity that owned and operated the site. In 2007, Wisconsin Electric, Wisconsin Gas, and several other parties entered into an Administrative Settlement Agreement and Order with the EPA to perform additional investigation and assessment and reimburse the EPA's oversight costs. The final remedial investigation report was submitted to the EPA in December 2015, and work will now begin on the feasibility study. Under the Administrative Settlement Agreement, neither Wisconsin Electric nor Wisconsin Gas admits to any liability for the site, waives any liability defenses, or commits to perform future site remedial activities. The companies' share of the costs to perform the required work and reimburse the EPA's oversight costs, as well as potential future remediation cost estimates and reserves, are included in the estimated manufactured gas plant values reported above . 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 U.S. 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 . As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
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, 2015 (in millions) Level 1 Level 2 Level 3 Total Assets Derivative assets Natural gas contracts $ 1.6 $ 1.5 $ — $ 3.1 FTRs — — 3.6 3.6 Petroleum products contracts 1.2 — — 1.2 Coal contracts — 2.0 — 2.0 Total derivative assets $ 2.8 $ 3.5 $ 3.6 $ 9.9 Investments held in rabbi trust $ 39.8 $ — $ — $ 39.8 Liabilities 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 December 31, 2014 (in millions) Level 1 Level 2 Level 3 Total Assets Derivative assets Natural gas contracts $ 1.1 $ 3.9 $ — $ 5.0 FTRs — — 7.0 7.0 Coal contracts — 3.3 — 3.3 Total derivative assets $ 1.1 $ 7.2 $ 7.0 $ 15.3 Liabilities Derivative liabilities Natural gas contracts $ 11.5 $ 0.8 $ — $ 12.3 Coal contracts — 0.2 — 0.2 Total derivative liabilities $ 11.5 $ 1.0 $ — $ 12.5 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) 2015 2014 2013 Balance at the beginning of the period $ 7.0 $ 3.5 $ 4.7 Realized and unrealized gains 1.3 — — Purchases 3.9 15.6 10.6 Sales (0.1 ) — — Settlements (11.9 ) (12.1 ) (11.8 ) Acquisition of Integrys (1.3 ) — — Net transfers out of level 3 4.7 — — Balance at the end of the period $ 3.6 $ 7.0 $ 3.5 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 : 2015 2014 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 27.3 $ 30.4 $ 27.1 Long-term debt, including current portion * $ 9,221.9 $ 9,681.0 $ 4,510.3 $ 5,126.0 * Long-term debt excludes capital lease obligations.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS The following table shows our derivative assets and derivative liabilities: December 31, 2015 December 31, 2014 (in millions) Balance Sheet Presentation Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Natural gas Other current $ 2.6 $ 38.5 $ 5.0 $ 11.5 Natural gas Other long-term 0.5 3.3 — 0.8 Petroleum products Other current 0.9 3.8 — — Petroleum products Other long-term 0.3 1.1 — — FTRs Other current 3.6 — 7.0 — Coal Other current 1.7 6.7 2.7 0.2 Coal Other long-term 0.3 5.6 0.6 — Other current 8.8 49.0 14.7 11.7 Other long-term 1.1 10.0 0.6 0.8 Total $ 9.9 $ 59.0 $ 15.3 $ 12.5 Our estimated notional sales volumes and gains (losses) were as follows: December 31, 2015 December 31, 2014 December 31, 2013 (in millions) Volume Gains (Losses) Volume Gains Volume Gains (Losses) Natural gas 86.2 Dth $ (50.5 ) 40.5 Dth $ 7.3 48.6 Dth $ (8.5 ) Petroleum products 7.8 gallons (1.9 ) 9.2 gallons 0.5 8.6 gallons 0.5 FTRs 27.3 MWh 6.7 26.1 MWh 12.7 25.3 MWh 14.9 Total $ (45.7 ) $ 20.5 $ 6.9 The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2015 December 31, 2014 Derivative Derivative Derivative Derivative (in millions) Assets Liabilities Assets Liabilities Gross amount recognized on the balance sheet $ 9.9 $ 59.0 $ 15.3 $ 12.5 Gross amount not offset on the balance sheet * (3.0 ) (22.5 ) (0.4 ) (11.5 ) Net amount $ 6.9 $ 36.5 $ 14.9 $ 1.0 * Includes cash collateral posted of $19.5 million and $10.3 million as of December 31, 2015 and 2014 , respectively. As of December 31, 2015 and 2014 , we posted collateral of $42.3 million and $11.2 million , respectively, in our margin accounts. 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, 2015 was $23.8 million , and zero at December 31, 2014 . At December 31, 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, 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 payments 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 2015 , we reclassified $1.2 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, 2015
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities. We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal and 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, transmission-only company regulated by the FERC. 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 instead 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 sheet at December 31, 2015 included our equity investment and accounts payable. At December 31, 2015, our equity investment was $1,380.9 million , which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $28.3 million of accounts payable due to ATC at December 31, 2015 for network transmission services. Purchased Power Agreement We have identified a purchased power agreement that represents a variable interest. This agreement is for 236 MW of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately six years . We have examined the risks of the entity, including operations and 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 $130.5 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, 2015, 2014, and 2013 were $53.6 million , $53.0 million , and $50.3 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, 2015
Regulated Operations [Abstract]
REGULATORY ENVIRONMENT	REGULATORY ENVIRONMENT Wisconsin Electric Power Company 2015 Wisconsin Rate Order In May 2014, Wisconsin Electric 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 Wisconsin Electric's retail electric customers of approximately $2.7 million ( 0.1% ) in 2015. This amount reflects Wisconsin Electric's receipt of SSR payments from MISO that were higher than Wisconsin Electric 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 Wisconsin Electric 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 Wisconsin Electric'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 Wisconsin Electric's natural gas customers in 2015, with no rate adjustment in 2016. • A rate increase of approximately $0.5 million ( 2.0% ) for Wisconsin Electric'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 Wisconsin Electric's Milwaukee County steam utility customers in 2015, with no rate adjustment in 2016. The authorized ROE for Wisconsin Electric was set at 10.2% , and its common equity component remained at an average of 51% . The PSCW order reaffirmed the deferral of Wisconsin Electric'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 Wisconsin Electric, which includes 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 Wisconsin Electric will receive under the PIPP SSR agreements. Under escrow accounting, Wisconsin Electric will record SSR revenues from MISO of $90.7 million a year. If actual SSR payments from MISO exceed $90.7 million a year, the difference will be 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 will be deferred and 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 Wisconsin Electric'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 Wisconsin Electric'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 Wisconsin Electric. See Note 2, Acquisition, for more information on this earnings sharing mechanism. 2013 Wisconsin Rate Order In March 2012, Wisconsin Electric 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 Wisconsin Electric'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 Wisconsin Electric'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 Wisconsin Electric's natural gas customers in 2013, with no rate adjustment in 2014. The Wisconsin Electric rates reflect a $6.4 million reduction in bad debt expense. • An increase of approximately $1.3 million ( 6.0% ) for Wisconsin Electric'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 Wisconsin Electric's Milwaukee County steam utility customers. Based on the PSCW order, the authorized ROE for Wisconsin Electric 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 Oak Creek expansion 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, Wisconsin Gas 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 Wisconsin Gas's natural gas customers. These rate adjustments were effective January 1, 2015. The authorized ROE for Wisconsin Gas was set at 10.3% . The PSCW also authorized an increase in Wisconsin Gas'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 Wisconsin Gas . See Note 2, Acquisition, for more information on this earnings sharing mechanism. 2013 Wisconsin Rate Order In March 2012, Wisconsin Gas initiated a rate proceeding with the PSCW. In December 2012, the PSCW approved a rate decrease of approximately $34.0 million ( -5.5% ) for Wisconsin Gas’s natural gas customers in 2013, with no rate adjustment in 2014. The Wisconsin Gas rates reflect a $43.8 million reduction in bad debt expense. The rate adjustments were effective January 1, 2013, and the authorized ROE for Wisconsin Gas 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% ). Based on the order, the PSCW will continue to allow escrow treatment for ATC and MISO network transmission expenses, including any future SSR payments. This allows WPS to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates until a future rate proceeding. In addition, the PSCW approved a deferral for ReACT™, which requires WPS to defer the revenue requirement of ReACT™ costs above the authorized $275.0 million level through 2016. Fuel costs will continue to be monitored using a 2% tolerance window. 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 includes 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 is allowing WPS to escrow ATC and MISO network transmission expenses for 2015 and 2016. As a result, WPS defers as a regulatory asset or liability the differences 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 reflect a 10.2% ROE and a common equity component average of 50.48% . The increase reflects the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflects 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. Lastly, WPS will not seek an increase to 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 the AMRP. The Illinois Attorney General’s office is also conducting an inquiry into the same allegations. Since the investigations are ongoing, it is too early to determine what effect, if any, the investigations will have on the AMRP. In July 2015, we engaged a nationally recognized engineering and construction firm to conduct an independent, bottom up review of the AMRP's long-term cost, scope, and schedule. We filed the results of that review with the ICC on November 30, 2015. In November 2015, the ICC initiated an investigation into whether we, PGL, or Integrys knowingly misled or withheld material information from the ICC at its open meeting on May 20, 2015. The investigation relates to the ICC Staff's presentation of the independent audit findings reached for the AMRP. The Illinois Attorney General’s office is conducting an inquiry into this matter as well. It is too early to estimate the outcome of these inquiries since they are still ongoing. In December 2015, the ICC ordered a series of stakeholder workshops to evaluate the AMRP. This ICC action does not impact PGL's ongoing work to modernize and maintain the safety of its natural gas distribution system, but it instead provides the ICC with an opportunity to analyze long-term elements of the program through the stakeholder workshops. The workshops are expected to result in an ICC order with final and binding recommendations for the AMRP. Since the workshops only commenced in January 2016, we are currently unable to determine what, if any, long-term impact there will be on the AMRP. 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 reflect a 9.05% ROE and a common equity component average of 50.33% . The rates for NSG reflect 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. In February 2015, the Attorney General and certain intervenors filed requests for rehearing on certain issues, which the ICC denied in March 2015. No appeals were filed related to the rehearing requests. Minnesota Energy Resources Corporation 2016 Minnesota Rate Case In September 2015, MERC initiated a rate proceeding with the MPUC to increase retail natural gas rates $14.8 million ( 5.5% ). MERC's request reflects a 10.3% ROE and a common equity component average of 50.32% . The proposed retail natural gas rate increase is primarily driven by higher construction and capital expenditures, general inflation, and improvements to customer service programs. The request also includes increases in costs related to the acquisition of Alliant Energy Corporation's Minnesota natural gas operations in April 2015. MERC is requesting authority from the MPUC to continue the use of its currently authorized decoupling mechanism. In November 2015, the MPUC approved an interim rate order, effective January 1, 2016, authorizing a retail natural gas rate increase for MERC of $9.7 million ( 3.7% ). The interim rates reflect a 9.35% ROE and a common equity component average of 50.32% . The interim rate increase is subject to refund pending the final rate order. 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 reflect 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 will be requested in a future 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 is in effect in 2016, MGU is required to establish a regulatory liability for the resulting cost savings and must refund the liability in its next general rate case.

Michigan Settlement

Michigan Settlement	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
MICHIGAN SETTLEMENT	MICHIGAN SETTLEMENT In March 2015, we entered into an Amended and Restated Settlement Agreement with the Attorney General of the State of Michigan, the Staff of the MPSC, Tilden Mining Company, and Empire Iron Mining Partnership (Amended Agreement) to resolve all objections these parties raised with the MPSC related to our acquisition of Integrys. The agreement includes the following provisions: • The parties to the Amended Agreement agree that the acquisition satisfies the applicable requirements under Michigan law and should be approved by the MPSC. • Wisconsin Electric will not enter into an SSR agreement for the operation of PIPP so long as both mines, if operational, remain full requirements customers of Wisconsin Electric until the earlier of: (a) the date a new, clean generation plant located in the Upper Peninsula of Michigan commences commercial operation; or (b) December 31, 2019. The prior SSR agreement was terminated effective February 1, 2015, with the return of the mines as full requirements customers. • We commit to invest, either through an ownership interest or a purchased power agreement, or to have, if formed, our future Michigan jurisdictional utility invest, in a plant subject to the issuance of a Certificate of Necessity from the MPSC. The costs of this plant would be recovered from Michigan customers. In addition, in March 2015, Wisconsin Electric entered into a special contract with each of the mines to provide full requirements electric service through December 31, 2019. In April 2015, the MPSC approved our acquisition of Integrys, the Amended Agreement, and the special contracts with the two mines.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
SEGMENT INFORMATION	SEGMENT INFORMATION During the third quarter of 2015, following the acquisition of Integrys, we reorganized our business segments to reflect our new internal organization and management structure. All prior period amounts impacted by this change were reclassified to conform to the new presentation. We use operating income to measure segment profitability and to allocate resources to our businesses. At December 31, 2015 , we reported six segments, which are described below. • The Wisconsin segment includes the electric and natural gas utility and non-utility operations of Wisconsin Electric, Wisconsin Gas, and WPS, including Wisconsin Electric's electric and WPS's electric and natural gas operations in the state of Michigan. • The Illinois segment includes the natural gas utility and non-utility operations of NSG and PGL. • 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 federally regulated electric transmission company. • The We Power segment includes our nonregulated entity that owns and leases generating facilities to Wisconsin Electric. • The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, Wisvest, WECC, WBS, PDL, and ITF. All of our operations and assets are located within the United States. The following tables show summarized financial information concerning our reportable segments for the years ended December 31, 2015 , 2014 , and 2013 . 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 PTF activity between We Power and Wisconsin Electric. 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 PTF activity between We Power and Wisconsin Electric. Regulated Operations 2013 (in millions) Wisconsin Illinois Other States Electric Transmission Total Regulated Operations We Power Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated External revenues $ 4,451.9 $ — $ — $ — $ 4,451.9 $ 56.6 $ 10.5 $ — $ 4,519.0 Intersegment revenues 10.1 — — — 10.1 380.9 — (391.0 ) — Other operation and maintenance 1,522.0 — — — 1,522.0 4.6 14.2 (385.8 ) 1,155.0 Depreciation and amortization 272.2 — — — 272.2 66.3 1.6 — 340.1 Operating income 719.4 — — — 719.4 366.6 (5.9 ) — 1,080.1 Equity in earnings of transmission affiliate — — — 68.5 68.5 — — — 68.5 Interest expense 135.0 — — — 135.0 65.7 50.8 (0.6 ) 250.9 Capital expenditures 695.7 — — — 695.7 25.8 3.7 — 725.2 Total assets * 13,934.6 — — 402.7 14,337.3 2,814.6 213.6 (2,922.3 ) 14,443.2 * Total assets at December 31, 2013 reflect an elimination of $2,231.2 million for all PTF activity between We Power and Wisconsin Electric.

QUARTERLY FINANCIAL INFORMATION

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)	12 Months Ended
	Dec. 31, 2015
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 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 2014 Operating revenues $ 1,695.0 $ 1,043.7 $ 1,033.3 $ 1,225.1 $ 4,997.1 Operating income 381.8 240.7 246.1 243.5 1,112.1 Net income attributed to common shareholders 207.6 133.0 126.3 121.4 588.3 Earnings per share * Basic $ 0.92 $ 0.59 $ 0.56 $ 0.54 $ 2.61 Diluted 0.91 0.58 0.56 0.53 2.59 * 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, 2015
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. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our financial statements. Classification and Measurement of Financial Instruments In January 2016, the FASB issued ASU 2016-01, Classification and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. 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. We are currently assessing the effects this guidance may have on our financial statements.

Schedule I -- Condensed Parent

Schedule I -- Condensed Parent Company Financial Statements	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 2013 Operating expenses $ 42.2 $ 26.8 $ 5.5 Equity earnings from subsidiaries 695.7 635.0 607.8 Other income, net 23.2 2.8 3.1 Interest expense 71.2 53.1 54.4 Income before income taxes 605.5 557.9 551.0 Income tax benefit 33.0 30.4 26.4 Net income attributed to common shareholders $ 638.5 $ 588.3 $ 577.4 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) 2015 2014 2013 Net income attributed to common shareholders $ 638.5 $ 588.3 $ 577.4 Other comprehensive income, net of tax Derivatives accounted for as cash flow hedges Gains on settlement, net of tax of $7.6 11.4 — — Reclassification of gains to net income, net of tax (0.8 ) — — Cash flow hedges, net 10.6 — — Defined benefit plans Pension and OPEB costs arising during period, net of tax of $1.0 (1.5 ) — — Other comprehensive loss from subsidiaries, net of tax (4.8 ) — — Other comprehensive income, net of tax 4.3 — — Comprehensive income attributed to common shareholders $ 642.8 $ 588.3 $ 577.4 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) 2015 2014 Assets Current assets Cash and cash equivalents $ 1.3 $ 37.3 Accounts receivable from related parties 13.2 5.6 Notes receivable from related parties 123.2 32.2 Prepaid taxes and other 2.2 103.4 Total current assets 139.9 178.5 Investments in subsidiaries 10,792.6 4,917.8 Other long-term assets 254.0 280.7 Total long-term assets 11,046.6 5,198.5 Total assets $ 11,186.5 $ 5,377.0 Liabilities and equity Current liabilities Short-term debt $ 307.9 $ — Accounts payable to related parties 1.7 2.6 Notes payable to related parties 119.0 117.2 Accrued taxes 75.6 — Other 17.5 19.8 Total current liabilities 521.7 139.6 Long-term debt 1,887.2 695.5 Other long-term liabilities 122.8 122.2 Total long-term liabilities 2,010.0 817.7 Shareholders' equity 8,654.8 4,419.7 Total liabilities and shareholders' equity $ 11,186.5 $ 5,377.0 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) 2015 2014 2013 Operating activities Net income attributed to common shareholders $ 638.5 $ 588.3 $ 577.4 Reconciliation to net cash provided by operating activities Equity earnings from subsidiaries (695.7 ) (635.0 ) (607.8 ) Dividends from subsidiaries 538.8 720.0 720.4 Deferred income taxes 30.9 60.1 (7.8 ) Accrued income taxes, net 175.7 4.1 66.8 Change in – other current assets (9.3 ) (0.3 ) (2.8 ) Change in – other current liabilities (3.2 ) 5.1 (22.9 ) Other, net (18.4 ) (8.1 ) (21.6 ) Net cash provided by operating activities 657.3 734.2 701.7 Investing activities Business acquisition (1,486.2 ) — — Proceeds from asset sales 20.8 — — Capital contributions to subsidiaries (135.3 ) (225.5 ) (195.3 ) Change in short-term notes receivable from related parties (91.0 ) — — Other, net (0.1 ) 5.0 4.0 Net cash used for investing activities (1,691.8 ) (220.5 ) (191.3 ) Financing activities Exercise of stock options 30.1 50.3 48.5 Purchase of common stock (74.7 ) (123.2 ) (223.4 ) Dividends paid on common stock (455.4 ) (352.0 ) (328.9 ) Issuance of long-term debt 1,200.0 — — Change in short-term debt 307.9 (72.0 ) 5.0 Change in short-term notes payable to related parties 1.8 3.5 (26.8 ) Other, net (11.2 ) 16.7 14.6 Net cash provided by (used for) financing activities 998.5 (476.7 ) (511.0 ) Net change in cash and cash equivalents (36.0 ) 37.0 (0.6 ) Cash and cash equivalents at beginning of year 37.3 0.3 0.9 Cash and cash equivalents at end of year $ 1.3 $ 37.3 $ 0.3 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) 2015 2014 2013 Wisconsin Electric $ 240.0 $ 390.0 $ 340.0 Wisconsin Gas 30.0 33.0 33.0 We Power 262.8 297.0 347.4 ATC Holding LLC 6.0 — — Total $ 538.8 $ 720.0 $ 720.4 NOTE 3—LONG-TERM DEBT The following table shows the future maturities of our long-term debt outstanding as of December 31, 2015 : (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 us and WECC, 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 at December 31 : 2015 2014 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt $ 1,887.2 $ 1,900.7 $ 695.5 $ 770.0 The carrying value of cash and cash equivalents, net accounts 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 or similar issues or upon the quoted market prices of U.S. 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) 2015 2014 2013 Cash paid for interest $ 68.8 $ 44.4 $ 44.4 Cash received from income tax refunds 242.9 95.1 86.1 NOTE 5—SHORT-TERM NOTES RECEIVABLE – RELATED PARTIES The following table shows our outstanding short-term notes receivable from related parties as of December 31: (in millions) 2015 2014 Integrys $ 95.1 $ — Bostco 19.6 22.4 Wispark 8.5 9.8 Total $ 123.2 $ 32.2 NOTE 6—SHORT-TERM NOTES PAYABLE – RELATED PARTIES The following table shows our outstanding short-term notes payable to related parties as of December 31: (in millions) 2015 2014 WECC $ 108.4 $ 106.6 Wisvest 10.6 10.6 Total $ 119.0 $ 117.2

Schedule II - Valuation and Qua

Schedule II - Valuation and Qualifying Accounts (Notes)	12 Months Ended
	Dec. 31, 2015
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 the Period Acquisitions of Businesses Expense (1) Deferral Net Write-offs (2) Balance at End of the Period 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 December 31, 2013 $ 58.0 — 49.4 0.4 (46.8 ) $ 61.0 (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, 2015
Accounting Policies [Abstract]
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 Wisconsin Electric, Wisconsin Gas, and WPS, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin. Wisconsin Electric'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 Wisconsin Electric. • Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Bostco, Wisvest, WECC, WBS, PDL, and ITF.
Investments	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. 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. It holds investments that are classified as trading securities for accounting purposes. We do not intend to sell these investments in the near term. They are included in other investments on our balance sheet at December 31, 2015. The net unrealized loss included in earnings related to the investments held at the end of the period was not significant for the year ended December 31, 2015. 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.
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.
Reclassifications	On the income statements for the years ended December 31, 2014 and 2013, we reclassified $17.4 million and $48.0 million , respectively, from treasury grant to depreciation and amortization. We also reclassified $1.2 million from interest expense to preferred stock dividends of subsidiaries on the income statements for the years ended December 31, 2014 and 2013. These reclassifications were made to be consistent with the current year presentation on the income statements. During the fourth quarter of 2015, we early implemented ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. As a result, debt issuance costs of $15.7 million , previously reported as other long-term assets, were reclassified to offset long-term debt on the December 31, 2014 balance sheet. We also early implemented ASU 2015-17, Balance Sheet Classification of Deferred Taxes, during the fourth quarter of 2015. Since we adopted this ASU on a retrospective basis, we reclassified current deferred income taxes of $242.7 million , previously reported as a separate component of current assets, to offset long-term deferred income tax liabilities on the December 31, 2014 balance sheet. On the statements of cash flows for the years ended December 31, 2014 and 2013, we reclassified $2.4 million and $4.2 million , respectively, from depreciation and amortization to other operating activities. In addition, we reclassified $13.9 million and $22.8 million of nonqualified pension and OPEB contributions from other operating activities to contributions to pension and OPEB plans on the statements of cash flows for the years ended December 31, 2014 and 2013, respectively. Preferred stock dividends of subsidiaries of $1.2 million were also reclassified from other financing activities to net income on the statements of cash flows for the years ended December 31, 2014 and 2013. These reclassifications were made to be consistent with the current year presentation on the statements of cash flows. During the third quarter of 2015, following the acquisition of Integrys, we reorganized our business segments. All prior period amounts impacted by this change were reclassified to conform to the new presentation.
Cash and cash equivalents	Cash and cash equivalents include marketable debt securities acquired three months or less from maturity.
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 return on common equity than authorized by the PSCW. • Wisconsin Electric 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 , and Note 23, Michigan Settlement , 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 Wisconsin Electric and Wisconsin Gas, 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 AMRP 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 revenue. 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. ITF accounts for revenues from construction management projects using the percentage of completion method. Revenues are recognized based on the percentage of costs incurred to date compared to the total estimated costs of each contract. This method is used because management considers total costs to be the best available measure of progress on these contracts. See Note 3, Dispositions, for more information . 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 Wisconsin Electric, Wisconsin Gas, 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, 2015 . In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2015 .
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 Last-in, First-out (LIFO) cost method. Inventories stated on a LIFO basis represented approximately 18.0% of total inventories at December 31, 2015 . The estimated replacement cost of natural gas in inventory at December 31, 2015 , exceeded the LIFO cost by $15.2 million . In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $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.
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 revenue 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.
Property, plant, and equipment	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 OC 1 and OC 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. We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and capitalized interest. Utility property also includes AFUDC – Equity. 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.
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 Wisconsin Electric, WPS, and Wisconsin Gas. Approximately 50% of Wisconsin Electric's, WPS's, and Wisconsin Gas's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. For 2015, Wisconsin Electric's average AFUDC retail rate was 8.45% , and its average AFUDC wholesale rate was 1.72% . For the six months ended December 31, 2015, WPS's average AFUDC retail rate was 7.92% and its average AFUDC wholesale rate was 5.04% . For 2015, Wisconsin Gas's average AFUDC retail rate was 8.33% . 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 2015, 2014, or 2013.
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.
Goodwill	Our reporting units containing goodwill perform annual goodwill impairment tests during the third quarter of each year. 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 the PTF 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 the PTF 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. A 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 AROs are accreted to their present value each period using the credit-adjusted risk-free interest rate associated with the expected settlement dates of the AROs. This rate is determined when the obligation is 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.
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 18, Commitments and Contingencies, for more information . 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.
Stock-based compensation	In accordance with stockholder approved plans, we provide long-term incentives through our equity interests to our outside directors, officers, and other key employees. The plans provide for the granting of stock options, restricted stock awards, performance shares, and other share-based awards. Awards may be paid in common stock, cash, or a combination thereof. We recognize share-based compensation expense on a straight-line basis. Accordingly, for employee awards classified as equity awards, share-based compensation expense is measured based on the grant-date fair value of the award and is recognized as expense ratably over the requisite service period. 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 grant. There were no modifications to the terms of outstanding stock options during the year. 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: 2015 2014 2013 Non-qualified stock options granted 516,475 899,500 1,418,560 Estimated fair value per non-qualified stock option $ 5.29 $ 4.18 $ 3.45 Assumptions used to value the options: Risk-free interest rate 0.1% – 2.1% 0.1% – 3.0% 0.1% – 1.9% Dividend yield 3.7 % 3.8 % 3.7 % Expected volatility 18.0 % 18.0 % 18.0 % Expected forfeiture rate 2.0 % 2.0 % 2.0 % Expected life (years) 5.8 5.8 5.9 The risk-free interest rate is based on the U.S. Treasury interest rate with a term consistent with the expected life of the stock options. Dividend yield, expected volatility, expected forfeiture rate, and expected life assumptions are 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. During the vesting period, restricted share recipients also have voting rights and are entitled to dividends in the same manner as other shareholders. 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 stockholder return (stock price appreciation plus dividends) as compared to the total stockholder return of a peer group of companies over a three-year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance unit award. All grants are settled in cash and are accounted for as liability awards accordingly. We accrue compensation costs over the three-year performance period based on our estimate of the final expected value of the awards.
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 by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. Options to purchase 516,475 shares of common stock with an exercise price of $52.90 were outstanding at December 31, 2015 , but were not included in the computation of diluted earnings per share because they were anti-dilutive. All stock options outstanding during 2014 and 2013 were included in the computation of diluted earnings per share.
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, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a perpetual dividend discount model. The fair value of our long-term debt, including the current portion of long-term debt, but excluding capitalized leases, is estimated based upon the quoted market value for the same issue, similar issues, or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows. We conduct a thorough review of fair value hierarchy classifications on a quarterly basis.
Derivative instruments	We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators. We record derivative instruments on our balance sheets as an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. 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.
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, 2015
Accounting Policies [Abstract]
Schedule of inventory	Our inventory as of December 31 consisted of: (in millions) 2015 2014 Natural gas in storage $ 284.1 $ 124.8 Materials and supplies 219.2 150.2 Fossil fuel 183.7 125.6 Total $ 687.0 $ 400.6
Schedule of annual utility composite depreciation rates	Annual utility composite depreciation rates are shown below: Annual Utility Composite Depreciation Rates 2015 2014 2013 Wisconsin Electric 3.01% 2.93% 2.90% WPS (1) 1.30% N/A N/A Wisconsin Gas 2.36% 2.69% 2.68% PGL (1) 1.67% N/A N/A NSG (1) 1.22% N/A N/A MERC (1) 1.26% N/A N/A MGU (1) 1.32% N/A N/A (1) The rates shown for 2015 are for a partial year as a result of the acquisition of Integrys on June 29, 2015. The full year rate would be approximately double the rate shown.
Allowance for funds used during construction	Our regulated utilities recorded the following AFUDC for the years ended December 31: (in millions) 2015 2014 2013 AFUDC – Debt $ 8.6 $ 2.3 $ 7.7 AFUDC – Equity $ 20.1 $ 5.6 $ 18.3
Fair value of stock options	The following table shows the estimated fair value per stock option granted along with the weighted-average assumptions used in the valuation models: 2015 2014 2013 Non-qualified stock options granted 516,475 899,500 1,418,560 Estimated fair value per non-qualified stock option $ 5.29 $ 4.18 $ 3.45 Assumptions used to value the options: Risk-free interest rate 0.1% – 2.1% 0.1% – 3.0% 0.1% – 1.9% Dividend yield 3.7 % 3.8 % 3.7 % Expected volatility 18.0 % 18.0 % 18.0 % Expected forfeiture rate 2.0 % 2.0 % 2.0 % Expected life (years) 5.8 5.8 5.9

Acquisition (Tables)

Acquisition (Tables)	12 Months Ended
	Dec. 31, 2015
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 preliminary allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. The allocation is subject to change during the remainder of the measurement period, which ends one year from the acquisition date, as we obtain additional information, including with respect to certain regulatory and legal matters and the expected sale of ITF. (in millions) Current assets $ 1,069.9 Net property, plant, and equipment 7,091.8 Investments * 1,062.5 Goodwill 2,581.6 Deferred charges and other assets, excluding goodwill 1,737.9 Current liabilities, including current maturities of long-term debt (1,293.5 ) Deferred credits and other liabilities (3,668.5 ) Long-term debt (2,947.5 ) 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 severance expense was recorded in the following segments: (in millions) 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, 2015
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, 2015
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) 2015 2014 2013 Balance at beginning of period $ 424.1 $ 402.7 $ 378.3 Add: Earnings from equity method investment 96.1 66.0 68.5 Add: Capital contributions 8.7 13.1 10.5 Add: Acquisition of Integrys's investment in ATC 541.5 — — Add: Equity method goodwill from the acquisition of Integrys * 395.8 — — Less: Distributions received 85.1 57.5 54.5 Less: Other 0.2 0.2 0.1 Balance at end of period $ 1,380.9 $ 424.1 $ 402.7 * Represents the purchase price allocated to Integrys's investment in ATC in excess of the recorded value.
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) 2015 2014 2013 Charges to ATC for services and construction $ 15.4 $ 8.1 $ 9.0 Charges from ATC for network transmission services 289.2 231.4 234.2
Schedule of receivables and payables with ATC	As of December 31, 2015 and 2014 , our balance sheets included the following receivables and payables related to ATC: (in millions) 2015 2014 Accounts receivable Services provided to ATC $ 1.0 $ 0.6 Accounts payable Services received from ATC 28.3 19.3
Schedule of summarized income statement data for ATC	Summarized financial data for ATC is included in the tables below: (in millions) 2015 2014 2013 Income statement data Revenues $ 615.8 $ 635.0 $ 626.3 Operating expenses 319.3 307.4 295.0 Other expense 96.1 88.9 83.7 Net income $ 200.4 $ 238.7 $ 247.6
Schedule of summarized balance sheet data for ATC	(in millions) December 31, 2015 December 31, 2014 Balance sheet data Current assets $ 80.5 $ 66.4 Noncurrent assets 3,957.6 3,728.7 Total assets $ 4,038.1 $ 3,795.1 Current liabilities $ 330.3 $ 313.1 Long-term debt 1,800.0 1,701.0 Other noncurrent liabilities 245.0 163.8 Shareholders' equity 1,662.8 1,617.2 Total liabilities and shareholders' equity $ 4,038.1 $ 3,795.1

Supplemental Cash Flow Inform44

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	(in millions) 2015 2014 2013 Cash paid for interest, net of amount capitalized $ 329.6 $ 241.1 $ 250.4 Cash paid (received) for income taxes, net of refunds 9.3 22.0 (39.6 ) Significant non-cash transactions: Construction costs funded through accounts payable 177.1 1.8 4.7 Amortization of deferred revenue 39.9 55.7 56.5 Note receivable received related to the sale of AMP Trillium* 12.0 — — Capital assets received related to the sale of AMP Trillium * 6.3 — — * See Note 3, Dispositions, for more information .

Regulatory Assets and Liabili45

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 See Note Regulatory assets (1) (2) Unrecognized pension and OPEB costs (3) $ 1,306.4 $ 669.1 17 Environmental remediation costs (4) 697.0 45.9 18 Income tax related items (5) 248.3 176.0 Electric transmission costs (6) 191.5 146.0 AROs 173.0 17.6 9 SSR 86.1 — 22 Derivatives 70.4 14.7 1(t) Energy efficiency programs (7) 48.7 58.0 PTF (8) 45.4 66.6 Other, net 234.9 77.3 Total regulatory assets $ 3,101.7 $ 1,271.2 Balance Sheet Presentation Current assets (9) $ 37.1 $ — Regulatory assets 3,064.6 1,271.2 Total regulatory assets $ 3,101.7 $ 1,271.2 (1) Based on prior and current rate treatment, we believe it is probable that our utility subsidiaries will continue to recover from customers the regulatory assets in the table above. (2) As of December 31, 2015 , we had $33.8 million of regulatory assets not earning a return and $136.6 million of regulatory assets earning a return based on short-term interest rates. (3) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. (4) As of December 31, 2015 , we had not yet made cash expenditures for $628.2 million of these environmental remediation costs. The recovery of these costs depends on the timing of the actual expenditures. (5) Adjustments related to deferred income taxes. As the related temporary differences reverse, we prospectively collect taxes from customers for which deferred taxes were recorded in prior years. (6) Represents amounts recoverable from customers related to transmission costs incurred that exceed amounts authorized for recovery in our current rates. (7) Represents amounts recoverable from customers related to programs at the utility subsidiaries designed to meet energy efficiency standards. (8) Represents amounts recoverable from customers related to Wisconsin Electric's costs of the PTF units, including subsequent capital additions. (9) Short-term regulatory assets are recorded in accounts receivable and accrued 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) 2015 2014 See Note Regulatory liabilities Removal costs (1) $ 1,209.6 $ 741.1 Energy costs refundable through rate adjustments (2) 76.9 18.9 Uncollectible expense (3) 31.8 30.1 Mines deferral (4) 31.6 — Unrecognized pension and OPEB costs (5) 26.3 3.8 17 Other, net 49.8 36.7 Total regulatory liabilities $ 1,426.0 $ 830.6 Balance Sheet Presentation Other current liabilities $ 33.8 $ — Regulatory liabilities 1,392.2 830.6 Total regulatory liabilities $ 1,426.0 $ 830.6 (1) Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment. (2) Represents energy costs that will be refunded to customers in the future. (3) Represents amounts refundable to customers related to our uncollectible expense tracking mechanisms. These mechanisms allow us to recover or refund the difference between actual uncollectible write-offs and the amounts recovered in rates. (4) Represents the deferral of margins from the 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. (5) Represents the unrecognized future OPEB costs resulting from actuarial gains on OPEB plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan.

Property, Plant, and Equipment

Property, Plant, and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment [Table Text Block]	Property, plant, and equipment consisted of the following utility and non-utility and other assets at December 31: (in millions) 2015 2014 Utility property, plant, and equipment $ 22,803.7 $ 12,290.7 Less: Accumulated depreciation 7,358.2 4,044.6 Net 15,445.5 8,246.1 CWIP 672.7 170.1 Net utility property, plant, and equipment 16,118.2 8,416.2 Non-utility and other property, plant, and equipment 3,482.2 3,260.3 Less: Accumulated depreciation 560.9 440.5 Net 2,921.3 2,819.8 CWIP 150.2 21.7 Net non-utility and other property, plant, and equipment 3,071.5 2,841.5 Total property, plant, and equipment $ 19,189.7 $ 11,257.7

Jointly Owned Facilities (Table

Jointly Owned Facilities (Tables)	12 Months Ended
	Dec. 31, 2015
Jointly Owned Plant, Net Ownership Amount [Abstract]
Schedule of Jointly Owned Plants	Information related to jointly owned facilities at December 31, 2015 was as follows: We Power WPS (in millions, except for percentages and MWs) Oak Creek Expansion Units 1 and 2 Weston 4 Columbia Energy Center Units 1 and 2 Edgewater Unit 4 Ownership 83.34 % 70.0 % 31.8 % 31.8 % Share of rated capacity (MWs) * 1,056.8 374.5 352.9 96.3 In-service date 2010 and 2011 2008 1975 and 1978 1969 Property, plant, and equipment $ 2,359.6 $ 591.5 $ 404.6 $ 47.6 Accumulated depreciation $ (283.4 ) $ (150.5 ) $ (122.6 ) $ (30.6 ) CWIP $ 35.5 $ 5.9 $ 23.4 $ 0.4 * Based on expected capacity ratings for summer 2016. 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.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Change in Asset Retirement Obligations	The following table shows changes to our AROs: (in millions) 2015 2014 2013 Balance as of January 1 $ 43.6 $ 42.3 $ 44.3 Integrys subsidiaries 491.0 — — Accretion 14.5 2.4 2.4 Additions and revisions to estimated cash flows 35.5 * — — Liabilities settled (13.4 ) (1.1 ) (4.4 ) Balance as of December 31 $ 571.2 $ 43.6 $ 42.3 * An ARO of $16.1 million was recorded during 2015 for fly-ash landfills located at generation facilities owned by Wisconsin Electric and WPS. An ARO of $9.0 million was also recorded for the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule passed by the EPA in April 2015. See Note 18, Commitments and Contingencies, for more information on this rule. 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 and Other Intangible49

Goodwill and Other Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill [Table Text Block]	The following table shows changes to our goodwill balances by segment during the years ended December 31, 2015 and 2014 : Wisconsin Illinois Other States Total (in millions) 2015 2014 2015 2014 2015 2014 2015 2014 Balance as of January 1 Gross goodwill $ 441.9 $ 441.9 $ — $ — $ — $ — $ 441.9 $ 441.9 Accumulated impairment losses — — — — — — — — Net goodwill as of January 1 441.9 441.9 — — — — 441.9 441.9 Acquisition of Integrys 1,667.6 — 731.2 — 182.8 — 2,581.6 — Balance as of December 31 Gross goodwill 2,109.5 441.9 731.2 — 182.8 — 3,023.5 441.9 Accumulated impairment losses — — — — — — — — Net goodwill as of December 31 $ 2,109.5 $ 441.9 $ 731.2 $ — $ 182.8 $ — $ 3,023.5 $ 441.9
Schedule of Finite-Lived Intangible Assets [Table Text Block]	The identifiable intangible assets other than goodwill listed below are part of other long-term assets on our balance sheets. We had no material intangible assets other than goodwill at December 31, 2014. December 31, 2015 (in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Amortized intangible assets (1) $ 16.0 $ (7.8 ) $ 8.2 Unamortized intangible assets (2) 5.7 — 5.7 Total intangible assets $ 21.7 $ (7.8 ) $ 13.9 (1) Primarily relates to contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at WPS's Fox Energy Center. The remaining weighted-average amortization period for our amortized intangible assets at December 31, 2015 , was approximately three years . (2) Consists primarily of a trade name.

Common Equity (Tables)

Common Equity (Tables)	12 Months Ended
	Dec. 31, 2015
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 share-based compensation expense and the related tax benefit for the year ended December 31: (in millions) 2015 2014 2013 Stock options $ 3.3 $ 3.7 $ 3.9 Restricted stock 7.0 2.8 2.4 Performance units 13.0 15.4 12.7 Share-based compensation expense $ 23.3 $ 21.9 $ 19.0 Related tax benefit $ 9.3 $ 8.8 $ 7.6
Stock option activity	The following is a summary of our stock option activity during 2015 : 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, 2015 6,770,194 $ 29.99 Granted 516,475 $ 52.90 Exercised (1,302,005 ) $ 23.09 Outstanding as of December 31, 2015 5,984,664 $ 33.47 5.6 $ 107.6 Exercisable as of December 31, 2015 3,280,334 $ 26.84 3.9 $ 80.3
Restricted stock activity	The following restricted stock activity occurred during 2015 : Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding as of January 1, 2015 155,479 $ 38.45 Granted 143,107 $ 51.13 Released (68,429 ) $ 36.95 Forfeited (1,139 ) $ 46.26 Outstanding as of December 31, 2015 229,018 $ 46.78
Shares repurchased	The following table identifies shares purchased during the year ended December 31 : 2015 2014 2013 (in millions) Shares Cost Shares Cost Shares Cost Under share repurchase programs — $ — 0.4 $ 18.6 3.0 $ 126.0 To fulfill exercised stock options and restricted stock awards 1.5 74.7 2.3 104.6 2.4 97.4 Total 1.5 $ 74.7 2.7 $ 123.2 $ 5.4 $ 223.4
Dividends declared	During the year ended December 31, 2015 , our Board of Directors declared common stock dividends which are summarized below: Date Declared Date Payable Per Share Period January 15, 2015 March 1, 2015 $0.4225 First quarter April 16, 2015 June 1, 2015 $0.4225 Second quarter June 12, 2015 (1) July 6, 2015 (2) $0.2067 45 days through June 28, 2015 June 12, 2015 (1) September 1, 2015 (3) $0.2337 47 days through Aug. 14, 2015 October 15, 2015 December 1, 2015 $0.4575 Fourth quarter (1) Pro rata dividends were declared on June 12, 2015, in anticipation of closing the acquisition of Integrys. (2) The dividend payable on July 6, 2015, was based on a quarterly rate of $0.4225 per share. (3) The dividend payable on September 1, 2015, was based on our new quarterly rate of $0.4575 per share, which represents an 8.3% increase over the prior quarterly rate. Pursuant to the terms of the Merger Agreement, our Board of Directors adopted a new dividend policy.

Preferred Stock (Tables)

Preferred Stock (Tables)	12 Months Ended
	Dec. 31, 2015
Class of Stock Disclosures [Abstract]
Schedule of Stock by Class [Table Text Block]	The following table shows preferred stock authorized and outstanding at December 31, 2015 and 2014 : 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 — — $ — Wisconsin Electric $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 2014 (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 — — $ — Wisconsin Electric $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 — — — Total $ 30.4

Short-Term Debt and Lines of 52

Short-Term Debt and Lines of Credit (Tables)	12 Months Ended
	Dec. 31, 2015
Short-term Debt [Abstract]
Short-term notes payable balances and their corresponding weighted-average interest rates	Short-term notes payable balances and their corresponding weighted-average interest rates as of December 31 consist of: 2015 2014 (in millions, except percentages) Balance Balance Commercial paper Amount outstanding at December 31 $ 1,095.0 $ 617.6 Average interest rate on amounts outstanding at December 31 0.68 % 0.22 % Average amounts outstanding during the year * 817.8 468.1 * Based on daily outstanding balances during the year.
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 2015 WEC Energy Group December 2020 $ 1,050.0 Wisconsin Electric December 2020 500.0 WPS * December 2016 250.0 Wisconsin Gas 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 $ 18.0 Commercial paper outstanding 1,095.0 Available capacity under existing agreements $ 1,387.0 * WPS plans to request approval from the PSCW to extend the maturity through December 2020.

Long-Term Debt and Capital Le53

Long-Term Debt and Capital Lease Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Long-term Debt and Capital Lease Obligations [Abstract]
Long-term debt outstanding maturities and sinking fund requirements	The following table shows the future maturities and sinking fund requirements of our long-term debt outstanding (excluding obligations under capital leases) as of December 31, 2015 : (in millions) Payments 2016 $ 127.4 2017 154.5 2018 836.1 2019 357.7 2020 684.4 Thereafter 7,094.6 Total $ 9,254.7
Summary of capitalized leased facilities	The following is a summary of our capitalized leased facilities as of December 31: (in millions) 2015 2014 Long-term power purchase commitment $ 140.3 $ 140.3 Accumulated amortization (103.9 ) (98.3 ) Total leased facilities $ 36.4 $ 42.0
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, 2015 are as follows: (in millions) Payments 2016 $ 45.1 2017 13.9 2018 14.7 2019 15.5 2020 16.4 Thereafter 24.9 Total minimum lease payments 130.5 Less: Estimated executory costs (47.4 ) Net minimum lease payments 83.1 Less: Interest (23.2 ) Present value of net minimum lease payments 59.9 Less: Due currently (30.3 ) Long-term obligations under capital lease $ 29.6

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Summary of Income Tax Examinations [Table Text Block]	As of December 31, 2015, we were subject to examination by state or local tax authorities for the 2008 through 2015 tax years in our major state operating jurisdictions as follows: Jurisdiction Years Federal 2012–2015 Illinois 2008–2015 Michigan 2008–2015 Minnesota 2011–2015 Wisconsin 2011–2015
Summary of income tax expense	The following table is a summary of income tax expense for each of the years ended December 31: (in millions) 2015 2014 2013 Current tax expense $ 15.1 $ 33.6 $ 25.2 Deferred income taxes, net 420.4 329.2 313.8 Investment tax credit, net (1.7 ) (1.1 ) (1.1 ) Total income tax expense $ 433.8 $ 361.7 $ 337.9
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 U.S. statutory federal income tax rate to income before income taxes as a result of the following:	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 U.S. statutory federal income tax rate to income before income taxes as a result of the following: 2015 2014 2013 Effective Effective Effective (in millions) Amount Tax Rate Amount Tax Rate Amount Tax Rate Expected tax at statutory federal tax rates $ 375.5 35.0 % $ 332.5 35.0 % $ 320.3 35.0 % State income taxes net of federal tax benefit 73.1 6.8 % 50.5 5.3 % 49.0 5.3 % Production tax credits (17.4 ) (1.6 )% (17.4 ) (1.8 )% (16.7 ) (1.8 )% AFUDC – Equity (7.1 ) (0.7 )% (1.9 ) (0.2 )% (6.4 ) (0.7 )% Investment tax credit restored (1.7 ) (0.2 )% (1.1 ) (0.1 )% (1.1 ) (0.1 )% Treasury grant (1.7 ) (0.2 )% (3.8 ) (0.4 )% (7.4 ) (0.8 )% Other, net 13.1 1.3 % 2.9 0.2 % 0.2 — % Total income tax expense $ 433.8 40.4 % $ 361.7 38.0 % $ 337.9 36.9 %
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) 2015 2014 Deferred tax assets Future tax benefits $ 382.8 $ 221.7 Employee benefits and compensation 229.9 111.9 Deferred revenues 219.9 221.3 Property-related 59.5 28.8 Other 177.1 118.4 Total deferred tax assets 1,069.2 702.1 Valuation allowance (17.1 ) — Net deferred tax assets $ 1,052.1 $ 702.1 Deferred tax liabilities Property-related 4,451.5 2,750.4 Employee benefits and compensation 428.9 242.5 Investment in transmission affiliate 420.4 188.6 Deferred transmission costs 76.7 58.5 Other 296.9 126.1 Total deferred tax liabilities 5,674.4 3,366.1 Deferred tax liability, net $ 4,622.3 $ 2,664.0
Components of deferred tax assets associated with federal and state tax benefit carryforwards [Table Text Block]	The components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2015 and 2014 are summarized in the table below: 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 ) 2014 (in millions) Gross Value Deferred Tax Effect Valuation Allowance Earliest Year of Expiration Future tax benefits as of December 31, 2014 Federal net operating loss $ 416.2 $ 145.7 $ — 2029 Federal tax credit — 76.0 — 2029 Balance as of December 31, 2014 $ 416.2 $ 221.7 $ —
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) 2015 2014 Balance as of January 1 $ 7.2 $ 8.4 Acquired legacy Integrys unrecognized tax benefits 3.6 — Additions for tax positions of prior years 0.3 — Additions based on tax positions related to the current year 0.2 — Reductions for tax positions of prior years (1.1 ) (1.2 ) Settlements during the period (0.7 ) — Balance as of December 31 $ 9.5 $ 7.2

Guarantees (Tables)

Guarantees (Tables)	12 Months Ended
	Dec. 31, 2015
Guarantees [Abstract]
Schedule of outstanding guarantees	The following table shows our outstanding guarantees: Total Amounts Committed Expiration (in millions) at December 31, 2015 Less Than 1 Year 1 to 3 Years Over 3 Years Guarantees Guarantees supporting commodity transactions of subsidiaries (1) $ 174.5 $ 95.0 $ — $ 79.5 Standby letters of credit (2) 28.4 18.5 9.7 0.2 Surety bonds (3) 38.6 38.6 — — Other guarantees (4) 70.5 20.6 0.1 49.8 Total guarantees $ 312.0 $ 172.7 $ 9.8 $ 129.5 (1) Consists of (a) $5.0 million and $11.0 million to support the business operations of WBS and PDL, respectively; and (b) $117.6 million , $40.3 million , and $0.6 million related to natural gas supply at MERC, MGU, and ITF, respectively. These amounts are not reflected on our balance sheets. (2) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets. (3) Primarily for the construction and operation of CNG fueling stations by ITF, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets. (4) Consists of (a) $19.1 million to support PDL's future payment obligations related to its distributed solar generation projects, of which $6.6 million is covered by a reciprocal guarantee from a third party; (b) $20.0 million for an interconnection agreement between WPS and ATC; (c) $10.0 million related to the sale of a nonregulated retail marketing business previously owned by Integrys; (d) $11.2 million related to the performance of an operating and maintenance agreement by ITF; and (e) $10.2 million related to other indemnifications. The amounts discussed in items (a), (b) and (d) are not reflected on our balance sheets. An insignificant liability was recorded for item (c) related to the possible imposition of additional miscellaneous gross receipts tax in the event of a change in law or interpretation of the law. In addition, a liability of $9.6 million related to workers compensation coverage was recorded for item (e).

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 2015 2014 Change in benefit obligation Obligation at January 1 $ 1,505.5 $ 1,410.2 $ 397.7 $ 362.7 Obligation assumed from acquisition 1,594.0 — 493.0 — Service cost 30.4 10.1 20.7 8.5 Interest cost 94.3 68.1 26.7 17.8 Participant contributions — — 12.7 9.1 Plan amendments — — — (4.6 ) Actuarial loss (gain) 14.6 120.4 (74.0 ) 29.4 Benefit payments (156.0 ) (103.3 ) (36.2 ) (26.4 ) Federal subsidy on benefits paid N/A N/A 1.6 1.2 Plan curtailment 0.2 — (0.2 ) — Obligation at December 31 $ 3,083.0 $ 1,505.5 $ 842.0 $ 397.7 Change in fair value of plan assets Fair Value at January 1 $ 1,444.6 $ 1,451.0 $ 333.5 $ 327.6 Assets received from acquisition 1,420.9 — 442.1 — Actual return on plan assets (62.1 ) 88.5 (15.6 ) 17.7 Employer contributions 107.7 8.4 13.3 5.5 Participant contributions — — 12.7 9.1 Benefit payments (156.0 ) (103.3 ) (36.2 ) (26.4 ) Fair value at December 31 $ 2,755.1 $ 1,444.6 $ 749.8 $ 333.5
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) 2015 2014 2015 2014 Other long-term assets $ 74.1 $ 39.2 $ 50.1 $ 39.5 Pension and other postretirement benefit obligations * 402.0 100.1 142.3 103.7 Total net liabilities $ 327.9 $ 60.9 $ 92.2 $ 64.2 * 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 the pension plans for which we have an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2015 2014 Projected benefit obligation $ 1,706.6 $ 100.1 Accumulated benefit obligation 1,560.5 99.8
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 2016: (in millions) Pension Costs OPEB Costs Net actuarial loss $ 41.6 $ 1.9 Prior service costs 1.7 (1.2 ) Total 2016 – estimated amortization $ 43.3 $ 0.7
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) 2015 2014 2015 2014 Accumulated other comprehensive loss (pre-tax) (1) Net actuarial loss (gain) $ 11.4 $ — $ (0.6 ) $ — Total $ 11.4 $ — $ (0.6 ) $ — Net regulatory assets (2) Net actuarial loss $ 798.1 $ 622.7 $ 23.7 $ 44.1 Prior service costs (credits) 4.7 6.8 (3.3 ) (4.6 ) Total $ 802.8 $ 629.5 $ 20.4 $ 39.5 (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.
Schedule of the components of net periodic benefit cost	The components of net periodic benefit cost for the years ended December 31 are as follows: Pension Costs OPEB Costs (in millions) 2015 2014 2013 2015 2014 2013 Service cost $ 30.4 $ 10.1 $ 14.6 $ 20.7 $ 8.5 $ 10.0 Interest cost 94.3 68.1 60.4 26.7 17.8 15.6 Expected return on plan assets (155.6 ) (98.6 ) (95.8 ) (39.6 ) (23.7 ) (21.3 ) Plan curtailment (0.3 ) — — — — — Amortization of prior service cost (credit) 2.2 2.1 2.3 (6.4 ) (1.8 ) (2.0 ) Amortization of net actuarial loss 68.5 36.7 54.5 3.9 1.2 3.7 Settlement charge — — 2.5 — — — Net periodic benefit cost $ 39.5 $ 18.4 $ 38.5 $ 5.3 $ 2.0 $ 6.0
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 2015 2014 2015 2014 Discount rate 4.46% 4.15% 4.38% 4.20% Rate of compensation increase 4.00% 4.00% N/A N/A Assumed medical cost trend rate N/A N/A 7.50% 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 2015 2014 2013 Discount rate 4.11% 5.00% 4.10% Expected return on plan assets 7.37% 7.25% 7.25% Rate of compensation increase 4.0% 4.0% 4.0% OPEB Costs 2015 2014 2013 Discount rate 4.09% 4.95% 4.15% Expected return on plan assets 7.54% 7.50% 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, 2015, 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 $ 6.5 $ (5.3 ) Effect on health care component of the accumulated postretirement benefit obligations 79.4 (65.9 )
Investments recorded at fair value, by asset class	The following tables provide the fair values of our investments by asset class: 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 $ 45.8 $ — $ 62.8 $ 9.8 $ 1.3 $ — $ 11.1 Equity securities: U.S. Equity 524.1 291.0 — 815.1 146.4 136.3 — 282.7 International Equity 192.2 351.2 — 543.4 57.2 133.3 — 190.5 Fixed income securities: * U.S. Bonds 53.2 1,019.2 — 1,072.4 122.3 116.1 — 238.4 International Bonds 67.4 140.3 — 207.7 16.0 6.7 — 22.7 Private Equity and Real Estate — — 53.7 53.7 — — 4.4 4.4 Total $ 853.9 $ 1,847.5 $ 53.7 $ 2,755.1 $ 351.7 $ 393.7 $ 4.4 $ 749.8 * This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries. December 31, 2014 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 $ 6.4 $ — $ — $ 6.4 $ 1.4 $ — $ — $ 1.4 Equity securities: U.S. Equity 503.8 — — 503.8 146.0 — — 146.0 International Equity 128.6 29.8 — 158.4 42.2 2.5 — 44.7 Fixed income securities: * U.S. Bonds 42.5 599.3 — 641.8 3.5 112.4 — 115.9 International Bonds 79.3 43.3 — 122.6 17.5 7.0 — 24.5 Private Equity and Real Estate — — 11.6 11.6 — — 1.0 1.0 Total $ 760.6 $ 672.4 $ 11.6 $ 1,444.6 $ 210.6 $ 121.9 $ 1.0 $ 333.5 * This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. 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 (in millions) Pension OPEB Beginning balance at January 1, 2015 $ 11.6 $ 1.0 Realized and unrealized gains (losses) 1.8 0.1 Purchases 51.1 4.2 Liquidations (10.8 ) (0.9 ) Ending balance at December 31, 2015 $ 53.7 $ 4.4 Private Equity and Real Estate (in millions) Pension OPEB Beginning balance at January 1, 2014 $ — $ — Purchases 11.6 1.0 Ending balance at December 31, 2014 $ 11.6 $ 1.0
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 2016 $ 305.7 $ 48.4 2017 215.4 53.4 2018 211.9 52.2 2019 223.2 54.7 2020 224.9 57.1 2021-2025 1,105.2 307.0

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 , including those of our subsidiaries. Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2016 2017 2018 2019 2020 Later Years Electric utility: Purchased power 2027 $ 811.9 $ 110.1 $ 78.4 $ 74.9 $ 62.1 $ 62.4 $ 424.0 Coal supply and transportation 2019 608.7 310.2 177.4 110.0 11.1 — — Nuclear 2033 10,012.5 412.8 415.3 420.0 445.4 475.1 7,843.9 Natural gas utility supply and transportation 2028 1,244.6 331.6 263.6 200.1 159.3 115.2 174.8 Total $ 12,677.7 $ 1,164.7 $ 934.7 $ 805.0 $ 677.9 $ 652.7 $ 8,442.7
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) 2016 $ 9.8 2017 9.8 2018 9.0 2019 6.2 2020 5.7 Later years 66.6 Total $ 107.1
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) 2015 2014 Regulatory assets $ 697.0 $ 45.9 Reserves for future remediation 628.0 32.6

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 (in millions) Level 1 Level 2 Level 3 Total Assets Derivative assets Natural gas contracts $ 1.6 $ 1.5 $ — $ 3.1 FTRs — — 3.6 3.6 Petroleum products contracts 1.2 — — 1.2 Coal contracts — 2.0 — 2.0 Total derivative assets $ 2.8 $ 3.5 $ 3.6 $ 9.9 Investments held in rabbi trust $ 39.8 $ — $ — $ 39.8 Liabilities 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 December 31, 2014 (in millions) Level 1 Level 2 Level 3 Total Assets Derivative assets Natural gas contracts $ 1.1 $ 3.9 $ — $ 5.0 FTRs — — 7.0 7.0 Coal contracts — 3.3 — 3.3 Total derivative assets $ 1.1 $ 7.2 $ 7.0 $ 15.3 Liabilities Derivative liabilities Natural gas contracts $ 11.5 $ 0.8 $ — $ 12.3 Coal contracts — 0.2 — 0.2 Total derivative liabilities $ 11.5 $ 1.0 $ — $ 12.5
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) 2015 2014 2013 Balance at the beginning of the period $ 7.0 $ 3.5 $ 4.7 Realized and unrealized gains 1.3 — — Purchases 3.9 15.6 10.6 Sales (0.1 ) — — Settlements (11.9 ) (12.1 ) (11.8 ) Acquisition of Integrys (1.3 ) — — Net transfers out of level 3 4.7 — — Balance at the end of the period $ 3.6 $ 7.0 $ 3.5
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 : 2015 2014 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 27.3 $ 30.4 $ 27.1 Long-term debt, including current portion * $ 9,221.9 $ 9,681.0 $ 4,510.3 $ 5,126.0 * Long-term debt excludes capital lease obligations.

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative instruments in balance sheet	The following table shows our derivative assets and derivative liabilities: December 31, 2015 December 31, 2014 (in millions) Balance Sheet Presentation Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Natural gas Other current $ 2.6 $ 38.5 $ 5.0 $ 11.5 Natural gas Other long-term 0.5 3.3 — 0.8 Petroleum products Other current 0.9 3.8 — — Petroleum products Other long-term 0.3 1.1 — — FTRs Other current 3.6 — 7.0 — Coal Other current 1.7 6.7 2.7 0.2 Coal Other long-term 0.3 5.6 0.6 — Other current 8.8 49.0 14.7 11.7 Other long-term 1.1 10.0 0.6 0.8 Total $ 9.9 $ 59.0 $ 15.3 $ 12.5
Derivative instruments' estimated notional volumes and gain (losses)	Our estimated notional sales volumes and gains (losses) were as follows: December 31, 2015 December 31, 2014 December 31, 2013 (in millions) Volume Gains (Losses) Volume Gains Volume Gains (Losses) Natural gas 86.2 Dth $ (50.5 ) 40.5 Dth $ 7.3 48.6 Dth $ (8.5 ) Petroleum products 7.8 gallons (1.9 ) 9.2 gallons 0.5 8.6 gallons 0.5 FTRs 27.3 MWh 6.7 26.1 MWh 12.7 25.3 MWh 14.9 Total $ (45.7 ) $ 20.5 $ 6.9
Offsetting Assets and Liabilities	The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2015 December 31, 2014 Derivative Derivative Derivative Derivative (in millions) Assets Liabilities Assets Liabilities Gross amount recognized on the balance sheet $ 9.9 $ 59.0 $ 15.3 $ 12.5 Gross amount not offset on the balance sheet * (3.0 ) (22.5 ) (0.4 ) (11.5 ) Net amount $ 6.9 $ 36.5 $ 14.9 $ 1.0 * Includes cash collateral posted of $19.5 million and $10.3 million as of December 31, 2015 and 2014 , respectively.

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Schedule of information concerning our reportable segments	The following tables show summarized financial information concerning our reportable segments for the years ended December 31, 2015 , 2014 , and 2013 . 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 PTF activity between We Power and Wisconsin Electric. 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 PTF activity between We Power and Wisconsin Electric. Regulated Operations 2013 (in millions) Wisconsin Illinois Other States Electric Transmission Total Regulated Operations We Power Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated External revenues $ 4,451.9 $ — $ — $ — $ 4,451.9 $ 56.6 $ 10.5 $ — $ 4,519.0 Intersegment revenues 10.1 — — — 10.1 380.9 — (391.0 ) — Other operation and maintenance 1,522.0 — — — 1,522.0 4.6 14.2 (385.8 ) 1,155.0 Depreciation and amortization 272.2 — — — 272.2 66.3 1.6 — 340.1 Operating income 719.4 — — — 719.4 366.6 (5.9 ) — 1,080.1 Equity in earnings of transmission affiliate — — — 68.5 68.5 — — — 68.5 Interest expense 135.0 — — — 135.0 65.7 50.8 (0.6 ) 250.9 Capital expenditures 695.7 — — — 695.7 25.8 3.7 — 725.2 Total assets * 13,934.6 — — 402.7 14,337.3 2,814.6 213.6 (2,922.3 ) 14,443.2 * Total assets at December 31, 2013 reflect an elimination of $2,231.2 million for all PTF activity between We Power and Wisconsin Electric.

QUARTERLY FINANCIAL INFORMATI61

QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2015
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 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 2014 Operating revenues $ 1,695.0 $ 1,043.7 $ 1,033.3 $ 1,225.1 $ 4,997.1 Operating income 381.8 240.7 246.1 243.5 1,112.1 Net income attributed to common shareholders 207.6 133.0 126.3 121.4 588.3 Earnings per share * Basic $ 0.92 $ 0.59 $ 0.56 $ 0.54 $ 2.61 Diluted 0.91 0.58 0.56 0.53 2.59 * 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 Accoun62

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

Summary of Significant Accoun63

Summary of Significant Accounting Policies Reclassifications (Details) - Restatement Adjustment [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Income Statement Reclassification [Member]
Prior Period Income Statement Reclassification Treasury Grant	$ 17.4	$ 48
Prior Period Income Statement Reclassification Interest Expense	1.2	1.2
Balance Sheet Reclassification [Member]
Prior Period Balance Sheet Reclassification ASU 2015-03 Long-Term	15.7
Prior Period Balance Sheet Reclassification ASU 2015-17	242.7
Cash Flow Statement Reclassification [Member]
Prior Period Cash Flow Statement Reclassification Depreciation and Amortization	2.4	4.2
Prior Period Cash Flow Statement Reclassification Other Operating Activities	13.9	22.8
Prior Period Cash Flow Statement Reclassification Other Financing Activities	$ 1.2	$ 1.2

Summary of Significant Accoun64

Summary of Significant Accounting Policies Revenues and Customer Receivables (Details)	12 Months Ended
	Dec. 31, 2015customer
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
Threshold percentage of revenues from major customers	10.00%
Number of customers that account for more than 10% of revenues	0

Summary of Significant Accoun65

Summary of Significant Accounting Policies Materials, Supplies, and Inventories (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / Dekatherm	Dec. 31, 2014USD ($)
Inventory [Line Items]
Natural gas in storage	$ 284.1	$ 124.8
Materials and supplies	219.2	150.2
Fossil Fuel	183.7	125.6
Total	$ 687	$ 400.6
Percentage of LIFO Inventory	18.00%
PGL and NSG
Inventory [Line Items]
Excess of replacement or current costs over stated LIFO value	$ 15.2
Natural gas price benchmark | $ / Dekatherm	2.48

Summary of Significant Accoun66

Summary of Significant Accounting Policies Property, Plant and Equipment (Details)	6 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Wisconsin Electric
Public Utility, Property, Plant and Equipment [Line Items]
Annual utility composite depreciation rate (as a percent)		3.00%	3.00%	3.00%
WPS
Public Utility, Property, Plant and Equipment [Line Items]
Annual utility composite depreciation rate (as a percent)	1.00%
Wisconsin Gas
Public Utility, Property, Plant and Equipment [Line Items]
Annual utility composite depreciation rate (as a percent)		2.00%	3.00%	3.00%
PGL
Public Utility, Property, Plant and Equipment [Line Items]
Annual utility composite depreciation rate (as a percent)	1.67%
NSG
Public Utility, Property, Plant and Equipment [Line Items]
Annual utility composite depreciation rate (as a percent)	1.22%
MERC
Public Utility, Property, Plant and Equipment [Line Items]
Annual utility composite depreciation rate (as a percent)	1.26%
MGU
Public Utility, Property, Plant and Equipment [Line Items]
Annual utility composite depreciation rate (as a percent)	1.32%
Maximum | PWGS 1 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation over an estimated useful life		P45Y
Maximum | PWGS 2 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation over an estimated useful life		P45Y
Maximum | OC 1 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation over an estimated useful life		P55Y
Maximum | OC 2 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation over an estimated useful life		P55Y
Maximum | Software [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation over an estimated useful life		P15Y
Minimum | PWGS 1 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation over an estimated useful life		P10Y
Minimum | PWGS 2 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation over an estimated useful life		P10Y
Minimum | OC 1 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation over an estimated useful life		P10Y
Minimum | OC 2 [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation over an estimated useful life		P10Y
Minimum | Software [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation over an estimated useful life		P3Y

Summary of Significant Accoun67

Summary of Significant Accounting Policies AFUDC (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Allowance for Funds Used During Construction [Line Items]
AFUDC - Debt		$ 8.6	$ 2.3	$ 7.7
AFUDC - Equity		$ 20.1	$ 5.6	$ 18.3
Wisconsin Electric
Allowance for Funds Used During Construction [Line Items]
Percentage of retail jurisdictional construction work in progress expenditure subject to public utilities allowance for funds used during construction calculation		50.00%
Retail Operations [Member] | Wisconsin Electric
Allowance for Funds Used During Construction [Line Items]
Interest rate on accrued AFUDC		8.45%
Retail Operations [Member] | WPS
Allowance for Funds Used During Construction [Line Items]
Interest rate on accrued AFUDC	7.92%
Retail Operations [Member] | Wisconsin Gas
Allowance for Funds Used During Construction [Line Items]
Interest rate on accrued AFUDC		8.33%
Wholesale Operations [Member] | Wisconsin Electric
Allowance for Funds Used During Construction [Line Items]
Interest rate on accrued AFUDC		1.72%
Wholesale Operations [Member] | WPS
Allowance for Funds Used During Construction [Line Items]
Interest rate on accrued AFUDC	5.04%

Summary of Significant Accoun68

Summary of Significant Accounting Policies Stock-Based Compensation (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Minimum Exercise Price of Stock Option as a Percent of Common Stock Fair Value on the Grant Date	100.00%
Period during which stock options can't be exercised in the event of a change in control	6 months
Maximum term of awards	10 years
Non-qualified stock options granted	516,475	899,500	1,418,560
Estimated fair value per non-qualified stock option	$ 5.29	$ 4.18	$ 3.45
Risk-free interest rate, minimum	0.10%	0.10%	0.10%
Risk-free interest rate, maximum	2.10%	3.00%	1.90%
Dividend yield	3.70%	3.80%	3.70%
Expected volatility	18.00%	18.00%	18.00%
Expected forfeiture rate	2.00%	2.00%	2.00%
Expected life (years)	5 years 10 months	5 years 10 months	5 years 11 months
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock vesting period in years	3 years
Share Based Compensation Arrangement By Share Based Payment Award Award Percentage To Vest Each Year After Grant Date	33.00%
Performance units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance units, payout ratio	0.00%
Performance units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance units, payout ratio	175.00%

Summary of Significant Accoun69

Summary of Significant Accounting Policies Earnings Per Share (Details) - Stock options	12 Months Ended
	Dec. 31, 2015$ / sharesshares
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares	516,475
Exercise price of options that were anti-dilutive | $ / shares	$ 52.90

Acquisition Consideration Trans

Acquisition Consideration Transferred (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended
	Jun. 30, 2015	Dec. 31, 2015	Jun. 29, 2015	Dec. 31, 2014
Acquisition
Percentage of Integrys common shares acquired			100.00%
Integrys common shares outstanding at June 29, 2015		315,683,496		225,517,339
Exchange ratio	1.128
Wisconsin Energy Shares issued for Integrys shares	90,187,884
Number of Wisconsin Energy fractional shares that were paid in cash			10,483
Dollar value of Wisconsin Energy fractional shares paid in cash			$ 0.5
Closing price of Wisconsin Energy 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
ATC
Acquisition
Equity interest in ATC			60.00%
Integrys
Acquisition
Integrys common shares outstanding at June 29, 2015			79,963,091
Integrys | ATC
Acquisition
Equity interest in ATC			34.00%

Acquisition Purchase Price Allo

Acquisition Purchase Price Allocation (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Jun. 29, 2015
Business Combinations [Abstract]
Duration of the measurement period	1 year
Assets acquired
Current assets				$ 1,069.9
Net property, plant, and equipment				7,091.8
Investments				1,062.5
Goodwill	$ 2,581.6	$ 2,581.6	$ 0
Deferred charges and other assets, excluding goodwill				1,737.9
Liabilities assumed
Current liabilities, including current maturities of long-term debt				(1,293.5)
Deferred credits and other liabilities				(3,668.5)
Long-term debt				(2,947.5)
Preferred stock of subsidiary				$ (51.1)
Total purchase price	$ 5,583.1

Acquisition Approval Conditions

Acquisition Approval Conditions (Details)	1 Months Ended
	Jun. 30, 2015	Jun. 29, 2015
Wisconsin Electric
Acquisition
Duration of earnings cap condition imposed by the PSCW	3 years
Percentage of first 50 basis points to be shared with customers		50.00%
ROE in excess of authorized amount		0.005
Wisconsin Gas
Acquisition
Duration of earnings cap condition imposed by the PSCW	3 years
Percentage of first 50 basis points to be shared with customers		50.00%
ROE in excess of authorized amount		0.005
PGL
Acquisition
Duration of rate base freeze condition imposed by the ICC	2 years
NSG
Acquisition
Duration of rate base freeze condition imposed by the ICC	2 years

Acquisition Pro Forma Financial

Acquisition Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Business Combinations [Abstract]
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

Acquisition Impacts (Details)

Acquisition Impacts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jun. 29, 2015
Business Combinations [Abstract]
Acquisition costs	$ 107.6	$ 12.5	$ 0
Acquisition
Severance expense	24.9
Severance payments	16.9
Severance reserve	8
Revenue attributable to Integrys	1,416.8
Net income attributable to Integrys	65.9
ATC
Business Combinations [Abstract]
Equity interest in ATC				60.00%
Wisconsin
Acquisition
Severance expense	11.1
Illinois
Acquisition
Severance expense	0.9
Other States
Acquisition
Severance expense	0.1
Corporate and Other
Acquisition
Severance expense	$ 12.8

Dispositions (Details)

Dispositions (Details) - Corporate and Other - ITF - USD ($) $ in Millions	1 Months Ended
	Nov. 30, 2015	Dec. 31, 2015
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]
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
Sale of a joint interest in a compressed natural gas fueling business
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Variable interest entity ownership (as a percent)	30.00%

Investment in American Transm76

Investment in American Transmission Company - Changes to Investment in ATC (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jun. 29, 2015
Changes to investment in ATC
Equity in earnings of transmission affiliate		$ 96.1	$ 66	$ 68.5
Add: Equity method goodwill from the acquisition of Integrys	$ 2,581.6	$ 2,581.6	0
ATC
Investment in ATC
Equity method investment, ownership interest (as a percent)		60.00%			26.20%
Number of representatives on ATC's board of directors		1
Total number of members serving on ATC's board of directors		10
Number of votes that can be placed by each member on ATC's board of directors		1
Number of members on ATC's board of directors with more than 10% voting control		0
Voting control of each member on ATC's board of directors		10.00%
Changes to investment in ATC
Investment in ATC, balance at beginning of period		$ 424.1	402.7	378.3
Equity in earnings of transmission affiliate		96.1	66	68.5
Add: Capital contributions		8.7	13.1	10.5
Add: Acquisition of Integrys's investment in ATC		541.5	0	0
Add: Equity method goodwill from the acquisition of Integrys		395.8	0	0
Less: Distributions received		85.1	57.5	54.5
Less: Other		0.2	0.2	0.1
Investment in ATC, balance at end of period		$ 1,380.9	$ 424.1	$ 402.7

Investment in American Transm77

Investment in American Transmission Company - Transactions with ATC (Details) - ATC - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Investment in ATC
Charges to ATC for services and construction	$ 15.4	$ 8.1	$ 9
Charges from ATC for network transmission services	289.2	231.4	$ 234.2
Accounts receivable for services provided to ATC	1	0.6
Accounts payable for services received from ATC	$ 28.3	$ 19.3

Investment in American Transm78

Investment in American Transmission Company - ATC Summarized Financial Data (Details) - ATC - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income statement data
Revenues	$ 615.8	$ 635	$ 626.3
Operating expenses	319.3	307.4	295
Other expense	96.1	88.9	83.7
Net income	200.4	238.7	$ 247.6
Balance sheet data
Current assets	80.5	66.4
Noncurrent assets	3,957.6	3,728.7
Total assets	4,038.1	3,795.1
Current liabilities	330.3	313.1
Long-term debt	1,800	1,701
Other noncurrent liabilities	245	163.8
Shareholders' equity	1,662.8	1,617.2
Total liabilities and shareholders' equity	$ 4,038.1	$ 3,795.1

Supplemental Cash Flow Inform79

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]
Cash paid for interest, net of amount capitalized	$ 329.6	$ 241.1	$ 250.4
Cash paid for income taxes, net of refunds	9.3	22
Cash received for income taxes, net of refund			(39.6)
Construction costs funded through accounts payable	177.1	1.8	4.7
Amortization of deferred revenue	39.9	55.7	56.5
Note reveivable received related to the sale of AMP Trillium	12	0	0
Capital assets received related to the sale of AMP Trillium	6.3	$ 0	$ 0
Restricted cash	$ 118.4

Regulatory Assets and Liabili80

Regulatory Assets and Liabilities - Regulatory Assets (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets
Current assets	$ 37.1	$ 0
Long-term assets	3,064.6	1,271.2
Total Regulatory Assets	3,101.7	1,271.2
Other Disclosures
Remaining assets not earning a return	33.8
Regulatory assets earnings return based on short-term rates	136.6
Environmental remediation	628.2	32.6
Unrecognized pension and OPEB costs
Regulatory Assets
Total Regulatory Assets	1,306.4	669.1
Environmental remediation costs
Regulatory Assets
Total Regulatory Assets	697	45.9
Other Disclosures
Environmental remediation	628.2
Income tax related items
Regulatory Assets
Total Regulatory Assets	248.3	176
Electric transmission costs
Regulatory Assets
Total Regulatory Assets	191.5	146
Asset retirement obligations
Regulatory Assets
Total Regulatory Assets	173	17.6
SSR
Regulatory Assets
Total Regulatory Assets	86.1	0
Derivatives
Regulatory Assets
Total Regulatory Assets	70.4	14.7
Energy efficiency programs
Regulatory Assets
Total Regulatory Assets	48.7	58
PTF
Regulatory Assets
Total Regulatory Assets	45.4	66.6
Other, net
Regulatory Assets
Total Regulatory Assets	$ 234.9	$ 77.3

Regulatory Assets and Liabili81

Regulatory Assets and Liabilities - Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Regulatory Liabilities
Current liabilities	$ 33.8	$ 0
Long-term liabilities	1,392.2	830.6
Total regulatory liabilities	1,426	830.6
Removal costs
Regulatory Liabilities
Total regulatory liabilities	1,209.6	741.1
Energy costs refundable through rate adjustments
Regulatory Liabilities
Total regulatory liabilities	76.9	18.9
Uncollectible expense
Regulatory Liabilities
Total regulatory liabilities	31.8	30.1
Mines deferral
Regulatory Liabilities
Total regulatory liabilities	31.6	0
Unrecognized pension and OPEB costs
Regulatory Liabilities
Total regulatory liabilities	26.3	3.8
Other, net
Regulatory Liabilities
Total regulatory liabilities	$ 49.8	$ 36.7

Property, Plant, and Equipmen82

Property, Plant, and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Less: Accumulated depreciation	$ 7,919.1	$ 4,485.1
CWIP	822.9	191.8
Net Property, Plant and Equipment	19,189.7	11,257.7
Utility operations
Property, Plant and Equipment [Line Items]
Property, plant, and equipment	22,803.7	12,290.7
Less: Accumulated depreciation	7,358.2	4,044.6
Net	15,445.5	8,246.1
CWIP	672.7	170.1
Net Property, Plant and Equipment	16,118.2	8,416.2
Nonutility operations
Property, Plant and Equipment [Line Items]
Property, plant, and equipment	3,482.2	3,260.3
Less: Accumulated depreciation	560.9	440.5
Net	2,921.3	2,819.8
CWIP	150.2	21.7
Net Property, Plant and Equipment	$ 3,071.5	$ 2,841.5

Jointly Owned Facilities (Detai

Jointly Owned Facilities (Details) $ in Millions	Dec. 31, 2015USD ($)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) | MW	1,056.8
Property, plant, and equipment	$ 2,359.6
Accumulated depreciation	(283.4)
Construction Work in Progress	$ 35.5
Weston 4 | WPS
Jointly Owned Electric Generating Facilities
Ownership (as a percentage)	70.00%
Share of rated capacity (MWs) | MW	374.5
Property, plant, and equipment	$ 591.5
Accumulated depreciation	(150.5)
Construction Work in Progress	$ 5.9
Columbia Energy Center Units 1 and 2 | WPS
Jointly Owned Electric Generating Facilities
Ownership (as a percentage)	31.80%
Share of rated capacity (MWs) | MW	352.9
Property, plant, and equipment	$ 404.6
Accumulated depreciation	(122.6)
Construction Work in Progress	$ 23.4
Edgewater Unit 4 | WPS
Jointly Owned Electric Generating Facilities
Ownership (as a percentage)	31.80%
Share of rated capacity (MWs) | MW	96.3
Property, plant, and equipment	$ 47.6
Accumulated depreciation	(30.6)
Construction Work in Progress	$ 0.4

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Change in Asset Retirement Obligations
Balance as of January 1	$ 43.6	$ 42.3	$ 44.3
Integrys subsidiaries	491	0	0
Accretion	14.5	2.4	2.4
Additions and revisions to estimated cash flows	35.5	0	0
Liabilities settled	(13.4)	(1.1)	(4.4)
Balance as of December 31	571.2	$ 43.6	$ 42.3
AROs increase due to revisions to estimated cash flows	10.4
Coal combustion product landfill sites [Member]
Change in Asset Retirement Obligations
ARO additions	16.1
Hazardous and Solid Waste Management System Disposal of Coal Combustion Residuals [Member]
Change in Asset Retirement Obligations
ARO additions	$ 9

Goodwill and Other Intangible85

Goodwill and Other Intangible Assets - Goodwill (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Aug. 31, 2015	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014
Goodwill [Roll Forward]
Balance at the beginning of the period, gross goodwill			$ 441.9	$ 441.9
Balance at the beginning of the period, accumulated impairment losses			0	0
Balance at the beginning of the period, net goodwill			441.9
Goodwill		$ 2,581.6	2,581.6	0
Balance at the end of the period, gross goodwill			3,023.5	441.9
Balance at the end of the period, accumulated impairment losses			0	0
Balance at the end of the period, net goodwill			3,023.5	441.9
Goodwill, Impairment Loss	$ 0
Wisconsin
Goodwill [Roll Forward]
Balance at the beginning of the period, gross goodwill			441.9	441.9
Balance at the beginning of the period, accumulated impairment losses			0	0
Balance at the beginning of the period, net goodwill			441.9	441.9
Goodwill			1,667.6	0
Balance at the end of the period, gross goodwill			2,109.5	441.9
Balance at the end of the period, accumulated impairment losses			0	0
Balance at the end of the period, net goodwill			2,109.5	441.9
Illinois
Goodwill [Roll Forward]
Balance at the beginning of the period, gross goodwill			0	0
Balance at the beginning of the period, accumulated impairment losses			0	0
Balance at the beginning of the period, net goodwill			0	0
Goodwill			731.2	0
Balance at the end of the period, gross goodwill			731.2	0
Balance at the end of the period, accumulated impairment losses			0	0
Balance at the end of the period, net goodwill			731.2	0
Other States
Goodwill [Roll Forward]
Balance at the beginning of the period, gross goodwill			0	0
Balance at the beginning of the period, accumulated impairment losses			0	0
Balance at the beginning of the period, net goodwill			0	0
Goodwill			182.8	0
Balance at the end of the period, gross goodwill			182.8	0
Balance at the end of the period, accumulated impairment losses			0	0
Balance at the end of the period, net goodwill			$ 182.8	$ 0

Goodwill and Other Intangible86

Goodwill and Other Intangible Assets - Intangible Assets (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Contractual service agreements, accumulated amortization	$ (7.8)
Indefinite-Lived Intangible Assets (Excluding Goodwill)	5.7
Intangible Assets, Gross (Excluding Goodwill)	21.7
Intangible Assets, Net (Excluding Goodwill)	13.9
Service Agreements [Member]
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Contractual service agreements, gross carrying amount	16
Contractual service agreements, accumulated amortization	(7.8)
Contractual service agreements, net carrying amount	$ 8.2
Finite-Lived Intangible Assets, Remaining Amortization Period	3 years

Common Equity - Stock-Based Com

Common Equity - Stock-Based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation expense	$ 23.3	$ 21.9	$ 19
Related Tax Benefit	9.3	8.8	7.6
Stock options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation expense	3.3	3.7	3.9
Restricted stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation expense	7	2.8	2.4
Performance units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation expense	$ 13	$ 15.4	$ 12.7

Common Equity - Stock Options (

Common Equity - Stock Options (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Common Equity (Textuals)
Exercise of stock options		$ 30.1	$ 50.3	$ 48.5
Stock options
Stock option activity
Outstanding, Shares, Beginning Balance	5,984,664	6,770,194
Outstanding, Weighted-Average Exercise Price, Beginning	$ 33.47	$ 29.99
Granted, shares		516,475	899,500	1,418,560
Granted, Weighted-Average Exercise Price		$ 52.90
Exercised, shares		(1,302,005)
Exercised, Weighted Average Exercise Price		$ 23.09
Outstanding, Shares, Ending Balance		5,984,664	6,770,194
Outstanding, Weighted-Average Exercise Price, Ending		$ 33.47	$ 29.99
Outstanding, Weighted-Average Remaining Contractual Life (Years)		5 years 7 months
Outstanding, Aggregate Intrinsic Value		$ 107.6
Exercisable, shares		3,280,334
Exercisable, Weighted-Average Exercise Price		$ 26.84
Exercisable, Weighted-Average Remaining Contractual Life (Years)		3 years 11 months
Exercisable, Aggregate Intrinsic Value		$ 80.3
Common Equity (Textuals)
Intrinsic value of options exercised		36.1	$ 50.5	$ 44.5
Exercise of stock options		30.1	50.3	48.5
Actual tax benefit realized for the tax deductions from option exercises/settlement		14.5	$ 19.9	$ 17.8
Compensation cost not yet recognized		$ 1.5
Months, on a weighted-average basis, expected for recognizing total compensation costs related to non-vested stock options		19 months
2016 Compensation Committee award | Stock options
Stock option activity
Granted, shares	752,085
Granted, Weighted-Average Exercise Price	$ 51.80

Common Equity - Restricted Shar

Common Equity - Restricted Shares (Details) - Restricted stock - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding, beginning of period (in shares)	229,018	155,479
Granted (in shares)		143,107
Released (in shares)		(68,429)
Forfeited (shares)		(1,139)
Outstanding, end of period (in shares)		229,018	155,479
Outstanding, beginning of period (in dollars)	$ 46.78	$ 38.45
granted (in dollars)		51.13
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		36.95
Forfeited, weighted-average market price		46.26
Outstanding, end of period (in dollars)		$ 46.78	$ 38.45
Intrinsic value of released restricted shares		$ 3.7	$ 2.7	$ 4
Employee Service Share Based Compensation Tax Benefit Realized from Distribution of Shares		1.3	$ 1	$ 1.3
Compensation cost not yet recognized		$ 3.1
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition		20 months
2016 Compensation Committee award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	113,892

Common Equity - Performance Uni

Common Equity - Performance Units (Details) - Performance units - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		195,365	233,735	239,120
Intrinsic value of vested performance units		$ 13.2	$ 13.2	$ 14.8
Tax Benefit Realized From Payment of Share-Based Liabilities		4.5	$ 4.8	$ 5.3
Compensation cost not yet recognized		$ 11.8
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition		20 months
2016 Compensation Committee award
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	283,505

Common Equity - Dividend Restri

Common Equity - Dividend Restrictions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Dividend Payment Restrictions [Line Items]
Amount of Restricted Net Assets for Consolidated and Unconsolidated Subsidiaries	$ 6,200
Percentage of equity method investment exceeding consolidated net assets	25.00%
Wisconsin Electric
Dividend Payment Restrictions [Line Items]
Preferred Interest Rate	3.60%
Ability to declare common dividends limited to Percentage Of Net Income	75% or 50%
Maximum debt to capitalization ratio required to be maintained (as a percent)	65.00%
Wisconsin Electric | Maximum
Dividend Payment Restrictions [Line Items]
Percentage of common stockholders' equity to total capitalization required to be maintained	25.00%
Wisconsin Electric | Minimum
Dividend Payment Restrictions [Line Items]
Percentage of common stockholders' equity to total capitalization required to be maintained	20.00%
Wisconsin Electric | Minimum | Public Service Commission of Wisconsin [Member]
Dividend Payment Restrictions [Line Items]
Common equity ratio required to be maintained (as a percent)	51.00%
Wisconsin Gas | Minimum | Public Service Commission of Wisconsin [Member]
Dividend Payment Restrictions [Line Items]
Common equity ratio required to be maintained (as a percent)	49.50%
WPS
Dividend Payment Restrictions [Line Items]
Maximum debt to capitalization ratio required to be maintained (as a percent)	65.00%
WPS | Minimum | Public Service Commission of Wisconsin [Member]
Dividend Payment Restrictions [Line Items]
Common equity ratio required to be maintained (as a percent)	51.00%
Integrys
Dividend Payment Restrictions [Line Items]
Maximum debt to capitalization ratio required to be maintained (as a percent)	65.00%

Common Equity - Share Repurchas

Common Equity - Share Repurchase Program (Details) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Stock Repurchased During Period, Shares	1.5	2.7	5.4
Stock Repurchased During Period, Value	$ 74.7	$ 123.2	$ 223.4
Share Repurchase Plan, 2013
Class of Stock [Line Items]
Stock Repurchase Program, Authorized Amount	$ 300
Stock Repurchased During Period, Shares	0	0.4	3
Stock Repurchased During Period, Value	$ 0	$ 18.6	$ 126
Share Repurchases to Fulfill Exercised Stock Options and Restricted Stock Awards
Class of Stock [Line Items]
Stock Repurchased During Period, Shares	1.5	2.3	2.4
Stock Repurchased During Period, Value	$ 74.7	$ 104.6	$ 97.4

Common Equity - Integrys Acquis

Common Equity - Integrys Acquisition (Details) shares in Millions	1 Months Ended
	Jun. 30, 2015shares
Common Equity 7 [Abstract]
Wisconsin Energy Shares issued for Integrys shares	90.2

Common Equity - Common Stock Di

Common Equity - Common Stock Dividends (Details) - $ / shares	Oct. 15, 2015	Sep. 01, 2015	Jul. 06, 2015	Jun. 12, 2015	Apr. 16, 2015	Jan. 15, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Dividends Paid and Payable [Line Items]
Common Stock, Dividends, Per Share, Declared		$ 0.4575	$ 0.4225				$ 1.74	$ 1.56	$ 1.45
Dividend Increase Percentage			8.30%
Dividends declared January 15, 2015, payable March 1, 2015
Dividends Paid and Payable [Line Items]
Common Stock, Dividends, Per Share, Declared						$ 0.4225
Dividends declared April 16, 2015, payable June 1, 2015
Dividends Paid and Payable [Line Items]
Common Stock, Dividends, Per Share, Declared					$ 0.4225
Dividends declared June 12, 2015, payable July 6, 2015
Dividends Paid and Payable [Line Items]
Common Stock, Dividends, Per Share, Declared				$ 0.2067
Dividends declared June 12, 2015, payable September 1, 2015
Dividends Paid and Payable [Line Items]
Common Stock, Dividends, Per Share, Declared				$ 0.2337
Dividends declared October 15, 2015, payable December 1, 2015
Dividends Paid and Payable [Line Items]
Common Stock, Dividends, Per Share, Declared	$ 0.4575

Preferred Stock (Details)

Preferred Stock (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Nov. 13, 2015
Class of Stock [Line Items]
Preferred Stock, Value, Issued		$ 30.4	$ 30.4
WEC Energy Group | $.01 pare value Preferred Stock [Member]
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
Wisconsin Electric | Six Per Cent. Preferred Stock [Member]
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
Wisconsin Electric | Serial preferred stock, $100 par value; authorized 2,286,500 shares [Member] [Member]
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
Wisconsin Electric | Serial preferred stock, 3.60% Series Redeemable [Member]
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
Wisconsin Electric | Serial preferred stock, $25 par value; authorized 5,000,000 shares; none outstanding [Member]
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
Class of Stock [Line Items]
Mandatorily Redeemable Preferred Stock Shares				511,882
Preferred Stock Redemption Price				$ 52.7
WPS | $100 par value, Preferred Stock WPS [Member]
Class of Stock [Line Items]
Preferred Stock, Par or Stated Value Per Share		$ 100
Preferred Stock, Shares Authorized		1,000,000
Preferred Stock, Shares Outstanding		0
Preferred Stock, Value, Issued		$ 0
WPS | Preferred Stock Series 5.00 Percent [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.00%
Mandatorily Redeemable Preferred Stock Shares				131,916
WPS | Preferred Stock Series 5.04 Percent [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.04%
Mandatorily Redeemable Preferred Stock Shares				29,983
WPS | Preferred Stock Series 5.08 Percent [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.08%
Mandatorily Redeemable Preferred Stock Shares				49,983
WPS | Preferred Stock Series 6.76 Percent [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	6.76%
Mandatorily Redeemable Preferred Stock Shares				150,000
WPS | Preferred Stock Series 6.88 Percent [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	6.88%
Mandatorily Redeemable Preferred Stock Shares				150,000
PGL | $100 par value, Cumulative Preferred Stock PGL [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized		430,000
Preferred Stock, Shares Outstanding		0
Preferred Stock, Value, Issued		$ 0
NSG | $100 par value, Cumulative Preferred Stock NSG [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized		160,000
Preferred Stock, Shares Outstanding		0
Preferred Stock, Value, Issued		$ 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, 2015	Dec. 31, 2014
WEC Energy Group
Short-term Debt [Line Items]
Maximum Debt to Capitalization Ratio	70.00%
Wisconsin Electric
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%
Wisconsin Gas
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]
Short-term Debt Outstanding	$ 1,095	$ 617.6
Average interest rate on amount outstanding	0.68%	0.22%
Average amount outstanding during the year	$ 817.8	$ 468.1

Short-Term Debt and Lines of 97

Short-Term Debt and Lines of Credit - Credit Facilities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)extension	Dec. 31, 2014USD ($)
Line of Credit Facility [Line Items]
Short-term credit capacity	$ 2,500
Letters of Credit Issued Inside Credit Facilities	18
Available capacity under existing agreements	1,387
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
Wisconsin Electric | 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
Wisconsin Gas | 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]
Short-term Debt Outstanding	$ 1,095	$ 617.6

Long-Term Debt and Capital Le98

Long-Term Debt and Capital Lease Obligations (Details) $ in Millions	Sep. 01, 2015USD ($)	Feb. 29, 2016USD ($)	Dec. 31, 2015USD ($)	Nov. 30, 2015USD ($)	Jul. 31, 2015USD ($)	Jun. 30, 2015USD ($)	May. 31, 2015USD ($)	Dec. 31, 2015USD ($)Megawatt	Dec. 31, 2014USD ($)	Dec. 31, 2009USD ($)	Feb. 01, 2016USD ($)	Dec. 01, 2015	Aug. 01, 2015USD ($)
Long-term debt outstanding maturities and sinking fund requirements
2,016			$ 127.4					$ 127.4
2,017			154.5					154.5
2,018			836.1					836.1
2,019			357.7					357.7
2,020			684.4					684.4
Thereafter			7,094.6					7,094.6
Total			9,254.7					9,254.7
Summary of capitalized leased facilities
Long-term power purchase commitment			140.3					140.3	$ 140.3
Accumulated amortization			(103.9)					(103.9)	(98.3)
Total Leased Facilities			36.4					36.4	42
Future minimum lease payments under capital lease and present value of net minimum lease payments
Due next year			45.1					45.1
Due in two years			13.9					13.9
Due in three years			14.7					14.7
Due in four years			15.5					15.5
Due in five years			16.4					16.4
Thereafter			24.9					24.9
Total Minimum Lease Payments			130.5					130.5
Less: Estimated Executory Costs			(47.4)					(47.4)
Capital Leases Future Minimum Payments Due, Less Executory Costs			83.1					83.1
Less: Interest			(23.2)					(23.2)
Net Minimum Lease Payments			59.9					59.9
Less: Due Currently			(30.3)					(30.3)
Future minimum lease payments under our capital lease and the present value of our net minimum lease payments			$ 29.6					$ 29.6
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Number of series of tax-exempt pollution control refunding bonds			2					2
Period of Power purchase contract with an unaffiliated independent power producer								25 years
Power capacity from a gas-fired cogeneration facility under capital lease (MW) | Megawatt								236
Minimum energy requirement in gas-fired cogeneration facility								0
Power purchase contract expiration year								Dec. 31, 2022
Power purchase contract expected future renewable period								10 years
Total operating lease payment								$ 36.2	34.9
Increase in regulatory asset due to minimum lease payment										$ 78.5
Regulatory asset value at the end of life of contract								0
Total capital lease obligation			$ 59.9					59.9	84.5
Capital lease obligation at the end of life of contract								0
Common Stock, Value, Issued			3.2					3.2	2.3
Long-term Debt, Gross			$ 114.9					$ 114.9
WEC Senior Notes due June 15, 2018 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			1.65%					1.65%
WEC Senior Notes due June 15, 2020 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			2.45%					2.45%
WEC Senior Notes due June 15, 2025 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			3.55%					3.55%
Wis Elec Debenture due June 1, 2025 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			3.10%					3.10%
Wis Elec Debenture due December 15, 2045 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			4.30%					4.30%
Debentures (unsecured), 6.25% due 2015 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			6.25%					6.25%
Long Term Debt 7.125 Percent Series, Due 2023 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate				7.125%
Secured Debt				$ 0.1
Debt redemption price (percent)				100.00%
Senior Notes 6.375 Percent, Due 2015 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate												6.375%
Repayments of Debt			$ 125
Long Term Debt 1.65% Series, Due 2018 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			1.65%					1.65%				1.65%
Proceeds from Issuance of Debt			$ 250
Wis Gas Debenture due September 30, 2025 [Member] [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			3.53%					3.53%
Debentures (unsecured), 5.20% due 2015 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			5.20%					5.20%
Fixed First and Refunding Mortgage WW Series 2.625 Percent Bonds, Due 2033 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			1.875%					1.875%
Fixed First and Refunding Mortgage XX Series 2.21 Percent Bonds, Due 2016 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			2.21%					2.21%
Notes (secured, nonrecourse), 4.91% due 2015-2030 [Member] [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			4.91%					4.91%
Notes (secured, nonrecourse), 6.00% due 2015-2033 [Member] [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			6.00%					6.00%
Notes (secured, nonrecourse), 5.209% due 2015-2030 [Member] [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			5.209%					5.209%
Notes (secured, nonrecourse), 4.673% due 2015-2031 [Member] [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			4.673%					4.673%
Notes (secured, nonrecourse), 6.09% due 2030-2040 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			6.09%					6.09%
Notes (unsecured), 6.20% due 2033 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			6.20%					6.20%
Junior Notes (unsecured), 6.25% due 2067 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent			$ 500					$ 500
Debt instrument interest rate stated percentage rate			6.25%					6.25%
Debt Instrument, Basis Spread on Variable Rate								2.1125%
TEG Junior Subordinated Notes, 6.11% due 2066 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			6.11%					6.11%
Debt Instrument, Basis Spread on Variable Rate								2.12%
Unsecured Senior Notes 4.17 Percent, Due 2020 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			4.17%					4.17%
TEG Junior Subordinated Notes, 6.00% due 2073 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			6.00%					6.00%
Debt Instrument, Basis Spread on Variable Rate								3.22%
Integrys Holding Inc
Debt Instrument [Line Items]
Long-term Debt Assumed in Business Combination			$ 3,000					$ 3,000
Fair Value Adjustment to Long-term Debt						$ 46.2
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Maximum Debt to Capitalization Ratio								65.00%
Integrys Holding Inc | TEG Senior Notes due June 1, 2016 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			8.00%					8.00%
Long-term Debt, Current Maturities			$ 50					$ 50
Offer to buy back $55 million 8% Senior Note					$ 55
Extinguishment of Debt, Amount					$ 5
Integrys Holding Inc | TEG Junior Subordinated Notes, 6.11% due 2066 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent			269.8					269.8	0
Integrys Holding Inc | Unsecured Senior Notes 4.17 Percent, Due 2020 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent			250					250	0
Integrys Holding Inc | TEG Junior Subordinated Notes, 6.00% due 2073 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent			$ 400					$ 400	0
Debt instrument interest rate stated percentage rate			6.00%					6.00%
Long-term Debt, Gross			$ 400					$ 400
WEC Energy Group
Long-term debt outstanding maturities and sinking fund requirements
2,018			300					300
2,020			400					400
Thereafter			1,200					1,200
Total			1,900					$ 1,900
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Maximum Debt to Capitalization Ratio								70.00%
WEC Energy Group | WEC Senior Notes due June 15, 2018 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent			$ 300					$ 300	0
Debt instrument interest rate stated percentage rate			1.65%					1.65%
Proceeds from Issuance of Debt						300
WEC Energy Group | WEC Senior Notes due June 15, 2020 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent			$ 400					$ 400	0
Debt instrument interest rate stated percentage rate			2.45%					2.45%
Proceeds from Issuance of Debt						400
WEC Energy Group | WEC Senior Notes due June 15, 2025 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent			$ 500					$ 500	0
Debt instrument interest rate stated percentage rate			3.55%					3.55%
Proceeds from Issuance of Debt						$ 500
WEC Energy Group | Notes (unsecured), 6.20% due 2033 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent			$ 200					$ 200	200
Debt instrument interest rate stated percentage rate			6.20%					6.20%
WEC Energy Group | Junior Notes (unsecured), 6.25% due 2067 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent			$ 500					$ 500	500
Debt instrument interest rate stated percentage rate			6.25%					6.25%
Wisconsin Electric
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent			$ 147					$ 147
Maximum Debt to Capitalization Ratio								65.00%
Wisconsin Electric | Wis Elec Debenture due June 1, 2025 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent			$ 250					$ 250	0
Debt instrument interest rate stated percentage rate			3.10%					3.10%
Proceeds from Issuance of Debt							$ 250
Wisconsin Electric | Wis Elec Debenture due December 15, 2045 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent			$ 250					$ 250	0
Proceeds from Issuance of Debt				$ 250
Wisconsin Electric | Debentures (unsecured), 6.25% due 2015 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent			$ 0					$ 0	250
Debt instrument interest rate stated percentage rate			6.25%					6.25%
Repayments of Debt				$ 250
WPS
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Maximum Debt to Capitalization Ratio								65.00%
WPS | Long Term Debt 1.65% Series, Due 2018 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent			$ 250					$ 250	$ 0
Wisconsin Gas
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Maximum Debt to Capitalization Ratio								65.00%
Wisconsin Gas | Wis Gas Debenture due September 30, 2025 [Member] [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			3.53%					3.53%
Proceeds from Issuance of Debt	$ 200
Wisconsin Gas | Debentures (unsecured), 5.20% due 2015 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			5.20%					5.20%
Repayments of Debt			$ 125
PGL
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Maximum Debt to Capitalization Ratio								65.00%
PGL | Fixed First and Refunding Mortgage WW Series 2.625 Percent Bonds, Due 2033 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			2.625%					2.625%
Long-term Debt, Gross													$ 50
PGL | Fixed First and Refunding Mortgage XX Series 2.21 Percent Bonds, Due 2016 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			2.21%					2.21%
Long-term Debt, Current Maturities			$ 50					$ 50
We Power | Notes (secured, nonrecourse), 4.91% due 2015-2030 [Member] [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			4.91%					4.91%
Long-term Debt, Gross			$ 112.1					$ 112.1
Long-term Debt, Current Maturities			$ 5.4					$ 5.4
We Power | Notes (secured, nonrecourse), 6.00% due 2015-2033 [Member] [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			6.00%					6.00%
Long-term Debt, Gross			$ 130.5					$ 130.5
Long-term Debt, Current Maturities			$ 4.4					$ 4.4
We Power | Notes (secured, nonrecourse), 5.209% due 2015-2030 [Member] [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			5.209%					5.209%
Long-term Debt, Gross			$ 215					$ 215
Long-term Debt, Current Maturities			$ 10.2					$ 10.2
We Power | Notes (secured, nonrecourse), 4.673% due 2015-2031 [Member] [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate			4.673%					4.673%
Long-term Debt, Gross			$ 178.3					$ 178.3
Long-term Debt, Current Maturities			$ 7.4					$ 7.4
Subsequent event
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt Instrument, Repurchase Amount											$ 128.6
Subsequent event | TEG Junior Subordinated Notes, 6.11% due 2066 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Extinguishment of Debt, Amount		$ 154.9
Subsequent event | Integrys Holding Inc | TEG Junior Subordinated Notes, 6.11% due 2066 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate											6.11%
Common Stock Issued to WEC to satisfy obligation under RCC [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Common Stock, Value, Issued											$ 66.4

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
Deferred Tax Assets, Uncertainty in Income Taxes	$ 6.2	$ 7.2
Summary of income tax expense
Current tax expense (benefit)	15.1	33.6	$ 25.2
Deferred income taxes	420.4	329.2	313.8
Investment tax credit, net	(1.7)	(1.1)	(1.1)
Total Income Tax Expense, Amount	433.8	361.7	337.9
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 U.S. statutory federal income tax rate to income before income taxes as a result of the following:
Expected tax at statutory federal tax rates, Amount	$ 375.5	$ 332.5	$ 320.3
Expected tax at statutory federal tax rates, Effective Tax Rate	35.00%	35.00%	35.00%
State income taxes net of federal tax benefit, Amount	$ 73.1	$ 50.5	$ 49
State income taxes net of federal tax benefit, Effective Tax Rate	6.80%	5.30%	5.30%
Production tax credits, Amount	$ (17.4)	$ (17.4)	$ (16.7)
Production tax credits, Effective Tax Rate	(1.60%)	(1.80%)	(1.80%)
AFUDC - Equity, Amount	$ (7.1)	$ (1.9)	$ (6.4)
AFUDC - Equity, Effective Tax Rate	(0.70%)	(0.20%)	(0.70%)
Investment tax credit restored, Amount	$ (1.7)	$ (1.1)	$ (1.1)
Investment tax credit restored, Effective Tax Rate	(0.20%)	(0.10%)	(0.10%)
Effective Tax Rate Reconciliation, 1603 Grant, Amount	$ (1.7)	$ (3.8)	$ (7.4)
Effective Tax Rate Reconciliation, 1603 Grant, Percent	(0.20%)	(0.40%)	(0.80%)
Other, net, Amount	$ 13.1	$ 2.9	$ 0.2
Other, net, Effective Tax Rate	1.30%	0.20%	0.00%
Total Income Tax Expense, Amount	$ 433.8	$ 361.7	$ 337.9
Total Income Tax Expense, Effective Tax Rate	40.40%	38.00%	36.90%
Non-current
Deferred Tax Assets, Future Federal Tax Benefits, Non Current	$ 382.8	$ 221.7
Employee benefits and compensation	229.9	111.9
Deferred revenues	219.9	221.3
Property-related	59.5	28.8
Other	177.1	118.4
Deferred Tax Assets, Gross	1,069.2	702.1
Valuation Allowances and Reserves, Balance	(113.3)	(74.5)	$ (61)	$ (58)
Total Deferred Tax Assets	1,052.1	702.1
Non-current
Property-related	4,451.5	2,750.4
Employee benefits and compensation	428.9	242.5
Investment in transmission affiliate	420.4	188.6
Deferred transmission costs	76.7	58.5
Other	296.9	126.1
Deferred Tax Liabilities, Gross, Noncurrent	5,674.4	3,366.1
Reconciliation of the beginning and ending amount of unrecognized tax benefits
Balance, January 1	7.2	8.4
Acquired Legacy Integrys tax assets	3.6	0
Additions for tax positions of prior years	0.3	0
Additions based on tax positions related to the current year	0.2	0
Reductions for tax positions of prior years	1.1	1.2
Settlements during the period	0.7	0
Balance, December 31	9.5	7.2	8.4
Income Taxes (Textuals)
Valuation allowances related to the uncertainty of ability to benefit from state loss	17.1	0
Net amount of unrecognized tax benefits having impact on the effective tax rate for continuing operations	2.2	0
Accrued interest in the Consolidated Income Statements		0.3	$ 0.2
Accrued penalties in the Consolidated Income Statements	0
Accrued interest on the Consolidated Balance Sheets	0.7	0.7
Accrued penalties on the Consolidated Balance Sheets	0.1	0
Deferred Tax Liabilities, Net	4,622.3	2,664
Deferred Tax Asset [Domain]
Income Taxes [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, Domestic	412.3	416.2
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	0
Deferred Tax Assets, Tax Credit Carryforwards, Other	0
Deferred Tax Assets, Charitable Contribution Carryforwards	4.7
Deferred Tax Assets, Operating Loss Carryforwards	185.9
Tax Credit Carryforward, Amount	0	0
Income Taxes (Textuals)
Balance of Tax Benefit Carryforward	602.9	416.2
Deferred income tax related
Income Taxes [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, Domestic	144.3	145.7
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	15.2
Deferred Tax Assets, Tax Credit Carryforwards, Other	207.8
Deferred Tax Assets, Charitable Contribution Carryforwards	1.9
Deferred Tax Assets, Operating Loss Carryforwards	9.3
Tax Credit Carryforward, Amount	4.3	76
Income Taxes (Textuals)
Balance of Tax Benefit Carryforward	382.8	221.7
Valuation Allowance of Deferred Tax Assets [Member]
Income Taxes [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, Domestic	0	0
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	(15.2)
Deferred Tax Assets, Tax Credit Carryforwards, Other	0
Deferred Tax Assets, Charitable Contribution Carryforwards	(1.9)
Deferred Tax Assets, Operating Loss Carryforwards	0
Tax Credit Carryforward, Amount	0	0
Income Taxes (Textuals)
Balance of Tax Benefit Carryforward	$ (17.1)	$ 0

Guarantees (Details)

Guarantees (Details) $ in Millions	Dec. 31, 2015USD ($)
Guarantor Obligations [Line Items]
Total guarantees	$ 312
Guarantees expiring in less than one year	172.7
Guarantees expiring within one to three years	9.8
Guarantees with expiration over three years	129.5
Guarantees supporting commodity transactions of subsidiaries
Guarantor Obligations [Line Items]
Total guarantees	174.5
Guarantees expiring in less than one year	95
Guarantees expiring within one to three years	0
Guarantees with expiration over three years	79.5
Guarantees supporting commodity transactions of subsidiaries | WBS
Guarantor Obligations [Line Items]
Total guarantees	5
Guarantees supporting commodity transactions of subsidiaries | PDL
Guarantor Obligations [Line Items]
Total guarantees	11
Guarantees supporting commodity transactions of subsidiaries | ITF
Guarantor Obligations [Line Items]
Total guarantees	0.6
Guarantees supporting commodity transactions of subsidiaries | MERC
Guarantor Obligations [Line Items]
Total guarantees	117.6
Guarantees supporting commodity transactions of subsidiaries | MGU
Guarantor Obligations [Line Items]
Total guarantees	40.3
Standby letters of credit
Guarantor Obligations [Line Items]
Total guarantees	28.4
Guarantees expiring in less than one year	18.5
Guarantees expiring within one to three years	9.7
Guarantees with expiration over three years	0.2
Surety bonds
Guarantor Obligations [Line Items]
Total guarantees	38.6
Guarantees expiring in less than one year	38.6
Guarantees expiring within one to three years	0
Guarantees with expiration over three years	0
Other guarantees
Guarantor Obligations [Line Items]
Total guarantees	70.5
Guarantees expiring in less than one year	20.6
Guarantees expiring within one to three years	0.1
Guarantees with expiration over three years	49.8
Other guarantees | PDL
Guarantor Obligations [Line Items]
Total guarantees	19.1
Other guarantees | ITF
Guarantor Obligations [Line Items]
Total guarantees	11.2
Other guarantees | WPS
Guarantor Obligations [Line Items]
Total guarantees	20
Other guarantees | Integrys Holding Inc
Guarantor Obligations [Line Items]
Total guarantees	10
Reciprocal guarantee | PDL
Guarantor Obligations [Line Items]
Total guarantees	6.6
Other indemnification
Guarantor Obligations [Line Items]
Total guarantees	10.2
Liability related to workers compensation coverage	$ 9.6

EMPLOYEE BENEFIT PLANS - CHANGE

EMPLOYEE BENEFIT PLANS - CHANGE IN BENEFIT OBLIGATIONS AND PLAN ASSETS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Long-term liabilities	$ 543.1	$ 203.8
Pension Benefits
Change in benefit obligation
Obligation at January 1	1,505.5		$ 1,410.2
Obligation assumed from acquisition	1,594	0
Service cost	30.4	10.1	14.6
Interest cost	94.3	68.1	60.4
Participant contributions	0	0
Plan amendments	0	0
Actuarial loss (gain), net	14.6	120.4
Benefit payments	(156)	(103.3)
Plan curtailments	0.2	0
Obligation at December 31		1,505.5
Change in fair value of plan assets
Beginning balance at January 1	1,444.6		1,451
Assets received from acquisition	1,420.9	0
Actual return on plan assets	(62.1)	88.5
Employer contributions	107.7	8.4
Participant contributions	0	0
Benefit payments	(156)	(103.3)
Ending balance at December 31	2,755.1	1,444.6
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Long-term assets	74.1	39.2
Long-term liabilities	402	100.1
Total net assets (liabilities)	327.9	60.9
Benefit obligations held for sale	0.8
Accumulated benefit obligation	2,936.4	1,504.6
Information for pension plans with an accumulated benefit obligation in excess of plan assets
Projected benefit obligation	1,706.6	100.1
Accumulated benefit obligation	1,560.5	99.8
OPEB
Change in benefit obligation
Obligation at January 1	397.7		362.7
Obligation assumed from acquisition	493	0
Service cost	20.7	8.5	10
Interest cost	26.7	17.8	15.6
Participant contributions	12.7	9.1
Plan amendments	0	(4.6)
Actuarial loss (gain), net	(74)	29.4
Benefit payments	(36.2)	(26.4)
Federal subsidy on benefits paid	1.6	1.2
Plan curtailments	(0.2)	0
Obligation at December 31		397.7
Change in fair value of plan assets
Beginning balance at January 1	333.5		$ 327.6
Assets received from acquisition	442.1	0
Actual return on plan assets	(15.6)	17.7
Employer contributions	13.3	5.5
Participant contributions	12.7	9.1
Benefit payments	(36.2)	(26.4)
Ending balance at December 31	749.8	333.5
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Long-term assets	50.1	39.5
Long-term liabilities	142.3	103.7
Total net assets (liabilities)	92.2	$ 64.2
Benefit obligations held for sale	$ 0.4

EMPLOYEE BENEFIT PLANS - NET PE

EMPLOYEE BENEFIT PLANS - NET PERIODIC BENEFIT COST (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Net regulatory assets
Net actuarial losses	$ 798.1	$ 622.7
Prior service cost (credit)	4.7	6.8
Total	802.8	629.5
Net actuarial loss	41.6
Prior service costs (credits)	1.7
Total 2016 - estimated amortization	43.3
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)
Service cost	30.4	10.1	$ 14.6
Interest cost	94.3	68.1	60.4
Expected return on plan assets	(155.6)	(98.6)	(95.8)
Plan curtailment	(0.3)	0	0
Amortization of prior service cost (credit)	2.2	2.1	2.3
Amortization of net actuarial loss	68.5	36.7	54.5
Loss on plan settlement	0	0	2.5
Net periodic benefit cost	39.5	18.4	38.5
OPEB
Net regulatory assets
Net actuarial losses	23.7	44.1
Prior service cost (credit)	(3.3)	(4.6)
Total	20.4	39.5
Net actuarial loss	1.9
Prior service costs (credits)	(1.2)
Total 2016 - estimated amortization	0.7
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)
Service cost	20.7	8.5	10
Interest cost	26.7	17.8	15.6
Expected return on plan assets	(39.6)	(23.7)	(21.3)
Plan curtailment	0	0	0
Amortization of prior service cost (credit)	(6.4)	(1.8)	(2)
Amortization of net actuarial loss	3.9	1.2	3.7
Loss on plan settlement	0	0	0
Net periodic benefit cost	5.3	2	$ 6
Nonutility operations | Pension Benefits
Employee Benefit Plans
Net actuarial loss	11.4	0
Total	11.4	0
Nonutility operations | OPEB
Employee Benefit Plans
Net actuarial loss	(0.6)	0
Total	$ (0.6)	$ 0

EMPLOYEE BENEFIT PLANS - ASSUMP

EMPLOYEE BENEFIT PLANS - ASSUMPTIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Weighted average assumptions used
Discount rate	4.46%	4.15%
Rate of compensation increase	4.00%	4.00%
Discount rate	4.11%	5.00%	4.10%
Expected return on plan assets	7.37%	7.25%	7.25%
Rate of compensation increase	4.00%	4.00%	4.00%
Expected return on assets during next fiscal year	7.13%
OPEB
Weighted average assumptions used
Discount rate	4.38%	4.20%
Assumed medical cost trend rate (as a percent)	7.50%	7.50%	7.50%
Ultimate trend rate (as a percent)	5.00%	5.00%
Year ultimate trend rate is reached	2,021	2,021
Discount rate	4.09%	4.95%	4.15%
Expected return on plan assets	7.54%	7.50%	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	$ 6.5
Effect of one-percentage-point decrease on total of service and interest cost components of net periodic postretirement health care benefit cost	(5.3)
Effect of one-percentage-point increase on the health care component of the accumulated postretirement benefit obligation	79.4
Effect of one-percentage-point decrease on the health care component of the accumulated postretirement benefit obligation	$ (65.9)
OPEB | Under age 65
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%	45.00%
Wisconsin Energy | Pension Benefits | Fixed income securities:
Target asset allocations
Target asset allocations (as a percent)	55.00%	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%	70.00%
Integrys Holding Inc | Pension Benefits | Fixed income securities:
Target asset allocations
Target asset allocations (as a percent)	40.00%	30.00%
Integrys Holding Inc | OPEB | Equity securities:
Target asset allocations
Target asset allocations (as a percent)	70.00%
Integrys Holding Inc | OPEB | Fixed income securities:
Target asset allocations
Target asset allocations (as a percent)	30.00%

EMPLOYEE BENEFIT PLANS - PENSIO

EMPLOYEE BENEFIT PLANS - PENSION AND OTHER POSTRETIREMENT PLAN ASSETS (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets		$ 24.5
Pension Plan Assets
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	$ 2,755.1	1,444.6		$ 1,451
Pension Plan Assets | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	62.8	6.4
Pension Plan Assets | United states equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	815.1	503.8
Pension Plan Assets | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	543.4	158.4
Pension Plan Assets | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	1,072.4	641.8
Pension Plan Assets | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	207.7	122.6
Pension Plan Assets | Private Placement
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	53.7	11.6
Pension Plan Assets | Level 1
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	853.9	760.6
Pension Plan Assets | Level 1 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	17	6.4
Pension Plan Assets | Level 1 | United states equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	524.1	503.8
Pension Plan Assets | Level 1 | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	192.2	128.6
Pension Plan Assets | Level 1 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	53.2	42.5
Pension Plan Assets | Level 1 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	67.4	79.3
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	1,847.5	672.4
Pension Plan Assets | Level 2 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	45.8	0
Pension Plan Assets | Level 2 | United states equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	291	0
Pension Plan Assets | Level 2 | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	351.2	29.8
Pension Plan Assets | Level 2 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	1,019.2	599.3
Pension Plan Assets | Level 2 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	140.3	43.3
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	53.7	11.6
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	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	53.7	11.6	$ 0
OPEB Plan Assets
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	749.8	333.5		$ 327.6
OPEB Plan Assets | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	11.1	1.4
OPEB Plan Assets | United states equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	282.7	146
OPEB Plan Assets | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	190.5	44.7
OPEB Plan Assets | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	238.4	115.9
OPEB Plan Assets | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	22.7
OPEB Plan Assets | Private Placement
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	4.4	1
OPEB Plan Assets | Level 1
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	351.7	210.6
OPEB Plan Assets | Level 1 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	9.8	1.4
OPEB Plan Assets | Level 1 | United states equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	146.4	146
OPEB Plan Assets | Level 1 | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	57.2	42.2
OPEB Plan Assets | Level 1 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	122.3	3.5
OPEB Plan Assets | Level 1 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	16	17.5
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	393.7	121.9
OPEB Plan Assets | Level 2 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	1.3	0
OPEB Plan Assets | Level 2 | United states equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	136.3	0
OPEB Plan Assets | Level 2 | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	133.3	2.5
OPEB Plan Assets | Level 2 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	116.1	112.4
OPEB Plan Assets | Level 2 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	6.7	7
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	4.4	1
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	$ 4.4	$ 1	$ 0

EMPLOYEE BENEFIT PLANS - CHA105

EMPLOYEE BENEFIT PLANS - CHANGES IN THE FAIR VALUE OF PLAN ASSETS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	$ 1,444.6
Net realized and unrealized losses	(62.1)	$ 88.5
Ending balance at December 31	2,755.1	1,444.6
Pension Benefits | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	11.6
Ending balance at December 31	53.7	11.6
Pension Benefits | Private Placement
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	11.6
Ending balance at December 31	53.7	11.6
Pension Benefits | Private Placement | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	11.6	0
Net realized and unrealized losses	1.8
Purchases	51.1	11.6
Liquidations	(10.8)
Ending balance at December 31	53.7	11.6
OPEB
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	333.5
Net realized and unrealized losses	(15.6)	17.7
Ending balance at December 31	749.8	333.5
OPEB | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	1
Ending balance at December 31	4.4	1
OPEB | Private Placement
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	1
Ending balance at December 31	4.4	1
OPEB | Private Placement | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	1	0
Net realized and unrealized losses	0.1
Purchases	4.2	1
Liquidations	(0.9)
Ending balance at December 31	$ 4.4	$ 1

EMPLOYEE BENEFIT PLANS - DEFINE

EMPLOYEE BENEFIT PLANS - DEFINED CONTRIBUTION BENEFIT PLANS (Details) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2013	Mar. 31, 2015
Employee Benefit Plans
Employee Stock Ownership Plan (ESOP), Shares in ESOP	5.5
Employee Stock Ownership Plan (ESOP), Deferred Shares, Fair Value	$ 280.6
Defined Contribution Benefit Plans
Total costs incurred for defined contribution benefit plans	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	23.8
Expected payments, reflecting expected future service
2,016	305.7
2,017	215.4
2,018	211.9
2,019	223.2
2,020	224.9
2021 through 2025	1,105.2
OPEB
Employee Benefit Plans
Expected contributions to the plans during the next fiscal year	6.9
Expected payments, reflecting expected future service
2,016	48.4
2,017	53.4
2,018	52.2
2,019	54.7
2,020	57.1
2021 through 2025	$ 307

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions	Dec. 31, 2015USD ($)
Minimum future commitments for purchase obligations
Total Amounts Committed	$ 12,677.7
2,016	1,164.7
2,017	934.7
2,018	805
2,019	677.9
2,020	652.7
Later Years	8,442.7
Purchased power | Electric utility
Minimum future commitments for purchase obligations
Total Amounts Committed	811.9
2,016	110.1
2,017	78.4
2,018	74.9
2,019	62.1
2,020	62.4
Later Years	424
Coal supply and transportation | Electric utility
Minimum future commitments for purchase obligations
Total Amounts Committed	608.7
2,016	310.2
2,017	177.4
2,018	110
2,019	11.1
2,020	0
Later Years	0
Nuclear | Electric utility
Minimum future commitments for purchase obligations
Total Amounts Committed	10,012.5
2,016	412.8
2,017	415.3
2,018	420
2,019	445.4
2,020	475.1
Later Years	7,843.9
Natural gas supply and transportation | Natural gas utility
Minimum future commitments for purchase obligations
Total Amounts Committed	1,244.6
2,016	331.6
2,017	263.6
2,018	200.1
2,019	159.3
2,020	115.2
Later Years	$ 174.8

COMMITMENTS AND CONTINGENCIE108

COMMITMENTS AND CONTINGENCIES - OPERATING LEASES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Leases [Abstract]
Rental expense attributable to operating leases	$ 12.7	$ 4.8	$ 4
Minimum future payments under noncancelable operating leases
2,016	9.8
2,017	9.8
2,018	9
2,019	6.2
2,020	5.7
Later years	66.6
Total	$ 107.1

COMMITMENTS AND CONTINGENCIE109

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) T in Millions, $ in Millions	1 Months Ended							12 Months Ended
	Jan. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Aug. 31, 2014	Jun. 30, 2013USD ($)	Apr. 30, 2013	Mar. 31, 2013USD ($)	Feb. 28, 2011	Dec. 31, 2015USD ($)T	Dec. 31, 2014USD ($)T	Jun. 01, 2015USD ($)
Mercury and other hazardous air pollutants | Electric utility
Air Quality
Percentage mercury emission reduction required by the State of Wisconsin's mercury rule		90.00%						90.00%
Mercury and other hazardous air pollutants | Electric utility | Wisconsin Electric
Air Quality
Term of MATS compliance extension					1 year
Mercury and other hazardous air pollutants | Electric utility | WPS
Air Quality
Term of MATS compliance extension								1 year
Climate Change | Electric utility
Air Quality
Percentage greenhouse gas emission reduction nationwide								32.00%
Percentage greenhouse gas emission reduction for retirement of a nuclear plant								10.00%
Carbon dioxide emissions | T								31
Climate Change | Electric utility | Wisconsin Energy
Air Quality
Carbon dioxide emissions | T									23.3
Climate Change | Electric utility | Wisconsin
Air Quality
Percentage greenhouse gas emission reduction by state								41.00%
Climate Change | Electric utility | Michigan
Air Quality
Percentage greenhouse gas emission reduction by state								39.00%
Term of extension for Federal Plan and Model Trading Rule		2 years
Climate Change | Natural gas utility
Air Quality
Carbon dioxide emissions | T								27.1
Climate Change | Natural gas utility | Wisconsin Energy
Air Quality
Carbon dioxide emissions | T									10.8
Clean Water Act Cooling Water Intake Structure Rule | Electric utility
Water Quality
Number of compliance options available to meet standard			7
Steam Electric Effluent Guidelines | Electric utility | Subsequent event
Environmental Matters
Renewal period for facility permits	5 years
Steam Electric Effluent Guidelines | Electric utility | Minimum | Subsequent event
Water Quality
Expected environmental costs to achieve required emission reductions	$ 70
Steam Electric Effluent Guidelines | Electric utility | Maximum | Subsequent event
Water Quality
Expected environmental costs to achieve required emission reductions	$ 100
Renewables, Efficiency, and Conservation | Electric utility | Wisconsin
Renewables, Efficiency, and Conservation
Percent goal of electricity consumption		10.00%						10.00%
Percent of annual operating revenues								1.20%
Renewables, Efficiency, and Conservation | Electric utility | Wisconsin | Wisconsin Electric
Renewables, Efficiency, and Conservation
Renewable energy percent required		8.27%						8.27%
Renewables, Efficiency, and Conservation | Electric utility | Wisconsin | WPS
Renewables, Efficiency, and Conservation
Renewable energy percent required		9.74%						9.74%
Renewables, Efficiency, and Conservation | Electric utility | Michigan
Renewables, Efficiency, and Conservation
Percent goal of electricity consumption		10.00%						10.00%
Renewables, Efficiency, and Conservation | Electric utility | Maximum | Michigan
Renewables, Efficiency, and Conservation
Renewable energy percent required		1.00%						1.00%
Manufactured Gas Plant Remediation | Natural gas utility
Manufactured Gas Plant Remediation
Regulatory assets recorded for cash and estimated future remediation expenditures		$ 697						$ 697	$ 45.9
Liabilities estimated and accrued for future undiscounted investigation and cleanup costs for all sites		$ 628						$ 628	$ 32.6
Valley Power Plant | Electric utility | Wisconsin Electric
Environmental Matters
Renewal period for facility permits							5 years
Weston and Pulliam Consent Decree | Electric utility
Consent Decrees
Regulatory asset for undepreciated book value of retired plants										$ 11.5
Weston and Pulliam Consent Decree | Electric utility | WPS
Consent Decrees
Beneficial environmental project amount						$ 6
Civil penalty						$ 1.2
Joint Ownership Power Plants Consent Decree - Columbia and Edgewater | Electric utility | WPS
Consent Decrees
Beneficial environmental project amount				$ 1.3
Civil penalty				$ 0.4

Fair Value Measurements - Asse

Fair Value Measurements - Assets and liabilities measured on a recurring basis (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Assets
Derivative asset	$ 9.9	$ 15.3
Liabilities
Derivative liability	59	12.5
Fair value measurements on a recurring basis | Level 1
Assets
Derivative asset	2.8	1.1
Investment in exchange-traded funds	39.8
Liabilities
Derivative liability	21.4	11.5
Fair value measurements on a recurring basis | Level 2
Assets
Derivative asset	3.5	7.2
Investment in exchange-traded funds	0
Liabilities
Derivative liability	37.6	1
Fair value measurements on a recurring basis | Level 3
Assets
Derivative asset	3.6	7
Investment in exchange-traded funds	0
Liabilities
Derivative liability	0	0
Fair value measurements on a recurring basis | Total
Assets
Derivative asset	9.9	15.3
Investment in exchange-traded funds	39.8
Liabilities
Derivative liability	59	12.5
Fair value measurements on a recurring basis | Natural Gas | Level 1
Assets
Derivative asset	1.6	1.1
Liabilities
Derivative liability	16.5	11.5
Fair value measurements on a recurring basis | Natural Gas | Level 2
Assets
Derivative asset	1.5	3.9
Liabilities
Derivative liability	25.3	0.8
Fair value measurements on a recurring basis | Natural Gas | Level 3
Assets
Derivative asset	0	0
Liabilities
Derivative liability	0	0
Fair value measurements on a recurring basis | Natural Gas | Total
Assets
Derivative asset	3.1	5
Liabilities
Derivative liability	41.8	12.3
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	3.6	7
Fair value measurements on a recurring basis | FTRs | Total
Assets
Derivative asset	3.6	7
Fair value measurements on a recurring basis | Petroleum products | Level 1
Assets
Derivative asset	1.2
Liabilities
Derivative liability	4.9
Fair value measurements on a recurring basis | Petroleum products | Level 2
Assets
Derivative asset	0
Liabilities
Derivative liability	0
Fair value measurements on a recurring basis | Petroleum products | Level 3
Assets
Derivative asset	0
Liabilities
Derivative liability	0
Fair value measurements on a recurring basis | Petroleum products | Total
Assets
Derivative asset	1.2
Liabilities
Derivative liability	4.9
Fair value measurements on a recurring basis | Coal | Level 1
Assets
Derivative asset	0	0
Liabilities
Derivative liability	0	0
Fair value measurements on a recurring basis | Coal | Level 2
Assets
Derivative asset	2	3.3
Liabilities
Derivative liability	12.3	0.2
Fair value measurements on a recurring basis | Coal | Level 3
Assets
Derivative asset	0	0
Liabilities
Derivative liability	0	0
Fair value measurements on a recurring basis | Coal | Total
Assets
Derivative asset	2	3.3
Liabilities
Derivative liability	$ 12.3	$ 0.2

Fair Value Measurements - Level

Fair Value Measurements - Level 3 Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at the beginning of the period	$ 7	$ 3.5	$ 4.7
Realized and unrealized gains	1.3	0	0
Purchases	3.9	15.6	10.6
Sales	(0.1)	0	0
Settlements	(11.9)	(12.1)	(11.8)
Acquisition of Integrys	(1.3)	0	0
Net transfers out of level 3	4.7	0	0
Balance at the end of period	$ 3.6	$ 7	$ 3.5

Fair Value Measurements - Finan

Fair Value Measurements - Financial Instruments not recorded at fair value (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Carrying Value
Financial Instruments
Preferred stock	$ 30.4	$ 30.4
Long-term debt, including current portion	9,221.9	4,510.3
Fair Value
Financial Instruments
Preferred stock	27.3	27.1
Long-term debt, including current portion	$ 9,681	$ 5,126

Derivative Instruments (Details

Derivative Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivatives Fair Value [Line Items]
Other current derivative asset	$ 8.8	$ 14.7
Other current derivative liabilities	49	11.7
Other long-term derivative assets	1.1	0.6
Other long-term derivative Iiabilities	10	0.8
Derivative asset	9.9	15.3
Derivative liability	59	12.5
Gains (losses)	(45.7)	20.5	$ 6.9
Natural Gas
Derivatives Fair Value [Line Items]
Other current derivative asset	2.6	5
Other current derivative liabilities	38.5	11.5
Other long-term derivative assets	0.5	0
Other long-term derivative Iiabilities	$ 3.3	$ 0.8
Volume	86.2 Dth	40.5 Dth	48.6 Dth
Gains (losses)	$ (50.5)	$ 7.3	$ (8.5)
Petroleum products
Derivatives Fair Value [Line Items]
Other current derivative asset	0.9	0
Other current derivative liabilities	3.8	0
Other long-term derivative assets	0.3	0
Other long-term derivative Iiabilities	$ 1.1	$ 0
Volume	7.8 gallons	9.2 gallons	8.6 gallons
Gains (losses)	$ (1.9)	$ 0.5	$ 0.5
FTRs
Derivatives Fair Value [Line Items]
Other current derivative asset	3.6	7
Other current derivative liabilities	$ 0	$ 0
Volume	27.3 MWh	26.1 MWh	25.3 MWh
Gains (losses)	$ 6.7	$ 12.7	$ 14.9
Coal Contract
Derivatives Fair Value [Line Items]
Other current derivative asset	1.7	2.7
Other current derivative liabilities	6.7	0.2
Other long-term derivative assets	0.3	0.6
Other long-term derivative Iiabilities	$ 5.6	$ 0

Derivative Instruments - Notion

Derivative Instruments - Notional Volumes/Gains and Losses/ Offset Table/Swap (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	$ 19,500,000	$ 10,300,000
Collateral in margin accounts	42,300,000	11,200,000
Derivative, Net Liability Position, Aggregate Fair Value	23,800,000	0
Assets Needed for Immediate Settlement, Aggregate Fair Value	18,000,000
Debt Instrument, Face Amount	9,254,700,000
Derivative, Amount of Hedged Item	19,000,000
Reclassified from accumulated OCI into income	1,200,000
Reclassification within next 12 months	2,200,000
Total senior notes issued in June 2015 [Member]
Derivative [Line Items]
Debt Instrument, Face Amount	1,200,000,000
Derviative Instrument by Counterparty, Gross Amount Recognized on Balance Sheet [Member]
Derivative [Line Items]
Derivative Asset	9,900,000	15,300,000
Derivative Liability	59,000,000	12,500,000
Derviative Instrument by Counterparty, Gross Amount Not Offset on Balance Sheet [Member] [Member]
Derivative [Line Items]
Derivative Asset	3,000,000	400,000
Derivative Liability	22,500,000	11,500,000
Derviative Instrument by Counterparty, Net Amount [Member]
Derivative [Line Items]
Derivative Asset	6,900,000	14,900,000
Derivative Liability	$ 36,500,000	$ 1,000,000

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
ATC
Variable Interest Entity [Line Items]
Equity method investment, ownership interest (as a percent)	60.00%
Equity Method Investments	$ 1,380.9
Accounts payable for services received from ATC	$ 28.3
Purchased Power Agreement [Member]
Variable Interest Entity [Line Items]
Firm Capacity From Capital Lease Purchased Power Agreement | MW	236
Minimum Energy Requirements Capital Lease Purchased Power Agreement | MW	0
Remaining Term Of Capital Lease Purchased Power Agreement	6 years
Residual Guarantee Capital Lease Purchased Power Agreement	$ 0
Total payments over remaining terms of the two agreements	130.5
Total Capacity And Lease Payments For Capital Lease Purchased Power Agreement	$ 53.6	$ 53	$ 50.3

Regulatory Environment (Details

Regulatory Environment (Details) $ in Millions

1 Months Ended

12 Months Ended

Dec. 31, 2015USD ($)

Nov. 30, 2015USD ($)

Sep. 30, 2015USD ($)

Jun. 30, 2015

Apr. 30, 2015USD ($)

Mar. 31, 2015

Feb. 28, 2015USD ($)

Jan. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Oct. 31, 2014USD ($)

Dec. 31, 2012USD ($)

Dec. 31, 2015

Regulatory environment

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

2.00%

Wisconsin Electric | 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%

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

Regulatory environment

Approved annual rate increase (decrease)

$ 0

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

Regulatory environment

Approved annual rate increase (decrease)

0

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

Regulatory environment

Approved annual rate increase (decrease)

$ 0

Wisconsin Electric | 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%

Wisconsin Electric | 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

Wisconsin Electric | 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%

Wisconsin Electric | 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%)

Wisconsin Electric | 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%)

Wisconsin Electric | 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%

Wisconsin Electric | 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%

Wisconsin Electric | 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%)

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

Regulatory environment

Approved annual rate increase (decrease)

$ 0

Wisconsin Electric | 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%

Wisconsin Electric | 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%

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

Regulatory environment

Approved return on equity (as a percent)

10.40%

Wisconsin Electric | 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%

Wisconsin Electric | 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%

Wisconsin Electric | 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%

Wisconsin Electric | 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%)

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

Regulatory environment

Approved annual rate increase (decrease)

$ (6.4)

Wisconsin Electric | 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%

Wisconsin Electric | 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%

Wisconsin Gas | 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%

Wisconsin Gas | 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%

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

Regulatory environment

Approved annual rate increase (decrease)

$ 0

Wisconsin Gas | 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%

Wisconsin Gas | 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

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

Regulatory environment

Number of appeals filed related to rehearing requests

0

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

Requested annual rate increase (decrease)

$ 14.8

Requested annual rate increase (decrease), percentage

5.50%

Requested return on equity (as a percent)

10.30%

Requested common equity component average (as a percent)

50.32%

Interim rate increase

$ 9.7

Interim rate increase, percentage

3.70%

Interim return on equity (as a percent)

9.35%

Interim common equity component average (as a percent)

50.32%

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%

Segment Information (Details)

Segment Information (Details) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)segment	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Jun. 29, 2015
Segment information
Number of reportable segments | segment									6
Revenues	$ 1,848.3	$ 1,698.7	$ 991.2	$ 1,387.9	$ 1,225.1	$ 1,033.3	$ 1,043.7	$ 1,695	$ 5,926.1	$ 4,997.1	$ 4,519
Other operation and maintenance									1,709.3	1,112.4	1,155
Depreciation and amortization									561.8	391.4	340.1
Operating income (loss)	380.2	$ 345.7	$ 165.8	$ 358.8	243.5	$ 246.1	$ 240.7	$ 381.8	1,250.5	1,112.1	1,080.1
Equity in earnings of transmission affiliate									96.1	66	68.5
Interest expense									331.4	240.3	250.9
Capital expenditures									1,266.2	761.2	725.2
Total assets	$ 29,355.2				14,905				$ 29,355.2	14,905	14,443.2
ATC
Segment information
Equity method investment, ownership interest (as a percent)	60.00%								60.00%			26.20%
Equity in earnings of transmission affiliate									$ 96.1	66	68.5
Intersegment revenues
Segment information
Revenues									0	0	0
We Power
Segment information
Revenues									40	55.7	56.6
Other operation and maintenance									4.3	4.4	4.6
Depreciation and amortization									67.5	66.7	66.3
Operating income (loss)									373.4	368	366.6
Equity in earnings of transmission affiliate									0	0	0
Interest expense									63.4	64.6	65.7
Capital expenditures									53.4	41	25.8
Total assets	$ 2,779				2,789.9				2,779	2,789.9	2,814.6
We Power | Intersegment revenues
Segment information
Revenues									405.2	383.4	380.9
Corporate and other
Segment information
Revenues									47.3	9.3	10.5
Other operation and maintenance									103.7	33	14.2
Depreciation and amortization									12.4	1.5	1.6
Operating income (loss)									(91.2)	(26.1)	(5.9)
Equity in earnings of transmission affiliate									0	0	0
Interest expense									91	48.8	50.8
Capital expenditures									33.4	5.2	3.7
Total assets	1,132.5				253.3				1,132.5	253.3	213.6
Corporate and other | Intersegment revenues
Segment information
Revenues									0	0	0
Reconciling eliminations
Segment information
Revenues									0	0	0
Other operation and maintenance									(409.3)	(387.7)	(385.8)
Depreciation and amortization									0	0	0
Operating income (loss)									0	0	0
Equity in earnings of transmission affiliate									0	0	0
Interest expense									(5.1)	(0.7)	(0.6)
Capital expenditures									0	0	0
Total assets	(3,431.7)				(2,966.1)				(3,431.7)	(2,966.1)	(2,922.3)
Reconciling eliminations | Wisconsin Electric
Segment information
Total assets	2,105.3				2,172.9				2,105.3	2,172.9	2,231.2
Reconciling eliminations | Intersegment revenues
Segment information
Revenues									(410.2)	(392.6)	(391)
Regulated operations
Segment information
Revenues									5,838.8	4,932.1	4,451.9
Other operation and maintenance									2,010.6	1,462.7	1,522
Depreciation and amortization									481.9	323.2	272.2
Operating income (loss)									968.3	770.2	719.4
Equity in earnings of transmission affiliate									96.1	66	68.5
Interest expense									182.1	127.6	135
Capital expenditures									1,179.4	715	695.7
Total assets	28,875.4				14,827.9				28,875.4	14,827.9	14,337.3
Regulated operations | Intersegment revenues
Segment information
Revenues									5	9.2	10.1
Regulated operations | Wisconsin
Segment information
Revenues									5,186.1	4,932.1	4,451.9
Other operation and maintenance									1,741	1,462.7	1,522
Depreciation and amortization									408.6	323.2	272.2
Operating income (loss)									884.2	770.2	719.4
Equity in earnings of transmission affiliate									0	0	0
Interest expense									157.1	127.6	135
Capital expenditures									950.3	715	695.7
Total assets	21,113.5				14,403.8				21,113.5	14,403.8	13,934.6
Regulated operations | Wisconsin | Intersegment revenues
Segment information
Revenues									5	9.2	10.1
Regulated operations | Illinois
Segment information
Revenues									503.4	0	0
Other operation and maintenance									219.6	0	0
Depreciation and amortization									63.3	0	0
Operating income (loss)									78.1	0	0
Equity in earnings of transmission affiliate									0	0	0
Interest expense									19.9	0	0
Capital expenditures									194.4	0	0
Total assets	5,462.9				0				5,462.9	0	0
Regulated operations | Illinois | Intersegment revenues
Segment information
Revenues									0	0	0
Regulated operations | Other States
Segment information
Revenues									149.3	0	0
Other operation and maintenance									50	0	0
Depreciation and amortization									10	0	0
Operating income (loss)									6	0	0
Equity in earnings of transmission affiliate									0	0	0
Interest expense									5.1	0	0
Capital expenditures									34.7	0	0
Total assets	918				0				918	0	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									96.1	66	68.5
Interest expense									0	0	0
Capital expenditures									0	0	0
Total assets	$ 1,381				$ 424.1				1,381	424.1	402.7
Regulated operations | Electric transmission | Intersegment revenues
Segment information
Revenues									$ 0	$ 0	$ 0

QUARTERLY FINANCIAL INFORMAT118

QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information [Abstract]
Operating revenues	$ 1,848.3	$ 1,698.7	$ 991.2	$ 1,387.9	$ 1,225.1	$ 1,033.3	$ 1,043.7	$ 1,695	$ 5,926.1	$ 4,997.1	$ 4,519
Operating Income (Loss)	380.2	345.7	165.8	358.8	243.5	246.1	240.7	381.8	1,250.5	1,112.1	1,080.1
Net income attributed to common shareholders	$ 179.3	$ 182.5	$ 80.9	$ 195.8	$ 121.4	$ 126.3	$ 133	$ 207.6	$ 638.5	$ 588.3	$ 577.4
Earnings Per Share, Basic
Earnings per common share (basic) (in dollars per share)	$ 0.57	$ 0.58	$ 0.36	$ 0.87	$ 0.54	$ 0.56	$ 0.59	$ 0.92	$ 2.36	$ 2.61	$ 2.54
Earnings Per Share (Diluted)
Earnings per common share (diluted) (in dollars per share)	$ 0.57	$ 0.58	$ 0.35	$ 0.86	$ 0.53	$ 0.56	$ 0.58	$ 0.91	$ 2.34	$ 2.59	$ 2.51

Schedule I - Income Statements

Schedule I - Income Statements (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Parent Company Income Statement
Equity earnings from subsidiaries									$ 96.1	$ 66	$ 68.5
Other income, net									58.9	13.4	18.8
Interest expense									331.4	240.3	250.9
Income before income taxes									1,074.1	951.2	916.5
Income tax benefit									(433.8)	(361.7)	(337.9)
Net income attributed to common shareholders	$ 179.3	$ 182.5	$ 80.9	$ 195.8	$ 121.4	$ 126.3	$ 133	$ 207.6	638.5	588.3	577.4
WEC Energy Group
Condensed Parent Company Income Statement
Operating expenses									42.2	26.8	5.5
Equity earnings from subsidiaries									695.7	635	607.8
Other income, net									23.2	2.8	3.1
Interest expense									71.2	53.1	54.4
Income before income taxes									605.5	557.9	551
Income tax benefit									33	30.4	26.4
Net income attributed to common shareholders									$ 638.5	$ 588.3	$ 577.4

Schedule I - Statements of Comp

Schedule I - Statements of Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
Net income attributed to common shareholders	$ 179.3	$ 182.5	$ 80.9	$ 195.8	$ 121.4	$ 126.3	$ 133	$ 207.6	$ 638.5	$ 588.3	$ 577.4
Derivatives accounted for as cash flow hedges
Gains on settlement, net of tax of $7.6									11.4	0	0
Reclassification of gains to net income, net of tax									(0.8)	0	0
Cash flow hedges, net									10.6	0	0
Defined Benefit Plans
Pension and OPEB costs arising during period, net of tax of $1.0									(6.3)	0	0
Other comprehensive income, net of tax									4.3	0	0
Comprehensive income attributed to common shareholders									642.8	588.3	577.4
Other Comprehensive Income (Loss), Tax
Gain on settlement, tax									7.6
Pension and OPEB costs arising during period, tax									4.2
WEC Energy Group
Condensed Financial Statements, Captions [Line Items]
Net income attributed to common shareholders									638.5	588.3	577.4
Derivatives accounted for as cash flow hedges
Gains on settlement, net of tax of $7.6										0	0
Reclassification of gains to net income, net of tax										0	0
Cash flow hedges, net									10.6	0	0
Defined Benefit Plans
Pension and OPEB costs arising during period, net of tax of $1.0									(1.5)	0	0
Other comprehensive loss from subsidiaries, net of tax									(4.8)	0	0
Other comprehensive income, net of tax									4.3	0	0
Comprehensive income attributed to common shareholders									642.8	$ 588.3	$ 577.4
Other Comprehensive Income (Loss), Tax
Gain on settlement, tax									7.6
Pension and OPEB costs arising during period, tax									$ 1

Schedule I - Balance Sheets (De

Schedule I - Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current Assets
Cash and cash equivalents	$ 49.8	$ 61.9	$ 26	$ 35.6
Prepaid taxes and other	58.8	38.6
Total current assets	2,206.8	1,292.7
Long-term assets
Other long-term assets	403.9	184.6
Total assets	29,355.2	14,905	14,443.2
Current Liabilities
Short-term debt	1,095	617.6
Other	471.2	168.6
Total current liabilities	2,709	1,668.7
Long-term liabilities
Long-term debt	9,124.1	4,170.7
Other long-term liabilities	1,071.7	270.4
Equity
Shareholders' equity	8,685.2	4,450.1	4,263.4	4,165.5
Total liabilities and shareholders' equity	29,355.2	14,905
WEC Energy Group
Current Assets
Cash and cash equivalents	1.3	37.3	$ 0.3	$ 0.9
Accounts receivable from related parties	13.2	5.6
Notes receivable from related parties	123.2	32.2
Prepaid taxes and other	2.2	103.4
Total current assets	139.9	178.5
Long-term assets
Investments in subsidiaries	10,792.6	4,917.8
Other long-term assets	254	280.7
Total long-term assets	11,046.6	5,198.5
Total assets	11,186.5	5,377
Current Liabilities
Short-term debt	307.9	0
Accounts payable to related parties	1.7	2.6
Notes payable to related parties	119	117.2
Accrued taxes	75.6	0
Other	17.5	19.8
Total current liabilities	521.7	139.6
Long-term liabilities
Long-term debt	1,887.2	695.5
Other long-term liabilities	122.8	122.2
Total long-term liabilities	2,010	817.7
Equity
Shareholders' equity	8,654.8	4,419.7
Total liabilities and shareholders' equity	$ 11,186.5	$ 5,377

Schedule I - Statements of Cash

Schedule I - Statements of Cash Flows (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Activities
Net income attributed to common shareholders	$ 179.3	$ 182.5	$ 80.9	$ 195.8	$ 121.4	$ 126.3	$ 133	$ 207.6	$ 638.5	$ 588.3	$ 577.4
Reconciliation to net cash provided by operating activities
Equity earnings from subsidiaries									(96.1)	(66)	(68.5)
Deferred income taxes									420.4	329.2	313.8
Accrued income taxes, net									35.7	(11.4)	36.6
Change in – other current assets									(27.2)	(13.9)	2.8
Change in – other current liabilities									(21.6)	(33.9)	(1.5)
Investing Activities
Proceeds from asset sales									28.9	13.9	2.5
Other, net									41.1	3.6	(12.6)
Financing Activities
Exercise of stock options									30.1	50.3	48.5
Purchase of common stock									(74.7)	(123.2)	(223.4)
Dividends paid on common stock									(455.4)	(352)	(328.9)
Issuance of long-term debt									2,150	250	251
Other, net									(18.9)	12.8	11.2
Cash and cash equivalents at beginning of year				61.9				26	61.9	26	35.6
Cash and cash equivalents at end of year	49.8				61.9				49.8	61.9	26
WEC Energy Group
Operating Activities
Net income attributed to common shareholders									638.5	588.3	577.4
Reconciliation to net cash provided by operating activities
Equity earnings from subsidiaries									(695.7)	(635)	(607.8)
Dividends from subsidiaries									538.8	720	720.4
Deferred income taxes									30.9	60.1	(7.8)
Accrued income taxes, net									175.7	4.1	66.8
Change in – other current assets									(9.3)	(0.3)	(2.8)
Change in – other current liabilities									(3.2)	5.1	(22.9)
Other, net									(18.4)	(8.1)	(21.6)
Net cash provided by operating activities									657.3	734.2	701.7
Investing Activities
Business acquisition									(1,486.2)	0	0
Proceeds from asset sales									20.8	0	0
Capital contributions to subsidiaries									(135.3)	(225.5)	(195.3)
Change in short-term notes receivable from related parties									(91)	0	0
Other, net									(0.1)	5	4
Net cash used for investing activities									(1,691.8)	(220.5)	(191.3)
Financing Activities
Exercise of stock options									30.1	50.3	48.5
Purchase of common stock									(74.7)	(123.2)	(223.4)
Dividends paid on common stock									(455.4)	(352)	(328.9)
Issuance of long-term debt									1,200	0	0
Change in short-term debt									307.9	(72)	5
Change in short-term notes payable to related parties									1.8	3.5	(26.8)
Other, net									(11.2)	16.7	14.6
Net cash provided by (used for) financing activities									998.5	(476.7)	(511)
Net change in cash and cash equivalents									(36)	37	(0.6)
Cash and cash equivalents at beginning of year				$ 37.3				$ 0.3	37.3	0.3	0.9
Cash and cash equivalents at end of year	$ 1.3				$ 37.3				$ 1.3	$ 37.3	$ 0.3

Schedule I - Dividends Received

Schedule I - Dividends Received from Subsidiaries (Details) - WEC Energy Group - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
Cash Dividends Received from Subsidiaries	$ 538.8	$ 720	$ 720.4
Wisconsin Electric
Condensed Financial Statements, Captions [Line Items]
Cash Dividends Received from Subsidiaries	240	390	340
Wisconsin Gas
Condensed Financial Statements, Captions [Line Items]
Cash Dividends Received from Subsidiaries	30	33	33
We Power
Condensed Financial Statements, Captions [Line Items]
Cash Dividends Received from Subsidiaries	262.8	297	347.4
ATC Holding LLC
Condensed Financial Statements, Captions [Line Items]
Cash Dividends Received from Subsidiaries	$ 6	$ 0	$ 0

Schedule I - Long-term Debt Fut

Schedule I - Long-term Debt Future Maturities (Details) $ in Millions	Dec. 31, 2015USD ($)
Future maturities of long-term debt outstanding
2,018	$ 836.1
2,020	684.4
Thereafter	7,094.6
Total	9,254.7
WECC
Future maturities of long-term debt outstanding
Long-Term debt, Unsecured	50
WEC Energy Group
Future maturities of long-term debt outstanding
2,018	300
2,020	400
Thereafter	1,200
Total	$ 1,900

Schedule I - Long-term Debt Fai

Schedule I - Long-term Debt Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Carrying Amount
Financial Instruments
Long-term Debt	$ 9,221.9	$ 4,510.3
Fair Value
Financial Instruments
Long-term Debt	9,681	5,126
WEC Energy Group | Carrying Amount
Financial Instruments
Long-term Debt	1,887.2	695.5
WEC Energy Group | Fair Value
Financial Instruments
Long-term Debt	$ 1,900.7	$ 770

Schedule I - Supplemental Cash

Schedule I - Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
Cash received from income tax refunds	$ (9.3)	$ (22)
WEC Energy Group
Condensed Financial Statements, Captions [Line Items]
Cash paid for interest	68.8	44.4	$ 44.4
Cash received from income tax refunds	$ 242.9	$ 95.1	$ 86.1

Schedule I - Short-term Notes R

Schedule I - Short-term Notes Receivable - Related Parties (Details) - WEC Energy Group - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Notes receivable from related parties	$ 123.2	$ 32.2
Integrys
Condensed Financial Statements, Captions [Line Items]
Notes receivable from related parties	95.1	0
Bostco LLC
Condensed Financial Statements, Captions [Line Items]
Notes receivable from related parties	19.6	22.4
Wispark
Condensed Financial Statements, Captions [Line Items]
Notes receivable from related parties	$ 8.5	$ 9.8

Schedule I - Short-term Notes P

Schedule I - Short-term Notes Payable Related Parties (Details) - WEC Energy Group - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Notes payable to related parties	$ 119	$ 117.2
WECC
Condensed Financial Statements, Captions [Line Items]
Notes payable to related parties	108.4	106.6
Wisvest
Condensed Financial Statements, Captions [Line Items]
Notes payable to related parties	$ 10.6	$ 10.6

Schedule II - Valuation and 129

Schedule II - Valuation and Qualifying Accounts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Valuation and Qualifying Accounts
Balance at Beginning of the Period	$ 74.5	$ 61	$ 58
Acquisition of Businesses	54.3	0	0
Expense	56.7	49.8	49.4
Deferral	8.2	18.4	0.4
Net Write-offs	80.4	54.7	46.8
Balance at End of the Period	$ 113.3	$ 74.5	$ 61