Integrys Holding (TEG) 10-K 2 Mar 15 2014 FY Annual report Financial data

DOCUMENT_AND_ENTITY_INFORMATIO

DOCUMENT AND ENTITY INFORMATION (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 25, 2015	Jun. 30, 2014
Document and Entity Information
Entity Registrant Name	INTEGRYS ENERGY GROUP, INC.
Entity Central Index Key	916863
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$5,656,939,310
Entity Common Stock, Shares Outstanding		79,963,091
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement [Abstract]
Operating revenues	$4,144.20	$3,485.50	$3,012.90
Cost of sales	2,133	1,598.70	1,349.10
Operating and maintenance expense	1,199.70	1,086.70	943
Depreciation and amortization expense	287.5	263.4	247.3
Taxes other than income taxes	97	97.2	94
Merger transaction costs	10.4	0	0
Gain on sale of UPPCO, net of transaction costs	-85.4	0	0
Gain on abandonment of PDI's Winnebago Energy Center	-5	0	0
Operating income	507	439.5	379.5
Earnings from equity method investments	88.3	91.5	87.2
Miscellaneous income	31	21.9	9
Interest expense	154.8	127.4	118.9
Other expense	-35.5	-14	-22.7
Income before taxes	471.5	425.5	356.8
Provision for income taxes	193.4	158	117.9
Net income from continuing operations	278.1	267.5	238.9
Discontinued operations, net of tax	1.8	87.3	45.4
Net income	279.9	354.8	284.3
Preferred stock dividends of subsidiary	-3.1	-3.1	-3.1
Noncontrolling interest in subsidiaries	0.1	0.1	0.2
Net income attributed to common shareholders	$276.90	$351.80	$281.40
Average shares of common stock
Basic (in shares)	80.2	79.5	78.6
Diluted (in shares)	80.7	80.1	79.3
Earnings per common share (basic)
Net income from continuing operations (in dollars per share)	$3.43	$3.33	$3
Discontinued operations, net of tax (in dollars per share)	$0.02	$1.10	$0.58
Earnings per common share (basic) (in dollars per share)	$3.45	$4.43	$3.58
Earnings per common share (diluted)
Net income from continuing operations (in dollars per share)	$3.41	$3.30	$2.98
Discontinued operations, net of tax (in dollars per share)	$0.02	$1.09	$0.57
Earnings per common share (diluted) (in dollars per share)	$3.43	$4.39	$3.55

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net income	$279.90	$354.80	$284.30
Cash flow hedges
Unrealized net gains (losses) arising during period, net of tax of an insignificant amount for all periods presented	0	0.7	-0.2
Reclassification of net losses (gains) to net income, net of tax of $1.2 million, $3.6 million, and $2.0 million, respectively	-0.1	1.4	6.5
Cash flow hedges, net	-0.1	2.1	6.3
Defined benefit plans
Pension and other postretirement benefit adjustments arising during period, net of tax of $(3.0) million, $8.9 million, and $(4.4) million, respectively	-6	13.2	-6.1
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $0.8 million, $1.7 million, and $1.0 million, respectively	1.7	2.4	1.4
Defined benefit plans, net	-4.3	15.6	-4.7
Other comprehensive income (loss), net of tax	-4.4	17.7	1.6
Comprehensive income	275.5	372.5	285.9
Preferred stock dividends of subsidiary	-3.1	-3.1	-3.1
Noncontrolling interest in subsidiaries	0.1	0.1	0.2
Comprehensive income attributed to common shareholders	$272.50	$369.50	$283

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Reclassification of net losses (gains) to net income, tax	$1.20	$3.60	$2
Pension and other postretirement benefit adjustments arising during period, tax	-3	8.9	-4.4
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, tax	$0.80	$1.70	$1

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Assets
Cash and cash equivalents	$18	$16.80
Accounts receivable and accrued unbilled revenues, net of reserves of $63.3 and $47.7, respectively	699.8	646.1
Inventories	327.2	218.9
Regulatory assets	118.9	127.4
Assets held for sale	0.7	277.9
Assets of discontinued operations related to IES's retail energy business	0	815.4
Deferred income taxes	52.4	31.4
Prepaid taxes	136.2	144.4
Other current assets	57.5	55.9
Current assets	1,410.70	2,334.20
Property, plant, and equipment, net of accumulated depreciation of $3,343.1 and $3,221.0, respectively	6,859.80	6,206.20
Regulatory assets	1,513.60	1,361.40
Equity method investments	572.4	540.9
Goodwill	655.4	655.4
Other long-term assets	270.1	145.4
Total assets	11,282	11,243.50
Liabilities and Equity
Short-term debt	317.6	326
Current portion of long-term debt	125	100
Accounts payable	490.7	401.9
Accrued taxes	87.7	78.9
Regulatory liabilities	153.7	101.1
Liabilities held for sale	0	49.1
Liabilities of discontinued operations related to IES's retail energy business	0	447.5
Other current liabilities	261.4	218.9
Current liabilities	1,436.10	1,723.40
Long-term debt	2,956.30	2,956.20
Deferred income taxes	1,570	1,390.30
Deferred investment tax credits	65.5	57.6
Regulatory liabilities	399.9	383.7
Environmental remediation liabilities	579.9	600
Pension and other postretirement benefit obligations	274.6	200.8
Asset retirement obligations	480.2	491
Other long-term liabilities	168.7	127.1
Long-term liabilities	6,495.10	6,206.70
Commitments and contingencies
Common stock – $1 par value; 200,000,000 shares authorized; 79,963,091 shares issued; 79,534,171 shares outstanding	80	79.9
Additional paid-in capital	2,642.20	2,660.50
Retained earnings	626	567.1
Accumulated other comprehensive loss	-27.6	-23.2
Shares in deferred compensation trust	-20.9	-23
Total common shareholders' equity	3,299.70	3,261.30
Preferred stock of subsidiary – $100 par value; 1,000,000 shares authorized; 511,882 shares issued; 510,495 shares outstanding	51.1	51.1
Noncontrolling interest in subsidiaries	0	1
Total liabilities and equity	$11,282	$11,243.50

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]
Accounts receivable and accrued unbilled revenues, reserves (in dollars)	$63.30	$47.70
Accumulated depreciation	$3,343.10	$3,221
Common stock, par value (in dollars per share)	$1
Common stock, shares authorized	200,000,000
Common stock, shares issued	79,963,091	79,919,176
Common stock, shares outstanding	79,534,171	79,445,380
Preferred stock of subsidiary, par value (in dollars per share)	$100
Preferred stock of subsidiary, shares authorized	1,000,000
Preferred stock of subsidiary, shares issued	511,882
Preferred stock of subsidiary, shares outstanding	510,495

CONSOLIDATED_STATEMENTS_OF_EQU

CONSOLIDATED STATEMENTS OF EQUITY (USD $)	Total	Total Common Shareholders' Equity	Shares in Deferred Compensation Trust	Common Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Preferred Stock of Subsidiary	Noncontrolling Interest in Subsidiaries
In Millions, unless otherwise specified
Balance at Dec. 31, 2011	$3,012.60	$2,961.40	($17.10)	$78.30	$2,579.10	$363.60	($42.50)	$51.10	$0.10
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributed to common shareholders	281.2	281.4	0	0	0	281.4	0	0	-0.2
Other comprehensive income (loss)	1.6	1.6	0	0	0	0	1.6	0	0
Stock-based compensation	-4.8	-4.8	0	0	-4.1	-0.7	0	0	0
Dividends on common stock (dividends per common share of $2.72)	-211.9	-211.9	0	0	0	-211.9	0	0	0
Shares issued to and purchased for the deferred compensation trust	-3.2	-3.2	-3.2	0	0	0	0	0	0
Other	1.3	1.3	2.6	0	-0.4	-0.9	0	0	0
Balance at Dec. 31, 2012	3,076.80	3,025.80	-17.7	78.3	2,574.60	431.5	-40.9	51.1	-0.1
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributed to common shareholders	351.7	351.8	0	0	0	351.8	0	0	-0.1
Other comprehensive income (loss)	17.7	17.7	0	0	0	0	17.7	0	0
Issuance of common stock	79.8	79.8	0	1.5	78.3	0	0	0	0
Stock-based compensation	0.3	0.3	0	0	1	-0.7	0	0	0
Dividends on common stock (dividends per common share of $2.72)	-214.6	-214.6	0	0	0	-214.6	0	0	0
Net contributions from noncontrolling parties	1	0	0	0	0	0	0	0	1
Shares issued to and purchased for the deferred compensation trust	0	0	-6.3	0.1	6.2	0	0	0	0
Other	0.7	0.5	1	0	0.4	-0.9	0	0	0.2
Balance at Dec. 31, 2013	3,313.40	3,261.30	-23	79.9	2,660.50	567.1	-23.2	51.1	1
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributed to common shareholders	276.8	276.9	0	0	0	276.9	0	0	-0.1
Other comprehensive income (loss)	-4.4	-4.4	0	0	0	0	-4.4	0	0
Issuance of common stock	2.4	2.4	0	0.1	2.3	0	0	0	0
Stock-based compensation	-21.7	-21.7	0	0	-20.9	-0.8	0	0	0
Dividends on common stock (dividends per common share of $2.72)	-216.3	-216.3	0	0	0	-216.3	0	0	0
Shares issued to and purchased for the deferred compensation trust	-0.6	-0.6	-0.6	0	0	0	0	0	0
Other	1.2	2.1	2.7	0	0.3	-0.9	0	0	-0.9
Balance at Dec. 31, 2014	$3,350.80	$3,299.70	($20.90)	$80	$2,642.20	$626	($27.60)	$51.10	$0

CONSOLIDATED_STATEMENTS_OF_EQU1

CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Stockholders' Equity [Abstract]
Dividends per common share declared (in dollars per share)	$0.68	$2.72	$2.72	$2.72

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating activities
Net income	$279.90	$354.80	$284.30
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization expense	290.2	266.6	252.5
Recoveries and refunds of regulatory assets and liabilities	42.6	44.3	49.9
Net unrealized gains on energy contracts	-21.4	-100.5	-34.6
Bad debt expense	51.6	34.4	26.2
Pension and other postretirement expense	19	62.1	62.3
Pension and other postretirement contributions	-108.8	-77	-287.9
Deferred income taxes and investment tax credits	165.9	209.8	146
Gain on sale of UPPCO	-86.5	0	0
Loss on sale of IES's retail energy business	24.3	0	0
Gain on sale or disposal of other assets	-15.2	-1.8	-2.7
Equity income, net of dividends	-13.3	-19.2	-17.5
Termination of tolling agreement with Fox Energy Company LLC	0	-50	0
Other	43.5	34.9	25.3
Changes in working capital
Collateral on deposit	-46.5	2.3	9.6
Accounts receivable and accrued unbilled revenues	11.2	-358.6	-26.2
Inventories	-124.4	16.8	28.9
Other current assets	-11.6	-50.4	6.6
Accounts payable	12.7	142.9	21.8
Other current liabilities	88.2	43.5	29.3
Net cash provided by operating activities	601.4	554.9	573.8
Investing activities
Capital expenditures	-865	-669.2	-594.4
Proceeds from the sale of UPPCO, net of cash divested	336.5	0	0
Proceeds from the sale of IES's retail energy business, net of cash divested	311.6	0	0
Proceeds from the sale or disposal of other assets	26.1	6.6	17
Capital contributions to equity method investments	-18.4	-13.7	-27.4
Rabbi trust funding related to potential change in control	-115.5	0	0
Acquisition of Fox Energy Company LLC	0	-391.6	0
Acquisitions at IES	0	-15.7	0
Grant received related to Crane Creek wind project	0	69	0
Other	-11.8	-8.1	2.2
Net cash used for investing activities	-336.5	-1,022.70	-602.6
Financing activities
Short-term debt, net	-8.4	-156.4	179.1
Borrowing on term credit facility	0	200	0
Repayment of term credit facility	0	-200	0
Issuance of long-term debt	200	1,174	428
Repayment of long-term debt	-175	-363.5	-305.2
Proceeds from stock option exercises	85.8	38.7	55.8
Shares purchased for stock-based compensation	-142.9	-2	-89.9
Payment of dividends
Preferred stock of subsidiary	-3.1	-3.1	-3.1
Common stock	-216.3	-202.6	-211.9
Other	-9.3	-22.4	-24.7
Net cash (used for) provided by financing activities	-269.2	462.7	28.1
Net change in cash and cash equivalents	-4.3	-5.1	-0.7
Cash and cash equivalents at beginning of year	22.3	27.4	28.1
Cash and cash equivalents at end of year	18	22.3	27.4
Supplemental cash flow information
Cash paid for interest	146.8	116.1	109.7
Cash paid (received) for income taxes	$6.30	($4.80)	($47.60)

SUMMARY_OF_SIGNIFICANT_ACCOUNT

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	Summary of Significant Accounting Policies
	(a) Nature of Operations—We are an energy holding company whose primary wholly owned subsidiaries at December 31, 2014, included MERC, MGU, NSG, PGL, WPS, IBS, ITF, and PDI. Of these subsidiaries, five are natural gas and/or electric utilities (MERC, MGU, NSG, PGL, and WPS). IBS is a centralized service company, ITF is a nonregulated compressed natural gas fueling business, and PDI is a nonregulated distributed solar energy company. In addition, we have an approximate 34% interest in ATC.
	In August 2014, we sold UPPCO, and, in November 2014, we sold IES's retail energy business. See Note 4, Dispositions, for more information on these sales.
	(b) Basis of Presentation—As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the consolidated statements of income, consolidated statements of comprehensive income, consolidated balance sheets, consolidated statements of equity, and consolidated statements of cash flows, unless otherwise noted.
	The financial statements include our accounts and the accounts of all of our majority owned subsidiaries, after eliminating intercompany transactions and balances. These financial statements also reflect our proportionate interests in certain jointly owned utility facilities. 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 businesses 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. See Note 10, Equity Method Investments, for more information.
	(c) Reclassifications—The assets and liabilities associated with the sale of UPPCO and the sale of eight ITF compressed natural gas fueling stations were reclassified to held for sale on our December 31, 2013, balance sheet. The assets and liabilities related to the sale of IES's retail energy business were reclassified as assets and liabilities of discontinued operations on our December 31, 2013, balance sheet. In addition, the operations of IES's retail energy business were reclassified to discontinued operations on our income statements for the years ended December 31, 2013, and 2012. See Note 4, Dispositions, for more information on these sales.
	(d) Use of Estimates—We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect assets, 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.
	(e) Cash and Cash Equivalents—Short-term investments with an original maturity of three months or less are reported as cash equivalents.
	(f) Revenues and Customer Receivables—Revenues related to the sale of energy are recognized when service is provided or energy is delivered to customers. We accrue estimated amounts of revenues for services provided or energy delivered but not yet billed to customers. Estimated unbilled revenues are calculated using a variety of judgments and assumptions related to customer class, contracted rates, weather, and customer use. At December 31, 2014 and 2013, our unbilled revenues were $269.4 million and $286.4 million, respectively.
	We present revenues net of pass-through taxes on the income statements.
	Below is a summary of the significant mechanisms our utility subsidiaries had in place in 2014 that allowed them to recover or refund changes in prudently incurred costs from rate case-approved amounts:
	•	Fuel and purchased power costs were recovered from customers on a one-for-one basis by UPPCO, WPS's wholesale electric operations, and WPS's Michigan retail electric operations.
	•	WPS's Wisconsin retail electric operations used a "fuel window" mechanism to recover fuel and purchased power costs. Under the fuel window rule, a deferral is required for 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. WPS monitors the deferral of these costs to ensure that it does not cause them to earn a greater return on common equity than authorized by the PSCW.
	•	The rates for all of our natural gas utilities included one-for-one recovery mechanisms for natural gas commodity costs.
	•	The rates of PGL and NSG included riders for cost recovery of both environmental cleanup and energy conservation and management program costs.
	•	MERC's rates included a conservation improvement program rider for cost recovery of energy conservation and management program costs as well as a financial incentive for meeting energy savings goals.
	•	The rates of PGL and NSG included riders for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in customer rates.
	•	The rates of PGL, NSG, and MERC included decoupling mechanisms. These mechanisms differ by state and allow utilities to recover or refund differences between actual and authorized margins. See Note 25, Regulatory Environment, for more information.
	•	In 2014, PGL's rates included a cost recovery mechanism for upgrades to the Illinois natural gas utility infrastructure.
	Revenues are also impacted by other accounting policies related to PGL's natural gas hub and our electric utilities' participation in the MISO market. Amounts collected from PGL's wholesale customers that use the natural gas hub are credited to natural gas costs, resulting in a reduction to retail customers' charges for natural gas and services. WPS sells and purchases power in the MISO market. UPPCO also sold and purchased power in the MISO market until it was sold in August 2014. If WPS or UPPCO was a net seller in a particular hour, the net amount was reported as revenue. If WPS or UPPCO was a net purchaser in a particular hour, the net amount was recorded as utility cost of fuel, natural gas, and purchased power on the income statements.
	ITF accounts for revenues from construction management projects using the percentage of completion method. Revenues are recognized based on the percentage of costs incurred to date compared to the total estimated costs of each contract. This method is used because management considers total costs to be the best available measure of progress on these contracts.
	We provide regulated electric and natural gas service to customers in Illinois, Michigan, Minnesota, and Wisconsin. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Credit risk exposure at PGL and NSG is mitigated by their rider for cost recovery or refund of uncollectible expense discussed above. As a result, we did not have any significant concentrations of credit risk at December 31, 2014. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2014.
	(g) Inventories—Inventories consist of materials and supplies, natural gas in storage, liquid propane, emission allowances at WPS, and fossil fuels, including coal. Average cost is used to value materials and supplies, fossil fuels, liquid propane, emission allowances at WPS, and natural gas in storage for the utilities, excluding PGL and NSG. PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the Last-in, First-out (LIFO) cost method. Inventories stated on a LIFO basis represented approximately 37% of total inventories at December 31, 2014, and 30% of total inventories at December 31, 2013. The estimated replacement cost of natural gas in inventory at December 31, 2014, and December 31, 2013, exceeded the LIFO cost by $47.7 million and $151.7 million, respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per dekatherm of $3.04 at December 31, 2014, and $4.77 at December 31, 2013.
	(h) Risk Management Activities—As part of our regular operations, we enter into contracts, including options, swaps, futures, forwards, and other contractual commitments, to manage market risks such as changes in commodity prices and interest rates. See Note 6, Risk Management Activities, for more information. Derivative instruments are entered into in accordance with the terms of each subsidiary's risk management policies approved by their respective Boards of Directors and, if applicable, by their respective regulators.
	All derivatives are recognized on the balance sheets at their 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. Because most energy-related derivatives at the utilities qualify for regulatory deferral, management believes any gains or losses resulting from the eventual settlement of derivative instruments will be refunded to or collected from customers in rates. As such, any changes in the fair value of these derivatives recorded as either risk management assets or liabilities are offset with regulatory liabilities or assets, as appropriate.
	We classify derivative assets and liabilities as current or long-term on the balance sheets based on the maturities of the underlying contracts. We record unrealized gains and losses on derivative instruments that do not qualify for hedge accounting or regulatory deferral as a component of margins or operating and maintenance expense, depending on the nature of the transactions. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on the 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 the balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received from others is reflected in other current liabilities.
	(i) Emission Allowances—WPS accounts for emission allowances as inventory at average cost by vintage year. Charges to income result when allowances are used in operating WPS's generation plants. These charges are included in the costs subject to the fuel window rules. Gains on sales of allowances at WPS are returned to ratepayers.
	(j) Property, Plant, and Equipment—Utility plant is stated at cost, including any associated AFUDC and asset retirement costs. The costs of renewals and betterments of units of property (as distinguished from minor items of property) are capitalized as additions to the utility plant accounts. Maintenance and repair costs, as well as replacement and renewal costs associated with items not qualifying as units of property, are recorded as operating expenses. The utilities record a regulatory liability for cost of removal accruals, which are included in rates. Actual removal costs are charged against the regulatory liability as incurred. Except for land, no gains or losses are recognized in connection with ordinary retirements of utility property units. Ordinary retirements, sales, and other disposals of units of property at the utilities are charged to accumulated depreciation at cost, less salvage value. When it becomes probable that an operating unit will be retired in the near future and substantially in advance of its expected useful life, the cost and corresponding accumulated depreciation of the asset is classified as plant to be retired, net within property, plant, and equipment.
	We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below:
	Annual Utility Composite Depreciation Rates		2014		2013			2012
	MERC (1)		2.49	%	1.88	%		3.07	%
	MGU (2)		2.65	%	1.93	%		2.71	%
	NSG		2.44	%	2.44	%		2.43	%
	PGL		3.2	%	3.19	%		3.16	%
	WPS – Electric		2.73	%	2.79	%		2.87	%
	WPS – Natural gas		2.17	%	2.19	%		2.21	%
	-1	The 2013 depreciation rate reflects the impact of a new depreciation study approved by the MPUC in July 2013. The rates were effective retroactive to January 2012. An approximate $2 million reduction in depreciation expense was recorded in 2013 related to the 2012 impact.
	(2)	The 2013 depreciation rate includes the impact of a $2.5 million reduction in depreciation expense that was recorded in the first quarter of 2013 as a result of the Michigan Court of Appeals order reversing the MPSC's previously ordered disallowance associated with the early retirement of certain MGU assets in 2010.
	The majority of nonregulated plant is stated at cost, net of impairments recorded, and includes capitalized interest. The costs of renewals, betterments, and major overhauls are capitalized as additions to plant. Nonregulated plant acquired as a result of mergers and acquisitions have been recorded at fair value. The gains or losses associated with ordinary retirements are recorded in the period of retirement. Maintenance and repair costs and minor replacement costs are expensed as incurred. Depreciation is computed for the majority of the nonregulated subsidiaries' assets using the straight-line method over the assets' useful lives.
	We capitalize certain costs related to software developed or obtained for internal use and amortize those costs to operating expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.
	We 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 7, Property, Plant, and Equipment, for more information.
	(k) AFUDC and Capitalized Interest—Our utilities and IBS capitalize the cost of funds used for construction using a calculation that includes both internal equity and external debt components, as required by regulatory accounting. The internal equity component is accounted for as other income. The external debt component is accounted for as a decrease to interest expense.
	The majority of AFUDC is recorded at WPS. Approximately 50% of WPS's retail jurisdictional construction work in progress expenditures are subject to the AFUDC calculation. For 2014, WPS's average AFUDC retail rate was 8.08%, and its average AFUDC wholesale rate was 6.99%. The AFUDC calculation for the other utilities and IBS is determined by their respective state commissions, each with specific requirements. Based on these requirements, the other utilities and IBS did not record significant AFUDC for 2014, 2013, or 2012.
	Total AFUDC was as follows for the years ended December 31:
			2014			2013				2012
	Allowance for equity funds used during construction		$	12.5		$	10.8			$	2.9
	Allowance for borrowed funds used during construction		5.2			4.1				1
	(l) Regulatory Assets and Liabilities—Regulatory assets represent probable future revenue associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts 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 year the determination is made. See Note 9, Regulatory Assets and Liabilities, for more information.
	(m) Investments in Exchange-Traded Funds—We have investments in exchange-traded funds. These investments are held in a rabbi trust to help fund our obligations under our deferred compensation plan and certain non-qualified pension plans. These investments are classified as trading securities for accounting purposes. As we do not intend to sell them in the near term, they are included in other long-term assets on our balance sheets. The net unrealized gains included in earnings related to the investments held at the end of the period were $1.8 million, $1.9 million, and $1.0 million for the years ended December 31, 2014, 2013, and 2012, respectively.
	(n) Asset Impairment—Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. Intangible assets with definite lives are reviewed for impairment on a quarterly basis. Other long-lived assets require an impairment review when events or circumstances indicate that the carrying amount may not be recoverable. We base our evaluation of other long-lived assets on the presence of impairment indicators such as the future economic benefit of the assets, any historical or future profitability measurements, and other external market conditions or factors.
	Our reporting units containing goodwill perform annual goodwill impairment tests during the second quarter of each year. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value. See Note 11, Goodwill and Other Intangible Assets, for more information on our goodwill and other intangible assets.
	The carrying amount of tangible long-lived assets held and used is considered not recoverable if the carrying amount exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. If the carrying amount is not recoverable, the impairment loss is measured as the excess of the asset's carrying amount over its fair value.
	The carrying amount of assets held for sale is not recoverable if the carrying amount exceeds the fair value less estimated costs to sell the asset. An impairment loss is recorded for the excess of the asset’s carrying amount over the fair value less estimated costs to sell.
	The carrying amounts of cost and equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts, if a fair value assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value.
	(o) Retirement of Debt—Any call premiums or unamortized expenses associated with refinancing utility debt obligations are amortized consistent with regulatory treatment of those items. Any gains or losses resulting from the retirement of utility debt that is not refinanced are amortized over the remaining life of the original debt. Any gains or losses resulting from the retirement of nonutility debt are recorded through current earnings.
	(p) Asset Retirement Obligations—We recognize at fair value legal obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction or development, and/or normal operation of the assets. A liability is recorded 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 asset retirement obligations are accreted using a credit-adjusted risk-free interest rate commensurate with the expected settlement dates of the asset retirement obligations; this rate is determined at the date the obligation is incurred. The associated retirement costs are capitalized as part of the related long-lived assets and are depreciated over the useful lives of the assets. 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 in the carrying amount of the liability and the associated retirement cost. See Note 15, Asset Retirement Obligations, for more information.
	(q) 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 (PRP). Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including former manufactured gas plant sites. See Note 17, Commitments and Contingencies, for more information on our 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 PRPs or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.
	Our utilities have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the respective Commission's approval.
	We review our estimated costs of remediation annually for our manufactured gas plant sites and 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.
	(r) Income Taxes—We file a consolidated United States income tax return that includes domestic subsidiaries of which our ownership is 80% or more. We and our consolidated subsidiaries are parties to a federal and state tax allocation arrangement under which each entity determines its provision for income taxes on a stand-alone basis. In several states, combined or consolidated filings are required for certain subsidiaries doing business in that state.
	Deferred income taxes have been recorded to recognize the expected future tax consequences of events that have been included in the financial statements by using currently enacted tax rates for the differences between the income tax basis of assets and liabilities and the basis reported in the financial statements. We record valuation allowances for deferred income tax assets unless it is more likely than not that the benefit will be realized in the future. Our utilities defer certain adjustments made to income taxes that will impact future rates and record regulatory assets or liabilities related to these adjustments.
We use the deferral method of accounting for investment tax credits (ITCs). Under this method, we record the ITCs as deferred credits and amortize such credits as a reduction to the provision for income taxes over the life of the asset that generated the ITCs. ITCs that do not reduce income taxes payable for the current year are eligible for carryover and recognized as a deferred income tax asset.
We report interest and penalties accrued related to income taxes as a component of provision for income taxes in the income statements, as well as regulatory assets or regulatory liabilities on the balance sheets.
We record excess tax benefits from stock-based compensation awards when the actual tax benefit is realized. We follow the tax law ordering approach to determine when the tax benefit has been realized. Under this approach, the tax benefit is realized in the year it reduces taxable income. Current year stock-based compensation deductions are assumed to be used before any net operating loss carryforwards.
See Note 16, Income Taxes, for more information regarding accounting for income taxes.
(s) Guarantees—We follow the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. See Note 22, Guarantees, for more information.
(t) Employee Benefits—The costs of pension and other postretirement benefits are expensed over the periods during which employees render service. Our transition obligation related to other postretirement benefit plans was recognized over a 20-year period that began in 1993, and ended in 2012. In computing the expected return on plan assets, we use a market-related value of plan assets, which is estimated using the following approaches by plan. For plans sponsored by IBS and WPS, we use the calculated value approach. For plans sponsored by PELLC, we use the fair market value approach. Changes in realized and unrealized investment gains and losses are recognized over the subsequent five years for plans sponsored by WPS, while differences between actual investment returns and the expected return on plan assets are recognized over a five-year period for plans sponsored by IBS and PELLC. The benefit costs associated with employee benefit plans are allocated among our subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the utilities' net periodic benefit cost calculated under GAAP.
We recognize the funded status of defined benefit postretirement plans on the balance sheet, and recognize changes in the plans' funded status in the year in which the changes occur. Our nonregulated businesses record changes in the funded status in accumulated other comprehensive income. The utilities record changes in the funded status to regulatory asset or liability accounts, pursuant to the Regulated Operations Topic of the FASB ASC.
See Note 18, Employee Benefit Plans, for more information.
(u) Stock-Based Compensation—In May 2014, our shareholders approved the 2014 Omnibus Incentive Compensation Plan (2014 Omnibus Plan). Under the provisions of the 2014 Omnibus Plan, the number of shares of stock that may be issued in satisfaction of plan awards may not exceed 3,000,000 shares, plus any shares forfeited under prior plans. No single employee who is our chief executive officer, chief financial officer, or any one of our other three highest compensated officers (including officers of our subsidiaries) can be granted stock options for more than 1,000,000 shares or receive a payout in excess of 250,000 shares for performance stock rights during any calendar year. Additional awards will not be issued under prior plans, although the plans continue to exist for purposes of the existing outstanding stock-based compensation awards. At December 31, 2014, stock options, performance stock rights, and restricted share units were outstanding under prior plans.
Stock Options
Our stock options have a term not longer than 10 years. The exercise price of each stock option is equal to the fair market value of our stock on the date the stock option is granted.
Effective October 24, 2014, our Board of Directors accelerated the vesting of all unvested stock options held by active employees in order to help mitigate the tax impacts of Section 280G of the Internal Revenue Code on us and certain of our employees. All stock options awarded to active employees also became exercisable as of this date. For retirees, 25% of their stock options granted will continue to become exercisable each year on the anniversary of the grant date.
The fair value of stock option awards granted is estimated using a binomial lattice model. The expected term of option awards is derived from the output of the binomial lattice model and represents the period of time that options are expected to be outstanding. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate. Our expected stock price volatility is estimated using the 10-year historical volatility of our stock price.
Performance Stock Rights
Performance stock rights generally vest over a three-year performance period. For accounting purposes, awards granted to retirement-eligible employees vest over a shorter period; however, the distribution of these awards is not accelerated. Effective October 24, 2014, our Board of Directors approved the acceleration of the distribution of certain performance stock rights held by active employees. For those performance stock rights with a performance period ending December 31, 2014, a portion of the estimated distribution was made in December 2014. This change was made to help mitigate the tax impacts of Section 280G of the Internal Revenue Code on us and certain of our employees.
Performance stock rights are paid out in shares of our common stock, or eligible employees can elect to defer the value of their awards into the deferred compensation plan and choose among various investment options, some of which are ultimately paid out in our common stock and some of which are ultimately paid out in cash. Eligible employees can only elect to defer up to 80% of the value of their awards. The number of shares paid out is calculated by multiplying a performance percentage by the number of outstanding stock rights at the completion of the performance period. The performance percentage is based on the total shareholder return of our common stock relative to the total shareholder return of a peer group of companies. The payout may range from 0% to 200% of target.
Performance stock rights are accounted for as either an equity award or a liability award, depending on their settlement features. Awards that can only be settled in our common stock are accounted for as equity awards. Awards that an employee has elected to defer, or is still able to defer, into the deferred compensation plan are accounted for as liability awards and are recorded at fair value each reporting period.
Six months prior to the end of the performance period, employees can no longer change their election to defer the value of their performance stock rights into the deferred compensation plan. As a result, any awards not elected for deferral at this point in the performance period will be settled in our common stock. This changes the classification of these awards from a liability award to an equity award. The change in classification is accounted for as an award modification. The fair value on the modification date is used to measure these awards for the remaining six months of the performance period. No incremental compensation expense is recorded as a result of this award modification.
The fair values of performance stock rights are estimated using a Monte Carlo valuation model. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate. Our expected stock price volatility is estimated using one to three years of historical data.
Restricted Share Units
Restricted share units generally have a four-year vesting period, with 25% of each award vesting on each anniversary of the grant date. For accounting purposes, awards granted to retirement-eligible employees vest over a shorter period; however, the release of shares to these employees is not accelerated. Restricted share unit recipients do not have voting rights, but they receive forfeitable dividend equivalents in the form of additional restricted share units.
Restricted share units are accounted for as either an equity award or a liability award, depending on their settlement features. Awards that can only be settled in our common stock and cannot be deferred into the deferred compensation plan are accounted for as equity awards. Eligible employees can only elect to defer up to 80% of their awards into the deferred compensation plan. Equity awards are measured based on the fair value on the grant date. Awards that an employee has elected to defer into the deferred compensation plan are accounted for as liability awards and are recorded at fair value each reporting period.
Nonemployee Directors Deferred Stock Units
Each nonemployee director is granted deferred stock units (DSUs), typically in January of each year. The number of DSUs granted is calculated by dividing a set dollar amount by our closing common stock price on December 31 of the prior year. DSUs generally vest over one year. Therefore, the expense for these awards is recognized pro-rata over the year in which the grant occurs. Upon vesting, these awards are deferred into the deferred compensation plan; however, their value cannot be diversified among the various investment options. As DSUs can only be settled in our common stock, they are accounted for as equity awards.
(v) Earnings Per Share—Basic earnings per share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for shares we are obligated to issue under the deferred compensation and restricted share unit plans. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include in-the-money stock options, performance stock rights, restricted share units, unvested director DSUs, and certain shares issuable under the deferred compensation plan. As the obligation for the shares issuable under the deferred compensation plan is accounted for as a liability, the numerator is adjusted for any changes in income or loss that would have resulted had it been accounted for as an equity instrument during the period.
(w) Fair Value—A fair value measurement is required to reflect the assumptions market participants would use in pricing an asset or liability based on the best available information.
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). 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.
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.
When possible, we base the valuations of our risk management assets and liabilities on quoted prices for identical assets in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on observable inputs related to market price risk (commodity or interest rate), price volatility (for option contracts), and price correlation (for cross commodity contracts). 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. The primary reasons for a Level 3 classification are as follows:
•	Financial contracts used to manage transmission congestion costs in the MISO market are valued using historical prices.
•	The valuation for physical coal contracts is based on significant assumptions made to extrapolate prices from the last observable period through the end of the transaction term.
•	Certain natural gas contracts are valued using internally-developed inputs due to the absence of available market data for certain locations.
We have established risk oversight committees whose primary responsibility includes directly or indirectly ensuring that all valuation methods are applied in accordance with predefined policies. The development and maintenance of our forward price curves has been assigned to our risk management department, which is part of the corporate treasury function. This group is separate and distinct from any of the supply functions within the organization. To validate the reasonableness of our fair value inputs, our risk management department compares changes in valuation and researches any significant differences in order to determine the underlying cause. Changes to the fair value inputs are made if necessary.
Derivatives are transferred between levels of the fair value hierarchy due to observable pricing becoming available as the remaining contract term becomes shorter. We recognize transfers at the value as of the end of the reporting period.
The fair values of long-term debt instruments are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. The fair values of preferred stock are estimated based on quoted market prices when available, or by using a perpetual dividend discount model. The fair values of long-term debt instruments and preferred stock are categorized within Level 2 of the fair value hierarchy. Due to the short-term nature of cash and cash equivalents, accounts receivable, accounts payable, and outstanding commercial paper, the carrying amount for each of these items approximates fair value.
We conduct a thorough review of fair value hierarchy classifications on a quarterly basis.
See Note 24, Fair Value, for more information.
(x) New Accounting Pronouncements—
Recently Issued Accounting Guidance Not Yet Effective
In February 2015, the FASB issued ASU 2015-02, "Amendments to the Consolidation Analysis." The guidance focuses on the consolidation evaluation for companies that are required to evaluate whether they should consolidate certain legal entities. This ASU eliminates the specialized guidance for limited partnerships and similar legal entities. It places more emphasis on risk of loss when determining a controlling financial interest and amends the guidance for assessing how relationships of related parties affect the consolidation analysis of variable interest entities. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact this guidance will have on our financial statements.
In January 2015, the FASB issued ASU 2015-01, "Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items." This guidance no longer requires or allows the disclosure of extraordinary items, net of tax, in the income statement after income from continuing operations. The guidance is effective for us for the reporting period ending March 31, 2016. We do not currently have any extraordinary items presented on the income statements. However, this guidance will eliminate the need for us to further assess whether unusual and infrequently occurring transactions qualify as an extraordinary item in the future.
In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers." This ASU supersedes the requirements in the Revenue Recognition Topic of the FASB ASC and most industry-specific guidance throughout the ASC. The guidance is based on the principle that revenue is recognized when promised goods or services are transferred to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The standard requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and cash flows from customer contracts. The guidance is effective for us for the reporting period ending March 31, 2017. The standard requires either retrospective application by restating each prior period presented in the financial statements, or modified retrospective application by recording the cumulative effect of prior reporting periods to beginning retained earnings in the year that the standard becomes effective. Management is currently evaluating the impact that the adoption of this standard will have on our financial statements.
In April 2014, the FASB issued ASU 2014-08, "Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." The guidance raises the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. The guidance applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. Management early adopted this guidance in the third quarter of 2014. See Note 4, Dispositions, for more information.
In January 2014, the FASB issued ASU 2014-01, "Accounting for Investments in Qualified Affordable Housing Projects." The guidance allows investors to use the proportional amortization method to account for investments in qualified affordable housing projects if certain conditions are met. Under that method, which replaces the effective yield method, an investor amortizes the cost of its investment, in proportion to the tax credits and other tax benefits it receives, to income tax expense. The guidance also requires new disclosures for all investments in these types of projects. The guidance is effective for us for the reporting period ending March 31, 2015. Although we have investments in affordable housing projects, adoption of this guidance is not expected to have a significant impact on our financial statements.

PROPOSED_MERGER_WITH_WISCONSIN

PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION	Proposed Merger with Wisconsin Energy Corporation
	In June 2014, we entered into an Agreement and Plan of Merger (Agreement) with Wisconsin Energy Corporation (Wisconsin Energy). Under this Agreement, upon the close of the transaction our shareholders will receive 1.128 shares of Wisconsin Energy common stock and $18.58 in cash for each share of our common stock then owned. In addition, under the Agreement all of our unvested stock-based compensation awards will fully vest upon the close of the transaction and will be paid out in cash to award recipients. Upon closing of the transaction, our shareholders will own approximately 28% of the combined company, and Wisconsin Energy shareholders will own approximately 72%.
	The combined entity will be named WEC Energy Group, Inc. and will serve more than 4.3 million total natural gas and electric customers across Wisconsin, Illinois, Michigan, and Minnesota.
	This transaction was approved unanimously by the Boards of Directors of both companies. It was also approved by the shareholders of both companies. On October 24, 2014, the Department of Justice closed its review of the transaction and the Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Act. The transaction is still subject to approvals from the FERC, Federal Communications Commission (FCC), PSCW, ICC, MPSC, and MPUC, as well as other customary closing conditions. We are a party to a contested settlement agreement with the MPSC staff and all but one of the parties in the MPSC approval docket. The settling parties agree that the MPSC should grant approval of the merger contingent on additional transactions, including the sale of the Presque Isle facility currently owned by Wisconsin Energy, as well as the Michigan electric distribution assets of Wisconsin Energy and WPS, to UPPCO. The asset sales require additional approvals, including the MPSC, PSCW, FERC, FCC, and Committee on Foreign Investment in the United States, as well as the requirements of the Hart-Scott-Rodino Act. We expect the merger transaction to close in the second half of 2015.
	Acquisitions
	Agreement to Purchase Alliant Energy Corporation's Natural Gas Distribution Business in Southeast Minnesota
	In September 2013, MERC entered into an agreement to purchase Alliant Energy Corporation's natural gas distribution business in southeast Minnesota. This transaction was approved by the MPUC. The purchase price will be based on book value as of the closing date, which is expected to approximate $14 million. We anticipate closing on this transaction by the end of the second quarter of 2015. It will not be material to us.
	Acquisition of Fox Energy Center
	In March 2013, WPS acquired all of the equity interests in Fox Energy Company LLC for $391.6 million. Fox Energy Company LLC was dissolved into WPS immediately after the purchase.
	The purchase included the Fox Energy Center, a 593-megawatt combined-cycle electric generating facility located in Wisconsin, along with associated contracts. Fox Energy Center is a dual-fuel facility, equipped to use fuel oil, but being run primarily on natural gas. This plant gives WPS a more balanced mix of owned electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources. In giving its approval for the purchase, the PSCW stated that the purchase price was reasonable and will benefit ratepayers.
	The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:
	(Millions)
	Assets acquired (1)
	Inventories		$	3
	Other current assets		0.4
	Property, plant, and equipment		374.4
	Other long-term assets (2)		15.6
	Total assets acquired		$	393.4
	Liabilities assumed
	Accounts payable		$	1.8
	Total liabilities assumed		$	1.8
	(1)	Relates to the electric utility segment.
	(2)	Intangible assets recorded for contractual services agreements. See Note 11, Goodwill and Other Intangible Assets, for more information.
	Prior to the purchase, WPS supplied natural gas for the facility and purchased 500 megawatts of capacity and the associated energy output under a tolling arrangement. WPS paid $50.0 million for the early termination of the tolling arrangement. This amount was recorded as a regulatory asset, as WPS is authorized recovery by the PSCW. The amount is being amortized over a nine-year period that began on January 1, 2014.
	WPS received regulatory approval to defer incremental costs incurred in 2013 associated with the purchase of the facility. These costs are included in WPS's 2015 retail electric rate increase. See Note 25, Regulatory Environment, for more information. WPS's rate order effective January 1, 2014, included the costs of owning and operating the Fox Energy Center.
	Pro forma adjustments to our revenues and earnings prior to the date of acquisition would not be meaningful or material. Prior to the acquisition, the Fox Energy Center was a nonregulated plant and sold all of its output to third parties, with most of the output purchased by WPS. The plant is now part of WPS's regulated fleet, used to serve its customers.

ACQUISITIONS

ACQUISITIONS	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
ACQUISITIONS	Proposed Merger with Wisconsin Energy Corporation
	In June 2014, we entered into an Agreement and Plan of Merger (Agreement) with Wisconsin Energy Corporation (Wisconsin Energy). Under this Agreement, upon the close of the transaction our shareholders will receive 1.128 shares of Wisconsin Energy common stock and $18.58 in cash for each share of our common stock then owned. In addition, under the Agreement all of our unvested stock-based compensation awards will fully vest upon the close of the transaction and will be paid out in cash to award recipients. Upon closing of the transaction, our shareholders will own approximately 28% of the combined company, and Wisconsin Energy shareholders will own approximately 72%.
	The combined entity will be named WEC Energy Group, Inc. and will serve more than 4.3 million total natural gas and electric customers across Wisconsin, Illinois, Michigan, and Minnesota.
	This transaction was approved unanimously by the Boards of Directors of both companies. It was also approved by the shareholders of both companies. On October 24, 2014, the Department of Justice closed its review of the transaction and the Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Act. The transaction is still subject to approvals from the FERC, Federal Communications Commission (FCC), PSCW, ICC, MPSC, and MPUC, as well as other customary closing conditions. We are a party to a contested settlement agreement with the MPSC staff and all but one of the parties in the MPSC approval docket. The settling parties agree that the MPSC should grant approval of the merger contingent on additional transactions, including the sale of the Presque Isle facility currently owned by Wisconsin Energy, as well as the Michigan electric distribution assets of Wisconsin Energy and WPS, to UPPCO. The asset sales require additional approvals, including the MPSC, PSCW, FERC, FCC, and Committee on Foreign Investment in the United States, as well as the requirements of the Hart-Scott-Rodino Act. We expect the merger transaction to close in the second half of 2015.
	Acquisitions
	Agreement to Purchase Alliant Energy Corporation's Natural Gas Distribution Business in Southeast Minnesota
	In September 2013, MERC entered into an agreement to purchase Alliant Energy Corporation's natural gas distribution business in southeast Minnesota. This transaction was approved by the MPUC. The purchase price will be based on book value as of the closing date, which is expected to approximate $14 million. We anticipate closing on this transaction by the end of the second quarter of 2015. It will not be material to us.
	Acquisition of Fox Energy Center
	In March 2013, WPS acquired all of the equity interests in Fox Energy Company LLC for $391.6 million. Fox Energy Company LLC was dissolved into WPS immediately after the purchase.
	The purchase included the Fox Energy Center, a 593-megawatt combined-cycle electric generating facility located in Wisconsin, along with associated contracts. Fox Energy Center is a dual-fuel facility, equipped to use fuel oil, but being run primarily on natural gas. This plant gives WPS a more balanced mix of owned electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources. In giving its approval for the purchase, the PSCW stated that the purchase price was reasonable and will benefit ratepayers.
	The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:
	(Millions)
	Assets acquired (1)
	Inventories		$	3
	Other current assets		0.4
	Property, plant, and equipment		374.4
	Other long-term assets (2)		15.6
	Total assets acquired		$	393.4
	Liabilities assumed
	Accounts payable		$	1.8
	Total liabilities assumed		$	1.8
	(1)	Relates to the electric utility segment.
	(2)	Intangible assets recorded for contractual services agreements. See Note 11, Goodwill and Other Intangible Assets, for more information.
	Prior to the purchase, WPS supplied natural gas for the facility and purchased 500 megawatts of capacity and the associated energy output under a tolling arrangement. WPS paid $50.0 million for the early termination of the tolling arrangement. This amount was recorded as a regulatory asset, as WPS is authorized recovery by the PSCW. The amount is being amortized over a nine-year period that began on January 1, 2014.
	WPS received regulatory approval to defer incremental costs incurred in 2013 associated with the purchase of the facility. These costs are included in WPS's 2015 retail electric rate increase. See Note 25, Regulatory Environment, for more information. WPS's rate order effective January 1, 2014, included the costs of owning and operating the Fox Energy Center.
	Pro forma adjustments to our revenues and earnings prior to the date of acquisition would not be meaningful or material. Prior to the acquisition, the Fox Energy Center was a nonregulated plant and sold all of its output to third parties, with most of the output purchased by WPS. The plant is now part of WPS's regulated fleet, used to serve its customers.

DISPOSITIONS

DISPOSITIONS	12 Months Ended
	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
DISPOSITIONS	Dispositions
	Dispositions
	Holding Company and Other Segment – Sale of Compressed Natural Gas (CNG) Fueling Stations
	In November 2014, ITF sold eight CNG fueling stations to AMP Trillium LLC, a joint venture between ITF and AMP Americas LLC. ITF owns 30% and AMP Americas LLC owns 70% of AMP Trillium LLC. The fair value of the CNG fueling stations was $13.0 million. ITF received cash proceeds of $7.2 million, a $2.7 million note receivable from the buyer with a seven-year term, and a $3.1 million equity interest in the joint venture to maintain its ownership interest. In November 2014, we recorded a pre-tax gain of $1.8 million related to the sale of the CNG fueling stations and deferred a gain of $0.8 million that is being recognized over the lives of the stations sold. The pre-tax gain was reported as a component of operating and maintenance expense on the income statement.
	In the third quarter of 2014, we early adopted the guidance in FASB ASU 2014-08, "Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." Under this guidance, the results of operations of a component of a business that is sold are only accounted for as discontinued operations if the sale represents a shift in strategy that has (or will have) a major effect on the entity's operations and financial results. The sale of the CNG stations did not represent a shift in our strategy. Therefore, the results of operations of the CNG fueling stations prior to the sale remain in continuing operations.
	Net property, plant, and equipment of $10.4 million was included with the sale on November 1, 2014, which is net of accumulated depreciation of $0.7 million. Net property, plant, and equipment of $5.3 million were classified as held for sale on the balance sheet at December 31, 2013, which was net of accumulated depreciation of $0.3 million.
	Electric Utility Segment – Sale of UPPCO
	In August 2014, we sold all of the stock of UPPCO to Balfour Beatty Infrastructure Partners LP for $336.7 million. In the third quarter of 2014, we recorded a pre-tax gain of $85.4 million ($51.2 million after-tax) related to the sale of UPPCO, which was net of transaction costs of $1.1 million. Following the sale, we are providing certain administrative and operational services to UPPCO during a transition period of 18 to 30 months.
	The sale of UPPCO was evaluated for accounting purposes prior to our early adoption of ASU 2014-08. UPPCO met the criteria in the accounting guidance to qualify as held for sale but did not meet the requirements to qualify as discontinued operations as WPS has significant continuing cash flows related to certain power purchase transactions with UPPCO that continued after the sale. Therefore, UPPCO's results of operations through the sale date remain in continuing operations.
	The following table shows the carrying values of the major classes of assets and liabilities related to UPPCO:
			As of the Closing Date				Held for Sale at
	(Millions)		in August 2014				31-Dec-13
	Current assets		$	24.3			$	26.5
	Property, plant, and equipment, net of accumulated depreciation of $91.3 and $88.9, respectively		194.4				193.8
	Other long-term assets		72.8				51.6
	Total assets		$	291.5			$	271.9
	Current liabilities		$	12.7			$	16.7
	Long-term liabilities		28.6				32.4
	Total liabilities		$	41.3			$	49.1
	In addition to the amounts in the table above, intercompany payables of $1.6 million at December 31, 2013 related to certain power purchase transactions with WPS that continued after the sale were eliminated during consolidation. As of the closing date, these payables were included in the sale and disclosed in the table above as current liabilities.
	Holding Company and Other Segment – Winnebago Energy Center
	In May 2014, a fire significantly damaged the Winnebago Energy Center, a landfill-gas-to-electric facility that was owned by PDI. Due to uncertainty surrounding the amount of the insurance settlement, we were unable to determine if we would rebuild or abandon the Winnebago Energy Center in the second quarter of 2014. In the third quarter of 2014, we decided to abandon the facility and received proceeds of $6.1 million for both insurance recovery for the damage caused by the fire and from the sale of miscellaneous parts. As a result, we recorded a pre-tax gain of $5.0 million.
	In the third quarter of 2014, we early adopted the guidance in FASB ASU 2014-08, as stated previously. Based on this new guidance, the Winnebago Energy Center did not qualify as discontinued operations since it did not represent a shift in our strategy. Therefore, its results of operations prior to the fire remain in continuing operations.
	Discontinued Operations
	See Note 5, Cash and Cash Equivalents, for cash flow information related to discontinued operations.
	Holding Company and Other Segment – Potential Sale of Combined Locks Energy Center (Combined Locks)
	We are currently pursuing the sale of Combined Locks, a natural gas-fired co-generation facility located in Wisconsin. Combined Locks had $0.7 million of assets that were classified as held for sale on the balance sheets at December 31, 2014, and December 31, 2013, which included inventories and property, plant, and equipment. We recorded after-tax losses of $0.5 million, $1.3 million, and $0.6 million in 2014, 2013, and 2012, respectively, in discontinued operations related to Combined Locks.
	IES Segment – Sale of IES Retail Energy Business
	In November 2014, we sold IES's retail energy business to Exelon Generation Company, LLC (Exelon) for $333.0 million. The purchase price is subject to adjustments for working capital. We recorded a pre-tax loss on the sale of $28.8 million ($17.3 million after tax), which included transaction costs of $4.5 million in 2014. Included in these costs is an immaterial amount related to severances. As part of the purchase agreement, we will continue to hold certain guarantees supporting the IES retail energy business for up to six months following the sale. Exelon is obligated under the purchase agreement to replace these guarantees with its own credit support for the IES retail energy business. See Note 22, Guarantees, for more information. Following the sale, we are providing certain administrative and operational services to Exelon during a transition period of up to 15 months.
	The retail energy business consisted of mostly financial assets and liabilities; therefore, it did not qualify as held for sale under the applicable accounting guidance. In the third quarter of 2014, we early adopted the guidance in FASB ASU 2014-08, as stated previously. The sale of the retail energy business is a result of a previously announced shift in our strategy to focus on our regulated businesses. Therefore, its results of operations were classified as discontinued operations beginning in the fourth quarter of 2014.
	The following table shows the carrying values of the major classes of assets and liabilities included in the sale:
			As of the Closing Date in
	(Millions)		Nov-14				31-Dec-13
	Cash and cash equivalents		$	7.6			$	5.5
	Accounts receivable and accrued unbilled revenues, net of reserves of $1.8 and $1.7, respectively		293.8				390.9
	Inventories		52.4				34.2
	Current assets from risk management activities		234.8				229.5
	Prepaid taxes		—				2.5
	Other current assets		75.1				41.5
	Property, plant, and equipment, net of accumulated depreciation of $16.6 and $15.6, respectively		4.5				5.2
	Long-term assets from risk management activities		106.9				73.4
	Goodwill		—				6.7
	Other long-term assets		25.5				26
	Total assets		$	800.6			$	815.4
	Accounts payable		$	186.9			$	202.9
	Current liabilities from risk management activities		169.7				160.6
	Accrued taxes		0.2				2
	Other current liabilities		6.7				13.1
	Long-term liabilities from risk management activities		79.5				61.9
	Other long-term liabilities		0.3				7
	Total liabilities		$	443.3			$	447.5
	Included in the sale were commodity contracts that did not meet the GAAP definition of derivative instruments and, therefore, were not reflected on the balance sheets. In accordance with GAAP, expected gains or losses related to nonderivative commodity contracts are not recognized until the contracts are settled.
	The following table shows the components of discontinued operations related to the sale of the IES retail energy business recorded on the income statements:
	(Millions)		2014				2013				2012
	Revenues		$	2,587.10			$	2,150.90			$	1,201.00
	Cost of sales		(2,444.7		)		(1,910.7		)		(1,018.9		)
	Operating and maintenance expense		(91.5		)		(105.6		)		(88.3		)
	Depreciation and amortization expense		(2.7		)		(3.2		)		(3.4		)
	Taxes other than income taxes		(4.9		)		(3.2		)		(2.4		)
	Goodwill impairment loss		(6.7		)		—				—
	Loss on sale of IES retail energy business		(28.8		)		—				—
	Miscellaneous income		0.6				7.9				0.3
	Interest expense		(0.7		)		(0.8		)		(1.3		)
	Income before taxes		7.7				135.3				87
Provision for income taxes *		(7.3		)		(52.8		)		(31.9		)
Discontinued operations, net of tax		$	0.4			$	82.5			$	55.1
*	See Note 16, Income Taxes, for more information.
The June 2014 announcement of the potential sale triggered an interim goodwill impairment test. Based on the results of the interim goodwill impairment analysis, IES recorded a non-cash goodwill impairment loss in the second quarter of 2014. This goodwill impairment loss reflected the offers received for IES's retail energy business.
Holding Company and Other Segment – Sale of WPS Beaver Falls Generation, LLC (Beaver Falls) and WPS Syracuse Generation, LLC (Syracuse)
In March 2013, WPS Empire State, Inc. sold all of the membership interests of Beaver Falls and Syracuse, both of which owned natural gas-fired generation plants located in the state of New York. We recorded a pre-tax impairment loss of $1.1 million ($0.7 million after tax) related to Beaver Falls and Syracuse during 2012 when the assets and liabilities were classified as held for sale. This impairment loss is reflected in operating and maintenance expense in the table below. The sale agreement included a potential annual payment to us for a four-year period following the sale based on a certain level of earnings achieved by the buyer (an earn-out). In September 2014, we entered into an agreement to receive $2.0 million in settlement of this earn-out agreement, which is presented in operating and maintenance expense in the table below.
The following table shows the components of discontinued operations related to Beaver Falls and Syracuse recorded on the income statements:
(Millions)		2014				2013				2012
Revenues		$	—			$	1.2			$	0.6
Cost of sales		—				(0.9		)		(2.0		)
Operating and maintenance expense		2				0.4			*	(3.5		)
Depreciation and amortization expense		—				—				(0.6		)
Taxes other than income taxes		—				(0.3		)		(1.4		)
Miscellaneous income		—				—				0.3
Income (loss) before taxes		2				0.4				(6.6		)
(Provision) benefit for income taxes		(0.8		)		(0.2		)		2.6
Discontinued operations, net of tax		$	1.2			$	0.2			$	(4.0	)
*	Includes a $1.0 million gain on sale at closing.
Holding Company and Other Segment – Uncertain Tax Positions
In 2014, we recorded a $0.7 million after-tax gain at the holding company and other segment when we remeasured an uncertain tax position included in our liability for unrecognized tax benefits due to a lapse in the statute of limitations. During 2013 and 2012, we recorded a $5.9 million after-tax gain and a $1.8 million after-tax gain, respectively, in discontinued operations at the holding company and other segment. We remeasured uncertain tax positions included in our liability for unrecognized tax benefits after effectively settling certain state income tax examinations. We reduced the provision for income taxes related to these remeasurements.
Holding Company and Other Segment – Sale of WPS Westwood Generation, LLC (Westwood)
In November 2012, Sunbury Holdings, LLC, a subsidiary of IES, sold all of the membership interests of Westwood, a waste coal generation plant located in Pennsylvania. We recorded a pre-tax impairment loss of $8.4 million ($5.0 million after tax) related to Westwood during the third quarter of 2012 when the assets and liabilities were classified as held for sale. This impairment loss is reflected in operating and maintenance expense in the table below.
The following table shows the components of discontinued operations related to Westwood recorded on the income statements:
(Millions)		2012
Revenues		$	9.2
Cost of sales		(4.4		)
Operating and maintenance expense		(14.3		)	*
Depreciation and amortization expense		(1.0		)
Taxes other than income taxes		(0.2		)
Interest expense		(0.7		)
Loss before taxes		(11.4		)
Benefit for income taxes		4.5
Discontinued operations, net of tax		$	(6.9	)
*	Includes a $0.6 million loss on sale at closing.

CASH_AND_CASH_EQUIVALENTS

CASH AND CASH EQUIVALENTS	12 Months Ended
	Dec. 31, 2014
Cash and Cash Equivalents [Abstract]
CASH AND CASH EQUIVALENTS	Cash and Cash Equivalents
	Continuing Operations
	Significant noncash transactions related to continuing operations were:
	(Millions)		2014			2013			2012
	Construction costs funded through accounts payable		$	180.5		$	108.5		$	92.4
	Accounts receivable converted to notes receivable related to sales of ITF fueling stations constructed on behalf of others		10.9			—			—
	Portion of ITF fueling station sale financed with note receivable *		2.7			—			—
	Equity interest in joint venture received for a portion of the ITF fueling station sale *		3.1			—			—
	Equity issued for employee stock ownership plan		1.7			14.3			—
	Equity issued for stock-based compensation plans		—			16.3			—
	Equity issued for reinvested dividends		—			12			—
	*	See Note 4, Dispositions, for more information.
	At December 31, 2014, restricted cash of $31.3 million was recorded within other long-term assets on our balance sheet. This amount was held in the rabbi trust and was a portion of the required funding for the rabbit trust that was triggered by the announcement of the proposed merger with Wisconsin Energy Corporation. See Note 2, Proposed Merger with Wisconsin Energy Corporation, for more information about the proposed merger. See Note 18, Employee Benefit Plans, for more information on the rabbi trust funding requirements.
	Discontinued Operations
	Following our early adoption of FASB ASU 2014-08, "Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity," we changed the presentation of our cash flow statement and no longer present cash flows related to discontinued operations separately. Significant noncash transactions and other information related to discontinued operations are disclosed below.
	(Millions)		2014			2013			2012
	Operating Activities
	Depreciation and amortization expense		$	2.7		$	3.3		$	5.3
	Net unrealized gains on energy contracts		(22.7		)	(100.3		)	(34.5		)
	Deferred income taxes and investment tax credits		36.1			56.1			(0.4		)
	Remeasurement of uncertain tax positions included in our liability for unrecognized tax benefits		(0.7		)	(5.9		)	(1.8		)
	Loss on sale of IES's retail energy business *		24.3			—			—
	Other		33.4			23.8			21.7
	Investing Activities
	Capital expenditures		(0.8		)	(2.6		)	(2.0		)
	Contingent consideration and payables related to the acquisition of Compass Energy Services		—			7.8			—
	Portion of Westwood sale financed with note receivable *		—			—			4
	*	See Note 4, Dispositions, for more information.
	See Note 1(x), New Accounting Pronouncements, for more information about the adoption of FASB ASU 2014-08.

RISK_MANAGEMENT_ACTIVITIES

RISK MANAGEMENT ACTIVITIES	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
RISK MANAGEMENT ACTIVITIES	Risk Management Activities
	The following tables show our assets and liabilities from risk management activities at the utilities and IBS:
				31-Dec-14
	(Millions)	Balance Sheet Presentation		Assets from				Liabilities from
				Risk Management Activities				Risk Management Activities
	Nonhedge derivatives
	Natural gas contracts	Other current		$	1.8			$	37.3
	Natural gas contracts	Other long-term		0.5				5.3
	Financial transmission rights (FTRs)	Other current		2.2				0.3
	Petroleum product contracts	Other current		—				2.7
	Petroleum product contracts	Other long-term		—				0.1
	Coal contracts	Other current		—				2.4
	Coal contracts	Other long-term		—				1
		Other current		4				42.7
		Other long-term		0.5				6.4
	Total			$	4.5			$	49.1
				December 31, 2013
	(Millions)	Balance Sheet Presentation		Assets from				Liabilities from
				Risk Management Activities				Risk Management Activities
	Nonhedge derivatives
	Natural gas contracts	Other current		$	8.3			$	1
	Natural gas contracts	Other long-term		1.8				0.1
	FTRs	Other current		1.5				0.3
	Petroleum product contracts	Other current		0.1				—
	Coal contracts	Other current		—				1.9
	Coal contracts	Other long-term		0.2				0.8
		Other current		9.9				3.2
		Other long-term		2				0.9
	Total			$	11.9			$	4.1
	The following tables show the potential effect on our financial position of netting arrangements for recognized derivative assets and liabilities:
		31-Dec-14
	(Millions)	Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
	Derivative assets subject to master netting or similar arrangements	$	3.2			$	1.3			$	1.9
	Derivative assets not subject to master netting or similar arrangements	1.3								1.3
	Total risk management assets	$	4.5							$	3.2
	Derivative liabilities subject to master netting or similar arrangements	$	45.7			$	8.8			$	36.9
	Derivative liabilities not subject to master netting or similar arrangements	3.4								3.4
	Total risk management liabilities	$	49.1							$	40.3
		31-Dec-13
	(Millions)	Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
	Derivative assets subject to master netting or similar arrangements	$	11.7			$	2.1			$	9.6
	Derivative assets not subject to master netting or similar arrangements	0.2								0.2
	Total risk management assets	11.9								9.8
	Derivative liabilities subject to master netting or similar arrangements	$	1.4			$	1.4			$	—
	Derivative liabilities not subject to master netting or similar arrangements	2.7								2.7
	Total risk management liabilities	$	4.1							$	2.7
	Our master netting and similar arrangements have conditional rights of setoff that can be enforced under a variety of situations, including counterparty default or credit rating downgrade below investment grade. We have trade receivables and trade payables, subject to master netting or similar arrangements, that are not included in the above table. These amounts may offset (or conditionally offset) the net amounts presented in the above table.
	Financial collateral received or provided is restricted to the extent that it is required per the terms of the related agreements. The following table shows our cash collateral positions:
	(Millions)	31-Dec-14				31-Dec-13
	Cash collateral provided to others:
	Related to contracts under master netting or similar arrangements	$	11.6			$	3.6
	Other	1.1				1.1
	Cash collateral received from others related to contracts under master netting or similar arrangements	—				0.7
	Certain of our derivative and nonderivative commodity instruments contain provisions that could require "adequate assurance" in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a liability position at December 31, 2014, and 2013, was $31.3 million, and $0.6 million, respectively. At December 31, 2014, and 2013, we had not posted any cash collateral related to the credit risk-related contingent features of these commodity instruments. If all of the credit risk-related contingent features contained in commodity instruments (including derivatives, nonderivatives, normal purchase and normal sales contracts, and applicable payables and receivables) had been triggered at December 31, 2014, we would have been required to post collateral of $27.1 million. If all of the credit risk-related contingent features contained in commodity instruments had been triggered at December 31, 2013, we would not have been required to post collateral.
	Utility Segments
	Non-Hedge Derivatives
	Utility derivatives include natural gas purchase contracts, coal purchase contracts, financial derivative contracts, and FTRs. The electric utility segment uses FTRs to manage electric transmission congestion costs. The natural gas and electric utility segments use financial derivative contracts to manage the risks associated with the market price volatility of natural gas supply costs. In addition, IBS enters into financial derivative contracts on behalf of the utilities to manage the cost of gasoline and diesel fuel used by utility vehicles.
	The notional volumes of outstanding derivative contracts at the utilities and IBS were as follows:
		31-Dec-14									31-Dec-13
	(Millions)	Purchases			Sales			Other Transactions			Purchases			Sales	Other Transactions
	Natural gas (therms)	1,860.00			—			N/A			3,124.80			29.3	N/A
	FTRs (kilowatt-hours)	N/A			N/A			4,287.70			N/A			N/A	3,427.00
	Petroleum products (barrels)	0.1			—			N/A			0.1			—	N/A
	Coal (tons)	3			—			N/A			4.8			—	N/A
The table below shows the unrealized gains (losses) recorded related to derivative contracts at the utilities and IBS:
(Millions)	Financial Statement Presentation		2014				2013				2012
Natural gas	Balance Sheet — Regulatory assets (current)		$	(38.0	)		$	13.4			$	24.6
Natural gas	Balance Sheet — Regulatory assets (long-term)		(5.2		)		2.3				8.3
Natural gas	Balance Sheet — Regulatory liabilities (current)		(3.9		)		4.6				(7.8		)
Natural gas	Balance Sheet — Regulatory liabilities (long-term)		(0.6		)		0.3				0.3
Natural gas	Income Statement — Cost of sales		—				—				0.2
Natural gas	Income Statement — Operating and maintenance expense		(0.8		)		0.1				—
FTRs	Balance Sheet — Regulatory assets (current)		—				0.2				(0.1		)
FTRs	Balance Sheet — Regulatory liabilities (current)		0.4				(0.3		)		—
Petroleum	Balance Sheet — Regulatory assets (current)		(1.1		)		—				0.1
Petroleum	Balance Sheet — Regulatory liabilities (current)		(0.1		)		0.1				—
Petroleum	Income Statement — Operating and maintenance expense		(1.7		)		0.1				—
Coal	Balance Sheet — Regulatory assets (current)		(1.3		)		(0.9		)		(2.2		)
Coal	Balance Sheet — Regulatory assets (long-term)		—				3.5				0.1
Coal	Balance Sheet — Regulatory liabilities (current)		(0.2		)		(0.2		)		0.3
Coal	Balance Sheet — Regulatory liabilities (long-term)		(0.1		)		(2.0		)		2.2
Holding Company and Other Segment
Cash Flow Hedges
In May 2010, we entered into interest rate swaps that were designated as cash flow hedges to hedge the variability in forecasted interest payments on a debt issuance. These swaps were terminated when the related debt was issued in November 2010. Amounts remaining in accumulated OCI were being reclassified to interest expense over the life of the related debt.
	Loss Reclassified from Accumulated OCI into Income (Effective Portion)
(Millions)	Income Statement Presentation		2014				2013				2012
Settled/Realized
Interest rate swaps	Interest expense		$	(1.1	)		$	(1.1	)		$	(1.1	)

PROPERTY_PLANT_AND_EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT, AND EQUIPMENT	Property, Plant, and Equipment
	Property, plant, and equipment consisted of the following utility, nonutility, and nonregulated assets at December 31:
	(Millions)		2014		2013
	Electric utility		$	3,587.40	$	3,289.20
	Natural gas utility		5,811.80		5,428.50
	Total utility property, plant, and equipment		9,399.20		8,717.70
	Less: Accumulated depreciation		3,185.90		3,073.20
	Net		6,213.30		5,644.50
	Construction work in progress		351.8		351.5
	Plant to be retired, net *		12.5		14.4
	Net utility property, plant, and equipment		6,577.60		6,010.40
	Nonutility plant		144.6		131.1
	Less: Accumulated depreciation		81.1		80.4
	Net		63.5		50.7
	Construction work in progress		73.9		38
	Net nonutility property, plant, and equipment		137.4		88.7
	PDI energy assets		140.2		109.8
	Other nonregulated		33.7		20.7
	Total nonregulated property, plant, and equipment		173.9		130.5
	Less: Accumulated depreciation		39.5		30.5
	Net		134.4		100
	Construction work in progress		10.4		7.1
	Net nonregulated property, plant, and equipment		144.8		107.1
	Total property, plant, and equipment		$	6,859.80	$	6,206.20
	*	In connection with the WPS Consent Decree with the EPA, WPS announced that the Weston 1, Pulliam 5, and Pulliam 6 generating units will be retired early. These units are currently included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. The amount presented above is net of accumulated depreciation. See Note 17, Commitments and Contingencies, for more information regarding the Consent Decree.
	We evaluate property, plant, and equipment for impairment whenever indicators of impairment exist. See Note 4, Dispositions, for impairment losses recorded in discontinued operations at the holding company and other segment during 2012. The impairments were recorded on property and equipment either sold during 2012 or presented on the balance sheet as assets held for sale.

JOINTLY_OWNED_UTILITY_FACILITI

JOINTLY OWNED UTILITY FACILITIES	12 Months Ended
	Dec. 31, 2014
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]
JOINTLY OWNED UTILITY FACILITIES	Jointly Owned Utility Facilities
	WPS holds a joint ownership interest in certain electric generating facilities. WPS is entitled to its share of generating capability and output of each facility equal to its respective ownership interest. WPS also pays its ownership share of additional construction costs, fuel inventory purchases, and operating expenses, unless specific agreements have been executed to limit its maximum exposure to additional costs. WPS records its proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. The amounts were as follows at December 31, 2014:
	(Millions, except for percentages and megawatts)	Weston 4			Columbia Energy Center			Edgewater Unit 4
					Units 1 and 2
	Ownership	70		%	31.8		%	31.8		%
	WPS's share of rated capacity (megawatts)	374.5			335.2			105
	In-service date	2008			1975 and 1978			1969
	Utility plant	$	581.9		$	390.7		$	42.9
	Accumulated depreciation	$	(132.6	)	$	(116.2	)	$	(29.6	)
	Construction work in progress	$	2.7		$	10.1		$	0.7
	WPS's proportionate share of direct expenses for the joint operation of these plants is recorded in operating expenses in the income statements. WPS has supplied its own financing for all jointly owned projects.

REGULATORY_ASSETS_AND_LIABILIT

REGULATORY ASSETS AND LIABILITIES	12 Months Ended
	Dec. 31, 2014
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:
	(Millions)		2014		2013		See Note
	Regulatory assets (1) (2)
	Environmental remediation costs (net of insurance recoveries) (3)		$	635.8	$	652.1	17
	Unrecognized pension and other postretirement benefit costs (4)		513.1		382.6		18
	Asset retirement obligations		109.4		89		15
	Merger and acquisition-related pension and other postretirement benefit costs (5)		86.6		98.3
	Income tax related items		60.6		55.3		16
	Derivatives		55.2		11.7		1(h)
	Termination of a tolling agreement with Fox Energy Company LLC		44.6		50		3
	Crane Creek production tax credits (6)		32.2		33.6
	Energy costs recoverable through rate adjustments (7)		22.2		17
	De Pere Energy Center (8)		21.4		23.8
	Unamortized loss on reacquired debt (9)		16.6		16.2		1(o)
	Uncollectible expense (10)		13.6		4.7
	Energy efficiency programs (11)		2.8		16.8
	Pension and other postretirement costs recoverable through rate adjustments (12)		—		9.4		25
	Decoupling		—		8.6		25
	Other		18.4		19.7
	Total regulatory assets		$	1,632.50	$	1,488.80
	Balance Sheet Presentation
	Current assets		$	118.9	$	127.4
	Long-term assets		1,513.60		1,361.40
	Total regulatory assets		$	1,632.50	$	1,488.80
	(1)	Based on prior and current rate treatment, we believe it is probable that our utility subsidiaries will continue to recover from customers the regulatory assets described above.
	(2)	The following regulatory assets are not earning a return: environmental remediation costs at WPS; unrecognized pension and other postretirement benefit costs at MERC, NSG, and PGL; asset retirement obligations, derivatives, and uncollectible expense at all utilities; merger and acquisition-related pension and other postretirement benefit costs at NSG and PGL; natural gas costs recoverable through rate adjustments at MERC and WPS; unamortized loss on reacquired debt at NSG and PGL; energy efficiency programs at WPS; pension and other postretirement costs recoverable through rate adjustments at WPS; and decoupling at MGU. However, these regulatory assets are expected to be recovered from customers in future rates.
	(3)	As of December 31, 2014, we had not yet made cash expenditures for $579.9 million of these environmental remediation costs. The recovery of these costs depends on the timing of the actual expenditures.
	(4)	Represents the unrecognized future pension and other postretirement costs resulting from actuarial gains and losses on defined benefit and other postretirement plans. We are authorized recovery of this regulatory asset over the average future remaining service life of each plan.
	(5)	Composed of unrecognized benefit costs that existed prior to the PELLC merger and the MERC and MGU acquisitions. MERC and MGU are authorized recovery of this regulatory asset through 2026. PGL and NSG are authorized recovery of the pension portion of this regulatory asset through 2023, and they are authorized recovery of the other postretirement benefit portion through 2019.
	(6)	In 2012, WPS 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, WPS reversed previously recorded production tax credits. WPS 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. WPS recorded a regulatory asset for the deferral of previously recorded production tax credits and is authorized recovery of this net regulatory asset through 2039.
	(7)	Represents the under-collection of energy costs that will be recovered from customers in the future.
	(8)	Prior to WPS purchasing the De Pere Energy Center in 2002, WPS 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. WPS is authorized recovery of this regulatory asset through 2023.
	(9)	Amounts are recovered over the term of the replacement debt for NSG and PGL as authorized by the ICC.
	(10)	Represents amounts recoverable from customers related to uncollectible expense. We are allowed to recover or refund the difference between the rate case authorized uncollectible expense and the actual uncollectible write-offs reported to the applicable commissions each year.
	(11)	Represents amounts recoverable from customers related to programs at the utility subsidiaries designed to meet energy efficiency standards.
	(12)	Represents the under-collection of pension and other postretirement costs that will be recovered from customers in the future.
	The following regulatory liabilities were reflected on our balance sheets as of December 31:
	(Millions)		2014		2013		See Note
	Regulatory liabilities
	Removal costs (1)		$	334	$	318
	Decoupling		49.4		51.5		25
	Unrecognized pension and other postretirement benefit costs (2)		45.2		30.2		18
	Energy costs refundable through rate adjustments (3)		44.8		27.1
	Energy efficiency programs (4)		21.3		19.6
	Derivatives		19.8		6.6		1(h)
	Uncollectible expense		15.7		10.1		25
	Crane Creek depreciation deferral (5)		8.7		9
	Fox Energy Center (6)		4.6		5.6		3
	Other		10.1		7.1
	Total regulatory liabilities		$	553.6	$	484.8
	Balance Sheet Presentation
	Current liabilities		$	153.7	$	101.1
	Long-term liabilities		399.9		383.7
	Total regulatory liabilities		$	553.6	$	484.8
	(1)	Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment.
	(2)	Represents the unrecognized future other postretirement benefit costs resulting from actuarial gains on other postretirement benefit plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan.
	(3)	Represents the over-collection of energy costs that will be refunded to customers in the future.
	(4)	Represents amounts refundable to customers related to programs at the utility subsidiaries designed to meet energy efficiency standards.
	(5)	Represents the book depreciation taken on the Crane Creek wind project prior to WPS's 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.
	(6)	Represents the deferral of incremental costs associated with WPS owning and operating the Fox Energy Center, which was purchased in March 2013. In accordance with GAAP, the deferral does not include an allowance for return on equity, which has created the net regulatory liability. This allowance was $22.8 million and $22.1 million, at December 31, 2014, and 2013, respectively.

EQUITY_METHOD_INVESTMENTS

EQUITY METHOD INVESTMENTS	12 Months Ended
	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
EQUITY METHOD INVESTMENTS	Equity Method Investments
	Investments in corporate joint ventures and other companies accounted for under the equity method at December 31, 2014, and 2013, were as follows:
	(Millions)	2014		2013
	ATC	$	536.7	$	508.4
	INDU Solar Holdings, LLC	21.8		24.7
	WRPC	7.7		7
	AMP Trillium, LLC	5.5		—
	Other	0.7		0.8
	Equity method investments	$	572.4	$	540.9
	ATC
	Our electric transmission investment segment consists of WPS Investments LLC’s ownership interest in ATC, which was approximately 34% at December 31, 2014. ATC is a for-profit, transmission-only company regulated by FERC.
	The following table shows changes to our investment in ATC during the years ended December 31:
	(Millions)	2014		2013		2012
	Balance at the beginning of period	$	508.4	$	476.6	$	439.4
	Add: Earnings from equity method investment	85.7		89.1		85.3
	Add: Capital contributions	17		13.7		20.4
	Less: Dividends received	74.4		71		68.5
	Balance at the end of period	$	536.7	$	508.4	$	476.6
	ATC is currently named in a complaint filed with the FERC requesting a reduction in the base return on equity (ROE) used by MISO transmission owners to 9.15%. ATC's current authorized ROE is 12.2%. Although we are currently unable to determine how the FERC may rule in this complaint, we believe it is probable that a refund will be required upon resolution of this issue, based on rulings in a similar complaint. As a result, our equity earnings and corresponding equity method investment in ATC reflected an estimated $6.6 million reduction during 2014.
	The electric utilities provide construction and other services to ATC and receive network transmission services from ATC. The related party transactions recorded by the electric utilities during the years ended December 31 were as follows:
	(Millions)	2014		2013		2012
	Total charges to ATC for services and construction	$	9.9	$	11.3	$	12.5
	Total costs for network transmission services provided by ATC	103.8		104.9		100.3
	INDU Solar Holdings, LLC
	Integrys Solar, LLC, a subsidiary of PDI, owns 50% of INDU Solar Holdings, LLC. INDU Solar Holdings, LLC owns solar energy projects in California, Pennsylvania, New Jersey, Arizona, and Massachusetts that deliver electricity and related products to commercial, government, and utility customers under long-term power purchase agreements.
	The following table shows changes to our investment in INDU Solar Holdings, LLC during the years ended December 31:
	(Millions)	2014		2013		2012
	Balance at the beginning of period	$	24.7	$	27.5	$	28.4
	Add: Earnings from equity method investment	1.8		1.3		1.1
	Add: Capital contributions	—		—		7
	Less: Return of capital to partners	4.7		4.1		9
	Balance at the end of period	$	21.8	$	24.7	$	27.5
	WRPC
	WPS owns 50% of the stock of WRPC, which owns two hydroelectric plants and an oil-fired combustion turbine. Half of the energy output of the hydroelectric plants is sold to WPS, and half is sold to Wisconsin Power and Light. The electric power from the combustion turbine is also sold in equal parts to WPS and Wisconsin Power and Light.
	The following table shows changes to our investment in WRPC during the years ended December 31:
	(Millions)	2014		2013		2012
	Balance at the beginning of period	$	7	$	7.3	$	7.7
	Add: Earnings from equity method investment	0.8		1		0.8
	Add: Capital contributions	0.5		—		—
	Less: Dividends received	0.6		1.3		1.2
	Balance at the end of period	$	7.7	$	7	$	7.3
	WPS provides services to WRPC, purchases energy from WRPC, and receives net proceeds from sales of energy into the MISO market from WRPC. The related party transactions recorded by WPS during the years ended December 31 were as follows:
	(Millions)	2014		2013		2012
	Charges to WRPC for operations	$	1.4	$	0.9	$	0.8
	Purchases of energy from WRPC	3.7		3.7		5
	Net proceeds from WRPC sales of energy to MISO	—		—		2.9
	AMP Trillium, LLC
	AMP Trillium, LLC is a joint venture between ITF and AMP Americas, LLC. ITF owns 30% and AMP Americas, LLC owns 70% of this joint venture. AMP Trillium, LLC owns and operates compressed natural gas (CNG) fueling stations. In April 2014, ITF and AMP Americas, LLC restructured this joint venture. Prior to the restructuring, we consolidated AMP Trillium, LLC. However, due to the restructuring, we started accounting for AMP Trillium, LLC as an equity method investment in April 2014. See Note 27, Variable Interest Entities, for more information.
	The following table shows changes to our investment in AMP Trillium, LLC during the year ended December 31:
	(Millions)	2014
	Balance at the beginning of period	$	—
	Add: Capital contributions	5.5
	Balance at the end of period	$	5.5
	ITF sells CNG fueling stations to AMP Trillium, LLC and provides financial support to AMP Trillium, LLC through loans. At December 31, 2014, ITF had $13.8 million of notes receivable due from AMP Trillium, LLC. During 2014, ITF recorded $3.1 million of net proceeds from the sale of CNG fueling stations to AMP Trillium, LLC.
	Financial Data
	Combined financial data of our significant equity method investments, ATC, INDU Solar Holdings, LLC, WRPC, and AMP Trillium, LLC, are included in the tables below:
	(Millions)	2014		2013		2012
	Income statement data
	Revenues	$	655.6	$	642	$	618.3
	Operating expenses	323.5		306.2		292.1
	Other expense	88.4		83.7		85.1
	Net income	$	243.7	$	252.1	$	241.1
	Earnings from equity method investments	$	88.3	$	91.4	$	87.2
	(Millions)	31-Dec-14		31-Dec-13
Balance sheet data
Current assets	$	80.7	$	90.2
Noncurrent assets	3,835.90		3,587.20
Total assets	$	3,916.60	$	3,677.40
Current liabilities	$	324	$	383.6
Long-term debt	1,721.60		1,559.10
Other noncurrent liabilities	173.2		134.4
Shareholders’ equity	1,697.80		1,600.30
Total liabilities and shareholders’ equity	$	3,916.60	$	3,677.40

GOODWILL_AND_OTHER_INTANGIBLE_

GOODWILL AND OTHER INTANGIBLE ASSETS	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL AND OTHER INTANGIBLE ASSETS	Goodwill and Other Intangible Assets
	The following table shows changes to our goodwill balances by segment during the years ended December 31, 2014, and 2013:
			Natural Gas Utility						Holding Company and Other				Total
	(Millions)		2014			2013			2014		2013		2014			2013
	Balance as of January 1
	Gross goodwill		$	933.5		$	933.5		$	19.6	$	15.8	$	953.1		$	949.3
	Accumulated impairment losses		(297.7		)	(297.7		)	—		—		(297.7		)	(297.7		)
	Net goodwill as of January 1		635.8			635.8			19.6		15.8		655.4			651.6
	Adjustment to ITF intellectual property *		—			—			—		3.8		—			3.8
	Balance as of December 31
	Gross goodwill		933.5			933.5			19.6		19.6		953.1			953.1
	Accumulated impairment losses		(297.7		)	(297.7		)	—		—		(297.7		)	(297.7		)
	Net goodwill as of December 31		$	635.8		$	635.8		$	19.6	$	19.6	$	655.4		$	655.4
	*	An immaterial adjustment was made to the gross goodwill balance at ITF in the second quarter of 2013 due to a correction to the life of certain intangible assets.
	In the second quarter of 2014, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of April 1, 2014. No impairments resulted from these tests.
	The identifiable intangible assets other than goodwill listed below are part of other long-term assets on the balance sheets.
			31-Dec-14								31-Dec-13
	(Millions)		Gross Carrying			Accumulated			Net Carrying		Gross Carrying		Accumulated			Net Carrying
			Amount			Amortization			Amount		Amount		Amortization			Amount
	Amortized intangible assets
	Contractual service agreements (1)		$	15.6		$	(4.3	)	$	11.3	$	15.6	$	(1.8	)	$	13.8
	Customer-owned equipment modifications (2)		4			(1.2		)	2.8		4		(0.9		)	3.1
	Intellectual property (3)		3.4			(0.8		)	2.6		3.4		(0.5		)	2.9
	Nonregulated easements (4)		3.9			(1.4		)	2.5		3.7		(1.1		)	2.6
	Compressed natural gas fueling contract assets (5)		5.6			(3.6		)	2		5.6		(2.7		)	2.9
	Customer-related (6)		1.9			(0.3		)	1.6		1.9		(0.1		)	1.8
	Other		0.5			(0.3		)	0.2		0.5		(0.3		)	0.2
	Total		$	34.9		$	(11.9	)	$	23	$	34.7	$	(7.4	)	$	27.3
	Unamortized intangible assets
	MGU trade name		$	5.2		$	—		$	5.2	$	5.2	$	—		$	5.2
	Trillium trade name (7)		3.5			—			3.5		3.5		—			3.5
	Pinnacle trade name (7)		1.5			—			1.5		1.5		—			1.5
	Total intangible assets		$	45.1		$	(11.9	)	$	33.2	$	44.9	$	(7.4	)	$	37.5
	(1)	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. In October 2014, WPS received approval from the PSCW to upgrade the combustion turbine generators at the Fox Energy Center earlier than planned. As a result of this approval, WPS shortened the amortization period of one of its service agreements. The remaining weighted-average amortization period for these intangible assets at December 31, 2014, was approximately four years. Since WPS has approval from the PSCW to recover the value of its service agreements from customers over seven years, the increase in amortization due to the shorter amortization period is recorded to a regulatory asset. This regulatory asset will be amortized to reflect the seven-year recovery period.
	(2)	Relates to modifications made by PDI and ITF to customer-owned equipment. These intangible assets are amortized on a straight-line basis, with a remaining weighted-average amortization period at December 31, 2014, of approximately nine years.
	(3)	Represents the fair value of intellectual property at ITF related to a system for more efficiently compressing natural gas to allow for faster fueling. An immaterial adjustment was made to the intangible assets balance in the second quarter of 2013 as a result of a correction to the life of the intangible assets. The remaining amortization period at December 31, 2014, was approximately eight years.
	(4)	Relates to easements supporting a pipeline at PDI. The easements are amortized on a straight-line basis, with a remaining amortization period at December 31, 2014, of approximately nine years.
	(5)	Represents the fair value of ITF contracts acquired in September 2011. The remaining amortization period at December 31, 2014, was approximately six years.
	(6)	Represents customer relationship assets associated with ITF's compressed natural gas fueling operations. The remaining weighted-average amortization period for customer-related intangible assets at December 31, 2014, was approximately 12 years.
	(7)	Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle) are wholly owned subsidiaries of ITF.
	The table below shows the amortization recorded during the years ended December 31:
	(Millions)		2014			2013			2012
	Amortization recorded in cost of sales		$	1.2		$	1.6		$	1.3
	Amortization recorded in depreciation and amortization expense		3			2.5			1
	Amortization recorded in regulatory assets		0.3			—			—
	Amortization for the next five years is estimated to be:
			For the Year Ending December 31
	(Millions)		2015			2016			2017		2018		2019
	Amortization to be recorded in cost of sales		$	1.1		$	0.9		$	0.9	$	0.8	$	0.6
	Amortization to be recorded in depreciation and amortization expense		3			2.9			2.4		1.9		1.9
	Amortization to be recorded in regulatory assets		1			1			0.5		—		—

LEASES

LEASES	12 Months Ended
	Dec. 31, 2014
Leases [Abstract]
LEASES	Leases
	We lease various property, plant, and equipment. Terms of the operating leases vary, but 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 $14.7 million, $11.2 million, and $11.0 million in 2014, 2013, and 2012, respectively. Future minimum rental obligations under noncancelable operating leases are payable as follows:
	Year Ending December 31	Payments
	(Millions)
	2015	$	4.7
	2016	5
	2017	5.8
	2018	5.6
	2019	4.7
	Later years	47.6
	Total	$	73.4

SHORTTERM_DEBT_AND_LINES_OF_CR

SHORT-TERM DEBT AND LINES OF CREDIT	12 Months Ended
	Dec. 31, 2014
Short-term Debt [Abstract]
SHORT-TERM DEBT AND LINES OF CREDIT	Short-Term Debt and Lines of Credit
	Our outstanding short-term borrowings were as follows:
	(Millions, except percentages)		2014				2013				2012
	Commercial paper
	Amount outstanding at December 31 (1)		$	317.6			$	326			$	482.4
	Average interest rate on amount outstanding at December 31		0.36%				0.22		%		0.4		%
	Average amount outstanding during the year (2)		$	283			$	378.4			$	326.3
	Short-term notes payable (3)
	Average amount outstanding during the year (2)		$	—			$	130.4		(4)	$	—
	(1)	Maturity dates ranged from January 2, 2015, through January 16, 2015.
	(2)	Based on daily outstanding balances during the year.
	(3)	We did not have short-term notes payable outstanding at December 31, 2014, 2013, and 2012.
	(4)	Average amount outstanding of a $200.0 million loan used for the purchase of Fox Energy Company LLC. This loan was repaid in November 2013. See Note 3, Acquisitions, for more information regarding this purchase.
	We manage our liquidity by maintaining adequate external financing commitments. The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities as of December 31:
	(Millions)		Maturity		2014				2013
	Revolving credit facility (Integrys Energy Group) (1)		5/17/14		$	—			$	275
	Revolving credit facility (Integrys Energy Group) (1)		5/17/16		—				200
	Revolving credit facility (Integrys Energy Group) (2)		6/13/17		285				635
	Revolving credit facility (Integrys Energy Group)		5/8/19		465				—
	Revolving credit facility (WPS) (1)		5/17/14		—				135
	Revolving credit facility (WPS) (3)		5/7/15		135				—
	Revolving credit facility (WPS)		6/13/17		115				115
	Revolving credit facility (PGL)		6/13/17		250				250
	Total short-term credit capacity				$	1,250.00			$	1,610.00
	Less:
	Letters of credit issued inside credit facilities				$	3.4			$	52.4
	Commercial paper outstanding				317.6				326
	Available capacity under existing agreements				$	929			$	1,231.60
	(1)	These credit facilities were terminated and replaced with new credit facilities in May 2014.
	(2)	This credit facility was reduced by $350 million during the fourth quarter of 2014 due to the sale of IES.
	(3)	We requested approval from the PSCW to extend this facility through May 8, 2019.
	Our revolving credit agreements and those of certain of our subsidiaries contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%, excluding non-recourse debt. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.

LONGTERM_DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
LONG-TERM DEBT	Long-Term Debt
						31-Dec
	(Millions)					2014			2013
	WPS First Mortgage Bonds (1)
		Series		Year Due
		7.125	%	2023		$	0.1		$	0.1
	WPS Senior Notes (1)
		Series		Year Due
		6.375	%	2015		125			125
		5.65	%	2017		125			125
		6.08	%	2028		50			50
		5.55	%	2036		125			125
		3.671	%	2042		300			300
		4.752	%	2044		450			450
	PGL First and Refunding Mortgage Bonds (2)
		Series		Year Due
		QQ, 4.875%		2038	Mandatory interest reset date on November 1, 2018	—			75
		RR, 4.30%		2035	Mandatory interest reset date on June 1, 2016	50			50
		TT, 8.00%		2018		5			5
		UU, 4.63%		2019		75			75
		VV, 3.90%		2030		50			50
		WW, 2.625%		2033	Mandatory interest reset date on August 1, 2015	50			50
		XX, 2.21%		2016		50			50
		YY, 3.98%		2042		100			100
		ZZ, 4.00%		2033		50			50
		AAA, 3.96%		2043		220			220
		BBB, 4.21%		2044		200			—
	NSG First Mortgage Bonds (3)
		Series		Year Due
		P, 3.43%		2027		28			28
		Q, 3.96%		2043		54			54
	Integrys Energy Group Unsecured Senior Notes (4)
		Series		Year Due
		7.27	%	2014		—			100
		8	%	2016		55			55
		4.17	%	2020		250			250
	Integrys Energy Group Unsecured Junior Subordinated Notes (5)
		Series		Year Due
		6.11	%	2066	Interest to become variable on December 1, 2016	269.8			269.8
		6	%	2073	Mandatory interest reset date on August 1, 2023	400			400
	Total					3,081.90			3,056.90
	Unamortized discount on debt					(0.6		)	(0.7		)
	Total debt					3,081.30			3,056.20
	Less current portion					125			100
	Total long-term debt					$	2,956.30		$	2,956.20
	(1)	WPS's First Mortgage Bonds and Senior Notes are subject to the terms and conditions of WPS's First Mortgage Indenture dated January 1, 1941, as supplemented. Under the terms of the Indenture, substantially all property owned by WPS is pledged as collateral for these outstanding debt securities. All of these debt securities require semi-annual payments of interest. WPS Senior Notes become noncollateralized if WPS retires all of its outstanding First Mortgage Bonds and no new mortgage indenture is put in place.
	In December 2015, our 6.375% Senior Notes will mature. As a result, the $125 million balance of these notes was included in the current portion of long-term debt on our balance sheet at December 31, 2014.
	(2)	PGL's First Mortgage Bonds are subject to the terms and conditions of PGL's First Mortgage Indenture dated January 2, 1926, as supplemented. Under the terms of the Indenture, substantially all property owned by PGL is pledged as collateral for these outstanding debt securities.
	PGL has used certain First Mortgage Bonds to secure tax exempt interest rates. The Illinois Finance Authority has issued Tax Exempt Bonds, and the proceeds from the sale of these bonds were loaned to PGL. In return, PGL issued equal principal amounts of certain collateralized First Mortgage Bonds.
	In November 2014, PGL issued $200.0 million of 4.21% Series BBB Bonds. These bonds are due in November 2044. A portion of the proceeds was used to redeem PGL's $75.0 million 4.875% Series QQ Bonds.
	(3)	NSG's First Mortgage Bonds are subject to the terms and conditions of NSG's First Mortgage Indenture dated April 1, 1955, as supplemented. Under the terms of the Indenture, substantially all property owned by NSG is pledged as collateral for these outstanding debt securities.
	(4)	In June 2014, our $100.0 million of 7.27% Unsecured Senior Notes matured, and the outstanding principal balance was repaid.
	(5)	The 6.11% Junior Subordinated Notes are considered hybrid instruments with a combination of debt and equity characteristics. Under a replacement capital covenant with the holders of our 4.17% Unsecured Senior Notes due November 1, 2020, prior to December 1, 2036, any amounts redeemed or repurchased in excess of 10% of the principal amount outstanding must first be replaced with a specified amount of proceeds from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than, the applicable characteristics of the 6.11% Junior Subordinated Notes.
	The 6.00% Junior Subordinated Notes are considered hybrid instruments with a combination of debt and equity characteristics. There is no replacement capital covenant associated with these securities.
	Our long-term debt obligations, and those of certain of our subsidiaries, contain covenants related to payment of principal and interest when due and various financial reporting obligations. In addition, certain long-term debt obligations contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.
	A schedule of all principal debt payment amounts related to bond maturities is as follows:
	(Millions)		Payments
	2015		$	125
	2016		105
	2017		125
	2018		5
	2019		75
	Later years		2,646.90
	Total		$	3,081.90

ASSET_RETIREMENT_OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	Asset Retirement Obligations
	The utility segments have asset retirement obligations primarily related to removal of natural gas distribution mains and service pipes (including asbestos and PCBs); asbestos abatement at certain generation facilities, office buildings, and service centers; dismantling wind generation projects; disposal of PCB-contaminated transformers; closure of fly-ash landfills at certain generation facilities; and removal of above ground storage tanks. The utilities establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the asset retirement obligation accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators. PDI has asset retirement obligations related to the removal of solar equipment components.
	The following table shows changes to our asset retirement obligations through December 31, 2014:
	(Millions)		Utilities				PDI		Total
	Asset retirement obligations at December 31, 2011		$	395.8			$	0.5	$	396.3
	Accretion		20.3				0.1		20.4
	Additions and revisions to estimated cash flows		(2.3		)		1.6		(0.7		)
	Settlements		(5.4		)		—		(5.4		)
	Asset retirement obligations at December 31, 2012		408.4				2.2		410.6
	Accretion		20.8				0.1		20.9
	Additions and revisions to estimated cash flows		70.1			*	0.5		70.6
	Settlements		(11.1		)		—		(11.1		)
	Asset retirement obligations at December 31, 2013		488.2				2.8		491
	Accretion		24.5				0.1		24.6
	Additions and revisions to estimated cash flows		(18.3		)	*	0.7		(17.6		)
	Settlements		(17.8		)		—		(17.8		)
	Asset retirement obligations at December 31, 2014		$	476.6			$	3.6	$	480.2
	*	Revisions were made to estimated cash flows related to asset retirement obligations primarily due to changes in the weighted average cost to retire natural gas distribution pipe at PGL.

INCOME_TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
INCOME TAXES	Income Taxes
	Deferred Income Tax Assets and Liabilities
	The principal components of deferred income tax assets and liabilities recognized on the balance sheets as of December 31 are included in the table below. Certain temporary differences are netted in the table when the offsetting amount is recorded as a regulatory asset or liability. This is consistent with regulatory treatment.
	(Millions)		2014				2013
	Deferred income tax assets
	Tax credit carryforwards		$	116.7			$	113.5
	Price risk management		—				13
	Other		77.4				98.5
	Total deferred income tax assets		$	194.1			$	225
	Valuation allowance		(3.6		)		(8.2		)
	Net deferred income tax assets		$	190.5			$	216.8
	Deferred income tax liabilities
	Plant-related		$	1,584.10			$	1,373.80
	Regulatory deferrals		55.6				78.8
	Employee benefits		45.4				79.6
	Other		23				43.5
	Total deferred income tax liabilities		$	1,708.10			$	1,575.70
	Total net deferred income tax liabilities		$	1,517.60			$	1,358.90
	Balance sheet presentation
	Current deferred income tax assets		$	52.4			$	31.4
	Long-term deferred income tax liabilities		1,570.00				1,390.30
	Net deferred income tax liabilities		$	1,517.60			$	1,358.90
	Deferred tax credit carryforwards at December 31, 2014, included $73.9 million of alternative minimum tax credits, which can be carried forward indefinitely. Other deferred tax credit carryforwards included $32.5 million of general business credits, which have a carryback period of one year and a carryforward period of 20 years. The majority of the general business credit carryforwards will expire in 2034. Deferred tax credit carryforwards also included $6.2 million of foreign tax credits, which have a carryback period of one year and a carryforward period of 10 years. The majority of the foreign tax credit carryforwards will expire in 2019. We also had $4.2 million of deferred state tax credit carryforwards, which have a carryforward period of five years. The majority of the state tax credit carryforwards will expire in 2018.
	At December 31, 2014, we had deferred income tax assets of $27.0 million reflecting federal operating loss carryforwards, which have a carryback period of two years and a carryforward period of 20 years. We also had deferred income tax assets of $19.2 million reflecting net state operating loss carryforwards. The majority of the state operating loss carryforwards relate to Wisconsin and have a carryforward period of 20 years. Any deferred tax assets that are not used to offset future taxable income will expire between 2020 and 2033 as follows:
	(Millions)
	2020 through 2025		$	7.6
	2026 through 2031		2.9
	2032 through 2033		35.7
	Valuation allowances are established for certain state operating losses based on our projected ability to realize these benefits by offsetting future taxable income. Realization is dependent on generating sufficient taxable income prior to expiration. As of December 31, 2014, the entire valuation allowance was related to noncurrent deferred income tax assets. The valuation allowance was reduced by $4.6 million in 2014 due to a foreign tax deduction.
	Our utilities record certain adjustments related to deferred income taxes to regulatory assets and liabilities. As the related temporary differences reverse, the utilities prospectively refund taxes to, or collect taxes from, customers for which deferred taxes were recorded in prior years at rates potentially different than current rates or upon enactment of changes in tax law. The net regulatory asset for these net recoveries and other regulatory tax effects totaled $58.8 million and $51.6 million at December 31, 2014, and 2013, respectively. See Note 9, Regulatory Assets and Liabilities, for more information.
	Income Before Taxes
	All income before taxes is domestic income for the years ended December 31, 2014, 2013, and 2012.
	Provision for Income Taxes
	The components of the provision for income taxes were as follows:
	(Millions)		2014				2013				2012
	Current provision
	Federal		$	19.9			$	1.6			$	(17.4	)
	State		25.2				4.7				(1.7		)
	Total current provision		45.1				6.3				(19.1		)
	Deferred provision
	Federal		123				134.1				119.8
	State		18.7				9.9				17.9
	Total deferred provision		141.7				144				137.7
	Investment tax credits
	Deferral		13.2				12.3				17.8
	Amortization		(5.2		)		(4.0		)		(12.6		)
	Penalties		—				(0.1		)		(0.3		)
	Unrecognized tax benefits		0.7				0.4				(2.9		)
	Interest		(2.1		)		(0.9		)		(2.7		)
	Total provision for income taxes related to continuing operations		193.4				158				117.9
	Total provision for income taxes related to discontinued operations		7.2				45.9				22.6
	Total		$	200.6			$	203.9			$	140.5
	Statutory Rate Reconciliation
	The following table presents a reconciliation of the difference between the effective tax rate and the amount computed by applying the statutory federal tax rate to income from continuing operations before taxes.
			2014							2013						2012
	(Millions, except for percentages)		Rate			Amount				Rate			Amount			Rate		Amount
	Statutory federal income tax		35	%		$	165			35	%		$	148.9		35	%	$	124.9
	State income taxes, net		7.5		*	35.5			*	3.7			15.9			4.9		17.6
	Benefits and compensation		(0.9	)		(4.3		)		(1.0	)		(4.1		)	(2.6	)	(9.3		)
	Other differences, net		(0.6	)		(2.8		)		(0.6	)		(2.7		)	(4.3	)	(15.3		)
	Effective income tax		41	%		$	193.4			37.1	%		$	158		33	%	$	117.9
	*	Includes the impact of a $13.0 million expense caused by the remeasurement of deferred taxes related to the sale of IES's retail energy business.
	With the exception of 2014, income taxes on discontinued operations are recorded at rates that are not materially different from the applicable statutory rates. In 2014, the rate varied from the applicable statutory rates primarily because of the impairment of nondeductible goodwill related to IES's retail energy business.
	Unrecognized Tax Benefits
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
(Millions)		2014				2013				2012
Balance at January 1		$	3.6			$	11.3			$	22.4
Increase related to tax positions taken in prior years		—				2.2				0.9
Decrease related to tax positions taken in prior years		(0.1		)		(8.7		)		(6.7		)
Increase related to tax positions taken in current year		0.5				0.3				0.6
Decrease related to settlements		—				(1.5		)		(5.7		)
Decrease related to lapse of statutes		(0.7		)		—				(0.2		)
Balance at December 31		$	3.3			$	3.6			$	11.3
We had accrued interest of $0.3 million and accrued penalties of $0.2 million related to unrecognized tax benefits at December 31, 2014. We had accrued interest of $0.8 million and accrued penalties of $0.4 million related to unrecognized tax benefits at December 31, 2013.
Our effective tax rate could be affected by recognition of $2.2 million of unrecognized tax benefits related to continuing operations in periods after December 31, 2014.
Our subsidiaries file income tax returns in the United States federal jurisdiction, in various state and local jurisdictions, and in Canada.
With a few exceptions, we are no longer subject to federal income tax examinations by the IRS for years prior to 2011.
We file state tax returns based on income in our major state operating jurisdictions of Wisconsin, Illinois, Michigan, and Minnesota. We also file tax returns in other state and local jurisdictions with varying statutes of limitations. With a few exceptions, we are no longer subject to state and local tax examinations for years prior to 2008. As of December 31, 2014, we were subject to examination by state or local tax authorities for the 2008 through 2013 tax years in our major state operating jurisdictions as follows:
State		Year
Illinois		2008
Michigan		2008
Minnesota		2011
Wisconsin		2010
During 2014, the Michigan taxing authority continued its examination of the 2008 through 2011 tax years and the Illinois taxing authority initiated its examination of the 2008 through 2010 tax years.
As of December 31, 2014, we were subject to examination by foreign income tax authorities for the 2009 through 2013 tax years. With a few exceptions, we are no longer subject to foreign income tax examinations by tax authorities for years prior to 2009.
In the next 12 months, it is reasonably possible that we and our subsidiaries will settle open examinations in multiple taxing jurisdictions related to tax years prior to 2012, resulting in a decrease in unrecognized tax benefits of up to $1.3 million.

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	Commitments and Contingencies
	(a) Unconditional Purchase Obligations
	We and our subsidiaries routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. The natural gas utilities have obligations to distribute and sell natural gas to their customers, and our electric utility has obligations to distribute and sell electricity to its customers. The utilities expect to recover costs related to these obligations in future customer rates.
	The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2014, including those of our subsidiaries.
						Payments Due By Period
	(Millions)		Date Contracts Extend Through	Total Amounts Committed		2015		2016		2017		2018		2019		Later Years
	Natural gas utility supply and transportation		2028	$	722.6	$	196.6	$	170.4	$	132.9	$	78.2	$	50.9	$	93.6
	Electric utility
	Purchased power		2029	836.8		122.8		42.8		53.3		55.9		57		505
	Coal supply and transportation		2019	162.8		55.3		31.9		32.6		31.9		11.1		—
	Total			$	1,722.20	$	374.7	$	245.1	$	218.8	$	166	$	119	$	598.6
	(b) Environmental Matters
	Air Permitting Violation Claims
	Weston and Pulliam Clean Air Act (CAA) Issues:
	In November 2009, the EPA issued a Notice of Violation (NOV) to WPS alleging violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. WPS reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree. This Consent Decree was approved by the U.S. District Court (Court) in March 2013, after a public comment period. The final Consent Decree includes:
	•	the installation of emission control technology, including ReACT™ on Weston 3,
	•	changed operating conditions (including refueling, repowering, and/or retirement of units),
	•	limitations on plant emissions,
	•	beneficial environmental projects totaling $6.0 million, and
	•	a civil penalty of $1.2 million.
	As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. WPS announced that certain Weston and Pulliam units mentioned in the Consent Decree will be retired early, in June 2015. WPS received approval from the PSCW in its 2015 rate order to defer and amortize the undepreciated book value of the retired plant associated with Pulliam 5 and 6 and Weston 1 starting with the actual retirement date in 2015 and concluding when the balance is fully amortized. See Note 7, Property, Plant, and Equipment, for more information.
	WPS received approval from the PSCW in its 2014 and 2015 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. We also believe that additional prudently incurred costs expected after 2015 will be recoverable from customers based on past precedent with the PSCW.
	The majority of the beneficial environmental projects proposed by WPS have been approved by the EPA. Amounts have been accrued and recorded to regulatory assets, excluding costs associated with capital projects.
	In May 2010, WPS received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of December 31, 2014. It is unknown whether the Sierra Club will take further action in the future.
	Columbia and Edgewater CAA Issues:
	In December 2009, the EPA issued an NOV to Wisconsin Power and Light (WP&L), the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric and WPS. The NOV alleges violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, WP&L, and Madison Gas and Electric reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree. This Consent Decree was approved by the Court in June 2013, after a public comment period. The final Consent Decree includes:
	•	the installation of emission control technology, including scrubbers at the Columbia plant,
	•	changed operating conditions (including refueling, repowering, and/or retirement of units),
	•	limitations on plant emissions,
	•	beneficial environmental projects, with WPS's portion totaling $1.3 million, and
	•	WPS's portion of a civil penalty and legal fees totaling $0.4 million.
	As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain of the Columbia and Edgewater units. As of December 31, 2014, no decision had been made on how to address this requirement. Therefore, retirement of the Columbia and Edgewater units mentioned in the Consent Decree was not considered probable.
	We believe that significant costs prudently incurred as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty, will be recoverable from customers.
	All of the beneficial environmental projects that WPS proposed have been approved by the EPA. Amounts have been accrued and recorded to regulatory assets, excluding costs associated with capital projects.
	Weston Title V Air Permit:
	In August 2013, the WDNR issued the Weston Title V air permit. In September 2013, WPS challenged various requirements in the permit by filing a contested case proceeding with the WDNR and also filed a Petition for Judicial Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also challenged various aspects of the permit. The WDNR granted all parties' requests for contested case proceedings. The Petitions for Judicial Review, by all parties, have been stayed pending the resolution of the contested cases. In February 2014, WPS also requested a modification to the construction permit for Weston 4 to remove the mercury Best Available Control Technology (BACT) emission limit requirement. This permit request was denied by the WDNR and WPS challenged this issue as well. At WPS's request, the permit was modified to resolve several of the petition issues. Those issues have now been voluntarily dismissed from the case, while one new permit change was challenged and added to the case. The administrative law judge (ALJ) recently dismissed some of the petition issues relating to the averaging period and monitoring issues. In May 2014, the WDNR issued an NOV alleging that WPS failed to maintain a minimum sorbent feed rate prior to the Continuous Emissions Monitoring System certification. The WDNR also issued a Notice of Inquiry (NOI) to WPS alleging that WPS failed to comply with reporting requirements related to challenged matters in the 2013 Weston Title V permit. The ALJ recently denied WPS's request to issue a stay or confirm that a statutory stay applies to the requirements identified in the NOV and NOI. The parties are discussing a briefing schedule, but no hearing date has been set. We do not expect these matters to have a material impact on our financial statements.
	Mercury and Interstate Air Quality Rules
	Mercury:
	The State of Wisconsin's mercury rule required a 40% reduction from historical baseline mercury emissions, beginning January 1, 2010, through the end of 2014. Beginning in 2015, electric generating units above 150 megawatts would have been required to further reduce mercury emissions. However, in December 2011, the EPA issued the final Utility Mercury and Air Toxics Standards (MATS), which regulates emissions of mercury and other hazardous air pollutants beginning in April 2015. The State of Wisconsin recently revised the state mercury rule to be consistent with the MATS rule. Projects approved and initiated to address the State of Wisconsin mercury rule are expected to ensure compliance with the mercury limits in the MATS rule.
	WPS was in compliance with the State of Wisconsin's mercury rule at the end of 2014. In addition, WPS is making progress toward compliance with the MATS rule in 2015. WPS estimated capital costs of approximately $9 million for its wholly owned plants to achieve the required reductions for MATS compliance, of which approximately $8 million was expended as of December 31, 2014. The capital costs are expected to be recovered in future rates.
	Sulfur Dioxide and Nitrogen Oxide:
	In July 2011, the EPA issued a final rule known as the Cross State Air Pollution Rule (CSAPR), which numerous parties, including WPS, challenged in the United States Court of Appeals (Court of Appeals) for the District of Columbia Circuit (D.C. Circuit). The new rule was to become effective in January 2012. However, in December 2011, the CSAPR requirements were stayed by the D.C. Circuit and a previous rule, the Clean Air Interstate Rule (CAIR), was implemented during the stay period. In August 2012, the D.C. Circuit issued their ruling vacating and remanding CSAPR and simultaneously reinstating CAIR pending the issuance of a replacement rule by the EPA. The case was appealed to the United States Supreme Court (Supreme Court), and in April 2014, the Supreme Court upheld the CSAPR rule and remanded the case to the Court of Appeals for the D.C. Circuit. In October 2014, the Court of Appeals granted the EPA's request to lift the stay on CSAPR and changed the compliance deadlines by three years, so that Phase 1 emissions budgets will apply in 2015 and 2016 and Phase 2 emissions budgets will apply to 2017 and beyond. We do not expect to incur significant costs to comply with either phase of CSAPR and expect to recover any future compliance costs in future rates.
	Under CAIR, units affected by the Best Available Retrofit Technology (BART) rule were considered in compliance with BART for sulfur dioxide and nitrogen oxide emissions if they were in compliance with CAIR. This determination was updated when CSAPR was issued (CSAPR satisfied BART). Although particulate emissions also contribute to visibility impairment, the WDNR's modeling for Pulliam Unit 8, the only unit covered by BART, has shown the impairment to be so insignificant that additional capital expenditures or controls may not be warranted.
	Clean Water Act Rule
	In August 2014, the EPA issued a final Clean Water Act, which established requirements under Section 316(b) to regulate water intake structures at industrial facilities that use large volumes of surface water as cooling water. The new rule became effective in October 2014 and has been challenged by a number of parties. The cases have been consolidated and will be heard in the United States Court of Appeals for the Second Circuit. To the extent that the rule is upheld, WPS will comply with the rule on the timeline required under the regulation. WPS will evaluate the impact of compliance by conducting the studies required by the rule at its facilities. WPS anticipates that the timing for compliance will be incorporated into future wastewater discharge permit renewals. We do not expect to incur significant costs to comply with the Clean Water Act rule as WPS's Weston plants are already equipped with cooling towers that assist with meeting these new requirements. We expect to recover any future compliance costs in future rates.
	Manufactured Gas Plant Remediation
	Our natural gas utilities, their predecessors, and certain former affiliates operated facilities in the past at multiple sites for the purpose of manufacturing and storing manufactured gas. In connection with these activities, waste materials were produced that may have resulted in soil and groundwater contamination at these sites. Under certain laws and regulations relating to the protection of the environment, our natural gas utilities are required to undertake remedial action with respect to some of these materials. The natural gas utilities are coordinating the investigation and cleanup of the sites subject to EPA jurisdiction 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.
	Our natural gas utilities are responsible for the environmental remediation of 53 sites, of which 20 have been transferred to the EPA Superfund Alternative Sites Program. Under the EPA's program, the remedy decisions at these sites will be made using risk-based criteria typically used at Superfund sites. Our balance sheet includes liabilities of $579.7 million that we have estimated and accrued for as of December 31, 2014, for future undiscounted investigation and cleanup costs for all sites. We may adjust these estimates in the future due to remedial technology, regulatory requirements, remedy determinations, and any claims of natural resource damages. As of December 31, 2014, cash expenditures for environmental remediation not yet recovered in rates were $54.6 million. Our balance sheet also includes a regulatory asset of $634.3 million at December 31, 2014, which is net of insurance recoveries, related to the expected recovery through rates of both cash expenditures and estimated future expenditures.
	Management believes that any costs incurred for environmental activities relating to former manufactured gas plant operations that are not recoverable through contributions from other entities or from insurance carriers have been prudently incurred and are, therefore, recoverable through rates for MGU, NSG, PGL, and WPS. Accordingly, we do not expect these costs to have a material impact on our financial statements. However, any changes in the approved rate mechanisms for recovery of these costs, or any adverse conclusions by the various regulatory commissions with respect to the prudence of costs actually incurred, could materially affect recovery of such costs through rates.

EMPLOYEE_BENEFIT_PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
EMPLOYEE BENEFIT PLANS	Employee Benefit Plans
	Defined Benefit Plans
	We and our subsidiaries maintain a noncontributory, qualified pension plan covering the majority of our employees, as well as several unfunded nonqualified retirement plans. In addition, we and our subsidiaries offer multiple other postretirement benefit plans to employees. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred.
	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. In March 2014, we remeasured the obligations of certain other postretirement benefit 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.
	In August 2014, we sold UPPCO. The pension and other postretirement plan assets and obligations related to UPPCO employees and retirees transferred with the sale and are disclosed in the table below. The impact of this transfer has been reflected in the measurement of the gain on sale of UPPCO. See Note 4, Dispositions, for more information.
	The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets:
			Pension Benefits						Other Benefits
	(Millions)		2014			2013			2014			2013
	Change in benefit obligation
	Obligation at January 1		$	1,641.70		$	1,784.90		$	576.3		$	621
	Service cost		24.8			30.2			21			24.9
	Interest cost		76.2			71.2			23.5			24.8
	Plan amendments		—			—			(90.4		)	0.2
	Divestitures - UPPCO		(100.4		)	—			(22.3		)	—
	Actuarial loss (gain), net		166.1			(153.1		)	33.1			(73.4		)
	Participant contributions		—			—			10			10.6
	Benefit payments		(102.7		)	(91.5		)	(33.3		)	(34.0		)
	Federal subsidy on benefits paid		—			—			2.1			2.2
	Obligation at December 31		$	1,705.70		$	1,641.70		$	520		$	576.3
	Change in fair value of plan assets
	Fair value of plan assets at January 1		$	1,527.70		$	1,348.10		$	470.1		$	424.4
	Actual return on plan assets		94.6			205.4			18.2			57.8
	Employer contributions		98.8			65.7			10			11.3
	Participant contributions		—			—			10			10.6
	Divestitures - UPPCO		(122.8		)	—			(27.3		)	—
	Benefit payments		(102.7		)	(91.5		)	(33.3		)	(34.0		)
	Fair value of plan assets at December 31		$	1,495.60		$	1,527.70		$	447.7		$	470.1
	Funded Status at December 31		$	(210.1	)	$	(114.0	)	$	(72.3	)	$	(106.2	)
	The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:
			Pension Benefits						Other Benefits
	(Millions)		2014			2013			2014			2013
	Long-term assets		$	—		$	—		$	1.5		$	—
	Current liabilities		9.1			8.9			0.2			0.2
	Liabilities held for sale		—			6.9			—			3.4
	Long-term liabilities		201			98.2			73.6			102.6
	Total net liabilities		$	(210.1	)	$	(114.0	)	$	(72.3	)	$	(106.2	)
	The accumulated benefit obligation for the defined benefit pension plans was $1,531.1 million and $1,489.1 million at December 31, 2014, and 2013, respectively.
	The following table shows information for the non-qualified pension plans for which we have an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these non-qualified pension plans. Amounts presented are as of December 31:
	(Millions)		2014			2013
	Projected benefit obligation		$	64.1		$	65.4
	Accumulated benefit obligation		61.2			63
	The following table shows the amounts that had not yet been recognized in our net periodic benefit cost as of December 31:
			Pension Benefits						Other Benefits
	(Millions)		2014			2013			2014			2013
	Accumulated other comprehensive loss (pre-tax) (1)
	Net actuarial loss		$	40.2		$	33.3		$	0.2		$	0.7
	Prior service credits		—			—			(0.1		)	(0.2		)
	Total		$	40.2		$	33.3		$	0.1		$	0.5
	Net regulatory assets (2)
	Net actuarial loss		$	501		$	356.2		$	50.4		$	6.2
	Prior service costs (credits)		1.8			2.4			(85.3		)	(12.4		)
	Total		$	502.8		$	358.6		$	(34.9	)	$	(6.2	)
	(1)	Amounts related to the nonregulated entities are included in accumulated other comprehensive loss.
	(2)	Amounts related to the utilities are recorded as net regulatory assets or liabilities.
	The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2015:
	(Millions)		Pension Benefits			Other Benefits
	Net actuarial loss		$	43.2		$	4.4
	Prior service costs (credits)		0.2			(10.3		)
	Total 2015 – estimated amortization		$	43.4		$	(5.9	)
	The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheets) for our benefit plans:
			Pension Benefits									Other Benefits
	(Millions)		2014			2013			2012			2014			2013			2012
	Service cost		$	24.8		$	30.2		$	46		$	21		$	24.9		$	20.8
	Interest cost		76.2			71.2			78			23.5			24.8			28.5
Expected return on plan assets		(112.4		)	(105.5		)	(107.9		)	(33.0		)	(30.6		)	(28.2		)
Loss on plan settlement		0.9			—			—			—			—			—
Amortization of transition obligation		—			—			—			—			—			0.3
Amortization of prior service cost (credit)		0.6			4			5			(9.4		)	(2.5		)	(3.4		)
Amortization of net actuarial loss		33.3			56.7			34			3.2			8.4			6.6
Net periodic benefit cost		$	23.4		$	56.6		$	55.1		$	5.3		$	25		$	24.6
Assumptions – Pension and Other Postretirement Benefit Plans
The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31:
		Pension Benefits			Other Benefits
		2014		2013	2014		2013
Discount rate		4.08%		4.92%	4.00%		4.83%
Rate of compensation increase		4.23%		4.24%	N/A		N/A
Assumed medical cost trend rate		N/A		N/A	6.00%		6.50%
Ultimate trend rate		N/A		N/A	5.00%		5.00%
Year ultimate trend rate is reached		N/A		N/A	2023		2019
Assumed dental cost trend rate		N/A		N/A	5.00%		5.00%
The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31:
		Pension Benefits
		2014		2013	2012
Discount rate		4.92%		4.07%	5.10%
Expected return on assets		8.00%		8.00%	8.25%
Rate of compensation increase		4.23%		4.25%	4.25%
		Other Benefits
		2014		2013	2012
Discount rate		4.65%		3.96%	4.94%
Expected return on assets		8.00%		8.00%	8.25%
Assumed medical cost trend rate (under age 65)		6.50%		7.00%	7.00%
Ultimate trend rate		5.00%		5.00%	5.00%
Year ultimate trend rate is reached		2019		2019	2016
Assumed medical cost trend rate (over age 65)		6.50%		7.00%	7.50%
Ultimate trend rate		5.00%		5.00%	5.50%
Year ultimate trend rate is reached		2019		2019	2016
Assumed dental cost trend rate		5.00%		5.00%	5.00%
We establish our expected return on assets assumption based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. For 2015, the expected return on assets assumption for the plans is 7.75%.
Assumed health care cost trend rates have a significant effect on the amounts reported by us for our health care plans. For the year ended December 31, 2014, a one-percentage-point change in assumed health care cost trend rates would have had the following effects:
		One-Percentage-Point
(Millions)		Increase			Decrease
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost		$	6.1		$	(5.0	)
Effect on the health care component of the accumulated postretirement benefit obligation		58.7			(55.1		)
Pension and Other Postretirement Benefit Plan Assets
Our investment policy includes various guidelines and procedures designed to ensure assets are invested in an appropriate manner to meet expected future benefits to be earned by participants. The investment guidelines consider a broad range of economic conditions. The policy is established and administered in a manner that is compliant at all times with applicable regulations.
Central to our policy are target allocation ranges by major asset categories. The objectives of the target allocations are to maintain investment portfolios that diversify risk through prudent asset allocation parameters and to achieve asset returns that meet or exceed the plans' actuarial assumptions and that are competitive with like instruments employing similar investment strategies. The portfolio diversification provides protection against significant concentrations of risk in the plan assets. In 2014, the pension plan target asset allocation was 70% equity securities and 30% fixed income securities. In December 2014, we changed the pension plan target asset allocation to 60% equity securities and 40% fixed income securities for 2015. The target asset allocation for other postretirement benefit plans that have significant assets is 70% equity securities and 30% fixed income securities. Equity securities primarily include investments in large-cap and small-cap companies. Fixed income securities primarily include corporate bonds of companies from diversified industries, United States government securities, and mortgage-backed securities.
The Board of Directors established the Employee Benefits Administrator Committee (composed of members of management) to manage the operations and administration of all benefit plans and trusts. The committee monitors the asset allocation, and the portfolio is rebalanced when necessary.
Pension and other postretirement benefit plan investments are recorded at fair value. See Note 1(w), Fair Value, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used.
The following tables provide the fair values of our investments by asset class:
		December 31, 2014
		Pension Plan Assets												Other Benefit Plan Assets
(Millions)		Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3		Total
Asset Class
Cash and cash equivalents		$	—		$	42.3		$	—		$	42.3		$	8.5		$	2.6		$	—	$	11.1
Equity securities:
United States equity		91			336.2			—			427.2			20.6			122.8			—		143.4
International equity		92.4			383.9			—			476.3			18.7			117.8			—		136.5
Fixed income securities:
United States government		70.3			21.6			—			91.9			111.1			—			—		111.1
Foreign government		—			20.6			—			20.6			—			—			—		—
Corporate debt		—			425.7			—			425.7			—			—			—		—
Other		—			53.5			—			53.5			1			—			—		1
		253.7			1,283.80			—			1,537.50			159.9			243.2			—		403.1
401(h) other benefit plan assets invested as pension assets (1)		(7.4		)	(37.2		)	—			(44.6		)	7.4			37.2			—		44.6
Total (2)		$	246.3		$	1,246.60		$	—		$	1,492.90		$	167.3		$	280.4		$	—	$	447.7
(1)	Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).
(2)	Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.
		December 31, 2013
		Pension Plan Assets												Other Benefit Plan Assets
(Millions)		Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3		Total
Asset Class
Cash and cash equivalents		$	2		$	36.6		$	—		$	38.6		$	—		$	4		$	—	$	4
Equity securities:
United States equity		100.4			445.1			—			545.5			21.4			132.2			—		153.6
International equity		114.1			429			—			543.1			19.5			125.5			—		145
Fixed income securities:
United States government		—			93.6			—			93.6			121.2			0.7			—		121.9
Foreign government		—			16.9			2.4			19.3			—			—			—		—
Corporate debt		—			250			1.3			251.3			—			—			—		—
Asset-backed securities		—			61.8			—			61.8			—			—			—		—
Other		—			17.4			—			17.4			1			—			—		1
		216.5			1,350.40			3.7			1,570.60			163.1			262.4			—		425.5
401(h) other benefit plan assets invested as pension assets (1)		(6.1		)	(37.9		)	(0.1		)	(44.1		)	6.1			37.9			0.1		44.1
Total (2)		$	210.4		$	1,312.50		$	3.6		$	1,526.50		$	169.2		$	300.3		$	0.1	$	469.6
(1)	Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).
(2)	Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.
The following tables set forth a reconciliation of changes in the fair value of pension plan assets categorized as Level 3 in the fair value hierarchy:
(Millions)		Foreign Government Debt			Corporate Debt			Total
Beginning balance at January 1, 2014		$	2.4		$	1.3		$	3.7
Sales		(2.4		)	(1.3		)	(3.7		)
Ending balance at December 31, 2014		$	—		$	—		$	—
Net unrealized gains (losses) related to assets still held at the end of the period		$	—		$	—		$	—
(Millions)		Foreign Government Debt			Corporate Debt			Asset-Backed Securities			Total
Beginning balance at January 1, 2013		$	4.1		$	1		$	0.1		$	5.2
Net realized and unrealized losses		(0.3		)	(0.4		)	—			(0.7		)
Purchases		0.6			—			—			0.6
Sales		(2.0		)	(0.4		)	—			(2.4		)
Transfers into Level 3		—			1.4			—			1.4
Transfers out of Level 3		—			(0.3		)	(0.1		)	(0.4		)
Ending balance at December 31, 2013		$	2.4		$	1.3		$	—		$	3.7
Net unrealized losses related to assets still held at the end of the period		$	(0.2	)	$	(0.3	)	$	—		$	(0.5	)
Cash Flows Related to Pension and Other Postretirement Benefit Plans
Our funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. We expect to contribute $9.1 million to the pension plans and $8.7 million to other postretirement benefit plans in 2015, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. In 2015, contributions of $7.0 million will be funded through a transfer of assets from the rabbi trust for certain nonqualified pension plans. See the discussion below in regard to the triggering of the full funding of the rabbi trust.
The following table shows the payments, reflecting expected future service, that we expect to make for pension and other postretirement benefits.
(Millions)		Pension Benefits			Other Benefits
2015		$	124.6		$	23.7
2016		122.3			26
2017		127.6			28.4
2018		126			30.6
2019		136.5			33.3
2020 through 2024		644.4			195.8
Rabbi Trust Funding
The Agreement and Plan of Merger entered into with Wisconsin Energy Corporation in June 2014 triggered the potential change in control provisions in the rabbi trust agreement. These provisions required the full funding of the present value of each participant's total benefit under the deferred compensation program and certain nonqualified pension plans. As a result, $65.0 million was moved to the rabbi trust in June 2014, $64.8 million, consisting of cash and exchange-traded funds, was moved to the rabbi trust in July 2014, and an additional $2.4 million was moved to the rabbi trust in December 2014. These amounts were included in other long-term assets on the balance sheet as of December 31, 2014. See Note 2, Proposed Merger with Wisconsin Energy Corporation, for more information.
Defined Contribution Benefit Plans
We maintain 401(k) Savings Plans for substantially all of our full-time employees. A percentage of employee contributions are matched through an employee stock ownership plan (ESOP) contribution or cash contribution up to certain limits. Certain union employees receive a contribution to their ESOP account regardless of their participation in the 401(k) Savings Plan. The ESOP held 3.9 million shares of our common stock (market value of $303.5 million) at December 31, 2014. Certain employees participate in a defined contribution pension plan, in which certain amounts are contributed to an employee's account based on the employee's wages, age, and years of service. Total costs incurred under all of these plans were $35.0 million in 2014, $36.4 million in 2013, and $19.1 million in 2012.
We maintain deferred compensation plans that enable certain key employees and nonemployee directors to defer payment of a portion of their compensation or fees on a pre-tax basis. Nonemployee directors can defer up to 100% of their director fees. Compensation is generally deferred in the form of cash and is indexed to certain investment options or our common stock. The deemed dividends paid on the common stock are automatically reinvested.
The deferred compensation arrangements for which distributions are made solely in our common stock are classified as an equity instrument on the balance sheets. Changes in the fair value of this portion of the deferred compensation obligation are not recognized. The deferred compensation obligation classified as an equity instrument was $24.3 million at December 31, 2014, and $24.8 million at December 31, 2013.
The portion of the deferred compensation obligation that is indexed to various investment options and allows for distributions in cash is classified as a liability on the balance sheets. The liability is adjusted, with a charge or credit to expense, to reflect changes in the fair value of the deferred compensation obligation. The obligation classified within other long-term liabilities was $64.4 million at December 31, 2014, and $53.4 million at December 31, 2013. The costs incurred under this arrangement were $9.5 million in 2014, $6.5 million in 2013, and $3.1 million in 2012.
Historically, the deferred compensation programs were partially funded through shares of our common stock that are held in a rabbi trust. The common stock held in the rabbi trust is classified as a reduction of equity in a manner similar to accounting for treasury stock. The total cost of our common stock held in the rabbi trust was $20.9 million at December 31, 2014, and $23.0 million at December 31, 2013.

PREFERRED_STOCK_OF_SUBSIDIARY

PREFERRED STOCK OF SUBSIDIARY (WPS)	12 Months Ended
	Dec. 31, 2014
WPS
Preferred stock of subsidiary
PREFERRED STOCK OF SUBSIDIARY	Preferred Stock of Subsidiary
	Our subsidiary, WPS, has 1,000,000 authorized shares of preferred stock with no mandatory redemption and a $100 par value. Outstanding shares owned by third parties were as follows at December 31:
	(Millions, except share amounts)	2014			2013
	Series	Shares Outstanding	Carrying Value		Shares Outstanding	Carrying Value
	5.00%	130,692	$	13.1	130,692	$	13.1
	5.04%	29,898	3		29,898	3
	5.08%	49,905	5		49,905	5
	6.76%	150,000	15		150,000	15
	6.88%	150,000	15		150,000	15
	Total	510,495	$	51.1	510,495	$	51.1
	All shares of WPS preferred stock of all series are of equal rank except as to dividend rates and redemption terms. Payment of dividends from any earned surplus or other available surplus is not restricted by the terms of any indenture or other undertaking by WPS. Each series of outstanding preferred stock is redeemable in whole or in part at WPS's option at any time on 30 days' notice at the respective redemption prices. WPS may not redeem less than all, nor purchase any, of its preferred stock during the existence of any dividend default.
	In the event of WPS's dissolution or liquidation, the holders of preferred stock are entitled to receive (a) the par value of their preferred stock out of the corporate assets other than profits before any of such assets are paid or distributed to the holders of common stock and (b) the amount of dividends accumulated and unpaid on their preferred stock out of the surplus or net profits before any of such surplus or net profits are paid to the holders of common stock. Thereafter, the remainder of the corporate assets, surplus, and net profits would be paid to the holders of common stock.
	The preferred stock has no pre-emptive, subscription, or conversion rights, and has no sinking fund provisions.

COMMON_EQUITY

COMMON EQUITY	12 Months Ended
	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
COMMON EQUITY	Common Equity
	We had the following changes to issued common stock:
	Balance at December 31, 2011		78,287,906
	Balance at December 31, 2012 *		78,287,906
	Shares issued
	Stock-based compensation		972,718
	Stock Investment Plan		298,532
	Employee Stock Ownership Plan		248,724
	Rabbi trust shares		111,296
	Balance at December 31, 2013		79,919,176
	Shares issued
	Stock Investment Plan		12,151
	Employee Stock Ownership Plan		31,764
	Balance at December 31, 2014		79,963,091
	*	We did not issue equity during 2012.
	The following table provides a summary of common stock activity to meet the requirements of our Stock Investment Plan and certain stock-based employee benefit and compensation plans:
	Period		Method of meeting requirements
	Beginning 02/05/2014		Purchasing shares on the open market
	02/05/2013 – 02/04/2014		Issued new shares
	01/01/2012 – 02/04/2013		Purchased shares on the open market
	Under the merger agreement with Wisconsin Energy Corporation (Wisconsin Energy), we cannot issue shares of our common stock.
	The following table reconciles common shares issued and outstanding:
			2014							2013
			Shares			Average Cost *				Shares			Average Cost *
	Common stock issued		79,963,091							79,919,176
	Less:
	Deferred compensation rabbi trust		428,920			$	48.73			473,796			$	48.5
	Total common shares outstanding		79,534,171							79,445,380
	*	Based on our stock price on the day the shares entered the deferred compensation rabbi trust. Shares paid out of the trust are valued at the average cost of shares in the trust.
	Earnings Per Share
	The following table reconciles our computation of basic and diluted earnings per share:
	(Millions, except per share amounts)		2014				2013				2012
	Numerator:
	Net income from continuing operations		$	278.1			$	267.5			$	238.9
	Discontinued operations, net of tax		1.8				87.3				45.4
	Preferred stock dividends of subsidiary		(3.1		)		(3.1		)		(3.1		)
	Noncontrolling interest in subsidiaries		0.1				0.1				0.2
	Net income attributed to common shareholders — basic		$	276.9			$	351.8			$	281.4
	Effect of dilutive securities
	Deferred compensation		—				(0.1		)		—
	Net income attributed to common shareholders — diluted		$	276.9			$	351.7			$	281.4
	Denominator:
	Average shares of common stock — basic		80.2				79.5				78.6
	Effect of dilutive securities
	Stock-based compensation		0.5				0.4				0.5
	Deferred compensation		—				0.2				0.2
	Average shares of common stock — diluted		80.7				80.1				79.3
	Earnings per common share
	Basic		$	3.45			$	4.43			$	3.58
	Diluted		3.43				4.39				3.55
	The calculation of diluted earnings per share excluded the following weighted-average outstanding securities that had an anti-dilutive effect:
	(Millions)		2014			2013			2012
	Stock-based compensation		0.2			0.3			0.7
	Deferred compensation		0.3			0.1			—
	Dividend Restrictions
	Our ability as a holding company to pay dividends is largely dependent upon the availability of funds from our subsidiaries. Various laws, regulations, and financial covenants impose restrictions on the ability of certain of our utility subsidiaries to transfer funds to us in the form of dividends. Our utility subsidiaries, with the exception of MGU, are prohibited from loaning funds to us, either directly or indirectly.
	The PSCW allows WPS to pay dividends on its common stock of no more than 103% of the previous year’s common stock dividend. WPS may return capital to us if its average financial common equity ratio is at least 51% on a calendar-year basis. WPS must obtain PSCW approval if a return of capital would cause its average financial common equity ratio to fall below this level. Our right to receive dividends on the common stock of WPS is also subject to the prior rights of WPS’s preferred shareholders and to provisions in WPS’s restated articles of incorporation, which limit the amount of common stock dividends that WPS may pay if its common stock and common stock surplus accounts constitute less than 25% of its total capitalization.
	NSG’s long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock.
	PGL and WPS have short-term debt obligations containing financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default which could result in the acceleration of their outstanding debt obligations.
	As of December 31, 2014, total restricted net assets of consolidated subsidiaries were $1,953.0 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $157.5 million at December 31, 2014.
	We also have short-term and long-term debt obligations that contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%. Failure to comply with these covenants could result in an event of default which could result in the acceleration of outstanding debt obligations. At December 31, 2014, these covenants did not restrict our retained earnings or the payment of any dividends.
	We have the option to defer interest payments on our outstanding Junior Subordinated Notes, from time to time, for one or more periods of up to ten consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, purchase, acquire, or make a liquidation payment on, any of our capital stock.
	Under the merger agreement with Wisconsin Energy, we may not declare or pay any dividends or distributions on our common stock other than the regular quarterly dividend of $0.68 per share.
	Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions.
Capital Transactions with Subsidiaries
During 2014, capital transactions with subsidiaries were as follows (in millions):
Subsidiary		Dividends To Parent				Return Of				Equity Contributions
						Capital To Parent				From Parent
IBS		$	—			$	—			$	25
ITF (1)		—				—				50.3
MERC		—				27				20
MGU		—				13				7
PGL(1)		—				—				65
UPPCO		—				12.5				94.4
WPS		111.8				—				55
WPS Investments, LLC (2)		74.3				—				17
Total		$	186.1			$	52.5			$	333.7
(1)	ITF and PGL are direct wholly owned subsidiaries of PELLC. As a result, they make distributions to PELLC, and receive equity contributions from PELLC. Subject to applicable law, PELLC does not have any dividend restrictions or limitations on distributions to us.
(2)	WPS Investments, LLC is a consolidated subsidiary that is jointly owned by us and WPS. In August 2014, UPPCO's ownership interest in WPS Investments, LLC was transferred to us as a result of the sale of UPPCO. At December 31, 2014, the ownership interest held by us and WPS was 89.02% and 10.98%, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2014, all equity contributions to WPS Investments, LLC were made solely by us.

ACCUMULATED_OTHER_COMPREHENSIV

ACCUMULATED OTHER COMPREHENSIVE LOSS	12 Months Ended
	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
ACCUMULATED OTHER COMPREHENSIVE LOSS	Accumulated Other Comprehensive Loss
	The following table shows the changes, net of tax, to our accumulated other comprehensive loss:
									Accumulated Other Comprehensive Loss
	(Millions)		Cash Flow Hedges			Defined Benefit Plans
	Balance at December 31, 2012		$	(5.2	)	$	(35.7	)	$	(40.9	)
	Other comprehensive income before reclassifications		0.7			13.2			13.9
	Amounts reclassified out of accumulated other comprehensive loss		1.4			2.4			3.8
	Net 2013 other comprehensive income		2.1			15.6			17.7
	Balance at December 31, 2013		(3.1		)	(20.1		)	(23.2		)
	Other comprehensive loss before reclassifications		—			(6.0		)	(6.0		)
	Amounts reclassified out of accumulated other comprehensive loss		(0.1		)	1.7			1.6
	Net 2014 other comprehensive loss		(0.1		)	(4.3		)	(4.4		)
	Balance at December 31, 2014		$	(3.2	)	$	(24.4	)	$	(27.6	)
	The following table shows the reclassifications out of accumulated other comprehensive loss during the years ended December 31:
			Amount Reclassified
	(Millions)		2014			2013			Affected Line Item in the Statements of Income
	Losses (gains) on cash flow hedges
	Utility commodity derivative contracts		$	—		$	0.2		Operating and maintenance expense (1) (2)
	Nonregulated commodity derivative contracts		—			3.7			Discontinued operations (2)
	Interest rate hedges		1.1			1.1			Interest expense
			1.1			5			Total before tax
			1.2			3.6			Tax expense
			(0.1		)	1.4			Net of tax
	Defined benefit plans
	Amortization of prior service costs (credits)		(0.2		)	4.3			(3)
	Amortization of net actuarial losses (gains)		2.7			(0.2		)	(3)
			2.5			4.1			Total before tax
			0.8			1.7			Tax expense
			1.7			2.4			Net of tax
	Total reclassifications		$	1.6		$	3.8
	(1)	This item relates to changes in the price of natural gas used to support utility operations.
	(2)	We no longer designate commodity contracts as cash flow hedges.
	(3)	These items are included in the computation of net periodic benefit cost. See Note 18, Employee Benefit Plans, for more information.

GUARANTEES

GUARANTEES	12 Months Ended
	Dec. 31, 2014
Guarantees [Abstract]
GUARANTEES	Guarantees
	The following table shows our outstanding guarantees:
			Total Amounts Committed		Expiration
	(Millions)		at December 31, 2014		Less Than 1 Year		1 to 3 Years		Over 3 Years
	Guarantees supporting commodity transactions of subsidiaries (1)		$	189.3	$	105.1	$	—	$	84.2
	Standby letters of credit (2)		1.2		1.1		0.1		—
	Surety bonds (3)		25.1		25		0.1		—
	Other guarantees (4)		73.5		—		—		73.5
	Guarantees temporarily retained related to the sale of IES's retail energy business (5)		279.5		$	248.4	$	1.8	$	29.3
	Total guarantees		$	568.6	$	379.6	$	2	$	187
	(1)	Consists of (a) $5.0 million to support the business operations of IBS, and (b) $0.4 million, $127.4 million, $44.7 million, and $11.8 million related to natural gas supply at ITF, MERC, MGU, and PDI, respectively. These guarantees are not reflected on our balance sheets.
	(2)	At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. This amount consists of $1.2 million issued to support ITF, MERC, MGU, NSG, PDI, PGL, and WPS. These amounts are not reflected on our balance sheets.
	(3)	Primarily for the construction and operation of compressed natural gas fueling stations, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These guarantees are not reflected on our balance sheets.
	(4)	Consists of (a) $46.1 million to support PDI's future payment obligations related to its distributed solar generation projects; (b) $10.0 million related to the sale agreement for IES’s Texas retail marketing business. An insignificant liability was recorded related to the possible imposition of additional miscellaneous gross receipts tax in the event of a change in law or interpretation of the tax law; (c) $11.2 million related to the performance of an operating and maintenance agreement by ITF; and (d) $6.2 million related to other indemnifications primarily for workers compensation coverage. The amounts discussed in items (a), (c), and (d) above are not reflected on our balance sheets.
	(5)	These guarantees are retained temporarily due to the sale of IES's retail energy business to Exelon Generation Company, LLC (Exelon). For up to six months after the sale, we will continue to provide these guarantees until either Exelon can replace them or until they expire. Exelon is contractually bound to reimburse us for any payments we make under the outstanding guarantees. These guarantees consist of (a) $267.4 million of guarantees supporting commodity transactions; (b) $6.9 million of standby letters of credit; (c) $3.4 million of surety bonds; and (d) $1.8 million related to the sale of WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC. Following the guidance of the Guarantees Topic of the FASB ASC, an insignificant liability related to these guarantees was recorded at fair value on our balance sheet. Our exposure under these guarantees related to open transactions at December 31, 2014, was $168.9 million.

STOCKBASED_COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
STOCK-BASED COMPENSATION	Stock-Based Compensation
	The following table reflects the stock-based compensation expense and the related deferred income tax benefit recognized in income for the years ended December 31:
	(Millions)		2014				2013			2012
	Stock options		$	2.7			$	1.8		$	2
	Performance stock rights		16.8				2.7			5
	Restricted share units		9.9				8.6			8.1
	Nonemployee director deferred stock units		0.8				0.9			1
	Total stock-based compensation expense		$	30.2			$	14		$	16.1
	Deferred income tax benefit		$	12.1			$	5.6		$	6.4
	No stock-based compensation cost was capitalized during 2014, 2013, and 2012.
	Stock Options
	The following table shows the weighted-average fair values per stock option granted along with the assumptions incorporated into the binomial lattice valuation models:
			2014 Grant		2013 Grant		2012 Grant
	Weighted-average fair value per stock option		6.7		6.03		6.3
	Expected term		8 years		5 years		5 years
	Risk-free interest rate		0.12% – 2.88%		0.18% – 2.11%		0.17% – 2.18%
	Expected dividend yield		5.28%		5.33%		5.28%
	Expected volatility		18%		24%		25%
	A summary of stock option activity for 2014, and information related to outstanding and exercisable stock options at December 31, 2014, is presented below:
			Stock Options			Weighted-Average			Weighted-Average		Aggregate
						Exercise Price Per			Remaining		Intrinsic Value
						Share			Contractual Life		(Millions)
									(in Years)
	Outstanding at December 31, 2013		1,550,374			$	50.93
	Granted		264,332			55.23
	Exercised		(1,676,831	)		51.33
	Forfeited		(3,858	)		55.23
	Outstanding at December 31, 2014		134,017			$	54.31		6.6		$	3.2
	Exercisable at December 31, 2014		59,714			$	55.21		5.6		$	1.4
	The aggregate intrinsic value for 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 all exercised their options on December 31, 2014. This is calculated as the difference between our closing stock price on December 31, 2014, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during 2014, 2013, and 2012, was $32.0 million, $9.0 million, and $11.0 million, respectively. The actual tax benefit realized for the tax deductions from these option exercises was $12.8 million, $3.6 million, and $4.4 million during 2014, 2013, and 2012, respectively.
	Due to the accelerated vesting of all unvested stock options held by active employees in October 2014, all compensation expense related to outstanding stock options has been recognized at December 31, 2014.
	Performance Stock Rights
	The table below reflects the assumptions used in the Monte Carlo valuation models to estimate the fair value of the outstanding performance stock rights at December 31:
			2014		2013		2012
	Risk-free interest rate		0.21% – 0.63%		0.13% – 1.27%		0.17% – 1.27%
	Expected dividend yield		5.25% – 5.33%		5.28% – 5.34%		5.18% – 5.34%
	Expected volatility		18% – 22%		15% – 36%		14% – 36%
	A summary of the 2014 activity related to performance stock rights accounted for as equity awards is presented below:
			Performance			Weighted-Average
			Stock Rights			Fair Value (2)
	Outstanding at December 31, 2013		85,749			$	46.62
	Granted		21,146			44.28
	Award modifications		64,612			85.09
	Distributed (1)		(74,345	)		77.67
	Adjustment for estimated payout and shares not distributed (1)		(28,591	)		52.67
	Forfeited		(308	)		44.28
	Outstanding at December 31, 2014		68,263			$	58.54
	(1)	No shares of common stock were distributed for performance stock rights with a performance period ending December 31, 2013, because the performance percentage was below the threshold payout level. In October 2014, our Board of Directors approved the acceleration of a portion of the estimated distribution for those performance stock rights held by active employees with a performance period ending December 31, 2014. This distribution was made in December 2014.
	(2)	Reflects the weighted-average fair value used to measure equity awards. Equity awards are measured using the grant date fair value or the fair value on the modification date.
	The weighted-average grant date fair value of performance stock rights awarded during 2014, 2013, and 2012, was $44.28, $48.50, and $52.70 per performance stock right, respectively.
	A summary of the 2014 activity related to performance stock rights accounted for as liability awards is presented below:
			Performance
			Stock Rights
	Outstanding at December 31, 2013		198,904
	Granted		84,529
	Award modifications		(64,612	)
	Distributed *		(10,760	)
	Adjustment for estimated payout and shares not distributed *		(36,519	)
	Forfeited		(1,234	)
	Outstanding at December 31, 2014		170,308
	*	No shares of common stock were distributed for performance stock rights with a performance period ending December 31, 2013, because the performance percentage was below the threshold payout level. In October 2014, our Board of Directors approved the acceleration of a portion of the estimated distribution for those performance stock rights held by active employees with a performance period ending December 31, 2014. This distribution was made in December 2014.
	The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of December 31, 2014, was $108.51 per performance stock right.
	As of December 31, 2014, $4.2 million of compensation cost related to unvested and outstanding performance stock rights (equity and liability awards) was expected to be recognized over a weighted-average period of 1.6 years.
	The total intrinsic value of performance stock rights distributed during 2014, 2013, and 2012, was $6.4 million, $8.8 million, and $4.7 million, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance stock rights during 2014, 2013, and 2012, was $2.6 million, $3.6 million, and $1.9 million, respectively.
Restricted Share Units
A summary of the 2014 activity related to all restricted share unit awards (equity and liability awards) is presented below:
		Restricted Share			Weighted-Average Grant Date Fair Value
		Unit Awards
Outstanding at December 31, 2013		511,301			$	52.24
Granted		214,953			55.23
Dividend equivalents		21,422			54.47
Vested and released		(208,964	)		49.76
Forfeited		(111,407	)		54.62
Outstanding at December 31, 2014		427,305			$	54.45
As of December 31, 2014, $7.3 million of unrecognized compensation cost related to these awards was expected to be recognized over a weighted-average period of 2.3 years.
The total intrinsic value of restricted share unit awards vested and released during 2014, 2013, and 2012, was $11.4 million, $11.7 million, and $10.7 million, respectively. The actual tax benefit realized for the tax deductions from the vesting and release of restricted share units during 2014, 2013, and 2012, was $4.6 million, $4.7 million, and $4.3 million, respectively.
The weighted-average grant date fair value of restricted share units awarded during 2014, 2013, and 2012, was $55.23, $55.93, and $53.24 per unit, respectively.

FAIR_VALUE

FAIR VALUE	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
FAIR VALUE	Fair Value
	Fair Value Measurements
	The following tables show assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:
			31-Dec-14
	(Millions)		Level 1			Level 2			Level 3			Total
	Assets
	Risk Management Assets
	Natural gas contracts		$	—		$	2.3		$	—		$	2.3
	Financial transmission rights (FTRs)		—			—			2.2			2.2
	Coal contracts		—			—			—			—
	Total Risk Management Assets		$	—		$	2.3		$	2.2		$	4.5
	Investment in Exchange-Traded Funds		$	102.4		$	—		$	—		$	102.4
	Liabilities
	Risk Management Liabilities
	Natural gas contracts		$	4.8		$	31.2		$	6.6		$	42.6
	FTRs		—			—			0.3			0.3
	Petroleum product contracts		2.8			—			—			2.8
	Coal contracts		—			1.2			2.2			3.4
	Total Risk Management Liabilities		$	7.6		$	32.4		$	9.1		$	49.1
			December 31, 2013
	(Millions)		Level 1			Level 2			Level 3			Total
	Assets
	Risk Management Assets
	Natural gas contracts		$	2.4		$	7.7		$	—		$	10.1
	FTRs		—			—			1.5			1.5
	Petroleum product contracts		0.1			—			—			0.1
	Coal contracts		—			—			0.2			0.2
	Total Risk Management Assets		$	2.5		$	7.7		$	1.7		$	11.9
	Investment in Exchange-Traded Funds		$	15.9		$	—		$	—		$	15.9
	Liabilities
	Risk Management Liabilities
	Natural gas contracts		$	0.5		$	0.6		$	—		$	1.1
	FTRs		—			—			0.3			0.3
	Coal contracts		—			—			2.7			2.7
	Total Risk Management Liabilities		$	0.5		$	0.6		$	3		$	4.1
	The risk management assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO market. See Note 6, Risk Management Activities, for more information on derivative instruments.
	Transfers between levels of the fair value hierarchy were not significant during 2014. There were no transfers between the levels of the fair value hierarchy during 2013.
	The significant unobservable inputs used in the valuations that resulted in categorization within Level 3 were as follows at December 31, 2014. The amounts listed in the table below represent the range of unobservable inputs that individually had a significant impact on the fair value determination and caused a transaction to be classified as Level 3.
			Fair Value (Millions)
			Assets			Liabilities			Valuation Technique		Unobservable Input	Average or Range
	Natural gas contracts		$	—		$	6.6		Income-based		Option volatilities (1)	50.5% – 67.2%
	FTRs		2.2			0.3			Market-based		Forward market prices ($/megawatt-month) (2)	$188.16
	Coal contracts		—			2.2			Market-based		Forward market prices ($/ton) (3)	$10.89 – $13.60
	(1)	Represents the range of volatilities used in the valuation of options. Volatilities are derived from an internal model based on volatility curves from third parties.
	(2)	Represents forward market prices developed using historical cleared pricing data from MISO.
	(3)	Represents third-party forward market pricing.
	Significant changes in option volatilities, historical settlement prices, and forward coal prices would result in a directionally similar significant change in fair value.
	The following tables set forth a reconciliation of changes in the fair value of items categorized as Level 3 measurements:
			2014
	(Millions)		Natural Gas Contracts			FTRs			Coal Contracts			Total
	Balance at the beginning of the period		$	—		$	1.2		$	(2.5	)	$	(1.3	)
	Net realized and unrealized gains included in earnings		—			0.2			—			0.2
	Net unrealized (losses) gains recorded as regulatory assets or liabilities		(6.6		)	0.4			(1.6		)	(7.8		)
	Purchases		—			4.3			—			4.3
	Settlements		—			(4.2		)	0.7			(3.5		)
	Net transfers out of Level 3		—			—			1.2			1.2
	Balance at the end of the period		$	(6.6	)	$	1.9		$	(2.2	)	$	(6.9	)
			2013
	(Millions)		FTRs			Coal Contracts			Total
	Balance at the beginning of the period		$	1.1		$	(6.5	)	$	(5.4	)
	Net realized and unrealized gains included in earnings		3			—			3
	Net unrealized (losses) gains recorded as regulatory assets or liabilities		(0.1		)	0.4			0.3
	Purchases		3.2			—			3.2
	Sales		(0.2		)	—			(0.2		)
Settlements		(5.8		)	3.6			(2.2		)
Balance at the end of the period		$	1.2		$	(2.5	)	$	(1.3	)
		2012
(Millions)		FTRs			Coal Contracts			Total
Balance at the beginning of the period		$	1.2		$	(6.9	)	$	(5.7	)
Net realized and unrealized gains included in earnings		1.8			—			1.8
Net unrealized (losses) gains recorded as regulatory assets or liabilities		(0.1		)	5.8			5.7
Purchases		2.8			—			2.8
Sales		(0.1		)	—			(0.1		)
Settlements		(4.5		)	(5.4		)	(9.9		)
Balance at the end of the period		$	1.1		$	(6.5	)	$	(5.4	)
Unrealized gains and losses on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through cost of sales on the statements of income.
Fair Value of Financial Instruments
The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:
		31-Dec-14						31-Dec-13
(Millions)		Carrying Amount			Fair Value			Carrying Amount			Fair Value
Long-term debt		$	3,081.30		$	3,271.40		$	3,056.20		$	3,031.60
Preferred stock of subsidiary		51.1			51.8			51.1			61.2

REGULATORY_ENVIRONMENT

REGULATORY ENVIRONMENT	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
REGULATORY ENVIRONMENT	Regulatory Environment
	Wisconsin
	2015 Rates
	In December 2014, the PSCW issued a final written order for WPS, effective January 1, 2015. It authorized a net retail electric rate increase of $24.6 million and a net retail natural gas rate decrease of $15.4 million, reflecting a 10.20% return on common equity. The order also included a common equity ratio of 50.28% in WPS's regulatory capital structure. The PSCW approved a change in rate design for WPS, which includes higher fixed charges to better match the related fixed costs of providing service. The retail electric rate increase included recovery of 2013 deferred costs related to the acquisition of the Fox Energy Center. WPS also received approval from the PSCW to defer and amortize the undepreciated book value of the retired plant associated with Pulliam 5 and 6 and Weston 1 starting with the actual retirement date in 2015 and concluding when the balance is fully amortized. See Note 17, Commitments and Contingencies, for more information. In addition, the PSCW will allow escrow treatment for ATC and MISO network transmission expenses for 2015 and 2016. This allows WPS to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a two percent tolerance window. The retail natural gas rate decrease included a refund to customers in 2015 of the 2013 decoupling over-collections.
	2014 Rates
	In December 2013, the PSCW issued a final written order for WPS, 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% return on common equity. The order also included a common equity ratio of 50.14% in WPS's regulatory capital structure. The retail electric rate impact consisted of a rate increase, including recovery of the difference between the 2012 fuel refund and the 2013 rate increase discussed below, 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, as discussed below. 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 17, Commitments and Contingencies, for more information. Additionally, the order required WPS to terminate its decoupling mechanism, beginning January 1, 2014.
	2013 Rates
	In December 2012, the PSCW issued a final written order for WPS, effective January 1, 2013. The order included a $28.5 million retail electric rate increase, partially offset by the actual 2012 fuel refund of $20.5 million. The difference between the 2012 fuel refund and the rate increase was deferred for recovery in 2014 rates. As a result, there was no change to customers' 2013 retail electric rates. The order also included a $3.4 million retail natural gas rate decrease. The order reflected a 10.30% return on common equity and a common equity ratio of 51.61% in WPS's regulatory capital structure. The rate changes included deferrals of $7.3 million for retail electric and $2.1 million for retail natural gas of pension and other employee benefit costs that are being recovered in 2014 rates. In addition, WPS was authorized recovery of $5.9 million related to income tax amounts previously expensed due to the Federal Health Care Reform Act. As a result, this amount was recorded as a regulatory asset in 2012, and recovery from customers began in 2013. The order also authorized the recovery of direct Cross State Air Pollution Rule costs incurred through the end of 2012. Lastly, the order authorized WPS to switch from production tax credits to Section 1603 Grants for the Crane Creek wind project.
	A decoupling mechanism for natural gas and electric residential and small commercial and industrial customers was approved on a pilot basis as part of the order. The mechanism was based on total rate case-approved margins, rather than being calculated on a per-customer basis. The mechanism did not cover all customer classes, and it included an annual $14.0 million cap for electric service and an annual $8.0 million cap for natural gas service. Amounts recoverable from or refundable to customers were subject to these caps.
	Michigan
	2015 WPS Rate Case
	In October 2014, WPS filed an application with the MPSC to increase retail electric rates $5.7 million, with interim rates expected to be effective in April 2015. WPS's request reflected a 10.60% return on common equity and a target common equity ratio of 50.48% in WPS's regulatory capital structure. The proposed retail electric rate increase was primarily driven by 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 generating plants. Expenses are expected to increase for line clearance, customer relations, uncollectible expenses, injuries and damages, and general inflation. The proposal included annual rate increases to be implemented over a three-year period.
	2014 MGU Rates
	In November 2013, the MPSC issued a final written order for MGU, effective January 1, 2014. The order authorized a retail natural gas rate increase of $4.5 million. The rates reflect a 10.25% return on common equity and a common equity ratio of 48.62% in MGU's regulatory capital structure. Additionally, the order required MGU to terminate its decoupling mechanism after December 31, 2013, and replace it with a new decoupling mechanism based on total margins, beginning January 1, 2015. The new decoupling mechanism does not cover variations in volumes due to actual weather being different from rate case-assumed weather. The rate order also terminated MGU's uncollectible expense true-up mechanism after December 31, 2013.
	MGU Depreciation Case
	In January 2013, the Michigan Court of Appeals issued an order reversing the MPSC's 2010 disallowance of $2.5 million associated with the early retirement of certain MGU assets. As a result, a $2.5 million reduction to depreciation expense was recorded in the first quarter of 2013. In June 2013, the MPSC issued an order related to MGU's most recent depreciation case. This order also approved a settlement agreement reflecting recovery of these previously disallowed costs.
	2014 UPPCO Rates
	In December 2013, the MPSC issued a final written order for UPPCO, effective January 1, 2014. The order authorized a retail electric rate increase of $5.8 million. The rates reflected a 10.15% return on common equity and a common equity ratio of 56.74% in UPPCO's regulatory capital structure. The order required UPPCO to terminate its decoupling mechanism after December 31, 2013. In addition, the order required UPPCO to achieve certain minimum line clearance performance metrics for recovery of costs related to clearing trees and other natural obstructions away from power lines.
	Illinois
	2015 Rates
	In January 2015, the ICC issued a final written order for PGL and NSG, effective January 28, 2015. The order authorized a retail natural gas rate increase of $74.8 million for PGL and $3.7 million for NSG. In February 2015, the ICC filed an amendatory order that revised the increases to $71.1 million for PGL and $3.5 million for NSG, effective February 26, 2015, to reflect the extension of bonus depreciation in 2014. The rates for PGL reflected a 9.05% return on common equity and a common equity ratio of 50.33% in PGL's regulatory capital structure. The rates for NSG reflected a 9.05% return on common equity and a common equity ratio of 50.48% in NSG's regulatory capital structure. The rate orders allowed PGL and NSG to continue the use of their decoupling mechanisms and uncollectible expense true-up mechanisms. In addition, PGL plans to recover a return on certain investments and depreciation expense through the Qualifying Infrastructure Plant rider discussed below, and accordingly, such costs are not subject to PGL's rate order. In February 2015, the Attorney General and certain intervenors filed requests for rehearing on certain issues, which the ICC will rule on in March 2015.
	Qualifying Infrastructure Plant Rider
	In July 2013, Illinois Public Act 98-0057 (formerly Senate Bill 2266), The Natural Gas Consumer, Safety & Reliability Act, became law. The Act gave PGL a cost recovery mechanism for prudently incurred costs to upgrade Illinois natural gas infrastructure that are collected through a surcharge on customer bills. This Act eliminated a requirement for PGL and NSG to file biennial rate proceedings under existing Illinois coal-to-gas legislation. In September 2013, PGL filed with the ICC requesting the proposed rider, which was approved in January 2014 and became effective on January 1, 2014.
	2013 Rates
	In June 2013, the ICC issued a final written order for PGL and NSG, effective June 27, 2013. The order authorized a retail natural gas rate increase of $57.2 million for PGL and $6.6 million for NSG. The rates for PGL reflected a 9.28% return on common equity and a common equity ratio of 50.43% in PGL's regulatory capital structure. The rates for NSG reflected a 9.28% return on common equity and a common equity ratio of 50.32% in NSG's regulatory capital structure. The rate order also allowed PGL and NSG to continue the use of their decoupling mechanisms, as affirmed by the Illinois Supreme Court. In addition, the ICC is required to conduct an investigation to monitor the costs and progress of the AMRP.
	In August 2013, the ICC granted certain rehearing requests on tax-related issues filed by PGL, NSG, and other intervenors. PGL and NSG asked for a correction of the revenue requirement for deferred tax assets related to tax net operating losses (NOLs) incurred in 2012 and 2013. In the ICC’s order, these deferred tax assets were included in rate base, but computational errors were made. Other intervenors requested the exclusion from rate base of the deferred tax asset related to the 2012 tax NOL. The tax NOLs in question resulted from PGL and NSG claiming accelerated depreciation deductions in 2012 and 2013. In December 2013, the ICC evaluated and approved a correction of the computational errors and rejected the intervenors' proposed exclusion of the 2012 tax NOL. Customer rates were increased by $2.6 million for PGL and $0.1 million for NSG for the impact of this correction, effective January 1, 2014. In January 2014, the Illinois Attorney General and Citizens Utility Board each filed an appeal with the Illinois Appellate Court (Court). In January 2015, the Citizens Utility Board filed to withdraw its appeal, and the Illinois Attorney General requested an extension of the briefing schedule.
	2012 Decoupling
	The ICC issued a final written order, effective January 21, 2012, which approved a permanent decoupling mechanism for PGL and NSG. The Illinois Attorney General and Citizens Utility Board appealed to the Court the ICC's authority to approve PGL's and NSG's decoupling mechanisms and filed a motion to stay the implementation of the permanent decoupling mechanisms or make collections subject to refund. In May 2012, the ICC issued a revised amendatory order granting the Illinois Attorney General's motion to make revenues collected under the permanent decoupling mechanisms subject to refund. Refunds would have been required if the Court found that the ICC did not have authority to approve decoupling and ordered a refund. As a result, the recovery of amounts related to decoupling in 2012 were uncertain, and PGL and NSG established offsetting reserves equal to decoupling amounts accrued. In March 2013, the Court issued an opinion that affirmed the ICC's order approving the permanent decoupling mechanisms. As a result, the reserves recorded in 2012 were reversed in the first quarter of 2013. PGL's and NSG's permanent decoupling mechanism was in place for 2013. In June 2013, the Illinois Attorney General and Citizens Utility Board petitioned the Illinois Supreme Court to appeal the Court's decision. In January 2015, the Illinois Supreme Court affirmed the ICC's authority to approve the permanent decoupling mechanism. As a result, decoupling amounts recorded in 2014 will be refunded to customers in 2015 as planned, and decoupling amounts in the future will continue to be accrued.
	Minnesota
	2014 Rates
	In October 2014, the MPUC issued a final written order, which is expected to become effective in the first half of 2015. The order authorized a retail natural gas rate increase of $7.6 million. The rates reflected a 9.35% return on common equity and a common equity ratio of 50.31% in MERC's regulatory capital structure. The order allows for a deferral of customer billing system costs, for which the recovery will be requested in a future rate case. A decoupling mechanism with a 10% cap will remain in effect for MERC's residential and small commercial and industrial customers. The final approved rate increase was lower than the interim rates collected from customers during 2014. Therefore, as of December 31, 2014, $3.1 million is estimated to be refunded to customers during 2015.
	2011 Rates Finalized in 2013
	In July 2012, the MPUC approved a final written order, effective January 1, 2013. The order authorized a retail natural gas rate increase of $11.0 million. The rates reflected a 9.70% return on common equity and a common equity ratio of 50.48% in MERC's regulatory capital structure. In addition, the order set recovery of MERC's 2011 test-year pension expense at 2010 levels. The MPUC also approved a decoupling mechanism for MERC that covers residential and small commercial and industrial customers on a three-year trial basis, effective January 1, 2013. The decoupling mechanism does not adjust for variations in volumes resulting from changes in customer count compared to rate case levels. It includes an annual 10% cap based on distribution revenues approved in the rate case. Amounts recoverable from or refundable to customers are subject to this cap.

MISCELLANEOUS_INCOME

MISCELLANEOUS INCOME	12 Months Ended
	Dec. 31, 2014
Other Income and Expenses [Abstract]
MISCELLANEOUS INCOME	Miscellaneous Income
	Total miscellaneous income was as follows at December 31:
	(Millions)	2014		2013		2012
	Equity portion of AFUDC	$	12.5	$	10.8	$	2.9
	Federal excise tax credit	4.4		4.1		—
	Gain on sale of land at the holding company	3.5		—		—
	Key executive life insurance income for retired employees	2.9		2.2		2.6
	Gains on exchange-traded funds	2.9		2.2		1.3
	Other	4.8		2.6		2.2
	Total miscellaneous income	$	31	$	21.9	$	9

VARIABLE_INTEREST_ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
	Dec. 31, 2014
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract]
VARIABLE INTEREST ENTITIES	Variable Interest Entities
	In 2012, ITF formed AMP Trillium LLC as a joint venture with AMP Americas LLC. This joint venture was established to own and operate compressed natural gas (CNG) fueling stations. ITF owns 30% and AMP Americas LLC owns 70% of the joint venture. At December 31, 2013, ITF was the primary beneficiary of this variable interest entity, and, as a result, we consolidated the assets, liabilities, and statements of income of the joint venture. However, in April 2014, ITF and AMP Americas LLC restructured this joint venture. Due to the restructuring, our influence over the activities that most significantly impact the variable interest entity's economic performance decreased. We determined that ITF is no longer the primary beneficiary of this variable interest entity and that we are no longer required to consolidate the joint venture. Therefore, we started accounting for this variable interest entity as an equity method investment in April 2014. At December 31, 2014, and December 31, 2013, our variable interests in the joint venture included an equity investment and receivables. See Note 10, Equity Method Investments, for more information. Our maximum exposure to loss as a result of this joint venture was not significant. In November 2014, ITF sold eight CNG fueling stations to AMP Trillium LLC. See Note 4, Dispositions, for more information.
	In 2013, ITF formed EVO Trillium LLC as a joint venture with Environmental Alternative Fuels LLC. ITF owns 15% and Environmental Alternative Fuels LLC owns 85% of the joint venture. This joint venture was established to own and operate CNG fueling stations. We determined that this joint venture is a variable interest entity but that consolidation is not required since we are not its primary beneficiary, as we do not have the power to direct its activities. We instead account for this variable interest entity as an equity method investment. At December 31, 2014, and December 31, 2013, the assets and liabilities on our balance sheets related to our involvement with this variable interest entity consisted of insignificant receivables and payables. Our maximum exposure to loss as a result of involvement with this variable interest entity was also not significant.

SEGMENTS_OF_BUSINESS

SEGMENTS OF BUSINESS	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
SEGMENTS OF BUSINESS	Segments of Business
	At December 31, 2014, we had four segments related to our continuing operations and one segment related to the discontinued operations of IES's retail energy business. Our reportable segments are described below.
	•	The natural gas utility segment includes the natural gas utility operations of MERC, MGU, NSG, PGL, and WPS.
	•	The electric utility segment includes the electric utility operations of UPPCO and WPS. In August 2014, we sold UPPCO to Balfour Beatty Infrastructure Partners LP. See Note 4, Dispositions, for more information on the sale of UPPCO.
	•	The electric transmission investment segment includes our approximate 34% ownership interest in ATC. ATC is a federally regulated electric transmission company.
	•	The IES segment includes the nonregulated energy operations of IES's retail energy business. Since we sold IES's retail energy business in November 2014, this segment only includes discontinued operations. See Note 4, Dispositions, for more information on the sale of IES's retail energy business. The remaining energy asset business, PDI, was reclassified to the holding company and other segment.
	•	The holding company and other segment includes the operations of the Integrys Energy Group holding company, ITF, PDI, and the PELLC holding company, along with any nonutility activities at IBS, MERC, MGU, NSG, PGL, UPPCO, and WPS.
	All of our operations and assets are located within the United States. The tables below present information related to our reportable segments:
			Regulated Operations											Nonutility and Nonregulated Operations
	2014 (Millions)		Natural Gas			Electric			Electric		Total			IES		Holding			Reconciling			Integrys
			Utility			Utility			Transmission		Regulated					Company			Eliminations			Energy Group
									Investment		Operations					and Other						Consolidated
	Income Statement
	External revenues		$	2,748.00		$	1,286.30		$	—	$	4,034.30		$	—	$	109.9		$	—		$	4,144.20
	Intersegment revenues		12.4			0.1			—		12.5			—		1.4			(13.9		)	—
	Depreciation and amortization expense		149			103			—		252			—		36			(0.5		)	287.5
	Merger transaction costs		—			—			—		—			—		10.4			—			10.4
	Gain on sale of UPPCO, net of transaction costs		—			(85.4		)	—		(85.4		)	—		—			—			(85.4		)
	Gain on abandonment of PDI's Winnebago Energy Center		—			—			—		—			—		(5.0		)	—			(5.0		)
	Earnings from equity method investments		—			—			85.7		85.7			—		2.6			—			88.3
	Miscellaneous income		1.9			11.1			—		13			—		29.8			(11.8		)	31
	Interest expense		54.4			47.4			—		101.8			—		64.8			(11.8		)	154.8
	Provision (benefit) for income taxes		65.6			103.3			34.4		203.3			—		(9.9		)	—			193.4
	Net income (loss) from continuing operations		100.7			166.3			51.3		318.3			—		(40.2		)	—			278.1
	Discontinued operations		—			—			—		—			0.4		1.4			—			1.8
	Preferred stock dividends of subsidiary		(0.5		)	(2.6		)	—		(3.1		)	—		—			—			(3.1		)
	Noncontrolling interest in subsidiaries		—			—			—		—			—		0.1			—			0.1
	Net income (loss) attributed to common shareholders		100.2			163.7			51.3		315.2			0.4		(38.7		)	—			276.9
	Total assets		6,292.50			3,506.90			536.7		10,336.10			—		1,638.10			(692.2		)	11,282.00
	Cash expenditures for long-lived assets		456.5			286.6			—		743.1			0.9		121			—			865
			Regulated Operations											Nonutility and Nonregulated Operations
	2013 (Millions)		Natural Gas Utility			Electric			Electric		Total			IES		Holding			Reconciling			Integrys
						Utility			Transmission		Regulated					Company			Eliminations			Energy Group
									Investment		Operations					and Other						Consolidated
	Income Statement
	External revenues		$	2,094.10		$	1,332.00		$	—	$	3,426.10		$	—	$	59.4		$	—		$	3,485.50
	Intersegment revenues		10.9			0.1			—		11			—		1.4			(12.4		)	—
	Depreciation and amortization expense		136			98.6			—		234.6			—		29.3			(0.5		)	263.4
	Earnings from equity method investments		—			—			89.1		89.1			—		2.4			—			91.5
	Miscellaneous income		1.2			9.8			—		11			—		23.3			(12.4		)	21.9
	Interest expense		50.2			36.4			—		86.6			—		53.2			(12.4		)	127.4
	Provision (benefit) for income taxes		78.9			67.3			35.2		181.4			—		(23.4		)	—			158
	Net income (loss) from continuing operations		124			113.4			53.9		291.3			—		(23.8		)	—			267.5
	Discontinued operations		—			—			—		—			82.5		4.8			—			87.3
	Preferred stock dividends of subsidiary		(0.6		)	(2.5		)	—		(3.1		)	—		—			—			(3.1		)
	Noncontrolling interest in subsidiaries		—			—			—		—			—		0.1			—			0.1
	Net income (loss) attributed to common shareholders		123.4			110.9			53.9		288.2			82.5		(18.9		)	—			351.8
	Total assets		5,672.00			3,514.40			508.5		9,694.90			815.4		1,519.70			(786.5		)	11,243.50
	Cash expenditures for long-lived assets		370			615			—		985			2.6		73.2			—			1,060.80
			Regulated Operations											Nonutility and Nonregulated Operations
	2012 (Millions)		Natural Gas Utility			Electric			Electric		Total			IES		Holding			Reconciling			Integrys
						Utility			Transmission		Regulated					Company			Eliminations			Energy Group
									Investment		Operations					and Other						Consolidated
	Income Statement
	External revenues		$	1,662.70		$	1,297.40		$	—	$	2,960.10		$	—	$	52.8		$	—		$	3,012.90
	Intersegment revenues		9.3			—			—		9.3			—		1.9			(11.2		)	—
	Depreciation and amortization expense		131.8			89			—		220.8			—		27			(0.5		)	247.3
	Earnings from equity method investments		—			—			85.3		85.3			—		1.9			—			87.2
	Miscellaneous income		0.6			2.6			—		3.2			—		19.9			(14.1		)	9
	Interest expense		47.3			35.9			—		83.2			—		49.8			(14.1		)	118.9
	Provision (benefit) for income taxes		61.4			49.4			32.9		143.7			—		(25.8		)	—			117.9
	Net income (loss) from continuing operations		94			110.4			52.4		256.8			—		(17.9		)	—			238.9
	Discontinued operations		—			—			—		—			55.1		(9.7		)	—			45.4
	Preferred stock dividends of subsidiary		(0.6		)	(2.5		)	—		(3.1		)	—		—			—			(3.1		)
Noncontrolling interest in subsidiaries		—			—			—		—			—		0.2			—			0.2
Net income (loss) attributed to common shareholders		93.4			107.9			52.4		253.7			55.1		(27.4		)	—			281.4
Total assets		5,446.20			3,041.30			476.6		8,964.10			493.7		1,523.30			(653.7		)	10,327.40
Cash expenditures for long-lived assets		375.1			163.9			—		539			2		53.4			—			594.4

QUARTERLY_FINANCIAL_INFORMATIO

QUARTERLY FINANCIAL INFORMATION (Unaudited)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)	Quarterly Financial Information (Unaudited)
	In November 2014, we sold IES's retail energy business to Exelon Generation Company, LLC. See Note 4, Dispositions, for more information. Due to the sale, certain previously reported amounts have been retrospectively adjusted as IES's retail energy business has been reclassified to discontinued operations for all periods presented.
	Amounts reflecting IES's retail energy business in discontinued operations
	(Millions, except per share amounts)		First Quarter		Second Quarter			Third Quarter			Fourth Quarter			Total
	2014
	Operating revenues		$	1,638.00	$	836.8		$	657.1		$	1,012.30		$	4,144.20
	Operating income		232.3		23.2			134.6			116.9			507
	Net income from continuing operations		140.2		8.8			75.3			53.8			278.1
	Net income		153.1		8			84			34.8			279.9
	Net income attributed to common shareholders		152.4		7.2			83.3			34			276.9
	Earnings per common share (basic) *
	Net income from continuing operations		$	1.74	$	0.1		$	0.93		$	0.66		$	3.43
	Discontinued operations, net of tax		0.16		(0.01		)	0.11			(0.24		)	0.02
	Earnings per common share (basic)		1.9		0.09			1.04			0.42			3.45
	Earnings per common share (diluted) *
	Net income from continuing operations		1.73		0.1			0.91			0.66			3.41
	Discontinued operations, net of tax		0.16		(0.01		)	0.11			(0.24		)	0.02
	Earnings per common share (diluted)		1.89		0.09			1.02			0.42			3.43
	2013
	Operating revenues		$	1,136.40	$	708.1		$	622.2		$	1,018.80		$	3,485.50
	Operating income		211.8		56.1			41.5			130.1			439.5
	Net income from continuing operations		129.6		36.8			26.9			74.2			267.5
	Net income (loss)		188.3		(4.7		)	38.8			132.4			354.8
	Net income (loss) attributed to common shareholders		187.5		(5.4		)	38.1			131.6			351.8
	Earnings (loss) per common share (basic) *
	Net income from continuing operations		$	1.64	$	0.45		$	0.33		$	0.91		$	3.33
	Discontinued operations, net of tax		0.74		(0.52		)	0.15			0.73			1.1
	Earnings (loss) per common share (basic)		2.38		(0.07		)	0.48			1.64			4.43
	Earnings (loss) per common share (diluted) *
	Net income from continuing operations		1.63		0.45			0.32			0.91			3.3
	Discontinued operations, net of tax		0.74		(0.52		)	0.15			0.72			1.09
	Earnings (loss) per common share (diluted)		2.37		(0.07		)	0.47			1.63			4.39
	*	Earnings per share for the individual quarters do not total the year ended earnings per share amount because of changes to the average number of shares outstanding and changes in incremental issuable shares throughout the year.
	Previously reported amounts reflecting IES's retail energy business in continuing operations
	(Millions, except per share amounts)		First Quarter		Second Quarter			Third Quarter			Fourth Quarter			Total
	2014
	Operating revenues		$	2,924.90	$	1,432.60		$	1,187.90		N/A			N/A
	Operating income		253.2		26.1			146.9			N/A			N/A
	Net income from continuing operations		153.2		8.1			82.9			N/A			N/A
	Net income		153.1		8			84			N/A			N/A
	Net income attributed to common shareholders		152.4		7.2			83.3			N/A			N/A
	Earnings per common share (basic) *
	Net income from continuing operations		$	1.9	$	0.09		$	1.03		N/A			N/A
	Discontinued operations, net of tax		—		—			0.01			N/A			N/A
	Earnings per common share (basic)		1.9		0.09			1.04			N/A			N/A
	Earnings per common share (diluted) *
	Net income from continuing operations		1.89		0.09			1.01			N/A			N/A
	Discontinued operations, net of tax		—		—			0.01			N/A			N/A
	Earnings per common share (diluted)		1.89		0.09			1.02			N/A			N/A
	2013
	Operating revenues		$	1,678.20	$	1,116.00		$	1,129.70		$	1,710.70		$	5,634.60
	Operating income (loss)		293.1		(6.9		)	55.3			226.2			567.7
	Net income (loss) from continuing operations		182.2		(3.9		)	39.4			132.3			350
	Net income (loss)		188.3		(4.7		)	38.8			132.4			354.8
	Net income (loss) attributed to common shareholders		187.5		(5.4		)	38.1			131.6			351.8
	Earnings (loss) per common share (basic) *
	Net income (loss) from continuing operations		$	2.3	$	(0.06	)	$	0.49		$	1.64		$	4.37
	Discontinued operations, net of tax		0.08		(0.01		)	(0.01		)	—			0.06
	Earnings (loss) per common share (basic)		2.38		(0.07		)	0.48			1.64			4.43
	Earnings (loss) per common share (diluted) *
	Net income (loss) from continuing operations		2.29		(0.06		)	0.48			1.63			4.33
	Discontinued operations, net of tax		0.08		(0.01		)	(0.01		)	—			0.06
	Earnings (loss) per common share (diluted)		2.37		(0.07		)	0.47			1.63			4.39
	*	Earnings per share for the individual quarters do not total the year ended earnings per share amount because of changes to the average number of shares outstanding and changes in incremental issuable shares throughout the year.
Because of various factors, the quarterly results of operations are not necessarily comparable.

SCHEDULE_I_CONDENSED_PARENT_CO

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
CONDENSED PARENT COMPANY FINANCIAL STATEMENTS	SCHEDULE I - CONDENSED
	PARENT COMPANY FINANCIAL STATEMENTS
	INTEGRYS ENERGY GROUP, INC. (PARENT COMPANY ONLY)
	A. STATEMENTS OF INCOME
	Year Ended December 31
	(Millions, except per share data)	2014			2013			2012
	Merger transaction costs	$	10.4		$	—		$	—
	Operating expense	10.6			8.2			6
	Gain on sale of UPPCO, net of transaction costs	(85.4		)	—			—
	Operating income (loss)	64.4			(8.2		)	(6.0		)
	Equity earnings from subsidiaries	303.8			314.6			277.3
	Miscellaneous income	23.5			18.5			21.2
	Interest expense	63.8			52.1			50
	Other income	263.5			281			248.5
	Income before taxes	327.9			272.8			242.5
	Provision for income taxes	52.8			8.3			6.5
	Net income from continuing operations	275.1			264.5			236
	Discontinued operations from Parent Company, net of tax	(18.9		)	0.6			1.4
	Discontinued operations from subsidiaries, net of tax	20.7			86.7			44
	Net income attributed to common shareholders	$	276.9		$	351.8		$	281.4
	Average shares of common stock
	Basic	80.2			79.5			78.6
	Diluted	80.7			80.1			79.3
	Earnings per common share (basic)
	Net income from continuing operations	$	3.43		$	3.33		$	3
	Discontinued operations, net of tax	0.02			1.1			0.58
	Earnings per common share (basic)	$	3.45		$	4.43		$	3.58
	Earnings per common share (diluted)
	Net income from continuing operations	$	3.41		$	3.3		$	2.98
	Discontinued operations, net of tax	0.02			1.09			0.57
	Earnings per common share (diluted)	$	3.43		$	4.39		$	3.55
	The accompanying notes to the Parent Company financial statements are an integral part of these statements.
	B. STATEMENTS OF COMPREHENSIVE INCOME
	Year Ended December 31
	(Millions)	2014			2013			2012
	Net income attributed to common shareholders	$	276.9		$	351.8		$	281.4
	Other comprehensive income, net of tax:
	Cash flow hedges
	Unrealized net gains (losses) arising during period, net of tax of $ - million, $ - million, and $0.1 million, respectively	—			0.6			(0.1		)
	Reclassification of net (gains) losses to net income, net of tax of $1.2 million, $2.0 million, and $(1.0) million, respectively	(0.1		)	(0.9		)	2.1
	Cash flow hedges, net	(0.1		)	(0.3		)	2
	Defined benefit plans
	Pension and other postretirement benefit adjustments arising during period, net of tax of $(5.5) million, $ - million, and $(0.9) million, respectively	(9.6		)	1.1			0.9
	Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $0.2 million, $0.9 million, and $0.4 million, respectively	0.3			(0.5		)	(0.1		)
	Defined benefit pension plans, net	(9.3		)	0.6			0.8
	Other comprehensive income (loss) from subsidiaries, net of tax	5			17.4			(1.2		)
	Other comprehensive income (loss), net of tax	(4.4		)	17.7			1.6
	Comprehensive income attributed to common shareholders	$	272.5		$	369.5		$	283
	The accompanying notes to the Parent Company financial statements are an integral part of these statements.
	C. BALANCE SHEETS
	At December 31
	(Millions)	2014			2013
	Assets
	Cash and cash equivalents	$	5.1		$	0.3
	Accounts receivable from related parties	31.2			32.2
	Interest receivable from related parties	4.8			4.1
	Deferred income taxes	0.4			0.6
	Notes receivable from related parties	51.6			84.9
	Current portion of long-term notes receivable from related parties	2.5			10
	Other current assets	49.1			47.8
	Current assets	144.7			179.9
	Total investments in subsidiaries, at equity	4,015.10			4,268.50
	Notes receivable from related parties	180.9			224.3
	Property and equipment, net of accumulated depreciation of $1.2 and $1.4, respectively	4.3			4.5
Receivables from related parties	19.2			18.3
Deferred income taxes	9.6			22.3
Other long-term assets	181.2			43.9
Total assets	$	4,555.00		$	4,761.70
Liabilities and Equity
Short-term notes payable to related parties	$	126.2		$	165.7
Short-term debt	7.2			123.2
Current portion of long-term debt	—			100
Accounts payable to related parties	5.8			0.9
Accounts payable	2.8			1.2
Deferred income taxes	6.2			6.4
Other current liabilities	43.2			2.8
Current liabilities	191.4			400.2
Long-term debt	974.7			974.7
Deferred income taxes	56.9			110.1
Other long-term liabilities	32.3			15.4
Long-term liabilities	1,063.90			1,100.20
Total common shareholders' equity	3,299.70			3,261.30
Total liabilities and equity	$	4,555.00		$	4,761.70
The accompanying notes to the Parent Company financial statements are an integral part of these statements.
D. STATEMENTS OF CASH FLOWS
Year Ended December 31
(Millions)	2014			2013			2012
Operating Activities
Net income attributed to common shareholders	$	276.9		$	351.8		$	281.4
Adjustments to reconcile net income to net cash provided by operating activities
Equity earnings from subsidiaries	(324.5		)	(401.3		)	(321.3		)
Dividends from subsidiaries	176.5			169.6			163.9
Deferred income taxes and investment tax credits	(46.0		)	26.3			11
Gain on sale of UPPCO	(86.5		)	—			—
Loss on sale of IES's retail energy business	24.3			—			—
Gain on sale of other assets	(4.0		)	—			—
Other	4.9			2.8			(3.7		)
Changes in working capital
Accounts receivable	0.7			(0.7		)	0.4
Accounts receivable from related parties	0.5			0.6			1
Other current assets	12.5			(7.9		)	29
Accounts payable	1.6			0.6			(0.5		)
Accounts payable to related parties	2.6			(0.2		)	(0.4		)
Other current liabilities	27.6			(2.4		)	0.9
Net cash provided by operating activities	67.1			139.2			161.7
Investing Activities
Short-term notes receivable from related parties	33.3			(50.4		)	(12.1		)
Issuance of long-term notes receivable to related parties	(20.0		)	(35.0		)	—
Repayment of long-term notes receivable from related parties	71.5			44.5			1.3
Equity contributions to subsidiaries	(218.4		)	(234.6		)	(89.9		)
Return of capital from subsidiaries	52.5			75			110.5
Proceeds from the sale of UPPCO	336.7			—			—
Proceeds from the sale of IES's retail energy business	319.2			—			—
Proceeds from the sale of other assets	4.1			—			—
Rabbi trust funding related to potential change in control	(115.5		)	—			—
Net cash provided by (used for) investing activities	463.4			(200.5		)	9.8
Financing Activities
Commercial paper, net	(116.0		)	(85.2		)	115.8
Short-term notes payable to related parties	(45.1		)	(92.3		)	76.2
Repayment of long-term notes payable to related parties	—			—			(21.0		)
Issuance of long-term debt	—			400			—
Repayment of long-term debt	(100.0		)	—			(100.0		)
Proceeds from stock option exercises	85.8			38.7			55.8
Shares purchased for stock-based compensation	(127.6		)	—			(75.3		)
Issuance of common stock	2.4			19.2			—
Dividends paid on common stock	(216.3		)	(202.6		)	(211.9		)
Other	(8.9		)	(18.8		)	(10.4		)
Net cash (used for) provided by financing activities	(525.7		)	59			(170.8		)
Net change in cash and cash equivalents	4.8			(2.3		)	0.7
Cash and cash equivalents at beginning of year	0.3			2.6			1.9
Cash and cash equivalents at end of year	$	5.1		$	0.3		$	2.6
Cash paid for interest	$	59.4		$	44.4		$	44.4
Cash paid for interest – related parties	0.4			0.7			1.4
Cash paid (received) for income taxes	40.2			(3.0		)	(24.1		)
The accompanying notes to the Parent Company financial statements are an integral part of these statements.
SCHEDULE I - CONDENSED
PARENT COMPANY FINANCIAL STATEMENTS
INTEGRYS ENERGY GROUP, INC. (PARENT COMPANY ONLY)
E. NOTES TO PARENT COMPANY FINANCIAL STATEMENTS
SUPPLEMENTAL NOTES
Note 1—Summary of Significant Accounting Policies
(a) Basis of Presentation—For Parent Company only presentation, investments in subsidiaries are accounted for using the equity method. The condensed Parent Company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of Integrys Energy Group appearing in this Annual Report on Form 10-K. The consolidated income statements of Integrys Energy Group reflect certain businesses as discontinued operations. The condensed Parent Company income statements also report the earnings of these businesses as discontinued operations.
(b) Cash and Cash Equivalents—Short-term investments with an original maturity of three months or less are reported as cash equivalents.
Note 2—Cash and Cash Equivalents
Significant noncash transactions were:
(Millions)	2014			2013			2012
Equity issued for reinvested dividends	$	—		$	12		$	—
Equity issued for stock-based compensation plans	—			16.3			—
The issuance of common stock line item on the Parent Company statements of cash flows does not equal the issuance of common stock line item on the Integrys Energy Group consolidated statements of cash flows. The Parent Company received cash from its subsidiaries and issued common stock to its subsidiaries' employees to facilitate the employee stock ownership plan. These intercompany amounts were eliminated on the Integrys Energy Group consolidated statements of cash flows.
Note 3—Fair Value of Financial Instruments – Related Parties
The following table shows the financial instruments included on the balance sheets of the Parent Company that are not recorded at fair value:
	2014						2013
(Millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Long-term notes receivable from related parties	$	180.9		$	195		$	224.3		$	238.5
Current portion of long-term notes receivable from related parties	2.5			2.8			10			10.2
Note 4—Short-Term Notes Receivable – Related Parties
(Millions)	2014			2013
IES	$	—		$	23.5
MGU	26.1			21.8
MERC	11.1			20.5
IBS	14.4			10.2
UPPCO	—			8.9
Total	$	51.6		$	84.9
Note 5—Long-Term Notes Receivable – Related Parties
(Millions)	Series		Year Due	2014			2013
WPS Leasing	8.76%		2015	$	2		$	2.4
	7.35%		2016	3.4			3.9
UPPCO	6.06%		2017	—			15
	3.35%		2018	—			10
	5.04%		2020	—			15
	3.99%		2023	—			20
MERC	6.16%		2016	29			29
	6.40%		2021	29			29
	3.99%		2023	29			29
	3.57%		2024	20			—
MGU	5.76%		2016	28			28
	5.98%		2021	28			28
	3.00%		2023	15			15
IBS	6.87%		2014	—			10
Total notes receivable – related parties				$	183.4		$	234.3
Less current portion				$	2.5		$	10
Total long-term notes receivable – related parties				$	180.9		$	224.3
Note 6—Short-term Notes Payable – Related Parties
(Millions)	2014			2013
PELLC	$	43.5		$	165.7
ITF	8.6			—
PDI	74.1			—
Total	$	126.2		$	165.7

SCHEDULE_II_VALUATION_AND_QUAL

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS	12 Months Ended
	Dec. 31, 2014
Valuation and Qualifying Accounts [Abstract]
Valuation and Qualifying Accounts	SCHEDULE II
	INTEGRYS ENERGY GROUP, INC.
	VALUATION AND QUALIFYING ACCOUNTS
	Allowance for Doubtful Accounts
	Years Ended December 31, 2014, 2013, and 2012
	(In Millions)
					Additions (Subtractions)
	Fiscal Year		Balance at Beginning of Year		Charged to Expense		Charged to Other Accounts (1)		Deductions (2)			Balance at End of Year
	2012		$	42.5	$	25.9	$	4	$	(31.3	)	$	41.1
	2013		$	41.1	$	33.7	$	5.5	$	(32.6	)	$	47.7
	2014		$	47.7	$	50.3	$	8	$	(42.7	)	$	63.3
	(1)	Represents additions (subtractions) charged to regulatory assets and amounts charged to tax liabilities related to revenue taxes and state use taxes uncollectible from customers.
	(2)	Represents amounts written off to the reserve, including any adjustments.

SUMMARY_OF_SIGNIFICANT_ACCOUNT1

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Nature of operations	(a) Nature of Operations—We are an energy holding company whose primary wholly owned subsidiaries at December 31, 2014, included MERC, MGU, NSG, PGL, WPS, IBS, ITF, and PDI. Of these subsidiaries, five are natural gas and/or electric utilities (MERC, MGU, NSG, PGL, and WPS). IBS is a centralized service company, ITF is a nonregulated compressed natural gas fueling business, and PDI is a nonregulated distributed solar energy company. In addition, we have an approximate 34% interest in ATC.
	In August 2014, we sold UPPCO, and, in November 2014, we sold IES's retail energy business. See Note 4, Dispositions, for more information on these sales.
Basis of presentation	(b) Basis of Presentation—As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the consolidated statements of income, consolidated statements of comprehensive income, consolidated balance sheets, consolidated statements of equity, and consolidated statements of cash flows, unless otherwise noted.
	The financial statements include our accounts and the accounts of all of our majority owned subsidiaries, after eliminating intercompany transactions and balances. These financial statements also reflect our proportionate interests in certain jointly owned utility facilities. 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 businesses 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. See Note 10, Equity Method Investments, for more information.
Reclassifications	(c) Reclassifications—The assets and liabilities associated with the sale of UPPCO and the sale of eight ITF compressed natural gas fueling stations were reclassified to held for sale on our December 31, 2013, balance sheet. The assets and liabilities related to the sale of IES's retail energy business were reclassified as assets and liabilities of discontinued operations on our December 31, 2013, balance sheet. In addition, the operations of IES's retail energy business were reclassified to discontinued operations on our income statements for the years ended December 31, 2013, and 2012. See Note 4, Dispositions, for more information on these sales.
Use of estimates	(d) Use of Estimates—We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect assets, 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	(e) Cash and Cash Equivalents—Short-term investments with an original maturity of three months or less are reported as cash equivalents.
Revenue and Customer Receivables	(f) Revenues and Customer Receivables—Revenues related to the sale of energy are recognized when service is provided or energy is delivered to customers. We accrue estimated amounts of revenues for services provided or energy delivered but not yet billed to customers. Estimated unbilled revenues are calculated using a variety of judgments and assumptions related to customer class, contracted rates, weather, and customer use. At December 31, 2014 and 2013, our unbilled revenues were $269.4 million and $286.4 million, respectively.
	We present revenues net of pass-through taxes on the income statements.
	Below is a summary of the significant mechanisms our utility subsidiaries had in place in 2014 that allowed them to recover or refund changes in prudently incurred costs from rate case-approved amounts:
	•	Fuel and purchased power costs were recovered from customers on a one-for-one basis by UPPCO, WPS's wholesale electric operations, and WPS's Michigan retail electric operations.
	•	WPS's Wisconsin retail electric operations used a "fuel window" mechanism to recover fuel and purchased power costs. Under the fuel window rule, a deferral is required for 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. WPS monitors the deferral of these costs to ensure that it does not cause them to earn a greater return on common equity than authorized by the PSCW.
	•	The rates for all of our natural gas utilities included one-for-one recovery mechanisms for natural gas commodity costs.
	•	The rates of PGL and NSG included riders for cost recovery of both environmental cleanup and energy conservation and management program costs.
	•	MERC's rates included a conservation improvement program rider for cost recovery of energy conservation and management program costs as well as a financial incentive for meeting energy savings goals.
	•	The rates of PGL and NSG included riders for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in customer rates.
	•	The rates of PGL, NSG, and MERC included decoupling mechanisms. These mechanisms differ by state and allow utilities to recover or refund differences between actual and authorized margins. See Note 25, Regulatory Environment, for more information.
	•	In 2014, PGL's rates included a cost recovery mechanism for upgrades to the Illinois natural gas utility infrastructure.
	Revenues are also impacted by other accounting policies related to PGL's natural gas hub and our electric utilities' participation in the MISO market. Amounts collected from PGL's wholesale customers that use the natural gas hub are credited to natural gas costs, resulting in a reduction to retail customers' charges for natural gas and services. WPS sells and purchases power in the MISO market. UPPCO also sold and purchased power in the MISO market until it was sold in August 2014. If WPS or UPPCO was a net seller in a particular hour, the net amount was reported as revenue. If WPS or UPPCO was a net purchaser in a particular hour, the net amount was recorded as utility cost of fuel, natural gas, and purchased power on the income statements.
	ITF accounts for revenues from construction management projects using the percentage of completion method. Revenues are recognized based on the percentage of costs incurred to date compared to the total estimated costs of each contract. This method is used because management considers total costs to be the best available measure of progress on these contracts.
	We provide regulated electric and natural gas service to customers in Illinois, Michigan, Minnesota, and Wisconsin. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Credit risk exposure at PGL and NSG is mitigated by their rider for cost recovery or refund of uncollectible expense discussed above. As a result, we did not have any significant concentrations of credit risk at December 31, 2014. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2014.
Inventories	(g) Inventories—Inventories consist of materials and supplies, natural gas in storage, liquid propane, emission allowances at WPS, and fossil fuels, including coal. Average cost is used to value materials and supplies, fossil fuels, liquid propane, emission allowances at WPS, and natural gas in storage for the utilities, excluding PGL and NSG. PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the Last-in, First-out (LIFO) cost method. Inventories stated on a LIFO basis represented approximately 37% of total inventories at December 31, 2014, and 30% of total inventories at December 31, 2013. The estimated replacement cost of natural gas in inventory at December 31, 2014, and December 31, 2013, exceeded the LIFO cost by $47.7 million and $151.7 million, respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per dekatherm of $3.04 at December 31, 2014, and $4.77 at December 31, 2013.
Risk Management Activities	(h) Risk Management Activities—As part of our regular operations, we enter into contracts, including options, swaps, futures, forwards, and other contractual commitments, to manage market risks such as changes in commodity prices and interest rates. See Note 6, Risk Management Activities, for more information. Derivative instruments are entered into in accordance with the terms of each subsidiary's risk management policies approved by their respective Boards of Directors and, if applicable, by their respective regulators.
	All derivatives are recognized on the balance sheets at their 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. Because most energy-related derivatives at the utilities qualify for regulatory deferral, management believes any gains or losses resulting from the eventual settlement of derivative instruments will be refunded to or collected from customers in rates. As such, any changes in the fair value of these derivatives recorded as either risk management assets or liabilities are offset with regulatory liabilities or assets, as appropriate.
	We classify derivative assets and liabilities as current or long-term on the balance sheets based on the maturities of the underlying contracts. We record unrealized gains and losses on derivative instruments that do not qualify for hedge accounting or regulatory deferral as a component of margins or operating and maintenance expense, depending on the nature of the transactions. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on the 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 the balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received from others is reflected in other current liabilities.
Emission Allowances	(i) Emission Allowances—WPS accounts for emission allowances as inventory at average cost by vintage year. Charges to income result when allowances are used in operating WPS's generation plants. These charges are included in the costs subject to the fuel window rules. Gains on sales of allowances at WPS are returned to ratepayers.
Property, plant, and equipment	(j) Property, Plant, and Equipment—Utility plant is stated at cost, including any associated AFUDC and asset retirement costs. The costs of renewals and betterments of units of property (as distinguished from minor items of property) are capitalized as additions to the utility plant accounts. Maintenance and repair costs, as well as replacement and renewal costs associated with items not qualifying as units of property, are recorded as operating expenses. The utilities record a regulatory liability for cost of removal accruals, which are included in rates. Actual removal costs are charged against the regulatory liability as incurred. Except for land, no gains or losses are recognized in connection with ordinary retirements of utility property units. Ordinary retirements, sales, and other disposals of units of property at the utilities are charged to accumulated depreciation at cost, less salvage value. When it becomes probable that an operating unit will be retired in the near future and substantially in advance of its expected useful life, the cost and corresponding accumulated depreciation of the asset is classified as plant to be retired, net within property, plant, and equipment.
	We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below:
	Annual Utility Composite Depreciation Rates		2014		2013			2012
	MERC (1)		2.49	%	1.88	%		3.07	%
	MGU (2)		2.65	%	1.93	%		2.71	%
	NSG		2.44	%	2.44	%		2.43	%
	PGL		3.2	%	3.19	%		3.16	%
	WPS – Electric		2.73	%	2.79	%		2.87	%
	WPS – Natural gas		2.17	%	2.19	%		2.21	%
	-1	The 2013 depreciation rate reflects the impact of a new depreciation study approved by the MPUC in July 2013. The rates were effective retroactive to January 2012. An approximate $2 million reduction in depreciation expense was recorded in 2013 related to the 2012 impact.
	(2)	The 2013 depreciation rate includes the impact of a $2.5 million reduction in depreciation expense that was recorded in the first quarter of 2013 as a result of the Michigan Court of Appeals order reversing the MPSC's previously ordered disallowance associated with the early retirement of certain MGU assets in 2010.
	The majority of nonregulated plant is stated at cost, net of impairments recorded, and includes capitalized interest. The costs of renewals, betterments, and major overhauls are capitalized as additions to plant. Nonregulated plant acquired as a result of mergers and acquisitions have been recorded at fair value. The gains or losses associated with ordinary retirements are recorded in the period of retirement. Maintenance and repair costs and minor replacement costs are expensed as incurred. Depreciation is computed for the majority of the nonregulated subsidiaries' assets using the straight-line method over the assets' useful lives.
	We capitalize certain costs related to software developed or obtained for internal use and amortize those costs to operating expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.
	We 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 7, Property, Plant, and Equipment, for more information.
AFUDC and capitalized interest	(k) AFUDC and Capitalized Interest—Our utilities and IBS capitalize the cost of funds used for construction using a calculation that includes both internal equity and external debt components, as required by regulatory accounting. The internal equity component is accounted for as other income. The external debt component is accounted for as a decrease to interest expense.
	The majority of AFUDC is recorded at WPS. Approximately 50% of WPS's retail jurisdictional construction work in progress expenditures are subject to the AFUDC calculation. For 2014, WPS's average AFUDC retail rate was 8.08%, and its average AFUDC wholesale rate was 6.99%. The AFUDC calculation for the other utilities and IBS is determined by their respective state commissions, each with specific requirements. Based on these requirements, the other utilities and IBS did not record significant AFUDC for 2014, 2013, or 2012.
	Total AFUDC was as follows for the years ended December 31:
			2014			2013				2012
	Allowance for equity funds used during construction		$	12.5		$	10.8			$	2.9
	Allowance for borrowed funds used during construction		5.2			4.1				1
Regulatory Assets and Liabilities	(l) Regulatory Assets and Liabilities—Regulatory assets represent probable future revenue associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts 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 year the determination is made. See Note 9, Regulatory Assets and Liabilities, for more information.
Investments in Exchange-Traded Funds	(m) Investments in Exchange-Traded Funds—We have investments in exchange-traded funds. These investments are held in a rabbi trust to help fund our obligations under our deferred compensation plan and certain non-qualified pension plans. These investments are classified as trading securities for accounting purposes. As we do not intend to sell them in the near term, they are included in other long-term assets on our balance sheets. The net unrealized gains included in earnings related to the investments held at the end of the period were $1.8 million, $1.9 million, and $1.0 million for the years ended December 31, 2014, 2013, and 2012, respectively.
Asset impairment	(n) Asset Impairment—Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. Intangible assets with definite lives are reviewed for impairment on a quarterly basis. Other long-lived assets require an impairment review when events or circumstances indicate that the carrying amount may not be recoverable. We base our evaluation of other long-lived assets on the presence of impairment indicators such as the future economic benefit of the assets, any historical or future profitability measurements, and other external market conditions or factors.
	Our reporting units containing goodwill perform annual goodwill impairment tests during the second quarter of each year. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value. See Note 11, Goodwill and Other Intangible Assets, for more information on our goodwill and other intangible assets.
	The carrying amount of tangible long-lived assets held and used is considered not recoverable if the carrying amount exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. If the carrying amount is not recoverable, the impairment loss is measured as the excess of the asset's carrying amount over its fair value.
	The carrying amount of assets held for sale is not recoverable if the carrying amount exceeds the fair value less estimated costs to sell the asset. An impairment loss is recorded for the excess of the asset’s carrying amount over the fair value less estimated costs to sell.
	The carrying amounts of cost and equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts, if a fair value assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists and it is determined to be other-than-temporary, a loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value.
Retirement of Debt	(o) Retirement of Debt—Any call premiums or unamortized expenses associated with refinancing utility debt obligations are amortized consistent with regulatory treatment of those items. Any gains or losses resulting from the retirement of utility debt that is not refinanced are amortized over the remaining life of the original debt. Any gains or losses resulting from the retirement of nonutility debt are recorded through current earnings.
Asset retirement obligations	(p) Asset Retirement Obligations—We recognize at fair value legal obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction or development, and/or normal operation of the assets. A liability is recorded 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 asset retirement obligations are accreted using a credit-adjusted risk-free interest rate commensurate with the expected settlement dates of the asset retirement obligations; this rate is determined at the date the obligation is incurred. The associated retirement costs are capitalized as part of the related long-lived assets and are depreciated over the useful lives of the assets. 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 in the carrying amount of the liability and the associated retirement cost. See Note 15, Asset Retirement Obligations, for more information.
Environmental Remediation Costs	(q) 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 (PRP). Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including former manufactured gas plant sites. See Note 17, Commitments and Contingencies, for more information on our 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 PRPs or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.
	Our utilities have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the respective Commission's approval.
	We review our estimated costs of remediation annually for our manufactured gas plant sites and 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	(r) Income Taxes—We file a consolidated United States income tax return that includes domestic subsidiaries of which our ownership is 80% or more. We and our consolidated subsidiaries are parties to a federal and state tax allocation arrangement under which each entity determines its provision for income taxes on a stand-alone basis. In several states, combined or consolidated filings are required for certain subsidiaries doing business in that state.
	Deferred income taxes have been recorded to recognize the expected future tax consequences of events that have been included in the financial statements by using currently enacted tax rates for the differences between the income tax basis of assets and liabilities and the basis reported in the financial statements. We record valuation allowances for deferred income tax assets unless it is more likely than not that the benefit will be realized in the future. Our utilities defer certain adjustments made to income taxes that will impact future rates and record regulatory assets or liabilities related to these adjustments.
	We use the deferral method of accounting for investment tax credits (ITCs). Under this method, we record the ITCs as deferred credits and amortize such credits as a reduction to the provision for income taxes over the life of the asset that generated the ITCs. ITCs that do not reduce income taxes payable for the current year are eligible for carryover and recognized as a deferred income tax asset.
	We report interest and penalties accrued related to income taxes as a component of provision for income taxes in the income statements, as well as regulatory assets or regulatory liabilities on the balance sheets.
	We record excess tax benefits from stock-based compensation awards when the actual tax benefit is realized. We follow the tax law ordering approach to determine when the tax benefit has been realized. Under this approach, the tax benefit is realized in the year it reduces taxable income. Current year stock-based compensation deductions are assumed to be used before any net operating loss carryforwards.
	See Note 16, Income Taxes, for more information regarding accounting for income taxes.
Guarantees	(s) Guarantees—We follow the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. See Note 22, Guarantees, for more information.
Employee Benefits	(t) Employee Benefits—The costs of pension and other postretirement benefits are expensed over the periods during which employees render service. Our transition obligation related to other postretirement benefit plans was recognized over a 20-year period that began in 1993, and ended in 2012. In computing the expected return on plan assets, we use a market-related value of plan assets, which is estimated using the following approaches by plan. For plans sponsored by IBS and WPS, we use the calculated value approach. For plans sponsored by PELLC, we use the fair market value approach. Changes in realized and unrealized investment gains and losses are recognized over the subsequent five years for plans sponsored by WPS, while differences between actual investment returns and the expected return on plan assets are recognized over a five-year period for plans sponsored by IBS and PELLC. The benefit costs associated with employee benefit plans are allocated among our subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the utilities' net periodic benefit cost calculated under GAAP.
	We recognize the funded status of defined benefit postretirement plans on the balance sheet, and recognize changes in the plans' funded status in the year in which the changes occur. Our nonregulated businesses record changes in the funded status in accumulated other comprehensive income. The utilities record changes in the funded status to regulatory asset or liability accounts, pursuant to the Regulated Operations Topic of the FASB ASC.
	See Note 18, Employee Benefit Plans, for more information.
Stock-Based Compensation	(u) Stock-Based Compensation—In May 2014, our shareholders approved the 2014 Omnibus Incentive Compensation Plan (2014 Omnibus Plan). Under the provisions of the 2014 Omnibus Plan, the number of shares of stock that may be issued in satisfaction of plan awards may not exceed 3,000,000 shares, plus any shares forfeited under prior plans. No single employee who is our chief executive officer, chief financial officer, or any one of our other three highest compensated officers (including officers of our subsidiaries) can be granted stock options for more than 1,000,000 shares or receive a payout in excess of 250,000 shares for performance stock rights during any calendar year. Additional awards will not be issued under prior plans, although the plans continue to exist for purposes of the existing outstanding stock-based compensation awards. At December 31, 2014, stock options, performance stock rights, and restricted share units were outstanding under prior plans.
	Stock Options
	Our stock options have a term not longer than 10 years. The exercise price of each stock option is equal to the fair market value of our stock on the date the stock option is granted.
	Effective October 24, 2014, our Board of Directors accelerated the vesting of all unvested stock options held by active employees in order to help mitigate the tax impacts of Section 280G of the Internal Revenue Code on us and certain of our employees. All stock options awarded to active employees also became exercisable as of this date. For retirees, 25% of their stock options granted will continue to become exercisable each year on the anniversary of the grant date.
	The fair value of stock option awards granted is estimated using a binomial lattice model. The expected term of option awards is derived from the output of the binomial lattice model and represents the period of time that options are expected to be outstanding. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate. Our expected stock price volatility is estimated using the 10-year historical volatility of our stock price.
	Performance Stock Rights
	Performance stock rights generally vest over a three-year performance period. For accounting purposes, awards granted to retirement-eligible employees vest over a shorter period; however, the distribution of these awards is not accelerated. Effective October 24, 2014, our Board of Directors approved the acceleration of the distribution of certain performance stock rights held by active employees. For those performance stock rights with a performance period ending December 31, 2014, a portion of the estimated distribution was made in December 2014. This change was made to help mitigate the tax impacts of Section 280G of the Internal Revenue Code on us and certain of our employees.
	Performance stock rights are paid out in shares of our common stock, or eligible employees can elect to defer the value of their awards into the deferred compensation plan and choose among various investment options, some of which are ultimately paid out in our common stock and some of which are ultimately paid out in cash. Eligible employees can only elect to defer up to 80% of the value of their awards. The number of shares paid out is calculated by multiplying a performance percentage by the number of outstanding stock rights at the completion of the performance period. The performance percentage is based on the total shareholder return of our common stock relative to the total shareholder return of a peer group of companies. The payout may range from 0% to 200% of target.
	Performance stock rights are accounted for as either an equity award or a liability award, depending on their settlement features. Awards that can only be settled in our common stock are accounted for as equity awards. Awards that an employee has elected to defer, or is still able to defer, into the deferred compensation plan are accounted for as liability awards and are recorded at fair value each reporting period.
	Six months prior to the end of the performance period, employees can no longer change their election to defer the value of their performance stock rights into the deferred compensation plan. As a result, any awards not elected for deferral at this point in the performance period will be settled in our common stock. This changes the classification of these awards from a liability award to an equity award. The change in classification is accounted for as an award modification. The fair value on the modification date is used to measure these awards for the remaining six months of the performance period. No incremental compensation expense is recorded as a result of this award modification.
	The fair values of performance stock rights are estimated using a Monte Carlo valuation model. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate. Our expected stock price volatility is estimated using one to three years of historical data.
	Restricted Share Units
	Restricted share units generally have a four-year vesting period, with 25% of each award vesting on each anniversary of the grant date. For accounting purposes, awards granted to retirement-eligible employees vest over a shorter period; however, the release of shares to these employees is not accelerated. Restricted share unit recipients do not have voting rights, but they receive forfeitable dividend equivalents in the form of additional restricted share units.
	Restricted share units are accounted for as either an equity award or a liability award, depending on their settlement features. Awards that can only be settled in our common stock and cannot be deferred into the deferred compensation plan are accounted for as equity awards. Eligible employees can only elect to defer up to 80% of their awards into the deferred compensation plan. Equity awards are measured based on the fair value on the grant date. Awards that an employee has elected to defer into the deferred compensation plan are accounted for as liability awards and are recorded at fair value each reporting period.
	Nonemployee Directors Deferred Stock Units
	Each nonemployee director is granted deferred stock units (DSUs), typically in January of each year. The number of DSUs granted is calculated by dividing a set dollar amount by our closing common stock price on December 31 of the prior year. DSUs generally vest over one year. Therefore, the expense for these awards is recognized pro-rata over the year in which the grant occurs. Upon vesting, these awards are deferred into the deferred compensation plan; however, their value cannot be diversified among the various investment options. As DSUs can only be settled in our common stock, they are accounted for as equity awards.
Earnings Per Share	(v) Earnings Per Share—Basic earnings per share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for shares we are obligated to issue under the deferred compensation and restricted share unit plans. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include in-the-money stock options, performance stock rights, restricted share units, unvested director DSUs, and certain shares issuable under the deferred compensation plan. As the obligation for the shares issuable under the deferred compensation plan is accounted for as a liability, the numerator is adjusted for any changes in income or loss that would have resulted had it been accounted for as an equity instrument during the period.
Fair Value	(w) Fair Value—A fair value measurement is required to reflect the assumptions market participants would use in pricing an asset or liability based on the best available information.
	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). 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.
	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.
	When possible, we base the valuations of our risk management assets and liabilities on quoted prices for identical assets in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on observable inputs related to market price risk (commodity or interest rate), price volatility (for option contracts), and price correlation (for cross commodity contracts). 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. The primary reasons for a Level 3 classification are as follows:
	•	Financial contracts used to manage transmission congestion costs in the MISO market are valued using historical prices.
	•	The valuation for physical coal contracts is based on significant assumptions made to extrapolate prices from the last observable period through the end of the transaction term.
	•	Certain natural gas contracts are valued using internally-developed inputs due to the absence of available market data for certain locations.
	We have established risk oversight committees whose primary responsibility includes directly or indirectly ensuring that all valuation methods are applied in accordance with predefined policies. The development and maintenance of our forward price curves has been assigned to our risk management department, which is part of the corporate treasury function. This group is separate and distinct from any of the supply functions within the organization. To validate the reasonableness of our fair value inputs, our risk management department compares changes in valuation and researches any significant differences in order to determine the underlying cause. Changes to the fair value inputs are made if necessary.
	Derivatives are transferred between levels of the fair value hierarchy due to observable pricing becoming available as the remaining contract term becomes shorter. We recognize transfers at the value as of the end of the reporting period.
	The fair values of long-term debt instruments are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. The fair values of preferred stock are estimated based on quoted market prices when available, or by using a perpetual dividend discount model. The fair values of long-term debt instruments and preferred stock are categorized within Level 2 of the fair value hierarchy. Due to the short-term nature of cash and cash equivalents, accounts receivable, accounts payable, and outstanding commercial paper, the carrying amount for each of these items approximates fair value.
	We conduct a thorough review of fair value hierarchy classifications on a quarterly basis.
	See Note 24, Fair Value, for more information.
New Accounting Pronouncements	(x) New Accounting Pronouncements—
	Recently Issued Accounting Guidance Not Yet Effective
	In February 2015, the FASB issued ASU 2015-02, "Amendments to the Consolidation Analysis." The guidance focuses on the consolidation evaluation for companies that are required to evaluate whether they should consolidate certain legal entities. This ASU eliminates the specialized guidance for limited partnerships and similar legal entities. It places more emphasis on risk of loss when determining a controlling financial interest and amends the guidance for assessing how relationships of related parties affect the consolidation analysis of variable interest entities. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact this guidance will have on our financial statements.
	In January 2015, the FASB issued ASU 2015-01, "Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items." This guidance no longer requires or allows the disclosure of extraordinary items, net of tax, in the income statement after income from continuing operations. The guidance is effective for us for the reporting period ending March 31, 2016. We do not currently have any extraordinary items presented on the income statements. However, this guidance will eliminate the need for us to further assess whether unusual and infrequently occurring transactions qualify as an extraordinary item in the future.
	In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers." This ASU supersedes the requirements in the Revenue Recognition Topic of the FASB ASC and most industry-specific guidance throughout the ASC. The guidance is based on the principle that revenue is recognized when promised goods or services are transferred to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The standard requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and cash flows from customer contracts. The guidance is effective for us for the reporting period ending March 31, 2017. The standard requires either retrospective application by restating each prior period presented in the financial statements, or modified retrospective application by recording the cumulative effect of prior reporting periods to beginning retained earnings in the year that the standard becomes effective. Management is currently evaluating the impact that the adoption of this standard will have on our financial statements.
	In April 2014, the FASB issued ASU 2014-08, "Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." The guidance raises the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. The guidance applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. Management early adopted this guidance in the third quarter of 2014. See Note 4, Dispositions, for more information.
	In January 2014, the FASB issued ASU 2014-01, "Accounting for Investments in Qualified Affordable Housing Projects." The guidance allows investors to use the proportional amortization method to account for investments in qualified affordable housing projects if certain conditions are met. Under that method, which replaces the effective yield method, an investor amortizes the cost of its investment, in proportion to the tax credits and other tax benefits it receives, to income tax expense. The guidance also requires new disclosures for all investments in these types of projects. The guidance is effective for us for the reporting period ending March 31, 2015. Although we have investments in affordable housing projects, adoption of this guidance is not expected to have a significant impact on our financial statements.

SUMMARY_OF_SIGNIFICANT_ACCOUNT2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Schedule of annual utility composite depreciation rates	Annual utility composite depreciation rates are shown below:
	Annual Utility Composite Depreciation Rates		2014		2013			2012
	MERC (1)		2.49	%	1.88	%		3.07	%
	MGU (2)		2.65	%	1.93	%		2.71	%
	NSG		2.44	%	2.44	%		2.43	%
	PGL		3.2	%	3.19	%		3.16	%
	WPS – Electric		2.73	%	2.79	%		2.87	%
	WPS – Natural gas		2.17	%	2.19	%		2.21	%
	-1	The 2013 depreciation rate reflects the impact of a new depreciation study approved by the MPUC in July 2013. The rates were effective retroactive to January 2012. An approximate $2 million reduction in depreciation expense was recorded in 2013 related to the 2012 impact.
	(2)	The 2013 depreciation rate includes the impact of a $2.5 million reduction in depreciation expense that was recorded in the first quarter of 2013 as a result of the Michigan Court of Appeals order reversing the MPSC's previously ordered disallowance associated with the early retirement of certain MGU assets in 2010.
Schedule of total AFUDC	Total AFUDC was as follows for the years ended December 31:
			2014			2013				2012
	Allowance for equity funds used during construction		$	12.5		$	10.8			$	2.9
	Allowance for borrowed funds used during construction		5.2			4.1				1

ACQUISITIONS_Tables

ACQUISITIONS (Tables) (Fox Energy Company LLC)	12 Months Ended
	Dec. 31, 2014
Fox Energy Company LLC
Acquisitions
Schedule of purchase price allocation	The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows:
	(Millions)
	Assets acquired (1)
	Inventories		$	3
	Other current assets		0.4
	Property, plant, and equipment		374.4
	Other long-term assets (2)		15.6
	Total assets acquired		$	393.4
	Liabilities assumed
	Accounts payable		$	1.8
	Total liabilities assumed		$	1.8
	(1)	Relates to the electric utility segment.
	(2)	Intangible assets recorded for contractual services agreements. See Note 11, Goodwill and Other Intangible Assets, for more information.

DISPOSITIONS_Tables

DISPOSITIONS (Tables)	12 Months Ended
	Dec. 31, 2014
WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC
Dispositions
Schedule of assets and liabilities included in a disposal group as well as the components of discontinued operations	The following table shows the components of discontinued operations related to Beaver Falls and Syracuse recorded on the income statements:
	(Millions)		2014				2013				2012
	Revenues		$	—			$	1.2			$	0.6
	Cost of sales		—				(0.9		)		(2.0		)
	Operating and maintenance expense		2				0.4			*	(3.5		)
	Depreciation and amortization expense		—				—				(0.6		)
	Taxes other than income taxes		—				(0.3		)		(1.4		)
	Miscellaneous income		—				—				0.3
	Income (loss) before taxes		2				0.4				(6.6		)
	(Provision) benefit for income taxes		(0.8		)		(0.2		)		2.6
	Discontinued operations, net of tax		$	1.2			$	0.2			$	(4.0	)
	*	Includes a $1.0 million gain on sale at closing
WPS Westwood Generation, LLC
Dispositions
Schedule of assets and liabilities included in a disposal group as well as the components of discontinued operations	The following table shows the components of discontinued operations related to Westwood recorded on the income statements:
	(Millions)		2012
	Revenues		$	9.2
	Cost of sales		(4.4		)
	Operating and maintenance expense		(14.3		)	*
	Depreciation and amortization expense		(1.0		)
	Taxes other than income taxes		(0.2		)
	Interest expense		(0.7		)
	Loss before taxes		(11.4		)
	Benefit for income taxes		4.5
	Discontinued operations, net of tax		$	(6.9	)
	*	Includes a $0.6 million loss on sale at closing.
Electric Utility | UPPCO
Dispositions
Schedule of assets and liabilities included in a disposal group as well as the components of discontinued operations	The following table shows the carrying values of the major classes of assets and liabilities related to UPPCO:
			As of the Closing Date				Held for Sale at
	(Millions)		in August 2014				31-Dec-13
	Current assets		$	24.3			$	26.5
	Property, plant, and equipment, net of accumulated depreciation of $91.3 and $88.9, respectively		194.4				193.8
	Other long-term assets		72.8				51.6
	Total assets		$	291.5			$	271.9
	Current liabilities		$	12.7			$	16.7
	Long-term liabilities		28.6				32.4
	Total liabilities		$	41.3			$	49.1
	In addition to the amounts in the table above, intercompany payables of $1.6 million at December 31, 2013 related to certain power purchase transactions with WPS that continued after the sale were eliminated during consolidation. As of the closing date, these payables were included in the sale and disclosed in the table above as current liabilities.
IES | IES's retail energy business
Dispositions
Schedule of assets and liabilities included in a disposal group as well as the components of discontinued operations	The following table shows the carrying values of the major classes of assets and liabilities included in the sale:
			As of the Closing Date in
	(Millions)		Nov-14				31-Dec-13
	Cash and cash equivalents		$	7.6			$	5.5
	Accounts receivable and accrued unbilled revenues, net of reserves of $1.8 and $1.7, respectively		293.8				390.9
	Inventories		52.4				34.2
	Current assets from risk management activities		234.8				229.5
	Prepaid taxes		—				2.5
	Other current assets		75.1				41.5
	Property, plant, and equipment, net of accumulated depreciation of $16.6 and $15.6, respectively		4.5				5.2
	Long-term assets from risk management activities		106.9				73.4
	Goodwill		—				6.7
	Other long-term assets		25.5				26
	Total assets		$	800.6			$	815.4
	Accounts payable		$	186.9			$	202.9
	Current liabilities from risk management activities		169.7				160.6
	Accrued taxes		0.2				2
	Other current liabilities		6.7				13.1
	Long-term liabilities from risk management activities		79.5				61.9
	Other long-term liabilities		0.3				7
	Total liabilities		$	443.3			$	447.5
	Included in the sale were commodity contracts that did not meet the GAAP definition of derivative instruments and, therefore, were not reflected on the balance sheets. In accordance with GAAP, expected gains or losses related to nonderivative commodity contracts are not recognized until the contracts are settled.
	The following table shows the components of discontinued operations related to the sale of the IES retail energy business recorded on the income statements:
	(Millions)		2014				2013				2012
	Revenues		$	2,587.10			$	2,150.90			$	1,201.00
	Cost of sales		(2,444.7		)		(1,910.7		)		(1,018.9		)
	Operating and maintenance expense		(91.5		)		(105.6		)		(88.3		)
	Depreciation and amortization expense		(2.7		)		(3.2		)		(3.4		)
	Taxes other than income taxes		(4.9		)		(3.2		)		(2.4		)
	Goodwill impairment loss		(6.7		)		—				—
	Loss on sale of IES retail energy business		(28.8		)		—				—
	Miscellaneous income		0.6				7.9				0.3
	Interest expense		(0.7		)		(0.8		)		(1.3		)
	Income before taxes		7.7				135.3				87
	Provision for income taxes *		(7.3		)		(52.8		)		(31.9		)
	Discontinued operations, net of tax		$	0.4			$	82.5			$	55.1
	*	See Note 16, Income Taxes, for more information.

CASH_AND_CASH_EQUIVALENTS_Tabl

CASH AND CASH EQUIVALENTS (Tables)	12 Months Ended
	Dec. 31, 2014
Continuing operations
Significant noncash transactions and other information
Schedule of significant noncash transactions and other cash flow information	Significant noncash transactions related to continuing operations were:
	(Millions)		2014			2013			2012
	Construction costs funded through accounts payable		$	180.5		$	108.5		$	92.4
	Accounts receivable converted to notes receivable related to sales of ITF fueling stations constructed on behalf of others		10.9			—			—
	Portion of ITF fueling station sale financed with note receivable *		2.7			—			—
	Equity interest in joint venture received for a portion of the ITF fueling station sale *		3.1			—			—
	Equity issued for employee stock ownership plan		1.7			14.3			—
	Equity issued for stock-based compensation plans		—			16.3			—
	Equity issued for reinvested dividends		—			12			—
	*	See Note 4, Dispositions, for more information.
Discontinued operations
Significant noncash transactions and other information
Schedule of significant noncash transactions and other cash flow information	Significant noncash transactions and other information related to discontinued operations are disclosed below.
	(Millions)		2014			2013			2012
	Operating Activities
	Depreciation and amortization expense		$	2.7		$	3.3		$	5.3
	Net unrealized gains on energy contracts		(22.7		)	(100.3		)	(34.5		)
	Deferred income taxes and investment tax credits		36.1			56.1			(0.4		)
	Remeasurement of uncertain tax positions included in our liability for unrecognized tax benefits		(0.7		)	(5.9		)	(1.8		)
	Loss on sale of IES's retail energy business *		24.3			—			—
	Other		33.4			23.8			21.7
	Investing Activities
	Capital expenditures		(0.8		)	(2.6		)	(2.0		)
	Contingent consideration and payables related to the acquisition of Compass Energy Services		—			7.8			—
	Portion of Westwood sale financed with note receivable *		—			—			4
	*	See Note 4, Dispositions, for more information.

RISK_MANAGEMENT_ACTIVITIES_Tab

RISK MANAGEMENT ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2014
Risk management activities
Assets and liabilities from risk management activities	The following tables show our assets and liabilities from risk management activities at the utilities and IBS:
				31-Dec-14
	(Millions)	Balance Sheet Presentation		Assets from				Liabilities from
				Risk Management Activities				Risk Management Activities
	Nonhedge derivatives
	Natural gas contracts	Other current		$	1.8			$	37.3
	Natural gas contracts	Other long-term		0.5				5.3
	Financial transmission rights (FTRs)	Other current		2.2				0.3
	Petroleum product contracts	Other current		—				2.7
	Petroleum product contracts	Other long-term		—				0.1
	Coal contracts	Other current		—				2.4
	Coal contracts	Other long-term		—				1
		Other current		4				42.7
		Other long-term		0.5				6.4
	Total			$	4.5			$	49.1
				December 31, 2013
	(Millions)	Balance Sheet Presentation		Assets from				Liabilities from
				Risk Management Activities				Risk Management Activities
	Nonhedge derivatives
	Natural gas contracts	Other current		$	8.3			$	1
	Natural gas contracts	Other long-term		1.8				0.1
	FTRs	Other current		1.5				0.3
	Petroleum product contracts	Other current		0.1				—
	Coal contracts	Other current		—				1.9
	Coal contracts	Other long-term		0.2				0.8
		Other current		9.9				3.2
		Other long-term		2				0.9
	Total			$	11.9			$	4.1
Potential effect of netting arrangements for recognized derivative assets and liabilities	The following tables show the potential effect on our financial position of netting arrangements for recognized derivative assets and liabilities:
		31-Dec-14
	(Millions)	Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
	Derivative assets subject to master netting or similar arrangements	$	3.2			$	1.3			$	1.9
	Derivative assets not subject to master netting or similar arrangements	1.3								1.3
	Total risk management assets	$	4.5							$	3.2
	Derivative liabilities subject to master netting or similar arrangements	$	45.7			$	8.8			$	36.9
	Derivative liabilities not subject to master netting or similar arrangements	3.4								3.4
	Total risk management liabilities	$	49.1							$	40.3
		31-Dec-13
	(Millions)	Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
	Derivative assets subject to master netting or similar arrangements	$	11.7			$	2.1			$	9.6
	Derivative assets not subject to master netting or similar arrangements	0.2								0.2
	Total risk management assets	11.9								9.8
	Derivative liabilities subject to master netting or similar arrangements	$	1.4			$	1.4			$	—
	Derivative liabilities not subject to master netting or similar arrangements	2.7								2.7
	Total risk management liabilities	$	4.1							$	2.7
Cash collateral positions	The following table shows our cash collateral positions:
	(Millions)	31-Dec-14				31-Dec-13
	Cash collateral provided to others:
	Related to contracts under master netting or similar arrangements	$	11.6			$	3.6
	Other	1.1				1.1
	Cash collateral received from others related to contracts under master netting or similar arrangements	—				0.7
Cash flow hedges | Holding Company and Other
Risk management activities
Loss reclassified from Accumulated Other Comprehensive Loss into Income (Effective Portion)
		Loss Reclassified from Accumulated OCI into Income (Effective Portion)
	(Millions)	Income Statement Presentation		2014				2013				2012
	Settled/Realized
	Interest rate swaps	Interest expense		$	(1.1	)		$	(1.1	)		$	(1.1	)
Non-hedge derivatives | Utility segments
Risk management activities
Notional volumes of outstanding derivative contracts	The notional volumes of outstanding derivative contracts at the utilities and IBS were as follows:
		31-Dec-14									31-Dec-13
	(Millions)	Purchases			Sales			Other Transactions			Purchases			Sales	Other Transactions
	Natural gas (therms)	1,860.00			—			N/A			3,124.80			29.3	N/A
	FTRs (kilowatt-hours)	N/A			N/A			4,287.70			N/A			N/A	3,427.00
	Petroleum products (barrels)	0.1			—			N/A			0.1			—	N/A
	Coal (tons)	3			—			N/A			4.8			—	N/A
Unrealized gains (losses) related to derivatives	The table below shows the unrealized gains (losses) recorded related to derivative contracts at the utilities and IBS:
	(Millions)	Financial Statement Presentation		2014				2013				2012
	Natural gas	Balance Sheet — Regulatory assets (current)		$	(38.0	)		$	13.4			$	24.6
	Natural gas	Balance Sheet — Regulatory assets (long-term)		(5.2		)		2.3				8.3
	Natural gas	Balance Sheet — Regulatory liabilities (current)		(3.9		)		4.6				(7.8		)
	Natural gas	Balance Sheet — Regulatory liabilities (long-term)		(0.6		)		0.3				0.3
	Natural gas	Income Statement — Cost of sales		—				—				0.2
	Natural gas	Income Statement — Operating and maintenance expense		(0.8		)		0.1				—
	FTRs	Balance Sheet — Regulatory assets (current)		—				0.2				(0.1		)
	FTRs	Balance Sheet — Regulatory liabilities (current)		0.4				(0.3		)		—
	Petroleum	Balance Sheet — Regulatory assets (current)		(1.1		)		—				0.1
	Petroleum	Balance Sheet — Regulatory liabilities (current)		(0.1		)		0.1				—
	Petroleum	Income Statement — Operating and maintenance expense		(1.7		)		0.1				—
	Coal	Balance Sheet — Regulatory assets (current)		(1.3		)		(0.9		)		(2.2		)
	Coal	Balance Sheet — Regulatory assets (long-term)		—				3.5				0.1
	Coal	Balance Sheet — Regulatory liabilities (current)		(0.2		)		(0.2		)		0.3
	Coal	Balance Sheet — Regulatory liabilities (long-term)		(0.1		)		(2.0		)		2.2

PROPERTY_PLANT_AND_EQUIPMENT_T

PROPERTY, PLANT, AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Schedule of property, plant, and equipment	Property, plant, and equipment consisted of the following utility, nonutility, and nonregulated assets at December 31:
	(Millions)		2014		2013
	Electric utility		$	3,587.40	$	3,289.20
	Natural gas utility		5,811.80		5,428.50
	Total utility property, plant, and equipment		9,399.20		8,717.70
	Less: Accumulated depreciation		3,185.90		3,073.20
	Net		6,213.30		5,644.50
	Construction work in progress		351.8		351.5
	Plant to be retired, net *		12.5		14.4
	Net utility property, plant, and equipment		6,577.60		6,010.40
	Nonutility plant		144.6		131.1
	Less: Accumulated depreciation		81.1		80.4
	Net		63.5		50.7
	Construction work in progress		73.9		38
	Net nonutility property, plant, and equipment		137.4		88.7
	PDI energy assets		140.2		109.8
	Other nonregulated		33.7		20.7
	Total nonregulated property, plant, and equipment		173.9		130.5
	Less: Accumulated depreciation		39.5		30.5
	Net		134.4		100
	Construction work in progress		10.4		7.1
	Net nonregulated property, plant, and equipment		144.8		107.1
	Total property, plant, and equipment		$	6,859.80	$	6,206.20
	*	In connection with the WPS Consent Decree with the EPA, WPS announced that the Weston 1, Pulliam 5, and Pulliam 6 generating units will be retired early. These units are currently included in rate base, and WPS continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. The amount presented above is net of accumulated depreciation. See Note 17, Commitments and Contingencies, for more information regarding the Consent Decree.

JOINTLY_OWNED_UTILITY_FACILITI1

JOINTLY OWNED UTILITY FACILITIES (Tables)	12 Months Ended
	Dec. 31, 2014
Jointly Owned Utility Plant, Net Ownership Amount [Abstract]
Schedule of WPS's share of significant jointly owned electric generating facilities	The amounts were as follows at December 31, 2014:
	(Millions, except for percentages and megawatts)	Weston 4			Columbia Energy Center			Edgewater Unit 4
					Units 1 and 2
	Ownership	70		%	31.8		%	31.8		%
	WPS's share of rated capacity (megawatts)	374.5			335.2			105
	In-service date	2008			1975 and 1978			1969
	Utility plant	$	581.9		$	390.7		$	42.9
	Accumulated depreciation	$	(132.6	)	$	(116.2	)	$	(29.6	)
	Construction work in progress	$	2.7		$	10.1		$	0.7

REGULATORY_ASSETS_AND_LIABILIT1

REGULATORY ASSETS AND LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2014
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets	The following regulatory assets were reflected on our balance sheets as of December 31:
	(Millions)		2014		2013		See Note
	Regulatory assets (1) (2)
	Environmental remediation costs (net of insurance recoveries) (3)		$	635.8	$	652.1	17
	Unrecognized pension and other postretirement benefit costs (4)		513.1		382.6		18
	Asset retirement obligations		109.4		89		15
	Merger and acquisition-related pension and other postretirement benefit costs (5)		86.6		98.3
	Income tax related items		60.6		55.3		16
	Derivatives		55.2		11.7		1(h)
	Termination of a tolling agreement with Fox Energy Company LLC		44.6		50		3
	Crane Creek production tax credits (6)		32.2		33.6
	Energy costs recoverable through rate adjustments (7)		22.2		17
	De Pere Energy Center (8)		21.4		23.8
	Unamortized loss on reacquired debt (9)		16.6		16.2		1(o)
	Uncollectible expense (10)		13.6		4.7
	Energy efficiency programs (11)		2.8		16.8
	Pension and other postretirement costs recoverable through rate adjustments (12)		—		9.4		25
	Decoupling		—		8.6		25
	Other		18.4		19.7
	Total regulatory assets		$	1,632.50	$	1,488.80
	Balance Sheet Presentation
	Current assets		$	118.9	$	127.4
	Long-term assets		1,513.60		1,361.40
	Total regulatory assets		$	1,632.50	$	1,488.80
	(1)	Based on prior and current rate treatment, we believe it is probable that our utility subsidiaries will continue to recover from customers the regulatory assets described above.
	(2)	The following regulatory assets are not earning a return: environmental remediation costs at WPS; unrecognized pension and other postretirement benefit costs at MERC, NSG, and PGL; asset retirement obligations, derivatives, and uncollectible expense at all utilities; merger and acquisition-related pension and other postretirement benefit costs at NSG and PGL; natural gas costs recoverable through rate adjustments at MERC and WPS; unamortized loss on reacquired debt at NSG and PGL; energy efficiency programs at WPS; pension and other postretirement costs recoverable through rate adjustments at WPS; and decoupling at MGU. However, these regulatory assets are expected to be recovered from customers in future rates.
	(3)	As of December 31, 2014, we had not yet made cash expenditures for $579.9 million of these environmental remediation costs. The recovery of these costs depends on the timing of the actual expenditures.
	(4)	Represents the unrecognized future pension and other postretirement costs resulting from actuarial gains and losses on defined benefit and other postretirement plans. We are authorized recovery of this regulatory asset over the average future remaining service life of each plan.
	(5)	Composed of unrecognized benefit costs that existed prior to the PELLC merger and the MERC and MGU acquisitions. MERC and MGU are authorized recovery of this regulatory asset through 2026. PGL and NSG are authorized recovery of the pension portion of this regulatory asset through 2023, and they are authorized recovery of the other postretirement benefit portion through 2019.
	(6)	In 2012, WPS 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, WPS reversed previously recorded production tax credits. WPS 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. WPS recorded a regulatory asset for the deferral of previously recorded production tax credits and is authorized recovery of this net regulatory asset through 2039.
	(7)	Represents the under-collection of energy costs that will be recovered from customers in the future.
	(8)	Prior to WPS purchasing the De Pere Energy Center in 2002, WPS 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. WPS is authorized recovery of this regulatory asset through 2023.
	(9)	Amounts are recovered over the term of the replacement debt for NSG and PGL as authorized by the ICC.
	(10)	Represents amounts recoverable from customers related to uncollectible expense. We are allowed to recover or refund the difference between the rate case authorized uncollectible expense and the actual uncollectible write-offs reported to the applicable commissions each year.
	(11)	Represents amounts recoverable from customers related to programs at the utility subsidiaries designed to meet energy efficiency standards.
	(12)	Represents the under-collection of pension and other postretirement costs that will be recovered from customers in the future.
Schedule of Regulatory Liabilities	The following regulatory liabilities were reflected on our balance sheets as of December 31:
	(Millions)		2014		2013		See Note
	Regulatory liabilities
	Removal costs (1)		$	334	$	318
	Decoupling		49.4		51.5		25
	Unrecognized pension and other postretirement benefit costs (2)		45.2		30.2		18
	Energy costs refundable through rate adjustments (3)		44.8		27.1
	Energy efficiency programs (4)		21.3		19.6
	Derivatives		19.8		6.6		1(h)
	Uncollectible expense		15.7		10.1		25
	Crane Creek depreciation deferral (5)		8.7		9
	Fox Energy Center (6)		4.6		5.6		3
	Other		10.1		7.1
	Total regulatory liabilities		$	553.6	$	484.8
	Balance Sheet Presentation
	Current liabilities		$	153.7	$	101.1
	Long-term liabilities		399.9		383.7
	Total regulatory liabilities		$	553.6	$	484.8
	(1)	Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment.
	(2)	Represents the unrecognized future other postretirement benefit costs resulting from actuarial gains on other postretirement benefit plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan.
	(3)	Represents the over-collection of energy costs that will be refunded to customers in the future.
	(4)	Represents amounts refundable to customers related to programs at the utility subsidiaries designed to meet energy efficiency standards.
	(5)	Represents the book depreciation taken on the Crane Creek wind project prior to WPS's 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.
	(6)	Represents the deferral of incremental costs associated with WPS owning and operating the Fox Energy Center, which was purchased in March 2013. In accordance with GAAP, the deferral does not include an allowance for return on equity, which has created the net regulatory liability. This allowance was $22.8 million and $22.1 million, at December 31, 2014, and 2013, respectively.

EQUITY_METHOD_INVESTMENTS_Tabl

EQUITY METHOD INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2014
Equity method investments
Schedule of equity method investments	Investments in corporate joint ventures and other companies accounted for under the equity method at December 31, 2014, and 2013, were as follows:
	(Millions)	2014		2013
	ATC	$	536.7	$	508.4
	INDU Solar Holdings, LLC	21.8		24.7
	WRPC	7.7		7
	AMP Trillium, LLC	5.5		—
	Other	0.7		0.8
	Equity method investments	$	572.4	$	540.9
ATC
Equity method investments
Schedule of changes to equity method investments	The following table shows changes to our investment in ATC during the years ended December 31:
	(Millions)	2014		2013		2012
	Balance at the beginning of period	$	508.4	$	476.6	$	439.4
	Add: Earnings from equity method investment	85.7		89.1		85.3
	Add: Capital contributions	17		13.7		20.4
	Less: Dividends received	74.4		71		68.5
	Balance at the end of period	$	536.7	$	508.4	$	476.6
Schedule of related party transactions	The related party transactions recorded by the electric utilities during the years ended December 31 were as follows:
	(Millions)	2014		2013		2012
	Total charges to ATC for services and construction	$	9.9	$	11.3	$	12.5
	Total costs for network transmission services provided by ATC	103.8		104.9		100.3
INDU Solar Holdings, LLC
Equity method investments
Schedule of changes to equity method investments	The following table shows changes to our investment in INDU Solar Holdings, LLC during the years ended December 31:
	(Millions)	2014		2013		2012
	Balance at the beginning of period	$	24.7	$	27.5	$	28.4
	Add: Earnings from equity method investment	1.8		1.3		1.1
	Add: Capital contributions	—		—		7
	Less: Return of capital to partners	4.7		4.1		9
	Balance at the end of period	$	21.8	$	24.7	$	27.5
WRPC
Equity method investments
Schedule of changes to equity method investments	The following table shows changes to our investment in WRPC during the years ended December 31:
	(Millions)	2014		2013		2012
	Balance at the beginning of period	$	7	$	7.3	$	7.7
	Add: Earnings from equity method investment	0.8		1		0.8
	Add: Capital contributions	0.5		—		—
	Less: Dividends received	0.6		1.3		1.2
	Balance at the end of period	$	7.7	$	7	$	7.3
Schedule of related party transactions	The related party transactions recorded by WPS during the years ended December 31 were as follows:
	(Millions)	2014		2013		2012
	Charges to WRPC for operations	$	1.4	$	0.9	$	0.8
	Purchases of energy from WRPC	3.7		3.7		5
	Net proceeds from WRPC sales of energy to MISO	—		—		2.9
AMP Trillium, LLC
Equity method investments
Schedule of changes to equity method investments	The following table shows changes to our investment in AMP Trillium, LLC during the year ended December 31:
	(Millions)	2014
	Balance at the beginning of period	$	—
	Add: Capital contributions	5.5
	Balance at the end of period	$	5.5
ATC, INDU Solar Holdings, LLC, WRPC, and AMP Trillium, LLC
Equity method investments
Summarized income statement data of significant equity method investments	Combined financial data of our significant equity method investments, ATC, INDU Solar Holdings, LLC, WRPC, and AMP Trillium, LLC, are included in the tables below:
	(Millions)	2014		2013		2012
	Income statement data
	Revenues	$	655.6	$	642	$	618.3
	Operating expenses	323.5		306.2		292.1
	Other expense	88.4		83.7		85.1
	Net income	$	243.7	$	252.1	$	241.1
	Earnings from equity method investments	$	88.3	$	91.4	$	87.2
Summarized balance sheet data of significant equity method investments
	(Millions)	31-Dec-14		31-Dec-13
	Balance sheet data
	Current assets	$	80.7	$	90.2
	Noncurrent assets	3,835.90		3,587.20
	Total assets	$	3,916.60	$	3,677.40
	Current liabilities	$	324	$	383.6
	Long-term debt	1,721.60		1,559.10
	Other noncurrent liabilities	173.2		134.4
	Shareholders’ equity	1,697.80		1,600.30
	Total liabilities and shareholders’ equity	$	3,916.60	$	3,677.40

GOODWILL_AND_OTHER_INTANGIBLE_1

GOODWILL AND OTHER INTANGIBLE ASSETS (Tables)	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of changes to the carrying amount of goodwill	The following table shows changes to our goodwill balances by segment during the years ended December 31, 2014, and 2013:
			Natural Gas Utility						Holding Company and Other				Total
	(Millions)		2014			2013			2014		2013		2014			2013
	Balance as of January 1
	Gross goodwill		$	933.5		$	933.5		$	19.6	$	15.8	$	953.1		$	949.3
	Accumulated impairment losses		(297.7		)	(297.7		)	—		—		(297.7		)	(297.7		)
	Net goodwill as of January 1		635.8			635.8			19.6		15.8		655.4			651.6
	Adjustment to ITF intellectual property *		—			—			—		3.8		—			3.8
	Balance as of December 31
	Gross goodwill		933.5			933.5			19.6		19.6		953.1			953.1
	Accumulated impairment losses		(297.7		)	(297.7		)	—		—		(297.7		)	(297.7		)
	Net goodwill as of December 31		$	635.8		$	635.8		$	19.6	$	19.6	$	655.4		$	655.4
	*	An immaterial adjustment was made to the gross goodwill balance at ITF in the second quarter of 2013 due to a correction to the life of certain intangible assets.
Schedule of identifiable intangible assets other than goodwill	The identifiable intangible assets other than goodwill listed below are part of other long-term assets on the balance sheets.
			31-Dec-14								31-Dec-13
	(Millions)		Gross Carrying			Accumulated			Net Carrying		Gross Carrying		Accumulated			Net Carrying
			Amount			Amortization			Amount		Amount		Amortization			Amount
	Amortized intangible assets
	Contractual service agreements (1)		$	15.6		$	(4.3	)	$	11.3	$	15.6	$	(1.8	)	$	13.8
	Customer-owned equipment modifications (2)		4			(1.2		)	2.8		4		(0.9		)	3.1
	Intellectual property (3)		3.4			(0.8		)	2.6		3.4		(0.5		)	2.9
	Nonregulated easements (4)		3.9			(1.4		)	2.5		3.7		(1.1		)	2.6
	Compressed natural gas fueling contract assets (5)		5.6			(3.6		)	2		5.6		(2.7		)	2.9
	Customer-related (6)		1.9			(0.3		)	1.6		1.9		(0.1		)	1.8
	Other		0.5			(0.3		)	0.2		0.5		(0.3		)	0.2
	Total		$	34.9		$	(11.9	)	$	23	$	34.7	$	(7.4	)	$	27.3
	Unamortized intangible assets
	MGU trade name		$	5.2		$	—		$	5.2	$	5.2	$	—		$	5.2
	Trillium trade name (7)		3.5			—			3.5		3.5		—			3.5
	Pinnacle trade name (7)		1.5			—			1.5		1.5		—			1.5
	Total intangible assets		$	45.1		$	(11.9	)	$	33.2	$	44.9	$	(7.4	)	$	37.5
	(1)	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. In October 2014, WPS received approval from the PSCW to upgrade the combustion turbine generators at the Fox Energy Center earlier than planned. As a result of this approval, WPS shortened the amortization period of one of its service agreements. The remaining weighted-average amortization period for these intangible assets at December 31, 2014, was approximately four years. Since WPS has approval from the PSCW to recover the value of its service agreements from customers over seven years, the increase in amortization due to the shorter amortization period is recorded to a regulatory asset. This regulatory asset will be amortized to reflect the seven-year recovery period.
	(2)	Relates to modifications made by PDI and ITF to customer-owned equipment. These intangible assets are amortized on a straight-line basis, with a remaining weighted-average amortization period at December 31, 2014, of approximately nine years.
	(3)	Represents the fair value of intellectual property at ITF related to a system for more efficiently compressing natural gas to allow for faster fueling. An immaterial adjustment was made to the intangible assets balance in the second quarter of 2013 as a result of a correction to the life of the intangible assets. The remaining amortization period at December 31, 2014, was approximately eight years.
	(4)	Relates to easements supporting a pipeline at PDI. The easements are amortized on a straight-line basis, with a remaining amortization period at December 31, 2014, of approximately nine years.
	(5)	Represents the fair value of ITF contracts acquired in September 2011. The remaining amortization period at December 31, 2014, was approximately six years.
	(6)	Represents customer relationship assets associated with ITF's compressed natural gas fueling operations. The remaining weighted-average amortization period for customer-related intangible assets at December 31, 2014, was approximately 12 years.
	(7)	Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle) are wholly owned subsidiaries of ITF.
Schedule of intangible asset amortization expense	The table below shows the amortization recorded during the years ended December 31:
	(Millions)		2014			2013			2012
	Amortization recorded in cost of sales		$	1.2		$	1.6		$	1.3
	Amortization recorded in depreciation and amortization expense		3			2.5			1
	Amortization recorded in regulatory assets		0.3			—			—
Schedule of intangible asset amortization expense for the next five years	Amortization for the next five years is estimated to be:
			For the Year Ending December 31
	(Millions)		2015			2016			2017		2018		2019
	Amortization to be recorded in cost of sales		$	1.1		$	0.9		$	0.9	$	0.8	$	0.6
	Amortization to be recorded in depreciation and amortization expense		3			2.9			2.4		1.9		1.9
	Amortization to be recorded in regulatory assets		1			1			0.5		—		—

LEASES_Tables

LEASES (Tables)	12 Months Ended
	Dec. 31, 2014
Leases [Abstract]
Schedule of future minimum rental obligations under noncancelable operating leases	Future minimum rental obligations under noncancelable operating leases are payable as follows:
	Year Ending December 31	Payments
	(Millions)
	2015	$	4.7
	2016	5
	2017	5.8
	2018	5.6
	2019	4.7
	Later years	47.6
	Total	$	73.4

SHORTTERM_DEBT_AND_LINES_OF_CR1

SHORT-TERM DEBT AND LINES OF CREDIT (Tables)	12 Months Ended
	Dec. 31, 2014
Short-term Debt [Abstract]
Schedule of short-term borrowings	Our outstanding short-term borrowings were as follows:
	(Millions, except percentages)		2014				2013				2012
	Commercial paper
	Amount outstanding at December 31 (1)		$	317.6			$	326			$	482.4
	Average interest rate on amount outstanding at December 31		0.36%				0.22		%		0.4		%
	Average amount outstanding during the year (2)		$	283			$	378.4			$	326.3
	Short-term notes payable (3)
	Average amount outstanding during the year (2)		$	—			$	130.4		(4)	$	—
	(1)	Maturity dates ranged from January 2, 2015, through January 16, 2015.
	(2)	Based on daily outstanding balances during the year.
	(3)	We did not have short-term notes payable outstanding at December 31, 2014, 2013, and 2012.
	(4)	Average amount outstanding of a $200.0 million loan used for the purchase of Fox Energy Company LLC. This loan was repaid in November 2013. See Note 3, Acquisitions, for more information regarding this purchase.
Schedule of revolving credit facilities and remaining available capacity	The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities as of December 31:
	(Millions)		Maturity		2014				2013
	Revolving credit facility (Integrys Energy Group) (1)		5/17/14		$	—			$	275
	Revolving credit facility (Integrys Energy Group) (1)		5/17/16		—				200
	Revolving credit facility (Integrys Energy Group) (2)		6/13/17		285				635
	Revolving credit facility (Integrys Energy Group)		5/8/19		465				—
	Revolving credit facility (WPS) (1)		5/17/14		—				135
	Revolving credit facility (WPS) (3)		5/7/15		135				—
	Revolving credit facility (WPS)		6/13/17		115				115
	Revolving credit facility (PGL)		6/13/17		250				250
	Total short-term credit capacity				$	1,250.00			$	1,610.00
	Less:
	Letters of credit issued inside credit facilities				$	3.4			$	52.4
	Commercial paper outstanding				317.6				326
	Available capacity under existing agreements				$	929			$	1,231.60

LONGTERM_DEBT_Tables

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Disclosure of long-term debt instruments
						31-Dec
	(Millions)					2014			2013
	WPS First Mortgage Bonds (1)
		Series		Year Due
		7.125	%	2023		$	0.1		$	0.1
	WPS Senior Notes (1)
		Series		Year Due
		6.375	%	2015		125			125
		5.65	%	2017		125			125
		6.08	%	2028		50			50
		5.55	%	2036		125			125
		3.671	%	2042		300			300
		4.752	%	2044		450			450
	PGL First and Refunding Mortgage Bonds (2)
		Series		Year Due
		QQ, 4.875%		2038	Mandatory interest reset date on November 1, 2018	—			75
		RR, 4.30%		2035	Mandatory interest reset date on June 1, 2016	50			50
		TT, 8.00%		2018		5			5
		UU, 4.63%		2019		75			75
		VV, 3.90%		2030		50			50
		WW, 2.625%		2033	Mandatory interest reset date on August 1, 2015	50			50
		XX, 2.21%		2016		50			50
		YY, 3.98%		2042		100			100
		ZZ, 4.00%		2033		50			50
		AAA, 3.96%		2043		220			220
		BBB, 4.21%		2044		200			—
	NSG First Mortgage Bonds (3)
		Series		Year Due
		P, 3.43%		2027		28			28
		Q, 3.96%		2043		54			54
	Integrys Energy Group Unsecured Senior Notes (4)
		Series		Year Due
		7.27	%	2014		—			100
		8	%	2016		55			55
		4.17	%	2020		250			250
	Integrys Energy Group Unsecured Junior Subordinated Notes (5)
		Series		Year Due
		6.11	%	2066	Interest to become variable on December 1, 2016	269.8			269.8
		6	%	2073	Mandatory interest reset date on August 1, 2023	400			400
	Total					3,081.90			3,056.90
	Unamortized discount on debt					(0.6		)	(0.7		)
	Total debt					3,081.30			3,056.20
	Less current portion					125			100
	Total long-term debt					$	2,956.30		$	2,956.20
	(1)	WPS's First Mortgage Bonds and Senior Notes are subject to the terms and conditions of WPS's First Mortgage Indenture dated January 1, 1941, as supplemented. Under the terms of the Indenture, substantially all property owned by WPS is pledged as collateral for these outstanding debt securities. All of these debt securities require semi-annual payments of interest. WPS Senior Notes become noncollateralized if WPS retires all of its outstanding First Mortgage Bonds and no new mortgage indenture is put in place.
	In December 2015, our 6.375% Senior Notes will mature. As a result, the $125 million balance of these notes was included in the current portion of long-term debt on our balance sheet at December 31, 2014.
	(2)	PGL's First Mortgage Bonds are subject to the terms and conditions of PGL's First Mortgage Indenture dated January 2, 1926, as supplemented. Under the terms of the Indenture, substantially all property owned by PGL is pledged as collateral for these outstanding debt securities.
	PGL has used certain First Mortgage Bonds to secure tax exempt interest rates. The Illinois Finance Authority has issued Tax Exempt Bonds, and the proceeds from the sale of these bonds were loaned to PGL. In return, PGL issued equal principal amounts of certain collateralized First Mortgage Bonds.
	In November 2014, PGL issued $200.0 million of 4.21% Series BBB Bonds. These bonds are due in November 2044. A portion of the proceeds was used to redeem PGL's $75.0 million 4.875% Series QQ Bonds.
	(3)	NSG's First Mortgage Bonds are subject to the terms and conditions of NSG's First Mortgage Indenture dated April 1, 1955, as supplemented. Under the terms of the Indenture, substantially all property owned by NSG is pledged as collateral for these outstanding debt securities.
	(4)	In June 2014, our $100.0 million of 7.27% Unsecured Senior Notes matured, and the outstanding principal balance was repaid.
	(5)	The 6.11% Junior Subordinated Notes are considered hybrid instruments with a combination of debt and equity characteristics. Under a replacement capital covenant with the holders of our 4.17% Unsecured Senior Notes due November 1, 2020, prior to December 1, 2036, any amounts redeemed or repurchased in excess of 10% of the principal amount outstanding must first be replaced with a specified amount of proceeds from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than, the applicable characteristics of the 6.11% Junior Subordinated Notes.
	The 6.00% Junior Subordinated Notes are considered hybrid instruments with a combination of debt and equity characteristics. There is no replacement capital covenant associated with these securities.
Schedule of all principal debt payment amounts related to bond maturities	A schedule of all principal debt payment amounts related to bond maturities is as follows:
	(Millions)		Payments
	2015		$	125
	2016		105
	2017		125
	2018		5
	2019		75
	Later years		2,646.90
	Total		$	3,081.90

ASSET_RETIREMENT_OBLIGATIONS_T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Schedule of changes to asset retirement obligations	The following table shows changes to our asset retirement obligations through December 31, 2014:
	(Millions)		Utilities				PDI		Total
	Asset retirement obligations at December 31, 2011		$	395.8			$	0.5	$	396.3
	Accretion		20.3				0.1		20.4
	Additions and revisions to estimated cash flows		(2.3		)		1.6		(0.7		)
	Settlements		(5.4		)		—		(5.4		)
	Asset retirement obligations at December 31, 2012		408.4				2.2		410.6
	Accretion		20.8				0.1		20.9
	Additions and revisions to estimated cash flows		70.1			*	0.5		70.6
	Settlements		(11.1		)		—		(11.1		)
	Asset retirement obligations at December 31, 2013		488.2				2.8		491
	Accretion		24.5				0.1		24.6
	Additions and revisions to estimated cash flows		(18.3		)	*	0.7		(17.6		)
	Settlements		(17.8		)		—		(17.8		)
	Asset retirement obligations at December 31, 2014		$	476.6			$	3.6	$	480.2
	*	Revisions were made to estimated cash flows related to asset retirement obligations primarily due to changes in the weighted average cost to retire natural gas distribution pipe at PGL.

INCOME_TAXES_Tables

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of principal components of deferred income tax assets and liabilities recognized in the balance sheets	The principal components of deferred income tax assets and liabilities recognized on the balance sheets as of December 31 are included in the table below. Certain temporary differences are netted in the table when the offsetting amount is recorded as a regulatory asset or liability. This is consistent with regulatory treatment.
	(Millions)	2014				2013
	Deferred income tax assets
	Tax credit carryforwards	$	116.7			$	113.5
	Price risk management	—				13
	Other	77.4				98.5
	Total deferred income tax assets	$	194.1			$	225
	Valuation allowance	(3.6		)		(8.2		)
	Net deferred income tax assets	$	190.5			$	216.8
	Deferred income tax liabilities
	Plant-related	$	1,584.10			$	1,373.80
	Regulatory deferrals	55.6				78.8
	Employee benefits	45.4				79.6
	Other	23				43.5
	Total deferred income tax liabilities	$	1,708.10			$	1,575.70
	Total net deferred income tax liabilities	$	1,517.60			$	1,358.90
	Balance sheet presentation
	Current deferred income tax assets	$	52.4			$	31.4
	Long-term deferred income tax liabilities	1,570.00				1,390.30
	Net deferred income tax liabilities	$	1,517.60			$	1,358.90
Schedule of Deferred Tax Asset expiration	Any deferred tax assets that are not used to offset future taxable income will expire between 2020 and 2033 as follows:
	(Millions)
	2020 through 2025	$	7.6
	2026 through 2031	2.9
	2032 through 2033	35.7
Schedule of components of the provision for income tax expense	The components of the provision for income taxes were as follows:
	(Millions)	2014				2013				2012
	Current provision
	Federal	$	19.9			$	1.6			$	(17.4	)
	State	25.2				4.7				(1.7		)
	Total current provision	45.1				6.3				(19.1		)
	Deferred provision
	Federal	123				134.1				119.8
	State	18.7				9.9				17.9
	Total deferred provision	141.7				144				137.7
	Investment tax credits
	Deferral	13.2				12.3				17.8
	Amortization	(5.2		)		(4.0		)		(12.6		)
	Penalties	—				(0.1		)		(0.3		)
	Unrecognized tax benefits	0.7				0.4				(2.9		)
	Interest	(2.1		)		(0.9		)		(2.7		)
	Total provision for income taxes related to continuing operations	193.4				158				117.9
	Total provision for income taxes related to discontinued operations	7.2				45.9				22.6
	Total	$	200.6			$	203.9			$	140.5
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement	The following table presents a reconciliation of the difference between the effective tax rate and the amount computed by applying the statutory federal tax rate to income from continuing operations before taxes.
		2014							2013						2012
	(Millions, except for percentages)	Rate			Amount				Rate			Amount			Rate		Amount
	Statutory federal income tax	35	%		$	165			35	%		$	148.9		35	%	$	124.9
	State income taxes, net	7.5		*	35.5			*	3.7			15.9			4.9		17.6
	Benefits and compensation	(0.9	)		(4.3		)		(1.0	)		(4.1		)	(2.6	)	(9.3		)
	Other differences, net	(0.6	)		(2.8		)		(0.6	)		(2.7		)	(4.3	)	(15.3		)
	Effective income tax	41	%		$	193.4			37.1	%		$	158		33	%	$	117.9
Reconciliation of the beginning and ending amount of unrecognized tax benefits	A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
	(Millions)	2014				2013				2012
	Balance at January 1	$	3.6			$	11.3			$	22.4
	Increase related to tax positions taken in prior years	—				2.2				0.9
	Decrease related to tax positions taken in prior years	(0.1		)		(8.7		)		(6.7		)
	Increase related to tax positions taken in current year	0.5				0.3				0.6
	Decrease related to settlements	—				(1.5		)		(5.7		)
	Decrease related to lapse of statutes	(0.7		)		—				(0.2		)
	Balance at December 31	$	3.3			$	3.6			$	11.3
Schedule of the earliest open tax years that were subject to examination by state taxing authorities by major operating jurisdictions	As of December 31, 2014, we were subject to examination by state or local tax authorities for the 2008 through 2013 tax years in our major state operating jurisdictions as follows:
	State	Year
	Illinois	2008
	Michigan	2008
	Minnesota	2011
	Wisconsin	2010

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014, including those of our subsidiaries.
					Payments Due By Period
	(Millions)	Date Contracts Extend Through	Total Amounts Committed		2015		2016		2017		2018		2019		Later Years
	Natural gas utility supply and transportation	2028	$	722.6	$	196.6	$	170.4	$	132.9	$	78.2	$	50.9	$	93.6
	Electric utility
	Purchased power	2029	836.8		122.8		42.8		53.3		55.9		57		505
	Coal supply and transportation	2019	162.8		55.3		31.9		32.6		31.9		11.1		—
	Total		$	1,722.20	$	374.7	$	245.1	$	218.8	$	166	$	119	$	598.6

EMPLOYEE_BENEFIT_PLANS_Tables

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Reconciliation of the changes in the plans' benefit obligations and fair value of assets	The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets:
			Pension Benefits						Other Benefits
	(Millions)		2014			2013			2014			2013
	Change in benefit obligation
	Obligation at January 1		$	1,641.70		$	1,784.90		$	576.3		$	621
	Service cost		24.8			30.2			21			24.9
	Interest cost		76.2			71.2			23.5			24.8
	Plan amendments		—			—			(90.4		)	0.2
	Divestitures - UPPCO		(100.4		)	—			(22.3		)	—
	Actuarial loss (gain), net		166.1			(153.1		)	33.1			(73.4		)
	Participant contributions		—			—			10			10.6
	Benefit payments		(102.7		)	(91.5		)	(33.3		)	(34.0		)
	Federal subsidy on benefits paid		—			—			2.1			2.2
	Obligation at December 31		$	1,705.70		$	1,641.70		$	520		$	576.3
	Change in fair value of plan assets
	Fair value of plan assets at January 1		$	1,527.70		$	1,348.10		$	470.1		$	424.4
	Actual return on plan assets		94.6			205.4			18.2			57.8
	Employer contributions		98.8			65.7			10			11.3
	Participant contributions		—			—			10			10.6
	Divestitures - UPPCO		(122.8		)	—			(27.3		)	—
	Benefit payments		(102.7		)	(91.5		)	(33.3		)	(34.0		)
	Fair value of plan assets at December 31		$	1,495.60		$	1,527.70		$	447.7		$	470.1
	Funded Status at December 31		$	(210.1	)	$	(114.0	)	$	(72.3	)	$	(106.2	)
Amounts recognized on the balance sheets at December 31 related to the funded status of the benefit plans	The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:
			Pension Benefits						Other Benefits
	(Millions)		2014			2013			2014			2013
	Long-term assets		$	—		$	—		$	1.5		$	—
	Current liabilities		9.1			8.9			0.2			0.2
	Liabilities held for sale		—			6.9			—			3.4
	Long-term liabilities		201			98.2			73.6			102.6
	Total net liabilities		$	(210.1	)	$	(114.0	)	$	(72.3	)	$	(106.2	)
Information for pension plans with an accumulated benefit obligation in excess of plan assets	The following table shows information for the non-qualified pension plans for which we have an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these non-qualified pension plans. Amounts presented are as of December 31:
	(Millions)		2014			2013
	Projected benefit obligation		$	64.1		$	65.4
	Accumulated benefit obligation		61.2			63
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 Benefits						Other Benefits
	(Millions)		2014			2013			2014			2013
	Accumulated other comprehensive loss (pre-tax) (1)
	Net actuarial loss		$	40.2		$	33.3		$	0.2		$	0.7
	Prior service credits		—			—			(0.1		)	(0.2		)
	Total		$	40.2		$	33.3		$	0.1		$	0.5
	Net regulatory assets (2)
	Net actuarial loss		$	501		$	356.2		$	50.4		$	6.2
	Prior service costs (credits)		1.8			2.4			(85.3		)	(12.4		)
	Total		$	502.8		$	358.6		$	(34.9	)	$	(6.2	)
	(1)	Amounts related to the nonregulated entities are included in accumulated other comprehensive loss.
	(2)	Amounts related to the utilities are recorded as net regulatory assets or liabilities.
Estimated amounts that will be amortized into net periodic benefit cost	The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2015:
	(Millions)		Pension Benefits			Other Benefits
	Net actuarial loss		$	43.2		$	4.4
	Prior service costs (credits)		0.2			(10.3		)
	Total 2015 – estimated amortization		$	43.4		$	(5.9	)
Schedule of the components of net periodic benefit cost	The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheets) for our benefit plans:
			Pension Benefits									Other Benefits
	(Millions)		2014			2013			2012			2014			2013			2012
	Service cost		$	24.8		$	30.2		$	46		$	21		$	24.9		$	20.8
	Interest cost		76.2			71.2			78			23.5			24.8			28.5
	Expected return on plan assets		(112.4		)	(105.5		)	(107.9		)	(33.0		)	(30.6		)	(28.2		)
	Loss on plan settlement		0.9			—			—			—			—			—
	Amortization of transition obligation		—			—			—			—			—			0.3
	Amortization of prior service cost (credit)		0.6			4			5			(9.4		)	(2.5		)	(3.4		)
	Amortization of net actuarial loss		33.3			56.7			34			3.2			8.4			6.6
	Net periodic benefit cost		$	23.4		$	56.6		$	55.1		$	5.3		$	25		$	24.6
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 Benefits			Other Benefits
			2014		2013	2014		2013
	Discount rate		4.08%		4.92%	4.00%		4.83%
	Rate of compensation increase		4.23%		4.24%	N/A		N/A
	Assumed medical cost trend rate		N/A		N/A	6.00%		6.50%
	Ultimate trend rate		N/A		N/A	5.00%		5.00%
	Year ultimate trend rate is reached		N/A		N/A	2023		2019
	Assumed dental cost trend rate		N/A		N/A	5.00%		5.00%
	The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31:
			Pension Benefits
			2014		2013	2012
	Discount rate		4.92%		4.07%	5.10%
	Expected return on assets		8.00%		8.00%	8.25%
	Rate of compensation increase		4.23%		4.25%	4.25%
			Other Benefits
			2014		2013	2012
	Discount rate		4.65%		3.96%	4.94%
	Expected return on assets		8.00%		8.00%	8.25%
	Assumed medical cost trend rate (under age 65)		6.50%		7.00%	7.00%
	Ultimate trend rate		5.00%		5.00%	5.00%
	Year ultimate trend rate is reached		2019		2019	2016
	Assumed medical cost trend rate (over age 65)		6.50%		7.00%	7.50%
	Ultimate trend rate		5.00%		5.00%	5.50%
	Year ultimate trend rate is reached		2019		2019	2016
	Assumed dental cost trend rate		5.00%		5.00%	5.00%
Effects of a one-percentage-point change in assumed health care cost trend rates	For the year ended December 31, 2014, a one-percentage-point change in assumed health care cost trend rates would have had the following effects:
			One-Percentage-Point
	(Millions)		Increase			Decrease
	Effect on total of service and interest cost components of net periodic postretirement health care benefit cost		$	6.1		$	(5.0	)
	Effect on the health care component of the accumulated postretirement benefit obligation		58.7			(55.1		)
Investments recorded at fair value, by asset class	The following tables provide the fair values of our investments by asset class:
			December 31, 2014
			Pension Plan Assets												Other Benefit Plan Assets
	(Millions)		Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3		Total
	Asset Class
	Cash and cash equivalents		$	—		$	42.3		$	—		$	42.3		$	8.5		$	2.6		$	—	$	11.1
	Equity securities:
	United States equity		91			336.2			—			427.2			20.6			122.8			—		143.4
	International equity		92.4			383.9			—			476.3			18.7			117.8			—		136.5
	Fixed income securities:
	United States government		70.3			21.6			—			91.9			111.1			—			—		111.1
	Foreign government		—			20.6			—			20.6			—			—			—		—
	Corporate debt		—			425.7			—			425.7			—			—			—		—
	Other		—			53.5			—			53.5			1			—			—		1
			253.7			1,283.80			—			1,537.50			159.9			243.2			—		403.1
	401(h) other benefit plan assets invested as pension assets (1)		(7.4		)	(37.2		)	—			(44.6		)	7.4			37.2			—		44.6
	Total (2)		$	246.3		$	1,246.60		$	—		$	1,492.90		$	167.3		$	280.4		$	—	$	447.7
	(1)	Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).
	(2)	Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.
			December 31, 2013
			Pension Plan Assets												Other Benefit Plan Assets
	(Millions)		Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3		Total
	Asset Class
	Cash and cash equivalents		$	2		$	36.6		$	—		$	38.6		$	—		$	4		$	—	$	4
	Equity securities:
	United States equity		100.4			445.1			—			545.5			21.4			132.2			—		153.6
	International equity		114.1			429			—			543.1			19.5			125.5			—		145
	Fixed income securities:
	United States government		—			93.6			—			93.6			121.2			0.7			—		121.9
	Foreign government		—			16.9			2.4			19.3			—			—			—		—
	Corporate debt		—			250			1.3			251.3			—			—			—		—
	Asset-backed securities		—			61.8			—			61.8			—			—			—		—
	Other		—			17.4			—			17.4			1			—			—		1
			216.5			1,350.40			3.7			1,570.60			163.1			262.4			—		425.5
	401(h) other benefit plan assets invested as pension assets (1)		(6.1		)	(37.9		)	(0.1		)	(44.1		)	6.1			37.9			0.1		44.1
	Total (2)		$	210.4		$	1,312.50		$	3.6		$	1,526.50		$	169.2		$	300.3		$	0.1	$	469.6
	(1)	Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).
	(2)	Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.
Reconciliation of changes in the fair value of pension assets categorized as Level 3 measurements	The following tables set forth a reconciliation of changes in the fair value of pension plan assets categorized as Level 3 in the fair value hierarchy:
	(Millions)		Foreign Government Debt			Corporate Debt			Total
	Beginning balance at January 1, 2014		$	2.4		$	1.3		$	3.7
	Sales		(2.4		)	(1.3		)	(3.7		)
	Ending balance at December 31, 2014		$	—		$	—		$	—
	Net unrealized gains (losses) related to assets still held at the end of the period		$	—		$	—		$	—
	(Millions)		Foreign Government Debt			Corporate Debt			Asset-Backed Securities			Total
	Beginning balance at January 1, 2013		$	4.1		$	1		$	0.1		$	5.2
	Net realized and unrealized losses		(0.3		)	(0.4		)	—			(0.7		)
	Purchases		0.6			—			—			0.6
	Sales		(2.0		)	(0.4		)	—			(2.4		)
	Transfers into Level 3		—			1.4			—			1.4
	Transfers out of Level 3		—			(0.3		)	(0.1		)	(0.4		)
	Ending balance at December 31, 2013		$	2.4		$	1.3		$	—		$	3.7
	Net unrealized losses related to assets still held at the end of the period		$	(0.2	)	$	(0.3	)	$	—		$	(0.5	)
Schedule of expected payments for pension and other postretirement benefits and expected federal subsidies which will partially offset other postretirement benefits	The following table shows the payments, reflecting expected future service, that we expect to make for pension and other postretirement benefits.
	(Millions)		Pension Benefits			Other Benefits
	2015		$	124.6		$	23.7
	2016		122.3			26
	2017		127.6			28.4
	2018		126			30.6
	2019		136.5			33.3
	2020 through 2024		644.4			195.8

PREFERRED_STOCK_OF_SUBSIDIARY_

PREFERRED STOCK OF SUBSIDIARY (Tables) (WPS, Preferred stock)	12 Months Ended
	Dec. 31, 2014
WPS | Preferred stock
Preferred stock of subsidiary
Schedule of outstanding shares of preferred stock owned by third parties	Outstanding shares owned by third parties were as follows at December 31:
	(Millions, except share amounts)	2014			2013
	Series	Shares Outstanding	Carrying Value		Shares Outstanding	Carrying Value
	5.00%	130,692	$	13.1	130,692	$	13.1
	5.04%	29,898	3		29,898	3
	5.08%	49,905	5		49,905	5
	6.76%	150,000	15		150,000	15
	6.88%	150,000	15		150,000	15
	Total	510,495	$	51.1	510,495	$	51.1

COMMON_EQUITY_Tables

COMMON EQUITY (Tables)	12 Months Ended
	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
Roll forward of issued common stock	We had the following changes to issued common stock:
	Balance at December 31, 2011		78,287,906
	Balance at December 31, 2012 *		78,287,906
	Shares issued
	Stock-based compensation		972,718
	Stock Investment Plan		298,532
	Employee Stock Ownership Plan		248,724
	Rabbi trust shares		111,296
	Balance at December 31, 2013		79,919,176
	Shares issued
	Stock Investment Plan		12,151
	Employee Stock Ownership Plan		31,764
	Balance at December 31, 2014		79,963,091
	*	We did not issue equity during 2012.
Schedule of common stock activity to meet requirements of our stock investment plan and stock-based employee benefit and compensation plans	The following table provides a summary of common stock activity to meet the requirements of our Stock Investment Plan and certain stock-based employee benefit and compensation plans:
	Period		Method of meeting requirements
	Beginning 02/05/2014		Purchasing shares on the open market
	02/05/2013 – 02/04/2014		Issued new shares
	01/01/2012 – 02/04/2013		Purchased shares on the open market
Reconciliation of shares issued and outstanding	The following table reconciles common shares issued and outstanding:
			2014							2013
			Shares			Average Cost *				Shares			Average Cost *
	Common stock issued		79,963,091							79,919,176
	Less:
	Deferred compensation rabbi trust		428,920			$	48.73			473,796			$	48.5
	Total common shares outstanding		79,534,171							79,445,380
	*	Based on our stock price on the day the shares entered the deferred compensation rabbi trust. Shares paid out of the trust are valued at the average cost of shares in the trust.
Computation of basic and diluted earnings per share	The following table reconciles our computation of basic and diluted earnings per share:
	(Millions, except per share amounts)		2014				2013				2012
	Numerator:
	Net income from continuing operations		$	278.1			$	267.5			$	238.9
	Discontinued operations, net of tax		1.8				87.3				45.4
	Preferred stock dividends of subsidiary		(3.1		)		(3.1		)		(3.1		)
	Noncontrolling interest in subsidiaries		0.1				0.1				0.2
	Net income attributed to common shareholders — basic		$	276.9			$	351.8			$	281.4
	Effect of dilutive securities
	Deferred compensation		—				(0.1		)		—
	Net income attributed to common shareholders — diluted		$	276.9			$	351.7			$	281.4
	Denominator:
	Average shares of common stock — basic		80.2				79.5				78.6
	Effect of dilutive securities
	Stock-based compensation		0.5				0.4				0.5
	Deferred compensation		—				0.2				0.2
	Average shares of common stock — diluted		80.7				80.1				79.3
	Earnings per common share
	Basic		$	3.45			$	4.43			$	3.58
	Diluted		3.43				4.39				3.55
Schedule of antidilutive securities	The calculation of diluted earnings per share excluded the following weighted-average outstanding securities that had an anti-dilutive effect:
	(Millions)		2014			2013			2012
	Stock-based compensation		0.2			0.3			0.7
	Deferred compensation		0.3			0.1			—
Capital transactions with subsidiaries	During 2014, capital transactions with subsidiaries were as follows (in millions):
	Subsidiary		Dividends To Parent				Return Of				Equity Contributions
							Capital To Parent				From Parent
	IBS		$	—			$	—			$	25
	ITF (1)		—				—				50.3
	MERC		—				27				20
	MGU		—				13				7
	PGL(1)		—				—				65
	UPPCO		—				12.5				94.4
	WPS		111.8				—				55
	WPS Investments, LLC (2)		74.3				—				17
	Total		$	186.1			$	52.5			$	333.7
	(1)	ITF and PGL are direct wholly owned subsidiaries of PELLC. As a result, they make distributions to PELLC, and receive equity contributions from PELLC. Subject to applicable law, PELLC does not have any dividend restrictions or limitations on distributions to us.
	(2)	WPS Investments, LLC is a consolidated subsidiary that is jointly owned by us and WPS. In August 2014, UPPCO's ownership interest in WPS Investments, LLC was transferred to us as a result of the sale of UPPCO. At December 31, 2014, the ownership interest held by us and WPS was 89.02% and 10.98%, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2014, all equity contributions to WPS Investments, LLC were made solely by us.

ACCUMULATED_OTHER_COMPREHENSIV1

ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)	12 Months Ended
	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Schedule of changes, net of tax, in accumulated other comprehensive loss	The following table shows the changes, net of tax, to our accumulated other comprehensive loss:
									Accumulated Other Comprehensive Loss
	(Millions)		Cash Flow Hedges			Defined Benefit Plans
	Balance at December 31, 2012		$	(5.2	)	$	(35.7	)	$	(40.9	)
	Other comprehensive income before reclassifications		0.7			13.2			13.9
	Amounts reclassified out of accumulated other comprehensive loss		1.4			2.4			3.8
	Net 2013 other comprehensive income		2.1			15.6			17.7
	Balance at December 31, 2013		(3.1		)	(20.1		)	(23.2		)
	Other comprehensive loss before reclassifications		—			(6.0		)	(6.0		)
	Amounts reclassified out of accumulated other comprehensive loss		(0.1		)	1.7			1.6
	Net 2014 other comprehensive loss		(0.1		)	(4.3		)	(4.4		)
	Balance at December 31, 2014		$	(3.2	)	$	(24.4	)	$	(27.6	)
Schedule of reclassifications out of accumulated other comprehensive loss	The following table shows the reclassifications out of accumulated other comprehensive loss during the years ended December 31:
			Amount Reclassified
	(Millions)		2014			2013			Affected Line Item in the Statements of Income
	Losses (gains) on cash flow hedges
	Utility commodity derivative contracts		$	—		$	0.2		Operating and maintenance expense (1) (2)
	Nonregulated commodity derivative contracts		—			3.7			Discontinued operations (2)
	Interest rate hedges		1.1			1.1			Interest expense
			1.1			5			Total before tax
			1.2			3.6			Tax expense
			(0.1		)	1.4			Net of tax
	Defined benefit plans
	Amortization of prior service costs (credits)		(0.2		)	4.3			(3)
	Amortization of net actuarial losses (gains)		2.7			(0.2		)	(3)
			2.5			4.1			Total before tax
			0.8			1.7			Tax expense
			1.7			2.4			Net of tax
	Total reclassifications		$	1.6		$	3.8
	(1)	This item relates to changes in the price of natural gas used to support utility operations.
	(2)	We no longer designate commodity contracts as cash flow hedges.
	(3)	These items are included in the computation of net periodic benefit cost. See Note 18, Employee Benefit Plans, for more information.

GUARANTEES_Tables

GUARANTEES (Tables)	12 Months Ended
	Dec. 31, 2014
Guarantees [Abstract]
Schedule of outstanding guarantees	The following table shows our outstanding guarantees:
			Total Amounts Committed		Expiration
	(Millions)		at December 31, 2014		Less Than 1 Year		1 to 3 Years		Over 3 Years
	Guarantees supporting commodity transactions of subsidiaries (1)		$	189.3	$	105.1	$	—	$	84.2
	Standby letters of credit (2)		1.2		1.1		0.1		—
	Surety bonds (3)		25.1		25		0.1		—
	Other guarantees (4)		73.5		—		—		73.5
	Guarantees temporarily retained related to the sale of IES's retail energy business (5)		279.5		$	248.4	$	1.8	$	29.3
	Total guarantees		$	568.6	$	379.6	$	2	$	187
	(1)	Consists of (a) $5.0 million to support the business operations of IBS, and (b) $0.4 million, $127.4 million, $44.7 million, and $11.8 million related to natural gas supply at ITF, MERC, MGU, and PDI, respectively. These guarantees are not reflected on our balance sheets.
	(2)	At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. This amount consists of $1.2 million issued to support ITF, MERC, MGU, NSG, PDI, PGL, and WPS. These amounts are not reflected on our balance sheets.
	(3)	Primarily for the construction and operation of compressed natural gas fueling stations, workers compensation self-insurance programs, and obtaining various licenses, permits, and rights-of-way. These guarantees are not reflected on our balance sheets.
	(4)	Consists of (a) $46.1 million to support PDI's future payment obligations related to its distributed solar generation projects; (b) $10.0 million related to the sale agreement for IES’s Texas retail marketing business. An insignificant liability was recorded related to the possible imposition of additional miscellaneous gross receipts tax in the event of a change in law or interpretation of the tax law; (c) $11.2 million related to the performance of an operating and maintenance agreement by ITF; and (d) $6.2 million related to other indemnifications primarily for workers compensation coverage. The amounts discussed in items (a), (c), and (d) above are not reflected on our balance sheets.
	(5)	These guarantees are retained temporarily due to the sale of IES's retail energy business to Exelon Generation Company, LLC (Exelon). For up to six months after the sale, we will continue to provide these guarantees until either Exelon can replace them or until they expire. Exelon is contractually bound to reimburse us for any payments we make under the outstanding guarantees. These guarantees consist of (a) $267.4 million of guarantees supporting commodity transactions; (b) $6.9 million of standby letters of credit; (c) $3.4 million of surety bonds; and (d) $1.8 million related to the sale of WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC. Following the guidance of the Guarantees Topic of the FASB ASC, an insignificant liability related to these guarantees was recorded at fair value on our balance sheet. Our exposure under these guarantees related to open transactions at December 31, 2014, was $168.9 million.

STOCKBASED_COMPENSATION_Tables

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of stock-based compensation expense and the related deferred tax benefit recognized in income	The following table reflects the stock-based compensation expense and the related deferred income tax benefit recognized in income for the years ended December 31:
	(Millions)		2014				2013			2012
	Stock options		$	2.7			$	1.8		$	2
	Performance stock rights		16.8				2.7			5
	Restricted share units		9.9				8.6			8.1
	Nonemployee director deferred stock units		0.8				0.9			1
	Total stock-based compensation expense		$	30.2			$	14		$	16.1
	Deferred income tax benefit		$	12.1			$	5.6		$	6.4
Schedule of weighted-average fair values per stock option granted along with the assumptions incorporated into the valuation models	The following table shows the weighted-average fair values per stock option granted along with the assumptions incorporated into the binomial lattice valuation models:
			2014 Grant		2013 Grant		2012 Grant
	Weighted-average fair value per stock option		6.7		6.03		6.3
	Expected term		8 years		5 years		5 years
	Risk-free interest rate		0.12% – 2.88%		0.18% – 2.11%		0.17% – 2.18%
	Expected dividend yield		5.28%		5.33%		5.28%
	Expected volatility		18%		24%		25%
Summary of stock option activity and information related to outstanding and exercisable stock options	A summary of stock option activity for 2014, and information related to outstanding and exercisable stock options at December 31, 2014, is presented below:
			Stock Options			Weighted-Average			Weighted-Average		Aggregate
						Exercise Price Per			Remaining		Intrinsic Value
						Share			Contractual Life		(Millions)
									(in Years)
	Outstanding at December 31, 2013		1,550,374			$	50.93
	Granted		264,332			55.23
	Exercised		(1,676,831	)		51.33
	Forfeited		(3,858	)		55.23
	Outstanding at December 31, 2014		134,017			$	54.31		6.6		$	3.2
	Exercisable at December 31, 2014		59,714			$	55.21		5.6		$	1.4
Schedule of assumptions incorporated into the valuation models for performance stock rights	The table below reflects the assumptions used in the Monte Carlo valuation models to estimate the fair value of the outstanding performance stock rights at December 31:
			2014		2013		2012
	Risk-free interest rate		0.21% – 0.63%		0.13% – 1.27%		0.17% – 1.27%
	Expected dividend yield		5.25% – 5.33%		5.28% – 5.34%		5.18% – 5.34%
	Expected volatility		18% – 22%		15% – 36%		14% – 36%
Information related to share based awards
Summary of the activity related to restricted share unit awards (equity and liability awards)	A summary of the 2014 activity related to all restricted share unit awards (equity and liability awards) is presented below:
			Restricted Share			Weighted-Average Grant Date Fair Value
			Unit Awards
	Outstanding at December 31, 2013		511,301			$	52.24
	Granted		214,953			55.23
	Dividend equivalents		21,422			54.47
	Vested and released		(208,964	)		49.76
	Forfeited		(111,407	)		54.62
	Outstanding at December 31, 2014		427,305			$	54.45
Performance Stock Rights Accounted For As Equity Awards
Information related to share based awards
Summary of the activity related to performance stock rights	A summary of the 2014 activity related to performance stock rights accounted for as equity awards is presented below:
			Performance			Weighted-Average
			Stock Rights			Fair Value (2)
	Outstanding at December 31, 2013		85,749			$	46.62
	Granted		21,146			44.28
	Award modifications		64,612			85.09
	Distributed (1)		(74,345	)		77.67
	Adjustment for estimated payout and shares not distributed (1)		(28,591	)		52.67
	Forfeited		(308	)		44.28
	Outstanding at December 31, 2014		68,263			$	58.54
	(1)	No shares of common stock were distributed for performance stock rights with a performance period ending December 31, 2013, because the performance percentage was below the threshold payout level. In October 2014, our Board of Directors approved the acceleration of a portion of the estimated distribution for those performance stock rights held by active employees with a performance period ending December 31, 2014. This distribution was made in December 2014.
	(2)	Reflects the weighted-average fair value used to measure equity awards. Equity awards are measured using the grant date fair value or the fair value on the modification date.
Performance Stock Rights Accounted For As Liability Awards
Information related to share based awards
Summary of the activity related to performance stock rights	A summary of the 2014 activity related to performance stock rights accounted for as liability awards is presented below:
			Performance
			Stock Rights
	Outstanding at December 31, 2013		198,904
	Granted		84,529
	Award modifications		(64,612	)
	Distributed *		(10,760	)
	Adjustment for estimated payout and shares not distributed *		(36,519	)
	Forfeited		(1,234	)
	Outstanding at December 31, 2014		170,308
	*	No shares of common stock were distributed for performance stock rights with a performance period ending December 31, 2013, because the performance percentage was below the threshold payout level. In October 2014, our Board of Directors approved the acceleration of a portion of the estimated distribution for those performance stock rights held by active employees with a performance period ending December 31, 2014. This distribution was made in December 2014.

FAIR_VALUE_Tables

FAIR VALUE (Tables)	12 Months Ended
	Dec. 31, 2014
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 show assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:
			31-Dec-14
	(Millions)		Level 1			Level 2			Level 3			Total
	Assets
	Risk Management Assets
	Natural gas contracts		$	—		$	2.3		$	—		$	2.3
	Financial transmission rights (FTRs)		—			—			2.2			2.2
	Coal contracts		—			—			—			—
	Total Risk Management Assets		$	—		$	2.3		$	2.2		$	4.5
	Investment in Exchange-Traded Funds		$	102.4		$	—		$	—		$	102.4
	Liabilities
	Risk Management Liabilities
	Natural gas contracts		$	4.8		$	31.2		$	6.6		$	42.6
	FTRs		—			—			0.3			0.3
	Petroleum product contracts		2.8			—			—			2.8
	Coal contracts		—			1.2			2.2			3.4
	Total Risk Management Liabilities		$	7.6		$	32.4		$	9.1		$	49.1
			December 31, 2013
	(Millions)		Level 1			Level 2			Level 3			Total
	Assets
	Risk Management Assets
	Natural gas contracts		$	2.4		$	7.7		$	—		$	10.1
	FTRs		—			—			1.5			1.5
	Petroleum product contracts		0.1			—			—			0.1
	Coal contracts		—			—			0.2			0.2
	Total Risk Management Assets		$	2.5		$	7.7		$	1.7		$	11.9
	Investment in Exchange-Traded Funds		$	15.9		$	—		$	—		$	15.9
	Liabilities
	Risk Management Liabilities
	Natural gas contracts		$	0.5		$	0.6		$	—		$	1.1
	FTRs		—			—			0.3			0.3
	Coal contracts		—			—			2.7			2.7
	Total Risk Management Liabilities		$	0.5		$	0.6		$	3		$	4.1
Significant unobservable inputs used in the valuation of derivatives categorized in Level 3	The significant unobservable inputs used in the valuations that resulted in categorization within Level 3 were as follows at December 31, 2014. The amounts listed in the table below represent the range of unobservable inputs that individually had a significant impact on the fair value determination and caused a transaction to be classified as Level 3.
			Fair Value (Millions)
			Assets			Liabilities			Valuation Technique		Unobservable Input	Average or Range
	Natural gas contracts		$	—		$	6.6		Income-based		Option volatilities (1)	50.5% – 67.2%
	FTRs		2.2			0.3			Market-based		Forward market prices ($/megawatt-month) (2)	$188.16
	Coal contracts		—			2.2			Market-based		Forward market prices ($/ton) (3)	$10.89 – $13.60
	(1)	Represents the range of volatilities used in the valuation of options. Volatilities are derived from an internal model based on volatility curves from third parties.
	(2)	Represents forward market prices developed using historical cleared pricing data from MISO.
	(3)	Represents third-party forward market pricing.
Reconciliation of changes in level 3 fair value measurements	The following tables set forth a reconciliation of changes in the fair value of items categorized as Level 3 measurements:
			2014
	(Millions)		Natural Gas Contracts			FTRs			Coal Contracts			Total
	Balance at the beginning of the period		$	—		$	1.2		$	(2.5	)	$	(1.3	)
	Net realized and unrealized gains included in earnings		—			0.2			—			0.2
	Net unrealized (losses) gains recorded as regulatory assets or liabilities		(6.6		)	0.4			(1.6		)	(7.8		)
	Purchases		—			4.3			—			4.3
	Settlements		—			(4.2		)	0.7			(3.5		)
	Net transfers out of Level 3		—			—			1.2			1.2
	Balance at the end of the period		$	(6.6	)	$	1.9		$	(2.2	)	$	(6.9	)
			2013
	(Millions)		FTRs			Coal Contracts			Total
	Balance at the beginning of the period		$	1.1		$	(6.5	)	$	(5.4	)
	Net realized and unrealized gains included in earnings		3			—			3
	Net unrealized (losses) gains recorded as regulatory assets or liabilities		(0.1		)	0.4			0.3
	Purchases		3.2			—			3.2
	Sales		(0.2		)	—			(0.2		)
	Settlements		(5.8		)	3.6			(2.2		)
	Balance at the end of the period		$	1.2		$	(2.5	)	$	(1.3	)
			2012
	(Millions)		FTRs			Coal Contracts			Total
	Balance at the beginning of the period		$	1.2		$	(6.9	)	$	(5.7	)
	Net realized and unrealized gains included in earnings		1.8			—			1.8
	Net unrealized (losses) gains recorded as regulatory assets or liabilities		(0.1		)	5.8			5.7
	Purchases		2.8			—			2.8
	Sales		(0.1		)	—			(0.1		)
	Settlements		(4.5		)	(5.4		)	(9.9		)
	Balance at the end of the period		$	1.1		$	(6.5	)	$	(5.4	)
Schedule of carrying value and estimated fair value of financial instruments	The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:
			31-Dec-14						31-Dec-13
	(Millions)		Carrying Amount			Fair Value			Carrying Amount			Fair Value
	Long-term debt		$	3,081.30		$	3,271.40		$	3,056.20		$	3,031.60
	Preferred stock of subsidiary		51.1			51.8			51.1			61.2

MISCELLANEOUS_INCOME_Tables

MISCELLANEOUS INCOME (Tables)	12 Months Ended
	Dec. 31, 2014
Other Income and Expenses [Abstract]
Schedule of miscellaneous income	Total miscellaneous income was as follows at December 31:
	(Millions)	2014		2013		2012
	Equity portion of AFUDC	$	12.5	$	10.8	$	2.9
	Federal excise tax credit	4.4		4.1		—
	Gain on sale of land at the holding company	3.5		—		—
	Key executive life insurance income for retired employees	2.9		2.2		2.6
	Gains on exchange-traded funds	2.9		2.2		1.3
	Other	4.8		2.6		2.2
	Total miscellaneous income	$	31	$	21.9	$	9

SEGMENTS_OF_BUSINESS_Tables

SEGMENTS OF BUSINESS (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Schedule of information related to reportable segments	The tables below present information related to our reportable segments:
		Regulated Operations											Nonutility and Nonregulated Operations
	2014 (Millions)	Natural Gas			Electric			Electric		Total			IES		Holding			Reconciling			Integrys
		Utility			Utility			Transmission		Regulated					Company			Eliminations			Energy Group
								Investment		Operations					and Other						Consolidated
	Income Statement
	External revenues	$	2,748.00		$	1,286.30		$	—	$	4,034.30		$	—	$	109.9		$	—		$	4,144.20
	Intersegment revenues	12.4			0.1			—		12.5			—		1.4			(13.9		)	—
	Depreciation and amortization expense	149			103			—		252			—		36			(0.5		)	287.5
	Merger transaction costs	—			—			—		—			—		10.4			—			10.4
	Gain on sale of UPPCO, net of transaction costs	—			(85.4		)	—		(85.4		)	—		—			—			(85.4		)
	Gain on abandonment of PDI's Winnebago Energy Center	—			—			—		—			—		(5.0		)	—			(5.0		)
	Earnings from equity method investments	—			—			85.7		85.7			—		2.6			—			88.3
	Miscellaneous income	1.9			11.1			—		13			—		29.8			(11.8		)	31
	Interest expense	54.4			47.4			—		101.8			—		64.8			(11.8		)	154.8
	Provision (benefit) for income taxes	65.6			103.3			34.4		203.3			—		(9.9		)	—			193.4
	Net income (loss) from continuing operations	100.7			166.3			51.3		318.3			—		(40.2		)	—			278.1
	Discontinued operations	—			—			—		—			0.4		1.4			—			1.8
	Preferred stock dividends of subsidiary	(0.5		)	(2.6		)	—		(3.1		)	—		—			—			(3.1		)
	Noncontrolling interest in subsidiaries	—			—			—		—			—		0.1			—			0.1
	Net income (loss) attributed to common shareholders	100.2			163.7			51.3		315.2			0.4		(38.7		)	—			276.9
	Total assets	6,292.50			3,506.90			536.7		10,336.10			—		1,638.10			(692.2		)	11,282.00
	Cash expenditures for long-lived assets	456.5			286.6			—		743.1			0.9		121			—			865
		Regulated Operations											Nonutility and Nonregulated Operations
	2013 (Millions)	Natural Gas Utility			Electric			Electric		Total			IES		Holding			Reconciling			Integrys
					Utility			Transmission		Regulated					Company			Eliminations			Energy Group
								Investment		Operations					and Other						Consolidated
	Income Statement
	External revenues	$	2,094.10		$	1,332.00		$	—	$	3,426.10		$	—	$	59.4		$	—		$	3,485.50
	Intersegment revenues	10.9			0.1			—		11			—		1.4			(12.4		)	—
	Depreciation and amortization expense	136			98.6			—		234.6			—		29.3			(0.5		)	263.4
	Earnings from equity method investments	—			—			89.1		89.1			—		2.4			—			91.5
	Miscellaneous income	1.2			9.8			—		11			—		23.3			(12.4		)	21.9
	Interest expense	50.2			36.4			—		86.6			—		53.2			(12.4		)	127.4
	Provision (benefit) for income taxes	78.9			67.3			35.2		181.4			—		(23.4		)	—			158
	Net income (loss) from continuing operations	124			113.4			53.9		291.3			—		(23.8		)	—			267.5
	Discontinued operations	—			—			—		—			82.5		4.8			—			87.3
	Preferred stock dividends of subsidiary	(0.6		)	(2.5		)	—		(3.1		)	—		—			—			(3.1		)
	Noncontrolling interest in subsidiaries	—			—			—		—			—		0.1			—			0.1
	Net income (loss) attributed to common shareholders	123.4			110.9			53.9		288.2			82.5		(18.9		)	—			351.8
	Total assets	5,672.00			3,514.40			508.5		9,694.90			815.4		1,519.70			(786.5		)	11,243.50
	Cash expenditures for long-lived assets	370			615			—		985			2.6		73.2			—			1,060.80
		Regulated Operations											Nonutility and Nonregulated Operations
	2012 (Millions)	Natural Gas Utility			Electric			Electric		Total			IES		Holding			Reconciling			Integrys
					Utility			Transmission		Regulated					Company			Eliminations			Energy Group
								Investment		Operations					and Other						Consolidated
	Income Statement
	External revenues	$	1,662.70		$	1,297.40		$	—	$	2,960.10		$	—	$	52.8		$	—		$	3,012.90
	Intersegment revenues	9.3			—			—		9.3			—		1.9			(11.2		)	—
	Depreciation and amortization expense	131.8			89			—		220.8			—		27			(0.5		)	247.3
	Earnings from equity method investments	—			—			85.3		85.3			—		1.9			—			87.2
	Miscellaneous income	0.6			2.6			—		3.2			—		19.9			(14.1		)	9
	Interest expense	47.3			35.9			—		83.2			—		49.8			(14.1		)	118.9
	Provision (benefit) for income taxes	61.4			49.4			32.9		143.7			—		(25.8		)	—			117.9
	Net income (loss) from continuing operations	94			110.4			52.4		256.8			—		(17.9		)	—			238.9
	Discontinued operations	—			—			—		—			55.1		(9.7		)	—			45.4
	Preferred stock dividends of subsidiary	(0.6		)	(2.5		)	—		(3.1		)	—		—			—			(3.1		)
	Noncontrolling interest in subsidiaries	—			—			—		—			—		0.2			—			0.2
	Net income (loss) attributed to common shareholders	93.4			107.9			52.4		253.7			55.1		(27.4		)	—			281.4
	Total assets	5,446.20			3,041.30			476.6		8,964.10			493.7		1,523.30			(653.7		)	10,327.40
	Cash expenditures for long-lived assets	375.1			163.9			—		539			2		53.4			—			594.4

QUARTERLY_FINANCIAL_INFORMATIO1

QUARTERLY FINANCIAL INFORMATION (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Amounts reflecting IES's retail energy business in discontinued operations
Quarterly financial information
Schedule of quarterly financial information (unaudited)
	Amounts reflecting IES's retail energy business in discontinued operations
	(Millions, except per share amounts)		First Quarter		Second Quarter			Third Quarter			Fourth Quarter			Total
	2014
	Operating revenues		$	1,638.00	$	836.8		$	657.1		$	1,012.30		$	4,144.20
	Operating income		232.3		23.2			134.6			116.9			507
	Net income from continuing operations		140.2		8.8			75.3			53.8			278.1
	Net income		153.1		8			84			34.8			279.9
	Net income attributed to common shareholders		152.4		7.2			83.3			34			276.9
	Earnings per common share (basic) *
	Net income from continuing operations		$	1.74	$	0.1		$	0.93		$	0.66		$	3.43
	Discontinued operations, net of tax		0.16		(0.01		)	0.11			(0.24		)	0.02
	Earnings per common share (basic)		1.9		0.09			1.04			0.42			3.45
	Earnings per common share (diluted) *
	Net income from continuing operations		1.73		0.1			0.91			0.66			3.41
	Discontinued operations, net of tax		0.16		(0.01		)	0.11			(0.24		)	0.02
	Earnings per common share (diluted)		1.89		0.09			1.02			0.42			3.43
	2013
	Operating revenues		$	1,136.40	$	708.1		$	622.2		$	1,018.80		$	3,485.50
	Operating income		211.8		56.1			41.5			130.1			439.5
	Net income from continuing operations		129.6		36.8			26.9			74.2			267.5
	Net income (loss)		188.3		(4.7		)	38.8			132.4			354.8
	Net income (loss) attributed to common shareholders		187.5		(5.4		)	38.1			131.6			351.8
	Earnings (loss) per common share (basic) *
	Net income from continuing operations		$	1.64	$	0.45		$	0.33		$	0.91		$	3.33
	Discontinued operations, net of tax		0.74		(0.52		)	0.15			0.73			1.1
	Earnings (loss) per common share (basic)		2.38		(0.07		)	0.48			1.64			4.43
	Earnings (loss) per common share (diluted) *
	Net income from continuing operations		1.63		0.45			0.32			0.91			3.3
	Discontinued operations, net of tax		0.74		(0.52		)	0.15			0.72			1.09
	Earnings (loss) per common share (diluted)		2.37		(0.07		)	0.47			1.63			4.39
	*	Earnings per share for the individual quarters do not total the year ended earnings per share amount because of changes to the average number of shares outstanding and changes in incremental issuable shares throughout the year.
Previously reported amounts reflecting IES's retail energy business in continuing operations
Quarterly financial information
Schedule of quarterly financial information (unaudited)
	Previously reported amounts reflecting IES's retail energy business in continuing operations
	(Millions, except per share amounts)		First Quarter		Second Quarter			Third Quarter			Fourth Quarter			Total
	2014
	Operating revenues		$	2,924.90	$	1,432.60		$	1,187.90		N/A			N/A
	Operating income		253.2		26.1			146.9			N/A			N/A
	Net income from continuing operations		153.2		8.1			82.9			N/A			N/A
	Net income		153.1		8			84			N/A			N/A
	Net income attributed to common shareholders		152.4		7.2			83.3			N/A			N/A
	Earnings per common share (basic) *
	Net income from continuing operations		$	1.9	$	0.09		$	1.03		N/A			N/A
	Discontinued operations, net of tax		—		—			0.01			N/A			N/A
	Earnings per common share (basic)		1.9		0.09			1.04			N/A			N/A
	Earnings per common share (diluted) *
	Net income from continuing operations		1.89		0.09			1.01			N/A			N/A
	Discontinued operations, net of tax		—		—			0.01			N/A			N/A
	Earnings per common share (diluted)		1.89		0.09			1.02			N/A			N/A
	2013
	Operating revenues		$	1,678.20	$	1,116.00		$	1,129.70		$	1,710.70		$	5,634.60
	Operating income (loss)		293.1		(6.9		)	55.3			226.2			567.7
	Net income (loss) from continuing operations		182.2		(3.9		)	39.4			132.3			350
	Net income (loss)		188.3		(4.7		)	38.8			132.4			354.8
	Net income (loss) attributed to common shareholders		187.5		(5.4		)	38.1			131.6			351.8
	Earnings (loss) per common share (basic) *
	Net income (loss) from continuing operations		$	2.3	$	(0.06	)	$	0.49		$	1.64		$	4.37
	Discontinued operations, net of tax		0.08		(0.01		)	(0.01		)	—			0.06
	Earnings (loss) per common share (basic)		2.38		(0.07		)	0.48			1.64			4.43
	Earnings (loss) per common share (diluted) *
	Net income (loss) from continuing operations		2.29		(0.06		)	0.48			1.63			4.33
	Discontinued operations, net of tax		0.08		(0.01		)	(0.01		)	—			0.06
	Earnings (loss) per common share (diluted)		2.37		(0.07		)	0.47			1.63			4.39
	*	Earnings per share for the individual quarters do not total the year ended earnings per share amount because of changes to the average number of shares outstanding and changes in incremental issuable shares throughout the year.

SUMMARY_OF_SIGNIFICANT_ACCOUNT3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES NATURE OF OPERATIONS (Details)	Dec. 31, 2014
Accounting Policies [Abstract]
Number of natural gas and/or electric utilities	5
ATC
Equity method investments
Ownership interest (as a percent)	34.00%

SUMMARY_OF_SIGNIFICANT_ACCOUNT4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES RECLASSIFICATIONS (Details) (ITF, Compressed natural gas fueling stations)	Nov. 01, 2014
ITF | Compressed natural gas fueling stations
Number of compressed natural gas fueling stations sold	8

SUMMARY_OF_SIGNIFICANT_ACCOUNT5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES CASH AND CASH EQUIVALENTS (Details)	12 Months Ended
	Dec. 31, 2014
Cash and cash equivalents
Maximum maturity of short-term investments to classify as cash equivalents	3 months

SUMMARY_OF_SIGNIFICANT_ACCOUNT6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES REVENUES AND CUSTOMER RECEIVABLES (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
	customer
Revenues from external customers
Unbilled revenues	269.4	$286.40
WPS
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
Customers that account for more than 10% of revenues	0
Threshold percentage of revenues from major customers or industries	10.00%

SUMMARY_OF_SIGNIFICANT_ACCOUNT7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES INVENTORIES (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Percentage of total inventories stated on a LIFO basis	37.00%	30.00%
PGL and NSG
Amount by which estimated replacement cost of natural gas in inventory exceeded LIFO cost	$47.70	$151.70
Natural Gas Price Benchmark	3.04	4.77

SUMMARY_OF_SIGNIFICANT_ACCOUNT8

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PROPERTY, PLANT, AND EQUIPMENT (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, plant, and equipment
Gain (loss) on retirement of utility property, excluding land	0
Software | Minimum
Property, plant, and equipment
Useful life	3 years
Software | Maximum
Property, plant, and equipment
Useful life	15 years
MERC
Property, plant, and equipment
Annual utility composite depreciation rate (as a percent)	2.49%	1.88%	3.07%
MERC | Minnesota Public Utilities Commission (MPUC)
Property, plant, and equipment
Reduction to depreciation expense		2
MGU
Property, plant, and equipment
Annual utility composite depreciation rate (as a percent)	2.65%	1.93%	2.71%
NSG
Property, plant, and equipment
Annual utility composite depreciation rate (as a percent)	2.44%	2.44%	2.43%
PGL
Property, plant, and equipment
Annual utility composite depreciation rate (as a percent)	3.20%	3.19%	3.16%
WPS | Electric
Property, plant, and equipment
Annual utility composite depreciation rate (as a percent)	2.73%	2.79%	2.87%
WPS | Natural gas
Property, plant, and equipment
Annual utility composite depreciation rate (as a percent)	2.17%	2.19%	2.21%

SUMMARY_OF_SIGNIFICANT_ACCOUNT9

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AFUDC AND CAPITALIZED INTEREST (Details) (WPS, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
AFUDC and capitalized interest
Percentage of retail jurisdictional construction work in progress expenditures subject to AFUDC calculation	50.00%
Allowance for equity funds used during construction	$12.50	$10.80	$2.90
Allowance for borrowed funds used during construction	$5.20	$4.10	$1
Retail
AFUDC and capitalized interest
Average AFUDC rate (as a percent)	8.08%
Wholesale
AFUDC and capitalized interest
Average AFUDC rate (as a percent)	6.99%

Recovered_Sheet1

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES INVESTMENTS IN EXCHANGE-TRADED FUNDS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Trading Securities [Abstract]
Net unrealized gains included in earnings related to investments held at the end of the period	$1.80	$1.90	$1

Recovered_Sheet2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES INCOME TAXES (Details) (Minimum)	12 Months Ended
	Dec. 31, 2014
Minimum
Income taxes
Threshold ownership percentage used to determine subsidiary inclusion in consolidated income tax return	80.00%

Recovered_Sheet3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES EMPLOYEE BENEFITS (Details)	12 Months Ended
	Dec. 31, 2014
Employee benefits
Recognition period for transition obligation to other postretirement benefit plans that existed prior to the merger	20 years
WPS
Employee benefits
Recognition period for changes in realized and unrealized investment gains and losses	5 years
IBS and PELLC
Employee benefits
Recognition period for differences between actual investment returns and expected return on plan assets	5 years

Recovered_Sheet4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES STOCK-BASED COMPENSATION (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014
Stock Options
Information related to share based awards
Maximum term of awards	10 years
Percentage of stock options that becomes exercisable for retirees	25.00%
Period of historical volatility used to estimate expected volatility	10 years
Performance Stock Rights
Information related to share based awards
Vesting period	3 years
Maximum percentage value of award that can be deferred into deferred compensation plan	80.00%
Period prior to the end of the performance period during which employees cannot change their election to defer the value of awards into the deferred compensation plan	6 months
Remaining performance period for which fair value on the modification date is used to measure the awards	6 months
Incremental compensation expense due to an award modification	0
Performance Stock Rights | Minimum
Information related to share based awards
Amount of performance payout (as a percent)	0.00%
Period of historical volatility used to estimate expected volatility	1 year
Performance Stock Rights | Maximum
Information related to share based awards
Amount of performance payout (as a percent)	200.00%
Period of historical volatility used to estimate expected volatility	3 years
Restricted Share Units
Information related to share based awards
Vesting period	4 years
Vesting rights percentage	25.00%
Maximum percentage value of award that can be deferred into deferred compensation plan	80.00%
Nonemployee Director Deferred Stock Units
Information related to share based awards
Vesting period	1 year
2014 Omnibus Incentive Compensation Plan
Information related to share based awards
Number of shares authorized for grant	3,000,000
Number of highest paid officers of entity or its subsidiary that cannot be granted awards in excess of a set amount	3
2014 Omnibus Incentive Compensation Plan | Stock Options
Information related to share based awards
Number of shares authorized for grant to single employee who is entity's chief executive officer or other three highest compensated officers of entity or its subsidiaries	1,000,000
2014 Omnibus Incentive Compensation Plan | Performance Stock Rights
Information related to share based awards
Number of shares authorized for grant to single employee who is entity's chief executive officer or other three highest compensated officers of entity or its subsidiaries	250,000

PROPOSED_MERGER_WITH_WISCONSIN1

PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION (Details) (USD $)	1 Months Ended
	Jun. 30, 2014
	customer
Business Combinations [Abstract]
Number of Wisconsin Energy Corporation shares received for each Integrys Energy Group share at closing	1.128
Cash per share of Integrys Energy Group common stock	$18.58
Integrys Energy Group shareholders ownership percentage of combined company	28.00%
Wisconsin Energy Corporation shareholders ownership percentage of combined company	72.00%
Number of total natural gas and electric customers upon closing of the merger	4,300,000

ACQUISITIONS_Details

ACQUISITIONS (Details) (USD $)	12 Months Ended			0 Months Ended	1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 02, 2014	Mar. 31, 2013
					MW
Acquisitions
Purchase price	$0	$391.60	$0
Alliant Energy Corporation's Natural Gas Distribution Business in Southeast Minnesota | MERC
Acquisitions
Estimated purchase price	14
Fox Energy Company LLC | WPS
Acquisitions
Purchase price					391.6
Capacity of Electric Generating Facility					593
Assets acquired
Inventories					3
Other current assets					0.4
Property, plant, and equipment					374.4
Other long-term assets					15.6
Total assets acquired					393.4
Liabilities assumed
Accounts payable					1.8
Total liabilities assumed					1.8
Contracted Capacity From Power Purchase Agreement					500
Termination of tolling agreement with Fox Energy Company LLC					$50
Amortization Period of Regulatory Asset	9 years
Beginning of regulatory asset amortization period				1-Jan-14

DISPOSITIONS_DISPOSITIONS_EXCL

DISPOSITIONS - DISPOSITIONS EXCLUDING DISCONTINUED OPERATIONS (Details) (USD $)	12 Months Ended			3 Months Ended	1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2014	Nov. 30, 2014	Aug. 31, 2014	Nov. 01, 2014
Disclosures related to the disposal
Pre-tax gain on sale or abandonment	$86.50	$0	$0
Assets and liabilities classified as held for sale on balance sheets
Assets held for sale	0.7	277.9
Total liabilities	0	49.1
ITF | Compressed natural gas fueling stations
Disclosures related to the disposal
Number of compressed natural gas fueling stations sold							8
Holding Company and Other | Winnebago Energy Center
Disclosures related to the disposal
Pre-tax gain on sale or abandonment				5
Proceeds received for both insurance recovery for damage caused by the fire and the sale of miscellaneous parts				6.1
Holding Company and Other | AMP Americas, LLC | Compressed natural gas fueling stations
Disclosures related to the disposal
Variable interest entity ownership interest (as a percent)					70.00%
Holding Company and Other | ITF | Compressed natural gas fueling stations
Disclosures related to the disposal
Number of compressed natural gas fueling stations sold							8
Variable interest entity ownership interest (as a percent)					30.00%
Fair value of CNG fueling stations sold							13
Cash proceeds from sale					7.2
Note receivable from the buyer					2.7
Term of note receivable from the buyer					7 years
Equity contribution to maintain ownership interest					3.1
Pre-tax gain on sale or abandonment					1.8
Deferred gain on sale							0.8
Property, plant, and equipment, net of accumulated depreciation		5.3					10.4
Accumulated depreciation		0.3					0.7
Assets and liabilities classified as held for sale on balance sheets
Property, plant, and equipment, net of accumulated depreciation		5.3					10.4
Electric Utility | UPPCO
Disclosures related to the disposal
Cash proceeds from sale						336.7
Pre-tax gain on sale or abandonment				85.4
After-tax gain on sale				51.2
Property, plant, and equipment, net of accumulated depreciation		193.8				194.4
Accumulated depreciation		88.9				91.3
Transaction costs related to a sale				1.1
Intercompany payables included in a sale		1.6
Assets and liabilities classified as held for sale on balance sheets
Current assets		26.5				24.3
Property, plant, and equipment, net of accumulated depreciation		193.8				194.4
Other long-term assets		51.6				72.8
Assets held for sale		271.9				291.5
Current liabilities		16.7				12.7
Long-term liabilities		32.4				28.6
Total liabilities		$49.10				$41.30
Electric Utility | UPPCO | Minimum
Disclosures related to the disposal
Transition period for services						18 months
Electric Utility | UPPCO | Maximum
Disclosures related to the disposal
Transition period for services						30 months

DISPOSITIONS_DISCONTINUED_OPER

DISPOSITIONS - DISCONTINUED OPERATIONS (Details) (USD $)	12 Months Ended			1 Months Ended	10 Months Ended	1 Months Ended		3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Nov. 30, 2014	Oct. 31, 2014	Sep. 30, 2014	Mar. 31, 2013	Sep. 30, 2012	Nov. 01, 2014
Disclosures related to discontinued operations
Discontinued operations, net of tax	$1.80	$87.30	$45.40
Pre-tax gain (loss) on sale	-24.3	0	0
Assets and liabilities classified as held for sale on balance sheets
Total assets	0.7	277.9
Total liabilities	0	49.1
Components of discontinued operations recorded in income statements
Provision for income taxes	-7.2	-45.9	-22.6
Discontinued operations, net of tax	1.8	87.3	45.4
IES | IES's retail energy business
Disclosures related to discontinued operations
Discontinued operations, net of tax		82.5	55.1		0.4
Cash proceeds from sale				333
Pre-tax gain (loss) on sale		0	0		-28.8
After-tax gain (loss) on sale					17.3
Transaction costs related to a sale					-4.5
Maximum number of months after sale that guarantees will be held				6 months
Transition period for services				15 months
Assets and liabilities classified as held for sale on balance sheets
Cash and cash equivalents		5.5							7.6
Accounts receivable and accrued unbilled revenues, net of reserves		390.9							293.8
Accounts receivable and accrued unbilled revenues, reserves		1.7							1.8
Inventories		34.2							52.4
Current assets from risk management activities		229.5							234.8
Prepaid taxes		2.5							0
Other current assets		41.5							75.1
Property, plant, and equipment, net of accumulated depreciation		5.2							4.5
Accumulated depreciation		15.6							16.6
Long-term assets from risk management activities		73.4							106.9
Goodwill		6.7							0
Other long-term assets		26							25.5
Total assets		815.4							800.6
Accounts payable		202.9							186.9
Current liabilities from risk management activities		160.6							169.7
Accrued taxes		2							0.2
Other current liabilities		13.1							6.7
Long-term liabilities from risk management activities		61.9							79.5
Other long-term liabilities		7							0.3
Total liabilities		447.5							443.3
Components of discontinued operations recorded in income statements
Revenues		2,150.90	1,201		2,587.10
Cost of sales		-1,910.70	-1,018.90		-2,444.70
Operating and maintenance expense		-105.6	-88.3		-91.5
Depreciation and amortization expense		-3.2	-3.4		-2.7
Taxes other than income taxes		-3.2	-2.4		-4.9
Goodwill impairment loss		0	0		-6.7
Miscellaneous income		7.9	0.3		0.6
Interest expense		-0.8	-1.3		-0.7
Income (loss) before taxes		135.3	87		7.7
Provision for income taxes		-52.8	-31.9		-7.3
Discontinued operations, net of tax		82.5	55.1		0.4
Holding Company and Other | Combined Locks Energy Center
Disclosures related to discontinued operations
Discontinued operations, net of tax	-0.5	-1.3	-0.6
Assets and liabilities classified as held for sale on balance sheets
Total assets	0.7	0.7
Components of discontinued operations recorded in income statements
Discontinued operations, net of tax	-0.5	-1.3	-0.6
Holding Company and Other | Uncertain tax positions
Disclosures related to discontinued operations
Discontinued operations, net of tax	0.7	5.9	1.8
Components of discontinued operations recorded in income statements
Discontinued operations, net of tax	0.7	5.9	1.8
Holding Company and Other | WPS Empire State, Inc | WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC
Disclosures related to discontinued operations
Discontinued operations, net of tax	1.2	0.2	-4
Pre-tax gain (loss) on sale	1
Pre-tax impairment loss			1.1
After-tax impairment loss			0.7
Earn-out mechanism period							4 years
Earn-out settlement payment						2
Components of discontinued operations recorded in income statements
Revenues	0	1.2	0.6
Cost of sales	0	-0.9	-2
Operating and maintenance expense	2	0.4	-3.5
Depreciation and amortization expense	0	0	-0.6
Taxes other than income taxes	0	-0.3	-1.4
Miscellaneous income	0	0	0.3
Income (loss) before taxes	2	0.4	-6.6
Provision for income taxes	-0.8	-0.2	2.6
Discontinued operations, net of tax	1.2	0.2	-4
Holding Company and Other | Sunbury Holdings, LLC | WPS Westwood Generation, LLC
Disclosures related to discontinued operations
Discontinued operations, net of tax			-6.9
Pre-tax gain (loss) on sale		-0.6
Pre-tax impairment loss								8.4
After-tax impairment loss								5
Components of discontinued operations recorded in income statements
Revenues			9.2
Cost of sales			-4.4
Operating and maintenance expense			-14.3
Depreciation and amortization expense			-1
Taxes other than income taxes			-0.2
Interest expense			-0.7
Income (loss) before taxes			-11.4
Provision for income taxes			4.5
Discontinued operations, net of tax			($6.90)

CASH_AND_CASH_EQUIVALENTS_CONT

CASH AND CASH EQUIVALENTS - CONTINUING OPERATIONS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Noncurrent restricted cash
Rabbi trust funding related to potential change in control	$31.30
Continuing operations
Significant noncash transactions
Construction costs funded through accounts payable	180.5	108.5	92.4
Accounts receivable converted to notes receivable related to sales of ITF fueling stations constructed on behalf of others	10.9	0	0
Portion of ITF fueling station sale financed with note receivable	2.7	0	0
Equity interest in joint venture received for a portion of the ITF fueling station sale	3.1	0	0
Equity issued for employee stock ownership plan	1.7	14.3	0
Equity issued for stock-based compensation plans	0	16.3	0
Equity issued for reinvested dividends	$0	$12	$0

CASH_AND_CASH_EQUIVALENTS_DISC

CASH AND CASH EQUIVALENTS - DISCONTINUED OPERATIONS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating activities
Depreciation and amortization expense	$287.50	$263.40	$247.30
Net unrealized gains on energy contracts	-21.4	-100.5	-34.6
Deferred income taxes and investment tax credits	165.9	209.8	146
Loss on sale of IES's retail energy business	24.3	0	0
Other	43.5	34.9	25.3
Investing activities
Capital expenditures	-865	-669.2	-594.4
Discontinued operations
Operating activities
Depreciation and amortization expense	2.7	3.3	5.3
Net unrealized gains on energy contracts	-22.7	-100.3	-34.5
Deferred income taxes and investment tax credits	36.1	56.1	-0.4
Remeasurement of uncertain tax positions included in our liability for unrecognized tax benefits	-0.7	-5.9	-1.8
Other	33.4	23.8	21.7
Investing activities
Capital expenditures	-0.8	-2.6	-2
Discontinued operations | Compass Energy Services, Inc.
Investing activities
Contingent consideration and payables related to the acquisition of Compass Energy Services	0	7.8	0
Discontinued operations | IES's retail energy business
Operating activities
Loss on sale of IES's retail energy business	24.3	0	0
Discontinued operations | WPS Westwood Generation, LLC
Investing activities
Portion of Westwood sale financed with note receivable	$0	$0	$4

RISK_MANAGEMENT_ACTIVITIES_RIS

RISK MANAGEMENT ACTIVITIES - RISK MANAGEMENT ASSETS AND LIABILITIES (Details) (Utility segments, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative assets and liabilities from risk management activities
Risk Management Assets	$4.50	$11.90
Risk Management Liabilities	49.1	4.1
Non-hedge derivatives
Derivative assets and liabilities from risk management activities
Current assets from risk management activities	4	9.9
Long-term assets from risk management activities	0.5	2
Risk Management Assets	4.5	11.9
Current liabilities from risk management activities	42.7	3.2
Long-term liabilities from risk management activities	6.4	0.9
Risk Management Liabilities	49.1	4.1
Non-hedge derivatives | Natural gas contracts
Derivative assets and liabilities from risk management activities
Current assets from risk management activities	1.8	8.3
Long-term assets from risk management activities	0.5	1.8
Current liabilities from risk management activities	37.3	1
Long-term liabilities from risk management activities	5.3	0.1
Non-hedge derivatives | FTRs
Derivative assets and liabilities from risk management activities
Current assets from risk management activities	2.2	1.5
Current liabilities from risk management activities	0.3	0.3
Non-hedge derivatives | Petroleum product contracts
Derivative assets and liabilities from risk management activities
Current assets from risk management activities	0	0.1
Long-term assets from risk management activities	0
Current liabilities from risk management activities	2.7	0
Long-term liabilities from risk management activities	0.1
Non-hedge derivatives | Coal contracts
Derivative assets and liabilities from risk management activities
Current assets from risk management activities	0	0
Long-term assets from risk management activities	0	0.2
Current liabilities from risk management activities	2.4	1.9
Long-term liabilities from risk management activities	$1	$0.80

RISK_MANAGEMENT_ACTIVITIES_NET

RISK MANAGEMENT ACTIVITIES - NETTING ARRANGEMENTS (Details) (Utility segments, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Utility segments
Assets
Derivative assets subject to master netting or similar arrangements, gross amount	$3.20	$11.70
Potential effects of netting, including cash collateral	1.3	2.1
Derivative assets subject to master netting or similar arrangements, net amount	1.9	9.6
Derivative assets not subject to master netting or similar arrangements	1.3	0.2
Risk Management Assets	4.5	11.9
Total Risk Management Assets, Net Amount	3.2	9.8
Liabilities
Derivative liabilities subject to master netting or similar arrangements, gross amount	45.7	1.4
Potential effects of netting, including cash collateral	8.8	1.4
Derivative liabilities subject to master netting or similar arrangements, net amount	36.9	0
Derivative liabilities not subject to master netting or similar arrangements	3.4	2.7
Risk Management Liabilities	49.1	4.1
Total Risk Management Liabilities, Net Amount	$40.30	$2.70

RISK_MANAGEMENT_ACTIVITIES_CAS

RISK MANAGEMENT ACTIVITIES - CASH COLLATERAL AND CREDIT-RISK RELATED CONTINGENT FEATURES (Details) (Utility segments, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Utility segments
Cash collateral
Cash collateral provided to others, related to contracts under master netting or similar arrangements	$11.60	$3.60
Cash collateral provided to others, other	1.1	1.1
Cash collateral received from others related to contracts under master netting or similar arrangements	0	0.7
Credit-risk related contingent features
Aggregate fair value of derivative instruments with credit risk-related contingent features that were is a liability position	31.3	0.6
Collateral that would have been required	$27.10

RISK_MANAGMENT_ACTIVITIES_UTIL

RISK MANAGMENT ACTIVITIES - UTILITY SEGMENTS, NOTIONAL VOLUMES (Details) (Non-hedge derivatives, Utility segments)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	MMBTU	MMBTU
Natural gas contracts | Purchases
Risk management activities
Notional volume of outstanding derivative contracts (mmbtu or kwh)	186,000,000	312,480,000
Natural gas contracts | Sales
Risk management activities
Notional volume of outstanding derivative contracts (mmbtu or kwh)	0	2,930,000
FTRs | Other transactions
Risk management activities
Notional volume of outstanding derivative contracts (mmbtu or kwh)	4,287,700,000	3,427,000,000
Petroleum product contracts | Purchases
Risk management activities
Notional volume of outstanding derivative contracts (barrels)	100,000	100,000
Petroleum product contracts | Sales
Risk management activities
Notional volume of outstanding derivative contracts (barrels)	0	0
Coal contracts | Purchases
Risk management activities
Notional volume of outstanding derivative contracts (tons)	3,000,000	4,800,000
Coal contracts | Sales
Risk management activities
Notional volume of outstanding derivative contracts (tons)	0	0

RISK_MANAGEMENT_ACTIVITIES_UTI

RISK MANAGEMENT ACTIVITIES - UTILITY SEGMENTS, UNREALIZED GAINS AND LOSSES (Details) (Utility segments, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Natural gas contracts | Income Statement - Cost of sales
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	$0	$0	$0.20
Natural gas contracts | Income Statement - Operating and maintenance expense
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	-0.8	0.1	0
Natural gas contracts | Balance Sheet - Regulatory assets (current)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	-38	13.4	24.6
Natural gas contracts | Balance Sheet - Regulatory assets (long-term)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	-5.2	2.3	8.3
Natural gas contracts | Balance Sheet - Regulatory liabilities (current)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	-3.9	4.6	-7.8
Natural gas contracts | Balance Sheet - Regulatory liabilities (long-term)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	-0.6	0.3	0.3
FTRs | Balance Sheet - Regulatory assets (current)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	0	0.2	-0.1
FTRs | Balance Sheet - Regulatory liabilities (current)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	0.4	-0.3	0
Petroleum product contracts | Income Statement - Operating and maintenance expense
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	-1.7	0.1	0
Petroleum product contracts | Balance Sheet - Regulatory assets (current)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	-1.1	0	0.1
Petroleum product contracts | Balance Sheet - Regulatory liabilities (current)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	-0.1	0.1	0
Coal contracts | Balance Sheet - Regulatory assets (current)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	-1.3	-0.9	-2.2
Coal contracts | Balance Sheet - Regulatory assets (long-term)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	0	3.5	0.1
Coal contracts | Balance Sheet - Regulatory liabilities (current)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	-0.2	-0.2	0.3
Coal contracts | Balance Sheet - Regulatory liabilities (long-term)
Risk management activities
Unrealized gain (loss) related to non-hedge derivative contracts	($0.10)	($2)	$2.20

RISK_MANAGEMENT_ACTIVITIES_CAS1

RISK MANAGEMENT ACTIVITIES - CASH FLOW HEDGES (Details) (Cash flow hedges, Holding Company and Other, Interest rate swaps, Interest expense, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flow hedges | Holding Company and Other | Interest rate swaps | Interest expense
Risk management activities
Loss Reclassified from Accumulated OCI into Income (Effective Portion)	($1.10)	($1.10)	($1.10)

PROPERTY_PLANT_AND_EQUIPMENT_D

PROPERTY, PLANT, AND EQUIPMENT (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Property, plant, and equipment
Less: Accumulated depreciation	$3,343.10	$3,221
Property, plant and equipment, net	6,859.80	6,206.20
Holding Company and Other | Nonutility operations
Property, plant, and equipment
Property, plant, and equipment, gross	144.6	131.1
Less: Accumulated depreciation	81.1	80.4
Net property, plant, and equipment excluding construction work in progress	63.5	50.7
Construction work in progress	73.9	38
Property, plant and equipment, net	137.4	88.7
Holding Company and Other | Nonregulated operations
Property, plant, and equipment
Property, plant, and equipment, gross	173.9	130.5
Less: Accumulated depreciation	39.5	30.5
Net property, plant, and equipment excluding construction work in progress	134.4	100
Construction work in progress	10.4	7.1
Property, plant and equipment, net	144.8	107.1
Holding Company and Other | Nonregulated operations | PDI
Property, plant, and equipment
Property, plant, and equipment, gross	140.2	109.8
Holding Company and Other | Nonregulated operations | Other nonregulated
Property, plant, and equipment
Property, plant, and equipment, gross	33.7	20.7
Regulated operations
Property, plant, and equipment
Property, plant, and equipment, gross	9,399.20	8,717.70
Less: Accumulated depreciation	3,185.90	3,073.20
Net property, plant, and equipment excluding construction work in progress	6,213.30	5,644.50
Construction work in progress	351.8	351.5
Plant to be retired, net	12.5	14.4
Property, plant and equipment, net	6,577.60	6,010.40
Regulated operations | Electric Utility
Property, plant, and equipment
Property, plant, and equipment, gross	3,587.40	3,289.20
Regulated operations | Natural Gas Utility
Property, plant, and equipment
Property, plant, and equipment, gross	$5,811.80	$5,428.50

JOINTLY_OWNED_UTILITY_FACILITI2

JOINTLY OWNED UTILITY FACILITIES (Details) (WPS, USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	MW
Weston 4
Share of significant jointly owned electric generating facilities
Ownership (as a percent)	70.00%
WPS's share of rated capacity (in megawatts)	374.5
Utility plant	$581.90
Accumulated depreciation	-132.6
Construction work in progress	2.7
Columbia Energy Center Units 1 and 2
Share of significant jointly owned electric generating facilities
Ownership (as a percent)	31.80%
WPS's share of rated capacity (in megawatts)	335.2
Utility plant	390.7
Accumulated depreciation	-116.2
Construction work in progress	10.1
Edgewater Unit 4
Share of significant jointly owned electric generating facilities
Ownership (as a percent)	31.80%
WPS's share of rated capacity (in megawatts)	105
Utility plant	42.9
Accumulated depreciation	-29.6
Construction work in progress	$0.70

REGULATORY_ASSETS_AND_LIABILIT2

REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Regulatory assets
Current assets	$118.90	$127.40
Long-term assets	1,513.60	1,361.40
Total regulatory assets	1,632.50	1,488.80
Other disclosures
Environmental remediation liabilities	579.9	600
Environmental remediation costs (net of insurance recoveries)
Regulatory assets
Total regulatory assets	635.8	652.1
Other disclosures
Environmental remediation liabilities	579.9
Unrecognized pension and other postretirement benefit costs
Regulatory assets
Total regulatory assets	513.1	382.6
Asset retirement obligations
Regulatory assets
Total regulatory assets	109.4	89
Merger and acquisition-related pension and other postretirement benefit costs
Regulatory assets
Total regulatory assets	86.6	98.3
Income tax related items
Regulatory assets
Total regulatory assets	60.6	55.3
Derivatives
Regulatory assets
Total regulatory assets	55.2	11.7
Termination of a tolling agreement with Fox Energy Company LLC
Regulatory assets
Total regulatory assets	44.6	50
Crane Creek production tax credits
Regulatory assets
Total regulatory assets	32.2	33.6
Other disclosures
Period over which the grant received will be reflected in income through a reduction of depreciation and amortization expense	12 years
Energy costs recoverable through rate adjustments
Regulatory assets
Total regulatory assets	22.2	17
De Pere Energy Center
Regulatory assets
Total regulatory assets	21.4	23.8
Unamortized loss on reacquired debt
Regulatory assets
Total regulatory assets	16.6	16.2
Uncollectible expense
Regulatory assets
Total regulatory assets	13.6	4.7
Energy efficiency programs
Regulatory assets
Total regulatory assets	2.8	16.8
Pension and other postretirement costs recoverable through rate adjustments
Regulatory assets
Total regulatory assets	0	9.4
Decoupling
Regulatory assets
Total regulatory assets	0	8.6
Other
Regulatory assets
Total regulatory assets	$18.40	$19.70

REGULATORY_ASSETS_AND_LIABILIT3

REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Regulatory liabilities
Current liabilities	$153.70	$101.10
Long-term liabilties	399.9	383.7
Total regulatory liabilities	553.6	484.8
Removal costs
Regulatory liabilities
Total regulatory liabilities	334	318
Decoupling
Regulatory liabilities
Total regulatory liabilities	49.4	51.5
Unrecognized pension and other postretirement benefit costs
Regulatory liabilities
Total regulatory liabilities	45.2	30.2
Energy costs refundable through rate adjustments
Regulatory liabilities
Total regulatory liabilities	44.8	27.1
Energy efficiency programs
Regulatory liabilities
Total regulatory liabilities	21.3	19.6
Derivatives
Regulatory liabilities
Total regulatory liabilities	19.8	6.6
Uncollectible expense
Regulatory liabilities
Total regulatory liabilities	15.7	10.1
Crane Creek depreciation deferral
Regulatory liabilities
Total regulatory liabilities	8.7	9
Fox Energy Center
Regulatory liabilities
Total regulatory liabilities	4.6	5.6
Other disclosures
Amount of allowance for earnings on equity capitalized for rate making purposes	22.8	22.1
Other
Regulatory liabilities
Total regulatory liabilities	$10.10	$7.10

EQUITY_METHOD_INVESTMENTS_INVE

EQUITY METHOD INVESTMENTS - INVESTMENTS (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Equity method investments
Equity method investments	$572.40	$540.90
ATC
Equity method investments
Equity method investments	536.7	508.4	476.6	439.4
INDU Solar Holdings, LLC
Equity method investments
Equity method investments	21.8	24.7	27.5	28.4
WRPC
Equity method investments
Equity method investments	7.7	7	7.3	7.7
AMP Trillium, LLC
Equity method investments
Equity method investments	5.5	0
Other
Equity method investments
Equity method investments	$0.70	$0.80

EQUITY_METHOD_INVESTMENTS_CHAN

EQUITY METHOD INVESTMENTS - CHANGES TO EQUITY METHOD INVESTMENTS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Changes to equity method investments
Equity method investment balance at beginning of period	$540.90
Earnings from equity method investments	88.3	91.5	87.2
Equity method investment balance at end of period	572.4	540.9
ATC
Equity method investments
Equity method investment, ownership interest (as a percent)	34.00%
Changes to equity method investments
Equity method investment balance at beginning of period	508.4	476.6	439.4
Earnings from equity method investments	85.7	89.1	85.3
Add: Capital contributions	17	13.7	20.4
Less: Dividends received	74.4	71	68.5
Equity method investment balance at end of period	536.7	508.4	476.6
ATC | Return on equity reduction for MISO transmission owners
Equity method investments
Requested return on equity (as a percent)	9.15%
Authorized return on equity (as a percent)	12.20%
Reduction in equity method investment earnings	6.6
INDU Solar Holdings, LLC
Equity method investments
Equity method investment, ownership interest (as a percent)	50.00%
Changes to equity method investments
Equity method investment balance at beginning of period	24.7	27.5	28.4
Earnings from equity method investments	1.8	1.3	1.1
Add: Capital contributions	0	0	7
Less: Return of capital to partners	4.7	4.1	9
Equity method investment balance at end of period	21.8	24.7	27.5
WRPC
Equity method investments
Equity method investment, ownership interest (as a percent)	50.00%
Changes to equity method investments
Equity method investment balance at beginning of period	7	7.3	7.7
Earnings from equity method investments	0.8	1	0.8
Add: Capital contributions	0.5	0	0
Less: Dividends received	0.6	1.3	1.2
Equity method investment balance at end of period	7.7	7	7.3
AMP Trillium, LLC
Changes to equity method investments
Equity method investment balance at beginning of period	0
Add: Capital contributions	5.5
Equity method investment balance at end of period	$5.50
AMP Trillium, LLC | AMP Americas, LLC
Equity method investments
Equity method investment, ownership interest (as a percent)	70.00%
AMP Trillium, LLC | ITF
Equity method investments
Equity method investment, ownership interest (as a percent)	30.00%

EQUITY_METHOD_INVESTMENTS_RELA

EQUITY METHOD INVESTMENTS - RELATED PARTY TRANSACTIONS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
ATC
Related party transactions
Charges to equity method investee for services, construction, and operations	$9.90	$11.30	$12.50
Total costs for network transmission services provided by ATC	103.8	104.9	100.3
WRPC
Related party transactions
Charges to equity method investee for services, construction, and operations	1.4	0.9	0.8
Purchases of energy from WRPC	3.7	3.7	5
Net proceeds from WRPC sales of energy to MISO	0	0	2.9
Number of hydroelectric plants owned	2
Portion of energy output sold to WPS	50.00%
Portion of energy output sold to Wisconsin Power and Light	50.00%
AMP Trillium, LLC
Related party transactions
Notes receivable due from related party	13.8
Net proceeds from the sale of CNG fueling stations	$3.10

EQUITY_METHOD_INVESTMENTS_COMB

EQUITY METHOD INVESTMENTS - COMBINED FINANCIAL DATA (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income statement data
Earnings from equity method investments	$88.30	$91.50	$87.20
ATC, INDU Solar Holdings, LLC, WRPC, and AMP Trillium, LLC
Income statement data
Revenues	655.6	642	618.3
Operating expenses	323.5	306.2	292.1
Other expense	88.4	83.7	85.1
Net income	243.7	252.1	241.1
Earnings from equity method investments	88.3	91.4	87.2
Balance sheet data
Current assets	80.7	90.2
Noncurrent assets	3,835.90	3,587.20
Total assets	3,916.60	3,677.40
Current liabilities	324	383.6
Long-term debt	1,721.60	1,559.10
Other noncurrent liabilities	173.2	134.4
Shareholders' equity	1,697.80	1,600.30
Total liabilities and shareholders' equity	$3,916.60	$3,677.40

GOODWILL_AND_OTHER_INTANGIBLE_2

GOODWILL AND OTHER INTANGIBLE ASSETS - GOODWILL (Details) (USD $)	1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Apr. 30, 2014	Dec. 31, 2014	Dec. 31, 2013
Changes in the gross carrying amount of goodwill and accumulated impairment losses
Balance at the beginning of the period, gross goodwill		$953.10	$949.30
Balance at the beginning of the period, accumulated impairment losses		-297.7	-297.7
Balance at the beginning of the period, net goodwill		655.4	651.6
Adjustment to ITF intellectual property		0	3.8
Balance at the end of the period, gross goodwill		953.1	953.1
Balance at the end of the period, accumulated impairment losses		-297.7	-297.7
Balance at the end of the period, net goodwill		655.4	655.4
Goodwill impairment loss	0
Natural Gas Utility
Changes in the gross carrying amount of goodwill and accumulated impairment losses
Balance at the beginning of the period, gross goodwill		933.5	933.5
Balance at the beginning of the period, accumulated impairment losses		-297.7	-297.7
Balance at the beginning of the period, net goodwill		635.8	635.8
Adjustment to ITF intellectual property		0	0
Balance at the end of the period, gross goodwill		933.5	933.5
Balance at the end of the period, accumulated impairment losses		-297.7	-297.7
Balance at the end of the period, net goodwill		635.8	635.8
Holding Company and Other
Changes in the gross carrying amount of goodwill and accumulated impairment losses
Balance at the beginning of the period, gross goodwill		19.6	15.8
Balance at the beginning of the period, accumulated impairment losses		0	0
Balance at the beginning of the period, net goodwill		19.6	15.8
Adjustment to ITF intellectual property		0	3.8
Balance at the end of the period, gross goodwill		19.6	19.6
Balance at the end of the period, accumulated impairment losses		0	0
Balance at the end of the period, net goodwill		$19.60	$19.60

GOODWILL_AND_OTHER_INTANGIBLE_3

GOODWILL AND OTHER INTANGIBLE ASSETS - INTANGIBLE ASSETS OTHER THAN GOODWILL (Details) (USD $)	12 Months Ended			1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 31, 2014
Intangible assets other than goodwill
Total intangible assets, gross	$45.10	$44.90
Total intangible assets, net	33.2	37.5
Amortized intangible assets
Amortized intangible assets, gross carrying amount	34.9	34.7
Accumulated amortization of intangible assets	-11.9	-7.4
Amortized intangible assets, net	23	27.3
Amortization expense for the next five years
Future amortization expense period	5 years
Regulatory assets
Amortized intangible assets
Amortization expense	0.3	0	0
Amortization expense for the next five years
Amortization expense, 2015	1
Amortization expense, 2016	1
Amortization expense, 2017	0.5
Amortization expense, 2018	0
Amortization expense, 2019	0
Cost of sales
Amortized intangible assets
Amortization expense	1.2	1.6	1.3
Amortization expense for the next five years
Amortization expense, 2015	1.1
Amortization expense, 2016	0.9
Amortization expense, 2017	0.9
Amortization expense, 2018	0.8
Amortization expense, 2019	0.6
Depreciation and amortization
Amortized intangible assets
Amortization expense	3	2.5	1
Amortization expense for the next five years
Amortization expense, 2015	3
Amortization expense, 2016	2.9
Amortization expense, 2017	2.4
Amortization expense, 2018	1.9
Amortization expense, 2019	1.9
Trade name | MGU
Unamortized intangible assets
Unamortized intangible assets, carrying amount	5.2	5.2
Trade name | Trillium
Unamortized intangible assets
Unamortized intangible assets, carrying amount	3.5	3.5
Trade name | Pinnacle
Unamortized intangible assets
Unamortized intangible assets, carrying amount	1.5	1.5
Contractual service agreements
Amortized intangible assets
Amortized intangible assets, gross carrying amount	15.6	15.6
Accumulated amortization of intangible assets	-4.3	-1.8
Amortized intangible assets, net	11.3	13.8
Contractual service agreements with shortened amortization period				1
Weighted-average amortization period	4 years
Recovery period	7 years
Customer-owned equipment modifications
Amortized intangible assets
Amortized intangible assets, gross carrying amount	4	4
Accumulated amortization of intangible assets	-1.2	-0.9
Amortized intangible assets, net	2.8	3.1
Weighted-average amortization period	9 years
Intellectual property
Amortized intangible assets
Amortized intangible assets, gross carrying amount	3.4	3.4
Accumulated amortization of intangible assets	-0.8	-0.5
Amortized intangible assets, net	2.6	2.9
Weighted-average amortization period	8 years
Nonregulated easements
Amortized intangible assets
Amortized intangible assets, gross carrying amount	3.9	3.7
Accumulated amortization of intangible assets	-1.4	-1.1
Amortized intangible assets, net	2.5	2.6
Weighted-average amortization period	9 years
Compressed natural gas fueling contract assets
Amortized intangible assets
Amortized intangible assets, gross carrying amount	5.6	5.6
Accumulated amortization of intangible assets	-3.6	-2.7
Amortized intangible assets, net	2	2.9
Weighted-average amortization period	6 years
Customer-related
Amortized intangible assets
Amortized intangible assets, gross carrying amount	1.9	1.9
Accumulated amortization of intangible assets	-0.3	-0.1
Amortized intangible assets, net	1.6	1.8
Weighted-average amortization period	12 years
Other amortized intangible assets
Amortized intangible assets
Amortized intangible assets, gross carrying amount	0.5	0.5
Accumulated amortization of intangible assets	-0.3	-0.3
Amortized intangible assets, net	$0.20	$0.20

LEASES_Details

LEASES (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Leases [Abstract]
Rental expense attributable to operating leases	$14.70	$11.20	$11
Future minimum rental obligations under noncancelable operating leases
2015	4.7
2016	5
2017	5.8
2018	5.6
2019	4.7
Later years	47.6
Total rental obligations	$73.40

SHORTTERM_DEBT_AND_LINES_OF_CR2

SHORT-TERM DEBT AND LINES OF CREDIT OUTSTANDING (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Nov. 30, 2013
Short-term borrowings
Short-term borrowings outstanding	$317.60	$326
Commercial paper
Short-term borrowings
Short-term borrowings outstanding	317.6	326	482.4
Average interest rate on amount outstanding at December 31 (as a percent)	0.36%	0.22%	0.40%
Average amount of short-term borrowings outstanding	283	378.4	326.3
Short-term notes payable
Short-term borrowings
Short-term borrowings outstanding				200
Average amount of short-term borrowings outstanding	$0	$130.40	$0

SHORTTERM_DEBT_AND_LINES_OF_CR3

SHORT-TERM DEBT AND LINES OF CREDIT CAPACITY (Details) (USD $)	1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Short-term borrowings
Total short-term credit capacity	$1,250	$1,250	$1,610
Letters of credit issued inside credit facilities	3.4	3.4	52.4
Short-term borrowings outstanding	317.6	317.6	326
Available capacity under existing agreements	929	929	1,231.60
Decrease Line of Credit Facility, Net	350
Debt to capitalization ratio required to be maintained (as a percent)		65.00%
Integrys Energy Group, Inc.
Short-term borrowings
Short-term borrowings outstanding	7.2	7.2	123.2
Debt to capitalization ratio required to be maintained (as a percent)		65.00%
WPS
Short-term borrowings
Debt to capitalization ratio required to be maintained (as a percent)		65.00%
PGL
Short-term borrowings
Debt to capitalization ratio required to be maintained (as a percent)		65.00%
Revolving credit facility maturing on May 17, 2014 | Integrys Energy Group, Inc.
Short-term borrowings
Total short-term credit capacity	0	0	275
Revolving credit facility maturing on May 17, 2014 | WPS
Short-term borrowings
Total short-term credit capacity	0	0	135
Revolving credit facility maturing on May 17, 2016 | Integrys Energy Group, Inc.
Short-term borrowings
Total short-term credit capacity	0	0	200
Revolving credit facility maturing on June 13, 2017 | Integrys Energy Group, Inc.
Short-term borrowings
Total short-term credit capacity	285	285	635
Revolving credit facility maturing on June 13, 2017 | WPS
Short-term borrowings
Total short-term credit capacity	115	115	115
Revolving credit facility maturing on June 13, 2017 | PGL
Short-term borrowings
Total short-term credit capacity	250	250	250
Revolving credit facility maturing on May 8, 2019 | Integrys Energy Group, Inc.
Short-term borrowings
Total short-term credit capacity	465	465	0
Revolving Credit Facility Maturing May 7, 2015 | WPS
Short-term borrowings
Total short-term credit capacity	135	135	0
Commercial paper
Short-term borrowings
Short-term borrowings outstanding	$317.60	$317.60	$326	$482.40

LONGTERM_DEBT_Details

LONG-TERM DEBT (Details) (USD $)	12 Months Ended	1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Nov. 30, 2014	Jun. 30, 2014	Dec. 31, 2013	Nov. 01, 2014	Jun. 01, 2014
LONG-TERM DEBT
Total	$3,081.90			$3,056.90
Unamortized discount on debt	-0.6			-0.7
Total debt	3,081.30			3,056.20
Less current portion	125			100
Total long-term debt	2,956.30			2,956.20
Debt to capitalization ratio required to be maintained (as a percent)	65.00%
WPS
LONG-TERM DEBT
Debt to capitalization ratio required to be maintained (as a percent)	65.00%
WPS | First Mortgage Bonds
LONG-TERM DEBT
Interest rate stated percentage	7.13%
Total	0.1			0.1
WPS | Senior Notes, 6.375% due 2015
LONG-TERM DEBT
Interest rate stated percentage	6.38%
Total	125			125
Less current portion	125
WPS | Senior Notes, 5.65% due 2017
LONG-TERM DEBT
Interest rate stated percentage	5.65%
Total	125			125
WPS | Senior Notes, 6.08% due 2028
LONG-TERM DEBT
Interest rate stated percentage	6.08%
Total	50			50
WPS | Senior Notes, 5.55% due 2036
LONG-TERM DEBT
Interest rate stated percentage	5.55%
Total	125			125
WPS | Senior Notes, 3.671% due 2042
LONG-TERM DEBT
Interest rate stated percentage	3.67%
Total	300			300
WPS | Senior Notes, 4.752% due 2044
LONG-TERM DEBT
Interest rate stated percentage	4.75%
Total	450			450
PGL
LONG-TERM DEBT
Debt to capitalization ratio required to be maintained (as a percent)	65.00%
PGL | Fixed First and Refunding Mortgage Bonds, Series QQ, 4.875% bonds due 2038
LONG-TERM DEBT
Interest rate stated percentage	4.88%				4.88%
Total	0			75
Principal balance repaid		75
PGL | Fixed First and Refunding Mortgage Bonds, Series RR, 4.30% bonds due 2035
LONG-TERM DEBT
Interest rate stated percentage	4.30%
Total	50			50
PGL | Fixed First and Refunding Mortgage Bonds, Series TT, 8.00% bonds due 2018
LONG-TERM DEBT
Interest rate stated percentage	8.00%
Total	5			5
PGL | Fixed First and Refunding Mortgage Bonds, Series UU, 4.63% bonds due 2019
LONG-TERM DEBT
Interest rate stated percentage	4.63%
Total	75			75
PGL | Fixed First and Refunding Mortgage Bonds, Series VV, 3.900% bonds due 2030
LONG-TERM DEBT
Interest rate stated percentage	3.90%
Total	50			50
PGL | Fixed First and Refunding Mortgage Bonds, Series WW, 2.625% bonds due 2033
LONG-TERM DEBT
Interest rate stated percentage	2.63%
Total	50			50
PGL | Fixed First and Refunding Mortgage Bonds, Series XX, 2.21% bonds due 2016
LONG-TERM DEBT
Interest rate stated percentage	2.21%
Total	50			50
PGL | Fixed First and Refunding Mortgage Bonds, Series YY, 3.98% bonds due 2042
LONG-TERM DEBT
Interest rate stated percentage	3.98%
Total	100			100
PGL | Fixed First and Refunding Mortgage Bonds, Series ZZ, 4.00% bonds due 2033
LONG-TERM DEBT
Interest rate stated percentage	4.00%
Total	50			50
PGL | Fixed First and Refunding Mortgage Bonds, Series AAA, 3.96% bonds due 2043
LONG-TERM DEBT
Interest rate stated percentage	3.96%
Total	220			220
PGL | Fixed First and Refunding Mortgage Bonds, Series BBB, 4.21% bonds due 2044 [Member]
LONG-TERM DEBT
Interest rate stated percentage	4.21%	4.21%
Total	200			0
Amount of debt issued		200
NSG | First Mortgage Series P, 3.43% bonds due 2027
LONG-TERM DEBT
Interest rate stated percentage	3.43%
Total	28			28
NSG | First Mortgage Series Q, 3.96% bonds due 2043
LONG-TERM DEBT
Interest rate stated percentage	3.96%
Total	54			54
Integrys Energy Group, Inc.
LONG-TERM DEBT
Less current portion	0			100
Total long-term debt	974.7			974.7
Debt to capitalization ratio required to be maintained (as a percent)	65.00%
Integrys Energy Group, Inc. | Unsecured Senior Notes, 7.27% due 2014
LONG-TERM DEBT
Interest rate stated percentage	7.27%					7.27%
Total	0			100
Principal balance repaid			100
Integrys Energy Group, Inc. | Unsecured Senior Notes, 8.00% due 2016
LONG-TERM DEBT
Interest rate stated percentage	8.00%
Total	55			55
Integrys Energy Group, Inc. | Unsecured Senior Notes, 4.17% due 2020
LONG-TERM DEBT
Interest rate stated percentage	4.17%
Total	250			250
Integrys Energy Group, Inc. | Junior Subordinated Notes, 6.11% due 2066
LONG-TERM DEBT
Interest rate stated percentage	6.11%
Total	269.8			269.8
Maximum percentage of notes that can be redeemed or repurchased without replacement	10.00%
Integrys Energy Group, Inc. | Junior Subordinated Notes, 6.00% due 2073
LONG-TERM DEBT
Interest rate stated percentage	6.00%
Total	$400			$400

LONGTERM_DEBT_PRINCIPAL_PAYMEN

LONG-TERM DEBT PRINCIPAL PAYMENTS (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Schedule of all principal debt payment amounts related to bond maturities
2015	$125
2016	105
2017	125
2018	5
2019	75
Later years	2,646.90
Total	$3,081.90	$3,056.90

ASSET_RETIREMENT_OBLIGATIONS_D

ASSET RETIREMENT OBLIGATIONS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Changes to asset retirement obligations
Asset retirement obligations at beginning of period	$491	$410.60	$396.30
Accretion	24.6	20.9	20.4
Additions and revisions to estimated cash flows	-17.6	70.6	-0.7
Settlements	-17.8	-11.1	-5.4
Asset retirement obligations at end of period	480.2	491	410.6
Utility segments
Changes to asset retirement obligations
Asset retirement obligations at beginning of period	488.2	408.4	395.8
Accretion	24.5	20.8	20.3
Additions and revisions to estimated cash flows	-18.3	70.1	-2.3
Settlements	-17.8	-11.1	-5.4
Asset retirement obligations at end of period	476.6	488.2	408.4
Nonregulated segments | PDI
Changes to asset retirement obligations
Asset retirement obligations at beginning of period	2.8	2.2	0.5
Accretion	0.1	0.1	0.1
Additions and revisions to estimated cash flows	0.7	0.5	1.6
Settlements	0	0	0
Asset retirement obligations at end of period	$3.60	$2.80	$2.20

INCOME_TAXES_Details

INCOME TAXES (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Deferred income tax assets
Tax credit carryforwards	116.7	$113.50
Price risk management	0	13
Other	77.4	98.5
Total deferred income tax assets	194.1	225
Valuation Allowance	3.6	8.2
Net deferred income tax assets	190.5	216.8
Deferred income tax liabilities
Plant-related	1,584.10	1,373.80
Regulatory deferrals	55.6	78.8
Employee benefits	45.4	79.6
Other	23	43.5
Total deferred income tax liabilities	1,708.10	1,575.70
Balance sheet presentation
Current deferred income tax assets	52.4	31.4
Long-term deferred income tax liabilities	1,570	1,390.30
Net deferred income tax liabilities	1,517.60	1,358.90
Expiration of deferred tax assets [Abstract]
Deferred Tax Assets Expiring Between 2020 and 2025	7.6
Deferred Tax Assets Expiring Between 2026 and 2031	2.9
Deferred Tax Assets Expiring 2032 through 2033	35.7
Income taxes, additional disclosures
Deferred tax credit carryforwards of alternative minimum tax credits	73.9
Deferred tax credit carryforwards of general business credits	32.5
Deferred tax credit carryforwards of foreign tax credits	6.2
Deferred tax credit carryforwards of state tax credits	4.2
Deferred income tax assets reflecting federal operating loss carryforwards	27
Deferred income tax assets reflecting state operating loss carryforwards	19.2
Deferred tax assets expiring between 2020 and 2033
Deferred Tax Assets Expiring Between 2020 and 2025	7.6
Deferred Tax Assets Expiring Between 2026 and 2031	2.9
Deferred Tax Assets Expiring 2032 through 2033	35.7
Net regulatory asset for regulatory tax effects	58.8	$51.60
Foreign carryforwards
Income taxes, additional disclosures
Carryback period of tax credits	1 year
Carryforward period of tax credits	10 years
State carryforwards
Income taxes, additional disclosures
Carryforward period of tax credits	5 years
Carryforward period of operating loss carryforwards	20 years
Federal carryforwards
Income taxes, additional disclosures
Carryback period of operating loss carryforwards	2 years
Carryforward period of operating loss carryforwards	20 years
General business credits
Income taxes, additional disclosures
Carryback period of tax credits	1 year
Carryforward period of tax credits	20 years

INCOME_TAXES_INCOME_TAXES_PROV

INCOME TAXES INCOME TAXES PROVISION (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current provision
Federal	$19.90	$1.60	($17.40)
State	25.2	4.7	-1.7
Total current provision	45.1	6.3	-19.1
Deferred provision
Federal	123	134.1	119.8
State	18.7	9.9	17.9
Total deferred provision	141.7	144	137.7
Penalties	0	-0.1	-0.3
Unrecognized tax benefits	0.7	0.4	-2.9
Interest	-2.1	-0.9	-2.7
Total provision for income taxes related to continuing operations	193.4	158	117.9
Total provision for income taxes related to discontiued operations	7.2	45.9	22.6
Total	200.6	203.9	140.5
Investment tax credit deferral
Deferred provision
Investment tax credits	13.2	12.3	17.8
Investment tax credit amortization
Deferred provision
Investment tax credits	($5.20)	($4)	($12.60)

INCOME_TAXES_RECONCILIATION_De

INCOME TAXES RECONCILIATION (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement (as a percent)
Statutory federal income tax rate (as a percent)	35.00%	35.00%	35.00%
State income tax rate, net (as a percent)	7.50%	3.70%	4.90%
Benefits and compensation (as a percent)	-0.90%	-1.00%	-2.60%
Other differences, net (as a percent)	-0.60%	-0.60%	-4.30%
Effective income tax rate (as a percent)	41.00%	37.10%	33.00%
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement
Statutory federal income tax	$165	$148.90	$124.90
State income taxes, net	35.5	15.9	17.6
Benefits and compensation	-4.3	-4.1	-9.3
Other differences, net	-2.8	-2.7	-15.3
Provision for income taxes	193.4	158	117.9
Reconciliation of the beginning and ending amount of unrecognized tax benefits
Balance at the beginning of the period	3.6	11.3	22.4
Increase related to tax positions taken in prior years	0	2.2	0.9
Decrease related to tax positions taken in prior years	-0.1	-8.7	-6.7
Increase related to tax positions taken in current year	0.5	0.3	0.6
Decrease related to settlements	0	-1.5	-5.7
Decrease related to lapse of statutes	-0.7	0	-0.2
Balance at the end of the period	3.3	3.6	11.3
Unrecognized tax benefits, additional disclosures
Accrued interest related to unrecognized tax benefits	0.3	0.8
Accrued penalties related to unrecognized tax benefits	0.2	0.4
Unrecognized tax benefits related to continuing operations that could affect our effective tax rate, if recognized	2.2
Reasonable possibility of decrease in unrecognized tax benefits with the next 12 months due to settlement of open examinations	($1.30)

COMMITMENTS_AND_CONTINGENCIES_1

COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) (Regulated operations, USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Minimum future commitments for purchase obligations
Total Amounts Committed	$1,722.20
2015	374.7
2016	245.1
2017	218.8
2018	166
2019	119
Later Years	598.6
Natural gas utility supply and transportation | Natural Gas Utility
Minimum future commitments for purchase obligations
Total Amounts Committed	722.6
2015	196.6
2016	170.4
2017	132.9
2018	78.2
2019	50.9
Later Years	93.6
Purchased power | Electric Utility
Minimum future commitments for purchase obligations
Total Amounts Committed	836.8
2015	122.8
2016	42.8
2017	53.3
2018	55.9
2019	57
Later Years	505
Coal supply and transportation | Electric Utility
Minimum future commitments for purchase obligations
Total Amounts Committed	162.8
2015	55.3
2016	31.9
2017	32.6
2018	31.9
2019	11.1
Later Years	$0

COMMITMENTS_AND_CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) (USD $)	1 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2013	Jun. 30, 2013	Oct. 31, 2014	Dec. 31, 2014
				site
Manufactured gas plant remediation | Natural Gas Utility
Manufactured Gas Plant Remediation
Number of environmental remediation sites				53
Number of environmental remediation sites transferred to the EPA Superfund Alternative Sites Program				20
Liabilities estimated and accrued for future undiscounted investigation and cleanup costs for all sites				$579.70
Environmental remediation cash expenditures not yet recovered in rates				54.6
Regulatory assets recorded for cash and estimated future remediation expenditures, net of insurance recoveries received				634.3
WPS | Weston and Pulliam plants | Electric Utility
Air Permitting Violation Claims
Beneficial environmental project amount	6
Civil penalty and/or legal fees	1.2
WPS | Columbia and Edgewater jointly-owned plants | Electric Utility
Air Permitting Violation Claims
Beneficial environmental project amount		1.3
Civil penalty and/or legal fees		0.4
WPS | Mercury emission | Electric Utility
Mercury and Interstate Air Quality Rules
Percentage mercury emission reduction required by the State of Wisconsin's mercury rule through 2014				40.00%
Level of electric generating units above which a 90% reduction in mercury emissions from fuel combusted is required by 2015 (in MW)				150
Estimated capital costs to achieve required emission reduction				9
Expended environmental capital costs to achieve required emission reduction				$8
WPS | Sulfur dioxide and nitrogen oxide | Electric Utility
Mercury and Interstate Air Quality Rules
EPA change to compliance deadline for Cross State Air Pollution Rule			3 years

EMPLOYEE_BENEFIT_PLANS_CHANGE_

EMPLOYEE BENEFIT PLANS - CHANGE IN BENEFIT OBLIGATIONS AND PLAN ASSETS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Liabilities held for sale	$0	$49.10
Long-term liabilities	274.6	200.8
Pension Benefits
Change in benefit obligation
Obligation at January 1	1,641.70	1,784.90
Service cost	24.8	30.2	46
Interest cost	76.2	71.2	78
Plan amendments	0	0
Divestitures - UPPCO	-100.4	0
Actuarial loss (gain), net	166.1	-153.1
Participant contributions	0	0
Benefit payments	-102.7	-91.5
Federal subsidy on benefits paid	0	0
Obligation at December 31	1,705.70	1,641.70	1,784.90
Change in fair value of plan assets
Fair value of plan assets at January 1	1,527.70	1,348.10
Actual return on plan assets	94.6	205.4
Employer contributions	98.8	65.7
Participant contributions	0	0
Divestitures - UPPCO	-122.8	0
Benefit payments	-102.7	-91.5
Fair value of plan assets at December 31	1,495.60	1,527.70	1,348.10
Funded status at December 31	-210.1	-114
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Long-term assets	0	0
Current liabilities	9.1	8.9
Liabilities held for sale	0	6.9
Long-term liabilities	201	98.2
Total net liabilities	-210.1	-114
Accumulated benefit obligation	1,531.10	1,489.10
Information for pension plans with an accumulated benefit obligation in excess of plan assets
Fair value of plan assets	0
Projected benefit obligation	64.1	65.4
Accumulated benefit obligation	61.2	63
Other Benefits
Change in benefit obligation
Obligation at January 1	576.3	621
Service cost	21	24.9	20.8
Interest cost	23.5	24.8	28.5
Plan amendments	-90.4	0.2
Divestitures - UPPCO	-22.3	0
Actuarial loss (gain), net	33.1	-73.4
Participant contributions	10	10.6
Benefit payments	-33.3	-34
Federal subsidy on benefits paid	2.1	2.2
Obligation at December 31	520	576.3	621
Change in fair value of plan assets
Fair value of plan assets at January 1	470.1	424.4
Actual return on plan assets	18.2	57.8
Employer contributions	10	11.3
Participant contributions	10	10.6
Divestitures - UPPCO	-27.3	0
Benefit payments	-33.3	-34
Fair value of plan assets at December 31	447.7	470.1	424.4
Funded status at December 31	-72.3	-106.2
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans
Long-term assets	1.5	0
Current liabilities	0.2	0.2
Liabilities held for sale	0	3.4
Long-term liabilities	73.6	102.6
Total net liabilities	($72.30)	($106.20)

EMPLOYEE_BENEFIT_PLANS_NET_PER

EMPLOYEE BENEFIT PLANS - NET PERIODIC BENEFIT COST (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits
Net regulatory assets
Net actuarial losses	$43.20
Prior service costs (credits)	0.2
Total 2015 - estimated amortization	43.4
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)
Service cost	24.8	30.2	46
Interest cost	76.2	71.2	78
Expected return on plan assets	-112.4	-105.5	-107.9
Loss on plan settlement	0.9	0	0
Amortization of transition obligation	0	0	0
Amortization of prior service cost (credit)	0.6	4	5
Amortization of net actuarial loss	33.3	56.7	34
Net periodic benefit cost	23.4	56.6	55.1
Pension Benefits | Nonregulated segments
Accumulated other comprehensive loss (pre-tax)
Net actuarial loss	40.2	33.3
Prior service credits	0	0
Total	40.2	33.3
Pension Benefits | Utility segments
Net regulatory assets
Net actuarial loss	501	356.2
Prior service costs (credits)	1.8	2.4
Total	502.8	358.6
Other Benefits
Net regulatory assets
Net actuarial losses	4.4
Prior service costs (credits)	-10.3
Total 2015 - estimated amortization	-5.9
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)
Service cost	21	24.9	20.8
Interest cost	23.5	24.8	28.5
Expected return on plan assets	-33	-30.6	-28.2
Loss on plan settlement	0	0	0
Amortization of transition obligation	0	0	0.3
Amortization of prior service cost (credit)	-9.4	-2.5	-3.4
Amortization of net actuarial loss	3.2	8.4	6.6
Net periodic benefit cost	5.3	25	24.6
Other Benefits | Nonregulated segments
Accumulated other comprehensive loss (pre-tax)
Net actuarial loss	0.2	0.7
Prior service credits	-0.1	-0.2
Total	0.1	0.5
Other Benefits | Utility segments
Net regulatory assets
Net actuarial loss	50.4	6.2
Prior service costs (credits)	-85.3	-12.4
Total	($34.90)	($6.20)

EMPLOYEE_BENEFIT_PLANS_ASSUMPT

EMPLOYEE BENEFIT PLANS - ASSUMPTIONS (Details) (USD $)	12 Months Ended			1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014
Pension Benefits
Weighted average assumptions used
Discount rate	4.08%	4.92%		4.08%
Rate of compensation increase	4.23%	4.24%		4.23%
Discount rate	4.92%	4.07%	5.10%
Expected return on plan assets	8.00%	8.00%	8.25%
Rate of compensation increase	4.23%	4.25%	4.25%
Pension Benefits | Equity securities
Target asset allocations
Target asset allocations (as a percent)	70.00%			60.00%
Pension Benefits | Fixed income securities
Target asset allocations
Target asset allocations (as a percent)	30.00%			40.00%
Other Benefits
Weighted average assumptions used
Discount rate	4.00%	4.83%		4.00%
Assumed medical cost trend rate (as a percent)	6.00%	6.50%
Ultimate trend rate (as a percent)	5.00%	5.00%
Year ultimate trend rate is reached	2023	2019		2023
Assumed dental cost trend rate (as a percent)	5.00%	5.00%	5.00%
Discount rate	4.65%	3.96%	4.94%
Expected return on plan assets	8.00%	8.00%	8.25%
Expected return on assets assumption for the next fiscal year	7.75%
Effects of a one-percentage-point change in assumed health care cost trend rates
Effect of one-percentage-point increase on total of service and interest cost components of net periodic postretirement health care benefit cost	6.1
Effect of one-percentage-point decrease on total of service and interest cost components of net periodic postretirement health care benefit cost	-5
Effect of one-percentage-point increase on the health care component of the accumulated postretirement benefit obligation	58.7
Effect of one-percentage-point decrease on the health care component of the accumulated benefit postretirement obligation	-55.1
Other Benefits | Under age 65
Weighted average assumptions used
Assumed medical cost trend rate (as a percent)	6.50%	7.00%	7.00%
Ultimate trend rate (as a percent)	5.00%	5.00%	5.00%
Year ultimate trend rate is reached	2019	2019	2016	2019
Other Benefits | Over age 65
Weighted average assumptions used
Assumed medical cost trend rate (as a percent)	6.50%	7.00%	7.50%
Ultimate trend rate (as a percent)	5.00%	5.00%	5.50%
Year ultimate trend rate is reached	2019	2019	2016	2019
Other Benefits | Equity securities
Target asset allocations
Target asset allocations (as a percent)	70.00%
Other Benefits | Fixed income securities
Target asset allocations
Target asset allocations (as a percent)	30.00%

EMPLOYEE_BENEFIT_PLANS_PENSION

EMPLOYEE BENEFIT PLANS - PENSION AND OTHER POSTRETIREMENT BENEFIT PLAN ASSETS (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Pension Plan Assets
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	$1,537.50	$1,570.60
401(h) other benefit plan assets invested as pension assets	-44.6	-44.1
Total	1,492.90	1,526.50
Pension Plan Assets | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	42.3	38.6
Pension Plan Assets | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	427.2	545.5
Pension Plan Assets | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	476.3	543.1
Pension Plan Assets | United States government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	91.9	93.6
Pension Plan Assets | Foreign government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	20.6	19.3
Pension Plan Assets | Corporate debt
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	425.7	251.3
Pension Plan Assets | Asset-backed securities
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets		61.8
Pension Plan Assets | Other
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	53.5	17.4
Pension Plan Assets | Level 1
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	253.7	216.5
401(h) other benefit plan assets invested as pension assets	-7.4	-6.1
Total	246.3	210.4
Pension Plan Assets | Level 1 | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	2
Pension Plan Assets | Level 1 | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	91	100.4
Pension Plan Assets | Level 1 | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	92.4	114.1
Pension Plan Assets | Level 1 | United States government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	70.3	0
Pension Plan Assets | Level 1 | Foreign government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Pension Plan Assets | Level 1 | Corporate debt
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Pension Plan Assets | Level 1 | Asset-backed securities
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets		0
Pension Plan Assets | Level 1 | Other
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Pension Plan Assets | Level 2
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	1,283.80	1,350.40
401(h) other benefit plan assets invested as pension assets	-37.2	-37.9
Total	1,246.60	1,312.50
Pension Plan Assets | Level 2 | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	42.3	36.6
Pension Plan Assets | Level 2 | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	336.2	445.1
Pension Plan Assets | Level 2 | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	383.9	429
Pension Plan Assets | Level 2 | United States government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	21.6	93.6
Pension Plan Assets | Level 2 | Foreign government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	20.6	16.9
Pension Plan Assets | Level 2 | Corporate debt
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	425.7	250
Pension Plan Assets | Level 2 | Asset-backed securities
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets		61.8
Pension Plan Assets | Level 2 | Other
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	53.5	17.4
Pension Plan Assets | Level 3
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	3.7	5.2
401(h) other benefit plan assets invested as pension assets	0	-0.1
Total	0	3.6
Pension Plan Assets | Level 3 | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Pension Plan Assets | Level 3 | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Pension Plan Assets | Level 3 | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Pension Plan Assets | Level 3 | United States government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Pension Plan Assets | Level 3 | Foreign government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	2.4	4.1
Pension Plan Assets | Level 3 | Corporate debt
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	1.3	1
Pension Plan Assets | Level 3 | Asset-backed securities
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets		0	0.1
Pension Plan Assets | Level 3 | Other
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Other Benefit Plan Assets
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	403.1	425.5
401(h) other benefit plan assets invested as pension assets	44.6	44.1
Total	447.7	469.6
Other Benefit Plan Assets | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	11.1	4
Other Benefit Plan Assets | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	143.4	153.6
Other Benefit Plan Assets | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	136.5	145
Other Benefit Plan Assets | United States government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	111.1	121.9
Other Benefit Plan Assets | Foreign government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Other Benefit Plan Assets | Corporate debt
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Other Benefit Plan Assets | Asset-backed securities
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets		0
Other Benefit Plan Assets | Other
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	1	1
Other Benefit Plan Assets | Level 1
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	159.9	163.1
401(h) other benefit plan assets invested as pension assets	7.4	6.1
Total	167.3	169.2
Other Benefit Plan Assets | Level 1 | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	8.5	0
Other Benefit Plan Assets | Level 1 | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	20.6	21.4
Other Benefit Plan Assets | Level 1 | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	18.7	19.5
Other Benefit Plan Assets | Level 1 | United States government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	111.1	121.2
Other Benefit Plan Assets | Level 1 | Foreign government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Other Benefit Plan Assets | Level 1 | Corporate debt
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Other Benefit Plan Assets | Level 1 | Asset-backed securities
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets		0
Other Benefit Plan Assets | Level 1 | Other
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	1	1
Other Benefit Plan Assets | Level 2
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	243.2	262.4
401(h) other benefit plan assets invested as pension assets	37.2	37.9
Total	280.4	300.3
Other Benefit Plan Assets | Level 2 | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	2.6	4
Other Benefit Plan Assets | Level 2 | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	122.8	132.2
Other Benefit Plan Assets | Level 2 | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	117.8	125.5
Other Benefit Plan Assets | Level 2 | United States government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0.7
Other Benefit Plan Assets | Level 2 | Foreign government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Other Benefit Plan Assets | Level 2 | Corporate debt
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Other Benefit Plan Assets | Level 2 | Asset-backed securities
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets		0
Other Benefit Plan Assets | Level 2 | Other
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Other Benefit Plan Assets | Level 3
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
401(h) other benefit plan assets invested as pension assets	0	0.1
Total	0	0.1
Other Benefit Plan Assets | Level 3 | Cash and cash equivalents
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Other Benefit Plan Assets | Level 3 | United States equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Other Benefit Plan Assets | Level 3 | International equity
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Other Benefit Plan Assets | Level 3 | United States government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Other Benefit Plan Assets | Level 3 | Foreign government
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Other Benefit Plan Assets | Level 3 | Corporate debt
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	0	0
Other Benefit Plan Assets | Level 3 | Asset-backed securities
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets		0
Other Benefit Plan Assets | Level 3 | Other
Investments recorded at fair value, by asset class
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets	$0	$0

EMPLOYEE_BENEFIT_PLANS_CHANGES

EMPLOYEE BENEFIT PLANS - CHANGES IN THE FAIR VALUE OF PLAN ASSETS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	$1,570.60
Net realized and unrealized losses	94.6	205.4
Sales	-122.8	0
Ending balance at December 31	1,537.50	1,570.60
Pension Benefits | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	3.7	5.2
Net realized and unrealized losses		-0.7
Purchases		0.6
Sales	-3.7	-2.4
Transfers into Level 3		1.4
Transfers out of Level 3		-0.4
Ending balance at December 31	0	3.7
Net realized losses related to assets still held at the end of the period	0	-0.5
Pension Benefits | Foreign government
Reconciliation of changes in the fair value of pension plan assets
Ending balance at December 31	20.6	19.3
Pension Benefits | Foreign government | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	2.4	4.1
Net realized and unrealized losses		-0.3
Purchases		0.6
Sales	-2.4	-2
Transfers into Level 3		0
Transfers out of Level 3		0
Ending balance at December 31	0	2.4
Net realized losses related to assets still held at the end of the period	0	-0.2
Pension Benefits | Corporate debt
Reconciliation of changes in the fair value of pension plan assets
Ending balance at December 31	425.7	251.3
Pension Benefits | Corporate debt | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	1.3	1
Net realized and unrealized losses		-0.4
Purchases		0
Sales	-1.3	-0.4
Transfers into Level 3		1.4
Transfers out of Level 3		-0.3
Ending balance at December 31	0	1.3
Net realized losses related to assets still held at the end of the period	0	-0.3
Pension Benefits | Asset-backed securities
Reconciliation of changes in the fair value of pension plan assets
Ending balance at December 31		61.8
Pension Benefits | Asset-backed securities | Level 3
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1		0.1
Net realized and unrealized losses		0
Purchases		0
Sales		0
Transfers into Level 3		0
Transfers out of Level 3		-0.1
Ending balance at December 31		0
Net realized losses related to assets still held at the end of the period		0
Other Benefits
Reconciliation of changes in the fair value of pension plan assets
Beginning balance at January 1	425.5
Net realized and unrealized losses	18.2	57.8
Sales	-27.3	0
Ending balance at December 31	403.1	425.5
Other Benefits | Level 3
Reconciliation of changes in the fair value of pension plan assets
Ending balance at December 31	0	0
Other Benefits | Foreign government
Reconciliation of changes in the fair value of pension plan assets
Ending balance at December 31	0	0
Other Benefits | Foreign government | Level 3
Reconciliation of changes in the fair value of pension plan assets
Ending balance at December 31	0	0
Other Benefits | Corporate debt
Reconciliation of changes in the fair value of pension plan assets
Ending balance at December 31	0	0
Other Benefits | Corporate debt | Level 3
Reconciliation of changes in the fair value of pension plan assets
Ending balance at December 31	0	0
Other Benefits | Asset-backed securities
Reconciliation of changes in the fair value of pension plan assets
Ending balance at December 31		0
Other Benefits | Asset-backed securities | Level 3
Reconciliation of changes in the fair value of pension plan assets
Ending balance at December 31		$0

EMPLOYEE_BENEFIT_PLANS_MISCELL

EMPLOYEE BENEFIT PLANS - MISCELLANEOUS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 31, 2014	Jun. 30, 2014
Employee Benefit Plans
Rabbi trust funding related to potential change in control	$2.40			$64.80	$65
Defined Contribution Benefit Plans
Shares of the entity's common stock held under employee stock ownership plan (ESOP)	3.9
Market value of shares of the entity's common stock held under employee stock ownership plan (ESOP)	303.5
Total costs incurred for defined contribution benefit plans	35	36.4	19.1
Deferred compensation plans
Percentage of director fees that can be deferred by nonemployee directors	100.00%
Deferred compensation obligation classified as an equity instrument	24.3	24.8
Deferred compensation obligation associated with deferrals that allow for distribution in cash	64.4	53.4
Costs incurred under deferred compensation arrangement	9.5	6.5	3.1
Total costs of the entity's common stock held in the Rabbi Trust	20.9	23
Pension Benefits
Employee Benefit Plans
Expected contributions to the plans during the next fiscal year	9.1
Contributions to be funded through a transfer of assets from the rabbi trust	7
Expected payments, reflecting expected future service
2015	124.6
2016	122.3
2017	127.6
2018	126
2019	136.5
2020 through 2024	644.4
Other Benefits
Employee Benefit Plans
Expected contributions to the plans during the next fiscal year	8.7
Expected payments, reflecting expected future service
2015	23.7
2016	26
2017	28.4
2018	30.6
2019	33.3
2020 through 2024	$195.80

PREFERRED_STOCK_OF_SUBSIDIARY_1

PREFERRED STOCK OF SUBSIDIARY (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Preferred stock of subsidiary
Authorized shares	1,000,000
Par value (in dollars per share)	$100
Shares outstanding	510,495
Carrying value	$51.10	$51.10
WPS
Preferred stock of subsidiary
Authorized shares	1,000,000
Mandatorily redeemable shares	0
Par value (in dollars per share)	$100
Shares outstanding	510,495	510,495
Carrying value	51.1	51.1
Notice period for redemption of preferred stock	30 days
Pre-emptive, subscription, or conversion rights	0
Sinking fund provisions	0
WPS | 5.00% preferred stock series
Preferred stock of subsidiary
Series (as a percent)	5.00%
Shares outstanding	130,692	130,692
Carrying value	13.1	13.1
WPS | 5.04% preferred stock series
Preferred stock of subsidiary
Series (as a percent)	5.04%
Shares outstanding	29,898	29,898
Carrying value	3	3
WPS | 5.08% preferred stock series
Preferred stock of subsidiary
Series (as a percent)	5.08%
Shares outstanding	49,905	49,905
Carrying value	5	5
WPS | 6.76% preferred stock series
Preferred stock of subsidiary
Series (as a percent)	6.76%
Shares outstanding	150,000	150,000
Carrying value	15	15
WPS | 6.88% preferred stock series
Preferred stock of subsidiary
Series (as a percent)	6.88%
Shares outstanding	150,000	150,000
Carrying value	$15	$15

COMMON_EQUITY_CHANGES_TO_ISSUE

COMMON EQUITY - CHANGES TO ISSUED COMMON STOCK (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2011
Roll forward of issued common stock
Common stock issued, balance at beginning of the period	79,919,176	78,287,906	78,287,906
Shares issued - Stock-based compensation		972,718
Shares issued - Stock Investment Plan	12,151	298,532
Shares issued - Employee Stock Ownership Plan	31,764	248,724
Shares issued - Rabbi trust shares		111,296
Common stock issued, balance at end of the period	79,963,091	79,919,176	78,287,906

COMMON_EQUITY_RECONCILIATION_O

COMMON EQUITY - RECONCILIATION OF SHARES ISSUED AND OUTSTANDING (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Shares Outstanding [Abstract]
Common stock issued (in shares)	79,963,091	79,919,176	78,287,906	78,287,906
Deferred compensation rabbi trust (in shares)	428,920	473,796
Average cost of shares in the rabbi trust (in dollars per share)	$48.73	$48.50
Total common shares outstanding	79,534,171	79,445,380

COMMON_EQUITY_EARNINGS_PER_SHA

COMMON EQUITY - EARNINGS PER SHARE (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Numerator:
Net income from continuing operations	$278.10	$267.50	$238.90
Discontinued operations, net of tax	1.8	87.3	45.4
Preferred stock dividends of subsidiary	-3.1	-3.1	-3.1
Noncontrolling interest in subsidiaries	0.1	0.1	0.2
Net income attributed to common shareholders	276.9	351.8	281.4
Effect of dilutive securities - Deferred compensation	0	-0.1	0
Net income attributed to common shareholders, diluted	$276.90	$351.70	$281.40
Denominator:
Average shares of common stock - basic	80.2	79.5	78.6
Effect of dilutive securities
Effect of dilutive securities - Stock-based compensation (in shares)	0.5	0.4	0.5
Effect of dilutive securities - Deferred compensation (in shares)	0	0.2	0.2
Average shares of common stock - diluted	80.7	80.1	79.3
Earnings per common share
Basic (in dollars per share)	$3.45	$4.43	$3.58
Diluted (in dollars per share)	$3.43	$4.39	$3.55
Stock-based compensation
Disclosure of antidilutive shares
Weighted-average outstanding securities that had an anti-dilutive effect	0.2	0.3	0.7
Deferred compensation
Disclosure of antidilutive shares
Weighted-average outstanding securities that had an anti-dilutive effect	0.3	0.1	0

COMMON_EQUITY_DIVIDEND_RESTRIC

COMMON EQUITY - DIVIDEND RESTRICTIONS (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Dividend Payment Restrictions
Maximum debt to capitalization ratio required to be maintained (as a percent)		65.00%
Total restricted net assets	$1,953	$1,953
Equity in undistributed earnings of 50% or less owned investees accounted for by the equity method	$157.50	$157.50
Dividends per common share declared (in dollars per share)	$0.68	$2.72	$2.72	$2.72
Maximum
Dividend Payment Restrictions
Equity method investment, ownership interest (as a percent)	50.00%	50.00%
Cumulative period of interest payment deferral on Junior Subordinated Notes		10 years
Minimum
Dividend Payment Restrictions
Number of periods for which interest payments can be deferred on Junior Subordinated Notes		1
WPS
Dividend Payment Restrictions
Maximum debt to capitalization ratio required to be maintained (as a percent)		65.00%
WPS | Maximum | Public Service Commission of Wisconsin (PSCW)
Dividend Payment Restrictions
Percentage of previous period's dividend as restriction on current period dividends		103.00%
WPS | Minimum
Dividend Payment Restrictions
Percentage of common stockholders' equity to total capitalization required to be maintained		25.00%
WPS | Minimum | Public Service Commission of Wisconsin (PSCW)
Dividend Payment Restrictions
Common equity ratio required to be maintained (as a percent)		51.00%
PGL
Dividend Payment Restrictions
Maximum debt to capitalization ratio required to be maintained (as a percent)		65.00%

COMMON_EQUIY_CAPITAL_TRANSACTI

COMMON EQUIY - CAPITAL TRANSACTIONS WITH SUBSIDIARIES (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Capital Transactions with Subsidiaries
Dividends to parent	$186.10
Return of capital to parent	52.5
Equity contributions from parent	333.7
IBS
Capital Transactions with Subsidiaries
Dividends to parent	0
Return of capital to parent	0
Equity contributions from parent	25
ITF
Capital Transactions with Subsidiaries
Dividends to parent	0
Return of capital to parent	0
Equity contributions from parent	50.3
MERC
Capital Transactions with Subsidiaries
Dividends to parent	0
Return of capital to parent	27
Equity contributions from parent	20
MGU
Capital Transactions with Subsidiaries
Dividends to parent	0
Return of capital to parent	13
Equity contributions from parent	7
PGL
Capital Transactions with Subsidiaries
Dividends to parent	0
Return of capital to parent	0
Equity contributions from parent	65
UPPCO
Capital Transactions with Subsidiaries
Dividends to parent	0
Return of capital to parent	12.5
Equity contributions from parent	94.4
WPS
Capital Transactions with Subsidiaries
Dividends to parent	111.8
Return of capital to parent	0
Equity contributions from parent	55
WPS Investments, LLC
Capital Transactions with Subsidiaries
Dividends to parent	74.3
Return of capital to parent	0
Equity contributions from parent	$17
WPS Investments, LLC
Capital Transactions with Subsidiaries
Ownership interest (as a percent)	89.02%
WPS Investments, LLC | WPS
Capital Transactions with Subsidiaries
Ownership interest (as a percent)	10.98%

ACCUMULATED_OTHER_COMPREHENSIV2

ACCUMULATED OTHER COMPREHENSIVE LOSS - ROLLFORWARD (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Changes in accumulated other comprehensive loss, net of tax
Accumulated other comprehensive loss, balance at beginning of period	($23.20)	($40.90)
Other comprehensive income (loss) before reclassifications	-6	13.9
Amounts reclassified out of accumulated other comprehensive loss	1.6	3.8
Other comprehensive income (loss), net of tax	-4.4	17.7	1.6
Accumulated other comprehensive loss, balance at end of period	-27.6	-23.2	-40.9
Cash flow hedges
Changes in accumulated other comprehensive loss, net of tax
Accumulated other comprehensive loss, balance at beginning of period	-3.1	-5.2
Other comprehensive income (loss) before reclassifications	0	0.7
Amounts reclassified out of accumulated other comprehensive loss	-0.1	1.4
Other comprehensive income (loss), net of tax	-0.1	2.1
Accumulated other comprehensive loss, balance at end of period	-3.2	-3.1
Defined benefit plans
Changes in accumulated other comprehensive loss, net of tax
Accumulated other comprehensive loss, balance at beginning of period	-20.1	-35.7
Other comprehensive income (loss) before reclassifications	-6	13.2
Amounts reclassified out of accumulated other comprehensive loss	1.7	2.4
Other comprehensive income (loss), net of tax	-4.3	15.6
Accumulated other comprehensive loss, balance at end of period	($24.40)	($20.10)

ACCUMULATED_OTHER_COMPREHENSIV3

ACCUMULATED OTHER COMPREHENSIVE LOSS - RECLASSIFICATIONS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Amount reclassified out of accumulated other comprehensive loss
Operating and maintenance expense	$1,199.70	$1,086.70	$943
Interest expense	154.8	127.4	118.9
Net of tax	-279.9	-354.8	-284.3
Amount reclassified
Amount reclassified out of accumulated other comprehensive loss
Net of tax	1.6	3.8
Utility segments
Amount reclassified out of accumulated other comprehensive loss
Interest expense	101.8	86.6	83.2
Losses (gains) on cash flow hedges | Amount reclassified
Amount reclassified out of accumulated other comprehensive loss
Total before taxes	1.1	5
Tax expense	1.2	3.6
Net of tax	-0.1	1.4
Losses (gains) on cash flow hedges | Commodity derivative contracts | Utility segments | Amount reclassified
Amount reclassified out of accumulated other comprehensive loss
Operating and maintenance expense	0	0.2
Losses (gains) on cash flow hedges | Commodity derivative contracts | Nonregulated segments | Amount reclassified
Amount reclassified out of accumulated other comprehensive loss
Discontinued operations	0	3.7
Losses (gains) on cash flow hedges | Interest rate hedges | Amount reclassified
Amount reclassified out of accumulated other comprehensive loss
Interest expense	1.1	1.1
Defined benefit plans | Amount reclassified
Amount reclassified out of accumulated other comprehensive loss
Amortization of prior service costs (credits)	-0.2	4.3
Amortization of net actuarial losses (gains)	2.7	-0.2
Total before taxes	2.5	4.1
Tax expense	0.8	1.7
Net of tax	$1.70	$2.40

GUARANTEES_Details

GUARANTEES (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Guarantees
Total guarantees	$568.60
Guarantees expiring in less than 1 year	379.6
Guarantees expiring within 1 to 3 years	2
Guarantees with expiration over 3 years	187
Guarantees supporting commodity transactions of subsidiaries
Guarantees
Total guarantees	189.3
Guarantees expiring in less than 1 year	105.1
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	84.2
Guarantees supporting commodity transactions of subsidiaries | IBS
Guarantees
Total guarantees	5
Guarantees supporting commodity transactions of subsidiaries | ITF
Guarantees
Total guarantees	0.4
Guarantees supporting commodity transactions of subsidiaries | MERC
Guarantees
Total guarantees	127.4
Guarantees supporting commodity transactions of subsidiaries | MGU
Guarantees
Total guarantees	44.7
Guarantees supporting commodity transactions of subsidiaries | PDI
Guarantees
Total guarantees	11.8
Standby letters of credit
Guarantees
Total guarantees	1.2
Guarantees expiring in less than 1 year	1.1
Guarantees expiring within 1 to 3 years	0.1
Guarantees with expiration over 3 years	0
Standby letters of credit | ITF, MERC, MGU, NSG, PDI, PGL, and WPS
Guarantees
Total guarantees	1.2
Surety bonds
Guarantees
Total guarantees	25.1
Guarantees expiring in less than 1 year	25
Guarantees expiring within 1 to 3 years	0.1
Guarantees with expiration over 3 years	0
Other guarantees
Guarantees
Total guarantees	73.5
Guarantees expiring in less than 1 year	0
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	73.5
Other guarantees | Texas Retail Electric Marketing Business
Guarantees
Total guarantees	10
Other guarantees | ITF
Guarantees
Total guarantees	11.2
Other guarantees | PDI
Guarantees
Total guarantees	46.1
Other indemnifications
Guarantees
Total guarantees	6.2
Guarantees temporarily retained related to the sale of IES's retail energy business
Guarantees
Total guarantees	279.5
Guarantees expiring in less than 1 year	248.4
Guarantees expiring within 1 to 3 years	1.8
Guarantees with expiration over 3 years	29.3
Period of time after the sale of IES for which guarantees will be provided	6 months
Guarantees supporting commodity transactions temporarily retained by Integrys Energy Group | IES's retail energy business
Guarantees
Total guarantees	267.4
Standby letters of credit temporarily retained by Integrys Energy Group | IES's retail energy business
Guarantees
Total guarantees	6.9
Surety bonds temporarily retained by Integrys Energy Group | IES's retail energy business
Guarantees
Total guarantees	3.4
Other guarantees temporarily retained by Integrys Energy Group | WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC
Guarantees
Total guarantees	1.8
Guarantee obligation maximum exposure related to open transactions | IES's retail energy business
Guarantees
Total guarantees	$168.90

STOCKBASED_COMPENSATION_STOCKB

STOCK-BASED COMPENSATION - STOCK-BASED COMPENSATION EXPENSE (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Information related to share based awards
Total stock-based compensation expense	$30.20	$14	$16.10
Deferred income tax benefit	12.1	5.6	6.4
Stock-based compensation cost capitalized	0	0	0
Stock Options
Information related to share based awards
Total stock-based compensation expense	2.7	1.8	2
Performance Stock Rights
Information related to share based awards
Total stock-based compensation expense	16.8	2.7	5
Restricted Share Units
Information related to share based awards
Total stock-based compensation expense	9.9	8.6	8.1
Nonemployee Director Deferred Stock Units
Information related to share based awards
Total stock-based compensation expense	$0.80	$0.90	$1

STOCKBASED_COMPENSATION_STOCK_

STOCK-BASED COMPENSATION - STOCK OPTIONS (Details) (Stock Options, USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Options
Weighted-average fair values along with the assumptions incorporated into the valuation models
Weighted-average fair value per stock option (in dollars per share)	$6.70	$6.03	$6.30
Expected term	8 years	5 years	5 years
Risk-free interest rate, minimum (as a percent)	0.12%	0.18%	0.17%
Risk-free interest rate, maximum (as a percent)	2.88%	2.11%	2.18%
Expected dividend yield (as a percent)	5.28%	5.33%	5.28%
Expected volatility (as a percent)	18.00%	24.00%	25.00%
Stock Options
Outstanding, at the beginning of the period (in shares)	1,550,374
Granted, (in shares)	264,332
Exercised (in shares)	-1,676,831
Forfeited (in shares)	-3,858
Outstanding, at the end of the period (in shares)	134,017	1,550,374
Exercisable at the end of the period (in shares)	59,714
Weighted-Average Exercise Price
Outstanding at the beginning of the period (in dollars per share)	$50.93
Granted (in dollars per share)	$55.23
Exercised (in dollars per share)	$51.33
Forfeited (in dollars per share)	$55.23
Outstanding at the end of the period (in dollars per share)	$54.31	$50.93
Exercisable at the end of the period (in dollars per share)	$55.21
Weighted-Average Remaining Contractual Life (in Years)
Outstanding at the end of the period	6 years 7 months
Exercisable at the end of period	5 years 7 months
Aggregate Intrinsic Value
Outstanding at the end of the period (in dollars)	$3.20
Exercisable at the end of the period (in dollars)	1.4
Options exercised (in dollars)	32	9	11
Additional disclosures
Tax benefit realized for the tax deductions from option exercises	$12.80	$3.60	$4.40

STOCKBASED_COMPENSATION_PERFOR

STOCK-BASED COMPENSATION - PERFORMANCE STOCK RIGHTS (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Performance Stock Rights
Assumptions incorporated into the valuation models
Risk-free interest rate, minimum (as a percent)	0.21%	0.13%	0.17%
Risk-free interest rate, maximum (as a percent)	0.63%	1.27%	1.27%
Expected volatility, minimum (as a percent)	18.00%	15.00%	14.00%
Expected volatility, maximum (as a percent)	22.00%	36.00%	36.00%
Additional disclosures
Compensation cost not yet recognized	$4.20
Weighted-average period over which compensation cost is to be recognized	1 year 7 months
Total intrinsic value of performance stock rights distributed during the period	6.4	8.8	4.7
Tax benefit realized from the distribution of shares	$2.60	$3.60	$1.90
Performance Stock Rights | Minimum
Assumptions incorporated into the valuation models
Expected dividend yield (as a percent)	5.25%	5.28%	5.18%
Performance Stock Rights | Maximum
Assumptions incorporated into the valuation models
Expected dividend yield (as a percent)	5.33%	5.34%	5.34%
Performance Stock Rights Accounted For As Equity Awards
Performance Stock Rights
Outstanding at the beginning of the period (in shares)	85,749
Granted (in shares)	21,146
Award modifications (in shares)	64,612
Distributed (in shares)	-74,345
Adjustment for estimated payout and shares not distributed (in shares)	-28,591
Forfeited (in shares)	-308
Outstanding at the end of the period (in shares)	68,263	85,749
Weighted-Average Fair Value
Outstanding at the beginning of the period (in dollars per share)	$46.62
Granted (in dollars per share)	$44.28	$48.50	$52.70
Award modifications (in dollars per share)	$85.09
Distributed (in dollars per share)	$77.67
Adjustment for estimated payout and shares not distributed (in dollars per shares)	$52.67
Forfeited (in dollars per share)	$44.28
Outstanding at the end of the period (in dollars per share)	$58.54	$46.62
Performance Stock Rights Accounted For As Equity Awards | Performance stock rights with a performance period ending December 31, 2013
Performance Stock Rights
Distributed (in shares)	0
Performance Stock Rights Accounted For As Liability Awards
Performance Stock Rights
Outstanding at the beginning of the period (in shares)	198,904
Granted (in shares)	84,529
Award modifications (in shares)	-64,612
Distributed (in shares)	-10,760
Adjustment for estimated payout and shares not distributed (in shares)	-36,519
Forfeited (in shares)	-1,234
Outstanding at the end of the period (in shares)	170,308
Weighted-Average Fair Value
Outstanding at end of the period, fair value as of the reporting date (in dollars per share)	$108.51
Performance Stock Rights Accounted For As Liability Awards | Performance stock rights with a performance period ending December 31, 2013
Performance Stock Rights
Distributed (in shares)	0

STOCKBASED_COMPENSATION_RESTRI

STOCK-BASED COMPENSATION - RESTRICTED SHARE UNITS (Details) (Restricted Share Units, USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Share Units
Restricted Share Unit Awards
Outstanding at the beginning of the period (in shares)	511,301
Granted (in shares)	214,953
Dividend equivalents (in shares)	21,422
Vested and released (in shares)	-208,964
Forfeited (in shares)	-111,407
Outstanding at the end of the period (in shares)	427,305	511,301
Weighted-Average Grant Date Fair Value
Outstanding at the beginning of the period (in dollars per share)	$52.24
Granted (in dollars per share)	$55.23	$55.93	$53.24
Dividend equivalents (in dollars per share)	$54.47
Vested and released (in dollars per share)	$49.76
Forfeited (in dollars per share)	$54.62
Outstanding at the end of the period (in dollars per share)	$54.45	$52.24
Additional disclosures
Compensation cost not yet recognized	$7.30
Weighted-average period over which compensation cost is to be recognized	2 years 3 months
Total intrinsic value of restricted share units vested and released	11.4	11.7	10.7
Tax benefit realized from the vesting and release of restricted share units	$4.60	$4.70	$4.30

FAIR_VALUE_ASSETS_AND_LIABILIT

FAIR VALUE - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2014
Utility segments
Assets
Risk Management Assets	$11.90	$4.50
Liabilities
Risk Management Liabilities	4.1	49.1
Fair value measurements on a recurring basis | Utility segments
Transfers Between the Levels of the Fair Value Hierarchy
Fair Value Transfers, Amount	0
Fair value measurements on a recurring basis | Utility segments | Level 1
Assets
Risk Management Assets	2.5	0
Liabilities
Risk Management Liabilities	0.5	7.6
Fair value measurements on a recurring basis | Utility segments | Level 2
Assets
Risk Management Assets	7.7	2.3
Liabilities
Risk Management Liabilities	0.6	32.4
Fair value measurements on a recurring basis | Utility segments | Level 3
Assets
Risk Management Assets	1.7	2.2
Liabilities
Risk Management Liabilities	3	9.1
Fair value measurements on a recurring basis | Utility segments | Total
Assets
Risk Management Assets	11.9	4.5
Liabilities
Risk Management Liabilities	4.1	49.1
Fair value measurements on a recurring basis | Utility segments | Natural gas contracts | Level 1
Assets
Risk Management Assets	2.4	0
Liabilities
Risk Management Liabilities	0.5	4.8
Fair value measurements on a recurring basis | Utility segments | Natural gas contracts | Level 2
Assets
Risk Management Assets	7.7	2.3
Liabilities
Risk Management Liabilities	0.6	31.2
Fair value measurements on a recurring basis | Utility segments | Natural gas contracts | Level 3
Assets
Risk Management Assets	0	0
Liabilities
Risk Management Liabilities	0	6.6
Fair value measurements on a recurring basis | Utility segments | Natural gas contracts | Total
Assets
Risk Management Assets	10.1	2.3
Liabilities
Risk Management Liabilities	1.1	42.6
Fair value measurements on a recurring basis | Utility segments | FTRs | Level 1
Assets
Risk Management Assets	0	0
Liabilities
Risk Management Liabilities	0	0
Fair value measurements on a recurring basis | Utility segments | FTRs | Level 2
Assets
Risk Management Assets	0	0
Liabilities
Risk Management Liabilities	0	0
Fair value measurements on a recurring basis | Utility segments | FTRs | Level 3
Assets
Risk Management Assets	1.5	2.2
Liabilities
Risk Management Liabilities	0.3	0.3
Fair value measurements on a recurring basis | Utility segments | FTRs | Total
Assets
Risk Management Assets	1.5	2.2
Liabilities
Risk Management Liabilities	0.3	0.3
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Level 1
Assets
Risk Management Assets	0.1
Liabilities
Risk Management Liabilities		2.8
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Level 2
Assets
Risk Management Assets	0
Liabilities
Risk Management Liabilities		0
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Level 3
Assets
Risk Management Assets	0
Liabilities
Risk Management Liabilities		0
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Total
Assets
Risk Management Assets	0.1
Liabilities
Risk Management Liabilities		2.8
Fair value measurements on a recurring basis | Utility segments | Coal contracts | Level 1
Assets
Risk Management Assets	0	0
Liabilities
Risk Management Liabilities	0	0
Fair value measurements on a recurring basis | Utility segments | Coal contracts | Level 2
Assets
Risk Management Assets	0	0
Liabilities
Risk Management Liabilities	0	1.2
Fair value measurements on a recurring basis | Utility segments | Coal contracts | Level 3
Assets
Risk Management Assets	0.2	0
Liabilities
Risk Management Liabilities	2.7	2.2
Fair value measurements on a recurring basis | Utility segments | Coal contracts | Total
Assets
Risk Management Assets	0.2	0
Liabilities
Risk Management Liabilities	2.7	3.4
Fair value measurements on a recurring basis | Holding Company and Other | Level 1
Assets
Investment in exchange-traded funds	15.9	102.4
Fair value measurements on a recurring basis | Holding Company and Other | Level 2
Assets
Investment in exchange-traded funds	0	0
Fair value measurements on a recurring basis | Holding Company and Other | Level 3
Assets
Investment in exchange-traded funds	0	0
Fair value measurements on a recurring basis | Holding Company and Other | Total
Assets
Investment in exchange-traded funds	$15.90	$102.40

FAIR_VALUE_SIGNIFICANT_UNOBSER

FAIR VALUE - SIGNIFICANT UNOBSERVABLE INPUTS (Details) (Utility segments, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Significant internally-developed unobservable inputs
Risk Management Assets	4.5	$11.90
Risk Management Liabilities	49.1	4.1
Fair value measurements on a recurring basis | Level 3
Significant internally-developed unobservable inputs
Risk Management Assets	2.2	1.7
Risk Management Liabilities	9.1	3
Fair value measurements on a recurring basis | Level 3 | Natural gas contracts
Significant internally-developed unobservable inputs
Risk Management Assets	0	0
Risk Management Liabilities	6.6	0
Fair value measurements on a recurring basis | Level 3 | Natural gas contracts | Valuation Technique: Income-based | Minimum
Significant internally-developed unobservable inputs
Option volatilities (as a percent)	50.50%
Fair value measurements on a recurring basis | Level 3 | Natural gas contracts | Valuation Technique: Income-based | Maximum
Significant internally-developed unobservable inputs
Option volatilities (as a percent)	67.20%
Fair value measurements on a recurring basis | Level 3 | FTRs
Significant internally-developed unobservable inputs
Risk Management Assets	2.2	1.5
Risk Management Liabilities	0.3	0.3
Fair value measurements on a recurring basis | Level 3 | FTRs | Valuation Technique: Market-based | Weighted Average
Significant internally-developed unobservable inputs
Forward market prices (in dollars per megawatt-month or ton)	188.16
Fair value measurements on a recurring basis | Level 3 | Coal contracts
Significant internally-developed unobservable inputs
Risk Management Assets	0	0.2
Risk Management Liabilities	2.2	$2.70
Fair value measurements on a recurring basis | Level 3 | Coal contracts | Valuation Technique: Market-based | Minimum
Significant internally-developed unobservable inputs
Forward market prices (in dollars per megawatt-month or ton)	10.89
Fair value measurements on a recurring basis | Level 3 | Coal contracts | Valuation Technique: Market-based | Maximum
Significant internally-developed unobservable inputs
Forward market prices (in dollars per megawatt-month or ton)	13.6

FAIR_VALUE_LEVEL_3_RECONCILIAT

FAIR VALUE - LEVEL 3 RECONCILIATION (Details) (Utility segments, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Changes in the fair value of items measured on a recurring basis and categorized as Level 3 measurements
Balance at the beginning of the period	($1.30)	($5.40)	($5.70)
Net realized and unrealized gains included in earnings	0.2	3	1.8
Net unrealized (losses) gains recorded as regulatory assets or liabilities	-7.8	0.3	5.7
Purchases	4.3	3.2	2.8
Sales		-0.2	-0.1
Settlements	-3.5	-2.2	-9.9
Net transfers out of Level 3	1.2
Balance at the end of the period	-6.9	-1.3	-5.4
Impact on earnings of unrealized gains (losses) on level 3 instruments	0	0	0
Natural gas contracts
Changes in the fair value of items measured on a recurring basis and categorized as Level 3 measurements
Balance at the beginning of the period	0
Net realized and unrealized gains included in earnings	0
Net unrealized (losses) gains recorded as regulatory assets or liabilities	-6.6
Purchases	0
Settlements	0
Net transfers out of Level 3	0
Balance at the end of the period	-6.6
FTRs
Changes in the fair value of items measured on a recurring basis and categorized as Level 3 measurements
Balance at the beginning of the period	1.2	1.1	1.2
Net realized and unrealized gains included in earnings	0.2	3	1.8
Net unrealized (losses) gains recorded as regulatory assets or liabilities	0.4	-0.1	-0.1
Purchases	4.3	3.2	2.8
Sales		-0.2	-0.1
Settlements	-4.2	-5.8	-4.5
Net transfers out of Level 3	0
Balance at the end of the period	1.9	1.2	1.1
Coal contracts
Changes in the fair value of items measured on a recurring basis and categorized as Level 3 measurements
Balance at the beginning of the period	-2.5	-6.5	-6.9
Net realized and unrealized gains included in earnings	0	0	0
Net unrealized (losses) gains recorded as regulatory assets or liabilities	-1.6	0.4	5.8
Purchases	0	0	0
Sales		0	0
Settlements	0.7	3.6	-5.4
Net transfers out of Level 3	1.2
Balance at the end of the period	($2.20)	($2.50)	($6.50)

FAIR_VALUE_FINANCIAL_INSTRUMEN

FAIR VALUE - FINANCIAL INSTRUMENTS NOT RECORDED AT FAIR VALUE (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Financial instruments not recorded at fair value
Long-term debt	$3,081.30	$3,056.20
Preferred stock of subsidiary – $100 par value; 1,000,000 shares authorized; 511,882 shares issued; 510,495 shares outstanding	51.1	51.1
Carrying Amount
Financial instruments not recorded at fair value
Long-term debt	3,081.30	3,056.20
Preferred stock of subsidiary – $100 par value; 1,000,000 shares authorized; 511,882 shares issued; 510,495 shares outstanding	51.1	51.1
Fair value
Financial instruments not recorded at fair value
Long-term debt	3,271.40	3,031.60
Preferred stock of subsidiary – $100 par value; 1,000,000 shares authorized; 511,882 shares issued; 510,495 shares outstanding	$51.80	$61.20

REGULATORY_ENVIRONMENT_Details

REGULATORY ENVIRONMENT (Details) (USD $)	1 Months Ended				3 Months Ended	1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 31, 2013	Mar. 31, 2013	Oct. 31, 2014	Nov. 30, 2013	Jun. 30, 2013	Jul. 31, 2012	Feb. 28, 2015	Jan. 31, 2015
WPS
Public Utilities, General Disclosures [Line Items]
Percentage price variance from rate case-approved fuel and purchased power costs before deferral is required	2.00%
Public Service Commission of Wisconsin (PSCW) | 2015 Rates | WPS
Public Utilities, General Disclosures [Line Items]
Approved return on common equity percent reflected in rates of customers	10.20%
Approved percent of capital structure composed of common equity	50.28%
Percentage price variance from rate case-approved fuel and purchased power costs before deferral is required	2.00%
Public Service Commission of Wisconsin (PSCW) | 2014 Rates | WPS
Public Utilities, General Disclosures [Line Items]
Approved return on common equity percent reflected in rates of customers		10.20%
Approved percent of capital structure composed of common equity		50.14%
Public Service Commission of Wisconsin (PSCW) | 2013 Rates | WPS
Public Utilities, General Disclosures [Line Items]
Approved return on common equity percent reflected in rates of customers			10.30%
Approved percent of capital structure composed of common equity			51.61%
Recovery of income tax amounts previously expensed related to the Federal Health Care Reform Act			$5.90
Public Service Commission of Wisconsin (PSCW) | Retail electric rates | 2015 Rates | WPS
Public Utilities, General Disclosures [Line Items]
Approved annual increase (decrease) in rates for customers	24.6
Public Service Commission of Wisconsin (PSCW) | Retail electric rates | 2014 Rates | WPS
Public Utilities, General Disclosures [Line Items]
Approved annual increase (decrease) in rates for customers		-12.8
Public Service Commission of Wisconsin (PSCW) | Retail electric rates | 2013 Rates | WPS
Public Utilities, General Disclosures [Line Items]
Approved annual increase (decrease) in rates for customers			28.5
Fuel refund			20.5
Deferral related to pension and other employee benefit costs			7.3
Annual cap for decoupling			14
Public Service Commission of Wisconsin (PSCW) | Retail natural gas rates | 2015 Rates | WPS
Public Utilities, General Disclosures [Line Items]
Approved annual increase (decrease) in rates for customers	-15.4
Public Service Commission of Wisconsin (PSCW) | Retail natural gas rates | 2014 Rates | WPS
Public Utilities, General Disclosures [Line Items]
Approved annual increase (decrease) in rates for customers		4
Public Service Commission of Wisconsin (PSCW) | Retail natural gas rates | 2013 Rates | WPS
Public Utilities, General Disclosures [Line Items]
Approved annual increase (decrease) in rates for customers			-3.4
Deferral related to pension and other employee benefit costs			2.1
Annual cap for decoupling			8
Michigan Public Service Commission (MPSC) | MGU
Public Utilities, General Disclosures [Line Items]
Reversal of disallowance of depreciation expense associated with the retirement of certain assets				2.5
Reduction to depreciation expense					2.5
Michigan Public Service Commission (MPSC) | Retail electric rates | 2015 Rates | WPS
Public Utilities, General Disclosures [Line Items]
Requested annual increase (decrease) in rates for customers						5.7
Requested return on common equity percent						10.60%
Requested percent of capital structure composed of common equity						50.48%
Michigan Public Service Commission (MPSC) | Retail electric rates | 2014 Rates | UPPCO
Public Utilities, General Disclosures [Line Items]
Approved annual increase (decrease) in rates for customers		5.8
Approved return on common equity percent reflected in rates of customers		10.15%
Approved percent of capital structure composed of common equity		56.74%
Michigan Public Service Commission (MPSC) | Retail natural gas rates | 2014 Rates | MGU
Public Utilities, General Disclosures [Line Items]
Approved annual increase (decrease) in rates for customers							4.5
Approved return on common equity percent reflected in rates of customers							10.25%
Approved percent of capital structure composed of common equity							48.62%
Illinois Commerce Commission (ICC) | Retail natural gas rates | 2013 Rates | NSG
Public Utilities, General Disclosures [Line Items]
Approved annual increase (decrease) in rates for customers								6.6
Approved return on common equity percent reflected in rates of customers								9.28%
Approved percent of capital structure composed of common equity								50.32%
Adjustment to annual increase (decrease) in rates for customers		0.1
Illinois Commerce Commission (ICC) | Retail natural gas rates | 2013 Rates | PGL
Public Utilities, General Disclosures [Line Items]
Approved annual increase (decrease) in rates for customers								57.2
Approved return on common equity percent reflected in rates of customers								9.28%
Approved percent of capital structure composed of common equity								50.43%
Adjustment to annual increase (decrease) in rates for customers		2.6
Minnesota Public Utilities Commission (MPUC) | Retail natural gas rates | 2014 Rates | MERC
Public Utilities, General Disclosures [Line Items]
Approved annual increase (decrease) in rates for customers						7.6
Approved return on common equity percent reflected in rates of customers						9.35%
Approved percent of capital structure composed of common equity						50.31%
Interim rates to be refunded to customers	3.1
Annual percent cap on decoupling based on distribution revenues approved in the rate case						10.00%
Minnesota Public Utilities Commission (MPUC) | Retail natural gas rates | 2011 Rates | MERC
Public Utilities, General Disclosures [Line Items]
Approved annual increase (decrease) in rates for customers									11
Approved return on common equity percent reflected in rates of customers									9.70%
Approved percent of capital structure composed of common equity									50.48%
Trial basis period for decoupling mechanism									3 years
Annual percent cap on decoupling based on distribution revenues approved in the rate case									10.00%
Subsequent Event | Illinois Commerce Commission (ICC) | Retail natural gas rates | 2015 Rates | NSG
Public Utilities, General Disclosures [Line Items]
Approved annual increase (decrease) in rates for customers											3.7
Approved return on common equity percent reflected in rates of customers											9.05%
Approved percent of capital structure composed of common equity											50.48%
Amended approved annual increase (decrease) in rates for customers										3.5
Subsequent Event | Illinois Commerce Commission (ICC) | Retail natural gas rates | 2015 Rates | PGL
Public Utilities, General Disclosures [Line Items]
Approved annual increase (decrease) in rates for customers											74.8
Approved return on common equity percent reflected in rates of customers											9.05%
Approved percent of capital structure composed of common equity											50.33%
Amended approved annual increase (decrease) in rates for customers										$71.10

MISCELLANEOUS_INCOME_Details

MISCELLANEOUS INCOME (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Income and Expenses [Abstract]
Equity portion of AFUDC	$12.50	$10.80	$2.90
Federal excise tax credit	4.4	4.1	0
Gain on sale of land at the holding company	3.5	0	0
Key executive life insurance income for retired employees	2.9	2.2	2.6
Gains on exchange-traded funds	2.9	2.2	1.3
Other	4.8	2.6	2.2
Total miscellaneous income	$31	$21.90	$9

VARIABLE_INTEREST_ENTITIES_Det

VARIABLE INTEREST ENTITIES (Details)	12 Months Ended
	Dec. 31, 2014	Nov. 01, 2014
AMP Trillium, LLC | Co-venturer
Variable interest entities
Variable interest entity ownership interest (as a percent)	70.00%
AMP Trillium, LLC | ITF
Variable interest entities
Variable interest entity ownership interest (as a percent)	30.00%
Number of CNG fueling stations sold		8
EVO Trillium, LLC | Co-venturer
Variable interest entities
Variable interest entity ownership interest (as a percent)	85.00%
EVO Trillium, LLC | ITF
Variable interest entities
Variable interest entity ownership interest (as a percent)	15.00%

SEGMENTS_OF_BUSINESS_Details

SEGMENTS OF BUSINESS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment reporting information
Revenues	$4,144.20	$3,485.50	$3,012.90
Depreciation and amortization expense	287.5	263.4	247.3
Merger transaction costs	10.4	0	0
Gain on sale of UPPCO, net of transaction costs	-85.4	0	0
Gain on abandonment of PDI's Winnebago Energy Center	-5	0	0
Earnings from equity method investments	88.3	91.5	87.2
Miscellaneous income	31	21.9	9
Interest expense	154.8	127.4	118.9
Provision for income taxes	193.4	158	117.9
Net income (loss) from continuing operations	278.1	267.5	238.9
Discontinued operations	1.8	87.3	45.4
Preferred stock dividends of subsidiary	-3.1	-3.1	-3.1
Noncontrolling interest in subsidiaries	0.1	0.1	0.2
Net income attributed to common shareholders	276.9	351.8	281.4
Total assets	11,282	11,243.50	10,327.40
Cash expenditures for long-lived assets	865	1,060.80	594.4
ATC
Segment reporting information
Equity method investment, ownership interest (as a percent)	34.00%
Earnings from equity method investments	85.7	89.1	85.3
Intersegment revenues
Segment reporting information
Revenues	0	0	0
Reconciling Eliminations
Segment reporting information
Revenues	0	0	0
Depreciation and amortization expense	-0.5	-0.5	-0.5
Merger transaction costs	0
Gain on sale of UPPCO, net of transaction costs	0
Gain on abandonment of PDI's Winnebago Energy Center	0
Earnings from equity method investments	0	0	0
Miscellaneous income	-11.8	-12.4	-14.1
Interest expense	-11.8	-12.4	-14.1
Provision for income taxes	0	0	0
Net income (loss) from continuing operations	0	0	0
Discontinued operations	0	0	0
Preferred stock dividends of subsidiary	0	0	0
Noncontrolling interest in subsidiaries	0	0	0
Net income attributed to common shareholders	0	0	0
Total assets	-692.2	-786.5	-653.7
Cash expenditures for long-lived assets	0	0	0
Reconciling Eliminations | Intersegment revenues
Segment reporting information
Revenues	-13.9	-12.4	-11.2
Regulated operations
Segment reporting information
Revenues	4,034.30	3,426.10	2,960.10
Depreciation and amortization expense	252	234.6	220.8
Merger transaction costs	0
Gain on sale of UPPCO, net of transaction costs	-85.4
Gain on abandonment of PDI's Winnebago Energy Center	0
Earnings from equity method investments	85.7	89.1	85.3
Miscellaneous income	13	11	3.2
Interest expense	101.8	86.6	83.2
Provision for income taxes	203.3	181.4	143.7
Net income (loss) from continuing operations	318.3	291.3	256.8
Discontinued operations	0	0	0
Preferred stock dividends of subsidiary	-3.1	-3.1	-3.1
Noncontrolling interest in subsidiaries	0	0	0
Net income attributed to common shareholders	315.2	288.2	253.7
Total assets	10,336.10	9,694.90	8,964.10
Cash expenditures for long-lived assets	743.1	985	539
Regulated operations | Intersegment revenues
Segment reporting information
Revenues	12.5	11	9.3
Regulated operations | Natural Gas Utility
Segment reporting information
Revenues	2,748	2,094.10	1,662.70
Depreciation and amortization expense	149	136	131.8
Merger transaction costs	0
Gain on sale of UPPCO, net of transaction costs	0
Gain on abandonment of PDI's Winnebago Energy Center	0
Earnings from equity method investments	0	0	0
Miscellaneous income	1.9	1.2	0.6
Interest expense	54.4	50.2	47.3
Provision for income taxes	65.6	78.9	61.4
Net income (loss) from continuing operations	100.7	124	94
Discontinued operations	0	0	0
Preferred stock dividends of subsidiary	-0.5	-0.6	-0.6
Noncontrolling interest in subsidiaries	0	0	0
Net income attributed to common shareholders	100.2	123.4	93.4
Total assets	6,292.50	5,672	5,446.20
Cash expenditures for long-lived assets	456.5	370	375.1
Regulated operations | Natural Gas Utility | Intersegment revenues
Segment reporting information
Revenues	12.4	10.9	9.3
Regulated operations | Electric Utility
Segment reporting information
Revenues	1,286.30	1,332	1,297.40
Depreciation and amortization expense	103	98.6	89
Merger transaction costs	0
Gain on sale of UPPCO, net of transaction costs	-85.4
Gain on abandonment of PDI's Winnebago Energy Center	0
Earnings from equity method investments	0	0	0
Miscellaneous income	11.1	9.8	2.6
Interest expense	47.4	36.4	35.9
Provision for income taxes	103.3	67.3	49.4
Net income (loss) from continuing operations	166.3	113.4	110.4
Discontinued operations	0	0	0
Preferred stock dividends of subsidiary	-2.6	-2.5	-2.5
Noncontrolling interest in subsidiaries	0	0	0
Net income attributed to common shareholders	163.7	110.9	107.9
Total assets	3,506.90	3,514.40	3,041.30
Cash expenditures for long-lived assets	286.6	615	163.9
Regulated operations | Electric Utility | Intersegment revenues
Segment reporting information
Revenues	0.1	0.1	0
Regulated operations | Electric Transmission Investment
Segment reporting information
Revenues	0	0	0
Depreciation and amortization expense	0	0	0
Merger transaction costs	0
Gain on sale of UPPCO, net of transaction costs	0
Gain on abandonment of PDI's Winnebago Energy Center	0
Earnings from equity method investments	85.7	89.1	85.3
Miscellaneous income	0	0	0
Interest expense	0	0	0
Provision for income taxes	34.4	35.2	32.9
Net income (loss) from continuing operations	51.3	53.9	52.4
Discontinued operations	0	0	0
Preferred stock dividends of subsidiary	0	0	0
Noncontrolling interest in subsidiaries	0	0	0
Net income attributed to common shareholders	51.3	53.9	52.4
Total assets	536.7	508.5	476.6
Cash expenditures for long-lived assets	0	0	0
Regulated operations | Electric Transmission Investment | Intersegment revenues
Segment reporting information
Revenues	0	0	0
Nonutility and nonregulated operations | IES
Segment reporting information
Revenues	0	0	0
Depreciation and amortization expense	0	0	0
Merger transaction costs	0
Gain on sale of UPPCO, net of transaction costs	0
Gain on abandonment of PDI's Winnebago Energy Center	0
Earnings from equity method investments	0	0	0
Miscellaneous income	0	0	0
Interest expense	0	0	0
Provision for income taxes	0	0	0
Net income (loss) from continuing operations	0	0	0
Discontinued operations	0.4	82.5	55.1
Preferred stock dividends of subsidiary	0	0	0
Noncontrolling interest in subsidiaries	0	0	0
Net income attributed to common shareholders	0.4	82.5	55.1
Total assets	0	815.4	493.7
Cash expenditures for long-lived assets	0.9	2.6	2
Nonutility and nonregulated operations | IES | Intersegment revenues
Segment reporting information
Revenues	0	0	0
Nonutility and nonregulated operations | Holding Company and Other
Segment reporting information
Revenues	109.9	59.4	52.8
Depreciation and amortization expense	36	29.3	27
Merger transaction costs	10.4
Gain on sale of UPPCO, net of transaction costs	0
Gain on abandonment of PDI's Winnebago Energy Center	-5
Earnings from equity method investments	2.6	2.4	1.9
Miscellaneous income	29.8	23.3	19.9
Interest expense	64.8	53.2	49.8
Provision for income taxes	-9.9	-23.4	-25.8
Net income (loss) from continuing operations	-40.2	-23.8	-17.9
Discontinued operations	1.4	4.8	-9.7
Preferred stock dividends of subsidiary	0	0	0
Noncontrolling interest in subsidiaries	0.1	0.1	0.2
Net income attributed to common shareholders	-38.7	-18.9	-27.4
Total assets	1,638.10	1,519.70	1,523.30
Cash expenditures for long-lived assets	121	73.2	53.4
Nonutility and nonregulated operations | Holding Company and Other | Intersegment revenues
Segment reporting information
Revenues	1.4	1.4	1.9
Continuing operations
Segment reporting information
Number of reportable segments	4
Discontinued operations
Segment reporting information
Number of reportable segments	1
Depreciation and amortization expense	$2.70	$3.30	$5.30

QUARTERLY_FINANCIAL_INFORMATIO2

QUARTERLY FINANCIAL INFORMATION (Unaudited) (Details) (USD $)	12 Months Ended			3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013
Quarterly financial information
Operating revenues	$4,144.20	$3,485.50	$3,012.90
Operating income (loss)	507	439.5	379.5
Net income (loss) from continuing operations	278.1	267.5	238.9
Net income (loss)	279.9	354.8	284.3
Net income (loss) attributed to common shareholders	276.9	351.8	281.4
Earnings (loss) per common share (basic)
Net income (loss) from continuing operations (in dollars per share)	$3.43	$3.33	$3
Discontinued operations, net of tax (in dollars per share)	$0.02	$1.10	$0.58
Earnings per common share (basic) (in dollars per share)	$3.45	$4.43	$3.58
Earnings (loss) per common share (diluted)
Net income (loss) from continuing operations (in dollars per share)	$3.41	$3.30	$2.98
Discontinued operations, net of tax (in dollars per share)	$0.02	$1.09	$0.57
Earnings per common share (diluted) (in dollars per share)	$3.43	$4.39	$3.55
Amounts reflecting IES's retail energy business in discontinued operations
Quarterly financial information
Operating revenues	4,144.20	3,485.50		1,012.30	657.1	836.8	1,638	1,018.80	622.2	708.1	1,136.40
Operating income (loss)	507	439.5		116.9	134.6	23.2	232.3	130.1	41.5	56.1	211.8
Net income (loss) from continuing operations	278.1	267.5		53.8	75.3	8.8	140.2	74.2	26.9	36.8	129.6
Net income (loss)	279.9	354.8		34.8	84	8	153.1	132.4	38.8	-4.7	188.3
Net income (loss) attributed to common shareholders	276.9	351.8		34	83.3	7.2	152.4	131.6	38.1	-5.4	187.5
Earnings (loss) per common share (basic)
Net income (loss) from continuing operations (in dollars per share)	$3.43	$3.33		$0.66	$0.93	$0.10	$1.74	$0.91	$0.33	$0.45	$1.64
Discontinued operations, net of tax (in dollars per share)	$0.02	$1.10		($0.24)	$0.11	($0.01)	$0.16	$0.73	$0.15	($0.52)	$0.74
Earnings per common share (basic) (in dollars per share)	$3.45	$4.43		$0.42	$1.04	$0.09	$1.90	$1.64	$0.48	($0.07)	$2.38
Earnings (loss) per common share (diluted)
Net income (loss) from continuing operations (in dollars per share)	$3.41	$3.30		$0.66	$0.91	$0.10	$1.73	$0.91	$0.32	$0.45	$1.63
Discontinued operations, net of tax (in dollars per share)	$0.02	$1.09		($0.24)	$0.11	($0.01)	$0.16	$0.72	$0.15	($0.52)	$0.74
Earnings per common share (diluted) (in dollars per share)	$3.43	$4.39		$0.42	$1.02	$0.09	$1.89	$1.63	$0.47	($0.07)	$2.37
Previously reported amounts reflecting IES's retail energy business in continuing operations
Quarterly financial information
Operating revenues		5,634.60			1,187.90	1,432.60	2,924.90	1,710.70	1,129.70	1,116	1,678.20
Operating income (loss)		567.7			146.9	26.1	253.2	226.2	55.3	-6.9	293.1
Net income (loss) from continuing operations		350			82.9	8.1	153.2	132.3	39.4	-3.9	182.2
Net income (loss)		354.8			84	8	153.1	132.4	38.8	-4.7	188.3
Net income (loss) attributed to common shareholders		$351.80			$83.30	$7.20	$152.40	$131.60	$38.10	($5.40)	$187.50
Earnings (loss) per common share (basic)
Net income (loss) from continuing operations (in dollars per share)		$4.37			$1.03	$0.09	$1.90	$1.64	$0.49	($0.06)	$2.30
Discontinued operations, net of tax (in dollars per share)		$0.06			$0.01	$0	$0	$0	($0.01)	($0.01)	$0.08
Earnings per common share (basic) (in dollars per share)		$4.43			$1.04	$0.09	$1.90	$1.64	$0.48	($0.07)	$2.38
Earnings (loss) per common share (diluted)
Net income (loss) from continuing operations (in dollars per share)		$4.33			$1.01	$0.09	$1.89	$1.63	$0.48	($0.06)	$2.29
Discontinued operations, net of tax (in dollars per share)		$0.06			$0.01	$0	$0	$0	($0.01)	($0.01)	$0.08
Earnings per common share (diluted) (in dollars per share)		$4.39			$1.02	$0.09	$1.89	$1.63	$0.47	($0.07)	$2.37

SCHEDULE_I_CONDENSED_PARENT_CO1

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS STATEMENTS OF INCOME (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Merger transaction costs	$10.40	$0	$0
Gain on sale of UPPCO, net of transaction costs	85.4	0	0
Operating income (loss)	507	439.5	379.5
Equity earnings from subsidiaries	88.3	91.5	87.2
Miscellaneous income	31	21.9	9
Interest expense	154.8	127.4	118.9
Other income	-35.5	-14	-22.7
Income before taxes	471.5	425.5	356.8
Provision for income taxes	193.4	158	117.9
Net income from continuing operations	278.1	267.5	238.9
Net income attributed to common shareholders	276.9	351.8	281.4
Average shares of common stock
Basic (in shares)	80.2	79.5	78.6
Diluted (in shares)	80.7	80.1	79.3
Earnings per common share (basic)
Net income from continuing operations (in dollars per share)	$3.43	$3.33	$3
Discontinued operations, net of tax (in dollars per share)	$0.02	$1.10	$0.58
Earnings per common share (basic) (in dollars per share)	$3.45	$4.43	$3.58
Earnings per common share (diluted)
Net income from continuing operations (in dollars per share)	$3.41	$3.30	$2.98
Discontinued operations, net of tax (in dollars per share)	$0.02	$1.09	$0.57
Earnings per common share (diluted) (in dollars per share)	$3.43	$4.39	$3.55
Integrys Energy Group, Inc.
Condensed Financial Statements, Captions [Line Items]
Merger transaction costs	10.4	0	0
Operating expense	10.6	8.2	6
Gain on sale of UPPCO, net of transaction costs	-85.4	0	0
Operating income (loss)	64.4	-8.2	-6
Equity earnings from subsidiaries	303.8	314.6	277.3
Miscellaneous income	23.5	18.5	21.2
Interest expense	63.8	52.1	50
Other income	263.5	281	248.5
Income before taxes	327.9	272.8	242.5
Provision for income taxes	52.8	8.3	6.5
Net income from continuing operations	275.1	264.5	236
Discontinued operations from Parent Company, net of tax	-18.9	0.6	1.4
Discontinued operations from subsidiaries, net of tax	20.7	86.7	44
Net income attributed to common shareholders	$276.90	$351.80	$281.40
Average shares of common stock
Basic (in shares)	80.2	79.5	78.6
Diluted (in shares)	80.7	80.1	79.3
Earnings per common share (basic)
Net income from continuing operations (in dollars per share)	$3.43	$3.33	$3
Discontinued operations, net of tax (in dollars per share)	$0.02	$1.10	$0.58
Earnings per common share (basic) (in dollars per share)	$3.45	$4.43	$3.58
Earnings per common share (diluted)
Net income from continuing operations (in dollars per share)	$3.41	$3.30	$2.98
Discontinued operations, net of tax (in dollars per share)	$0.02	$1.09	$0.57
Earnings per common share (diluted) (in dollars per share)	$3.43	$4.39	$3.55

SCHEDULE_I_CONDENSED_PARENT_CO2

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS STATEMENTS OF COMPREHENSIVE INCOME (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Net income attributed to common shareholders	$276.90	$351.80	$281.40
Cash flow hedges
Unrealized net gains (losses) arising during period, net of tax of $ - million, $ - million, and $0.1 million, respectively	0	0.7	-0.2
Reclassification of net (gains) losses to net income, net of tax of $1.2 million, $2.0 million, and $(1.0) million, respectively	-0.1	1.4	6.5
Reclassification of net (gains) losses to net income, tax	1.2	3.6	2
Cash flow hedges, net	-0.1	2.1	6.3
Defined benefit plans
Pension and other postretirement benefit adjustments arising during period, net of tax of $(5.5) million, $ - million, and $(0.9) million, respectively	-6	13.2	-6.1
Pension and other postretirement benefit adjustments arising during period, tax	-3	8.9	-4.4
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $0.2 million, $0.9 million, and $0.4 million, respectively	1.7	2.4	1.4
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, tax	0.8	1.7	1
Defined benefit plans, net	-4.3	15.6	-4.7
Other comprehensive income (loss), net of tax	-4.4	17.7	1.6
Comprehensive income attributed to common shareholders	272.5	369.5	283
Integrys Energy Group, Inc.
Condensed Financial Statements, Captions [Line Items]
Net income attributed to common shareholders	276.9	351.8	281.4
Cash flow hedges
Unrealized net gains (losses) arising during period, net of tax of $ - million, $ - million, and $0.1 million, respectively	0	0.6	-0.1
Unrealized net gains (losses) arising during period, tax	0	0	0.1
Reclassification of net (gains) losses to net income, net of tax of $1.2 million, $2.0 million, and $(1.0) million, respectively	-0.1	-0.9	2.1
Reclassification of net (gains) losses to net income, tax	1.2	2	-1
Cash flow hedges, net	-0.1	-0.3	2
Defined benefit plans
Pension and other postretirement benefit adjustments arising during period, net of tax of $(5.5) million, $ - million, and $(0.9) million, respectively	-9.6	1.1	0.9
Pension and other postretirement benefit adjustments arising during period, tax	-5.5	0	-0.9
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $0.2 million, $0.9 million, and $0.4 million, respectively	0.3	-0.5	-0.1
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, tax	0.2	0.9	0.4
Defined benefit plans, net	-9.3	0.6	0.8
Other comprehensive income (loss) from subsidiaries, net of tax	5	17.4	-1.2
Other comprehensive income (loss), net of tax	-4.4	17.7	1.6
Comprehensive income attributed to common shareholders	$272.50	$369.50	$283

SCHEDULE_I_CONDENSED_PARENT_CO3

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS BALANCE SHEETS (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Assets
Cash and cash equivalents	$18	$16.80
Other current assets	57.5	55.9
Current assets	1,410.70	2,334.20
Total investments in subsidiaries, at equity	572.4	540.9
Property and equipment, net of accumulated depreciation of $1.2 and $1.4, respectively	6,859.80	6,206.20
Accumulated depreciation	3,343.10	3,221
Other long-term assets	270.1	145.4
Total assets	11,282	11,243.50	10,327.40
Liabilities and Equity
Short-term debt	317.6	326
Current portion of long-term debt	125	100
Accounts payable	490.7	401.9
Other current liabilities	261.4	218.9
Current liabilities	1,436.10	1,723.40
Long-term debt	2,956.30	2,956.20
Other long-term liabilities	168.7	127.1
Long-term liabilities	6,495.10	6,206.70
Total liabilities and equity	11,282	11,243.50
Integrys Energy Group, Inc.
Assets
Cash and cash equivalents	5.1	0.3	2.6	1.9
Accounts receivable from related parties	31.2	32.2
Interest receivable from related parties	4.8	4.1
Deferred income taxes	0.4	0.6
Notes receivable from related parties	51.6	84.9
Current portion of long-term notes receivable from related parties	2.5	10
Other current assets	49.1	47.8
Current assets	144.7	179.9
Total investments in subsidiaries, at equity	4,015.10	4,268.50
Notes receivable from related parties	180.9	224.3
Property and equipment, net of accumulated depreciation of $1.2 and $1.4, respectively	4.3	4.5
Accumulated depreciation	1.2	1.4
Receivables from related parties	19.2	18.3
Deferred income taxes	9.6	22.3
Other long-term assets	181.2	43.9
Total assets	4,555	4,761.70
Liabilities and Equity
Short-term notes payable to related parties	126.2	165.7
Short-term debt	7.2	123.2
Current portion of long-term debt	0	100
Accounts payable to related parties	5.8	0.9
Accounts payable	2.8	1.2
Deferred income taxes	6.2	6.4
Other current liabilities	43.2	2.8
Current liabilities	191.4	400.2
Long-term debt	974.7	974.7
Deferred income taxes	56.9	110.1
Other long-term liabilities	32.3	15.4
Long-term liabilities	1,063.90	1,100.20
Total common shareholders' equity	3,299.70	3,261.30
Total liabilities and equity	$4,555	$4,761.70

SCHEDULE_I_CONDENSED_PARENT_CO4

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS STATEMENTS OF CASH FLOWS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating activities
Net income attributed to common shareholders	$276.90	$351.80	$281.40
Adjustments to reconcile net income to net cash provided by operating activities
Dividends from subsidiaries	186.1
Deferred income taxes and investment tax credits	165.9	209.8	146
Gain on sale of other assets	-3.5	0	0
Other	43.5	34.9	25.3
Changes in working capital
Accounts receivable	11.2	-358.6	-26.2
Other current assets	-11.6	-50.4	6.6
Accounts payable	12.7	142.9	21.8
Other current liabilities	88.2	43.5	29.3
Net cash provided by operating activities	601.4	554.9	573.8
Investing activities
Net cash provided by (used for) investing activities	-336.5	-1,022.70	-602.6
Financing Activities
Commercial paper, net	-8.4	-156.4	179.1
Issuance of long-term debt	200	1,174	428
Repayment of long-term debt	-175	-363.5	-305.2
Proceeds from stock option exercises	85.8	38.7	55.8
Shares purchased for stock-based compensation	-142.9	-2	-89.9
Dividends paid on common stock	-216.3	-202.6	-211.9
Other	-9.3	-22.4	-24.7
Net cash (used for) provided by financing activities	-269.2	462.7	28.1
Cash and cash equivalents at beginning of year	16.8
Cash and cash equivalents at end of year	18	16.8
Supplemental cash flow information
Cash paid for interest	146.8	116.1	109.7
Cash paid (received) for income taxes	6.3	-4.8	-47.6
Integrys Energy Group, Inc.
Operating activities
Net income attributed to common shareholders	276.9	351.8	281.4
Adjustments to reconcile net income to net cash provided by operating activities
Equity earnings from subsidiaries	-324.5	-401.3	-321.3
Dividends from subsidiaries	176.5	169.6	163.9
Deferred income taxes and investment tax credits	-46	26.3	11
Gain on sale of other assets	-4	0	0
Other	4.9	2.8	-3.7
Changes in working capital
Accounts receivable	0.7	-0.7	0.4
Accounts receivable from related parties	0.5	0.6	1
Other current assets	12.5	-7.9	29
Accounts payable	1.6	0.6	-0.5
Accounts payable to related parties	2.6	-0.2	-0.4
Other current liabilities	27.6	-2.4	0.9
Net cash provided by operating activities	67.1	139.2	161.7
Investing activities
Short-term notes receivable from related parties	33.3	-50.4	-12.1
Issuance of long-term notes receivable to related parties	-20	-35	0
Repayment of long-term notes receivable from related parties	71.5	44.5	1.3
Equity contributions to subsidiaries	-218.4	-234.6	-89.9
Return of capital from subsidiaries	52.5	75	110.5
Proceeds from the sale of other assets	4.1	0	0
Rabbi trust funding related to potential change in control	-115.5	0	0
Net cash provided by (used for) investing activities	463.4	-200.5	9.8
Financing Activities
Commercial paper, net	-116	-85.2	115.8
Short-term notes payable to related parties	-45.1	-92.3	76.2
Repayment of long-term notes payable to related parties	0	0	-21
Issuance of long-term debt	0	400	0
Repayment of long-term debt	-100	0	-100
Proceeds from stock option exercises	85.8	38.7	55.8
Shares purchased for stock-based compensation	-127.6	0	-75.3
Issuance of common stock	2.4	19.2	0
Dividends paid on common stock	-216.3	-202.6	-211.9
Other	-8.9	-18.8	-10.4
Net cash (used for) provided by financing activities	-525.7	59	-170.8
Net change in cash and cash equivalents	4.8	-2.3	0.7
Cash and cash equivalents at beginning of year	0.3	2.6	1.9
Cash and cash equivalents at end of year	5.1	0.3	2.6
Supplemental cash flow information
Cash paid for interest	59.4	44.4	44.4
Cash paid for interest – related parties	0.4	0.7	1.4
Cash paid (received) for income taxes	40.2	-3	-24.1
Integrys Energy Group, Inc. | UPPCO
Adjustments to reconcile net income to net cash provided by operating activities
(Gain) loss on sale of business	-86.5	0	0
Investing activities
Proceeds from the sale of a business	336.7	0	0
Integrys Energy Group, Inc. | IES's retail energy business
Adjustments to reconcile net income to net cash provided by operating activities
(Gain) loss on sale of business	24.3	0	0
Investing activities
Proceeds from the sale of a business	$319.20	$0	$0

SCHEDULE_I_CONDENSED_PARENT_CO5

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2014
Cash and Cash Equivalents
Maximum maturity of short-term investments to classify as cash equivalents	3 months
Integrys Energy Group, Inc.
Cash and Cash Equivalents
Maximum maturity of short-term investments to classify as cash equivalents	3 months

SCHEDULE_I_CONDENSED_PARENT_CO6

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS CASH AND CASH EQUIVALENTS (Details) (Integrys Energy Group, Inc., USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Integrys Energy Group, Inc.
Other Significant Noncash Transactions [Line Items]
Equity issued for reinvested dividends	$0	$12	$0
Equity issued for stock-based compensation plans	$0	$16.30	$0

SCHEDULE_I_CONDENSED_PARENT_CO7

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS FAIR VALUE OF FINANCIAL INSTRUMENTS - RELATED PARTIES (Details) (Integrys Energy Group, Inc., USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Financial instruments not recorded at fair value
Long-term notes receivable from related parties	$180.90	$224.30
Current portion of long-term notes receivable from related parties	2.5	10
Carrying Amount
Financial instruments not recorded at fair value
Long-term notes receivable from related parties	180.9	224.3
Current portion of long-term notes receivable from related parties	2.5	10
Fair value
Financial instruments not recorded at fair value
Long-term notes receivable from related parties	195	238.5
Current portion of long-term notes receivable from related parties	$2.80	$10.20

SCHEDULE_I_CONDENSED_PARENT_CO8

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS SHORT-TERM NOTES RECEIVABLE - RELATED PARTIES (Details) (Integrys Energy Group, Inc., USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
SHORT-TERM NOTES RECEIVABLE - RELATED PARTIES
Short-term notes receivable from related parties	$51.60	$84.90
IES
SHORT-TERM NOTES RECEIVABLE - RELATED PARTIES
Short-term notes receivable from related parties	0	23.5
MGU
SHORT-TERM NOTES RECEIVABLE - RELATED PARTIES
Short-term notes receivable from related parties	26.1	21.8
MERC
SHORT-TERM NOTES RECEIVABLE - RELATED PARTIES
Short-term notes receivable from related parties	11.1	20.5
IBS
SHORT-TERM NOTES RECEIVABLE - RELATED PARTIES
Short-term notes receivable from related parties	14.4	10.2
UPPCO
SHORT-TERM NOTES RECEIVABLE - RELATED PARTIES
Short-term notes receivable from related parties	$0	$8.90

SCHEDULE_I_CONDENSED_PARENT_CO9

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS LONG-TERM NOTES RECEIVABLE - RELATED PARTIES (Details) (Integrys Energy Group, Inc., USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES
Total notes receivable from related parties	$183.40	$234.30
Less current portion	2.5	10
Long-term notes receivable from related parties	180.9	224.3
WPS Leasing | Notes Receivable 8.76 Percent Due 2015
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES
Interest rate stated percentage	8.76%
Total notes receivable from related parties	2	2.4
WPS Leasing | Notes Receivable 7.35 Percent Due 2016
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES
Interest rate stated percentage	7.35%
Total notes receivable from related parties	3.4	3.9
UPPCO | Notes Receivable 6.059 Percent Due 2017
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES
Interest rate stated percentage	6.06%
Total notes receivable from related parties	0	15
UPPCO | Notes Receivable 3.35 Percent Due 2018
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES
Interest rate stated percentage	3.35%
Total notes receivable from related parties	0	10
UPPCO | Notes Receivable 5.041 Percent Due 2020
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES
Interest rate stated percentage	5.04%
Total notes receivable from related parties	0	15
UPPCO | Notes Receivable 3.99 Percent Due 2023
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES
Interest rate stated percentage	3.99%
Total notes receivable from related parties	0	20
MERC | Notes Receivable 3.99 Percent Due 2023
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES
Interest rate stated percentage	3.99%
Total notes receivable from related parties	29	29
MERC | Notes Receivable 6.16 Percent Due 2016
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES
Interest rate stated percentage	6.16%
Total notes receivable from related parties	29	29
MERC | Notes Receivable 6.40 Percent Due 2021
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES
Interest rate stated percentage	6.40%
Total notes receivable from related parties	29	29
MERC | Notes Receivable 3.57 Percent Due 2024
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES
Interest rate stated percentage	3.57%
Total notes receivable from related parties	20	0
MGU | Notes Receivable 5.76 Percent Due 2016
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES
Interest rate stated percentage	5.76%
Total notes receivable from related parties	28	28
MGU | Notes Receivable 5.98 Percent Due 2021
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES
Interest rate stated percentage	5.98%
Total notes receivable from related parties	28	28
MGU | Notes Receivable 3.00 Percent Due 2023
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES
Interest rate stated percentage	3.00%
Total notes receivable from related parties	15	15
IBS | Notes Receivable 6.865 Percent Due 2014
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES
Interest rate stated percentage	6.87%
Total notes receivable from related parties	$0	$10

Recovered_Sheet5

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS SHORT-TERM NOTES PAYABLE - RELATED PARTIES (Details) (Integrys Energy Group, Inc., USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
SHORT-TERM NOTES PAYABLE - RELATED PARTIES
Short-term notes payable to related parties	$126.20	$165.70
PELLC
SHORT-TERM NOTES PAYABLE - RELATED PARTIES
Short-term notes payable to related parties	43.5	165.7
ITF
SHORT-TERM NOTES PAYABLE - RELATED PARTIES
Short-term notes payable to related parties	8.6	0
PDI
SHORT-TERM NOTES PAYABLE - RELATED PARTIES
Short-term notes payable to related parties	$74.10	$0

SCHEDULE_II_VALUATION_AND_QUAL1

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Allowance for doubtful accounts
Balance at beginning of year	$47.70	$41.10	$42.50
Charged to expense	50.3	33.7	25.9
Charged to other accounts	8	5.5	4
Deductions	-42.7	-32.6	-31.3
Balance at end of year	$63.30	$47.70	$41.10