Wisconsin Public Service (WSPBP) 10-K 28 Feb 17 2016 FY Annual report Financial data

DOCUMENT AND ENTITY INFORMATION

DOCUMENT AND ENTITY INFORMATION - USD ($)	12 Months Ended
	Dec. 31, 2016	Jan. 31, 2017	Jun. 30, 2016
Document and Entity Information
Entity Registrant Name	WISCONSIN PUBLIC SERVICE CORP
Entity Central Index Key	107,833
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		23,896,962
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Operating revenues	$ 1,448.2	$ 1,483.3	$ 1,683.6
Cost of sales	527.6	599.8	771.1
Other operation and maintenance	493.2	493.4	499.7
Depreciation and amortization	124.1	121	116.8
Property and revenue taxes	39.8	41	38.4
Total operating expenses	1,184.7	1,255.2	1,426
Operating income	263.5	228.1	257.6
Other income, net	30.8	25.6	25.2
Interest expense	48.1	53.5	57.4
Other expense	(17.3)	(27.9)	(32.2)
Income before income taxes	246.2	200.2	225.4
Income tax expense	90.5	75	84.7
Net income	155.7	125.2	140.7
Preferred stock dividend requirements	0	2.7	3.1
Net income attributed to common shareholder	$ 155.7	$ 122.5	$ 137.6

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Assets
Cash and cash equivalents	$ 3.1	$ 6.1
Accounts receivable and unbilled revenues, net of reserves of $3.0 and $2.5, respectively	194.7	164
Receivables from related parties	3	3.1
Materials, supplies, and inventories	125.3	145
Prepaid taxes	57.3	48.1
Other	24.5	27
Current assets	407.9	393.3
Property, plant, and equipment, net of accumulated depreciation of $1,595.1 and $1,565.7, respectively	3,662	3,418.6
Regulatory assets	465.8	462.5
Goodwill	36.4	36.4
Pension and OPEB assets	114.8	102.4
Other	121.3	91.9
Long-term assets	4,400.3	4,111.8
Total assets	4,808.2	4,505.1
Liabilities and Shareholders' Equity
Short-term debt	176.8	182.8
Current portion of long-term debt	125	0
Current portion of long-term debt to parent	0	2.9
Accounts payable	165.4	181.8
Payables to related parties	21.6	35.6
Other	64.2	50.2
Current liabilities	553	453.3
Long-term debt	1,165.3	1,289.4
Deferred income taxes	929.5	774.1
Deferred investment tax credits	7	7.4
Regulatory liabilities	291.3	290
Environmental remediation liabilities	97.2	83.5
Pension and OPEB obligations	25.4	24.4
Payables to related parties	4.1	4.8
Other	107.2	92.3
Long-term liabilities	2,627	2,565.9
Commitments and contingencies (Note 16)
Common stock – $4 par value; 32,000,000 shares authorized; 23,896,962 shares issued and outstanding	95.6	95.6
Additional paid-in capital	966.9	861.8
Retained earnings	565.7	528.5
Shareholder's equity	1,628.2	1,485.9
Total liabilities and shareholder's equity	$ 4,808.2	$ 4,505.1

CONSOLIDATED BALANCE SHEETS (PA

CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Accounts receivable and unbilled revenues, reserves (in dollars)	$ 3	$ 2.5
Property, plant, and equipment, accumulated depreciation (in dollars)	$ 1,595.1	$ 1,565.7
Common stock, par value (in dollars per share)	$ 4
Common stock, shares authorized	32,000,000
Common stock, shares issued	23,896,962	23,896,962
Common stock, shares outstanding	23,896,962	23,896,962

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Activities
Net income	$ 155.7	$ 125.2	$ 140.7
Reconciliation to cash provided by operating activities
Depreciation and amortization	124.1	121	113.8
Pension and other postretirement expense (credit)	3	(2.7)	(6.2)
Contributions to pension and OPEB plans	(1.4)	(2.4)	(49.5)
Deferred income taxes and investment tax credits, net	143	43.6	90.5
Change in –
Collateral on deposit	(0.2)	(17.4)	(3.8)
Accounts receivable and unbilled revenues	(33.1)	38.6	13.4
Materials, supplies, and inventories	20.3	(16.1)	(28)
Prepaid taxes	(9.2)	17.6	(2.1)
Other current assets	0.9	1.5	3.7
Accounts payable	(24.4)	5	15.5
Other current liabilities	17.7	(3.3)	(14)
Other, net	(7.4)	(5.9)	(10.5)
Net cash provided by operating activities	389	304.7	263.5
Investing activities
Capital expenditures	(311.1)	(371)	(322)
Payments for assets received from WBS	(34.1)	0	0
Other, net	4.4	(2.3)	0.9
Net cash used for investing activities	(340.8)	(373.3)	(321.1)
Financing activities
Change in short-term debt	(6)	37.7	119.5
Repayment of loan	(28.6)	0	0
Repayment of long-term debt	0	(125.1)	0
Repayment of long-term debt to parent	(2.9)	(2.5)	(0.9)
Issuance of long-term debt	0	250	0
Payments of dividend to parent	(118.5)	(115.1)	(111.8)
Equity contribution from parent	105	235	55
Return of capital to parent	0	150	0
Preferred stock dividend requirements	0	(2.7)	(3.1)
Redemption of preferred stock	0	(52.7)	0
Other, net	(0.2)	(5.3)	(1.4)
Net cash (used for) provided by financing activities	(51.2)	69.3	57.3
Net change in cash and cash equivalents	(3)	0.7	(0.3)
Cash and cash equivalents at beginning of year	6.1	5.4	5.7
Cash and cash equivalents at end of year	$ 3.1	$ 6.1	$ 5.4

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions	Total	Total Common Shareholder's Equity	Common Stock	Additional Paid in Capital	Retained Earnings
Balance at Dec. 31, 2013		$ 1,315.4	$ 95.6	$ 723.5	$ 496.3
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributed to common shareholder	$ 137.6	137.6	0	0	137.6
Equity contribution from parent	55	55	0	55	0
Return of capital to parent	0
Dividends to parent		(111.8)	0	0	(111.8)
Other		3.2	0	3.5	(0.3)
Balance at Dec. 31, 2014		1,399.4	95.6	782	521.8
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributed to common shareholder	122.5	122.5	0	0	122.5
Equity contribution from parent	235	235	0	235	0
Return of capital to parent	(150)	(150)	0	(150)	0
Dividends to parent		(115.1)	0	0	(115.1)
Other		(5.9)	0	(5.2)	(0.7)
Balance at Dec. 31, 2015	1,485.9	1,485.9	95.6	861.8	528.5
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributed to common shareholder	155.7	155.7	0	0	155.7
Equity contribution from parent	105	105	0	105	0
Return of capital to parent	0
Dividends to parent		(118.5)	0	0	(118.5)
Other		0.1	0	0.1	0
Balance at Dec. 31, 2016	$ 1,628.2	$ 1,628.2	$ 95.6	$ 966.9	$ 565.7

CONSOLIDATED STATEMENTS OF CAPI

CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Schedule of Capitalization
Common shareholder's equity	$ 1,628.2	$ 1,485.9
Current portion of long-term debt to parent	0	(2.9)
Total long-term debt to parent	0	0
Total	1,300	1,300
Unamortized debt issuance costs	(9.1)	(9.9)
Unamortized discount, net	(0.6)	(0.7)
Total long-term debt, including current portion	1,290.3	1,289.4
Current portion of long-term debt	(125)	0
Total long-term debt	1,165.3	1,289.4
Total long-term capitalization	$ 2,793.5	2,775.3
Long Term debt to parent, 7.35% Series, Year Due, 2016
Schedule of Capitalization
Interest rate, (as a percent)	7.35%
Notes payable to Integrys	$ 0	2.9
Long Term debt, 5.65% Series, Year Due, 2017
Schedule of Capitalization
Interest rate, (as a percent)	5.65%
Senior Notes	$ 125	125
Long Term Debt 1.65% Series, Due 2018
Schedule of Capitalization
Interest rate, (as a percent)	1.65%
Senior Notes	$ 250	250
Long Term debt, 6.08% Series, Year Due, 2028
Schedule of Capitalization
Interest rate, (as a percent)	6.08%
Senior Notes	$ 50	50
Long Term debt, 5.55% Series, Year Due, 2036
Schedule of Capitalization
Interest rate, (as a percent)	5.55%
Senior Notes	$ 125	125
Long Term Debt 3.671% Series, Year Due, 2042
Schedule of Capitalization
Interest rate, (as a percent)	3.671%
Senior Notes	$ 300	300
Long Term debt 4.752% Series, Year Due 2044
Schedule of Capitalization
Interest rate, (as a percent)	4.752%
Senior Notes	$ 450	$ 450

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a) General Information —On June 29, 2015, Wisconsin Energy Corporation acquired our parent company, Integrys, and changed its name to WEC Energy Group. See Note 2, Merger, for more information on the acquisition. We are an electric and natural gas utility company that serves customers in northeastern Wisconsin and served customers in the Upper Peninsula of Michigan. We are subject to the jurisdiction of, and regulation by, the PSCW, which has general supervisory and regulatory powers over virtually all phases of the public utility industry in Wisconsin. We are also subject to the jurisdiction of the FERC, which regulates our natural gas pipelines and wholesale electric rates. 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 WE located in the Upper Peninsula of Michigan. 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. The financial statements include our accounts and the accounts of our former wholly owned subsidiary, WPS Leasing, which was dissolved in July 2016. These financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 7, Jointly Owned Utility Facilities, for more information . The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. 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) Cash and Cash Equivalents —Cash and cash equivalents include marketable debt securities with an original maturity of three months or less. (c) 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. • 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. 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 and natural gas service to customers in northeastern Wisconsin and provided this service to customers in the Upper Peninsula of Michigan through December 31, 2016. See Note 3, Related Parties , and Note 19, 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. 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 . (d) Materials, Supplies, and Inventories —Our inventory as of December 31 consisted of: (in millions) 2016 2015 Fossil fuel $ 66.7 $ 76.4 Materials and supplies 37.5 40.5 Natural gas in storage 21.1 28.1 Total $ 125.3 $ 145.0 Substantially all fossil fuel, materials and supplies, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting. (e) 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 5, Regulatory Assets and Liabilities, for more information . (f) Property, Plant, and Equipment —We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Depreciation as a percent of average depreciable utility plant was 2.58% , 2.60% , and 2.63% 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 3 to 11 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement. We receive grants related to certain renewable generation projects under federal and state grant programs. Our policy is to reduce the depreciable basis of the qualifying project by the grant received. We then reflect the benefit of the grant in income over the life of the related renewable generation project through a reduction in depreciation expense. See Note 6, Property, Plant, and Equipment, for more information . (g) 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 7.72% , 7.92% , and 8.08% for 2016 , 2015 , and 2014 , respectively. Our average AFUDC wholesale rates were 3.00% , 5.10% , and 6.99% for 2016 , 2015 , and 2014 , respectively. We recorded the following AFUDC for the years ended December 31: (in millions) 2016 2015 2014 AFUDC – Debt $ 8.1 $ 6.1 $ 4.6 AFUDC – Equity 19.5 15.1 11.0 (h) Emission Allowances —We account for emission allowances as inventory at average cost by vintage year. Charges to income result when allowances are used in operating our generation plants. These charges are included in the costs subject to the fuel window rules. Gains on sales of allowances are returned to ratepayers. (i) Goodwill —Goodwill is subject to an annual impairment test. Our utility reporting unit contains goodwill and performed its annual goodwill impairment test as of July 1, 2016. Due to the WEC Merger, we changed the date of our annual goodwill impairment test from April 1 to July 1 during 2016. Interim impairment tests are also performed when impairment indicators are present. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value. (j) 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 8, Asset Retirement Obligations, for more information . (k) 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 8, 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 potential 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 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. (l) 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. (m) Guarantees —We follow the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. As of December 31, 2016, we had a $9.4 million standby letter of credit, due in May 2017, that was issued by a financial institution for the benefit of a third party that extended credit to us. This amount is not reflected on our balance sheets. (n) Employee Benefits —The costs of pension and OPEB 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 . (o) Stock-Based Compensation —Prior to the WEC Merger, our employees were granted awards under Integrys’s stock-based compensation plans. Pursuant to the Merger Agreement, immediately prior to completion of the merger, all outstanding stock-based compensation awards became fully vested and were either paid to award recipients in cash, or the value of the awards was deferred into a deferred compensation plan. The total intrinsic value of awards granted to our employees that were settled due to the WEC Merger was $6.7 million . In 2016, our employees were granted awards under WEC Energy Group's 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 6 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 Non-qualified stock options granted 24,485 Estimated fair value per non-qualified stock option $ 5.63 Risk-free interest rate 0.4% – 1.8% Dividend yield 4.0 % Expected volatility 18.0 % Expected life (years) 7.5 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. (p) Fair Value Measurements —Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. Derivatives were transferred between levels of the fair value hierarchy primarily due to observable pricing becoming available. We recognize transfers at their value as of the end of the reporting period. Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our long-term debt is estimated based upon the quoted market value for the same or similar issues. The fair value of long-term debt is categorized within Level 2 of the fair value hierarchy. See Note 17, Fair Value Measurements, for more information . (q) 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 were approved by the PSCW and the MPSC. We record derivative instruments on our balance sheets as assets or liabilities measured at fair value, unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Realized gains and losses on derivative instruments are primarily recorded in cost of sales on 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. See Note 18, Derivative Instruments, for more information . (r) 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 accounts payable on our balance sheets.

MERGER

MERGER	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
MERGER	MERGER On June 29, 2015, the WEC Merger was completed, and our parent company became a wholly owned subsidiary of Wisconsin Energy Corporation. Wisconsin Energy Corporation then changed its name to WEC Energy Group. The merger 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 requires that 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 WE filed a joint integrated resource plan with the PSCW for our combined loads, which indicated that there is no need to proceed with the proposed construction of a new generating unit at the Fox Energy Center site at this time. We have been authorized to recover the costs we have recorded related to the proposed construction. We do not believe that the conditions set forth in the various regulatory orders approving the WEC Merger will have a material impact on our operations or financial results. In 2015, we recorded $4.6 million of severance expense that resulted from employee reductions related to the post-merger 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 $4.3 million were made during 2015, leaving an insignificant severance accrual on our balance sheets at December 31, 2016 and 2015.

RELATED PARTIES

RELATED PARTIES	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
RELATED PARTIES	RELATED PARTIES We 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 ultimate parent, WEC Energy Group, and other subsidiaries of WEC Energy Group. Following the WEC Merger on June 29, 2015, Integrys Business Support, LLC (IBS) changed its name to WBS, and a new AIA (Non-WBS AIA) went into effect. The Non-WBS AIA included the former Wisconsin Energy Corporation and its subsidiaries. It 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 under interim WBS AIAs. The Non-WBS AIA included no other significant changes from the prior Non-IBS AIA. 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 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 WBS AIAs. Other modifications or amendments to the 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. For more information on the natural gas storage facility acquisition, see below. We hold a 10.37% investment in WPSI, which holds an approximate 34% interest in ATC. We provide services to and receive services from ATC for its transmission facilities under several agreements approved by the PSCW. Services were billed to ATC under these agreements at our fully allocated cost. Effective January 1, 2017, based upon input we received from the PSCW, we transferred our ownership interest in WPSI to another subsidiary of Integrys. This transaction was a non-cash equity transfer between entities under common control, and therefore, did not result in a gain or loss recognized. We provide services to WRPC under an operating agreement approved by the PSCW. We are also under a service agreement with WRPC under which either party may be a service provider. Services are billed to and from WRPC under these agreements at a fully allocated cost. The table below includes information summarizing other transactions entered into with related parties: (in millions) December 31, 2016 December 31, 2015 Accounts receivable Service provided to ATC $ 1.1 $ 0.5 Notes payable, current portion * Integrys — 2.9 Accounts payable Network transmission services from ATC 8.8 8.5 Liability related to income tax allocation Integrys 4.8 5.4 * WPS Leasing, our former consolidated subsidiary, had a note payable to our parent company, Integrys, that was paid off in May 2016. The following table shows activity associated with related party transactions for the years ended December 31: (in millions) 2016 2015 2014 Electric transactions Sales to UPPCO (1) $ — $ — $ 15.3 Natural gas transactions Sales to WE 1.9 0.4 — Purchases from IES (2) — — 2.5 Transactions with WE (3) Billings to WE 4.2 4.9 — Billings from WE 9.0 13.4 — Transactions with WBS Billings to WBS (4) 21.7 9.7 7.6 Billings from WBS (5) 171.0 148.4 149.0 Transactions with equity-method investees Charges from ATC for network transmission services 109.4 101.3 99.0 Charges to ATC for services and construction 8.6 10.3 8.6 Purchases of energy from WRPC 3.7 3.8 3.7 Charges to WRPC for operations 0.7 1.1 1.4 Equity earnings from WPSI (6) 8.7 7.7 9.5 (1) Integrys sold UPPCO in August 2014. (2) Integrys sold IES's retail energy business in November 2014. (3) Includes amounts billed for services, pass through costs, and other items in accordance with the approved AIAs discussed above. (4) Includes $7.3 million for the transfer of certain software assets to WBS for the year ended December 31, 2016 . (5) Includes $18.2 million for the transfer of certain benefit-related liabilities to WBS and $34.1 million for the transfer of certain software assets to us for the year ended December 31, 2016. (6) At December 31, 2016, WPSI was an indirect wholly-owned subsidiary of WEC Energy Group that was jointly owned by Integrys and us. WPSI holds an approximate 34% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. At December 31, 2016 , we had a 10.37% interest in WPSI accounted for under the equity method. On January 1, 2017, we transferred our interest in WPSI to another subsidiary of Integrys. 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 9,000 retail electric customers and 5,300 natural gas customers to UMERC, along with approximately 600 miles of electric distribution lines and approximately 100 miles of natural gas distribution mains. 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 $19 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 WE. The new utility has also proposed a long-term generation solution for electric reliability in the region. See Note 19, Regulatory Environment, for more information . Parent Company's Acquisition of a Natural Gas Storage Facility in Michigan In January 2017, WEC Energy Group 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.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
CASH AND CASH EQUIVALENTS	SUPPLEMENTAL CASH FLOW INFORMATION (in millions) 2016 2015 2014 Cash (paid) for interest, net of amount capitalized $ (54.6 ) $ (58.1 ) $ (56.8 ) Cash received (paid) for income taxes, net 39.9 (14.5 ) 6.2 Significant non-cash transactions: Accounts payable related to construction costs 67.2 70.5 54.0

REGULATORY ASSETS AND LIABILITI

REGULATORY ASSETS AND LIABILITIES	12 Months Ended
	Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
REGULATORY ASSETS AND LIABILITIES	REGULATORY ASSETS AND LIABILITIES The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2016 2015 See Note Regulatory assets (1) (2) Unrecognized pension and OPEB costs (3) $ 182.9 $ 176.6 15 Environmental remediation costs (4) 116.0 104.4 16 Income tax related items (5) 55.7 40.8 Termination of a tolling agreement with Fox Energy Company LLC (6) 33.7 39.1 Crane Creek production tax credits (7) 29.6 30.9 De Pere Energy Center (8) 16.7 19.0 Other, net 31.2 51.9 Total regulatory assets $ 465.8 $ 462.7 Balance Sheet Presentation Current assets (9) $ — $ 0.2 Regulatory assets 465.8 462.5 Total regulatory assets $ 465.8 $ 462.7 (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 $18.8 million of regulatory assets not earning a return. The regulatory assets not earning a return relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures. (3) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We are authorized recovery of this regulatory asset over the average remaining service life of each plan. (4) As of December 31, 2016 , we had not yet made cash expenditures for $97.2 million of these environmental remediation costs. (5) Represents adjustments related to deferred income taxes, which are recovered in rates as the temporary differences that generated the income tax benefit reverse. (6) Represents an early termination fee of a tolling agreement we had with the Fox Energy Center. Prior to the purchase of the Fox Energy Center in 2013, we supplied natural gas for the facility and purchased capacity and the associated energy output under the tolling agreement. We are authorized recovery of this asset over a nine-year period that began on January 1, 2014. (7) In 2012, we elected to claim and subsequently received a Section 1603 Grant for the Crane Creek wind project in lieu of the production tax credit. As a result, we reversed previously recorded production tax credits. We also reduced the depreciable basis of the qualifying facility by the amount of the grant proceeds, which will result in a reduction of depreciation and amortization expense over a 12 -year period. We recorded a regulatory asset for the deferral of previously recorded production tax credits and are authorized recovery of this net regulatory asset through 2039. (8) Prior to purchasing the De Pere Energy Center in 2002, we had a long-term power purchase contract with them that was accounted for as a capital lease. As a result of the purchase, the capital lease obligation was reversed, and the difference between the capital lease asset and the purchase price was recorded as a regulatory asset. We are authorized recovery of this regulatory asset through 2023. (9) Short-term regulatory assets are recorded in accounts receivable and unbilled revenues on our balance sheets. The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2016 2015 See Note Regulatory liabilities Removal costs (1) $ 248.9 $ 243.7 Energy costs refundable through rate adjustments (2) 14.5 29.4 Unrecognized pension and OPEB costs (3) 14.3 1.0 15 Crane Creek depreciation deferral (4) 8.0 8.3 Other, net 10.8 11.2 Total regulatory liabilities $ 296.5 $ 293.6 Balance Sheet Presentation Other current liabilities $ 5.2 $ 3.6 Regulatory liabilities 291.3 290.0 Total regulatory liabilities $ 296.5 $ 293.6 (1) Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment. (2) Represents energy costs that will be refunded to customers in the future. (3) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan. (4) Represents the book depreciation taken on the Crane Creek wind project prior to our election to claim a Section 1603 Grant for the project in lieu of the production tax credit. See more information in the regulatory assets section above.

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 assets at December 31: (in millions) 2016 2015 Utility property, plant, and equipment $ 5,144.5 $ 4,541.2 Less: Accumulated depreciation 1,594.7 1,559.6 Net 3,549.8 2,981.6 CWIP 111.9 434.2 Net utility property, plant, and equipment 3,661.7 3,415.8 Non-utility property, plant, and equipment 0.7 8.9 Less: Accumulated depreciation 0.4 6.1 Net non-utility plant 0.3 2.8 Total property, plant, and equipment $ 3,662.0 $ 3,418.6 On January 1, 2017, we transferred approximately 600 miles of electric distribution lines and approximately 100 miles of natural gas distribution mains to UMERC. We also transferred related electric distribution substations in the Upper Peninsula of Michigan. The estimated net book value of the property, plant, and equipment we transferred to UMERC was $19 million . See Note 3, Related Parties , and Note 19, Regulatory Environment , for more information.

JOINTLY OWNED UTILITY FACILITIE

JOINTLY OWNED UTILITY FACILITIES	12 Months Ended
	Dec. 31, 2016
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]
JOINTLY OWNED UTILITY FACILITIES	JOINTLY OWNED UTILITY FACILITIES We hold a joint ownership interest in certain electric generating facilities. We are entitled to our share of generating capability and output of each facility equal to our respective ownership interest. We also pay our ownership share of additional construction costs, fuel inventory purchases, and operating expenses, unless specific agreements have been executed to limit our maximum exposure to additional costs. We record our proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. Information related to jointly owned facilities at December 31, 2016 was as follows: (in millions, except for percentages and MWs) Weston Unit 4 Columbia Energy Center Units 1 and 2 Edgewater Unit 4 Ownership 70.0 % 31.8 % (2) 31.8 % Our share of rated capacity (MWs) (1) 373.5 334.4 98.0 In-service date 2008 1975 and 1978 1969 Property, plant, and equipment $ 596.3 $ 417.9 $ 45.8 Accumulated depreciation $ (170.3 ) $ (128.3 ) $ (31.7 ) CWIP $ 0.2 $ 41.2 $ 0.1 (1) Based on expected capacity ratings for summer 2017 . The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. (2) Columbia Energy Center (Columbia) is jointly owned by Wisconsin Power and Light (WPL), Madison Gas and Electric (MGE), and us. In October 2016, WPL received an order from the PSCW approving amendments to the Columbia joint operating agreement between the parties allowing MGE and us to forgo certain capital expenditures. As a result, WPL will incur these capital expenditures in exchange for a proportional increase in its ownership share of Columbia. Based upon the additional capital expenditures WPL expects to incur through June 1, 2020, our ownership interest would decrease to 27.5% . Our proportionate share of direct expenses for the joint operation of these plants is recorded in operating expenses in the income statements. We have supplied our own financing for all jointly owned projects. See Note 16, Commitments and Contingencies , for information related to the requirement to refuel, repower, or retire Edgewater Unit 4.

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 facilities, office buildings, and service centers; the dismantling of wind generation projects; the disposal of polychlorinated biphenyls-contaminated transformers; and the closure of fly-ash landfills at certain 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 $ 32.7 $ 20.3 $ 18.0 Accretion 1.5 1.2 1.0 Additions and revisions to estimated cash flows (1.6 ) (1 ) 11.4 (2 ) 1.5 (3 ) Liabilities settled — (0.2 ) (0.2 ) Balance as of December 31 $ 32.6 $ 32.7 $ 20.3 (1) We revised the AROs recorded for our fly-ash landfills during 2016 due to changes in estimated removal costs. (2) During 2015, an ARO of $9.0 million was recorded for the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule passed by the EPA in April 2015. In addition, we revised the AROs recorded for our fly-ash landfills due to changes in estimated removal costs and settlement dates. (3) We revised the AROs recorded for the asbestos at our electric generation facilities during 2014 primarily due to changes in estimated settlement dates.

GOODWILL AND OTHER INTANGIBLE A

GOODWILL AND OTHER INTANGIBLE ASSETS	12 Months Ended
	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL AND OTHER INTANGIBLE ASSETS	GOODWILL AND OTHER INTANGIBLE ASSETS Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. We had no changes to the carrying amount of goodwill during the years ended December 31, 2016 and 2015 . Due to the WEC Merger, we changed the date of our annual goodwill impairment test from April 1 to July 1. Since no more than 12 months is allowed to elapse between impairment tests, we performed a step zero qualitative impairment test as of April 1, 2016, and a quantitative impairment test as of July 1, 2016. No impairments resulted from these tests. The identifiable intangible assets other than goodwill listed below are classified as other long-term assets on our balance sheets. December 31, 2016 December 31, 2015 (in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Amortized intangible assets * $ 15.6 $ (10.7 ) $ 4.9 $ 15.6 $ (7.5 ) $ 8.1 Unamortized intangible assets 0.4 — 0.4 0.4 — 0.4 Total intangible assets $ 16.0 $ (10.7 ) $ 5.3 $ 16.0 $ (7.5 ) $ 8.5 * Represents contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The remaining weighted-average amortization period for these intangible assets at December 31, 2016 , was approximately three years .

COMMON EQUITY

COMMON EQUITY	12 Months Ended
	Dec. 31, 2016
Stockholders' Equity Note [Abstract]
COMMON EQUITY	COMMON EQUITY Stock-Based Compensation 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 WEC Energy Group stock options $ 0.5 $ — $ — WEC Energy Group restricted shares 1.4 — — WEC Energy Group performance units 1.5 — — Integrys stock options — — 1.0 Integrys performance stock rights — 1.3 6.3 Integrys restricted share units — 3.5 3.8 Stock-based compensation expense $ 3.4 $ 4.8 $ 11.1 Related tax benefit $ 1.4 $ 1.9 $ 4.4 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 — $ — Granted 24,485 $ 55.36 Outstanding as of December 31, 2016 24,485 $ 55.36 9.1 $ 0.1 Exercisable as of December 31, 2016 1,840 $ 55.36 9.1 $ — 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. 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 23,300 non-qualified WEC Energy Group stock options with an exercise price of $58.31 and a weighted-average grant date fair value of $7.53 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 — $ — Granted 18,306 $ 55.48 Forfeited (4,071 ) $ 55.48 Outstanding as of December 31, 2016 14,235 $ 55.48 As of December 31, 2016 , we expect to recognize approximately $1.2 million of unrecognized compensation cost related to WEC Energy Group restricted stock over the next 2.0 years on a weighted-average basis. During the first quarter of 2017 , the Compensation Committee awarded 2,313 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 , the Compensation Committee awarded 9,235 WEC Energy Group performance units to our officers and other key employees under the WEC Energy Group Performance Unit Plan. As of December 31, 2016 , we expect to recognize approximately $1.9 million of unrecognized compensation cost related to WEC Energy Group performance units over the next 1.4 years on a weighted-average basis. In January 2017, the Compensation Committee awarded 10,025 WEC Energy Group performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. Restrictions Various laws, regulations, and financial covenants impose restrictions on our ability to transfer funds to Integrys 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 or Integrys. 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. 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 $531.9 million . Our equity in undistributed earnings of investees accounted for by the equity method was $34.5 million at December 31, 2016 . Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions.

PREFERRED STOCK

PREFERRED STOCK	12 Months Ended
	Dec. 31, 2016
Class of Stock Disclosures [Abstract]
PREFERRED STOCK	PREFERRED STOCK We have 1,000,000 shares of preferred stock with a $100 par value authorized for issuance, of which none were issued and outstanding at December 31, 2016 and 2015.

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	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 $ 176.8 $ 182.8 Average interest rate on amounts outstanding at December 31 1.01% 0.66 % Our average amount of commercial paper borrowings based on daily outstanding balances during 2016 was $145.8 million , with a weighted-average interest rate during the period of 0.62% . 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% . 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 $ 250.0 Less: commercial paper outstanding 176.8 Available capacity under existing agreement $ 73.2 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

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT See our statements of capitalization for details on our long-term debt. The following table shows the future maturities of our long-term debt outstanding as of December 31, 2016 : (in millions) Payments 2017 $ 125.0 2018 250.0 2019 — 2020 — 2021 — Thereafter 925.0 Total $ 1,300.0 We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense.

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 $ (52.5 ) $ 31.4 $ (6.1 ) Deferred income taxes, net 143.3 44.0 91.1 Investment tax credit, net (0.3 ) (0.4 ) (0.3 ) Total income tax expense $ 90.5 $ 75.0 $ 84.7 Statutory Rate Reconciliation The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: 2016 2015 2014 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate Expected tax at statutory federal tax rates $ 86.2 35.0 % $ 70.1 35.0 % $ 78.9 35.0 % State income taxes net of federal tax benefit 11.6 4.7 9.9 5.0 10.9 4.8 AFUDC – Equity (6.8 ) (2.7 ) (5.3 ) (2.6 ) (3.8 ) (1.7 ) Other, net (0.5 ) (0.2 ) 0.3 0.1 (1.3 ) (0.5 ) Total income tax expense $ 90.5 36.8 % $ 75.0 37.5 % $ 84.7 37.6 % Deferred Income Tax Assets and Liabilities The components of deferred income taxes as of December 31 are as follows: (in millions) 2016 2015 Total deferred tax assets $ 12.9 $ 23.9 Deferred tax liabilities Plant-related 800.5 639.1 Employee benefits and compensation 99.3 91.7 Regulatory deferrals 38.4 52.0 Other 4.2 15.2 Total deferred tax liabilities 942.4 798.0 Deferred tax liability, net $ 929.5 $ 774.1 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 $11.4 million and $5.7 million of net operating loss and tax credit carryforwards resulting in deferred tax assets of $4.0 million and $5.7 million , respectively. These federal net operating loss and tax credit carryforwards begin to expire in 2028. We expect to have future taxable income sufficient to utilize these deferred tax assets. As of December 31, 2015, we had $46.1 million and $5.0 million of net operating loss and tax credit carryforwards resulting in deferred tax assets of $16.1 million and $5.0 million , respectively. As of December 31, 2016 and 2015, we had $18.6 million and $0.4 million , respectively, of state net operating loss carryforwards resulting in deferred tax assets of $1.0 million and zero . These state net operating loss carryforwards begin to expire in 2035. We expect to have future taxable income sufficient to utilize these deferred tax assets. Unrecognized Tax Benefits We had no unrecognized tax benefits at December 31, 2016, and 2015. We had no accrued interest or penalties related to unrecognized tax benefits at December 31, 2016 , and 2015 . We do not expect any unrecognized tax benefits to affect our effective tax rate in periods after December 31, 2016 . With a few exceptions, we are no longer subject to federal income tax examinations by the United States Internal Revenue Service for years prior to 2013. We file state tax returns based on income in our major state operating jurisdictions of Wisconsin and Michigan. We are no longer subject to state and local tax examinations for years prior to 2011. As of December 31, 2016 , we were subject to examination by the Wisconsin taxing authority for tax years 2011 through 2016 and the Michigan taxing authority for tax years 2012 through 2016. During 2016, the Michigan taxing authority completed its examination of tax years 2008 through 2011.

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 Through December 31, 2016, we participated in the Integrys Energy Group Retirement Plan, a noncontributory, qualified pension plan sponsored by WBS. We were responsible for our share of the plan assets and obligations. Effective January 1, 2017, the Integrys Energy Group Retirement Plan was split into six separate plans. As a result, we now have our own pension plan. While the split did not impact our pension benefit obligation, federal regulations required a different allocation of assets among the new plans. Assets were transferred out of our plan in January 2017, however we made additional contributions to the plan as discussed below. We serve as plan sponsor and administrator for certain OPEB plans. The benefits 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. WEC Energy Group also offers medical, dental, and life insurance benefits to our active employees and their dependents. We expense the allocated costs of these benefits as incurred. The defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. These employees receive an annual company contribution to their 401(k) savings plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year. In March 2014, we remeasured the obligations of certain OPEB plans as a result of a plan design change to move participants age 65 and older to a Medicare Advantage plan starting January 1, 2015. 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 share of the 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 $ 633.9 $ 791.8 $ 231.6 $ 252.5 Service cost 9.9 10.7 7.3 8.7 Interest cost 27.0 31.7 10.6 10.4 Plan amendments — — (18.9 ) — Transfer to/from affiliates * 6.2 (130.5 ) — — Actuarial loss (gain) 26.1 (36.4 ) 0.6 (31.7 ) Participant contributions — — 0.4 0.3 Benefit payments (47.9 ) (33.3 ) (8.5 ) (8.6 ) Plan curtailment — (0.1 ) — — Obligation at December 31 $ 655.2 $ 633.9 $ 223.1 $ 231.6 Change in fair value of plan assets Fair value at January 1 $ 719.0 $ 897.4 $ 224.5 $ 236.6 Actual return on plan assets 58.0 (29.4 ) 14.6 (5.1 ) Employer contributions 1.3 1.1 0.1 1.3 Participant contributions — — 0.4 0.3 Benefit payments (47.9 ) (33.3 ) (8.5 ) (8.6 ) Transfer to/from affiliates * 6.2 (116.8 ) — — Fair value at December 31 $ 736.6 $ 719.0 $ 231.1 $ 224.5 Funded status at December 31 $ 81.4 $ 85.1 $ 8.0 $ (7.1 ) * Benefit obligations and plan assets were moved along with our employees who were transferred to/from affiliated entities. As a result of the WEC Merger, certain of our employees were realigned across WEC Energy Group's various subsidiaries. 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 Pension and OPEB assets $ 89.0 $ 93.8 $ 25.8 $ 8.6 Pension and OPEB obligations 7.6 8.7 17.8 15.7 Total net assets (liabilities) $ 81.4 $ 85.1 $ 8.0 $ (7.1 ) The accumulated benefit obligation for the defined benefit pension plans was $590.8 million and $569.6 million at December 31, 2016 , and 2015 , respectively. The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31: (in millions) 2016 2015 Projected benefit obligation $ 7.6 $ 8.7 Accumulated benefit obligation 7.6 8.5 The following table shows the amounts that had 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 $ 221.4 $ 61.2 $ 27.8 $ 5.2 Prior service credits — — (80.6 ) — Total $ 221.4 $ 61.2 $ (52.8 ) $ 5.2 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 $ 17.3 $ 2.5 Prior service credits — (9.2 ) Total 2017 – estimated amortization $ 17.3 $ (6.7 ) 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 $ 9.9 $ 10.7 $ 8.6 $ 7.3 $ 8.7 $ 7.7 Interest cost 27.0 31.7 34.4 10.6 10.4 11.5 Expected return on plan assets (52.6 ) (64.8 ) (64.1 ) (15.9 ) (16.0 ) (16.0 ) Loss on plan settlement 3.4 0.1 0.4 — — — Amortization of prior service cost (credit) — 0.2 0.6 (7.4 ) (9.3 ) (8.0 ) Amortization of net actuarial loss 18.0 21.0 15.0 2.5 3.7 2.8 Net periodic benefit cost $ 5.7 $ (1.1 ) $ (5.1 ) $ (2.9 ) $ (2.5 ) $ (2.0 ) The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension OPEB 2016 2015 2016 2015 Discount rate 4.19% 4.49% 4.21% 4.46% Rate of compensation increase 4.00% 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 net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Costs 2016 2015 2014 Discount rate 4.25% 4.08% 4.92% Expected return on assets 7.25% 7.75% 8.00% Rate of compensation increase 4.00% 4.23% 4.25% OPEB Costs 2016 2015 2014 Discount rate 4.46% 4.11% 4.78% Expected return on assets 7.25% 7.75% 8.00% Assumed medical cost trend rate (Pre 65/Post 65) 7.50% 6.00% 6.50% Ultimate trend rate 5.00% 5.00% 5.00% Year ultimate trend rate is reached 2021 2023 2019 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 for the pension and OPEB plans is 7.25% . 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 $ 3.3 $ (2.6 ) Effect on the health care component of the accumulated postretirement benefit obligation 29.9 (23.7 ) 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 60% equity securities and 40% fixed income securities. The two largest OPEB trusts have target asset allocations of 50% equity investments and 50% fixed income, and 45% equity investments and 55% fixed income, respectively. Equity securities primarily 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(p), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used. Following our adoption of ASU 2015-07 on January 1, 2016, the assets that are not subject to leveling are investments that are valued using the net asset value per share (or its equivalent) practical expedient. We have applied this approach retrospectively to the 2015 table for comparability. The following tables provide the fair values of our investments by asset class: December 31, 2016 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ 1.3 $ 19.2 $ — $ 20.5 $ 10.3 $ 0.2 $ — $ 10.5 Equity securities: United States Equity 94.9 0.1 — 95.0 7.1 — — 7.1 International Equity 18.1 0.3 — 18.4 0.3 0.1 — 0.4 Fixed income securities: * United States Bonds — 151.7 0.5 152.2 — 33.2 — 33.2 International Bonds — 20.1 — 20.1 — 1.8 — 1.8 $ 114.3 $ 191.4 $ 0.5 $ 306.2 $ 17.7 $ 35.3 $ — $ 53.0 Investments measured at net asset value $ 430.4 $ 178.1 Total $ 114.3 $ 191.4 $ 0.5 $ 736.6 $ 17.7 $ 35.3 $ — $ 231.1 * 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 $ — $ 16.3 $ — $ 16.3 $ 3.7 $ 0.2 $ — $ 3.9 Equity securities: United States Equity 18.7 1.9 — 20.6 5.8 — — 5.8 International Equity 39.7 — — 39.7 15.9 — — 15.9 Fixed income securities: * United States Bonds 6.3 93.6 — 99.9 0.1 1.1 — 1.2 International Bonds — 22.1 — 22.1 — 0.2 — 0.2 $ 64.7 $ 133.9 $ — $ 198.6 $ 25.5 $ 1.5 $ — $ 27.0 Investments measured at net asset value $ 520.4 $ 197.5 Total $ 64.7 $ 133.9 $ — $ 719.0 $ 25.5 $ 1.5 $ — $ 224.5 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. The following table sets forth a reconciliation of changes in the fair value of pension plan assets categorized as Level 3 in 2016. There was no level 3 activity in 2015. (in millions) United States Bonds Beginning balance at January 1, 2016 $ — Purchases 0.5 Ending balance at December 31, 2016 $ 0.5 Cash Flows In January 2017, we contributed $65.0 million to the pension plan and expect to contribute an additional $0.7 million in 2017 , dependent on various factors affecting us, including our liquidity position and 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 $ 31.9 $ 9.7 2018 32.3 10.7 2019 33.2 11.4 2020 35.0 11.1 2021 35.5 11.6 2022-2026 179.3 63.5 Savings Plans WEC Energy Group sponsors a 401(k) savings plan which allows substantially all of our full-time employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. Certain employees participate in a defined contribution pension plan, in which amounts are contributed to an employee's savings plan account based on the employee's wages, age, and years of service. Our share of the total costs incurred under all of these plans was $9.0 million in 2016, $9.7 million in 2015 , and $8.6 million in 2014 .

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES We 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: Purchased power 2027 $ 622.7 $ 85.8 $ 54.7 $ 57.7 $ 60.1 $ 58.7 $ 305.7 Coal supply and transportation 2019 141.9 85.8 42.8 13.3 — — — Natural gas utility supply and transportation 2024 155.2 43.7 42.4 27.1 14.6 11.8 15.6 Total $ 919.8 $ 215.3 $ 139.9 $ 98.1 $ 74.7 $ 70.5 $ 321.3 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 $1.5 million , $1.4 million , and $1.6 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 $ 0.4 2018 0.6 2019 0.4 2020 0.5 2021 0.5 Later years 11.8 Total $ 14.2 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 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 June 2016, we provided modeling to the WDNR that shows the area around the Weston Power Plant to be in compliance. Based upon the submittal, the WDNR provided final modeling to the EPA demonstrating the area around the Weston Power Plant to be in compliance. We expect that the EPA will consider the WDNR's recommendation and finalize its recommended designation in August 2017, for finalization by the end of 2017. We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation. 8-Hour Ozone National Ambient Air Quality Standards The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released the final rule, which lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. For nonattainment areas, the state of Wisconsin will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020 and are in the process of reviewing and determining potential impacts resulting from this rule. We believe we are well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule. Mercury and Other Hazardous Air Pollutants In December 2011, the EPA issued the final MATS rule, which imposed stringent limitations on emissions of mercury and other hazardous air pollutants from coal and oil-fired electric generating units beginning in April 2015. In addition, Wisconsin has 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. Construction and testing of the ReACT TM multi-pollutant control system at Weston Unit 3 is complete, and the unit is currently in compliance with both MATS and our Consent Decree emission requirements. Climate Change In 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the final rule for existing fossil-fueled generating units, numerous states (including Wisconsin), 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 of 41% 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. 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. 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 5.7 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 5.7 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 3.5 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 3.6 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. Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for Pulliam Units 7 and 8 and Weston Unit 2, satisfy the IM BTA requirements. We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNR BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit. BTA determinations must also be made by the WDNR to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. BTA determinations for EM will be made in future permit reissuances for Pulliam Units 7 and 8 and Weston Units 2 through 4. 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 Weston Units 3 and 4 (which have existing cooling towers that meet EM BTA requirements), we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. Entrainment studies are currently being conducted at Pulliam Units 7 and 8. 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. 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 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. 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 Pulliam Units 7 and 8 and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $25 million to $35 million for these bottom ash transport systems. 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, some of which are in the EPA Superfund Alternative Approach Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure. In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below. The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites. We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31: (in millions) 2016 2015 Regulatory assets $ 116.0 $ 104.4 Reserves for future remediation 97.2 83.5 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 9.74% and met our compliance requirements by constructing various wind parks 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. We were in compliance with these requirements as of December 31, 2016 . 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. Consent Decrees Consent Decree – Weston and Pulliam In November 2009, the EPA issued a NOV to us, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. We entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013. The final Consent Decree includes: • the installation of emission control technology, including ReACT™ on Weston 3, • changed operating conditions (including refueling, repowering, and/or retirement of units), • limitations on plant emissions, • beneficial environmental projects totaling $6.0 million , and • a civil penalty of $1.2 million . The Consent Decree also contains requirements to refuel, repower, and/or retire certain Weston and Pulliam units. Effective June 1, 2015, we retired Weston Unit 1 and Pulliam Units 5 and 6. In March 2016, we submitted a proposed revision to the EPA to update requirements reflecting the conversion of Weston Unit 2 from coal to natural gas fuel, and also proposed revisions to the list of beneficial environmental projects required by the Consent Decree. These proposed revisions were approved by the EPA in May 2016. The revisions to the environmental projects are not expected to materially impact the overall costs noted above. We received approval from the PSCW in our 2015 rate order to defer and amortize the undepreciated book value of the retired plant related to Weston Unit 1 and Pulliam Units 5 and 6 starting June 1, 2015, and concluding by 2023. Therefore, in June 2015, we recorded a regulatory asset of $11.5 million for the undepreciated book value. In addition, we received approval from the PSCW in our rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. Also, in May 2010, we received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that we violated the CAA at the Weston and Pulliam plants. We entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of December 31, 2016 . It is unknown whether the Sierra Club will take further action in the future. Joint Ownership Power Plants Consent Decree – Columbia and Edgewater In December 2009, the EPA issued a NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, WE (former co-owner of an Edgewater unit), and us. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. We, along with Wisconsin Power and Light, Madison Gas and Electric, and WE entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. The final Consent Decree includes: • the installation of emission control technology, including scrubbers at the Columbia plant, • changed operating conditions (including refueling, repowering, and/or retirement of units), • limitations on plant emissions, • beneficial environmental projects, with our portion totaling $1.3 million , and • Our portion of a civil penalty and legal fees totaling $0.4 million . The Consent Decree contains a requirement to, among other things, refuel, repower, or retire Edgewater Unit 4, of which we are a joint owner, by no later than December 31, 2018. In the first quarter of 2015, management of the joint owners recommended that Edgewater Unit 4 be retired in December 2018. However, a final decision on how to address the requirement for this unit has not yet been made by the joint owners, as early retirement is contingent on various operational and market factors, and other alternatives to retirement are still available.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.1 $ 0.1 $ — $ 0.2 FTRs — — 2.0 2.0 Coal contracts — 0.1 — 0.1 Total derivative assets $ 0.1 $ 0.2 $ 2.0 $ 2.3 Derivative liabilities Coal contracts $ — $ 1.4 $ — $ 1.4 December 31, 2015 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.3 $ — $ — $ 0.3 FTRs — — 2.0 2.0 Total derivative assets $ 0.3 $ — $ 2.0 $ 2.3 Derivative liabilities Natural gas contracts $ 0.9 $ — $ — $ 0.9 Petroleum products contracts 0.5 — — 0.5 Coal contracts — 4.7 — 4.7 Total derivative liabilities $ 1.4 $ 4.7 $ — $ 6.1 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 at December 31 : (in millions) 2016 2015 2014 Balance at the beginning of the period $ 2.0 $ (0.3 ) $ (1.3 ) Realized and unrealized losses (0.2 ) (10.7 ) (1.0 ) Purchases 7.1 9.8 4.3 Sales (0.2 ) (0.1 ) — Settlements (6.7 ) (1.4 ) (3.5 ) Transfers out of level 3 — 4.7 1.2 Balance at the end of the period $ 2.0 $ 2.0 $ (0.3 ) 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 Long-term debt, including current portion $ 1,290.3 $ 1,373.4 $ 1,289.4 $ 1,350.4 Long-term debt to parent, including current portion * — — 2.9 3.0 * Our former consolidated subsidiary, WPS Leasing, Inc., had a note payable to our parent company, Integrys, that was paid off in May 2016.

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 $ 0.2 $ — $ 0.3 $ 0.9 Petroleum products contracts — — — 0.5 FTRs 2.0 — 2.0 — Coal contracts — 0.9 — 3.3 Total other current $ 2.2 $ 0.9 $ 2.3 $ 4.7 Other long-term Coal contracts $ 0.1 $ 0.5 $ — $ 1.4 Total $ 2.3 $ 1.4 $ 2.3 $ 6.1 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 (Losses) Natural gas contracts 28.6 Dth $ (1.4 ) 22.9 Dth $ (4.9 ) 20.0 Dth $ 0.6 Petroleum products contracts 4.4 gallons (0.6 ) 6.1 gallons (1.7 ) 5.3 gallons (0.1 ) FTRs 8.4 MWh 6.0 9.0 MWh 3.3 8.7 MWh 3.2 Total $ 4.0 $ (3.3 ) $ 3.7 At December 31, 2016 and 2015 , we had posted cash collateral of $16.1 million and $17.6 million , respectively, 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 $ 2.3 $ 1.4 $ 2.3 $ 6.1 Gross amount not offset on the balance sheet * — — (0.3 ) (1.4 ) Net amount $ 2.3 $ 1.4 $ 2.0 $ 4.7 * Includes cash collateral posted of $1.1 million at December 31, 2015 . There was no cash collateral included at December 31, 2016 .

REGULATORY ENVIRONMENT

REGULATORY ENVIRONMENT	12 Months Ended
	Dec. 31, 2016
Regulated Operations [Abstract]
REGULATORY ENVIRONMENT	REGULATORY ENVIRONMENT 2016 Wisconsin Rate Order In April 2015, we initiated a rate proceeding with the PSCW. In December 2015, the PSCW issued a final written order, effective January 1, 2016. The order, which reflects a 10.0% ROE and a common equity component average of 51.0% , authorized a net retail electric rate decrease of $7.9 million ( -0.8% ) and a net retail natural gas rate decrease of $6.2 million ( -2.1% ). The decrease in retail electric rates was due to lower monitored fuel costs in 2016 compared to 2015. Absent the adjustment for electric fuel costs, we would have realized an electric rate increase. Based on the order, the PSCW allowed escrow treatment for ATC and MISO network transmission expenses through 2016. In addition, future system support resource payments will continue to be escrowed until a future rate proceeding. The order directed us to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates. In addition, the PSCW approved a deferral for ReACT™, which required us to defer the revenue requirement of ReACT™ costs above the authorized $275.0 million level through 2016. Fuel costs will continue to be monitored using a 2% tolerance window. In March 2016, we requested extensions from the PSCW through 2017 for the deferral of the revenue requirement of ReACT™ costs above the authorized $275.0 million level as well as escrow accounting of ATC and MISO network transmission expenses. In April 2016, we also requested to extend through 2017 the previously approved deferral of the revenue requirement difference between the Real Time Market Pricing and the standard tariffed rates for any of our current large commercial and industrial customers who entered into a service agreement with us under Real Time Market Pricing prior to April 15, 2016. These requests were approved by the PSCW in June 2016. The amounts deferred related to these items as of December 31, 2016 , were not material. 2015 Wisconsin Rate Order In April 2014, we initiated a rate proceeding with the PSCW. In December 2014, the PSCW issued a final written order, effective January 1, 2015. It authorized a net retail electric rate increase of $24.6 million and a net retail natural gas rate decrease of $15.4 million , reflecting a 10.20% ROE. The order also included a common equity component average of 50.28% . The PSCW approved a change in rate design, which included higher fixed charges to better match the related fixed costs of providing service. In addition, the order continued to exclude a decoupling mechanism that was terminated beginning January 1, 2014. The primary driver of the increase in retail electric rates was higher costs of fuel for electric generation of approximately $42.0 million . In addition, 2015 rates include approximately $9.0 million of lower refunds to customers related to decoupling over-collections. In 2015 rates, we refunded approximately $4.0 million to customers related to 2013 decoupling over-collections compared with refunding approximately $13.0 million to customers in 2014 rates related to 2012 decoupling over-collections. Absent these adjustments for electric fuel costs and decoupling refunds, we would have realized an electric rate decrease. In addition, we received approval from the PSCW to defer and amortize the undepreciated book value associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. See Note 16, Commitments and Contingencies, for more information . The PSCW allowed us to escrow ATC and MISO network transmission expenses for 2015 and 2016. As a result, we deferred as a regulatory asset the differences between actual transmission expenses and those included in rates until a future rate proceeding. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a 2% tolerance window. The retail natural gas rate decrease was driven by the approximate $16.0 million year-over-year negative impact of decoupling refunds to and collections from customers. In 2015 rates, we refunded approximately $8.0 million to customers related to 2013 decoupling over-collections compared with recovering approximately $8.0 million from customers in 2014 rates related to 2012 decoupling under-collections. Absent the adjustment for decoupling refunds to and collections from customers, we would have realized a retail natural gas rate increase. 2014 Wisconsin Rate Order In March 2013, we initiated a rate proceeding with the PSCW. In December 2013, the PSCW issued a final written order, effective January 1, 2014. It authorized a net retail electric rate decrease of $12.8 million and a net retail natural gas rate increase of $4.0 million , reflecting a 10.20% ROE. The order also included a common equity component average of 50.14% . The retail electric rate impact consisted of a rate increase, including recovery of the difference between the 2012 fuel refund and a 2013 rate increase, entirely offset by a portion of estimated fuel cost over-collections from customers in 2013. Retail electric rates were further decreased by 2012 decoupling over-collections to be returned to customers in 2014. The retail natural gas rate impact consisted of a rate decrease, which was more than offset by the positive impact of 2012 decoupling under-collections to be recovered from customers in 2014. Both the retail electric and retail natural gas rate changes included the recovery of pension and other employee benefit increases that were deferred in the 2013 rate case. The PSCW also authorized the recovery of prudently incurred 2014 environmental mitigation project costs related to compliance with a Consent Decree signed in January 2013 related to the Pulliam and Weston sites. See Note 16, Commitments and Contingencies, for more information . Additionally, the order required us to terminate our decoupling mechanism, beginning January 1, 2014. 2015 Michigan Rate Order In October 2014, we initiated a rate proceeding with the MPSC. In April 2015, the MPSC issued a final written order, effective April 24, 2015, approving a settlement agreement. The order authorized a retail electric rate increase of $4.0 million to be implemented over three years to recover costs for the 2013 acquisition of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generation plants. The rates reflected a 10.2% ROE and a common equity component average of 50.48% . The increase reflected the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflected the deferral of Weston Unit 3 ReACT™ environmental project costs. On the second anniversary of the order, we will discontinue the deferral of Fox Energy Center costs and will begin amortizing this deferral along with the deferral associated with the termination of a tolling agreement related to the Fox Energy Center. We also received approval from the MPSC to defer and amortize the undepreciated book value of the retired plant associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. As a result of the formation of UMERC, we transferred the deferrals mentioned above, as well as our customers and property, plant, and equipment located in the Upper Peninsula of Michigan to the new utility, effective January 1, 2017. Therefore, the terms and conditions of this rate order are now applicable to UMERC. UMERC will not seek an increase to our legacy retail electric base rates that would become effective prior to January 1, 2018. 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 WE's electric and natural gas distribution assets located in the Upper Peninsula of Michigan.

Other Income, Net

Other Income, Net	12 Months Ended
	Dec. 31, 2016
Other Income, net [Abstract]
Other Income and Other Expense Disclosure [Text Block]	OTHER INCOME, NET Total other income, net was as follows for the years ended December 31 : (in millions) 2016 2015 2014 AFUDC – Equity $ 19.5 $ 15.1 $ 11.0 Earnings from equity method investments 9.5 8.5 10.3 Other, net 1.8 2.0 3.9 Other income, net $ 30.8 $ 25.6 $ 25.2

SEGMENTS INFORMATION

SEGMENTS INFORMATION	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
SEGMENTS OF BUSINESS	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 operations. Our electric utility operations were engaged in the generation, distribution, and sale of electricity in northeastern Wisconsin and the Upper Peninsula of Michigan. Our natural gas utility operations were engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in northeastern Wisconsin and the Upper Peninsula of Michigan. Effective January 1, 2017, we transferred our customers and electric and natural gas distribution assets located in the Upper Peninsula of Michigan to UMERC. See Note 3, Related Parties , and Note 19, Regulatory Environment , for more information. The other segment included non-utility activities, as well as equity earnings from our investments in WRPC and WPSI, which holds an approximate 34% interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, we transferred our 10.37% ownership interest in WPSI to another subsidiary of Integrys. See Note 3, Related Parties , 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 Reconciling Eliminations Wisconsin Public Service Corporation Consolidated External revenues $ 1,448.2 $ — $ — $ 1,448.2 Intersegment revenues — 0.3 (0.3 ) — Other operation and maintenance 492.5 1.0 (0.3 ) 493.2 Depreciation and amortization 124.0 0.1 — 124.1 Operating income (loss) 264.4 (0.9 ) — 263.5 Other income, net 23.3 7.5 — 30.8 Interest expense 48.0 0.1 — 48.1 Capital expenditures 311.1 — — 311.1 Total assets 4,686.4 121.8 — 4,808.2 2015 (in millions) Utility Other Reconciling Wisconsin Public Service Corporation Consolidated External revenues $ 1,483.3 $ — $ — $ 1,483.3 Intersegment revenues — 0.8 (0.8 ) — Other operation and maintenance 493.9 0.3 (0.8 ) 493.4 Depreciation and amortization 120.7 0.3 — 121.0 Operating income 228.0 0.1 — 228.1 Other income, net 16.0 9.6 — 25.6 Interest expense 53.2 0.3 — 53.5 Capital expenditures 371.0 — — 371.0 Total assets 4,416.8 88.3 — 4,505.1 2014 (in millions) Utility Other Reconciling Wisconsin Public Service Corporation Consolidated External revenues $ 1,683.6 $ — $ — $ 1,683.6 Intersegment revenues — 1.4 (1.4 ) — Other operation and maintenance 499.3 0.4 — 499.7 Depreciation and amortization 116.7 0.6 (0.5 ) 116.8 Operating income 257.2 0.4 — 257.6 Other income, net 12.3 12.9 — 25.2 Interest expense 55.3 2.1 — 57.4 Capital expenditures 322.0 — — 322.0 Total assets 4,183.9 85.4 — 4,269.3

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 $ 374.7 $ 331.5 $ 381.0 $ 361.0 $ 1,448.2 Operating income 76.9 43.4 105.3 37.9 263.5 Net income attributed to common shareholder 44.5 26.3 64.7 20.2 155.7 2015 Operating revenues $ 425.0 $ 330.3 $ 390.8 $ 337.2 $ 1,483.3 Operating income 69.9 44.2 88.5 25.5 228.1 Net income attributed to common shareholder 39.0 22.6 50.3 10.6 122.5 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 PUBLIC SERVICE CORPORATION VALUATION AND QUALIFYING ACCOUNTS Allowance for Doubtful Accounts (in millions) Balance at Beginning of Period Expense (1) Net Write-offs (2) Balance at End of Period December 31, 2016 $ 2.5 $ 7.7 $ (7.2 ) $ 3.0 December 31, 2015 3.2 6.7 (7.4 ) 2.5 December 31, 2014 2.5 7.3 (6.6 ) 3.2 (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, Wisconsin Energy Corporation acquired our parent company, Integrys, and changed its name to WEC Energy Group. See Note 2, Merger, for more information on the acquisition. We are an electric and natural gas utility company that serves customers in northeastern Wisconsin and served customers in the Upper Peninsula of Michigan. We are subject to the jurisdiction of, and regulation by, the PSCW, which has general supervisory and regulatory powers over virtually all phases of the public utility industry in Wisconsin. We are also subject to the jurisdiction of the FERC, which regulates our natural gas pipelines and wholesale electric rates.
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.
Investment	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.
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.
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. • 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. 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 and natural gas service to customers in northeastern Wisconsin and provided this service to customers in the Upper Peninsula of Michigan through December 31, 2016. See Note 3, Related Parties , and Note 19, 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. 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 .
Inventories	Substantially all fossil fuel, materials and supplies, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting.
Regulatory accounting	The economic effects of regulation can result in regulated companies recording costs and revenues that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future 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 5, Regulatory Assets and Liabilities, for more information .
Property, plant, and equipment	We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Depreciation as a percent of average depreciable utility plant was 2.58% , 2.60% , and 2.63% 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 3 to 11 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement. We receive grants related to certain renewable generation projects under federal and state grant programs. Our policy is to reduce the depreciable basis of the qualifying project by the grant received. We then reflect the benefit of the grant in income over the life of the related renewable generation project through a reduction in depreciation expense. See Note 6, Property, Plant, and Equipment, for more information .
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 7.72% , 7.92% , and 8.08% for 2016 , 2015 , and 2014 , respectively. Our average AFUDC wholesale rates were 3.00% , 5.10% , and 6.99% for 2016 , 2015 , and 2014 , respectively.
Emission allowances	We account for emission allowances as inventory at average cost by vintage year. Charges to income result when allowances are used in operating our generation plants. These charges are included in the costs subject to the fuel window rules. Gains on sales of allowances are returned to ratepayers.
Goodwill	Goodwill is subject to an annual impairment test. Our utility reporting unit contains goodwill and performed its annual goodwill impairment test as of July 1, 2016. Due to the WEC Merger, we changed the date of our annual goodwill impairment test from April 1 to July 1 during 2016. Interim impairment tests are also performed when impairment indicators are present. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value.
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 8, 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 8, 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 potential 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 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.
Guarantees	We follow the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee.
Employee benefits	The costs of pension and OPEB are expensed over the periods during which employees render service. These costs are allocated among 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	Prior to the WEC Merger, our employees were granted awards under Integrys’s stock-based compensation plans. Pursuant to the Merger Agreement, immediately prior to completion of the merger, all outstanding stock-based compensation awards became fully vested and were either paid to award recipients in cash, or the value of the awards was deferred into a deferred compensation plan. The total intrinsic value of awards granted to our employees that were settled due to the WEC Merger was $6.7 million . In 2016, our employees were granted awards under WEC Energy Group's 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 6 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 Non-qualified stock options granted 24,485 Estimated fair value per non-qualified stock option $ 5.63 Risk-free interest rate 0.4% – 1.8% Dividend yield 4.0 % Expected volatility 18.0 % Expected life (years) 7.5 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	Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. Derivatives were transferred between levels of the fair value hierarchy primarily due to observable pricing becoming available. We recognize transfers at their value as of the end of the reporting period. Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our long-term debt is estimated based upon the quoted market value for the same or similar issues. The fair value of long-term debt is categorized within Level 2 of the fair value hierarchy. See Note 17, Fair Value Measurements, for more information
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 were approved by the PSCW and the MPSC. We record derivative instruments on our balance sheets as assets or liabilities measured at fair value, unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Realized gains and losses on derivative instruments are primarily recorded in cost of sales on 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. See Note 18, Derivative Instruments, for more information .
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 accounts payable 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 Fossil fuel $ 66.7 $ 76.4 Materials and supplies 37.5 40.5 Natural gas in storage 21.1 28.1 Total $ 125.3 $ 145.0
Schedule of annual utility composite depreciation rates
Schedule of total AFUDC	We recorded the following AFUDC for the years ended December 31: (in millions) 2016 2015 2014 AFUDC – Debt $ 8.1 $ 6.1 $ 4.6 AFUDC – Equity 19.5 15.1 11.0
Schedule of assumption 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 Non-qualified stock options granted 24,485 Estimated fair value per non-qualified stock option $ 5.63 Risk-free interest rate 0.4% – 1.8% Dividend yield 4.0 % Expected volatility 18.0 % Expected life (years) 7.5

RELATED PARTIES (Tables)

RELATED PARTIES (Tables)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Schedule of information summarizing other related party transactions	The table below includes information summarizing other transactions entered into with related parties: (in millions) December 31, 2016 December 31, 2015 Accounts receivable Service provided to ATC $ 1.1 $ 0.5 Notes payable, current portion * Integrys — 2.9 Accounts payable Network transmission services from ATC 8.8 8.5 Liability related to income tax allocation Integrys 4.8 5.4 * WPS Leasing, our former consolidated subsidiary, had a note payable to our parent company, Integrys, that was paid off in May 2016.
Schedule of activity associated with related party transactions	The following table shows activity associated with related party transactions for the years ended December 31: (in millions) 2016 2015 2014 Electric transactions Sales to UPPCO (1) $ — $ — $ 15.3 Natural gas transactions Sales to WE 1.9 0.4 — Purchases from IES (2) — — 2.5 Transactions with WE (3) Billings to WE 4.2 4.9 — Billings from WE 9.0 13.4 — Transactions with WBS Billings to WBS (4) 21.7 9.7 7.6 Billings from WBS (5) 171.0 148.4 149.0 Transactions with equity-method investees Charges from ATC for network transmission services 109.4 101.3 99.0 Charges to ATC for services and construction 8.6 10.3 8.6 Purchases of energy from WRPC 3.7 3.8 3.7 Charges to WRPC for operations 0.7 1.1 1.4 Equity earnings from WPSI (6) 8.7 7.7 9.5 (1) Integrys sold UPPCO in August 2014. (2) Integrys sold IES's retail energy business in November 2014. (3) Includes amounts billed for services, pass through costs, and other items in accordance with the approved AIAs discussed above. (4) Includes $7.3 million for the transfer of certain software assets to WBS for the year ended December 31, 2016 . (5) Includes $18.2 million for the transfer of certain benefit-related liabilities to WBS and $34.1 million for the transfer of certain software assets to us for the year ended December 31, 2016. (6) At December 31, 2016, WPSI was an indirect wholly-owned subsidiary of WEC Energy Group that was jointly owned by Integrys and us. WPSI holds an approximate 34% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. At December 31, 2016 , we had a 10.37% interest in WPSI accounted for under the equity method. On January 1, 2017, we transferred our interest in WPSI to another subsidiary of Integrys. 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 9,000 retail electric customers and 5,300 natural gas customers to UMERC, along with approximately 600 miles of electric distribution lines and approximately 100 miles of natural gas distribution mains. 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 $19 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 WE. The new utility has also proposed a long-term generation solution for electric reliability in the region. See Note 19, Regulatory Environment, for more information . Parent Company's Acquisition of a Natural Gas Storage Facility in Michigan In January 2017, WEC Energy Group 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.

SUPPLEMENTAL CASH FLOW INFORM35

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 $ (54.6 ) $ (58.1 ) $ (56.8 ) Cash received (paid) for income taxes, net 39.9 (14.5 ) 6.2 Significant non-cash transactions: Accounts payable related to construction costs 67.2 70.5 54.0

REGULATORY ASSETS AND LIABILI36

REGULATORY ASSETS AND LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets	The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2016 2015 See Note Regulatory assets (1) (2) Unrecognized pension and OPEB costs (3) $ 182.9 $ 176.6 15 Environmental remediation costs (4) 116.0 104.4 16 Income tax related items (5) 55.7 40.8 Termination of a tolling agreement with Fox Energy Company LLC (6) 33.7 39.1 Crane Creek production tax credits (7) 29.6 30.9 De Pere Energy Center (8) 16.7 19.0 Other, net 31.2 51.9 Total regulatory assets $ 465.8 $ 462.7 Balance Sheet Presentation Current assets (9) $ — $ 0.2 Regulatory assets 465.8 462.5 Total regulatory assets $ 465.8 $ 462.7 (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 $18.8 million of regulatory assets not earning a return. The regulatory assets not earning a return relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures. (3) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We are authorized recovery of this regulatory asset over the average remaining service life of each plan. (4) As of December 31, 2016 , we had not yet made cash expenditures for $97.2 million of these environmental remediation costs. (5) Represents adjustments related to deferred income taxes, which are recovered in rates as the temporary differences that generated the income tax benefit reverse. (6) Represents an early termination fee of a tolling agreement we had with the Fox Energy Center. Prior to the purchase of the Fox Energy Center in 2013, we supplied natural gas for the facility and purchased capacity and the associated energy output under the tolling agreement. We are authorized recovery of this asset over a nine-year period that began on January 1, 2014. (7) In 2012, we elected to claim and subsequently received a Section 1603 Grant for the Crane Creek wind project in lieu of the production tax credit. As a result, we reversed previously recorded production tax credits. We also reduced the depreciable basis of the qualifying facility by the amount of the grant proceeds, which will result in a reduction of depreciation and amortization expense over a 12 -year period. We recorded a regulatory asset for the deferral of previously recorded production tax credits and are authorized recovery of this net regulatory asset through 2039. (8) Prior to purchasing the De Pere Energy Center in 2002, we had a long-term power purchase contract with them that was accounted for as a capital lease. As a result of the purchase, the capital lease obligation was reversed, and the difference between the capital lease asset and the purchase price was recorded as a regulatory asset. We are authorized recovery of this regulatory asset through 2023. (9) Short-term regulatory assets are recorded in accounts receivable and unbilled revenues on our balance sheets.
Schedule of Regulatory Liabilities	The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2016 2015 See Note Regulatory liabilities Removal costs (1) $ 248.9 $ 243.7 Energy costs refundable through rate adjustments (2) 14.5 29.4 Unrecognized pension and OPEB costs (3) 14.3 1.0 15 Crane Creek depreciation deferral (4) 8.0 8.3 Other, net 10.8 11.2 Total regulatory liabilities $ 296.5 $ 293.6 Balance Sheet Presentation Other current liabilities $ 5.2 $ 3.6 Regulatory liabilities 291.3 290.0 Total regulatory liabilities $ 296.5 $ 293.6 (1) Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment. (2) Represents energy costs that will be refunded to customers in the future. (3) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan. (4) Represents the book depreciation taken on the Crane Creek wind project prior to our election to claim a Section 1603 Grant for the project in lieu of the production tax credit. See more information in the regulatory assets section above.

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 assets at December 31: (in millions) 2016 2015 Utility property, plant, and equipment $ 5,144.5 $ 4,541.2 Less: Accumulated depreciation 1,594.7 1,559.6 Net 3,549.8 2,981.6 CWIP 111.9 434.2 Net utility property, plant, and equipment 3,661.7 3,415.8 Non-utility property, plant, and equipment 0.7 8.9 Less: Accumulated depreciation 0.4 6.1 Net non-utility plant 0.3 2.8 Total property, plant, and equipment $ 3,662.0 $ 3,418.6

JOINTLY OWNED UTILITY FACILIT38

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

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule of changes to asset retirement obligations	The following table shows changes to our AROs during the years ended December 31: (in millions) 2016 2015 2014 Balance as of January 1 $ 32.7 $ 20.3 $ 18.0 Accretion 1.5 1.2 1.0 Additions and revisions to estimated cash flows (1.6 ) (1 ) 11.4 (2 ) 1.5 (3 ) Liabilities settled — (0.2 ) (0.2 ) Balance as of December 31 $ 32.6 $ 32.7 $ 20.3 (1) We revised the AROs recorded for our fly-ash landfills during 2016 due to changes in estimated removal costs. (2) During 2015, an ARO of $9.0 million was recorded for the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule passed by the EPA in April 2015. In addition, we revised the AROs recorded for our fly-ash landfills due to changes in estimated removal costs and settlement dates. (3) We revised the AROs recorded for the asbestos at our electric generation facilities during 2014 primarily due to changes in estimated settlement dates.

GOODWILL AND OTHER INTANGIBLE40

GOODWILL AND OTHER INTANGIBLE ASSETS (Tables)	12 Months Ended
	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of identifiable intangible assets other than goodwill	The identifiable intangible assets other than goodwill listed below are classified as other long-term assets on our balance sheets. December 31, 2016 December 31, 2015 (in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Amortized intangible assets * $ 15.6 $ (10.7 ) $ 4.9 $ 15.6 $ (7.5 ) $ 8.1 Unamortized intangible assets 0.4 — 0.4 0.4 — 0.4 Total intangible assets $ 16.0 $ (10.7 ) $ 5.3 $ 16.0 $ (7.5 ) $ 8.5 * Represents contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The remaining weighted-average amortization period for these intangible assets at December 31, 2016 , was approximately three years .

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 WEC Energy Group stock options $ 0.5 $ — $ — WEC Energy Group restricted shares 1.4 — — WEC Energy Group performance units 1.5 — — Integrys stock options — — 1.0 Integrys performance stock rights — 1.3 6.3 Integrys restricted share units — 3.5 3.8 Stock-based compensation expense $ 3.4 $ 4.8 $ 11.1 Related tax benefit $ 1.4 $ 1.9 $ 4.4
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 — $ — Granted 24,485 $ 55.36 Outstanding as of December 31, 2016 24,485 $ 55.36 9.1 $ 0.1 Exercisable as of December 31, 2016 1,840 $ 55.36 9.1 $ —
Schedule of restricted stock activity	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 — $ — Granted 18,306 $ 55.48 Forfeited (4,071 ) $ 55.48 Outstanding as of December 31, 2016 14,235 $ 55.48

SHORT-TERM DEBT AND LINES OF 42

SHORT-TERM DEBT AND LINES OF CREDIT (Tables)	12 Months Ended
	Dec. 31, 2016
Short-term Debt [Abstract]
Schedule of short-term borrowings	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 $ 176.8 $ 182.8 Average interest rate on amounts outstanding at December 31 1.01% 0.66 %
Schedule of revolving credit facilities and remaining available capacity	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 $ 250.0 Less: commercial paper outstanding 176.8 Available capacity under existing agreement $ 73.2

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of all principal debt payment amounts related to bond maturities	The following table shows the future maturities of our long-term debt outstanding as of December 31, 2016 : (in millions) Payments 2017 $ 125.0 2018 250.0 2019 — 2020 — 2021 — Thereafter 925.0 Total $ 1,300.0

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Schedule of components of the provision for 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 $ (52.5 ) $ 31.4 $ (6.1 ) Deferred income taxes, net 143.3 44.0 91.1 Investment tax credit, net (0.3 ) (0.4 ) (0.3 ) Total income tax expense $ 90.5 $ 75.0 $ 84.7
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement	The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: 2016 2015 2014 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate Expected tax at statutory federal tax rates $ 86.2 35.0 % $ 70.1 35.0 % $ 78.9 35.0 % State income taxes net of federal tax benefit 11.6 4.7 9.9 5.0 10.9 4.8 AFUDC – Equity (6.8 ) (2.7 ) (5.3 ) (2.6 ) (3.8 ) (1.7 ) Other, net (0.5 ) (0.2 ) 0.3 0.1 (1.3 ) (0.5 ) Total income tax expense $ 90.5 36.8 % $ 75.0 37.5 % $ 84.7 37.6 %
Schedule of principal components of deferred income tax assets and liabilities recognized in the balance sheets	The components of deferred income taxes as of December 31 are as follows: (in millions) 2016 2015 Total deferred tax assets $ 12.9 $ 23.9 Deferred tax liabilities Plant-related 800.5 639.1 Employee benefits and compensation 99.3 91.7 Regulatory deferrals 38.4 52.0 Other 4.2 15.2 Total deferred tax liabilities 942.4 798.0 Deferred tax liability, net $ 929.5 $ 774.1

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 share of the 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 $ 633.9 $ 791.8 $ 231.6 $ 252.5 Service cost 9.9 10.7 7.3 8.7 Interest cost 27.0 31.7 10.6 10.4 Plan amendments — — (18.9 ) — Transfer to/from affiliates * 6.2 (130.5 ) — — Actuarial loss (gain) 26.1 (36.4 ) 0.6 (31.7 ) Participant contributions — — 0.4 0.3 Benefit payments (47.9 ) (33.3 ) (8.5 ) (8.6 ) Plan curtailment — (0.1 ) — — Obligation at December 31 $ 655.2 $ 633.9 $ 223.1 $ 231.6 Change in fair value of plan assets Fair value at January 1 $ 719.0 $ 897.4 $ 224.5 $ 236.6 Actual return on plan assets 58.0 (29.4 ) 14.6 (5.1 ) Employer contributions 1.3 1.1 0.1 1.3 Participant contributions — — 0.4 0.3 Benefit payments (47.9 ) (33.3 ) (8.5 ) (8.6 ) Transfer to/from affiliates * 6.2 (116.8 ) — — Fair value at December 31 $ 736.6 $ 719.0 $ 231.1 $ 224.5 Funded status at December 31 $ 81.4 $ 85.1 $ 8.0 $ (7.1 ) * Benefit obligations and plan assets were moved along with our employees who were transferred to/from affiliated entities. As a result of the WEC Merger, certain of our employees were realigned across WEC Energy Group's various subsidiaries.
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 Pension and OPEB assets $ 89.0 $ 93.8 $ 25.8 $ 8.6 Pension and OPEB obligations 7.6 8.7 17.8 15.7 Total net assets (liabilities) $ 81.4 $ 85.1 $ 8.0 $ (7.1 )
Information for pension plans with an accumulated benefit obligation in excess of plan assets	The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31: (in millions) 2016 2015 Projected benefit obligation $ 7.6 $ 8.7 Accumulated benefit obligation 7.6 8.5
Amounts that had not yet been recognized in the entity's net periodic benefit cost	The following table shows the amounts that had 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 $ 221.4 $ 61.2 $ 27.8 $ 5.2 Prior service credits — — (80.6 ) — Total $ 221.4 $ 61.2 $ (52.8 ) $ 5.2
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 $ 17.3 $ 2.5 Prior service credits — (9.2 ) Total 2017 – estimated amortization $ 17.3 $ (6.7 )
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 $ 9.9 $ 10.7 $ 8.6 $ 7.3 $ 8.7 $ 7.7 Interest cost 27.0 31.7 34.4 10.6 10.4 11.5 Expected return on plan assets (52.6 ) (64.8 ) (64.1 ) (15.9 ) (16.0 ) (16.0 ) Loss on plan settlement 3.4 0.1 0.4 — — — Amortization of prior service cost (credit) — 0.2 0.6 (7.4 ) (9.3 ) (8.0 ) Amortization of net actuarial loss 18.0 21.0 15.0 2.5 3.7 2.8 Net periodic benefit cost $ 5.7 $ (1.1 ) $ (5.1 ) $ (2.9 ) $ (2.5 ) $ (2.0 )
Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost for the plans	The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension OPEB 2016 2015 2016 2015 Discount rate 4.19% 4.49% 4.21% 4.46% Rate of compensation increase 4.00% 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 net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Costs 2016 2015 2014 Discount rate 4.25% 4.08% 4.92% Expected return on assets 7.25% 7.75% 8.00% Rate of compensation increase 4.00% 4.23% 4.25% OPEB Costs 2016 2015 2014 Discount rate 4.46% 4.11% 4.78% Expected return on assets 7.25% 7.75% 8.00% Assumed medical cost trend rate (Pre 65/Post 65) 7.50% 6.00% 6.50% Ultimate trend rate 5.00% 5.00% 5.00% Year ultimate trend rate is reached 2021 2023 2019
Effects of a one-percentage-point change in assumed health care cost trend rates	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 $ 3.3 $ (2.6 ) Effect on the health care component of the accumulated postretirement benefit obligation 29.9 (23.7 )
Investments recorded at fair value, by asset class	The following tables provide the fair values of our investments by asset class: December 31, 2016 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ 1.3 $ 19.2 $ — $ 20.5 $ 10.3 $ 0.2 $ — $ 10.5 Equity securities: United States Equity 94.9 0.1 — 95.0 7.1 — — 7.1 International Equity 18.1 0.3 — 18.4 0.3 0.1 — 0.4 Fixed income securities: * United States Bonds — 151.7 0.5 152.2 — 33.2 — 33.2 International Bonds — 20.1 — 20.1 — 1.8 — 1.8 $ 114.3 $ 191.4 $ 0.5 $ 306.2 $ 17.7 $ 35.3 $ — $ 53.0 Investments measured at net asset value $ 430.4 $ 178.1 Total $ 114.3 $ 191.4 $ 0.5 $ 736.6 $ 17.7 $ 35.3 $ — $ 231.1 * 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 $ — $ 16.3 $ — $ 16.3 $ 3.7 $ 0.2 $ — $ 3.9 Equity securities: United States Equity 18.7 1.9 — 20.6 5.8 — — 5.8 International Equity 39.7 — — 39.7 15.9 — — 15.9 Fixed income securities: * United States Bonds 6.3 93.6 — 99.9 0.1 1.1 — 1.2 International Bonds — 22.1 — 22.1 — 0.2 — 0.2 $ 64.7 $ 133.9 $ — $ 198.6 $ 25.5 $ 1.5 $ — $ 27.0 Investments measured at net asset value $ 520.4 $ 197.5 Total $ 64.7 $ 133.9 $ — $ 719.0 $ 25.5 $ 1.5 $ — $ 224.5 * 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 table sets forth a reconciliation of changes in the fair value of pension plan assets categorized as Level 3 in 2016. There was no level 3 activity in 2015. (in millions) United States Bonds Beginning balance at January 1, 2016 $ — Purchases 0.5 Ending balance at December 31, 2016 $ 0.5
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 $ 31.9 $ 9.7 2018 32.3 10.7 2019 33.2 11.4 2020 35.0 11.1 2021 35.5 11.6 2022-2026 179.3 63.5

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of minimum future commitments related to purchase obligations	The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2016 . Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2017 2018 2019 2020 2021 Later Years Electric utility: Purchased power 2027 $ 622.7 $ 85.8 $ 54.7 $ 57.7 $ 60.1 $ 58.7 $ 305.7 Coal supply and transportation 2019 141.9 85.8 42.8 13.3 — — — Natural gas utility supply and transportation 2024 155.2 43.7 42.4 27.1 14.6 11.8 15.6 Total $ 919.8 $ 215.3 $ 139.9 $ 98.1 $ 74.7 $ 70.5 $ 321.3
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 $ 0.4 2018 0.6 2019 0.4 2020 0.5 2021 0.5 Later years 11.8 Total $ 14.2
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 $ 116.0 $ 104.4 Reserves for future remediation 97.2 83.5

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair value of assets and liabilities measured on a recurring basis, categorized by level within the fair value hierarchy	The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.1 $ 0.1 $ — $ 0.2 FTRs — — 2.0 2.0 Coal contracts — 0.1 — 0.1 Total derivative assets $ 0.1 $ 0.2 $ 2.0 $ 2.3 Derivative liabilities Coal contracts $ — $ 1.4 $ — $ 1.4 December 31, 2015 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.3 $ — $ — $ 0.3 FTRs — — 2.0 2.0 Total derivative assets $ 0.3 $ — $ 2.0 $ 2.3 Derivative liabilities Natural gas contracts $ 0.9 $ — $ — $ 0.9 Petroleum products contracts 0.5 — — 0.5 Coal contracts — 4.7 — 4.7 Total derivative liabilities $ 1.4 $ 4.7 $ — $ 6.1
Reconciliation of changes in the fair value of items categorized as Level 3 measurements	The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31 : (in millions) 2016 2015 2014 Balance at the beginning of the period $ 2.0 $ (0.3 ) $ (1.3 ) Realized and unrealized losses (0.2 ) (10.7 ) (1.0 ) Purchases 7.1 9.8 4.3 Sales (0.2 ) (0.1 ) — Settlements (6.7 ) (1.4 ) (3.5 ) Transfers out of level 3 — 4.7 1.2 Balance at the end of the period $ 2.0 $ 2.0 $ (0.3 )
Schedule of carrying value and estimated fair value of financial instruments not recorded at fair value	The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: December 31, 2016 December 31, 2015 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 1,290.3 $ 1,373.4 $ 1,289.4 $ 1,350.4 Long-term debt to parent, including current portion * — — 2.9 3.0 * Our former consolidated subsidiary, WPS Leasing, Inc., had a note payable to our parent company, Integrys, that was paid off in May 2016.

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 $ 0.2 $ — $ 0.3 $ 0.9 Petroleum products contracts — — — 0.5 FTRs 2.0 — 2.0 — Coal contracts — 0.9 — 3.3 Total other current $ 2.2 $ 0.9 $ 2.3 $ 4.7 Other long-term Coal contracts $ 0.1 $ 0.5 $ — $ 1.4 Total $ 2.3 $ 1.4 $ 2.3 $ 6.1
Estimated notional volumes and realized gains (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 (Losses) Natural gas contracts 28.6 Dth $ (1.4 ) 22.9 Dth $ (4.9 ) 20.0 Dth $ 0.6 Petroleum products contracts 4.4 gallons (0.6 ) 6.1 gallons (1.7 ) 5.3 gallons (0.1 ) FTRs 8.4 MWh 6.0 9.0 MWh 3.3 8.7 MWh 3.2 Total $ 4.0 $ (3.3 ) $ 3.7
Offsetting assets and liabilities	The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2016 December 31, 2015 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 2.3 $ 1.4 $ 2.3 $ 6.1 Gross amount not offset on the balance sheet * — — (0.3 ) (1.4 ) Net amount $ 2.3 $ 1.4 $ 2.0 $ 4.7 * Includes cash collateral posted of $1.1 million at December 31, 2015 . There was no cash collateral included at December 31, 2016 .

Other Income, Net (Tables)

Other Income, Net (Tables)	12 Months Ended
	Dec. 31, 2016
Other Income, net [Abstract]
Schedule of Other Nonoperating Income (Expense) [Table Text Block]	Total other income, net was as follows for the years ended December 31 : (in millions) 2016 2015 2014 AFUDC – Equity $ 19.5 $ 15.1 $ 11.0 Earnings from equity method investments 9.5 8.5 10.3 Other, net 1.8 2.0 3.9 Other income, net $ 30.8 $ 25.6 $ 25.2

SEGMENTS INFORMATION (Tables)

SEGMENTS INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Schedule of information related to 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 Reconciling Eliminations Wisconsin Public Service Corporation Consolidated External revenues $ 1,448.2 $ — $ — $ 1,448.2 Intersegment revenues — 0.3 (0.3 ) — Other operation and maintenance 492.5 1.0 (0.3 ) 493.2 Depreciation and amortization 124.0 0.1 — 124.1 Operating income (loss) 264.4 (0.9 ) — 263.5 Other income, net 23.3 7.5 — 30.8 Interest expense 48.0 0.1 — 48.1 Capital expenditures 311.1 — — 311.1 Total assets 4,686.4 121.8 — 4,808.2 2015 (in millions) Utility Other Reconciling Wisconsin Public Service Corporation Consolidated External revenues $ 1,483.3 $ — $ — $ 1,483.3 Intersegment revenues — 0.8 (0.8 ) — Other operation and maintenance 493.9 0.3 (0.8 ) 493.4 Depreciation and amortization 120.7 0.3 — 121.0 Operating income 228.0 0.1 — 228.1 Other income, net 16.0 9.6 — 25.6 Interest expense 53.2 0.3 — 53.5 Capital expenditures 371.0 — — 371.0 Total assets 4,416.8 88.3 — 4,505.1 2014 (in millions) Utility Other Reconciling Wisconsin Public Service Corporation Consolidated External revenues $ 1,683.6 $ — $ — $ 1,683.6 Intersegment revenues — 1.4 (1.4 ) — Other operation and maintenance 499.3 0.4 — 499.7 Depreciation and amortization 116.7 0.6 (0.5 ) 116.8 Operating income 257.2 0.4 — 257.6 Other income, net 12.3 12.9 — 25.2 Interest expense 55.3 2.1 — 57.4 Capital expenditures 322.0 — — 322.0 Total assets 4,183.9 85.4 — 4,269.3

QUARTERLY FINANCIAL INFORMATI51

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 $ 374.7 $ 331.5 $ 381.0 $ 361.0 $ 1,448.2 Operating income 76.9 43.4 105.3 37.9 263.5 Net income attributed to common shareholder 44.5 26.3 64.7 20.2 155.7 2015 Operating revenues $ 425.0 $ 330.3 $ 390.8 $ 337.2 $ 1,483.3 Operating income 69.9 44.2 88.5 25.5 228.1 Net income attributed to common shareholder 39.0 22.6 50.3 10.6 122.5

SUMMARY OF SIGNIFICANT ACCOUN52

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES CASH AND CASH EQUIVALENTS (Details)	12 Months Ended
	Dec. 31, 2016
Cash and cash equivalents
Maximum maturity of short-term investments to classify instruments as cash equivalents	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
Percentage price variance from rate case-approved fuel and purchased power costs before deferral is required	2.00%
Customer concentration risk
Revenues from external customers
Number of customers that account for more than 10% of revenues	0
Threshold percentage of revenues from major customers	10.00%

SUMMARY OF SIGNIFICANT ACCOUN54

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Fossil fuel	$ 66.7	$ 76.4
Materials and supplies	37.5	40.5
Natural gas in storage	21.1	28.1
Total	$ 125.3	$ 145

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
Annual utility composite depreciation rate (as a percent)	2.58%	2.60%	2.63%
Software | Minimum
Property, plant and equipment
Estimated useful life	3 years
Software | Maximum
Property, plant and equipment
Estimated useful life	11 years

SUMMARY OF SIGNIFICANT ACCOUN56

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AFUDC (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
AFUDC
Percentage of retail jurisdictional construction work in progress expenditures subject to AFUDC calculation	50.00%
Allowance for borrowed funds used during construction	$ 8.1	$ 6.1	$ 4.6
Allowance for equity funds used during construction	$ 19.5	$ 15.1	$ 11
Retail
AFUDC
Average AFUDC rate (as a percent)	7.72%	7.92%	8.08%
Wholesale
AFUDC
Average AFUDC rate (as a percent)	3.00%	5.10%	6.99%

SUMMARY OF SIGNIFICANT ACCOUN57

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES GUARANTEES (Details) $ in Millions	Dec. 31, 2016USD ($)
Standby letters of credit
Guarantor Obligations
Guarantees expiring in less than one year	$ 9.4

SUMMARY OF SIGNIFICANT ACCOUN58

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES STOCK-BASED COMPENSATION (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic value of Integrys awards canceled due to WEC merger		$ 6.7
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	10 years
Non-qualified stock options granted	24,485
Estimated fair value per non-qualified stock option (in dollars per share)	$ 5.63
Risk-free interest rate, minimum (as a percent)	0.40%
Risk-free interest rate, maximum (as a percent	1.80%
Dividend yield (as a percent)	4.00%
Expected Volatility (as a percent)	18.00%
Expected life (years)	7 years 6 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]
Payout ratio (as a percent)	0.00%
Performance units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout ratio (as a percent)	175.00%

MERGER (Details)

MERGER (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Business Combinations [Abstract]
Severance expense	$ 4.6
Severance payments	$ 4.3

RELATED PARTIES (Details)

RELATED PARTIES (Details) $ in Millions	Jan. 01, 2017USD ($)milecustomer	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Related parties
Equity earnings from WPS Investments, LLC		$ 9.5	$ 8.5	$ 10.3
Payments for assets received from WBS		(34.1)	0	0
WRPC
Related parties
Purchases from related party		3.7	3.8	3.7
Charges to equity method investee for services, construction, and/or operations		0.7	1.1	1.4
WPS Investments, LLC
Related parties
Equity earnings from WPS Investments, LLC		$ 8.7	7.7	9.5
Equity method investment, ownership interest (as a percent)		10.37%
ATC
Related parties
Billings from related party for services, pass through costs and other items		$ 109.4	101.3	99
Charges to equity method investee for services, construction, and/or operations		$ 8.6	10.3	8.6
Equity method investment, ownership interest (as a percent)		34.00%
WBS
Related parties
Number of other significant changes from the non-IBS affiliated interest agreement		0
Billings from related party for services, pass through costs and other items		$ 171	148.4	149
Charges to equity method investee for services, construction, and/or operations		21.7	9.7	7.6
Proceeds from assets transferred to related party		7.3
Payments for transfer of liabilities to related party		18.2
Payments for assets received from WBS		(34.1)
UPPCO | Electric utility
Related parties
Sales to related party		0	0	15.3
Wisconsin Electric
Related parties
Billings from related party for services, pass through costs and other items		9	13.4	0
Charges to equity method investee for services, construction, and/or operations		4.2	4.9	0
Wisconsin Electric | Natural gas utility
Related parties
Sales to related party		1.9	0.4	0
IES | Natural gas utility
Related parties
Purchases from related party		$ 0	$ 0	$ 2.5
UMERC Transfer | Subsequent event
Related parties
Miles of electric distribution lines transferred | mile	600
Miles of gas distribution mains transferred | mile	100
Net book value of property, plant and equipment transferred	$ 19
UMERC Transfer | Subsequent event | Electric utility
Related parties
Number of customers | customer	9,000
UMERC Transfer | Subsequent event | Natural gas utility
Related parties
Number of customers | customer	5,300

RELATED PARTIES Balance sheet b

RELATED PARTIES Balance sheet balances with related parties (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Integrys
Related parties
Liability related to income tax allocation	$ 4.8	$ 5.4
ATC
Related parties
Accounts receivable for services provided to ATC	1.1	0.5
Accounts payable to ATC for network transmission services	8.8	8.5
WPS Leasing | Integrys
Related parties
Notes payable to Integrys	$ 0	$ 2.9

SUPPLEMENTAL CASH FLOW INFORM62

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	$ (54.6)	$ (58.1)	$ (56.8)
Cash (paid) for income taxes, net		(14.5)
Cash received for income taxes, net	39.9		6.2
Accounts payable related to construction costs	$ 67.2	$ 70.5	$ 54

REGULATORY ASSETS AND LIABILI63

REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Regulatory assets
Current assets	$ 0	$ 0.2
Regulatory assets	465.8	462.5
Total regulatory assets	465.8	462.7
Other Disclosures
Regulatory assets not earning a return	18.8
Environmental remediation liabilities	97.2	83.5
Unrecognized pension and OPEB costs
Regulatory assets
Total regulatory assets	182.9	176.6
Environmental remediation costs
Regulatory assets
Total regulatory assets	116	104.4
Other Disclosures
Environmental remediation liabilities	97.2
Income tax related items
Regulatory assets
Total regulatory assets	55.7	40.8
Termination of a tolling agreement with Fox Energy Company LLC
Regulatory assets
Total regulatory assets	33.7	39.1
Crane Creek production tax credits
Regulatory assets
Total regulatory assets	$ 29.6	30.9
Other Disclosures
Period over which grant received will be reflected in income through reduction of depreciation and amortization expense	12 years
De Pere Energy Center
Regulatory assets
Total regulatory assets	$ 16.7	19
Other, net
Regulatory assets
Total regulatory assets	$ 31.2	$ 51.9

REGULATORY ASSETS AND LIABILI64

REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Regulatory Liabilities
Other current liabilities	$ 5.2	$ 3.6
Regulatory liabilities	291.3	290
Total regulatory liabilities	296.5	293.6
Removal costs
Regulatory Liabilities
Total regulatory liabilities	248.9	243.7
Energy costs refundable through rate adjustments
Regulatory Liabilities
Total regulatory liabilities	14.5	29.4
Unrecognized pension and OPEB costs
Regulatory Liabilities
Total regulatory liabilities	14.3	1
Crane Creek depreciation deferral
Regulatory Liabilities
Total regulatory liabilities	8	8.3
Other, net
Regulatory Liabilities
Total regulatory liabilities	$ 10.8	$ 11.2

PROPERTY, PLANT, AND EQUIPMEN65

PROPERTY, PLANT, AND EQUIPMENT (Details) $ in Millions	Jan. 01, 2017USD ($)mile	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Property, Plant and Equipment, Net [Abstract]
Accumulated depreciation		$ 1,595.1	$ 1,565.7
Net property, plant, and equipment		3,662	3,418.6
Subsequent event | UMERC Transfer
Transfer of Assets to UMERC
Miles of electric distribution lines transferred | mile	600
Miles of gas distribution mains transferred | mile	100
Net book value of property, plant and equipment transferred	$ 19
Utility operations
Property, Plant and Equipment, Net [Abstract]
Property, plant, and equipment, gross		5,144.5	4,541.2
Accumulated depreciation		1,594.7	1,559.6
Net		3,549.8	2,981.6
CWIP		111.9	434.2
Net property, plant, and equipment		3,661.7	3,415.8
Nonutility operations
Property, Plant and Equipment, Net [Abstract]
Property, plant, and equipment, gross		0.7	8.9
Accumulated depreciation		0.4	6.1
Net property, plant, and equipment		$ 0.3	$ 2.8

JOINTLY OWNED UTILITY FACILIT66

JOINTLY OWNED UTILITY FACILITIES (Details) $ in Millions	Dec. 31, 2016USD ($)MW
Weston 4
Share of significant jointly owned electric generating facilities
Ownership (as a percent)	70.00%
Our share of rated capacity (in megawatts) | MW	373.5
Utility plant	$ 596.3
Accumulated depreciation	(170.3)
Construction work in progress	$ 0.2
Columbia Energy Center Units 1 and 2
Share of significant jointly owned electric generating facilities
Ownership (as a percent)	31.80%
Our share of rated capacity (in megawatts) | MW	334.4
Utility plant	$ 417.9
Accumulated depreciation	(128.3)
Construction work in progress	$ 41.2
Edgewater Unit 4
Share of significant jointly owned electric generating facilities
Ownership (as a percent)	31.80%
Our share of rated capacity (in megawatts) | MW	98
Utility plant	$ 45.8
Accumulated depreciation	(31.7)
Construction work in progress	$ 0.1
Wisconsin Public Service Corporation [Member] | Columbia Energy Center Units 1 and 2
Share of significant jointly owned electric generating facilities
Future Ownership Interest of Columbia	27.50%

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	$ 32.7	$ 20.3	$ 18
Accretion	1.5	1.2	1
Additions and revisions to estimated cash flows	(1.6)	11.4	1.5
Liabilities settled	0	(0.2)	(0.2)
Balance as of December 31	32.6	$ 32.7	$ 20.3
Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule
Changes to asset retirement obligations
AROs additions	$ 9

GOODWILL AND OTHER INTANGIBLE68

GOODWILL AND OTHER INTANGIBLE ASSETS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Goodwill and other intangible assets
Changes to the carrying amount of goodwill	$ 0	$ 0
Maximum number of months between goodwill impairment tests	12 months
Goodwill impairment loss	$ 0
Intangible assets other than goodwill
Amortized intangible assets, accumulated amortization	(10.7)	(7.5)
Unamortized intangible assets, carrying amount	0.4	0.4
Total intangible assets, gross carrying amount	16	16
Total intangible assets, net carrying amount	5.3	8.5
Contractual service agreements
Intangible assets other than goodwill
Amortized intangible assets, gross carrying amount	15.6	15.6
Amortized intangible assets, accumulated amortization	(10.7)	(7.5)
Amortized intangible assets, net carrying amount	$ 4.9	$ 8.1
Remaining weighted-average amortization period	3 years

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	$ 3.4	$ 4.8	$ 11.1
Related Tax Benefit	1.4	1.9	4.4
Stock options | WEC Energy Group stock-based compensation plans
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	0.5	0	0
Stock options | Integrys stock-based compensation plans
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	0	0	1
Restricted stock | WEC Energy Group stock-based compensation plans
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	1.4	0	0
Performance stock rights | WEC Energy Group stock-based compensation plans
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	1.5	0	0
Performance stock rights | Integrys stock-based compensation plans
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	0	1.3	6.3
Restricted stock units | Integrys stock-based compensation plans
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 0	$ 3.5	$ 3.8

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
Options Activity [Roll Forward]
Outstanding, shares, beginning balance	24,485	0
Granted, shares		24,485
Outstanding, shares, ending balance		24,485
Options - Weighted Average Exercise Price
Outstanding, Weighted-Average Exercise Price, Beginning	$ 55.36	$ 0
Granted, Weighted-Average Exercise Price		55.36
Outstanding, Weighted-Average Exercise Price, Ending		$ 55.36
Options - Additional Disclosures
Outstanding, Weighted-Average Remaining Contractual Life (Years)		9 years 1 month
Outstanding, Aggregate Intrinsic Value		$ 0.1
Exercisable, shares		1,840
Exercisable, Weighted-Average Exercise Price		$ 55.36
Exercisable, Weighted-Average Remaining Contractual Life (Years)		9 years 1 month
Exercisable, Aggregate Intrinsic Value		$ 0
Estimated fair value per non-qualified stock option (in dollars per share)		$ 5.63
Subsequent event
Options Activity [Roll Forward]
Granted, shares	23,300
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)	$ 7.53

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
Restricted Stock Activity [Roll Forward]
Outstanding, shares, beginning of period	14,235	0
Granted, shares		18,306
Forfeited, shares		(4,071)
Outstanding, shares, end of period		14,235
Restricted Stock Weighted-Average Grant Date Fair Value
Outstanding, weighted-average grant date fair value, beginning of period	$ 55.48	$ 0
Granted, weighted-average grant date fair value		55.48
Forfeited, weighted-average grant date fair value		55.48
Outstanding, weighted-average grant date fair value, end of period		$ 55.48
Restricted Stock - Additional Disclosures
Compensation cost not yet recognized		$ 1.2
Weighted-average period over which unrecognized compensation cost is expected to be recognized		2 years
Subsequent event
Restricted Stock Activity [Roll Forward]
Granted, shares	2,313
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
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, shares		9,235
Compensation cost not yet recognized		$ 1.9
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	10,025

COMMON EQUITY - DIVIDEND RESTRI

COMMON EQUITY - DIVIDEND RESTRICTIONS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Dividend Payment Restrictions [Line Items]
Restricted retained earnings	$ 531.9
Undistributed earnings from equity method investees	$ 34.5
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) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Authorized shares	1,000,000	1,000,000
Par value (in dollars per share)	$ 100	$ 100
Shares outstanding	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 borrowings
Short-term borrowings outstanding	$ 176.8	$ 182.8
Commercial paper
Short-term borrowings
Short-term borrowings outstanding	$ 176.8	$ 182.8
Average interest rate on amounts outstanding (as a percent)	1.01%	0.66%
Average amount of short-term borrowings outstanding during the year	$ 145.8
Commercial Paper Weighted Average Interest Rate	0.62%

SHORT-TERM DEBT AND LINES OF 76

SHORT-TERM DEBT AND LINES OF CREDIT CAPACITY (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)extension	Dec. 31, 2015USD ($)
Short-term borrowings
Debt to capitalization ratio required to be maintained (as a percent)	65.00%
Short-term borrowings outstanding	$ 176.8	$ 182.8
Available capacity under existing agreements	$ 73.2
Number of extensions available on a credit facility | extension	2
Length of credit facility extension	1 year
Revolving credit facility maturing in December 2016 [Member]
Short-term borrowings
Total short-term credit capacity	$ 250
Commercial paper
Short-term borrowings
Short-term borrowings outstanding	$ 176.8	$ 182.8

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Long-term Debt, Fiscal Year Maturity
2,017	$ 125
2,018	250
2,019	0
2,020	0
2,021	0
Thereafter	925
Total	$ 1,300	$ 1,300

INCOME TAXES INCOME TAXES PROVI

INCOME TAXES INCOME TAXES PROVISION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Provision for income taxes
Current tax expense	$ (52.5)	$ 31.4	$ (6.1)
Deferred income taxes, net	143.3	44	91.1
Investment tax credit, net	(0.3)	(0.4)	(0.3)
Total income tax expense	$ 90.5	$ 75	$ 84.7

INCOME TAXES RECONCILIATION (De

INCOME TAXES RECONCILIATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement
Expected tax at statutory federal tax rates	$ 86.2	$ 70.1	$ 78.9
State income taxes net of federal tax benefit	11.6	9.9	10.9
AFUDC-Equity	(6.8)	(5.3)	(3.8)
Other, net	(0.5)	0.3	(1.3)
Total income tax expense	$ 90.5	$ 75	$ 84.7
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement (as a percent)
Expected tax at statutory federal tax rates	35.00%	35.00%	35.00%
State income taxes net of federal tax benefit	4.70%	5.00%	4.80%
AFUDC-Equity	(2.70%)	(2.60%)	(1.70%)
Other, net	(0.20%)	0.10%	(0.50%)
Effective income tax rate	36.80%	37.50%	37.60%
Unrecognized tax benefits, additional disclosures
Unrecognized Tax Benefits	$ 0	$ 0
Accrued interest related to unrecognized tax benefits	0	0
Accrued penalties related to unrecognized tax benefits	$ 0	$ 0

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Income taxes
Deferred tax assets, operating loss carryforwards, federal	$ 4	$ 16.1
Deferred tax assets, tax credit carryforwards federal	5.7	5
Deferred tax assets, state operating loss carryforwards	1	0
Domestic tax authority
Income taxes
Net operating loss carryforwards	11.4	46.1
Federal tax credit carryforward	5.7	5
State and local jurisdiction
Income taxes
Net operating loss carryforwards	$ 18.6	$ 0.4

DEFERRED INCOME TAXES (Details)

DEFERRED INCOME TAXES (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Deferred income tax assets
Total deferred tax assets	$ 12.9	$ 23.9
Deferred income tax liabilities
Plant-related	800.5	639.1
Employee benefits and compensation	99.3	91.7
Regulatory deferrals	38.4	52
Other	4.2	15.2
Total deferred tax liabilities	942.4	798
Deferred tax liability, net	$ 929.5	$ 774.1

EMPLOYEE BENEFITS - CHANGE IN B

EMPLOYEE BENEFITS - CHANGE IN BENEFIT OBLIGATIONS AND PLAN ASSETS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Long-term assets	$ 114.8	$ 102.4
Long-term liabilities	25.4	24.4
Information for pension plans with an accumulated benefit obligation in excess of plan assets
Fair value of plan assets	0
Pension Benefits
Change in benefit obligation
Obligation at January 1	633.9	791.8
Service cost	9.9	10.7	$ 8.6
Interest cost	27	31.7	34.4
Plan amendments	0	0
Transfer to/from affiliates	6.2	(130.5)
Actuarial loss (gain)	26.1	(36.4)
Participant contributions	0	0
Benefit payments	(47.9)	(33.3)
Plan curtailments	0	(0.1)
Obligation at December 31	655.2	633.9	791.8
Change in fair value of plan assets
Fair value of plan assets at January 1	719	897.4
Actual return on plan assets	58	(29.4)
Employer contributions	1.3	1.1
Participant contributions	0	0
Benefit payments	(47.9)	(33.3)
Transfer to/from affiliates	6.2	(116.8)
Fair value of plan assets at December 31	736.6	719	897.4
Funded status at December 31	81.4	85.1
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Long-term assets	89	93.8
Long-term liabilities	7.6	8.7
Total net assets (liabilities)	81.4	85.1
Accumulated benefit obligation	590.8	569.6
Information for pension plans with an accumulated benefit obligation in excess of plan assets
Projected benefit obligation	7.6	8.7
Accumulated benefit obligation	7.6	8.5
OPEB
Change in benefit obligation
Obligation at January 1	231.6	252.5
Service cost	7.3	8.7	7.7
Interest cost	10.6	10.4	11.5
Plan amendments	(18.9)	0
Transfer to/from affiliates	0	0
Actuarial loss (gain)	0.6	(31.7)
Participant contributions	0.4	0.3
Benefit payments	(8.5)	(8.6)
Plan curtailments	0	0
Obligation at December 31	223.1	231.6	252.5
Change in fair value of plan assets
Fair value of plan assets at January 1	224.5	236.6
Actual return on plan assets	14.6	(5.1)
Employer contributions	0.1	1.3
Participant contributions	0.4	0.3
Benefit payments	(8.5)	(8.6)
Transfer to/from affiliates	0	0
Fair value of plan assets at December 31	231.1	224.5	$ 236.6
Funded status at December 31	8	(7.1)
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Long-term assets	25.8	8.6
Long-term liabilities	17.8	15.7
Total net assets (liabilities)	$ 8	$ (7.1)

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	$ 221.4	$ 61.2
Prior service credits	0	0
Total	221.4	61.2
Net actuarial loss	17.3
Prior service credits	0
Total 2017 - estimated amortization	17.3
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)
Service cost	9.9	10.7	$ 8.6
Interest cost	27	31.7	34.4
Expected return on plan assets	(52.6)	(64.8)	(64.1)
Loss on plan settlement	3.4	0.1	0.4
Amortization of prior service cost (credit)	0	0.2	0.6
Amortization of net actuarial loss	18	21	15
Net periodic benefit cost	5.7	(1.1)	(5.1)
OPEB
Net regulatory assets
Net actuarial loss	27.8	5.2
Prior service credits	(80.6)	0
Total	(52.8)	5.2
Net actuarial loss	2.5
Prior service credits	(9.2)
Total 2017 - estimated amortization	(6.7)
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)
Service cost	7.3	8.7	7.7
Interest cost	10.6	10.4	11.5
Expected return on plan assets	(15.9)	(16)	(16)
Loss on plan settlement		0	0
Amortization of prior service cost (credit)	(7.4)	(9.3)	(8)
Amortization of net actuarial loss	2.5	3.7	2.8
Net periodic benefit cost	$ (2.9)	$ (2.5)	$ (2)

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	4.19%	4.49%
Rate of compensation increase	4.00%	4.00%
Discount rate	4.25%	4.08%	4.92%
Expected return on plan assets	7.25%	7.75%	8.00%
Rate of compensation increase	4.00%	4.23%	4.25%
Expected return on assets during next fiscal year	7.25%
Pension Benefits | Equity securities:
Target asset allocations
Target asset allocations (as a percent)	60.00%
Pension Benefits | Fixed income securities:
Target asset allocations
Target asset allocations (as a percent)	40.00%
OPEB
Weighted average assumptions used
Discount rate	4.21%	4.46%
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	4.46%	4.11%	4.78%
Expected return on plan assets	7.25%	7.75%	8.00%
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	$ 3.3
Effect of one-percentage-point decrease on total of service and interest cost components of net periodic postretirement health care benefit cost	(2.6)
Effect of one-percentage-point increase on the health care component of the accumulated postretirement benefit obligation	29.9
Effect of one-percentage-point decrease on the health care component of the accumulated postretirement benefit obligation	$ (23.7)
OPEB | Maximum
Weighted average assumptions used
Assumed medical cost trend rate (as a percent)	7.50%	6.00%	6.50%
Ultimate trend rate (as a percent)	5.00%	5.00%	5.00%
Year ultimate trend rate is reached	2,021	2,023	2,019
OPEB | Equity securities:
Target asset allocations
Target asset allocations (as a percent)	50.00%
OPEB | Equity securities: | Maximum
Target asset allocations
Target asset allocations (as a percent)	45.00%
OPEB | Fixed income securities:
Target asset allocations
Target asset allocations (as a percent)	50.00%
OPEB | Fixed income securities: | Maximum
Target asset allocations
Target asset allocations (as a percent)	55.00%

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	$ 736.6	$ 719	$ 897.4
Fair value of plan assets subject to levelling	306.2	198.6
Pension Plan Assets | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	20.5	16.3
Pension Plan Assets | United States equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	95	20.6
Pension Plan Assets | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	18.4	39.7
Pension Plan Assets | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	152.2	99.9
Pension Plan Assets | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	20.1	22.1
Pension Plan Assets | Investments measured at net asset value
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	430.4	520.4
Pension Plan Assets | Level 1
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	114.3	64.7
Pension Plan Assets | Level 1 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	1.3	0
Pension Plan Assets | Level 1 | United States equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	94.9	18.7
Pension Plan Assets | Level 1 | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	18.1	39.7
Pension Plan Assets | Level 1 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	6.3
Pension Plan Assets | Level 1 | International bonds
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	191.4	133.9
Pension Plan Assets | Level 2 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	19.2	16.3
Pension Plan Assets | Level 2 | United States equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0.1	1.9
Pension Plan Assets | Level 2 | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0.3	0
Pension Plan Assets | Level 2 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	151.7	93.6
Pension Plan Assets | Level 2 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	20.1	22.1
Pension Plan Assets | Level 3
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0.5	0
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	0.5	0
Pension Plan Assets | Level 3 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
OPEB Plan Assets
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	231.1	224.5	$ 236.6
Fair value of plan assets subject to levelling	53	27
OPEB Plan Assets | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	10.5	3.9
OPEB Plan Assets | United States equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	7.1	5.8
OPEB Plan Assets | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0.4	15.9
OPEB Plan Assets | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	33.2	1.2
OPEB Plan Assets | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	1.8	0.2
OPEB Plan Assets | Investments measured at net asset value
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	178.1	197.5
OPEB Plan Assets | Level 1
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	17.7	25.5
OPEB Plan Assets | Level 1 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	10.3	3.7
OPEB Plan Assets | Level 1 | United States equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	7.1	5.8
OPEB Plan Assets | Level 1 | International equity
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0.3	15.9
OPEB Plan Assets | Level 1 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0.1
OPEB Plan Assets | Level 1 | International bonds
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	35.3	1.5
OPEB Plan Assets | Level 2 | Cash and cash equivalents
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0.2	0.2
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	0.1	0
OPEB Plan Assets | Level 2 | United States bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	33.2	1.1
OPEB Plan Assets | Level 2 | International bonds
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	1.8	0.2
OPEB Plan Assets | Level 3
Employee Benefit Plans
Defined Benefit Plan, Fair Value of Plan Assets	0	0
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

EMPLOYEE BENEFITS - CHANGES IN

EMPLOYEE BENEFITS - CHANGES IN THE FAIR VALUE OF PLAN ASSETS (Details) - Pension Benefits - Level 3 $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Employee Benefit Plans
Defined benefit plan change in fair value	$ 0
United States bonds
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	0
Purchases	0.5
Ending balance at December 31	$ 0.5

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
Defined Contribution Benefit Plans
Total costs incurred for defined contribution benefit plans	$ 9	$ 9.7	$ 8.6
Pension Benefits
Employee Benefit Plans
Expected contributions to the plans during the next fiscal year	0.7
Expected payments, reflecting expected future service
2,017	31.9
2,018	32.3
2,019	33.2
2,020	35
2,021	35.5
2022 through 2026	179.3
OPEB
Expected payments, reflecting expected future service
2,017	9.7
2,018	10.7
2,019	11.4
2,020	11.1
2,021	11.6
2022 through 2026	$ 63.5

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions	Dec. 31, 2016USD ($)
Minimum future commitments for purchase obligations
Total Amounts Committed	$ 919.8
2,017	215.3
2,018	139.9
2,019	98.1
2,020	74.7
2,021	70.5
Later Years	321.3
Electric | Purchased power
Minimum future commitments for purchase obligations
Total Amounts Committed	622.7
2,017	85.8
2,018	54.7
2,019	57.7
2,020	60.1
2,021	58.7
Later Years	305.7
Electric | Coal supply and transportation
Minimum future commitments for purchase obligations
Total Amounts Committed	141.9
2,017	85.8
2,018	42.8
2,019	13.3
2,020	0
2,021	0
Later Years	0
Natural gas | Natural gas supply and transportation
Minimum future commitments for purchase obligations
Total Amounts Committed	155.2
2,017	43.7
2,018	42.4
2,019	27.1
2,020	14.6
2,021	11.8
Later Years	$ 15.6

COMMITMENTS AND CONTINGENCIES89

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	$ 1.5	$ 1.4	$ 1.6
Minimum future payments under noncancelable operating leases
2,017	0.4
2,018	0.6
2,019	0.4
2,020	0.5
2,021	0.5
Later years	11.8
Total	$ 14.2

COMMITMENTS AND CONTINGENCIES90

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) T in Millions, $ in Millions	1 Months Ended						12 Months Ended
	Sep. 30, 2016	Jan. 31, 2016	Dec. 31, 2015USD ($)	Aug. 31, 2014	Jun. 30, 2013USD ($)	Mar. 31, 2013USD ($)	Dec. 31, 2016USD ($)T	Dec. 31, 2015USD ($)T	Jun. 01, 2015USD ($)
Electric | Cross-State Air Pollution Rule
Air Quality
Number Of States Impacted By Cross State Air Pollution Rule	23
Electric | Mercury And Other Hazardous Air Pollutants
Air Quality
Percentage Mercury Emission Reduction							90.00%
Electric | Climate Change
Air Quality
Percentage greenhouse gas emission reduction nationwide								32.00%
Interim requirement greenhouse gas emissions reductions								0.667
Percentage carbon dioxide emission reduction company goal							40.00%
Carbon dioxide emissions | T							5.7	5.7
Electric | Clean Water Act Cooling Water Intake Structure Rule [Member]
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							$ 25
Electric | Steam Electric Effluent Guidelines | Maximum
Water Quality
Expected environmental costs to achieve required emission reductions							$ 35
Electric | Weston and Pulliam Consent Decree
Consent Decrees
Beneficial environmental project amount						$ 6
Civil penalty						$ 1.2
Regulatory asset for undepreciated book value of retired plants									$ 11.5
Electric | Joint Ownership Power Plants Consent Decree - Columbia and Edgewater
Consent Decrees
Beneficial environmental project amount					$ 1.3
Civil penalty					$ 0.4
Natural gas | Climate Change
Air Quality
Carbon dioxide emissions | T							3.6	3.5
Natural gas | Manufactured gas plant remediation
Manufactured Gas Plant Remediation
Regulatory assets recorded for remediation of manufactured gas plant sites			$ 104.4				$ 116	$ 104.4
Reserves recorded for remediation of manufactured gas plant sites			$ 83.5				$ 97.2	$ 83.5
MICHIGAN | Electric | Renewables, efficiency, and conservation
Renewables, Efficiency, and Conservation
Percent goal of electricity consumption							10.00%
Energy optimization target							1.00%
WISCONSIN | Electric | Climate Change
Air Quality
Percentage greenhouse gas emission reduction state								41.00%
Percentage greenhouse gas emission reduction for retirement of a nuclear plant			10.00%
WISCONSIN | Electric | Renewables, efficiency, and conservation
Renewables, Efficiency, and Conservation
Percent goal of electricity consumption							10.00%
Renewable energy percent required							9.74%
Percent of annual operating revenues							1.20%

FAIR VALUE MEASUREMENTS - ASSET

FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Fair Value
Document Period End Date	Dec. 31, 2016
Assets
Derivative Asset	$ 2.3	$ 2.3
Liabilities
Derivative Liability	1.4	6.1
Fair value measurements on a recurring basis
Assets
Derivative Asset	2.3	2.3
Liabilities
Derivative Liability		6.1
Fair value measurements on a recurring basis | Level 1
Assets
Derivative Asset	0.1	0.3
Liabilities
Derivative Liability		1.4
Fair value measurements on a recurring basis | Level 2
Assets
Derivative Asset	0.2	0
Liabilities
Derivative Liability		4.7
Fair value measurements on a recurring basis | Level 3
Assets
Derivative Asset	2	2
Liabilities
Derivative Liability		0
Fair value measurements on a recurring basis | Natural gas contracts
Assets
Derivative Asset	0.2	0.3
Liabilities
Derivative Liability		0.9
Fair value measurements on a recurring basis | Natural gas contracts | Level 1
Assets
Derivative Asset	0.1	0.3
Liabilities
Derivative Liability		0.9
Fair value measurements on a recurring basis | Natural gas contracts | Level 2
Assets
Derivative Asset	0.1	0
Liabilities
Derivative Liability		0
Fair value measurements on a recurring basis | Natural gas contracts | Level 3
Assets
Derivative Asset	0	0
Liabilities
Derivative Liability		0
Fair value measurements on a recurring basis | FTRs
Assets
Derivative Asset	2	2
Fair value measurements on a recurring basis | FTRs | Level 1
Assets
Derivative Asset	0	0
Fair value measurements on a recurring basis | FTRs | Level 2
Assets
Derivative Asset	0	0
Fair value measurements on a recurring basis | FTRs | Level 3
Assets
Derivative Asset	2	2
Fair value measurements on a recurring basis | Petroleum product contracts
Liabilities
Derivative Liability		0.5
Fair value measurements on a recurring basis | Petroleum product contracts | Level 1
Liabilities
Derivative Liability		0.5
Fair value measurements on a recurring basis | Petroleum product contracts | Level 2
Liabilities
Derivative Liability		0
Fair value measurements on a recurring basis | Petroleum product contracts | Level 3
Liabilities
Derivative Liability		0
Fair value measurements on a recurring basis | Coal contracts
Assets
Derivative Asset	0.1
Liabilities
Derivative Liability	1.4	4.7
Fair value measurements on a recurring basis | Coal contracts | Level 1
Assets
Derivative Asset	0
Liabilities
Derivative Liability	0	0
Fair value measurements on a recurring basis | Coal contracts | Level 2
Assets
Derivative Asset	0.1
Liabilities
Derivative Liability	1.4	4.7
Fair value measurements on a recurring basis | Coal contracts | Level 3
Assets
Derivative Asset	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, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at the beginning of period	$ 2	$ (0.3)	$ (1.3)
Net realized and unrealized (losses)	(0.2)	(10.7)	(1)
Purchases	7.1	9.8	4.3
Sales	(0.2)	(0.1)	0
Settlements	(6.7)	(1.4)	(3.5)
Transfers out of Level 3	0	4.7	1.2
Balance at the end of the period	$ 2	$ 2	$ (0.3)

FAIR VALUE MEASUREMENTS - FINAN

FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS NOT RECORDED AT FAIR VALUE (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 1,290.3	$ 1,289.4
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,290.3	1,289.4
Long-term debt to parent	0	2.9
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	1,373.4	1,350.4
Long-term debt to parent	$ 0	$ 3

DERIVATIVE INSTRUMENTS - DERIVA

DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative Asset
Other current derivative assets	$ 2.2	$ 2.3
Derivative Asset	2.3	2.3
Derivative Liability
Other current derivative liabilities	0.9	4.7
Derivative Liability	1.4	6.1
Natural gas contracts
Derivative Asset
Other current derivative assets	0.2	0.3
Derivative Liability
Other current derivative liabilities	0	0.9
Petroleum product contracts
Derivative Asset
Other current derivative assets	0	0
Derivative Liability
Other current derivative liabilities	0	0.5
FTRs
Derivative Asset
Other current derivative assets	2	2
Derivative Liability
Other current derivative liabilities	0	0
Coal contracts
Derivative Asset
Other current derivative assets	0	0
Other long-term derivative assets	0.1	0
Derivative Liability
Other current derivative liabilities	0.9	3.3
Other long-term derivative liabilities	$ 0.5	$ 1.4

DERIVATIVE INSTRUMENTS - GAINS

DERIVATIVE INSTRUMENTS - GAINS (LOSSES) AND NOTIONAL VOLUMES (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MWhMMBTUgal	Dec. 31, 2015USD ($)MWhMMBTUgal	Dec. 31, 2014USD ($)MWhMMBTUgal
Realized Gain (Loss)
Gain (Loss)	$ 4	$ (3.3)	$ 3.7
Natural gas contracts
Realized Gain (Loss)
Gain (Loss)	$ (1.4)	$ (4.9)	$ 0.6
Notional Disclosures
Notional sales volumes (Dth or MWh) | MMBTU	28.6	22.9	20
Petroleum product contracts
Realized Gain (Loss)
Gain (Loss)	$ (0.6)	$ (1.7)	$ (0.1)
Notional Disclosures
Notional sales volumes (gallons) | gal	4.4	6.1	5.3
FTRs
Realized Gain (Loss)
Gain (Loss)	$ 6	$ 3.3	$ 3.2
Notional Disclosures
Notional sales volumes (Dth or MWh) | MWh	8.4	9	8.7

DERIVATIVE INSTRUMENTS - BALANC

DERIVATIVE INSTRUMENTS - BALANCE SHEET OFFSETTING (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Cash collateral
Cash Collateral	$ 16.1	$ 17.6
Cash collateral not offset	0	1.1
Offsetting Derivative Assets
Gross amount recognized on the balance sheet	2.3	2.3
Gross amount not offset on the balance sheet	0	(0.3)
Net Amount	2.3	2
Offsetting Derivative Liabilities
Gross amount recognized on balance sheet	1.4	6.1
Gross amount not offset on balance sheet	0	(1.4)
Net Amount	$ 1.4	$ 4.7

REGULATORY ENVIRONMENT (Details

REGULATORY ENVIRONMENT (Details) - USD ($) $ in Millions	1 Months Ended					12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Apr. 30, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2016
Regulatory environment
Percent fuel costs can vary from the rate case approved costs before deferral is required						2.00%
Public Service Commission of Wisconsin (PSCW) | 2016 Rates
Regulatory environment
Approved return on equity (as a percent)		10.00%
Approved common equity component average (as a percent)		51.00%
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Electric rates
Regulatory environment
Approved annual rate increase (decrease)		$ (7.9)
Approved annual rate increase (decrease), percentage		(0.80%)
Authorized revenue requirement for ReACT	$ 275	$ 275
Percent fuel costs can vary from the rate case approved costs before deferral is required		2.00%
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Natural gas rates
Regulatory environment
Approved annual rate increase (decrease)		$ (6.2)
Approved annual rate increase (decrease), percentage		(2.10%)
Public Service Commission of Wisconsin (PSCW) | 2015 Rates
Regulatory environment
Approved return on equity (as a percent)				10.20%
Approved common equity component average (as a percent)				50.28%
Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Electric rates
Regulatory environment
Approved annual rate increase (decrease)				$ 24.6
Percent fuel costs can vary from the rate case approved costs before deferral is required				2.00%
Increase in cost of fuel for electric generation				$ 42
Year-over-year positive (negative) change in decoupling refunded to or collected from customers				9
Customer recoveries (refunds) related to decoupling				(4)
Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Natural gas rates
Regulatory environment
Approved annual rate increase (decrease)				15.4
Year-over-year positive (negative) change in decoupling refunded to or collected from customers				(16)
Customer recoveries (refunds) related to decoupling				(8)
Public Service Commission of Wisconsin (PSCW) | 2014 Rates
Regulatory environment
Approved return on equity (as a percent)					10.20%
Approved common equity component average (as a percent)					50.14%
Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Electric rates
Regulatory environment
Approved annual rate increase (decrease)					$ (12.8)
Customer recoveries (refunds) related to decoupling				(13)
Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Natural gas rates
Regulatory environment
Approved annual rate increase (decrease)					$ 4
Customer recoveries (refunds) related to decoupling				$ 8
Michigan Public Service Commission (MPSC) | 2015 Rates | Electric rates
Regulatory environment
Approved return on equity (as a percent)			10.20%
Approved common equity component average (as a percent)			50.48%
Approved annual rate increase (decrease)			$ 4
Period of rate implementation			3 years

Other Income, Net (Details)

Other Income, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Income, net [Abstract]
AFUDC - Equity	$ 19.5	$ 15.1	$ 11
Earnings from equity method investments	9.5	8.5	10.3
Other, net	1.8	2	3.9
Other income, net	$ 30.8	$ 25.6	$ 25.2

SEGMENTS INFORMATION (Details)

SEGMENTS INFORMATION (Details) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2016USD ($)segment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Segment reporting information
Number of reportable segments | segment									2
Revenues	$ 361	$ 381	$ 331.5	$ 374.7	$ 337.2	$ 390.8	$ 330.3	$ 425	$ 1,448.2	$ 1,483.3	$ 1,683.6
Other operation and maintenance									493.2	493.4	499.7
Depreciation and amortization									124.1	121	116.8
Operating income (loss)	37.9	$ 105.3	$ 43.4	$ 76.9	25.5	$ 88.5	$ 44.2	$ 69.9	263.5	228.1	257.6
Other income, net									30.8	25.6	25.2
Interest expense									48.1	53.5	57.4
Capital expenditures									311.1	371	322
Total assets	4,808.2				4,505.1				4,808.2	4,505.1	4,269.3
Intersegment revenues
Segment reporting information
Revenues									0	0	0
Utility
Segment reporting information
Revenues									1,448.2	1,483.3	1,683.6
Other operation and maintenance									492.5	493.9	499.3
Depreciation and amortization									124	120.7	116.7
Operating income (loss)									264.4	228	257.2
Other income, net									23.3	16	12.3
Interest expense									48	53.2	55.3
Capital expenditures									311.1	371	322
Total assets	4,686.4				4,416.8				4,686.4	4,416.8	4,183.9
Utility | Intersegment revenues
Segment reporting information
Revenues									0	0	0
Other
Segment reporting information
Revenues									0	0	0
Other operation and maintenance									1	0.3	0.4
Depreciation and amortization									0.1	0.3	0.6
Operating income (loss)									(0.9)	0.1	0.4
Other income, net									7.5	9.6	12.9
Interest expense									0.1	0.3	2.1
Capital expenditures									0	0	0
Total assets	121.8				88.3				121.8	88.3	85.4
Other | Intersegment revenues
Segment reporting information
Revenues									0.3	0.8	1.4
Reconciling Eliminations
Segment reporting information
Revenues									0	0	0
Other operation and maintenance									(0.3)	(0.8)	0
Depreciation and amortization									0	0	(0.5)
Operating income (loss)									0	0	0
Other income, net									0	0	0
Interest expense									0	0	0
Capital expenditures									0	0	0
Total assets	$ 0				$ 0				0	0	0
Reconciling Eliminations | Intersegment revenues
Segment reporting information
Revenues									$ (0.3)	$ (0.8)	$ (1.4)
ATC
Segment reporting information
Equity method investment, ownership interest (as a percent)	34.00%								34.00%
WPS Investments, LLC
Segment reporting information
Equity method investment, ownership interest (as a percent)	10.37%								10.37%

QUARTERLY FINANCIAL INFORMAT100

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	$ 361	$ 381	$ 331.5	$ 374.7	$ 337.2	$ 390.8	$ 330.3	$ 425	$ 1,448.2	$ 1,483.3	$ 1,683.6
Operating income	37.9	105.3	43.4	76.9	25.5	88.5	44.2	69.9	263.5	228.1	257.6
Net income attributed to common shareholder	$ 20.2	$ 64.7	$ 26.3	$ 44.5	$ 10.6	$ 50.3	$ 22.6	$ 39	$ 155.7	$ 122.5	$ 137.6

SCHEDULE II - VALUATION AND 101

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	$ 2.5	$ 3.2	$ 2.5
Expense	7.7	6.7	7.3
Net write-offs	(7.2)	(7.4)	(6.6)
Balance at end of period	$ 3	$ 2.5	$ 3.2