Wisconsin Electric Power Company PFD 3.60% (WELPP) 10-K 28 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Jan. 31, 2017	Jun. 30, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	WISCONSIN ELECTRIC POWER CO
Entity Central Index Key	107,815
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		33,289,327
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 0

Consolidated Income Statements

Consolidated Income Statements - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Operating revenues	$ 3,792.8	$ 3,854.1	$ 4,059.4
Cost of sales	1,292.1	1,399	1,660.7
Other operation and maintenance	1,430.2	1,384.9	1,356.4
Depreciation and amortization	325.4	304	278.3
Property and revenue taxes	115.6	117.3	113.6
Total operating expenses	3,163.3	3,205.2	3,409
Operating income	629.5	648.9	650.4
Equity in earnings of transmission affiliate	55.5	47.8	57.9
Other income, net	9.1	11.2	8.7
Interest expense	117.6	119	116.5
Other expense	(53)	(60)	(49.9)
Income before income taxes	576.5	588.9	600.5
Total income tax expense	211	212	222.6
Net income	365.5	376.9	377.9
Preferred stock dividend requirements	1.2	1.2	1.2
Net income attributed to common shareholder	$ 364.3	$ 375.7	$ 376.7

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents	$ 15.4	$ 27.1
Accounts receivable, net of allowance for doubtful accounts of $40.9 and $43.0, respectively	503.2	461.4
Accounts receivable from related parties	58.2	41.1
Materials, supplies and inventories	271	301.6
Prepayments	138	171.8
Other	24.6	19.6
Total current assets	1,010.4	1,022.6
Long-term assets
Property, plant, and equipment, net of accumulated depreciation of $3,619.6 and $3,461.9, respectively	9,832.3	9,767.5
Regulatory assets	2,036.6	1,855.9
Equity investment in transmission affiliate	402	382.2
Other	90.2	111.4
Long-term assets	12,361.1	12,117
Total Assets	13,371.5	13,139.6
Current Liabilities
Short-term debt	159	144
Current portion of capital lease obligations	28.5	123.6
Subsidiary note payable to WEC Energy Group	18.5	19.6
Accounts payable	297.9	286.4
Accounts payable to related parties	112.9	95.7
Accrued payroll and benefits	51.8	87.5
Accrued taxes	46	15.6
Other	100.1	100.1
Current liabilities	814.7	872.5
Long-term liabilities
Long-term debt	2,661.1	2,658.8
Capital lease obligations	2,756.5	2,692.5
Deferred income taxes	2,333.3	2,110
Regulatory liabilities	853.9	741.2
Pension and OPEB obligations	167.6	210.9
Other	260.2	259.3
Long-term liabilities	9,032.6	8,672.7
Commitments and contingencies (Note 16)
Common shareholder's equity
Common stock - $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding	332.9	332.9
Additional paid in capital	1,020.1	999.7
Retained earnings	2,140.8	2,231.4
Common shareholder's equity	3,493.8	3,564
Preferred stock	30.4	30.4
Total liabilities and equity	$ 13,371.5	$ 13,139.6

Consolidated Balance Sheets Par

Consolidated Balance Sheets Parenthetical (Parentheticals) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Allowance for doubtful accounts receivable	$ 40.9	$ 43
Property, plant, and equipment, accumulated depreciation	$ 3,619.6	$ 3,461.9
Common stock, par value	$ 10
Common stock, shares authorized	65,000,000
Common stock, shares outstanding	33,289,327	33,289,327

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Cash Flows [Abstract]
Net income	$ 365.5	$ 376.9	$ 377.9
Reconciliation to cash provided by operating activities
Depreciation and amortization	325.4	323.7	302.6
Deferred income taxes and investment tax credits, net	206.2	178.9	191.4
Contributions and payments related to pension and OPEB plans	(8)	(107.6)	(10.4)
Equity income in transmission affiliate, net of distributions	(17.2)	(4.9)	(7.4)
Payments for liabilities transferred to WBS	(116)	0	0
Change In
Accounts receivable and unbilled revenues	(59)	(2.9)	91
Material, supplies, and inventories	30.6	18.8	(39.5)
Prepaid taxes	39.4	(2.8)	(2.5)
Other current assets	9.3	0.3	(6.2)
Accounts payable	31.3	(5.9)	18.2
Accrued taxes	30.4	(42.1)	(7.5)
Other current liabilities	10.7	(1.2)	(36.8)
Other, net	(0.2)	(56.8)	(8)
Net cash provided by operating activities	848.4	674.4	862.8
Investing Activities
Capital expenditures	(469.5)	(519.2)	(561.8)
Capital contributions to transmission affiliate	(16.1)	(4.6)	(11.5)
Proceeds from the sale of assets	31.7	0.2	6
Proceeds from assets transferred to WBS	13.1	0	0
Other, net	4	3.4	(0.2)
Net cash used in investing activities	(436.8)	(520.2)	(567.5)
Financing Activities
Dividends paid on common stock	(455)	(240)	(390)
Dividends paid on preferred stock	(1.2)	(1.2)	(1.2)
Issuance of long-term debt	0	500	250
Retirement of long-term debt	0	(250)	(300)
Change in short-term debt	15	(162.8)	131.9
Repayment of subsidiary note WEC Energy Group	(1.1)	(2.9)	0
Other, net	19	5.8	12.9
Net cash used in financing activities	(423.3)	(151.1)	(296.4)
Net change in cash and cash equivalents	(11.7)	3.1	(1.1)
Cash and cash equivalents at beginning of year	27.1	24	25.1
Cash and cash equivalents at end of year	$ 15.4	$ 27.1	$ 24

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) $ in Millions	Total	Total Common Shareholders' Equity	Common Stock	Additional Paid-In Capital	Retained Earnings	Preferred Stock
Balance at Dec. 31, 2013	$ 3,437.2	$ 3,406.8	$ 332.9	$ 965.1	$ 2,108.8	$ 30.4
Equity
Net income	377.9	377.9	0	0	377.9	0
Dividends
Common stock dividends	(390)	(390)	0	0	(390)	0
Preferred stock dividends	(1.2)	(1.2)	0	0	(1.2)	0
Stock-based compensation	3.5	3.5	0	3.5	0	0
Tax benefit of exercised stock options allocated from parent	15.8	15.8	0	15.8	0	0
Balance at Dec. 31, 2014	3,443.2	3,412.8	332.9	984.4	2,095.5	30.4
Equity
Net income	376.9	376.9	0	0	376.9	0
Dividends
Common stock dividends	(240)	(240)	0	0	(240)	0
Preferred stock dividends	(1.2)	(1.2)	0	0	(1.2)	0
Stock-based compensation	3.2	3.2	0	3.2	0	0
Tax benefit of exercised stock options allocated from parent	12.1	12.1	0	12.1	0	0
Other	0.2	0.2	0	0	0.2	0
Balance at Dec. 31, 2015	3,594.4	3,564	332.9	999.7	2,231.4	30.4
Equity
Net income	365.5	365.5	0	0	365.5	0
Dividends
Common stock dividends	(455)	(455)	0	0	(455)	0
Preferred stock dividends	(1.2)	(1.2)	0	0	(1.2)	0
Stock-based compensation	1.1	1.1	0	1.1	0	0
Tax benefit of exercised stock options allocated from parent	19.3	19.3	0	19.3	0	0
Other	0.1	0.1	0	0	0.1	0
Balance at Dec. 31, 2016	$ 3,524.2	$ 3,493.8	$ 332.9	$ 1,020.1	$ 2,140.8	$ 30.4

Consolidated Statements of Capi

Consolidated Statements of Capitalization - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Common Shareholder's equity	$ 3,493.8	$ 3,564
Preferred stock	30.4	30.4
Obligations under capital leases	2,785	2,816.1
Total	5,472	5,503.1
Unamortized debt issuance costs	(3.6)	(3.9)
Unamortized discount, net	(22.3)	(24.3)
Total long-term debt and capital lease obligations, including current portion	5,446.1	5,474.9
Current portion of capital lease obligations	(28.5)	(123.6)
Total long-term debt and capital lease obligations	5,417.6	5,351.3
Total long-term capitalization	8,941.8	8,945.7
Debentures (unsecured), 1.70% due 2018 [Member]
Long-term Debt, unsecured	$ 250	250
Debt Instrument, Interest Rate, Stated Percentage	1.70%
Debentures (unsecured), 4.25% due 2019 [Member]
Long-term Debt, unsecured	$ 250	250
Debt Instrument, Interest Rate, Stated Percentage	4.25%
Debentures (unsecured) 2.95% due 2021 [Member]
Long-term Debt, unsecured	$ 300	300
Debt Instrument, Interest Rate, Stated Percentage	2.95%
Wis Elec Debenture due June 1, 2025 [Member]
Long-term Debt, unsecured	$ 250	250
Debt Instrument, Interest Rate, Stated Percentage	3.10%
Debentures (unsecured), 6-1/2% due 2028 [Member]
Long-term Debt, unsecured	$ 150	150
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debentures (unsecured), 5.625% due 2033 [Member]
Long-term Debt, unsecured	$ 335	335
Debt Instrument, Interest Rate, Stated Percentage	5.625%
Debentures (unsecured), 5.70% due 2036 [Member]
Long-term Debt, unsecured	$ 300	300
Debt Instrument, Interest Rate, Stated Percentage	5.70%
Debentures (unsecured), 3.65% due 2042 [Member]
Long-term Debt, unsecured	$ 250	250
Debt Instrument, Interest Rate, Stated Percentage	3.65%
Debentures (unsecured), 4.25% due 2044 [Member]
Long-term Debt, unsecured	$ 250	250
Debt Instrument, Interest Rate, Stated Percentage	4.25%
Wis Elec Debenture due December 15, 2045 [Member]
Long-term Debt, unsecured	$ 250	250
Debt Instrument, Interest Rate, Stated Percentage	4.30%
Debentures (unsecured), 6-7/8% due 2095 [Member]
Long-term Debt, unsecured	$ 100	100
Debt Instrument, Interest Rate, Stated Percentage	6.875%
Notes (secured, nonrecourse), 4.81% effective rate due 2030 [Member]
Long-term Debt, secured	$ 2	$ 2
Debt Instrument, Interest Rate, Stated Percentage	4.81%

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a) General Information —On June 29, 2015, our parent company, Wisconsin Energy Corporation, acquired Integrys and changed its name to WEC Energy Group, Inc. See Note 2, Acquisitions, for more information on this acquisition. We are an electric, natural gas, and steam utility company that serves electric customers in Wisconsin and an iron ore mine owned by the Tilden Mining Company (Tilden) in the Upper Peninsula of Michigan, natural gas customers in Wisconsin, and steam customers in metropolitan Milwaukee, Wisconsin. In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan, and it became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets previously held by us and WPS located in the Upper Peninsula of Michigan. The existing contract between us and the Tilden Mining Company will remain in place until a new power generation solution for the region is commercially operational. As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, statements of equity, and statements of capitalization, unless otherwise noted. At December 31, 2016 , we had one wholly owned subsidiary, Bostco. Bostco had total assets of $24.4 million and $29.8 million as of December 31, 2016 and 2015 , respectively. The financial statements include our accounts and the accounts of our wholly owned subsidiary. 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. During the second quarter of 2016, 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. See Note 21, Segment Information, for more information on our business segments. We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates. (b) Balance Sheet Presentation — To be consistent with the current year presentation, we changed our December 31, 2015 balance sheet from a utility format to a traditional format. This change revised the order of certain balance sheet line items, but it did not result in any change to the classification of amounts between line items. (c) Cash and Cash Equivalents —Cash and cash equivalents include marketable debt securities with an original maturity of three months or less. (d) Revenues and Customer Receivables —We recognize revenues related to the sale of energy on the accrual basis and include estimated amounts for services provided but not yet billed to customers. We present revenues net of pass-through taxes on the income statements. Below is a summary of the significant mechanisms we had in place that allowed us 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. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater ROE than authorized by the PSCW. • We received payments from MISO under an SSR agreement for our PIPP units through February 1, 2015. We recorded revenue for these payments to recover costs for operating and maintaining these units. See Note 20, Regulatory Environment , for more information. • Our natural gas utility rates included a one-for-one recovery mechanism 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. • Our residential rates included a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. Revenues are also impacted by other accounting policies related to our participation in the MISO Energy Markets. We 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 we were a net seller in a particular hour, the net amount was reported as operating revenues. If we were a net purchaser in a particular hour, the net amount was recorded as cost of sales on our income statements. We provide regulated electric, natural gas, and steam service to customers in Wisconsin and provided electric service to customers in the Upper Peninsula of Michigan through December 31, 2016. See Note 4, Related Parties , and Note 20, Regulatory Environment , for information regarding the transfer of our customers located in the Upper Peninsula of Michigan to UMERC as of January 1, 2017. 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. Our credit risk exposure is mitigated by our recovery mechanism for uncollectible expense discussed above. As a result, we did not have any significant concentrations of credit risk at December 31, 2016 . In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2016 . (e) Materials, Supplies, and Inventories —Our inventory as of December 31 consisted of: (in millions) 2016 2015 Materials and supplies $ 148.1 $ 151.1 Fossil fuel 91.1 110.5 Natural gas in storage 31.8 40.0 Total $ 271.0 $ 301.6 Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting. (f) Regulatory Assets and Liabilities —The economic effects of regulation can result in regulated companies recording costs and revenues that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future revenues associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts that are collected in rates for future costs. Recovery or refund of regulatory assets and liabilities is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to which they relate. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the reporting period the determination is made. See Note 7, Regulatory Assets and Liabilities, for more information . (g) Property, Plant, and Equipment —We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. We record straight-line depreciation over the estimated useful life of utility property using depreciation rates approved by the PSCW and MPSC that include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 3.00% , 3.01% , and 2.93% in 2016 , 2015 , and 2014 , respectively. 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 5 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement. For assets other than our regulated assets and leased equipment, we accrue depreciation expense at straight-line rates over the estimated useful lives of the assets, or over the non-cancellable lease term for leased equipment. (h) 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. Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 8.45% for 2016 and 2015 , and 9.09% for 2014 . Our average AFUDC wholesale rates were 2.73% , 1.72% , and 0.87% for 2016 , 2015 , and 2014 , respectively. We recorded the following AFUDC for the years ended December 31: (in millions) 2016 2015 2014 AFUDC – Debt $ 1.7 $ 2.2 $ 1.8 AFUDC – Equity $ 4.2 $ 5.7 $ 4.4 (i) Asset Retirement Obligations —We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted to their present values each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated retirement costs. 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 . (j) Environmental Remediation Costs —We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 9, Asset Retirement Obligations, for more information regarding coal combustion product landfill sites and Note 16, Commitments and Contingencies , for more information regarding manufactured gas plant sites. We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation. We 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's 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. (k) 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 are included in WEC Energy Group's consolidated Federal and state income tax returns. In accordance with our tax allocation agreement with WEC Energy Group, we are allocated income tax payments and refunds based upon our separate tax computation. See Note 14, Income Taxes, for more information . We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense in our income statements. (l) Employee Benefits —The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are allocated among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for our net periodic benefit cost calculated under GAAP. See Note 15, Employee Benefits, for more information . (m) Stock-Based Compensation —Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the shareholder approved Omnibus Stock Incentive Plan, WEC Energy Group provides a long-term incentive through its equity interests to its non-employee directors, selected officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. The number of shares of WEC Energy Group common stock authorized for issuance under the plan is 34.3 million . Stock-based compensation expense is allocated to us based on the outstanding awards held by our employees and our allocation of labor costs. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period based on an estimate of the final expected value of the awards. Stock Options Our employees are granted WEC Energy Group 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 the fair market value of WEC Energy Group common stock on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of WEC Energy Group common stock on the date of 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. WEC Energy Group stock options are classified as equity awards. The fair value of each stock option was calculated using a binomial option-pricing model. The following table shows the estimated fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models: 2016 2015 2014 Non-qualified stock options granted * 92,880 495,550 864,860 Estimated fair value per non-qualified stock option $ 4.92 $ 5.29 $ 4.18 Risk-free interest rate 0.5% – 2.2% 0.1% – 2.1% 0.1% – 3.0% Dividend yield 4.0 % 3.7 % 3.8 % Expected volatility 18.0 % 18.0 % 18.0 % Expected life (years) 5.8 5.8 5.8 * Effective January 1, 2016, certain of our employees were transferred into WBS. See Note 4, Related Parties, for more information . The risk-free interest rate is based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on WEC Energy Group's current dividend rate and historical stock prices. Expected volatility and expected life assumptions were based on WEC Energy Group's historical experience. Restricted Shares WEC Energy Group restricted shares have a three -year vesting period, and generally, one-third of the award vests on each anniversary of the grant date. The restricted shares are classified as equity awards. Performance Units Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on WEC Energy Group's total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over a three -year period, and beginning in 2017, other performance metrics as determined by the Compensation Committee. Participants may earn between 0% and 175% of the base performance unit award, as adjusted pursuant to the terms of the plan. All grants are settled in cash and are accounted for as liability awards accordingly. Stock-based compensation costs are recorded over the three -year performance period. See Note 10, Common Equity , for more information on WEC Energy Group's stock-based compensation plans. (n) Fair Value Measurements —Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. We recognize transfers at their value as of the end of the reporting period. Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a dividend discount model. The fair value of our long-term debt is estimated based upon the quoted market value for the same or similar issues. The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy. See Note 17, Fair Value Measurements, for more information . (o) 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. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW. We record derivative instruments on our balance sheets as assets or liabilities measured at fair value, unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Realized gains and losses on derivative instruments are primarily recorded in cost of sales on our income statements. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows. Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current liabilities. See Note 18, Derivative Instruments, for more information . (p) 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 other current liabilities on our balance sheets.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
ACQUISITIONS	ACQUISITIONS Parent Company's Acquisition of Integrys On June 29, 2015, our parent company 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. The acquisition was subject to the approvals of various government agencies, including the PSCW. Approvals were obtained from all agencies subject to several conditions. The PSCW order includes the following conditions: • We are subject to an earnings sharing mechanism for three years beginning January 1, 2016. Under the earnings sharing mechanism, if we earn over our authorized rate of return, 50% of the first 50 basis points of additional utility earnings will be shared with customers and will reduce our transmission escrow. All utility earnings above the first 50 basis points will be solely used to reduce the transmission escrow. For the year ended December 31, 2016, we recorded $21.1 million of expense related to this earnings sharing mechanism. • Any future electric generation projects affecting Wisconsin ratepayers submitted by WEC Energy Group or its subsidiaries will first consider the extent to which existing intercompany resources can meet energy and capacity needs. In September 2015, we and WPS filed a joint integrated resource plan with the PSCW for our combined loads, which indicated that no new generation is currently needed. 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. In 2015, we recorded $6.6 million of severance expense that resulted from employee reductions related to the post-acquisition integration. Severance expense incurred during 2016 was not significant. The severance expense was recorded in our utility segment and is included in the other operation and maintenance line item on the income statements. Severance payments of $4.6 million and $1.2 million were made during 2016 and 2015, respectively. The severance accruals on our balance sheets were not significant at December 31, 2016 and 2015. Parent Company's Acquisition of a Natural Gas Storage Facility in Michigan In January 2017, our parent company signed an agreement for the acquisition of a natural gas storage facility in Michigan that would provide for some of our storage needs for our natural gas utility operations. We plan to enter into a long-term service agreement to take the allocated storage, subject to PSCW approval and closing of the acquisition. PSCW approval and closing of this transaction are expected to occur by the third quarter of 2017.

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2016
Discontinued Operations and Disposal Groups [Abstract]
DISPOSITIONS	DISPOSITIONS Utility Segment – Sale of Milwaukee County Power Plant In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $10.9 million ( $6.5 million after tax), which was included in other operation and maintenance on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations of this plant remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
RELATED PARTIES	RELATED PARTIES We and our consolidated subsidiary, Bostco, routinely enter into transactions with related parties, including WEC Energy Group, its subsidiaries, ATC, and other affiliated entities. We provide and receive services, property, and other items of value to and from our parent, WEC Energy Group, and other subsidiaries of WEC Energy Group. Following the acquisition of Integrys by Wisconsin Energy Corporation on June 29, 2015, an AIA (Non-WBS AIA) went into effect. The Non-WBS AIA governed the provision and receipt of services by WEC Energy Group's subsidiaries, except that WBS continued to provide services to Integrys and its subsidiaries only under the existing WBS AIAs. WBS provided services to WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries, including us, under interim WBS AIAs. The PSCW and all other relevant state commissions approved the Non-WBS AIA or granted appropriate waivers related to the Non-WBS AIA. Services under the Non-WBS AIA were subject to various pricing methodologies. All services provided by any regulated subsidiary to another regulated subsidiary were priced at cost. All services provided by any regulated subsidiary to any nonregulated subsidiary were priced at the greater of cost or fair market value. All services provided by any nonregulated subsidiary to any regulated subsidiary were priced at the lesser of cost or fair market value. All services provided by any regulated or nonregulated subsidiary to WBS were priced at cost. WBS provided several categories of services (including financial, human resource, and administrative services) to us pursuant to the interim WBS AIAs, which were approved, or from which we were granted appropriate waivers, by the appropriate regulators, including the PSCW. As required by FERC regulations for centralized service companies, WBS renders services at cost. The PSCW must be notified prior to making changes to the services offered under and the allocation methods specified in the interim WBS AIAs. Other modifications or amendments to the interim WBS AIAs would require PSCW approval. Recovery of allocated costs is addressed in our rate cases. On April 1, 2016, we, along with WEC Energy Group, filed a new agreement for approval with the PSCW and all other relevant state commissions. The PSCW approved the new agreement in August 2016. We later received approval from the two other states reviewing the agreement, and the new agreement took effect January 1, 2017. The new agreement replaces the previous agreements. The pricing methodology and services under this new agreement are substantially identical to those under the agreements being replaced. In February 2017, a request was filed with the PSCW for modifications to the new AIA to incorporate WEC Energy Group's acquisition of a natural gas storage facility in Michigan. See Note 2, Acquisitions, for more information on the natural gas storage facility acquisition. Effective January 1, 2016, 485 of our employees were transferred into WBS. In connection with this transfer of employees, certain benefit-related liabilities were also transferred to WBS. In addition, we transferred certain software assets to WBS in 2016. We provide services to and receive services from ATC for its transmission facilities under several agreements approved by the PSCW. Services are billed to ATC under these agreements at our fully allocated cost. On January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 5, Investment in American Transmission Company, for more information . Bostco has a note payable to our parent company, WEC Energy Group. At December 31, 2016 and 2015 , the balance of this note payable was $18.5 million and $19.6 million , respectively. The following table shows activity associated with our related party transactions for the years ended December 31: (in millions) 2016 2015 2014 Lease agreements Lease payments to We Power (1) $ 412.2 $ 410.5 $ 389.0 CWIP billed to We Power 37.9 58.8 41.0 Transactions with WBS (2) Billings to WBS (3) 213.8 11.1 — Billings from WBS (4) 310.6 1.3 — Transactions with WPS (2) Billings to WPS 9.0 13.4 — Billings from WPS 4.2 4.9 — Transactions with WG Natural gas purchases from WG 5.3 5.3 6.6 Services received from WG 21.5 23.5 20.6 Services provided to WG 60.6 79.4 81.7 (1) We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS 1, PWGS 2, ER 1, and ER 2. (2) Includes amounts billed for services, pass through costs, and other items in accordance with the approved AIAs discussed above. (3) Includes $13.1 million for the transfer of certain software assets to WBS for the year ended December 31, 2016. (4) Includes $116.0 million for the transfer of certain benefit-related liabilities to WBS for the year ended December 31, 2016. Upper Michigan Energy Resources Corporation In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. We transferred approximately 27,500 retail electric customers and 50 electric distribution-only customers to UMERC, along with approximately 2,500 miles of electric distribution lines. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The estimated net book value of the property, plant, and equipment transferred to UMERC from us as of January 1, 2017, was $83 million . This transaction was a non-cash equity transfer between entities under common control, and therefore, did not result in a gain or loss recognized. UMERC obtains its energy through the MISO Energy Markets and meets its market obligations through power purchase agreements with us and WPS. The new utility has also proposed a long-term generation solution for electric reliability in the region. See Note 20, Regulatory Environment, for more information . The Tilden Mining Company will remain a customer of ours until this new generation begins commercial operation.

Investment in American Transmis

Investment in American Transmission Company	12 Months Ended
	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
INVESTMENT IN AMERICAN TRANSMISSION COMPANY	INVESTMENT IN AMERICAN TRANSMISSION COMPANY At December 31, 2016, we owned approximately 23% of ATC, a for-profit, transmission-only company regulated by the FERC and certain state regulatory commissions. On January 1, 2017, based upon input we received from the PSCW, we transferred our investment in ATC to another subsidiary of WEC Energy Group. This transaction was a non-cash equity transfer between entities under common control, and therefore, did not result in a gain or loss recognized. WEC Energy Group has one representative on ATC's ten -member board of directors. Each member of the board has only one vote. Due to voting requirements, no individual board member has more than 10% of the voting control. The following table shows changes to our investment in ATC during the years ended December 31: (in millions) 2016 2015 2014 Balance at beginning of period $ 382.2 $ 372.9 $ 354.1 Add: Earnings from equity method investment 55.5 47.8 57.9 Add: Capital contributions 16.1 4.6 11.5 Less: Distributions 51.7 * 42.9 50.5 Less: Other 0.1 0.2 0.1 Balance at end of period $ 402.0 $ 382.2 $ 372.9 * Of this amount, $13.4 million was recorded as a receivable at December 31, 2016. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service. The following table summarizes our significant related party transactions with ATC during the years ended December 31: (in millions) 2016 2015 2014 Charges to ATC for services and construction $ 10.0 $ 9.7 $ 8.1 Charges from ATC for network transmission services 247.8 238.5 231.4 As of December 31, 2016 and 2015 , our balance sheets included the following receivables and payables related to ATC: (in millions) 2016 2015 Accounts receivable Services provided to ATC $ 1.1 $ 0.6 Accounts payable Services received from ATC 20.0 19.9 Summarized financial data for ATC is included in the tables below: (in millions) 2016 2015 2014 Income statement data Revenues $ 650.8 $ 615.8 $ 635.0 Operating expenses 322.5 319.3 307.4 Other expense 95.5 96.1 88.9 Net income $ 232.8 $ 200.4 $ 238.7 (in millions) December 31, 2016 December 31, 2015 Balance sheet data Current assets $ 75.8 $ 80.5 Noncurrent assets 4,312.9 3,948.3 Total assets $ 4,388.7 $ 4,028.8 Current liabilities $ 495.1 $ 330.3 Long-term debt 1,865.3 1,790.7 Other noncurrent liabilities 271.5 245.0 Shareholders' equity 1,756.8 1,662.8 Total liabilities and shareholders' equity $ 4,388.7 $ 4,028.8

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION (in millions) 2016 2015 2014 Cash (paid) for interest, net of amount capitalized $ (116.2 ) $ (116.2 ) $ (117.9 ) Cash received (paid) for income taxes, net 100.2 (58.5 ) (20.8 ) Significant non-cash transactions: Accounts payable related to construction costs 9.1 11.7 1.7

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory assets and liabilities	REGULATORY ASSETS AND LIABILITIES The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2016 2015 See Note Regulatory assets (1) (2) Plant related – capital leases $ 724.8 $ 674.4 13 Unrecognized pension and OPEB costs (3) 520.3 535.8 15 Electric transmission costs 231.9 191.5 20 Income tax related items (4) 200.8 177.4 SSR 188.1 86.1 20 We Power generation (5) 54.1 45.4 AROs 39.7 36.3 9 Energy efficiency programs (6) 38.5 50.7 Other, net 38.4 58.3 Total regulatory assets $ 2,036.6 $ 1,855.9 (1) Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in the table. (2) As of December 31, 2016 , we had $10.4 million of regulatory assets not earning a return and $204.0 million of regulatory assets earning a return based on short-term interest rates. The regulatory assets not earning a return relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures. (3) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We are authorized recovery of this regulatory asset over the average remaining service life of each plan. (4) Represents adjustments related to deferred income taxes, which are recovered in rates as the temporary differences that generated the income tax benefit reverse. (5) Represents amounts recoverable from customers related to our costs of the generating units leased from We Power, including subsequent capital additions. (6) Represents amounts recoverable from customers related to programs designed to meet energy efficiency standards. The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2016 2015 Regulatory liabilities Removal costs (1) $ 722.9 $ 696.9 Mines deferral (2) 70.2 31.6 Other, net 71.0 12.7 Total regulatory liabilities $ 864.1 $ 741.2 Balance Sheet Presentation Other current liabilities $ 10.2 $ — Regulatory liabilities 853.9 741.2 Total regulatory liabilities $ 864.1 $ 741.2 (1) Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment. (2) Represents the deferral of revenues less the associated cost of sales related to 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.

Property, Plant, and Equipment

Property, Plant, and Equipment	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT, AND EQUIPMENT	PROPERTY, PLANT, AND EQUIPMENT Property, plant, and equipment consisted of the following utility and non-utility and other assets at December 31: (in millions) 2016 2015 Utility property, plant, and equipment $ 11,232.9 $ 10,863.1 Less: Accumulated depreciation 3,606.9 3,447.2 Net 7,626.0 7,415.9 CWIP 111.5 170.3 Net utility property, plant, and equipment 7,737.5 7,586.2 Property under capital leases 2,898.0 2,876.7 Less: Accumulated amortization 837.8 735.0 Net leased facilities 2,060.2 2,141.7 Non-utility and other property, plant, and equipment 46.4 54.0 Less: Accumulated depreciation 12.7 14.7 Net 33.7 39.3 CWIP 0.9 0.3 Net non-utility and other property, plant, and equipment 34.6 39.6 Total property, plant, and equipment $ 9,832.3 $ 9,767.5 On January 1, 2017, we transferred 2,500 miles of electric distribution lines and related electric distribution substations in the Upper Peninsula of Michigan to UMERC. The estimated net book value of the property, plant, and equipment we transferred to UMERC was $83 million . See Note 4, Related Parties, for more information .

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS We have recorded AROs primarily for asbestos abatement at certain generation and substation facilities, the removal and dismantlement of generation facilities, and the closure of fly-ash landfills at our generation facilities. We 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. On our balance sheets, AROs are recorded within other long-term liabilities. The following table shows changes to our AROs during the years ended December 31: (in millions) 2016 2015 2014 Balance as of January 1 $ 58.7 $ 40.5 $ 39.4 Accretion 3.0 2.3 2.2 Additions — 15.9 * — Liabilities settled (0.2 ) — (1.1 ) Balance as of December 31 $ 61.5 $ 58.7 $ 40.5 * During 2015, an ARO was recorded for the fly-ash landfills located at our generation facilities.

Common Equity

Common Equity	12 Months Ended
	Dec. 31, 2016
Stockholders' Equity Note [Abstract]
COMMON EQUITY	COMMON EQUITY Stock-Based Compensation Plans The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit for the years ended December 31: (in millions) 2016 2015 2014 Stock options $ 1.8 $ 3.2 $ 3.6 Restricted stock 1.8 2.1 2.1 Performance units 3.9 7.5 12.7 Stock-based compensation expense $ 7.5 $ 12.8 $ 18.4 Related tax benefit $ 3.0 $ 5.1 $ 7.4 Stock-based compensation costs capitalized during 2016 , 2015 , and 2014 were not significant. Stock Options The following is a summary of our employees' WEC Energy Group stock option activity during 2016 : Stock Options Number of Options Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life (in years) Aggregate Intrinsic Value (in millions) Outstanding as of January 1, 2016 5,687,714 $ 33.58 Granted 92,880 $ 50.93 Exercised (439,043 ) $ 27.57 Transferred * (4,055,745 ) $ 34.68 Outstanding as of December 31, 2016 1,285,806 $ 33.41 4.6 $ 32.4 Exercisable as of December 31, 2016 1,010,061 $ 29.64 3.7 $ 29.3 * Relates to the transfer of certain employees into WBS. See Note 4, Related Parties, for more information . The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2016 . This is calculated as the difference between WEC Energy Group's closing stock price on December 31, 2016 , and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2016 , 2015 , and 2014 was $14.1 million , $34.6 million , and $47.5 million , respectively. Cash received by WEC Energy Group from exercises of its options by our employees was $12.1 million , $29.2 million , and $47.9 million during the years ended December 31, 2016 , 2015 , and 2014 , respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $5.6 million , $14.0 million , and $18.8 million , respectively. As of December 31, 2016 , our estimated unrecognized compensation cost related to unvested WEC Energy Group stock options was not significant. During the first quarter of 2017 , the Compensation Committee awarded 80,770 non-qualified WEC Energy Group stock options with an exercise price of $58.31 and a weighted-average grant date fair value of $7.12 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation. Restricted Shares The following is a summary of our employees' WEC Energy Group restricted stock activity during 2016 : Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding as of January 1, 2016 175,443 $ 47.66 Granted 8,049 $ 51.78 Released (7,901 ) $ 44.66 Transferred * (158,635 ) $ 47.73 Forfeited (695 ) $ 50.42 Outstanding as of December 31, 2016 16,261 $ 50.39 * Relates to the transfer of certain employees into WBS. See Note 4, Related Parties, for more information . The intrinsic value of WEC Energy Group restricted stock held by our employees that was released was $0.4 million , $2.7 million , and $2.3 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $0.2 million , $1.1 million , and $0.9 million , respectively. As of December 31, 2016 , our estimated unrecognized compensation cost related to WEC Energy Group restricted stock was not significant. During the first quarter of 2017 , the Compensation Committee awarded 8,001 WEC Energy Group restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $58.10 per share. Performance Units In 2016 , 2015 , and 2014 , the Compensation Committee awarded 35,700 ; 187,450 ; and 224,735 WEC Energy Group performance units, respectively, to our officers and other key employees under the WEC Energy Group Performance Unit Plan. In 2016, we transferred 573,499 performance units to WBS in connection with the transfer of certain employees. See Note 4, Related Parties, for more information . Performance units with an intrinsic value of $3.4 million , $11.6 million , and $13.1 million were settled during 2016 , 2015 , and 2014 , respectively. The actual tax benefit realized for the tax deductions from the distribution of performance units for the same years was approximately $0.5 million , $4.2 million , and $4.7 million , respectively. As of December 31, 2016 , we expect to recognize approximately $4.4 million of unrecognized compensation cost related to WEC Energy Group performance units over the next 1.4 years on a weighted-average basis. During the first quarter of 2017 , performance units held by our employees with an intrinsic value of $1.4 million were settled. The actual tax benefit realized from the distribution of these awards was $0.4 million . In January 2017, the Compensation Committee also awarded 34,765 WEC Energy Group performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. Restrictions Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans or advances. In addition, under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to WEC Energy Group. In accordance with our most recent rate order, we may not pay common dividends above the test year forecasted amount reflected in our rate case, if it would cause our average common equity ratio, on a financial basis, to fall below our authorized level of 51% . A return of capital in excess of the test year amount can be paid by us at the end of the year provided that our average common equity ratio does not fall below the authorized level. We may not pay common dividends to WEC Energy Group under our Restated Articles of Incorporation if any dividends on our outstanding preferred stock have not been paid. In addition, pursuant to the terms of our 3.60% Serial Preferred Stock, our ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if our common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20% , respectively. See Note 12, Short-Term Debt and Lines of Credit , for discussion of certain financial covenants related to short-term debt obligations. As of December 31, 2016 , our restricted retained earnings totaled $1.9 billion . Our equity in undistributed earnings of investees accounted for by the equity method was $142.2 million at December 31, 2016 . We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.

Preferred Stock

Preferred Stock	12 Months Ended
	Dec. 31, 2016
Class of Stock Disclosures [Abstract]
PREFERRED STOCK	PREFERRED STOCK The following table shows preferred stock authorized and outstanding at December 31, 2016 and 2015 : (in millions, except share and per share amounts) Shares Authorized Shares Outstanding Redemption Price Per Share Total $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 Cr

Short-Term Debt and Lines of Credit	12 Months Ended
	Dec. 31, 2016
Short-term Debt [Abstract]
SHORT-TERM DEBT AND LINES OF CREDIT	SHORT-TERM DEBT AND LINES OF CREDIT The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31: (in millions, except percentages) 2016 2015 Commercial paper Amount outstanding at December 31 $ 159.0 $ 144.0 Average interest rate on amounts outstanding at December 31 0.87 % 0.70 % Our average amount of commercial paper borrowings based on daily outstanding balances during 2016 was $110.0 million , with a weighted-average interest rate during the period of 0.54% . We have entered into a bank back-up credit facility to maintain short-term credit liquidity which, among other terms, requires us to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 65% . As of December 31, 2016 , we had approximately $323.0 million of available capacity under our bank back-up credit facility and $159.0 million of commercial paper outstanding that was supported by the credit facility. As of December 31, 2016 , our subsidiary had an $18.5 million note payable to WEC Energy Group with a weighted-average interest rate of 5.17% . The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility as of December 31 : (in millions) Maturity 2016 Revolving credit facility December 2020 $ 500.0 Less: Letters of credit issued inside credit facility $ 18.0 Commercial paper outstanding 159.0 Available capacity under existing agreement $ 323.0 This facility has a renewal provision for two one -year extensions, subject to lender approval. Our bank back-up credit facility contains customary covenants, including certain limitations on our ability to sell assets. The credit facility also contains 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.

Long-Term Debt and Capital Leas

Long-Term Debt and Capital Lease Obligations	12 Months Ended
	Dec. 31, 2016
Long-term Debt and Capital Lease Obligations [Abstract]
LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS	LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS See our statements of capitalization for details on our long-term debt. Debentures and Notes The following table shows the future maturities of our long-term debt outstanding (excluding obligations under capital leases) as of December 31, 2016 : (in millions) 2017 $ — 2018 250.0 2019 250.0 2020 — 2021 300.0 Thereafter 1,887.0 Total $ 2,687.0 We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense. We are the obligor under a series of tax-exempt pollution control refunding bonds with an outstanding principal amount of $80.0 million . In August 2009, we terminated a letter of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2016 , the repurchased bonds were still outstanding, but are not reported in our long-term debt or included in our capitalization statements since they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on this bond series and have it remarketed to third parties. A related bond series that had an outstanding principal amount of $67.0 million matured on August 1, 2016. Obligations Under Capital Leases We are the obligor under a power purchase contract with an unaffiliated third party and we lease power plants from We Power. Under capital lease accounting, we have recorded the leased plants and corresponding obligations under the capital leases on our balance sheets. We treat these agreements as operating leases for rate-making purposes. We record our minimum lease payments under the power purchase contract as purchased power expense on our income statements. We record the lease payments under our leases with We Power as rent expense in other operation and maintenance in our income statements. 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. See Note 7, Regulatory Assets and Liabilities, for more information on our plant related capital leases. Power Purchase Commitment In 1997, we entered into a 25 -year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MW of firm capacity from a natural gas-fired cogeneration facility, includes zero minimum energy requirements. When the contract expires in 2022 , we may, at our 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 record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our balance sheets. Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to approximately $78.5 million during 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $29.6 million as of December 31, 2016 , and will decrease to zero over the remaining life of the contract. Port Washington Generating Station We are leasing PWGS 1 and PWGS 2, two 545 MW natural gas-fired generation units which were placed in service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. The leased units and corresponding obligations for the units have been recorded at the estimated fair value of $704.2 million . We are amortizing the leased units on a straight-line basis over the original 25 -year term of the leases. The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $130.8 million in the year 2021 for PWGS 1 and to approximately $131.6 million in the year 2024 for PWGS 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases for the units was $636.1 million as of December 31, 2016 , and will decrease to zero over the remaining lives of the contracts. Elm Road Generating Station We are leasing ER 1, ER 2, and the common facilities, which are also utilized by our OC 5 through OC 8, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the 30 -year term of the leases. ER 1 and ER 2 were placed in service in February 2010 and January 2011, respectively. The leased units and corresponding capital lease obligations have been recorded at the estimated fair value of $2,053.5 million . The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $542.8 million in the year 2029 for ER 1 and to approximately $447.2 million in the year 2030 for ER 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases was $2,119.3 million as of December 31, 2016 , and will decrease to zero over the remaining lives of the contracts. We paid the following lease payments during 2016 , 2015 , and 2014 : (in millions) 2016 2015 2014 Long-term power purchase commitment $ 37.6 $ 36.2 $ 34.9 PWGS 82.4 103.8 99.2 ERGS 329.8 306.7 277.8 Total $ 449.8 $ 446.7 $ 411.9 The following table summarizes our capitalized leased facilities as of December 31: (in millions) 2016 2015 Long-term power purchase commitment Under capital lease $ 140.3 $ 140.3 Accumulated amortization (109.5 ) (103.9 ) Total long-term power purchase commitment $ 30.8 $ 36.4 PWGS Under capital lease $ 704.2 $ 692.5 Accumulated amortization (274.7 ) (245.7 ) Total PWGS $ 429.5 $ 446.8 ERGS Under capital lease $ 2,053.5 $ 2,043.9 Accumulated amortization (453.6 ) (385.4 ) Total ERGS $ 1,599.9 $ 1,658.5 Total leased facilities $ 2,060.2 $ 2,141.7 Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2016 are as follows: (in millions) Power Purchase Commitment PWGS ERGS Total 2017 $ 13.9 $ 102.7 $ 315.4 $ 432.0 2018 14.7 102.7 315.4 432.8 2019 15.5 102.7 315.4 433.6 2020 16.4 102.7 315.4 434.5 2021 17.2 102.7 315.4 435.3 Thereafter 7.6 1,020.2 5,828.7 6,856.5 Total minimum lease payments 85.3 1,533.7 7,405.7 9,024.7 Less: Estimated executory costs (39.9 ) — — (39.9 ) Net minimum lease payments 45.4 1,533.7 7,405.7 8,984.8 Less: Interest (15.8 ) (897.6 ) (5,286.4 ) (6,199.8 ) Present value of minimum lease payments 29.6 636.1 2,119.3 2,785.0 Less: Due currently (2.7 ) (13.9 ) (11.9 ) (28.5 ) Long-term obligations under capital lease $ 26.9 $ 622.2 $ 2,107.4 $ 2,756.5

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Income Tax Expense The following table is a summary of income tax expense for each of the years ended December 31: (in millions) 2016 2015 2014 Current tax expense $ 4.8 $ 33.1 $ 31.2 Deferred income taxes, net 207.3 180.0 192.5 Investment tax credit, net (1.1 ) (1.1 ) (1.1 ) Total income tax expense $ 211.0 $ 212.0 $ 222.6 Statutory Rate Reconciliation The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes and preferred dividend as a result of the following: 2016 2015 2014 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate Expected tax at statutory federal tax rates $ 201.4 35.0 % $ 205.7 35.0 % $ 209.8 35.0 % State income taxes net of federal tax benefit 31.8 5.5 % 31.0 5.3 % 33.0 5.5 % Production tax credits (16.5 ) (2.8 )% (17.8 ) (3.0 )% (17.4 ) (2.9 )% Domestic production activities deduction (7.8 ) (1.4 )% (7.8 ) (1.3 )% — — % AFUDC – Equity (1.5 ) (0.3 )% (2.0 ) (0.3 )% (1.5 ) (0.2 )% Investment tax credit restored (1.1 ) (0.2 )% (1.1 ) (0.2 )% (1.1 ) (0.2 )% Other, net 4.7 0.8 % 4.0 0.5 % (0.2 ) (0.1 )% Total income tax expense $ 211.0 36.6 % $ 212.0 36.0 % $ 222.6 37.1 % Deferred Income Tax Assets and Liabilities The components of deferred income taxes as of December 31 were as follows: (in millions) 2016 2015 Deferred tax assets Deferred revenues $ 207.2 $ 219.9 Future federal tax benefits 143.7 72.9 Employee benefits and compensation 77.6 103.2 Construction advances 20.0 17.7 Uncollectible account expense 16.1 14.3 Emission allowances 0.2 0.2 Other 70.9 48.7 Total deferred tax assets 535.7 476.9 Deferred tax liabilities Property-related 2,257.3 2,058.5 Investment in transmission affiliate 195.1 174.9 Employee benefits and compensation 179.3 164.6 Deferred transmission costs 93.1 76.7 Prepaid tax, insurance, and other 50.2 50.6 Other 94.0 61.6 Total deferred tax liabilities 2,869.0 2,586.9 Deferred tax liability, net $ 2,333.3 $ 2,110.0 Consistent with rate-making treatment, deferred taxes in the table above are offset for temporary differences that have related regulatory assets and liabilities. As of December 31, 2016, we had $82.8 million and $107.2 million of federal net operating loss and tax credit carryforwards resulting in deferred tax assets of $29.0 million and $107.2 million , respectively. These federal net operating loss and tax credit carryforwards begin to expire in 2031. We expect to have future taxable income sufficient to utilize these deferred tax assets. As of December 31, 2015, we had approximately $72.9 million of deferred tax assets associated with tax credit carryforwards. As of December 31, 2016 we had $149.9 million state net operating loss carryforwards resulting in deferred tax assets of $7.5 million . These state net operating loss carryforwards begin to expire in 2025. We expect to have future taxable income sufficient to utilize these deferred tax assets. Unrecognized Tax Benefits We previously adopted accounting guidance related to uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: (in millions) 2016 2015 Balance as of January 1 $ 6.1 $ 7.2 Reductions for tax positions of prior years (1.0 ) (1.1 ) Balance as of December 31 $ 5.1 $ 6.1 The amount of unrecognized tax benefits as of December 31, 2016 and 2015 excludes deferred tax assets related to uncertainty in income taxes of $5.1 million and $6.1 million , respectively. As of December 31, 2016 and 2015, there were no unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations. We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2016, 2015, and 2014, we recognized $0.2 million of interest expense, $0.1 million of interest income, and $0.3 million of interest expense, respectively, in our income statements. For the years ended December 31, 2016, 2015, and 2014, we recognized no penalties in our income statements. As of December 31, 2016 and 2015, we had $0.7 million and $0.6 million , respectively, of interest accrued on our balance sheets. Our primary tax jurisdictions include Federal and the state of Wisconsin. Currently, the tax years of 2013 through 2016 are subject to federal examination and the tax years 2012 through 2016 are subject to examination by the state of Wisconsin.

Employee Benefits

Employee Benefits	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFITS Pension and Other Postretirement Employee Benefits We participate in WEC Energy Group's defined benefit pension plans and OPEB plans that cover substantially all of our employees. We are responsible for our share of the plan assets and obligations. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. Our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets and obligations. 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, employees who started with us after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. New management employees hired after December 31, 2014 receive a 6% annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans. We use a year-end measurement date to measure the funded status of all of the 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 the pension and OPEB plans qualify as a regulatory asset. The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets: Pension Costs OPEB Costs (in millions) 2016 2015 2016 2015 Change in benefit obligation Obligation at January 1 $ 1,290.6 $ 1,315.2 $ 313.8 $ 322.3 Service cost 10.5 14.7 7.3 9.0 Interest cost 49.7 52.9 13.2 13.4 Participant contributions — — 8.8 8.8 Plan amendments (2.6 ) — — — Transfer to affiliates * (121.1 ) (2.4 ) (17.0 ) — Actuarial loss (gain) 25.3 (11.5 ) (9.7 ) (22.3 ) Benefit payments (75.4 ) (78.3 ) (19.0 ) (18.7 ) Federal subsidy on benefits paid N/A N/A 1.1 1.3 Obligation at December 31 $ 1,177.0 $ 1,290.6 $ 298.5 $ 313.8 Change in fair value of plan assets Fair value at January 1 $ 1,179.3 $ 1,160.0 $ 216.1 $ 224.9 Actual return on plan assets 73.0 (7.8 ) 13.5 (1.5 ) Employer contributions 5.3 105.0 2.7 2.6 Participant contributions — — 8.8 8.8 Transfer to/from affiliates * (79.4 ) 0.4 (17.0 ) — Benefit payments (75.4 ) (78.3 ) (19.0 ) (18.7 ) Fair value at December 31 $ 1,102.8 $ 1,179.3 $ 205.1 $ 216.1 Funded status at December 31 $ (74.2 ) $ (111.3 ) $ (93.4 ) $ (97.7 ) * Benefit obligations and plan assets were moved along with our employees who were transferred to/from affiliated entities. See Note 4, Related Parties, for more information . The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows: Pension Costs OPEB Costs (in millions) 2016 2015 2016 2015 Other long-term assets $ — $ — $ — $ 1.9 Pension and OPEB obligations 74.2 111.3 93.4 99.6 Total net liabilities $ (74.2 ) $ (111.3 ) $ (93.4 ) $ (97.7 ) The accumulated benefit obligation for all defined benefit pension plans was $1,175.8 million and $1,287.5 million as of December 31, 2016 and 2015 , 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) 2016 2015 Projected benefit obligation $ 1,177.0 $ 1,290.2 Accumulated benefit obligation 1,175.8 1,289.5 Fair value of plan assets 1,102.8 1,178.9 The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31: Pension Costs OPEB Costs (in millions) 2016 2015 2016 2015 Net regulatory assets Net actuarial loss $ 518.5 $ 520.9 $ 4.6 $ 14.7 Prior service cost (credit) 0.2 4.3 (3.0 ) (4.1 ) Total $ 518.7 $ 525.2 $ 1.6 $ 10.6 The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2017: (in millions) Pension Costs OPEB Costs Net actuarial loss $ 35.4 $ 1.0 Prior service costs (credits) 1.1 (1.1 ) Total 2017 – estimated amortization $ 36.5 $ (0.1 ) The components of net periodic benefit cost (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows: Pension Costs OPEB Costs (in millions) 2016 2015 2014 2016 2015 2014 Service cost $ 10.5 $ 14.7 $ 9.4 $ 7.3 $ 9.0 $ 8.1 Interest cost 49.7 52.9 59.3 13.2 13.4 14.4 Expected return on plan assets (77.7 ) (83.6 ) (79.1 ) (14.0 ) (16.0 ) (16.2 ) Amortization of prior service cost (credit) 1.6 2.0 2.0 (1.1 ) (1.1 ) (1.7 ) Amortization of net actuarial loss 32.4 35.6 26.9 1.0 1.0 0.2 Net periodic benefit cost $ 16.5 $ 21.6 $ 18.5 $ 6.4 $ 6.3 $ 4.8 The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension OPEB 2016 2015 2016 2015 Discount rate 4.15% 4.45% 4.20% 4.45% Rate of compensation increase 3.20% 4.00% N/A N/A Assumed medical cost trend rate N/A N/A 7.00% 7.50% Ultimate trend rate N/A N/A 5.00% 5.00% Year ultimate trend rate is reached N/A N/A 2021 2021 The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Costs 2016 2015 2014 Discount rate 4.45% 4.15% 5.00% Expected return on plan assets 7.00% 7.00% 7.25% Rate of compensation increase 3.50% 4.00% 4.00% OPEB Costs 2016 2015 2014 Discount rate 4.45% 4.20% 4.95% Expected return on plan assets 7.25% 7.25% 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 WEC Energy Group consults with its investment advisors on an annual basis to help forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund. For 2017, the expected return on assets assumption is 7.00% for the pension plan and 7.25% for the OPEB plan. Assumed health care cost trend rates have a significant effect on the amounts reported by us for the health care plans. For the year ended December 31, 2016 , a one-percentage-point change in assumed health care cost trend rates would have had the following effects: (in millions) 1% Increase 1% Decrease Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $ 2.9 $ (2.3 ) Effect on the health care component of the accumulated postretirement benefit obligation 31.5 (26.0 ) 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. Our pension trust target asset allocation is 35% equity investments, 55% fixed income investments, and 10% private equity and real estate investments. The OPEB trusts' target asset allocations are 60% equity investments and 40% fixed income investments. Equity securities include investments in large-cap, mid-cap, and small-cap companies primarily located in the United States. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and United States Treasuries. Pension and OPEB plan investments are recorded at fair value. See Note 1(n), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used. Following our adoption of ASU 2015-07 on January 1, 2016, the assets that are not subject to leveling are investments that are valued using the net asset value per share (or its equivalent) practical expedient. We have applied this approach retrospectively to the 2015 table for comparability. The following table summarizes the fair values of our investments by asset class: December 31, 2016 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ 1.1 $ 19.2 $ — $ 20.3 $ 6.5 $ 1.3 $ — $ 7.8 Equity securities: Unites States Equity 85.5 0.1 — 85.6 10.5 — — 10.5 International Equity 17.7 — — 17.7 1.3 — — 1.3 Fixed income securities: * United States Bonds — 455.3 — 455.3 — 44.0 — 44.0 International Bonds — 31.6 — 31.6 — 2.8 — 2.8 Private Equity and Real Estate — — 11.0 11.0 — — 0.7 0.7 $ 104.3 $ 506.2 $ 11.0 $ 621.5 $ 18.3 $ 48.1 $ 0.7 $ 67.1 Investments measured at net asset value $ 481.3 $ 138.0 Total $ 104.3 $ 506.2 $ 11.0 $ 1,102.8 $ 18.3 $ 48.1 $ 0.7 $ 205.1 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2015 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ 15.5 $ — $ — $ 15.5 $ 2.4 $ — $ — $ 2.4 Equity securities: United States equity 80.1 — — 80.1 11.8 — — 11.8 International equity 25.8 — — 25.8 1.7 — — 1.7 Fixed income securities: * United States bonds — 509.4 — 509.4 — 78.1 — 78.1 International bonds — 32.6 — 32.6 — 4.5 — 4.5 Private Equity and Real Estate — — 4.5 4.5 — — 0.3 0.3 $ 121.4 $ 542.0 $ 4.5 $ 667.9 $ 15.9 $ 82.6 $ 0.3 $ 98.8 Investments measured at net asset value $ 511.4 $ 117.3 Total $ 121.4 $ 542.0 $ 4.5 $ 1,179.3 $ 15.9 $ 82.6 $ 0.3 $ 216.1 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. The following tables set forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy: Private Equity and Real Estate (in millions) Pension OPEB Beginning balance at January 1, 2016 $ 4.5 $ 0.3 Purchases 6.5 0.4 Ending balance at December 31, 2016 $ 11.0 $ 0.7 Private Equity and Real Estate (in millions) Pension OPEB Beginning balance at January 1, 2015 $ — $ — Purchases 4.5 0.3 Ending balance at December 31, 2015 $ 4.5 $ 0.3 Cash Flows We expect to contribute $4.9 million to the pension plans in 2017 , dependent upon various factors affecting us, including our liquidity position and possible tax law changes. We do not expect to contribute to the OPEB plans in 2017 . The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB: (in millions) Pension Costs OPEB Costs 2017 $ 90.7 $ 13.3 2018 88.6 14.4 2019 86.6 15.3 2020 86.5 16.1 2021 82.7 16.8 2022-2026 381.1 89.3 Savings Plans We sponsor 401(k) savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. Total costs incurred under these plans were $10.4 million in 2016, and $13.0 million in both 2015 and 2014 .

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES We have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, operating leases, environmental matters, and enforcement and litigation matters. Unconditional Purchase Obligations We routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2016 . Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2017 2018 2019 2020 2021 Later Years Electric utility: Nuclear 2033 $ 9,599.8 $ 415.3 $ 420.1 $ 445.4 $ 475.1 $ 501.1 $ 7,342.8 Coal supply and transportation 2019 313.1 183.6 97.5 32.0 — — — Purchased power 2031 86.0 30.5 21.7 9.2 6.9 5.9 11.8 Natural gas utility supply and transportation 2024 217.2 56.3 49.3 43.0 31.5 17.9 19.2 Total $ 10,216.1 $ 685.7 $ 588.6 $ 529.6 $ 513.5 $ 524.9 $ 7,373.8 Operating Leases We lease property, plant, and equipment under various terms. The operating leases generally require us to pay property taxes, insurance premiums, and maintenance costs associated with the leased property. Many of our leases contain one of the following options upon the end of the lease term: (a) purchase the property at the current fair market value, or (b) exercise a renewal option, as set forth in the lease agreement. Rental expense attributable to operating leases was $5.0 million , $6.7 million , and $4.8 million in 2016 , 2015 , and 2014 , respectively. Future minimum payments under noncancelable operating leases are payable as follows: Year Ending December 31 Payments (in millions) 2017 $ 4.4 2018 3.3 2019 1.4 2020 1.3 2021 1.4 Later years 21.7 Total $ 33.5 Environmental Matters Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO 2 , NOx, fine particulates, mercury, and GHGs; water discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites. We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including: • the development of additional sources of renewable electric energy supply; • the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems; • the addition of emission control equipment to existing facilities to comply with ambient air quality standards and federal clean air rules; • the protection of wetlands and waterways, threatened and endangered species, and cultural resources associated with utility construction projects; • the retirement of old coal-fired power plants and conversion to modern, efficient, natural gas generation and super-critical pulverized coal generation; • the beneficial use of ash and other products from coal-fired and biomass generating units; and • the remediation of former manufactured gas plant sites. Air Quality Cross-State Air Pollution Rule In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of NOx and SO 2 that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation and trading plan. After several lawsuits and related appeals, in October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. The emissions budgets of Phase I of the rule applied in 2015 and 2016, while the Phase II emissions budgets discussed below apply to 2017 and beyond. In December 2015, the EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS and issued the final rule in September 2016. Starting in 2017, this rule requires reductions in the ozone season (May 1 through September 30) NOx emissions from power plants in 23 states in the eastern United States, including Wisconsin. The EPA updated Phase II CSAPR NOx ozone season budgets for electric generating units in the affected states. In the final rule, the EPA significantly increased the NOx ozone season budget from the proposed rule for Wisconsin starting in 2017. We believe we are well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule. Sulfur Dioxide National Ambient Air Quality Standards The EPA issued a revised 1-Hour SO 2 NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard. The final rule affords state agencies some latitude in rule implementation. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area. In March 2015, a federal court entered a consent decree between the EPA and the Sierra Club and others agreeing to specific actions related to implementing the revised standard for areas containing large sources emitting above a certain threshold level of SO 2 . The consent decree required the EPA to complete attainment designations for certain areas with large sources by no later than July 2016. SO 2 emissions from PIPP are above the consent decree emission threshold, which means that the Marquette area required action earlier than would otherwise have been required under the revised NAAQS. However, we were able to show through modeling that the area should be designated as attainment. In July 2016, the EPA finalized its recommendation and published a notice in the Federal Register designating Marquette County, Michigan as unclassified/attainment, effective September 2016. We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation. 8-Hour Ozone National Ambient Air Quality Standards The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released the final rule, which lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. For nonattainment areas, the state of Wisconsin will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020 and are in the process of reviewing and determining potential impacts resulting from this rule. We believe we are well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule. Mercury and Other Hazardous Air Pollutants In December 2011, the EPA issued the final MATS rule, which imposed stringent limitations on emissions of mercury and other hazardous air pollutants from coal and oil-fired electric generating units beginning in April 2015. In addition, both Wisconsin and Michigan have state mercury rules that require a 90% reduction of mercury; however, these rules are not in effect as long as MATS is in place. In June 2015, the Supreme Court ruled on a challenge to the MATS rule and remanded the case back to the D.C. Circuit Court of Appeals, ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule remains in effect until the D.C. Circuit Court of Appeals takes action on the EPA's April 2016 updated cost evaluation. We believe that our fleet is well positioned to comply with the final MATS rule and do not expect to incur any significant additional costs to comply with this regulation. The addition of a dry sorbent injection system for further control of mercury and acid gases at PIPP was placed into service in March 2016, allowing PIPP to be in compliance with MATS. Climate Change In 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the final rule for existing fossil-fueled generating units, numerous states (including Wisconsin and Michigan), trade associations, and private parties filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the Clean Power Plan until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. In addition, in February 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan. The D.C. Circuit Court of Appeals heard the case in September 2016. The final rule for existing fossil-fueled generating units seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39% , respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction. The building blocks used by the EPA to determine each state's emission reduction requirements include a combination of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources. We continue to evaluate possible reduction opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions, given the uncertain future of the Clean Power Plan and current fuel and technology markets. Our evaluation to date indicates that the Clean Power Plan, as well as current fuel markets and advances in technology, are not expected to result in significant additional compliance costs, including capital expenditures, but could impact how we operate our existing fossil-fueled power plants and biomass facility. However, the timelines for the 2022 through 2029 interim goals and the 2030 final goal for states, as well as all other aspects of the rule, likely will be changed due to the stay and subsequent legal proceedings. With the new Federal Executive Administration as of January 2017, the Clean Power Plan, or its successor, could be significantly changed from the final rule of October 2015. Notwithstanding the potential changes to the Clean Power Plan, addressing climate change is an integral component of our strategic planning process. We continue to reshape our portfolio of electric generation facilities with investments that will improve our environmental performance, including reduced GHG intensity of our operating fleet. As the regulation of GHG emissions takes shape, our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO 2 emissions by approximately 40% below 2005 levels by 2030. We continue to evaluate numerous options in order to meet our CO 2 reduction goal, such as increased utilization of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation. Draft Federal Plan and Model Trading Rules (Model Rules) were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for reconsideration of the EPA's final standards for existing, as well as for new, modified, and reconstructed generating units. A petition for reconsideration of the EPA's final standards for existing generating units was also submitted jointly by the Wisconsin utilities. Among other things, the petitions narrowly asked the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's CO 2 equivalent reduction goal by about 10% . In May 2016, the EPA denied the state of Wisconsin's petition for reconsideration related to new, modified, and reconstructed generating units, except that the EPA deferred the portion related to the treatment of biomass. The EPA has not issued decisions yet regarding the above referenced petitions for reconsideration of the final EPA standards for existing generating units. In December 2016, the EPA withdrew the draft Model Rules and accompanying draft documents from the review process and made working drafts available to the public. They are not final documents, are not signed by the Administrator, and will not be published in the Federal Register. The EPA’s docket will remain open, with the potential for completing the agency’s work on these materials and finalizing them at a later date. We are required to report our CO 2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2015 , we reported aggregated CO 2 equivalent emissions of approximately 25.3 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO 2 equivalent emissions of approximately 23.9 million metric tonnes to the EPA for 2016 . The level of CO 2 and other GHG emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO. We are also required to report CO 2 equivalent amounts related to the natural gas that our natural gas operations distribute and sell. For 2015 , we reported aggregated CO 2 equivalent emissions of approximately 3.8 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO 2 equivalent emissions of approximately 3.7 million metric tonnes to the EPA for 2016 . Water Quality Clean Water Act Cooling Water Intake Structure Rule In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake). The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities. Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities satisfy the IM BTA requirements. BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for PWGS, Pleasant Prairie Power Plant, PIPP, and OC 5 through OC 8. During 2017 and 2018, we will continue to complete studies and evaluate options to address the EM BTA requirements at our plants. With the exception of Pleasant Prairie Power Plant (which has 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. Based on discussions with the MDEQ, if we provide information about unit retirements with our next National Pollutant Discharge Elimination System permit application and then submit a signed certification by August 2017 stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived. Entrainment studies were recently completed at PIPP. See UMERC discussion in Note 20, Regulatory Environment , regarding the potential retirement of PIPP. We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation. Steam Electric Effluent Guidelines The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin and Michigan. This rule is being litigated in the United States Court of Appeals for the Fifth Circuit and may result in changes to the discharge requirements. The WDNR and MDEQ will continue to modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years . We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment will require additional zero liquid discharge or other advanced treatment capital improvements for the Oak Creek site and Pleasant Prairie facilities. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications will be required at OC 7, OC 8, and the Pleasant Prairie units. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $55 million to $75 million for these advanced treatment and bottom ash transport systems. A similar system would be required at PIPP if we were not expecting to retire the plant. See UMERC discussion in Note 20, Regulatory Environment , regarding the potential retirement of PIPP. Land Quality Manufactured Gas Plant Remediation We have identified sites at which we 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. We are responsible for the environmental remediation of these sites. 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. The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites. We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31: (in millions) 2016 2015 Regulatory assets $ 29.9 $ 16.9 Reserves for future remediation 19.0 5.6 Renewables, Efficiency, and Conservation Wisconsin Legislation In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. We have achieved a renewable energy percentage of 8.27% and met our compliance requirements by constructing various wind parks, a biomass facility, and by also relying on renewable energy purchases. We continue to review our renewable energy portfolios and acquire cost-effective renewables as needed to meet our requirements on an ongoing basis. The PSCW administers the renewable program related to Act 141, and we fund the program, along with other utilities, based on 1.2% of our annual operating revenues. Michigan Legislation In 2008, Michigan enacted Act 295, which required 10% of the state's energy to come from renewables by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. In December 2016, Michigan revised this legislation with Act 342, which requires additional renewable energy requirements beyond 2015. The new legislation retains the 10% renewable energy portfolio requirement for years 2016 through 2018, increases the requirement to 12.5% for years 2019 through 2020, and increases the requirement to 15.0% for 2021. We were in compliance with these requirements as of December 31, 2016 . The revised legislation continues to allow recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective. Enforcement and Litigation Matters We are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations. Paris Generating Station Units 1 and 4 Construction Permit In December 2013, Act 91 was signed into law in Wisconsin, creating a process by which the EPA and WDNR were able to revise the regulations and emissions rates applicable to Paris Generating Station Units 1 and 4. Act 91, along with a new construction permit, allowed those units to restart after a temporary outage. In October 2014, the Sierra Club filed for a contested case hearing with the WDNR challenging this permit. In February 2013, the Sierra Club also filed for a contested case hearing with the WDNR in connection with the administration order issued in this matter, which was granted. The Sierra Club has withdrawn the contested case hearing request, thereby concluding this matter.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 6.0 $ 0.8 $ — $ 6.8 Petroleum products contracts 0.2 — — 0.2 FTRs — — 3.1 3.1 Coal contracts — 1.9 — 1.9 Total derivative assets $ 6.2 $ 2.7 $ 3.1 $ 12.0 Derivative liabilities Natural gas contracts $ 0.1 $ — $ — $ 0.1 Petroleum products contracts 0.1 — — 0.1 Coal contracts — 0.5 — 0.5 Total derivative liabilities $ 0.2 $ 0.5 $ — $ 0.7 December 31, 2015 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.5 $ — $ — $ 0.5 Petroleum products contracts 1.2 — — 1.2 FTRs — — 1.6 1.6 Coal contracts — 2.0 — 2.0 Total derivative assets $ 1.7 $ 2.0 $ 1.6 $ 5.3 Derivative liabilities Natural gas contracts $ 9.2 $ 0.2 $ — $ 9.4 Petroleum products contracts 4.4 — — 4.4 Coal contracts — 7.6 — 7.6 Total derivative liabilities $ 13.6 $ 7.8 $ — $ 21.4 The derivative assets and liabilities listed in the tables above include options, 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 18, Derivative Instruments, for more information . The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: (in millions) 2016 2015 2014 Balance at the beginning of the period $ 1.6 $ 7.0 $ 3.5 Purchases 8.1 3.9 15.6 Settlements (6.6 ) (9.3 ) (12.1 ) Balance at the end of the period $ 3.1 $ 1.6 $ 7.0 Unrealized gains and losses on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through cost of sales on our 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: December 31, 2016 December 31, 2015 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 28.8 $ 30.4 $ 27.3 Long-term debt 2,661.1 2,923.4 2,658.8 2,888.2

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS The following table shows our derivative assets and derivative liabilities: December 31, 2016 December 31, 2015 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 6.3 $ 0.1 $ 0.5 $ 8.1 Petroleum products contracts 0.2 0.1 0.9 3.3 FTRs 3.1 — 1.6 — Coal contracts 1.5 0.5 1.7 3.4 Total other current $ 11.1 $ 0.7 $ 4.7 $ 14.8 Other long-term Natural gas contracts $ 0.5 $ — $ — $ 1.3 Petroleum products contracts — — 0.3 1.1 Coal contracts 0.4 — 0.3 4.2 Total other long-term $ 0.9 $ — $ 0.6 $ 6.6 Total $ 12.0 $ 0.7 $ 5.3 $ 21.4 Our estimated notional sales volumes and realized gains (losses) were as follows: December 31, 2016 December 31, 2015 December 31, 2014 (in millions) Volume Gains (Losses) Volume Gains (Losses) Volume Gains Natural gas contracts 35.3 Dth $ (12.3 ) 24.0 Dth $ (12.6 ) 21.4 Dth $ 4.0 Petroleum products contracts 10.3 gallons (2.6 ) 4.0 gallons (0.2 ) 9.2 gallons 0.5 FTRs 25.3 MWh 7.3 22.8 MWh 3.2 26.1 MWh 12.7 Total $ (7.6 ) $ (9.6 ) $ 17.2 At December 31, 2016 , we had received cash collateral of $3.4 million in our margin accounts, and at December 31, 2015 , we had posted cash collateral of $14.9 million in our margin accounts. The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2016 December 31, 2015 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 12.0 $ 0.7 $ 5.3 $ 21.4 Gross amount not offset on the balance sheet * (3.6 ) (0.2 ) (0.7 ) (13.5 ) Net amount $ 8.4 $ 0.5 $ 4.6 $ 7.9 * Includes cash collateral received of $3.4 million at December 31, 2016 , and cash collateral posted of $12.8 million at December 31, 2015 .

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2016
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis. This ASU focuses on the consolidation analysis for companies that are required to evaluate whether they should consolidate certain legal entities. It emphasizes the risk of loss when determining a controlling financial interest and amends the guidance for assessing how related party relationships affect the consolidation analysis of variable interest entities. We adopted the standard upon its effective date in the first quarter of 2016, and our adoption resulted in no changes to our disclosures or financial statement presentation. The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities. We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance. American Transmission Company As of December 31, 2016, we owned approximately 23% of ATC, a for-profit, transmission-only company regulated by the FERC and certain state regulatory commissions. However, effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. Prior to the transfer, ATC was a variable interest entity, but consolidation was not required since we were not ATC's primary beneficiary. We did not have the power to direct the activities that most significantly impacted ATC's economic performance. At December 31, 2016, we accounted for ATC as an equity method investment. See Note 5, Investment in American Transmission Company, for more information . The significant assets and liabilities related to ATC recorded on our balance sheets at December 31, 2016, included our equity investment and accounts payable. At December 31, 2016 , and 2015 , our equity investment was $402.0 million and $382.2 million , respectively, which approximated our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $20.0 million and $19.9 million of accounts payable due to ATC at December 31, 2016 , and 2015 , respectively, for network transmission services. Purchased Power Agreement We have identified a purchased power agreement that represents a variable interest. This agreement is for 236 MW of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately five years . We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the purchased power agreement. We have approximately $85.3 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the years ended December 31, 2016 , 2015 , and 2014 were $54.2 million , $53.6 million , and $53.0 million , respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

Regulatory Environment

Regulatory Environment	12 Months Ended
	Dec. 31, 2016
Regulated Operations [Abstract]
REGULATORY ENVIRONMENT	REGULATORY ENVIRONMENT 2015 Wisconsin Rate Order In May 2014, we applied to the PSCW for a biennial review of costs and rates. In December 2014, the PSCW approved the following rate adjustments, effective January 1, 2015: • A net bill increase related to non-fuel costs for our retail electric customers of approximately $2.7 million ( 0.1% ) in 2015. This amount reflected the receipt of SSR payments from MISO that were higher than we anticipated when we filed our rate request in May 2014, as well as an offset of $26.6 million related to a refund of prior fuel costs and the remainder of the proceeds from a Treasury Grant that we received in connection with our 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 our 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 our natural gas customers in 2015, with no rate adjustment in 2016. • A rate increase of approximately $0.5 million ( 2.0% ) for our 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 our Milwaukee County steam utility customers in 2015, with no rate adjustment in 2016. As a result of the sale of the MCPP, we no longer have any Milwaukee County steam utility customers. See Note 3, Dispositions, for more information about the sale of the MCPP. Our authorized ROE was set at 10.2% , and our common equity component remained at an average of 51% . The PSCW order reaffirmed the deferral of our 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 us, which included higher fixed charges to better match the related fixed costs of providing service. The PSCW order also authorized escrow accounting for SSR revenues because of the uncertainty of the actual revenues we will receive under the PIPP SSR agreements. Under escrow accounting, we record SSR revenues of $90.7 million a year. If actual SSR payments from MISO exceed $90.7 million a year, the difference is deferred and returned to customers, with interest, in a future rate case. If actual SSR payments from MISO are less than $90.7 million a year, the difference is deferred and will be recovered from customers with interest, in a future rate case. In January 2015, certain parties appealed a portion of the PSCW's final decision adopting our specific rate design changes, including new charges for customer-owned generation within our service territory. The Dane County Circuit Court, in its November 2015 order, ruled that there was not enough evidence provided in our 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 us. See Note 2, Acquisitions, for more information on this earnings sharing mechanism. 2013 Wisconsin Rate Order In March 2012, we initiated a rate proceeding with the PSCW. In December 2012, the PSCW approved the following rate adjustments, effective January 1, 2013: • A net bill increase related to non-fuel costs for our 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 our 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 our natural gas customers in 2013, with no rate adjustment in 2014. The rates reflected a $6.4 million reduction in bad debt expense. • An increase of approximately $1.3 million ( 6.0% ) for our 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 our Milwaukee County steam utility customers. Based on the PSCW order, our authorized ROE remained at 10.4% . In addition, the PSCW approved escrow accounting treatment for the Treasury Grant. The PSCW also determined the construction costs for the ERGS units were prudently incurred, and it approved the recovery of the majority of these costs in rates. Upper Michigan Energy Resources Corporation In December 2016, both the MPSC and the PSCW approved the operation of UMERC, a subsidiary of WEC Energy Group, as a stand-alone utility in the Upper Peninsula of Michigan and it became operational effective January 1, 2017. This utility holds our and WPS's electric and natural gas distribution assets located in the Upper Peninsula. In August 2016, WEC Energy Group entered into an agreement with the Tilden Mining Company (Tilden) under which it will purchase electric power from UMERC for its iron ore mine for 20 years . The agreement also calls for UMERC to construct and operate approximately 180 MW of natural gas-fired generation located in the Upper Peninsula of Michigan. On January 30, 2017, UMERC filed an application with the MPSC for a certificate of necessity to begin construction of the proposed generation. The estimated cost of this project is approximately $265 million ( $275 million with AFUDC), 50% of which is expected to be recovered from Tilden, with the remaining 50% expected to be recovered from utility customers located in the Upper Peninsula of Michigan. Subject to regulatory approval of both the agreement with Tilden and the construction of the proposed generation, the new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. Tilden will remain our customer until this new generation begins commercial operation.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
SEGMENT INFORMATION	SEGMENT INFORMATION During the second quarter of 2016, 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, 2016 , we reported two segments, which are described below. Our utility segment includes our electric and natural gas utility operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, northern Wisconsin, and the Upper Peninsula of Michigan. Effective January 1, 2017, we transferred all of our electric distribution assets and customers located in the Upper Peninsula of Michigan to UMERC, with the exception of the Tilden Mining Company. See Note 4, Related Parties , and Note 20, Regulatory Environment , for additional information. Our electric utility operations also include our steam operations which produce, distribute, and sell steam to customers in metropolitan Milwaukee, Wisconsin. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in our three service areas within southeastern, east central, and northern Wisconsin. At December 31, 2016 , our other segment included our approximate 23% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions, and Bostco, our non-utility subsidiary, that develops and invests in real estate. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 5, Investment in American Transmission Company, for more information . All of our operations and assets are located within the United States. The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2016 , 2015 , and 2014 . 2016 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Operating revenues $ 3,792.8 $ — $ 3,792.8 Other operation and maintenance 1,430.2 — 1,430.2 Depreciation and amortization 325.4 — 325.4 Operating income 629.5 — 629.5 Equity in earnings of transmission affiliate — 55.5 55.5 Interest expense 116.6 1.0 117.6 Capital expenditures 468.9 0.6 469.5 Total assets 12,945.1 426.4 13,371.5 2015 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Operating revenues $ 3,854.1 $ — $ 3,854.1 Other operation and maintenance 1,384.9 — 1,384.9 Depreciation and amortization 304.0 — 304.0 Operating income 648.9 — 648.9 Equity in earnings of transmission affiliate — 47.8 47.8 Interest expense 117.7 1.3 119.0 Capital expenditures 518.8 0.4 519.2 Total assets 12,727.6 412.0 13,139.6 2014 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Operating revenues $ 4,059.4 $ — $ 4,059.4 Other operation and maintenance 1,356.4 — 1,356.4 Depreciation and amortization 278.3 — 278.3 Operating income 650.4 — 650.4 Equity in earnings of transmission affiliate — 57.9 57.9 Interest expense 114.9 1.6 116.5 Capital expenditures 561.8 — 561.8 Total assets 12,195.9 401.3 12,597.2

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)	QUARTERLY FINANCIAL INFORMATION (Unaudited) (in millions) First Quarter Second Quarter Third Quarter Fourth Quarter Total 2016 Operating revenues $ 975.5 $ 877.2 $ 1,023.8 $ 916.3 $ 3,792.8 Operating income 181.5 146.9 196.4 104.7 629.5 Net income attributed to common shareholder 107.3 82.6 115.2 59.2 364.3 2015 Operating revenues $ 1,084.6 $ 883.0 $ 981.1 $ 905.4 $ 3,854.1 Operating income 204.7 128.7 169.8 145.7 648.9 Net income attributed to common shareholder 121.4 74.6 100.1 79.6 375.7 Due to various factors, the quarterly results of operations are not necessarily comparable.

New Accounting Pronouncements

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

Schedule II - Valuation and Qua

Schedule II - Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2016
Valuation and Qualifying Accounts [Abstract]
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS	SCHEDULE II WISCONSIN ELECTRIC POWER COMPANY VALUATION AND QUALIFYING ACCOUNTS Allowance for Doubtful Accounts (in millions) Balance at Beginning of Period Expense (1) Deferral Net Write-offs (2) Balance at End of Period December 31, 2016 $ 43.0 $ 31.1 $ (5.7 ) $ (27.5 ) $ 40.9 December 31, 2015 46.8 30.6 0.3 (34.7 ) 43.0 December 31, 2014 39.7 31.3 10.0 (34.2 ) 46.8 (1) Net of recoveries (2) Represents amounts written off to the reserve, net of adjustments to regulatory assets.

Summary of Significant Accoun32

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Nature of operations	On June 29, 2015, our parent company, Wisconsin Energy Corporation, acquired Integrys and changed its name to WEC Energy Group, Inc. See Note 2, Acquisitions, for more information on this acquisition. We are an electric, natural gas, and steam utility company that serves electric customers in Wisconsin and an iron ore mine owned by the Tilden Mining Company (Tilden) in the Upper Peninsula of Michigan, natural gas customers in Wisconsin, and steam customers in metropolitan Milwaukee, Wisconsin.
Consolidation	As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, statements of equity, and statements of capitalization, unless otherwise noted.
Investments	At December 31, 2016 , we had one wholly owned subsidiary, Bostco. Bostco had total assets of $24.4 million and $29.8 million as of December 31, 2016 and 2015 , respectively. The financial statements include our accounts and the accounts of our wholly owned subsidiary. 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.
Segment reporting	During the second quarter of 2016, 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. See Note 21, Segment Information, for more information on our business segments.
Use of estimates	We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.
Balance sheet presentation	To be consistent with the current year presentation, we changed our December 31, 2015 balance sheet from a utility format to a traditional format. This change revised the order of certain balance sheet line items, but it did not result in any change to the classification of amounts between line items.
Cash and cash equivalents	Cash and cash equivalents include marketable debt securities with an original maturity of three months or less.
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 we had in place that allowed us 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. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater ROE than authorized by the PSCW. • We received payments from MISO under an SSR agreement for our PIPP units through February 1, 2015. We recorded revenue for these payments to recover costs for operating and maintaining these units. See Note 20, Regulatory Environment , for more information. • Our natural gas utility rates included a one-for-one recovery mechanism 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. • Our residential rates included a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. Revenues are also impacted by other accounting policies related to our participation in the MISO Energy Markets. We 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 we were a net seller in a particular hour, the net amount was reported as operating revenues. If we were a net purchaser in a particular hour, the net amount was recorded as cost of sales on our income statements. We provide regulated electric, natural gas, and steam service to customers in Wisconsin and provided electric service to customers in the Upper Peninsula of Michigan through December 31, 2016. See Note 4, Related Parties , and Note 20, Regulatory Environment , for information regarding the transfer of our customers located in the Upper Peninsula of Michigan to UMERC as of January 1, 2017. 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. Our credit risk exposure is mitigated by our recovery mechanism for uncollectible expense discussed above. As a result, we did not have any significant concentrations of credit risk at December 31, 2016 . In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2016 .
Materials, supplies and inventories	Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting.
Regulatory assets and liabilities	The economic effects of regulation can result in regulated companies recording costs and revenues that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future revenues associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts that are collected in rates for future costs. Recovery or refund of regulatory assets and liabilities is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to which they relate. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the reporting period the determination is made. See Note 7, Regulatory Assets and Liabilities, for more information .
Property, plant, and equipment	We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. We record straight-line depreciation over the estimated useful life of utility property using depreciation rates approved by the PSCW and MPSC that include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 3.00% , 3.01% , and 2.93% in 2016 , 2015 , and 2014 , respectively. 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 5 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement. For assets other than our regulated assets and leased equipment, we accrue depreciation expense at straight-line rates over the estimated useful lives of the assets, or over the non-cancellable lease term for leased equipment.
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. Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 8.45% for 2016 and 2015 , and 9.09% for 2014 . Our average AFUDC wholesale rates were 2.73% , 1.72% , and 0.87% for 2016 , 2015 , and 2014 , respectively.
Asset retirement obligations	We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted to their present values each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated retirement costs. We recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 9, Asset Retirement Obligations, for more information .
Environmental remediation costs	We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 9, Asset Retirement Obligations, for more information regarding coal combustion product landfill sites and Note 16, Commitments and Contingencies , for more information regarding manufactured gas plant sites. We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation. We 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's 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 are included in WEC Energy Group's consolidated Federal and state income tax returns. In accordance with our tax allocation agreement with WEC Energy Group, we are allocated income tax payments and refunds based upon our separate tax computation. See Note 14, Income Taxes, for more information . We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense in our income statements.
Employee benefits	The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are allocated among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for our net periodic benefit cost calculated under GAAP. See Note 15, Employee Benefits, for more information .
Stock-based compensation	Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the shareholder approved Omnibus Stock Incentive Plan, WEC Energy Group provides a long-term incentive through its equity interests to its non-employee directors, selected officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. The number of shares of WEC Energy Group common stock authorized for issuance under the plan is 34.3 million . Stock-based compensation expense is allocated to us based on the outstanding awards held by our employees and our allocation of labor costs. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period based on an estimate of the final expected value of the awards. Stock Options Our employees are granted WEC Energy Group 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 the fair market value of WEC Energy Group common stock on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of WEC Energy Group common stock on the date of 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. WEC Energy Group stock options are classified as equity awards. The fair value of each stock option was calculated using a binomial option-pricing model. The following table shows the estimated fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models: 2016 2015 2014 Non-qualified stock options granted * 92,880 495,550 864,860 Estimated fair value per non-qualified stock option $ 4.92 $ 5.29 $ 4.18 Risk-free interest rate 0.5% – 2.2% 0.1% – 2.1% 0.1% – 3.0% Dividend yield 4.0 % 3.7 % 3.8 % Expected volatility 18.0 % 18.0 % 18.0 % Expected life (years) 5.8 5.8 5.8 * Effective January 1, 2016, certain of our employees were transferred into WBS. See Note 4, Related Parties, for more information . The risk-free interest rate is based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on WEC Energy Group's current dividend rate and historical stock prices. Expected volatility and expected life assumptions were based on WEC Energy Group's historical experience. Restricted Shares WEC Energy Group restricted shares have a three -year vesting period, and generally, one-third of the award vests on each anniversary of the grant date. The restricted shares are classified as equity awards. Performance Units Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on WEC Energy Group's total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over a three -year period, and beginning in 2017, other performance metrics as determined by the Compensation Committee. Participants may earn between 0% and 175% of the base performance unit award, as adjusted pursuant to the terms of the plan. All grants are settled in cash and are accounted for as liability awards accordingly. Stock-based compensation costs are recorded over the three -year performance period.
Fair value measurements	Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. We recognize transfers at their value as of the end of the reporting period. Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a dividend discount model. The fair value of our long-term debt is estimated based upon the quoted market value for the same or similar issues. The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.
Derivative instruments	We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW. We record derivative instruments on our balance sheets as assets or liabilities measured at fair value, unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Realized gains and losses on derivative instruments are primarily recorded in cost of sales on our income statements. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows. Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current liabilities.
Customer deposits and credit balances	When utility customers apply for new service, they may be required to provide a deposit for the service. Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets.

Summary of Significant Accoun33

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Schedule of inventory	Our inventory as of December 31 consisted of: (in millions) 2016 2015 Materials and supplies $ 148.1 $ 151.1 Fossil fuel 91.1 110.5 Natural gas in storage 31.8 40.0 Total $ 271.0 $ 301.6
Allowance for funds used during construction	We recorded the following AFUDC for the years ended December 31: (in millions) 2016 2015 2014 AFUDC – Debt $ 1.7 $ 2.2 $ 1.8 AFUDC – Equity $ 4.2 $ 5.7 $ 4.4
Schedule of assumptions used to estimate the fair value of stock options granted	The following table shows the estimated fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models: 2016 2015 2014 Non-qualified stock options granted * 92,880 495,550 864,860 Estimated fair value per non-qualified stock option $ 4.92 $ 5.29 $ 4.18 Risk-free interest rate 0.5% – 2.2% 0.1% – 2.1% 0.1% – 3.0% Dividend yield 4.0 % 3.7 % 3.8 % Expected volatility 18.0 % 18.0 % 18.0 % Expected life (years) 5.8 5.8 5.8 * Effective January 1, 2016, certain of our employees were transferred into WBS. See Note 4, Related Parties, for more information .

Related Parties (Tables)

Related Parties (Tables)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Schedule of activity associated with related party transactions	The following table shows activity associated with our related party transactions for the years ended December 31: (in millions) 2016 2015 2014 Lease agreements Lease payments to We Power (1) $ 412.2 $ 410.5 $ 389.0 CWIP billed to We Power 37.9 58.8 41.0 Transactions with WBS (2) Billings to WBS (3) 213.8 11.1 — Billings from WBS (4) 310.6 1.3 — Transactions with WPS (2) Billings to WPS 9.0 13.4 — Billings from WPS 4.2 4.9 — Transactions with WG Natural gas purchases from WG 5.3 5.3 6.6 Services received from WG 21.5 23.5 20.6 Services provided to WG 60.6 79.4 81.7 (1) We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS 1, PWGS 2, ER 1, and ER 2. (2) Includes amounts billed for services, pass through costs, and other items in accordance with the approved AIAs discussed above. (3) Includes $13.1 million for the transfer of certain software assets to WBS for the year ended December 31, 2016. (4) Includes $116.0 million for the transfer of certain benefit-related liabilities to WBS for the year ended December 31, 2016.

Investment in American Transm35

Investment in American Transmission Company (Tables)	12 Months Ended
	Dec. 31, 2016
Investment in ATC
Schedule of significant transactions with ATC	The following table shows activity associated with our related party transactions for the years ended December 31: (in millions) 2016 2015 2014 Lease agreements Lease payments to We Power (1) $ 412.2 $ 410.5 $ 389.0 CWIP billed to We Power 37.9 58.8 41.0 Transactions with WBS (2) Billings to WBS (3) 213.8 11.1 — Billings from WBS (4) 310.6 1.3 — Transactions with WPS (2) Billings to WPS 9.0 13.4 — Billings from WPS 4.2 4.9 — Transactions with WG Natural gas purchases from WG 5.3 5.3 6.6 Services received from WG 21.5 23.5 20.6 Services provided to WG 60.6 79.4 81.7 (1) We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS 1, PWGS 2, ER 1, and ER 2. (2) Includes amounts billed for services, pass through costs, and other items in accordance with the approved AIAs discussed above. (3) Includes $13.1 million for the transfer of certain software assets to WBS for the year ended December 31, 2016. (4) Includes $116.0 million for the transfer of certain benefit-related liabilities to WBS for the year ended December 31, 2016.
ATC
Investment in ATC
Schedule of changes to our investment in ATC	The following table shows changes to our investment in ATC during the years ended December 31: (in millions) 2016 2015 2014 Balance at beginning of period $ 382.2 $ 372.9 $ 354.1 Add: Earnings from equity method investment 55.5 47.8 57.9 Add: Capital contributions 16.1 4.6 11.5 Less: Distributions 51.7 * 42.9 50.5 Less: Other 0.1 0.2 0.1 Balance at end of period $ 402.0 $ 382.2 $ 372.9 * Of this amount, $13.4 million was recorded as a receivable at December 31, 2016.
Schedule of significant transactions with ATC	The following table summarizes our significant related party transactions with ATC during the years ended December 31: (in millions) 2016 2015 2014 Charges to ATC for services and construction $ 10.0 $ 9.7 $ 8.1 Charges from ATC for network transmission services 247.8 238.5 231.4
Schedule of receivables and payables with ATC	As of December 31, 2016 and 2015 , our balance sheets included the following receivables and payables related to ATC: (in millions) 2016 2015 Accounts receivable Services provided to ATC $ 1.1 $ 0.6 Accounts payable Services received from ATC 20.0 19.9
Schedule of summarized income statement data for ATC	Summarized financial data for ATC is included in the tables below: (in millions) 2016 2015 2014 Income statement data Revenues $ 650.8 $ 615.8 $ 635.0 Operating expenses 322.5 319.3 307.4 Other expense 95.5 96.1 88.9 Net income $ 232.8 $ 200.4 $ 238.7
Schedule of summarized balance sheet data for ATC	(in millions) December 31, 2016 December 31, 2015 Balance sheet data Current assets $ 75.8 $ 80.5 Noncurrent assets 4,312.9 3,948.3 Total assets $ 4,388.7 $ 4,028.8 Current liabilities $ 495.1 $ 330.3 Long-term debt 1,865.3 1,790.7 Other noncurrent liabilities 271.5 245.0 Shareholders' equity 1,756.8 1,662.8 Total liabilities and shareholders' equity $ 4,388.7 $ 4,028.8

Supplemental Cash Flow Inform36

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	(in millions) 2016 2015 2014 Cash (paid) for interest, net of amount capitalized $ (116.2 ) $ (116.2 ) $ (117.9 ) Cash received (paid) for income taxes, net 100.2 (58.5 ) (20.8 ) Significant non-cash transactions: Accounts payable related to construction costs 9.1 11.7 1.7

Regulatory Assets and Liabili37

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets	The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2016 2015 See Note Regulatory assets (1) (2) Plant related – capital leases $ 724.8 $ 674.4 13 Unrecognized pension and OPEB costs (3) 520.3 535.8 15 Electric transmission costs 231.9 191.5 20 Income tax related items (4) 200.8 177.4 SSR 188.1 86.1 20 We Power generation (5) 54.1 45.4 AROs 39.7 36.3 9 Energy efficiency programs (6) 38.5 50.7 Other, net 38.4 58.3 Total regulatory assets $ 2,036.6 $ 1,855.9 (1) Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in the table. (2) As of December 31, 2016 , we had $10.4 million of regulatory assets not earning a return and $204.0 million of regulatory assets earning a return based on short-term interest rates. The regulatory assets not earning a return relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures. (3) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We are authorized recovery of this regulatory asset over the average remaining service life of each plan. (4) Represents adjustments related to deferred income taxes, which are recovered in rates as the temporary differences that generated the income tax benefit reverse. (5) Represents amounts recoverable from customers related to our costs of the generating units leased from We Power, including subsequent capital additions. (6) Represents amounts recoverable from customers related to programs designed to meet energy efficiency standards.
Schedule of Regulatory Liabilities	The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2016 2015 Regulatory liabilities Removal costs (1) $ 722.9 $ 696.9 Mines deferral (2) 70.2 31.6 Other, net 71.0 12.7 Total regulatory liabilities $ 864.1 $ 741.2 Balance Sheet Presentation Other current liabilities $ 10.2 $ — Regulatory liabilities 853.9 741.2 Total regulatory liabilities $ 864.1 $ 741.2 (1) Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment. (2) Represents the deferral of revenues less the associated cost of sales related to 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.

Property, Plant, and Equipment

Property, Plant, and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	Property, plant, and equipment consisted of the following utility and non-utility and other assets at December 31: (in millions) 2016 2015 Utility property, plant, and equipment $ 11,232.9 $ 10,863.1 Less: Accumulated depreciation 3,606.9 3,447.2 Net 7,626.0 7,415.9 CWIP 111.5 170.3 Net utility property, plant, and equipment 7,737.5 7,586.2 Property under capital leases 2,898.0 2,876.7 Less: Accumulated amortization 837.8 735.0 Net leased facilities 2,060.2 2,141.7 Non-utility and other property, plant, and equipment 46.4 54.0 Less: Accumulated depreciation 12.7 14.7 Net 33.7 39.3 CWIP 0.9 0.3 Net non-utility and other property, plant, and equipment 34.6 39.6 Total property, plant, and equipment $ 9,832.3 $ 9,767.5

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule of changes to asset retirement obligations	The following table shows changes to our AROs during the years ended December 31: (in millions) 2016 2015 2014 Balance as of January 1 $ 58.7 $ 40.5 $ 39.4 Accretion 3.0 2.3 2.2 Additions — 15.9 * — Liabilities settled (0.2 ) — (1.1 ) Balance as of December 31 $ 61.5 $ 58.7 $ 40.5 * During 2015, an ARO was recorded for the fly-ash landfills located at our generation facilities.

Common Equity (Tables)

Common Equity (Tables)	12 Months Ended
	Dec. 31, 2016
Stockholders' Equity Note [Abstract]
Schedule of stock-based compensation expense and related deferred tax benefit recognized in income	The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit for the years ended December 31: (in millions) 2016 2015 2014 Stock options $ 1.8 $ 3.2 $ 3.6 Restricted stock 1.8 2.1 2.1 Performance units 3.9 7.5 12.7 Stock-based compensation expense $ 7.5 $ 12.8 $ 18.4 Related tax benefit $ 3.0 $ 5.1 $ 7.4
Schedule of stock option activity	The following is a summary of our employees' WEC Energy Group stock option activity during 2016 : Stock Options Number of Options Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life (in years) Aggregate Intrinsic Value (in millions) Outstanding as of January 1, 2016 5,687,714 $ 33.58 Granted 92,880 $ 50.93 Exercised (439,043 ) $ 27.57 Transferred * (4,055,745 ) $ 34.68 Outstanding as of December 31, 2016 1,285,806 $ 33.41 4.6 $ 32.4 Exercisable as of December 31, 2016 1,010,061 $ 29.64 3.7 $ 29.3 * Relates to the transfer of certain employees into WBS. See Note 4, Related Parties, for more information .
Schedule of restricted stock activity	Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding as of January 1, 2016 175,443 $ 47.66 Granted 8,049 $ 51.78 Released (7,901 ) $ 44.66 Transferred * (158,635 ) $ 47.73 Forfeited (695 ) $ 50.42 Outstanding as of December 31, 2016 16,261 $ 50.39 * Relates to the transfer of certain employees into WBS. See Note 4, Related Parties, for more information .

Preferred Stock (Tables)

Preferred Stock (Tables)	12 Months Ended
	Dec. 31, 2016
Class of Stock Disclosures [Abstract]
Schedule of stock by class	The following table shows preferred stock authorized and outstanding at December 31, 2016 and 2015 : (in millions, except share and per share amounts) Shares Authorized Shares Outstanding Redemption Price Per Share Total $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 42

Short-Term Debt and Lines of Credit (Tables)	12 Months Ended
	Dec. 31, 2016
Short-term Debt [Line Items]
Short-term notes payable balances and their corresponding weighted-average interest rates	The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31: (in millions, except percentages) 2016 2015 Commercial paper Amount outstanding at December 31 $ 159.0 $ 144.0 Average interest rate on amounts outstanding at December 31 0.87 % 0.70 %
Schedule of Revolving Credit Facilities	The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility as of December 31 : (in millions) Maturity 2016 Revolving credit facility December 2020 $ 500.0 Less: Letters of credit issued inside credit facility $ 18.0 Commercial paper outstanding 159.0 Available capacity under existing agreement $ 323.0

Long-Term Debt and Capital Le43

Long-Term Debt and Capital Lease Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Long-term Debt and Capital Lease Obligations [Abstract]
Long-term debt outstanding maturities	The following table shows the future maturities of our long-term debt outstanding (excluding obligations under capital leases) as of December 31, 2016 : (in millions) 2017 $ — 2018 250.0 2019 250.0 2020 — 2021 300.0 Thereafter 1,887.0 Total $ 2,687.0
Capital lease payments	We paid the following lease payments during 2016 , 2015 , and 2014 : (in millions) 2016 2015 2014 Long-term power purchase commitment $ 37.6 $ 36.2 $ 34.9 PWGS 82.4 103.8 99.2 ERGS 329.8 306.7 277.8 Total $ 449.8 $ 446.7 $ 411.9
Summary of capitalized leased facilities	The following table summarizes our capitalized leased facilities as of December 31: (in millions) 2016 2015 Long-term power purchase commitment Under capital lease $ 140.3 $ 140.3 Accumulated amortization (109.5 ) (103.9 ) Total long-term power purchase commitment $ 30.8 $ 36.4 PWGS Under capital lease $ 704.2 $ 692.5 Accumulated amortization (274.7 ) (245.7 ) Total PWGS $ 429.5 $ 446.8 ERGS Under capital lease $ 2,053.5 $ 2,043.9 Accumulated amortization (453.6 ) (385.4 ) Total ERGS $ 1,599.9 $ 1,658.5 Total leased facilities $ 2,060.2 $ 2,141.7
Future minimum lease payments under capital lease and present value of net minimum lease payments	Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2016 are as follows: (in millions) Power Purchase Commitment PWGS ERGS Total 2017 $ 13.9 $ 102.7 $ 315.4 $ 432.0 2018 14.7 102.7 315.4 432.8 2019 15.5 102.7 315.4 433.6 2020 16.4 102.7 315.4 434.5 2021 17.2 102.7 315.4 435.3 Thereafter 7.6 1,020.2 5,828.7 6,856.5 Total minimum lease payments 85.3 1,533.7 7,405.7 9,024.7 Less: Estimated executory costs (39.9 ) — — (39.9 ) Net minimum lease payments 45.4 1,533.7 7,405.7 8,984.8 Less: Interest (15.8 ) (897.6 ) (5,286.4 ) (6,199.8 ) Present value of minimum lease payments 29.6 636.1 2,119.3 2,785.0 Less: Due currently (2.7 ) (13.9 ) (11.9 ) (28.5 ) Long-term obligations under capital lease $ 26.9 $ 622.2 $ 2,107.4 $ 2,756.5

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Summary of income tax expense	The following table is a summary of income tax expense for each of the years ended December 31: (in millions) 2016 2015 2014 Current tax expense $ 4.8 $ 33.1 $ 31.2 Deferred income taxes, net 207.3 180.0 192.5 Investment tax credit, net (1.1 ) (1.1 ) (1.1 ) Total income tax expense $ 211.0 $ 212.0 $ 222.6
Statutory rate reconciliation	The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes and preferred dividend as a result of the following: 2016 2015 2014 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate Expected tax at statutory federal tax rates $ 201.4 35.0 % $ 205.7 35.0 % $ 209.8 35.0 % State income taxes net of federal tax benefit 31.8 5.5 % 31.0 5.3 % 33.0 5.5 % Production tax credits (16.5 ) (2.8 )% (17.8 ) (3.0 )% (17.4 ) (2.9 )% Domestic production activities deduction (7.8 ) (1.4 )% (7.8 ) (1.3 )% — — % AFUDC – Equity (1.5 ) (0.3 )% (2.0 ) (0.3 )% (1.5 ) (0.2 )% Investment tax credit restored (1.1 ) (0.2 )% (1.1 ) (0.2 )% (1.1 ) (0.2 )% Other, net 4.7 0.8 % 4.0 0.5 % (0.2 ) (0.1 )% Total income tax expense $ 211.0 36.6 % $ 212.0 36.0 % $ 222.6 37.1 %
Components of deferred income taxes	The components of deferred income taxes as of December 31 were as follows: (in millions) 2016 2015 Deferred tax assets Deferred revenues $ 207.2 $ 219.9 Future federal tax benefits 143.7 72.9 Employee benefits and compensation 77.6 103.2 Construction advances 20.0 17.7 Uncollectible account expense 16.1 14.3 Emission allowances 0.2 0.2 Other 70.9 48.7 Total deferred tax assets 535.7 476.9 Deferred tax liabilities Property-related 2,257.3 2,058.5 Investment in transmission affiliate 195.1 174.9 Employee benefits and compensation 179.3 164.6 Deferred transmission costs 93.1 76.7 Prepaid tax, insurance, and other 50.2 50.6 Other 94.0 61.6 Total deferred tax liabilities 2,869.0 2,586.9 Deferred tax liability, net $ 2,333.3 $ 2,110.0
Reconciliation of unrecognized tax benefits	We previously adopted accounting guidance related to uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: (in millions) 2016 2015 Balance as of January 1 $ 6.1 $ 7.2 Reductions for tax positions of prior years (1.0 ) (1.1 ) Balance as of December 31 $ 5.1 $ 6.1

Employee Benefits (Tables)

Employee Benefits (Tables)	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Reconciliation of the changes in the plans' benefit obligations and fair value of assets	The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets: Pension Costs OPEB Costs (in millions) 2016 2015 2016 2015 Change in benefit obligation Obligation at January 1 $ 1,290.6 $ 1,315.2 $ 313.8 $ 322.3 Service cost 10.5 14.7 7.3 9.0 Interest cost 49.7 52.9 13.2 13.4 Participant contributions — — 8.8 8.8 Plan amendments (2.6 ) — — — Transfer to affiliates * (121.1 ) (2.4 ) (17.0 ) — Actuarial loss (gain) 25.3 (11.5 ) (9.7 ) (22.3 ) Benefit payments (75.4 ) (78.3 ) (19.0 ) (18.7 ) Federal subsidy on benefits paid N/A N/A 1.1 1.3 Obligation at December 31 $ 1,177.0 $ 1,290.6 $ 298.5 $ 313.8 Change in fair value of plan assets Fair value at January 1 $ 1,179.3 $ 1,160.0 $ 216.1 $ 224.9 Actual return on plan assets 73.0 (7.8 ) 13.5 (1.5 ) Employer contributions 5.3 105.0 2.7 2.6 Participant contributions — — 8.8 8.8 Transfer to/from affiliates * (79.4 ) 0.4 (17.0 ) — Benefit payments (75.4 ) (78.3 ) (19.0 ) (18.7 ) Fair value at December 31 $ 1,102.8 $ 1,179.3 $ 205.1 $ 216.1 Funded status at December 31 $ (74.2 ) $ (111.3 ) $ (93.4 ) $ (97.7 ) * Benefit obligations and plan assets were moved along with our employees who were transferred to/from affiliated entities. See Note 4, Related Parties, for more information
Amounts recognized on the balance sheets at December 31 related to the funded status of the benefit plans	The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows: Pension Costs OPEB Costs (in millions) 2016 2015 2016 2015 Other long-term assets $ — $ — $ — $ 1.9 Pension and OPEB obligations 74.2 111.3 93.4 99.6 Total net liabilities $ (74.2 ) $ (111.3 ) $ (93.4 ) $ (97.7 )
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) 2016 2015 Projected benefit obligation $ 1,177.0 $ 1,290.2 Accumulated benefit obligation 1,175.8 1,289.5 Fair value of plan assets 1,102.8 1,178.9
Amounts that had not yet been recognized in the entity's net periodic benefit cost	The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31: Pension Costs OPEB Costs (in millions) 2016 2015 2016 2015 Net regulatory assets Net actuarial loss $ 518.5 $ 520.9 $ 4.6 $ 14.7 Prior service cost (credit) 0.2 4.3 (3.0 ) (4.1 ) Total $ 518.7 $ 525.2 $ 1.6 $ 10.6
Estimated amounts that will be amortized into net periodic benefit cost	The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2017: (in millions) Pension Costs OPEB Costs Net actuarial loss $ 35.4 $ 1.0 Prior service costs (credits) 1.1 (1.1 ) Total 2017 – estimated amortization $ 36.5 $ (0.1 )
Schedule of the components of net periodic benefit cost	The components of net periodic benefit cost (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows: Pension Costs OPEB Costs (in millions) 2016 2015 2014 2016 2015 2014 Service cost $ 10.5 $ 14.7 $ 9.4 $ 7.3 $ 9.0 $ 8.1 Interest cost 49.7 52.9 59.3 13.2 13.4 14.4 Expected return on plan assets (77.7 ) (83.6 ) (79.1 ) (14.0 ) (16.0 ) (16.2 ) Amortization of prior service cost (credit) 1.6 2.0 2.0 (1.1 ) (1.1 ) (1.7 ) Amortization of net actuarial loss 32.4 35.6 26.9 1.0 1.0 0.2 Net periodic benefit cost $ 16.5 $ 21.6 $ 18.5 $ 6.4 $ 6.3 $ 4.8
Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost for the plans	The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension OPEB 2016 2015 2016 2015 Discount rate 4.15% 4.45% 4.20% 4.45% Rate of compensation increase 3.20% 4.00% N/A N/A Assumed medical cost trend rate N/A N/A 7.00% 7.50% Ultimate trend rate N/A N/A 5.00% 5.00% Year ultimate trend rate is reached N/A N/A 2021 2021 The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Costs 2016 2015 2014 Discount rate 4.45% 4.15% 5.00% Expected return on plan assets 7.00% 7.00% 7.25% Rate of compensation increase 3.50% 4.00% 4.00% OPEB Costs 2016 2015 2014 Discount rate 4.45% 4.20% 4.95% Expected return on plan assets 7.25% 7.25% 7.50% Assumed medical cost trend rate (Pre 65/Post 65) 7.50% 7.50% 7.50% Ultimate trend rate 5.00% 5.00% 5.00% Year ultimate trend rate is reached 2021 2021 2021
Effects of a one-percentage-point change in assumed health care cost trend rates	For the year ended December 31, 2016 , a one-percentage-point change in assumed health care cost trend rates would have had the following effects: (in millions) 1% Increase 1% Decrease Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $ 2.9 $ (2.3 ) Effect on the health care component of the accumulated postretirement benefit obligation 31.5 (26.0 )
Investments recorded at fair value, by asset class	The following table summarizes the fair values of our investments by asset class: December 31, 2016 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ 1.1 $ 19.2 $ — $ 20.3 $ 6.5 $ 1.3 $ — $ 7.8 Equity securities: Unites States Equity 85.5 0.1 — 85.6 10.5 — — 10.5 International Equity 17.7 — — 17.7 1.3 — — 1.3 Fixed income securities: * United States Bonds — 455.3 — 455.3 — 44.0 — 44.0 International Bonds — 31.6 — 31.6 — 2.8 — 2.8 Private Equity and Real Estate — — 11.0 11.0 — — 0.7 0.7 $ 104.3 $ 506.2 $ 11.0 $ 621.5 $ 18.3 $ 48.1 $ 0.7 $ 67.1 Investments measured at net asset value $ 481.3 $ 138.0 Total $ 104.3 $ 506.2 $ 11.0 $ 1,102.8 $ 18.3 $ 48.1 $ 0.7 $ 205.1 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2015 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ 15.5 $ — $ — $ 15.5 $ 2.4 $ — $ — $ 2.4 Equity securities: United States equity 80.1 — — 80.1 11.8 — — 11.8 International equity 25.8 — — 25.8 1.7 — — 1.7 Fixed income securities: * United States bonds — 509.4 — 509.4 — 78.1 — 78.1 International bonds — 32.6 — 32.6 — 4.5 — 4.5 Private Equity and Real Estate — — 4.5 4.5 — — 0.3 0.3 $ 121.4 $ 542.0 $ 4.5 $ 667.9 $ 15.9 $ 82.6 $ 0.3 $ 98.8 Investments measured at net asset value $ 511.4 $ 117.3 Total $ 121.4 $ 542.0 $ 4.5 $ 1,179.3 $ 15.9 $ 82.6 $ 0.3 $ 216.1 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.
Reconciliation of changes in the fair value of pension assets categorized as Level 3 measurements	The following tables set forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy: Private Equity and Real Estate (in millions) Pension OPEB Beginning balance at January 1, 2016 $ 4.5 $ 0.3 Purchases 6.5 0.4 Ending balance at December 31, 2016 $ 11.0 $ 0.7 Private Equity and Real Estate (in millions) Pension OPEB Beginning balance at January 1, 2015 $ — $ — Purchases 4.5 0.3 Ending balance at December 31, 2015 $ 4.5 $ 0.3
Schedule of expected future benefit payments	The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB: (in millions) Pension Costs OPEB Costs 2017 $ 90.7 $ 13.3 2018 88.6 14.4 2019 86.6 15.3 2020 86.5 16.1 2021 82.7 16.8 2022-2026 381.1 89.3

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of minimum future commitments related to purchase obligations	The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2016 . Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2017 2018 2019 2020 2021 Later Years Electric utility: Nuclear 2033 $ 9,599.8 $ 415.3 $ 420.1 $ 445.4 $ 475.1 $ 501.1 $ 7,342.8 Coal supply and transportation 2019 313.1 183.6 97.5 32.0 — — — Purchased power 2031 86.0 30.5 21.7 9.2 6.9 5.9 11.8 Natural gas utility supply and transportation 2024 217.2 56.3 49.3 43.0 31.5 17.9 19.2 Total $ 10,216.1 $ 685.7 $ 588.6 $ 529.6 $ 513.5 $ 524.9 $ 7,373.8
Schedule of minimum future payments under noncancelable operating leases	Future minimum payments under noncancelable operating leases are payable as follows: Year Ending December 31 Payments (in millions) 2017 $ 4.4 2018 3.3 2019 1.4 2020 1.3 2021 1.4 Later years 21.7 Total $ 33.5
Schedule of regulatory assets and reserves related to manufactured gas plants	We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31: (in millions) 2016 2015 Regulatory assets $ 29.9 $ 16.9 Reserves for future remediation 19.0 5.6

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair value of assets and liabilities measured on recurring basis, by level within the fair value hierarchy	The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 6.0 $ 0.8 $ — $ 6.8 Petroleum products contracts 0.2 — — 0.2 FTRs — — 3.1 3.1 Coal contracts — 1.9 — 1.9 Total derivative assets $ 6.2 $ 2.7 $ 3.1 $ 12.0 Derivative liabilities Natural gas contracts $ 0.1 $ — $ — $ 0.1 Petroleum products contracts 0.1 — — 0.1 Coal contracts — 0.5 — 0.5 Total derivative liabilities $ 0.2 $ 0.5 $ — $ 0.7 December 31, 2015 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.5 $ — $ — $ 0.5 Petroleum products contracts 1.2 — — 1.2 FTRs — — 1.6 1.6 Coal contracts — 2.0 — 2.0 Total derivative assets $ 1.7 $ 2.0 $ 1.6 $ 5.3 Derivative liabilities Natural gas contracts $ 9.2 $ 0.2 $ — $ 9.4 Petroleum products contracts 4.4 — — 4.4 Coal contracts — 7.6 — 7.6 Total derivative liabilities $ 13.6 $ 7.8 $ — $ 21.4
Reconcilation of changes in the FV of items categorized as level 3 measurements	The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: (in millions) 2016 2015 2014 Balance at the beginning of the period $ 1.6 $ 7.0 $ 3.5 Purchases 8.1 3.9 15.6 Settlements (6.6 ) (9.3 ) (12.1 ) Balance at the end of the period $ 3.1 $ 1.6 $ 7.0
Carrying amount and estimated fair value of certain financial instruments	The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: December 31, 2016 December 31, 2015 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 28.8 $ 30.4 $ 27.3 Long-term debt 2,661.1 2,923.4 2,658.8 2,888.2

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets and derivative liabilities	The following table shows our derivative assets and derivative liabilities: December 31, 2016 December 31, 2015 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 6.3 $ 0.1 $ 0.5 $ 8.1 Petroleum products contracts 0.2 0.1 0.9 3.3 FTRs 3.1 — 1.6 — Coal contracts 1.5 0.5 1.7 3.4 Total other current $ 11.1 $ 0.7 $ 4.7 $ 14.8 Other long-term Natural gas contracts $ 0.5 $ — $ — $ 1.3 Petroleum products contracts — — 0.3 1.1 Coal contracts 0.4 — 0.3 4.2 Total other long-term $ 0.9 $ — $ 0.6 $ 6.6 Total $ 12.0 $ 0.7 $ 5.3 $ 21.4
Estimated notional volumes and gain (losses)	Our estimated notional sales volumes and realized gains (losses) were as follows: December 31, 2016 December 31, 2015 December 31, 2014 (in millions) Volume Gains (Losses) Volume Gains (Losses) Volume Gains Natural gas contracts 35.3 Dth $ (12.3 ) 24.0 Dth $ (12.6 ) 21.4 Dth $ 4.0 Petroleum products contracts 10.3 gallons (2.6 ) 4.0 gallons (0.2 ) 9.2 gallons 0.5 FTRs 25.3 MWh 7.3 22.8 MWh 3.2 26.1 MWh 12.7 Total $ (7.6 ) $ (9.6 ) $ 17.2
Offsetting Assets and Liabilities [Table Text Block]	The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2016 December 31, 2015 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 12.0 $ 0.7 $ 5.3 $ 21.4 Gross amount not offset on the balance sheet * (3.6 ) (0.2 ) (0.7 ) (13.5 ) Net amount $ 8.4 $ 0.5 $ 4.6 $ 7.9 * Includes cash collateral received of $3.4 million at December 31, 2016 , and cash collateral posted of $12.8 million at December 31, 2015 .

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Schedule of information concerning our reportable segments	The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2016 , 2015 , and 2014 . 2016 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Operating revenues $ 3,792.8 $ — $ 3,792.8 Other operation and maintenance 1,430.2 — 1,430.2 Depreciation and amortization 325.4 — 325.4 Operating income 629.5 — 629.5 Equity in earnings of transmission affiliate — 55.5 55.5 Interest expense 116.6 1.0 117.6 Capital expenditures 468.9 0.6 469.5 Total assets 12,945.1 426.4 13,371.5 2015 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Operating revenues $ 3,854.1 $ — $ 3,854.1 Other operation and maintenance 1,384.9 — 1,384.9 Depreciation and amortization 304.0 — 304.0 Operating income 648.9 — 648.9 Equity in earnings of transmission affiliate — 47.8 47.8 Interest expense 117.7 1.3 119.0 Capital expenditures 518.8 0.4 519.2 Total assets 12,727.6 412.0 13,139.6 2014 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Operating revenues $ 4,059.4 $ — $ 4,059.4 Other operation and maintenance 1,356.4 — 1,356.4 Depreciation and amortization 278.3 — 278.3 Operating income 650.4 — 650.4 Equity in earnings of transmission affiliate — 57.9 57.9 Interest expense 114.9 1.6 116.5 Capital expenditures 561.8 — 561.8 Total assets 12,195.9 401.3 12,597.2

Quarterly Financial Informati50

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information (unaudited)	(in millions) First Quarter Second Quarter Third Quarter Fourth Quarter Total 2016 Operating revenues $ 975.5 $ 877.2 $ 1,023.8 $ 916.3 $ 3,792.8 Operating income 181.5 146.9 196.4 104.7 629.5 Net income attributed to common shareholder 107.3 82.6 115.2 59.2 364.3 2015 Operating revenues $ 1,084.6 $ 883.0 $ 981.1 $ 905.4 $ 3,854.1 Operating income 204.7 128.7 169.8 145.7 648.9 Net income attributed to common shareholder 121.4 74.6 100.1 79.6 375.7

Summary of Significant Accoun51

Summary of Significant Accounting Policies General Information (Details) $ in Millions	Dec. 31, 2016USD ($)wholly_owned_subsidiaries	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Condensed Financial Statements, Captions
Assets	$ 13,371.5	$ 13,139.6	$ 12,597.2
Subsidiaries
Condensed Financial Statements, Captions
Number of wholly owned subsidiaries | wholly_owned_subsidiaries	1
Assets	$ 24.4	$ 29.8

Summary of Significant Accoun52

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

Summary of Significant Accoun53

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

Summary of Significant Accoun54

Summary of Significant Accounting Policies Materials, Supplies, and Inventories (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Materials and supplies	$ 148.1	$ 151.1
Fossil fuel	91.1	110.5
Natural gas in storage	31.8	40
Total	$ 271	$ 301.6

Summary of Significant Accoun55

Summary of Significant Accounting Policies Property, Plant, and Equipment (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Annual utility composite depreciation rate (as a percent)	3.00%	3.01%	2.93%
Software | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	5 years
Software | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	15 years

Summary of Significant Accoun56

Summary of Significant Accounting Policies Allowance for Funds Used During Construction (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Allowance for funds used during construction
Percentage of retail jurisdictional construction work in progress expenditure subject to public utilities allowance for funds used during construction calculation	50.00%
AFUDC - Debt	$ 1.7	$ 2.2	$ 1.8
AFUDC - Equity	$ 4.2	$ 5.7	$ 4.4
Retail operations
Allowance for funds used during construction
Interest rate on accrued AFUDC	8.45%	8.45%	9.09%
Wholesale operations
Allowance for funds used during construction
Interest rate on accrued AFUDC	2.73%	1.72%	0.87%

Summary of Significant Accoun57

Summary of Significant Accounting Policies Stock-Based Compensation (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of WEC Energy Group common stock authorized for issuance	34,300,000
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	3 years
Minimum Exercise Price of Stock Option as a Percent of Common Stock Fair Value on the Grant Date	100.00%
Period after the grant date during which stock options can't be exercised (in months)	6 months
Maximum term of awards (in years)	10 years
Non-qualified stock options granted (in shares)	92,880	495,550	864,860
Estimated fair value per non-qualified stock option (in dollars per share)	$ 4.92	$ 5.29	$ 4.18
Risk-free interest rate, minimum (as a percent)	0.50%	0.10%	0.10%
Risk-free interest rate, maximum (as a percent)	2.20%	2.10%	3.00%
Dividend yield (as a percent)	4.00%	3.70%	3.80%
Expected volatility (as a percent)	18.00%	18.00%	18.00%
Expected life (years)	5 years 9 months	5 years 9 months	5 years 9 months
Restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	3 years
Percentage to vest each year after the grant date	33.00%
Performance units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	3 years
Performance units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance units, payout ratio (as a percent)	0.00%
Performance units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance units, payout ratio (as a percent)	175.00%

Acquisitions (Details)

Acquisitions (Details) - Integrys - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Jun. 29, 2015
PSCW Conditions of Approval - Earnings Sharing Mechanism
Duration of earnings cap condition imposed by the PSCW (in years)	3 years
Percentage of first 50 basis points to be shared with customers				50.00%
ROE in excess of authorized amount (as a percent)				0.50%
Severance
Severance expense			$ 6.6
Severance payments		$ 4.6	$ 1.2
WEC Energy Group
Business Acquisition [Line Items]
Percentage of Integrys common shares acquired				100.00%
Earnings sharing mechanism
PSCW Conditions of Approval - Earnings Sharing Mechanism
Expense for earnings sharing mechanism		$ 21.1

Dispositions (Details)

Dispositions (Details) - Utility $ in Millions	3 Months Ended
	Jun. 30, 2016USD ($)
Dispositions
After-tax gain on sale	$ 6.5
Other operation and maintenance
Dispositions
Pre-tax gain on sale	$ 10.9

Related Parties (Details)

Related Parties (Details) $ in Millions	Jan. 01, 2017USD ($)milecustomer	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Related parties
Proceeds from assets transferred to WBS		$ 13.1	$ 0	$ 0
Payments for liabilities transferred to WBS		116	0	0
WBS
Related parties
Charges to related party		213.8	11.1	0
Charges from related party		310.6	1.3	0
Proceeds from assets transferred to WBS		13.1
Payments for liabilities transferred to WBS		116
WEC Energy Group | Bostco
Related parties
Note payable to WEC Energy Group		18.5	19.6
We Power | Electric utility segment
Related parties
Lease payments to We Power		412.2	410.5	389
Construction work in progress billed to We Power		37.9	58.8	41
Wisconsin Public Service Corporation
Related parties
Charges to related party		9	13.4	0
Charges from related party		4.2	4.9	0
Wisconsin Gas
Related parties
Charges to related party		60.6	79.4	81.7
Charges from related party		21.5	23.5	20.6
Purchases from related party		$ 5.3	$ 5.3	$ 6.6
UMERC Transfer | Subsequent event
Related parties
Miles of electric distribution lines transferred | mile	2,500
Net book value of property, plant, and equipment transferred	$ 83
UMERC Transfer | Subsequent event | Electric utility segment
Related parties
Number of customers | customer	27,500
UMERC Transfer | Subsequent event | Electric distribution
Related parties
Number of customers | customer	50

Investment in American Transm61

Investment in American Transmission Company - Changes to Investment in ATC (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)membervote	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Changes to investment in ATC
Earnings from equity method investment	$ 55.5	$ 47.8	$ 57.9
Capital contributions	$ 16.1	4.6	11.5
ATC
Investment in ATC
Ownership interest in ATC (as a percent)	23.00%
Number of representatives on ATC's board of directors | member	1
Total number of members serving on ATC's board of directors | member	10
Number of votes that can be placed by each member on ATC's board of directors | vote	1
Number of members on ATC's board of directors with more than 10% voting control | member	0
Maximum voting control of any member of ATC's board of directors	10.00%
Changes to investment in ATC
Investment in ATC, balance at beginning of period	$ 382.2	372.9	354.1
Earnings from equity method investment	55.5	47.8	57.9
Capital contributions	16.1	4.6	11.5
Distributions	51.7	42.9	50.5
Other	0.1	0.2	0.1
Investment in ATC, balance at end of period	402	$ 382.2	$ 372.9
Dividends not received
Dividends Receivable	$ 13.4

Investment in American Transm62

Investment in American Transmission Company - Transactions with ATC (Details) - ATC - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Investment in ATC
Charges to ATC for services and construction	$ 10	$ 9.7	$ 8.1
Charges from ATC for network transmission services	247.8	238.5	$ 231.4
Accounts receivable for services provided to ATC	1.1	0.6
Accounts payable for services received from ATC	$ 20	$ 19.9

Investment in American Transm63

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

Supplemental Cash Flow Inform64

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Cash (paid) for interest, net of amount capitalized	$ (116.2)	$ (116.2)	$ (117.9)
Cash (paid) for income taxes, net		(58.5)	(20.8)
Cash received for income taxes	100.2
Accounts payable related to construction costs	$ 9.1	$ 11.7	$ 1.7

Regulatory Assets and Liabili65

Regulatory Assets and Liabilities - Regulatory Assets (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets
Total regulatory assets	$ 2,036.6	$ 1,855.9
Other Disclosures
Regulatory assets not earning a return	10.4
Regulatory assets earning a return based on short-term interest rates	204
Plant related -- capital leases
Regulatory Assets
Total regulatory assets	724.8	674.4
Unrecognized pension and OPEB costs
Regulatory Assets
Total regulatory assets	520.3	535.8
Electric transmission costs
Regulatory Assets
Total regulatory assets	231.9	191.5
Income tax related items
Regulatory Assets
Total regulatory assets	200.8	177.4
SSR
Regulatory Assets
Total regulatory assets	188.1	86.1
We Power generation
Regulatory Assets
Total regulatory assets	54.1	45.4
AROs
Regulatory Assets
Total regulatory assets	39.7	36.3
Energy efficiency programs
Regulatory Assets
Total regulatory assets	38.5	50.7
Other, net
Regulatory Assets
Total regulatory assets	$ 38.4	$ 58.3

Regulatory Assets and Liabili66

Regulatory Assets and Liabilities - Regulatory Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Regulatory Liabilities
Other current liabilities	$ 10.2	$ 0
Regulatory liabilities	853.9	741.2
Total regulatory liabilities	864.1	741.2
Removal costs
Regulatory Liabilities
Total regulatory liabilities	722.9	696.9
Mines deferral
Regulatory Liabilities
Total regulatory liabilities	70.2	31.6
Other, net
Regulatory Liabilities
Total regulatory liabilities	$ 71	$ 12.7

Property, Plant, and Equipmen67

Property, Plant, and Equipment (Details) $ in Millions	Jan. 01, 2017USD ($)mile	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Property, Plant and Equipment [Line Items]
Less: Accumulated depreciation		$ 3,619.6	$ 3,461.9
Total property, plant and equipment		9,832.3	9,767.5
Subsequent event | UMERC Transfer
Transfer of Assets to UMERC
Miles of electric distribution lines transferred | mile	2,500
Net book value of property, plant, and equipment transferred	$ 83
Utility Operations
Property, Plant and Equipment [Line Items]
Property, plant and equipment		11,232.9	10,863.1
Less: Accumulated depreciation		3,606.9	3,447.2
Net		7,626	7,415.9
Construction work in progress		111.5	170.3
Total property, plant and equipment		7,737.5	7,586.2
Nonutility Operations
Property, Plant and Equipment [Line Items]
Property, plant and equipment		46.4	54
Less: Accumulated depreciation		12.7	14.7
Net		33.7	39.3
Construction work in progress		0.9	0.3
Total property, plant and equipment		34.6	39.6
Nonutility Operations | Capital Leases
Property, Plant and Equipment [Line Items]
Property, plant and equipment		2,898	2,876.7
Less: Accumulated depreciation		837.8	735
Total property, plant and equipment		$ 2,060.2	$ 2,141.7

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Changes to asset retirement obligations
Balance as of January 1	$ 58.7	$ 40.5	$ 39.4
Accretion	3	2.3	2.2
Additions	0	15.9	0
Liabilities settled	(0.2)	0	(1.1)
Balance as of December 31	$ 61.5	$ 58.7	$ 40.5

Common Equity - Stock-Based Com

Common Equity - Stock-Based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 7.5	$ 12.8	$ 18.4
Related Tax Benefit	3	5.1	7.4
Stock options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	1.8	3.2	3.6
Restricted stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	1.8	2.1	2.1
Performance units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 3.9	$ 7.5	$ 12.7

Common Equity - Stock Options (

Common Equity - Stock Options (Details) - Stock options - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Options Activity [Roll Forward]
Outstanding, shares, beginning balance	1,285,806	5,687,714
Granted, shares		92,880	495,550	864,860
Exercised, shares		(439,043)
Transferred, shares		(4,055,745)
Outstanding, shares, ending balance		1,285,806	5,687,714
Options - Weighted Average Exercise Price
Outstanding, Weighted-Average Exercise Price, Beginning	$ 33.41	$ 33.58
Granted, Weighted-Average Exercise Price		50.93
Exercised, Weighted-Average Exercise Price		27.57
Transferred, Weighted-Average Exercise Price		34.68
Outstanding, Weighted-Average Exercise Price, Ending		$ 33.41	$ 33.58
Options - Additional Disclosures
Outstanding, Weighted-Average Remaining Contractual Life (Years)		4 years 7 months
Outstanding, Aggregate Intrinsic Value		$ 32.4
Exercisable, shares		1,010,061
Exercisable, Weighted-Average Exercise Price		$ 29.64
Exercisable, Weighted-Average Remaining Contractual Life (Years)		3 years 8 months
Exercisable, Aggregate Intrinsic Value		$ 29.3
Intrinsic value of options exercised		14.1	$ 34.6	$ 47.5
Actual tax benefit realized for the tax deductions		$ 5.6	$ 14	$ 18.8
Estimated fair value per non-qualified stock option (in dollars per share)		$ 4.92	$ 5.29	$ 4.18
Subsequent event
Options Activity [Roll Forward]
Granted, shares	80,770
Options - Weighted Average Exercise Price
Granted, Weighted-Average Exercise Price	$ 58.31
Options - Additional Disclosures
Estimated fair value per non-qualified stock option (in dollars per share)	$ 7.12
WEC Energy Group
Options - Additional Disclosures
Cash received by WEC Energy Group from options exercised by WE employees		$ 12.1	$ 29.2	$ 47.9

Common Equity - Restricted Shar

Common Equity - Restricted Shares (Details) - Restricted stock - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted Stock Activity [Roll Forward]
Outstanding, shares, beginning of period	16,261	175,443
Granted, shares		8,049
Released, shares		(7,901)
Transferred, shares		(158,635)
Forfeited, shares		(695)
Outstanding, shares, end of period		16,261	175,443
Restricted Stock Weighted-Average Grant Date Fair Value
Outstanding, weighted-average grant date fair value, beginning of period	$ 50.39	$ 47.66
Granted, weighted-average grant date fair value		51.78
Released, weighted-average grant date fair value		44.66
Transferred, weighted-average grant date fair value		47.73
Forfeited, weighted-average grant date fair value		50.42
Outstanding, weighted-average grant date fair value, end of period		$ 50.39	$ 47.66
Restricted Stock - Additional Disclosures
Intrinsic value of released restricted shares		$ 0.4	$ 2.7	$ 2.3
Actual tax benefit realized for the tax deductions		$ 0.2	$ 1.1	$ 0.9
Subsequent event
Restricted Stock Activity [Roll Forward]
Granted, shares	8,001
Restricted Stock Weighted-Average Grant Date Fair Value
Granted, weighted-average grant date fair value	$ 58.10

Common Equity - Performance Uni

Common Equity - Performance Units (Details) - Performance units - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, shares		35,700	187,450	224,735
Transferred, shares		573,499
Intrinsic value of settled performance units		$ 3.4	$ 11.6	$ 13.1
Actual tax benefit realized for the tax deductions		0.5	$ 4.2	$ 4.7
Compensation cost not yet recognized		$ 4.4
Weighted-average period over which unrecognized compensation cost is expected to be recognized		1 year 5 months
Subsequent event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, shares	34,765
Intrinsic value of settled performance units	$ 1.4
Actual tax benefit realized for the tax deductions	$ 0.4

Common Equity - Dividend Restri

Common Equity - Dividend Restrictions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Dividend Payment Restrictions [Line Items]
Restricted retained earnings	$ 1,900
Undistributed earnings from equity method investees	$ 142.2
Serial preferred stock, 3.60% series redeemable
Dividend Payment Restrictions [Line Items]
Preferred Stock, dividend rate (as a percent)	3.60%	3.60%
Serial preferred stock, 3.60% series redeemable | Common stock equity to total capitalization is less than 25%
Dividend Payment Restrictions [Line Items]
Percentage of net income for which dividends can be declared	75.00%
Serial preferred stock, 3.60% series redeemable | Common stock equity to total capitalization is less than 20%
Dividend Payment Restrictions [Line Items]
Percentage of net income for which dividends can be declared	50.00%
Maximum | Serial preferred stock, 3.60% series redeemable | Common stock equity to total capitalization is less than 25%
Dividend Payment Restrictions [Line Items]
Percentage of common equity to total capitalization required to be maintained	25.00%
Maximum | Serial preferred stock, 3.60% series redeemable | Common stock equity to total capitalization is less than 20%
Dividend Payment Restrictions [Line Items]
Percentage of common equity to total capitalization required to be maintained	20.00%
Public Service Commission of Wisconsin | Minimum
Dividend Payment Restrictions [Line Items]
Common equity ratio required to be maintained (as a percent)	51.00%

Preferred Stock (Details)

Preferred Stock (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Class of Stock
Preferred stock	$ 30.4	$ 30.4
Six per cent. preferred stock
Class of Stock
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	$ 4.4	$ 4.4
Serial preferred stock, $100 par value; authorized 2,286,500 shares
Class of Stock
Preferred stock, par or stated value per share	$ 100	$ 100
Preferred stock, shares authorized	2,286,500	2,286,500
Serial preferred stock, 3.60% series redeemable
Class of Stock
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	$ 26	$ 26
Serial preferred stock, $25 par value; authorized 5,000,000 shares; none outstanding
Class of Stock
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, redemption price per share	$ 0	$ 0
Preferred stock	$ 0	$ 0

Short-Term Debt and Lines of 75

Short-Term Debt and Lines of Credit Outstanding (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Short-term Debt [Line Items]
Maximum debt to capitalization ratio required to be maintained (as a percent)	65.00%
Commercial Paper
Short-term Debt [Line Items]
Short-term debt outstanding	$ 159	$ 144
Average interest rate on amounts outstanding	0.87%	0.70%
Average amounts outstanding during year	$ 110
Commercial Paper Weighted Average Interest Rate	0.54%

Short-Term Debt and Lines of 76

Short-Term Debt and Lines of Credit - Credit Facilities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)extension	Dec. 31, 2015USD ($)
Line of Credit Facility [Line Items]
Subsidiary note payable to WEC Energy Group	$ 18.5	$ 19.6
Letters of Credit Issued Inside Credit Facilities	18
Available capacity under existing agreements	$ 323
Number of extensions available on a credit facility | extension	2
Length of credit facility extension	1 year
Credit facility maturing December 2020
Line of Credit Facility [Line Items]
Short-term credit capacity	$ 500
Bostco | WEC Energy Group
Line of Credit Facility [Line Items]
Subsidiary note payable to WEC Energy Group	$ 18.5
Note payable, related party, interest rate	5.17%
Commercial Paper
Line of Credit Facility [Line Items]
Short-term debt outstanding	$ 159	$ 144

Long-Term Debt and Capital Le77

Long-Term Debt and Capital Lease Obligations (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)Megawatt	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Aug. 01, 2016USD ($)
Long-term debt outstanding maturities
2,017	$ 0
2,018	250
2,019	250
2,020	0
2,021	300
Thereafter	1,887
Total	2,687
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Long-term Pollution Control Bond	80			$ 67
Total capital lease obligation	$ 2,785	$ 2,816.1
Number of PWGS natural gas-fired generation units	2
Total lease payment	$ 449.8	446.7	$ 411.9
Summary of capitalized leased facilities
Total leased facilities	2,060.2	2,141.7
Future minimum lease payments under capital lease and present value of net minimum lease payments
2,017	432
2,018	432.8
2,019	433.6
2,020	434.5
2,021	435.3
Thereafter	6,856.5
Total minimum lease payments	9,024.7
Less: Estimated executory costs	(39.9)
Net minimum lease payments	8,984.8
Less: Interest	(6,199.8)
Present value of minimum lease payments	2,785
Less: Due currently	(28.5)	(123.6)
Long-term obligations under capital lease	$ 2,756.5	2,692.5
Purchase power agreement
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
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
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	29.6
Power Purchase Commitment
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Total lease payment	37.6	36.2	34.9
Summary of capitalized leased facilities
Capital lease asset	140.3	140.3
Accumulated amortization	(109.5)	(103.9)
Total leased facilities	30.8	36.4
Future minimum lease payments under capital lease and present value of net minimum lease payments
2,017	13.9
2,018	14.7
2,019	15.5
2,020	16.4
2,021	17.2
Thereafter	7.6
Total minimum lease payments	85.3
Less: Estimated executory costs	(39.9)
Net minimum lease payments	45.4
Less: Interest	(15.8)
Present value of minimum lease payments	29.6
Less: Due currently	(2.7)
Long-term obligations under capital lease	$ 26.9
PWGS Units 1 and 2
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
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	545
Capital lease obligation at the end of life of contract	$ 0
Total lease payment	82.4	103.8	99.2
Summary of capitalized leased facilities
Capital lease asset	704.2	692.5
Accumulated amortization	(274.7)	(245.7)
Total leased facilities	429.5	446.8
Future minimum lease payments under capital lease and present value of net minimum lease payments
2,017	102.7
2,018	102.7
2,019	102.7
2,020	102.7
2,021	102.7
Thereafter	1,020.2
Total minimum lease payments	1,533.7
Less: Estimated executory costs	0
Net minimum lease payments	1,533.7
Less: Interest	(897.6)
Present value of minimum lease payments	636.1
Less: Due currently	(13.9)
Long-term obligations under capital lease	622.2
PWGS 1
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Estimated Total Increase In Regulatory Asset due to Minimum Lease Payment, Over Life of Contract	$ 130.8
Increase In Regulatory Asset Due To Minimum Lease Payment, End Date of Increase	Dec. 31, 2021
PWGS 2
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Power capacity from a gas-fired cogeneration facility under capital lease (MW) | Megawatt	545
Regulatory asset value at the end of life of contract	$ 0
Estimated Total Increase In Regulatory Asset due to Minimum Lease Payment, Over Life of Contract	$ 131.6
Increase In Regulatory Asset Due To Minimum Lease Payment, End Date of Increase	Dec. 31, 2024
ERGS
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Period of Power purchase contract with an unaffiliated independent power producer	30 years
Regulatory asset value at the end of life of contract	$ 0
Capital lease obligation at the end of life of contract	0
Total lease payment	329.8	306.7	$ 277.8
Summary of capitalized leased facilities
Capital lease asset	2,053.5	2,043.9
Accumulated amortization	(453.6)	(385.4)
Total leased facilities	1,599.9	$ 1,658.5
Future minimum lease payments under capital lease and present value of net minimum lease payments
2,017	315.4
2,018	315.4
2,019	315.4
2,020	315.4
2,021	315.4
Thereafter	5,828.7
Total minimum lease payments	7,405.7
Less: Estimated executory costs	0
Net minimum lease payments	7,405.7
Less: Interest	(5,286.4)
Present value of minimum lease payments	2,119.3
Less: Due currently	(11.9)
Long-term obligations under capital lease	2,107.4
ER 1
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Estimated Total Increase In Regulatory Asset due to Minimum Lease Payment, Over Life of Contract	$ 542.8
Increase In Regulatory Asset Due To Minimum Lease Payment, End Date of Increase	May 31, 2029
ER 2
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Estimated Total Increase In Regulatory Asset due to Minimum Lease Payment, Over Life of Contract	$ 447.2
Increase In Regulatory Asset Due To Minimum Lease Payment, End Date of Increase	Jan. 31, 2030

Income Taxes Income Taxes - Pro

Income Taxes Income Taxes - Provision (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Current tax expense (benefit)	$ 4.8	$ 33.1	$ 31.2
Deferred income taxes, net	207.3	180	192.5
Investment tax credit, net	(1.1)	(1.1)	(1.1)
Total income tax expense	$ 211	$ 212	$ 222.6

Income Taxes Income Taxes - Rec

Income Taxes Income Taxes - Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Expected tax at statutory federal tax rates	$ 201.4	$ 205.7	$ 209.8
State income taxes net of federal tax benefit	31.8	31	33
Production tax credits	(16.5)	(17.8)	(17.4)
Domestic production activities deduction	(7.8)	(7.8)	0
AFUDC - Equity	(1.5)	(2)	(1.5)
Investment tax credit restored	(1.1)	(1.1)	(1.1)
Other, net	4.7	4	(0.2)
Total income tax expense	$ 211	$ 212	$ 222.6
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Expected tax at statutory federal tax rates	35.00%	35.00%	35.00%
State income taxes net of federal tax benefit	5.50%	5.30%	5.50%
Production tax credits	(2.80%)	(3.00%)	(2.90%)
Domestic production activities deduction	(1.40%)	(1.30%)	(0.00%)
AFUDC - Equity	(0.30%)	(0.30%)	(0.20%)
Investment tax credit restored	(0.20%)	(0.20%)	(0.20%)
Other, net	0.80%	0.50%	(0.10%)
Total income tax expense	36.60%	36.00%	37.10%

Income Taxes Income Taxes - Def

Income Taxes Income Taxes - Deferred Income Taxes (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Non-current
Deferred revenues	$ 207.2	$ 219.9
Future federal tax benefits	143.7	72.9
Employee benefits and compensation	77.6	103.2
Construction advances	20	17.7
Uncollectible account expense	16.1	14.3
Emission allowances	0.2	0.2
Other	70.9	48.7
Total deferred tax assets	535.7	476.9
Non-current
Property-related	2,257.3	2,058.5
Investment in transmission affiliate	195.1	174.9
Employee benefits and compensation	179.3	164.6
Deferred transmission costs	93.1	76.7
Prepaid tax, insurance, other	50.2	50.6
Other	94	61.6
Total deferred tax liabilities	2,869	2,586.9
Deferred tax liability, net	$ 2,333.3	$ 2,110

Income Taxes - Carryforwards (D

Income Taxes - Carryforwards (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Income Taxes
Operating loss carryforward, deferred tax asset	$ 29
Tax credit carryforward, deferred tax asset	107.2	$ 72.9
State net operating loss carryforwards, deferred tax asset	7.5
Domestic Tax Authority
Income Taxes
Net operating loss carryforward	82.8
Tax credit carryforward	107.2
State and Local Jurisdiction
Income Taxes
Net operating loss carryforward	$ 149.9

Income Taxes Income Taxes - Unr

Income Taxes Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance, January 1	$ 6.1	$ 7.2
Reductions for tax positions of prior years	(1)	(1.1)
Balance, December 31	5.1	6.1	$ 7.2
Income Taxes
Deferred tax assets, uncertainty in income taxes	5.1	6.1
Unrecognized tax benefits that would impact effective tax rate	0	0
Accrued interest in the consolidated income statements	0.2	0.1	0.3
Accrued penalties in the consolidated income statements	0	0	$ 0
Accrued interest on the consolidated balance sheets	$ 0.7	$ 0.6

Employee Benefits - Change in B

Employee Benefits - Change in Benefit Obligations and Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Mar. 31, 2015
Employee Benefit Plans
New 401k Contribution for new hires				6.00%
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Pension and OPEB obligations	$ 167.6	$ 210.9
Pension Benefits
Change in benefit obligation
Obligation at January 1	1,290.6	1,315.2
Service cost	10.5	14.7	$ 9.4
Interest cost	49.7	52.9	59.3
Participant contributions	0	0
Plan amendments	(2.6)	0
Transfer to affiliates	(121.1)	(2.4)
Actuarial loss (gain), net	25.3	(11.5)
Benefit payments	(75.4)	(78.3)
Obligation at December 31	1,177	1,290.6	1,315.2
Change in fair value of plan assets
Beginning balance at January 1	1,179.3	1,160
Actual return on plan assets	73	(7.8)
Employer contributions	5.3	105
Participant contributions	0	0
Transfer to affiliates	(79.4)	0.4
Benefit payments	(75.4)	(78.3)
Ending balance at December 31	1,102.8	1,179.3	1,160
Funded status at December 31	(74.2)	(111.3)
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Other long-term assets	0	0
Pension and OPEB obligations	74.2	111.3
Total net liabilities	(74.2)	(111.3)
Accumulated benefit obligation	1,175.8	1,287.5
Information for pension plans with an accumulated benefit obligation in excess of plan assets
Projected benefit obligation	1,177	1,290.2
Accumulated benefit obligation	1,175.8	1,289.5
Fair value of plan assets	1,102.8	1,178.9
OPEB
Change in benefit obligation
Obligation at January 1	313.8	322.3
Service cost	7.3	9	8.1
Interest cost	13.2	13.4	14.4
Participant contributions	8.8	8.8
Plan amendments	0	0
Transfer to affiliates	(17)	0
Actuarial loss (gain), net	(9.7)	(22.3)
Benefit payments	(19)	(18.7)
Federal subsidy on benefits paid	1.1	1.3
Obligation at December 31	298.5	313.8	322.3
Change in fair value of plan assets
Beginning balance at January 1	216.1	224.9
Actual return on plan assets	13.5	(1.5)
Employer contributions	2.7	2.6
Participant contributions	8.8	8.8
Transfer to affiliates	(17)	0
Benefit payments	(19)	(18.7)
Ending balance at December 31	205.1	216.1	$ 224.9
Funded status at December 31	(93.4)	(97.7)
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Other long-term assets	0	1.9
Pension and OPEB obligations	93.4	99.6
Total net liabilities	$ (93.4)	$ (97.7)

Employee Benefits - Net Periodi

Employee Benefits - Net Periodic Benefit Cost (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Net regulatory assets
Net actuarial loss	$ 518.5	$ 520.9
Prior service cost (credit)	0.2	4.3
Total	518.7	525.2
Net actuarial loss	35.4
Prior service costs (credit)	1.1
Total 2017 - estimated amortization	36.5
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)
Service cost	10.5	14.7	$ 9.4
Interest cost	49.7	52.9	59.3
Expected return on plan assets	(77.7)	(83.6)	(79.1)
Amortization of prior service cost (credit)	1.6	2	2
Amortization of net actuarial loss	32.4	35.6	26.9
Net periodic benefit cost	16.5	21.6	18.5
OPEB
Net regulatory assets
Net actuarial loss	4.6	14.7
Prior service cost (credit)	(3)	(4.1)
Total	1.6	10.6
Net actuarial loss	1
Prior service costs (credit)	(1.1)
Total 2017 - estimated amortization	(0.1)
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)
Service cost	7.3	9	8.1
Interest cost	13.2	13.4	14.4
Expected return on plan assets	(14)	(16)	(16.2)
Amortization of prior service cost (credit)	(1.1)	(1.1)	(1.7)
Amortization of net actuarial loss	1	1	0.2
Net periodic benefit cost	$ 6.4	$ 6.3	$ 4.8

Employee Benefits - Assumptions

Employee Benefits - Assumptions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Weighted average assumptions used
Discount rate	4.15%	4.45%
Rate of compensation increase	3.20%	4.00%
Discount rate	4.45%	4.15%	5.00%
Expected return on plan assets	7.00%	7.00%	7.25%
Rate of compensation increase	3.50%	4.00%	4.00%
Expected return on assets during next fiscal year	7.00%
Pension Benefits | Equity securities:
Target asset allocations
Target asset allocations (as a percent)	35.00%
Pension Benefits | Fixed income securities:
Target asset allocations
Target asset allocations (as a percent)	55.00%
Pension Benefits | Private Equity Funds
Target asset allocations
Target asset allocations (as a percent)	10.00%
OPEB
Weighted average assumptions used
Discount rate	4.20%	4.45%
Assumed medical cost trend rate (as a percent)	7.00%	7.50%
Ultimate trend rate (as a percent)	5.00%	5.00%
Year ultimate trend rate is reached	2,021	2,021
Discount rate	4.45%	4.20%	4.95%
Expected return on plan assets	7.25%	7.25%	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	$ 2.9
Effect of one-percentage-point decrease on total of service and interest cost components of net periodic postretirement health care benefit cost	(2.3)
Effect of one-percentage-point increase on the health care component of the accumulated postretirement benefit obligation	31.5
Effect of one-percentage-point decrease on the health care component of the accumulated postretirement benefit obligation	$ (26)
OPEB | Maximum
Weighted average assumptions used
Assumed medical cost trend rate (as a percent)	7.50%	7.50%	7.50%
Ultimate trend rate (as a percent)	5.00%	5.00%	5.00%
Year ultimate trend rate is reached	2,021	2,021	2,021
OPEB | Equity securities:
Target asset allocations
Target asset allocations (as a percent)	60.00%
OPEB | Fixed income securities:
Target asset allocations
Target asset allocations (as a percent)	40.00%

Employee Benefits - Pension and

Employee Benefits - Pension and Other Postretirement Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plan Assets
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	$ 1,102.8	$ 1,179.3	$ 1,160
Fair value of plan assets subject to levelling	621.5	667.9
Pension Plan Assets | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	20.3	15.5
Pension Plan Assets | United States Equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	85.6	80.1
Pension Plan Assets | International Equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	17.7	25.8
Pension Plan Assets | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	455.3	509.4
Pension Plan Assets | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	31.6	32.6
Pension Plan Assets | Private Placement
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	11	4.5
Pension Plan Assets | Investments measured at net asset value
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	481.3	511.4
Pension Plan Assets | Level 1
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	104.3	121.4
Pension Plan Assets | Level 1 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	1.1	15.5
Pension Plan Assets | Level 1 | United States Equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	85.5	80.1
Pension Plan Assets | Level 1 | International Equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	17.7	25.8
Pension Plan Assets | Level 1 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plan Assets | Level 1 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plan Assets | Level 1 | Private Placement
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plan Assets | Level 2
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	506.2	542
Pension Plan Assets | Level 2 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	19.2	0
Pension Plan Assets | Level 2 | United States Equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0.1	0
Pension Plan Assets | Level 2 | International Equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plan Assets | Level 2 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	455.3	509.4
Pension Plan Assets | Level 2 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	31.6	32.6
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	11	4.5
Pension Plan Assets | Level 3 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plan Assets | Level 3 | United States Equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plan Assets | Level 3 | International Equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plan Assets | Level 3 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	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	11	4.5	0
OPEB Plan Assets
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	205.1	216.1	224.9
Fair value of plan assets subject to levelling	67.1	98.8
OPEB Plan Assets | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	7.8	2.4
OPEB Plan Assets | United States Equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	10.5	11.8
OPEB Plan Assets | International Equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	1.3	1.7
OPEB Plan Assets | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	44	78.1
OPEB Plan Assets | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	2.8	4.5
OPEB Plan Assets | Private Placement
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0.7	0.3
OPEB Plan Assets | Investments measured at net asset value
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	138	117.3
OPEB Plan Assets | Level 1
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	18.3	15.9
OPEB Plan Assets | Level 1 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	6.5	2.4
OPEB Plan Assets | Level 1 | United States Equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	10.5	11.8
OPEB Plan Assets | Level 1 | International Equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	1.3	1.7
OPEB Plan Assets | Level 1 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
OPEB Plan Assets | Level 1 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
OPEB Plan Assets | Level 1 | Private Placement
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
OPEB Plan Assets | Level 2
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	48.1	82.6
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	0	0
OPEB Plan Assets | Level 2 | International Equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
OPEB Plan Assets | Level 2 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	44	78.1
OPEB Plan Assets | Level 2 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	2.8	4.5
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	0.7	0.3
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	$ 0.7	$ 0.3	$ 0

Employee Benefits - Changes in

Employee Benefits - Changes in the Fair Value of Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	$ 1,179.3	$ 1,160
Ending balance at December 31	1,102.8	1,179.3
Pension Benefits | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	4.5
Ending balance at December 31	11	4.5
OPEB
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	216.1	224.9
Ending balance at December 31	205.1	216.1
OPEB | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	0.3
Ending balance at December 31	0.7	0.3
Private Placement | Pension Benefits
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	4.5
Ending balance at December 31	11	4.5
Private Placement | Pension Benefits | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	4.5	0
Purchases	6.5	4.5
Ending balance at December 31	11	4.5
Private Placement | OPEB
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	0.3
Ending balance at December 31	0.7	0.3
Private Placement | OPEB | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	0.3	0
Purchases	0.4	0.3
Ending balance at December 31	$ 0.7	$ 0.3

Employee Benefits - Defined Con

Employee Benefits - Defined Contribution Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Mar. 31, 2015
Defined Contribution Benefit Plans
Total costs incurred for defined contribution benefit plans	$ 10.4	$ 13	$ 13
New 401k Contribution for new hires				6.00%
Pension Benefits
Employee Benefit Plans
Expected contributions to the plans during the next fiscal year	4.9
Expected payments, reflecting expected future service
2,017	90.7
2,018	88.6
2,019	86.6
2,020	86.5
2,021	82.7
2022 through 2026	381.1
OPEB
Expected payments, reflecting expected future service
2,017	13.3
2,018	14.4
2,019	15.3
2,020	16.1
2,021	16.8
2022 through 2026	$ 89.3

Commitments and Contingencies -

Commitments and Contingencies - Unconditional Purchase Obligations (Details) $ in Millions	Dec. 31, 2016USD ($)
Total
Minimum future commitments for purchase obligations
Total Amounts Committed	$ 10,216.1
2,017	685.7
2,018	588.6
2,019	529.6
2,020	513.5
2,021	524.9
Later Years	7,373.8
Nuclear | Electric
Minimum future commitments for purchase obligations
Total Amounts Committed	9,599.8
2,017	415.3
2,018	420.1
2,019	445.4
2,020	475.1
2,021	501.1
Later Years	7,342.8
Coal supply and transportation | Electric
Minimum future commitments for purchase obligations
Total Amounts Committed	313.1
2,017	183.6
2,018	97.5
2,019	32
2,020	0
2,021	0
Later Years	0
Purchased power | Electric
Minimum future commitments for purchase obligations
Total Amounts Committed	86
2,017	30.5
2,018	21.7
2,019	9.2
2,020	6.9
2,021	5.9
Later Years	11.8
Natural gas utility supply and transportation | Natural gas
Minimum future commitments for purchase obligations
Total Amounts Committed	217.2
2,017	56.3
2,018	49.3
2,019	43
2,020	31.5
2,021	17.9
Later Years	$ 19.2

Commitments and Contingencies90

Commitments and Contingencies - Operating Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Leases [Abstract]
Rental expense attributable to operating leases	$ 5	$ 6.7	$ 4.8
Minimum future payments under noncancelable operating leases
2,017	4.4
2,018	3.3
2,019	1.4
2,020	1.3
2,021	1.4
Later years	21.7
Total	$ 33.5

Commitments and Contingencies91

Commitments and Contingencies - Environmental Matters (Details) T in Millions, $ in Millions	1 Months Ended				12 Months Ended
	Sep. 30, 2016	Jan. 31, 2016	Dec. 31, 2015USD ($)	Aug. 31, 2014	Dec. 31, 2016USD ($)T	Dec. 31, 2015USD ($)T
Electric | Cross-State Air Pollution Rule [Member]
Air Quality
Number of states impacted by Cross State Air Pollution rule	23
Electric | Mercury and other hazardous air pollutants
Air Quality
Percentage mercury emission reduction required by the State of Wisconsin's mercury rule					90.00%
Electric | Climate Change
Air Quality
Percentage greenhouse gas emission reduction nationwide						32.00%
Interim requirement greenhouse gas emissions reductions						0.667
Percentage carbon dioxide emission reduction company goal					40.00%
Carbon dioxide emissions | T					23.9	25.3
Electric | Climate Change | WISCONSIN
Air Quality
Percentage greenhouse gas emission reduction state						41.00%
Percentage greenhouse gas emission reduction for retirement of a nuclear plant			10.00%
Electric | Climate Change | MICHIGAN
Air Quality
Percentage greenhouse gas emission reduction state						39.00%
Electric | Clean Water Act Cooling Water Intake Structure Rule
Water Quality
Number of compliance options available to meet standard				7
Electric | Steam Electric Effluent Guidelines
Water Quality
Renewal period for facility permits		5 years
Electric | Steam Electric Effluent Guidelines | Minimum
Water Quality
Expected environmental costs to achieve required emission reductions					$ 55
Electric | Steam Electric Effluent Guidelines | Maximum
Water Quality
Expected environmental costs to achieve required emission reductions					$ 75
Electric | Renewables, Efficiency, and Conservation | WISCONSIN
Renewables, Efficiency, and Conservation
Percent renewable portfolio energy requirement for years 2016 through 2018.					10.00%
Renewable energy percent required					8.27%
Percent of annual operating revenues					1.20%
Percentage renewable portfolio requirement for years 2019 through 2020					12.50%
Percentage renewable portfolio requirement for 2021					15.00%
Electric | Renewables, Efficiency, and Conservation | MICHIGAN
Renewables, Efficiency, and Conservation
Percent renewable portfolio energy requirement for years 2016 through 2018.					10.00%
Electric | Renewables, Efficiency, and Conservation | Maximum | MICHIGAN
Renewables, Efficiency, and Conservation
Energy optimization target					1.00%
Natural gas | Climate Change
Air Quality
Carbon dioxide emissions | T					3.7	3.8
Natural gas | Manufactured Gas Plant Remediation
Manufactured Gas Plant Remediation
Regulatory assets recorded for manufactured gas plant sites			$ 16.9		$ 29.9	$ 16.9
Reserves recorded for remediation of manufactured gas plant sites			$ 5.6		$ 19	$ 5.6

Fair Value Measurements - Asset

Fair Value Measurements - Assets and liabilities measured on a recurring basis (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Assets
Derivative asset	$ 12	$ 5.3
Liabilities
Derivative liability	0.7	21.4
Fair value measurements on a recurring basis
Assets
Derivative asset	12	5.3
Liabilities
Derivative liability	0.7	21.4
Natural gas contracts | Fair value measurements on a recurring basis
Assets
Derivative asset	6.8	0.5
Liabilities
Derivative liability	0.1	9.4
Petroleum products contracts | Fair value measurements on a recurring basis
Assets
Derivative asset	0.2	1.2
Liabilities
Derivative liability	0.1	4.4
FTRs | Fair value measurements on a recurring basis
Assets
Derivative asset	3.1	1.6
Coal contracts | Fair value measurements on a recurring basis
Assets
Derivative asset	1.9	2
Liabilities
Derivative liability	0.5	7.6
Level 1 | Fair value measurements on a recurring basis
Assets
Derivative asset	6.2	1.7
Liabilities
Derivative liability	0.2	13.6
Level 1 | Natural gas contracts | Fair value measurements on a recurring basis
Assets
Derivative asset	6	0.5
Liabilities
Derivative liability	0.1	9.2
Level 1 | Petroleum products contracts | Fair value measurements on a recurring basis
Assets
Derivative asset	0.2	1.2
Liabilities
Derivative liability	0.1	4.4
Level 1 | FTRs | Fair value measurements on a recurring basis
Assets
Derivative asset	0	0
Level 1 | Coal contracts | Fair value measurements on a recurring basis
Assets
Derivative asset	0	0
Liabilities
Derivative liability	0	0
Level 2 | Fair value measurements on a recurring basis
Assets
Derivative asset	2.7	2
Liabilities
Derivative liability	0.5	7.8
Level 2 | Natural gas contracts | Fair value measurements on a recurring basis
Assets
Derivative asset	0.8	0
Liabilities
Derivative liability	0	0.2
Level 2 | Petroleum products contracts | Fair value measurements on a recurring basis
Assets
Derivative asset	0	0
Liabilities
Derivative liability	0	0
Level 2 | FTRs | Fair value measurements on a recurring basis
Assets
Derivative asset	0	0
Level 2 | Coal contracts | Fair value measurements on a recurring basis
Assets
Derivative asset	1.9	2
Liabilities
Derivative liability	0.5	7.6
Level 3 | Fair value measurements on a recurring basis
Assets
Derivative asset	3.1	1.6
Liabilities
Derivative liability	0	0
Level 3 | Natural gas contracts | Fair value measurements on a recurring basis
Assets
Derivative asset	0	0
Liabilities
Derivative liability	0	0
Level 3 | Petroleum products contracts | Fair value measurements on a recurring basis
Assets
Derivative asset	0	0
Liabilities
Derivative liability	0	0
Level 3 | FTRs | Fair value measurements on a recurring basis
Assets
Derivative asset	3.1	1.6
Level 3 | Coal contracts | Fair value measurements on a recurring basis
Assets
Derivative asset	0	0
Liabilities
Derivative liability	$ 0	$ 0

Fair Value Measurements - Level

Fair Value Measurements - Level 3 Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Balance at the beginning of the period	$ 1.6	$ 7	$ 3.5
Purchases	8.1	3.9	15.6
Settlements	(6.6)	(9.3)	(12.1)
Balance at the end of the period	$ 3.1	$ 1.6	$ 7

Fair Value Measurements, Financ

Fair Value Measurements, Financial Instruments not recorded at Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Carrying value and estimated fair value of financial instruments
Preferred stock	$ 30.4	$ 30.4
Long-term debt including current portion	2,661.1	2,658.8
Carrying Amount
Carrying value and estimated fair value of financial instruments
Preferred stock	30.4	30.4
Long-term debt including current portion	2,661.1	2,658.8
Fair Value
Carrying value and estimated fair value of financial instruments
Preferred stock	28.8	27.3
Debt Instrument, Fair Value Disclosure	$ 2,923.4	$ 2,888.2

Derivative Instruments - Deriva

Derivative Instruments - Derivative Assets and Derivative Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative Asset
Other current derivative assets	$ 11.1	$ 4.7
Other long-term derivative assets	0.9	0.6
Derivative asset	12	5.3
Derivative Liability
Other current derivative liabilities	0.7	14.8
Other long-term derivative liabilities	0	6.6
Derivative liability	0.7	21.4
Cash collateral
Cash collateral posted		14.9
Cash collateral received	3.4
Natural gas contracts
Derivative Asset
Other current derivative assets	6.3	0.5
Other long-term derivative assets	0.5	0
Derivative Liability
Other current derivative liabilities	0.1	8.1
Other long-term derivative liabilities	0	1.3
Petroleum products contracts
Derivative Asset
Other current derivative assets	0.2	0.9
Other long-term derivative assets	0	0.3
Derivative Liability
Other current derivative liabilities	0.1	3.3
Other long-term derivative liabilities	0	1.1
FTRs
Derivative Asset
Other current derivative assets	3.1	1.6
Derivative Liability
Other current derivative liabilities	0	0
Coal contracts
Derivative Asset
Other current derivative assets	1.5	1.7
Other long-term derivative assets	0.4	0.3
Derivative Liability
Other current derivative liabilities	0.5	3.4
Other long-term derivative liabilities	$ 0	$ 4.2

Derivative Instruments Derivati

Derivative Instruments Derivative Instruments - Gains (Losses) and Notional Volumes (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MMBTUMWhgal	Dec. 31, 2015USD ($)MMBTUMWhgal	Dec. 31, 2014USD ($)MMBTUMWhgal
Derivative, Gain (Loss) on Derivative, Net [Abstract]
Gains (losses)	$ (7.6)	$ (9.6)	$ 17.2
Natural gas contracts
Derivative, Gain (Loss) on Derivative, Net [Abstract]
Gains (losses)	$ (12.3)	$ (12.6)	$ 4
Notional Disclosures [Abstract]
Notional sales volumes (Dth or MWh) | MMBTU	35.3	24	21.4
Petroleum products contracts
Derivative, Gain (Loss) on Derivative, Net [Abstract]
Gains (losses)	$ (2.6)	$ (0.2)	$ 0.5
Notional Disclosures [Abstract]
Notional sales volumes (gallons) | gal	10.3	4	9.2
FTRs
Derivative, Gain (Loss) on Derivative, Net [Abstract]
Gains (losses)	$ 7.3	$ 3.2	$ 12.7
Notional Disclosures [Abstract]
Notional sales volumes (Dth or MWh) | MWh	25.3	22.8	26.1

Derivative Instruments - Offset

Derivative Instruments - Offsetting Table (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Offsetting Derivative Assets
Gross amount recognized on balance sheet	$ 12	$ 5.3
Gross amount not offset on the balance sheet	3.6	0.7
Net amount	8.4	4.6
Offsetting Derivative Liabilities
Gross amount recognized on the balance sheet	0.7	21.4
Gross amount not offset on the balance sheet	0.2	13.5
Net amount	0.5	7.9
Cash collateral
Cash collateral received	$ 3.4
Cash collateral posted		$ 12.8

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016USD ($)	Dec. 31, 2016USD ($)MW	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
ATC
Variable interest entities
Ownership interest in ATC (as a percent)		23.00%
Equity investment in ATC		$ 402	$ 382.2
Accounts payable due to ATC		$ 20	19.9
Purchase power agreement
Variable interest entities
Firm capacity from purchase power agreement (in megawatts) | MW		236
Minimum energy requirements over remaining term of purchased power agreement (in megawatts) | MW		0
Remaining term of purchased power agreement (in years)		5 years
Residual guarantee associated with purchased power agreement		$ 0
Required payments over remaining term of purchased power agreement		85.3
Total capacity and lease payments under purchased power agreement		$ 54.2	$ 53.6	$ 53
Accounting Standards Update 2015-02
Variable interest entities
Changes to disclosures and financial statement presentation	$ 0

Regulatory Environment (Details

Regulatory Environment (Details) $ in Millions	1 Months Ended
	Aug. 31, 2016USD ($)MW	Nov. 30, 2015	Dec. 31, 2014USD ($)	Dec. 31, 2012USD ($)
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%
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Natural gas rates
Regulatory environment
Approved annual rate increase (decrease)			$ 0
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Steam rates | Downtown Milwaukee (Valley) steam customers
Regulatory environment
Approved annual rate increase (decrease)			0
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Steam rates | Milwaukee County steam customers
Regulatory environment
Approved annual rate increase (decrease)			$ 0
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%
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
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%
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%)
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%)
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%
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%
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%)
Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Natural gas rates
Regulatory environment
Approved annual rate increase (decrease)				$ 0
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%
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%
Public Service Commission of Wisconsin (PSCW) | 2013 Rates
Regulatory environment
Approved return on equity (as a percent)				10.40%
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%
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%
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%
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%)
Public Service Commission of Wisconsin (PSCW) | 2013 Rates | Natural gas rates | Bad debt expense
Regulatory environment
Approved annual rate increase (decrease)				$ (6.4)
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%
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%
UMERC
Regulatory environment
Term of Electric Power Purchase Agreement	20 years
Capacity of Natural Gas Generating Facility | MW	180
Cost to construct power plant	$ 265
Cost to construct power plant with AFUDC	$ 275
Estimated portion of power plant cost recovery from Tilden Mines	50.00%
Estimated portion of power plant cost recovery from utility customers	50.00%

Segment Information (Details)

Segment Information (Details) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)areasegment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Segment information
Number of reportable segments | segment									2
Number of areas serviced by our natural gas utility segment | area									3
Operating revenues	$ 916.3	$ 1,023.8	$ 877.2	$ 975.5	$ 905.4	$ 981.1	$ 883	$ 1,084.6	$ 3,792.8	$ 3,854.1	$ 4,059.4
Other operation and maintenance									1,430.2	1,384.9	1,356.4
Depreciation and amortization									325.4	304	278.3
Operating income	104.7	$ 196.4	$ 146.9	$ 181.5	145.7	$ 169.8	$ 128.7	$ 204.7	629.5	648.9	650.4
Equity in earnings of transmission affiliate									55.5	47.8	57.9
Interest expense									117.6	119	116.5
Capital expenditures									469.5	519.2	561.8
Assets	13,371.5				13,139.6				13,371.5	13,139.6	12,597.2
Utility
Segment information
Operating revenues									3,792.8	3,854.1	4,059.4
Other operation and maintenance									1,430.2	1,384.9	1,356.4
Depreciation and amortization									325.4	304	278.3
Operating income									629.5	648.9	650.4
Equity in earnings of transmission affiliate									0	0	0
Interest expense									116.6	117.7	114.9
Capital expenditures									468.9	518.8	561.8
Assets	12,945.1				12,727.6				12,945.1	12,727.6	12,195.9
Other
Segment information
Operating revenues									0	0	0
Other operation and maintenance									0	0	0
Depreciation and amortization									0	0	0
Operating income									0	0	0
Equity in earnings of transmission affiliate									55.5	47.8	57.9
Interest expense									1	1.3	1.6
Capital expenditures									0.6	0.4	0
Assets	$ 426.4				$ 412				426.4	412	401.3
ATC
Segment information
Equity in earnings of transmission affiliate									$ 55.5	$ 47.8	$ 57.9
Equity Method Investment, Ownership Percentage	23.00%								23.00%

Quarterly Financial Informat101

Quarterly Financial Information (Unaudited) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 916.3	$ 1,023.8	$ 877.2	$ 975.5	$ 905.4	$ 981.1	$ 883	$ 1,084.6	$ 3,792.8	$ 3,854.1	$ 4,059.4
Operating income	104.7	196.4	146.9	181.5	145.7	169.8	128.7	204.7	629.5	648.9	650.4
Net income attributed to common shareholder	$ 59.2	$ 115.2	$ 82.6	$ 107.3	$ 79.6	$ 100.1	$ 74.6	$ 121.4	$ 364.3	$ 375.7	$ 376.7

Schedule II - Valuation and 102

Schedule II - Valuation and Qualifying Accounts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Valuation and qualifying accounts
Balance at beginning of period	$ 43	$ 46.8	$ 39.7
Expense	31.1	30.6	31.3
Deferral	(5.7)	0.3	10
Net write-offs	(27.5)	(34.7)	(34.2)
Balance at end of period	$ 40.9	$ 43	$ 46.8