Integrys Holding (TEG) 10-K 27 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 25, 2014	Jun. 28, 2013
Document and Entity Information	'	'	'
Entity Registrant Name	'INTEGRYS ENERGY GROUP, INC.	'	'
Entity Central Index Key	'0000916863	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Public Float	'	'	$4,623,528,068
Entity Common Stock, Shares Outstanding	'	79,963,091	'
Document Fiscal Year Focus	'2013	'	'
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, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]	'	'	'
Utility revenues	$3,425.60	$2,959.50	$3,294.50
Nonregulated revenues	2,209	1,252.90	1,391.40
Total revenues	5,634.60	4,212.40	4,685.90
Utility cost of fuel, natural gas, and purchased power	1,570.40	1,326.30	1,635.30
Nonregulated cost of sales	1,937.20	1,040.20	1,274.20
Operating and maintenance expense	1,192.30	1,031.30	1,024.80
Depreciation and amortization expense	266.6	250.7	247.7
Taxes other than income taxes	100.4	96.4	97.1
Operating income	567.7	467.5	406.8
Earnings from equity method investments	91.5	87.2	79.4
Miscellaneous income	29.8	9.3	5.3
Interest expense	128.2	120.2	128.2
Other expense	-6.9	-23.7	-43.5
Income before taxes	560.8	443.8	363.3
Provision for income taxes	210.8	149.8	133.3
Net income from continuing operations	350	294	230
Discontinued operations, net of tax	4.8	-9.7	0.5
Net income	354.8	284.3	230.5
Preferred stock dividends of subsidiary	-3.1	-3.1	-3.1
Noncontrolling interest in subsidiaries	0.1	0.2	0
Net income attributed to common shareholders	$351.80	$281.40	$227.40
Average shares of common stock	'	'	'
Basic (in shares)	79.5	78.6	78.6
Diluted (in shares)	80.1	79.3	79.1
Earnings (loss) per common share (basic)	'	'	'
Net income from continuing operations (in dollars per share)	$4.37	$3.70	$2.89
Discontinued operations, net of tax (in dollars per share)	$0.06	($0.12)	$0
Earnings per common share (basic) (in dollars per share)	$4.43	$3.58	$2.89
Earnings (loss) per common share (diluted)	'	'	'
Net income from continuing operations (in dollars per share)	$4.33	$3.67	$2.87
Discontinued operations, net of tax (in dollars per share)	$0.06	($0.12)	$0
Earnings per common share (diluted) (in dollars per share)	$4.39	$3.55	$2.87

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Other Comprehensive Income [Abstract]	'	'	'
Net income	$354.80	$284.30	$230.50
Cash flow hedges	'	'	'
Unrealized net gains (losses) arising during period, net of tax of $0.1 million, $(0.1) million, and $0.4 million, respectively	0.7	-0.2	1.5
Reclassification of net losses to net income, net of tax of $3.6 million, $2.0 million, and $4.4 million, respectively	1.4	6.5	7.4
Cash flow hedges, net	2.1	6.3	8.9
Defined benefit plans	'	'	'
Pension and other postretirement benefit adjustments arising during period, net of tax of $8.9 million, $(4.4) million, and $(5.7) million, respectively	13.2	-6.1	-7.5
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $1.7 million, $1.0 million, and $0.6 million, respectively	2.4	1.4	0.8
Defined benefit plans, net	15.6	-4.7	-6.7
Other comprehensive income, net of tax	17.7	1.6	2.2
Comprehensive income	372.5	285.9	232.7
Preferred stock dividends of subsidiary	-3.1	-3.1	-3.1
Noncontrolling interest in subsidiaries	0.1	0.2	0
Comprehensive income attributed to common shareholders	$369.50	$283	$229.60

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Other Comprehensive Income [Abstract]	'	'	'
Unrealized net gains (losses) arising during period, tax	$0.10	($0.10)	$0.40
Reclassification of net losses to net income, tax	3.6	2	4.4
Pension and other postretirement benefit adjustments arising during period, tax	8.9	-4.4	-5.7
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, tax	$1.70	$1	$0.60

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Assets	'	'
Cash and cash equivalents	$22.30	$27.40
Collateral on deposit	38.7	41
Accounts receivable and accrued unbilled revenues, net of reserves of $49.8 and $43.5, respectively	1,052.10	796.8
Inventories	254.8	271.9
Assets from risk management activities	240.1	145.4
Regulatory assets	129.4	110.8
Assets held for sale	0.7	10.1
Deferred income taxes	31.4	64.3
Prepaid taxes	146.9	152.8
Other current assets	55.8	38.6
Current assets	1,972.20	1,659.10
Property, plant, and equipment, net of accumulated depreciation of $3,325.8 and $3,114.7, respectively	6,410.50	5,501.90
Regulatory assets	1,412.60	1,813.80
Assets from risk management activities	75.4	45.3
Equity method investments	540.9	512.2
Goodwill	662.1	658.3
Other long-term assets	169.8	136.8
Total assets	11,243.50	10,327.40
Liabilities and Equity	'	'
Short-term debt	326	482.4
Current portion of long-term debt	100	313.5
Accounts payable	613.2	457.7
Liabilities from risk management activities	163.8	181.9
Accrued taxes	86.3	83
Regulatory liabilities	101.5	65.6
Liabilities held for sale	0	0.2
Other current liabilities	231.3	229
Current liabilities	1,622.10	1,813.30
Long-term debt	2,956.20	1,931.70
Deferred income taxes	1,390.30	1,203.80
Deferred investment tax credits	57.6	49.3
Regulatory liabilities	400.9	370.5
Environmental remediation liabilities	600.8	651.5
Pension and other postretirement benefit obligations	211	625.2
Liabilities from risk management activities	62.8	58.4
Asset retirement obligations	491.5	411.2
Other long-term liabilities	136.9	135.7
Long-term liabilities	6,308	5,437.30
Commitments and contingencies	'	'
Common stock – $1 par value; 200,000,000 shares authorized; 79,919,176 shares issued; 79,445,380 shares outstanding	79.9	78.3
Additional paid-in capital	2,660.50	2,574.60
Retained earnings	567.1	431.5
Accumulated other comprehensive loss	-23.2	-40.9
Shares in deferred compensation trust	-23	-17.7
Total common shareholders’ equity	3,261.30	3,025.80
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	1	-0.1
Total liabilities and equity	$11,243.50	$10,327.40

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]	'	'
Accounts receivable and accrued unbilled revenues, reserves (in dollars)	$49.80	$43.50
Accumulated depreciation	$3,325.80	$3,114.70
Common stock, par value (in dollars per share)	$1	'
Common stock, shares authorized	200,000,000	'
Common stock, shares issued	79,919,176	78,287,906
Common stock, shares outstanding	79,445,380	77,902,467
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, 2010	$2,957	$2,905.80	($18.50)	$77.80	$2,540.40	$350.80	($44.70)	$51.10	$0.10
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'	'
Net income attributed to common shareholders	227.4	227.4	0	0	0	227.4	0	0	0
Other comprehensive income	2.2	2.2	0	0	0	0	2.2	0	0
Issuance of common stock	22.2	22.2	0	0.5	21.7	0	0	0	0
Stock-based compensation	5.4	5.4	0	0	7.5	-2.1	0	0	0
Dividends on common stock (dividends per common share of $2.72)	-211.8	-211.8	0	0	0	-211.8	0	0	0
Shares issued to and purchased for the deferred compensation trust	-1	-1	-3.3	'	2.3	'	'	'	'
Other	11.2	11.2	4.7	0	7.2	-0.7	0	0	0
Balance at Dec. 31, 2011	3,012.60	2,961.40	-17.1	78.3	2,579.10	363.6	-42.5	51.1	0.1
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	1.6	1.6	0	0	0	0	1.6	0	0
Issuance of common stock	0	0	0	0	0	0	0	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	'	'	'	'	'	'
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	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)	$79.90	$2,660.50	$567.10	($23.20)	$51.10	$1

CONSOLIDATED_STATEMENTS_OF_EQU1

CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Stockholders' Equity [Abstract]	'	'	'
Dividends per common share declared (in dollars per share)	$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, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating activities	'	'	'
Net income	$354.80	$284.30	$230.50
Adjustments to reconcile net income to net cash provided by operating activities	'	'	'
Discontinued operations, net of tax	-4.8	9.7	-0.5
Depreciation and amortization expense	266.6	250.7	247.7
Recoveries and refunds of regulatory assets and liabilities	44.3	49.9	56.1
Net unrealized (gains) losses on energy contracts	-102.2	-40.3	45.2
Bad debt expense	34.4	26.2	35
Pension and other postretirement expense	62.1	62.1	59.9
Pension and other postretirement contributions	-77	-287.5	-131.5
Deferred income taxes and investment tax credits	198.5	148.2	174.1
Equity income, net of dividends	-19.2	-17.5	-14.8
Termination of tolling agreement with Fox Energy Company LLC	-50	0	0
Other	41	20.1	45.9
Changes in working capital	'	'	'
Collateral on deposit	2.3	9.6	-17.3
Accounts receivable and accrued unbilled revenues	-358.8	-26.2	93.4
Inventories	16.8	28.5	-37.1
Other current assets	-42	6.1	55.3
Accounts payable	143.1	22	-37.3
Other current liabilities	45.1	23.1	-86.8
Net cash provided by operating activities	555	569	717.8
Investing activities	'	'	'
Capital expenditures	-669.2	-594.3	-310.1
Capital contributions to equity method investments	-13.7	-27.4	-37.6
Acquisition of Fox Energy Company LLC	-391.6	0	0
Acquisitions at Integrys Energy Services	-15.7	0	0
Grant received related to Crane Creek wind project	69	0	0
Acquisition of compressed natural gas fueling companies, net of cash acquired	0	1.3	-42.6
Other	-3.1	15.4	-3.2
Net cash used for investing activities	-1,024.30	-605	-393.5
Financing activities	'	'	'
Short-term debt, net	-156.4	179.1	303.3
Repayment of notes payable	0	0	-10
Borrowing on term credit facility	200	0	0
Repayment of term credit facility	-200	0	0
Issuance of long-term debt	1,174	428	50
Repayment of long-term debt	-363.5	-278.2	-565.8
Proceeds from stock option exercises	38.7	55.8	10.3
Shares purchased for stock-based compensation	-2	-89.9	-17
Payment of dividends	'	'	'
Preferred stock of subsidiary	-3.1	-3.1	-3.1
Common stock	-202.6	-211.9	-206.4
Payments made on derivative contracts related to divestitures classified as financing activities	-5.8	-23.7	-31.9
Other	-16.6	-1	-7.5
Net cash provided by (used for) financing activities	462.7	55.1	-478.1
Change in cash and cash equivalents - continuing operations	-6.6	19.1	-153.8
Change in cash and cash equivalents - discontinued operations	'	'	'
Net cash (used for) provided by operating activities	-0.1	4.8	4.1
Net cash provided by (used for) investing activities	1.6	2.4	-0.9
Net cash used for financing activities	0	-27	-0.3
Net change in cash and cash equivalents	-5.1	-0.7	-150.9
Cash and cash equivalents at beginning of year	27.4	28.1	179
Cash and cash equivalents at end of year	22.3	27.4	28.1
Supplemental cash flow information	'	'	'
Cash paid for interest	116.1	109.7	130.7
Cash received for income taxes	($4.80)	($47.60)	($80)

SUMMARY_OF_SIGNIFICANT_ACCOUNT

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	Summary of Significant Accounting Policies
	(a) Nature of Operations—We are a holding company whose primary wholly owned subsidiaries at December 31, 2013, included MERC, MGU, NSG, PGL, UPPCO, WPS, IBS, Integrys Energy Services, and ITF. Of these subsidiaries, six are regulated natural gas and/or electric utilities (MERC, MGU, NSG, PGL, UPPCO, and WPS). IBS is a centralized service company, Integrys Energy Services is a nonregulated retail energy supply and services company, and ITF is a nonregulated compressed natural gas fueling business. In addition, we have an approximate 34% interest in ATC.
	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 term "utility" refers to the regulated activities of the electric and natural gas utility companies, while the term "nonutility" refers to the activities of the electric and natural gas utility companies that are not regulated. The term "nonregulated" refers to activities at Integrys Energy Services, ITF, the Integrys Energy Group holding company, and the PELLC holding company.
	(b) Consolidated Basis of Presentation—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 8, Equity Method Investments, for more information.
	(c) 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.
	(d) Cash and Cash Equivalents—Short-term investments with an original maturity of three months or less are reported as cash equivalents.
	Significant noncash transactions were:
	(Millions)		2013			2012				2011
	Construction costs funded through accounts payable		$	108.5		$	92.4			$	58.6
	Portion of Westwood sale financed with note receivable (1)		—			4				—
	Equity issued for stock-based compensation plans		16.3			—				10.6
	Equity issued for employee stock ownership plan		14.3			—				5.2
	Equity issued for reinvested dividends		12			—				5.4
	Contingent consideration related to the acquisition of Compass Energy Services (2)		7.8			—				—
	(1)	See Note 4, Discontinued Operations, for more information.
	-2	See Note 3, Acquisitions, for more information on the contingent consideration.
	(e) Revenue 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, 2013 and 2012, our unbilled revenues were $438.2 million and $298.2 million, respectively.
	At December 31, 2013, there were no customers or industries that accounted for more than 10% of our revenues.
	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 2013 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.
	•	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, NSG, and MGU included riders for cost recovery or refund of bad debts based on the difference between actual bad debt write-offs (as defined in the latest rate order) and the amount recovered in rates. MGU's rider was terminated after December 31, 2013.
	•	The rates of all of our utilities included decoupling mechanisms. These mechanisms differ state by state and allow utilities to recover or refund differences between the applicable actual and authorized margins. See Note 26, Regulatory Environment, for more information on decoupling.
	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 and UPPCO both sell and purchase power in the MISO market. If WPS or UPPCO is a net seller in a particular hour, the net amount is reported as revenue. If WPS or UPPCO is a net purchaser in a particular hour, the net amount is 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.
	See Note 1(g), Risk Management Activities, for more information on the classification of certain unrealized gains and losses on derivative instruments in revenues.
	(f) 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 regulated 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 26% of total inventories at December 31, 2013, and 30% of total inventories at December 31, 2012. The estimated replacement cost of natural gas in inventory at December 31, 2013, and December 31, 2012, exceeded the LIFO cost by $151.7 million and $95.3 million, respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per dekatherm of $4.77 at December 31, 2013, and $3.58 at December 31, 2012.
	Inventories at Integrys Energy Services are valued at the lower of cost or market. As a result, Integrys Energy Services recorded net write-downs of $3.6 million, $3.4 million, and $11.6 million in 2013, 2012, and 2011, respectively.
	(g) 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 2, 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 unless the derivative contracts contain an other-than-insignificant financing element, in which case the cash flows are classified within financing activities.
	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 shown separately as collateral on deposit, and cash collateral received from others is reflected in other current liabilities.
	(h) Emission Allowances—Integrys Energy Services accounts for emission allowances as intangible assets, with cash inflows and outflows related to purchases and sales of emission allowances recorded as investing activities in the statements of cash flows. 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.
	(i) 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, repair, replacement, and renewal costs associated with items not qualifying as units of property are considered 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		2013		2012			2011
	MERC (1)		1.88	%	3.07	%		3.1	%
	MGU (2)		1.93	%	2.71	%		2.73	%
	NSG		2.44	%	2.43	%		2.42	%
	PGL		3.19	%	3.16	%		3.18	%
	UPPCO		3.29	%	3.31	%		3.33	%
	WPS – Electric		2.79	%	2.87	%		2.88	%
	WPS – Natural gas		2.19	%	2.21	%		2.22	%
	-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, repair, 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 5, Property, Plant, and Equipment, for more information.
	(j) 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 2013, WPS's average AFUDC retail rate was 8.61%, and its average AFUDC wholesale rate was 2.64%. 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 2013, 2012, or 2011.
	Total AFUDC was as follows for the years ended December 31:
			2013			2012				2011
	Allowance for equity funds used during construction		$	10.8		$	2.9			$	0.7
	Allowance for borrowed funds used during construction		4.1			1				0.3
	Our nonregulated subsidiaries capitalize interest for construction projects. However, the nonregulated subsidiaries did not capitalize significant interest during 2013, 2012, and 2011.
	(k) 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 7, Regulatory Assets and Liabilities, for more information.
	(l) Investments in Exchange-Traded Funds—We have investments in exchange-traded funds which are classified as trading securities for accounting purposes. These investments are used to offset gains and losses related to our deferred compensation obligations. As we do not intend to sell these investments in the near term, they are included in other long-term assets on our balance sheets. The net unrealized gains (losses) included in earnings related to the investments still held at the end of the period were $1.9 million, $1.0 million, and $(0.1) million for the years ended December 31, 2013, 2012, and 2011, respectively.
(m) Asset Impairment—Goodwill and other intangible assets with indefinite lives are not amortized, but 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 9, 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.
Integrys Energy Services evaluates emission allowances for impairment by comparing the expected undiscounted future cash flows to the carrying amount. When allowances are expected to be used for generation, the allowances are grouped with the related power plant in the impairment evaluation.
(n) 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.
(o) 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 13, Asset Retirement Obligations, for more information.
(p) 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 15, 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 possible 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 regulated 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 to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.
(q) 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 regulated 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 14, Income Taxes, for more information regarding accounting for income taxes.
(r) Guarantees—Integrys Energy Group follows the guidance of the of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. See Note 16, Guarantees, for more information.
(s) 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. 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 regulated 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 segments record changes in the funded status in accumulated other comprehensive income. The regulated 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 17, Employee Benefit Plans, for more information.
(t) Stock-Based Compensation—In May 2010, our shareholders approved the 2010 Omnibus Incentive Compensation Plan (2010 Omnibus Plan). Under the provisions of the 2010 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 remaining or forfeited under prior plans. No more than 900,000 shares of stock, plus shares remaining or forfeited under prior plans, can be granted as full value shares in the form of performance shares, restricted stock, or restricted stock units. 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, 2013, stock options, performance stock rights, and restricted share units were outstanding under the various 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. Generally, 25% of the stock options granted vest and become exercisable each year on the anniversary of the grant date. For accounting purposes, stock options granted to retirement-eligible employees vest over a shorter period; however, there is no acceleration of when the options become exercisable. Under the provisions of the 2010 Omnibus Plan, no single employee who is our chief executive officer or 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 during any calendar year.
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. No single employee who is our chief executive officer or one of our other three highest compensated officers (including officers of our subsidiaries) can receive a payout in excess of 250,000 performance shares during any calendar year. 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 Shares and Restricted Share Units
Restricted shares and 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. During 2011, the last of the outstanding restricted shares vested. Only restricted share units remain outstanding at December 31, 2013. 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. Prior to January 1, 2013, under the terms of the agreement, these awards vested immediately, and therefore were expensed on the grant date. Beginning in 2013, these awards generally vest over one year. Therefore, the expense for these awards is recognized pro-rata over the year in which the grant occurs.
(u) 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, 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.
(v) 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. These assumptions include the risks inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model.
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.
We primarily determine fair value using a market-based approach that uses observable market inputs where available, and internally developed inputs only when observable market data is not readily available. For the unobservable inputs, consideration is given to the assumptions that market participants would use in valuing the asset or liability. These factors include not only the credit standing of the counterparties involved, but also the impact of our nonperformance risk on our liabilities.
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 include inputs related to market price risk (commodity or interest rate), price volatility (for option contracts), and price correlation (for cross commodity contracts). These inputs are available through multiple sources, including exchanges and brokers. 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:
•	While forward price curves may have been based on observable information, significant assumptions may have been made regarding monthly shaping and locational basis differentials.
•	Certain transactions were valued using price curves that extended beyond an observable period. Assumptions were made to extrapolate prices from the last observable period through the end of the transaction term, primarily through the use of historically settled data or correlations to other 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 trading 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 the levels of the fair value hierarchy primarily due to changes in the source of data used to construct price curves as a result of changes in market liquidity. 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 23, Fair Value, for more information.
(w) Advertising Costs—We expense all advertising costs as incurred, except for those capitalized as direct-response advertising. Costs associated with certain natural gas and electric direct-response advertising campaigns at Integrys Energy Services were capitalized and reported as other long-term assets on the balance sheets. The capitalized costs result in probable future benefits and were incurred to solicit sales to customers who could be shown to have responded specifically to the advertising. The asset balances for each of the direct-response advertising cost pools are reviewed quarterly for impairment. Direct-response advertising costs are amortized to operating and maintenance expense over the estimated period of benefit, which is approximately two years.
(x) New Accounting Pronouncements—
Recently Issued Accounting Guidance Not Yet Effective
Accounting Standards Update (ASU) 2013-04, "Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date," was issued in February 2013. The guidance requires an entity to measure obligations under these arrangements, for which the total amount of the obligation is fixed at the reporting date, as the sum of the reporting entity's portion and any additional amount it expects to pay on behalf of its co-obligors. The guidance also requires additional disclosures about the nature and amount of the obligations. The guidance is effective for us for the reporting period ending March 31, 2014. Adoption of this guidance is not expected to have a significant impact on our financial statements.
ASU 2013-11, "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists," was issued in July 2013. The guidance states that an unrecognized tax benefit should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. However, there are certain exceptions under which the unrecognized tax benefit would be presented in the balance sheet as a liability. The guidance is effective for us for the reporting period ending March 31, 2014. Adoption of this guidance is not expected to have a significant impact on our financial statements.
ASU 2014-01, "Accounting for Investments in Qualified Affordable Housing Projects," was issued in January 2014. 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. Adoption of this guidance is not expected to have a significant impact on our financial statements.

RISK_MANAGEMENT_ACTIVITIES

RISK MANAGEMENT ACTIVITIES	12 Months Ended
	Dec. 31, 2013
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:
					31-Dec-13
	(Millions)		Balance Sheet Presentation		Assets from				Liabilities from
					Risk Management Activities				Risk Management Activities
	Utility Segments
	Nonhedge derivatives
	Natural gas contracts		Current		$	8.3			$	1
	Natural gas contracts		Long-term		1.8				0.1
	Financial transmission rights (FTRs)		Current		2.1				0.3
	Petroleum product contracts		Current		0.1				—
	Coal contracts		Current		—				1.9
	Coal contracts		Long-term		0.2				0.8
	Nonregulated Segments
	Nonhedge derivatives
	Natural gas contracts		Current		57.6				42.9
	Natural gas contracts		Long-term		29.5				18.6
	Electric contracts		Current		172				117.7
	Electric contracts		Long-term		43.9				43.3
			Current		240.1				163.8
			Long-term		75.4				62.8
	Total				$	315.5			$	226.6
					December 31, 2012
	(Millions)		Balance Sheet Presentation		Assets from				Liabilities from
					Risk Management Activities				Risk Management Activities
	Utility Segments
	Nonhedge derivatives
	Natural gas contracts		Current		$	2.5			$	14
	Natural gas contracts		Long-term		0.9				0.8
	FTRs		Current		2.1				0.1
	Petroleum product contracts		Current		0.2				—
	Coal contracts		Current		0.3				4.7
	Coal contracts		Long-term		2.2				4.3
	Cash flow hedges
	Natural gas contracts		Current		—				0.4
	Nonregulated Segments
	Nonhedge derivatives
	Natural gas contracts		Current		51.7				48.5
	Natural gas contracts		Long-term		11.5				7.6
	Electric contracts		Current		88.6				114.2
	Electric contracts		Long-term		30.7				45.7
			Current		145.4				181.9
			Long-term		45.3				58.4
	Total				$	190.7			$	240.3
	The following tables show the potential effect on our financial position of netting arrangements for recognized derivative assets and liabilities:
			31-Dec-13
	(Millions)		Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
	Derivative assets subject to master netting or similar arrangements
	Utility segments		$	12.3			$	2.1			$	10.2
	Nonregulated segments		301.9				178.1				123.8
	Total		314.2				180.2				134
	Derivative assets not subject to master netting or similar arrangements		1.3								1.3
	Total risk management assets		$	315.5							$	135.3
	Derivative liabilities subject to master netting or similar arrangements
	Utility segments		$	1.4			$	1.4			$	—
	Nonregulated segments		222.1				178.1				44
	Total		223.5				179.5				44
	Derivative liabilities not subject to master netting or similar arrangements		3.1								3.1
	Total risk management liabilities		$	226.6							$	47.1
			31-Dec-12
	(Millions)		Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
	Derivative assets subject to master netting or similar arrangements
	Utility segments		$	5.7			$	3			$	2.7
Nonregulated segments		182.5				145.4				37.1
Total		188.2				148.4				39.8
Derivative assets not subject to master netting or similar arrangements		2.5								2.5
Total risk management assets		$	190.7							$	42.3
Derivative liabilities subject to master netting or similar arrangements
Utility segments		$	15.3			$	3.8			$	11.5
Nonregulated segments		215.4				159.8				55.6
Total		230.7				163.6				67.1
Derivative liabilities not subject to master netting or similar arrangements		9.6								9.6
Total risk management liabilities		$	240.3							$	76.7
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-13				December 31, 2012
Cash collateral provided to others:
Related to contracts under master netting or similar arrangements		$	37.6			$	39.9
Other		1.1				1.1
Cash collateral received from others related to contracts under master netting or similar arrangements		0.7				0.2
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 following table shows the aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a liability position:
(Millions)		31-Dec-13				December 31, 2012
Utility segments		$	0.6			$	14
Nonregulated segments		76.7				108.9
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, our collateral requirement would have been as follows:
(Millions)		31-Dec-13				December 31, 2012
Collateral that would have been required:
Utility segments		$	—			$	10.1
Nonregulated segments		197.6				173.8
Collateral already satisfied:
Nonregulated segments — Letters of credit		4.5				3.2
Collateral remaining:
Utility segments		—				10.1
Nonregulated segments		193.1				170.6
Utility Segments
Non-Hedge Derivatives
Utility derivatives include natural gas purchase contracts, coal purchase contracts, financial derivative contracts (futures, options, and swaps), and FTRs used to manage electric transmission congestion costs. The electric and natural gas utility segments use futures, options, and swaps to manage the risks associated with the market price volatility of natural gas supply costs, and the costs of gasoline and diesel fuel used by utility vehicles. The electric utility segment also uses oil futures and options to manage price risk related to coal transportation.
The utilities had the following notional volumes of outstanding derivative contracts:
		31-Dec-13									December 31, 2012
(Millions, except barrels)		Purchases			Sales			Other Transactions			Purchases			Sales	Other Transactions
Natural gas (therms)		3,124.80			29.3			N/A			1,072.60			0.1	N/A
FTRs (kilowatt-hours)		N/A			N/A			3,633.10			N/A			N/A	4,057.20
Petroleum products (barrels)		102,811.00			14,000.00			N/A			62,811.00			—	N/A
Coal (tons)		4.8			—			N/A			5.1			—	N/A
The table below shows the unrealized gains (losses) recorded related to derivative contracts at the utilities:
(Millions)		Financial Statement Presentation		2013				2012				2011
Natural gas		Balance Sheet — Regulatory assets (current)		$	13.4			$	24.6			$	(11.3	)
Natural gas		Balance Sheet — Regulatory assets (long-term)		2.3				8.3				(7.6		)
Natural gas		Balance Sheet — Regulatory liabilities (current)		4.6				(7.8		)		8.4
Natural gas		Balance Sheet — Regulatory liabilities (long-term)		0.3				0.3				—
Natural gas		Income Statement — Utility cost of fuel, natural gas, and purchased power		—				0.2				—
Natural gas		Income Statement — Operating and maintenance expense		0.1				—				—
FTRs		Balance Sheet — Regulatory assets (current)		0.1				0.1				(0.4		)
FTRs		Balance Sheet — Regulatory liabilities (current)		(0.4		)		0.1				(1.3		)
Petroleum		Balance Sheet — Regulatory assets (current)		—				0.1				(0.1		)
Petroleum		Balance Sheet — Regulatory liabilities (current)		0.1				—				—
Petroleum		Income Statement — Operating and maintenance expense		0.1				—				(0.1		)
Coal		Balance Sheet — Regulatory assets (current)		(0.9		)		(2.2		)		(1.3		)
Coal		Balance Sheet — Regulatory assets (long-term)		3.5				0.1				(4.4		)
Coal		Balance Sheet — Regulatory liabilities (current)		(0.2		)		0.3				—
Coal		Balance Sheet — Regulatory liabilities (long-term)		(2.0		)		2.2				(3.7		)
Nonregulated Segments
Nonhedge Derivatives
Integrys Energy Services enters into derivative contracts such as futures, forwards, options, and swaps that are used to manage commodity price risk primarily associated with retail electric and natural gas customer contracts.
Integrys Energy Services had the following notional volumes of outstanding derivative contracts:
		31-Dec-13						December 31, 2012
(Millions)		Purchases			Sales			Purchases			Sales
Commodity
Natural gas (therms)		1,199.90			1,065.40			782			679
Electric (kilowatt-hours)		49,186.30			30,813.80			54,127.60			31,809.60
Foreign exchange (Canadian dollars)		—			—			0.4			0.4
Gains (losses) related to derivative contracts are recognized currently in earnings, as shown in the table below:
(Millions)		Income Statement Presentation		2013				2012				2011
Natural gas		Nonregulated revenue		$	36.7			$	6.8			$	14
Natural gas		Nonregulated cost of sales		(27.6		)		—				—
Natural gas		Nonregulated revenue (reclassified from accumulated OCI) *		(0.3		)		(2.0		)		(2.3		)
Electric		Nonregulated revenue		73.6				(2.0		)		(79.0		)
Electric		Nonregulated cost of sales		10.8				—				—
Electric		Nonregulated revenue (reclassified from accumulated OCI) *		(3.4		)		(4.3		)		(1.7		)
Total				$	89.8			$	(1.5	)		$	(69.0	)
*	Represents amounts reclassified from accumulated other comprehensive loss (OCI) related to cash flow hedges that were dedesignated in prior periods.
In the next 12 months, insignificant gains related to discontinued cash flow hedges of electric contracts are expected to be recognized in earnings as the forecasted transactions occur. These amounts are expected to be offset by the settlement of the related nonderivative customer contracts.
Cash Flow Hedges
Prior to July 1, 2011, Integrys Energy Services designated derivative contracts such as futures, forwards, and swaps as accounting hedges under GAAP. These contracts were used to manage commodity price risk associated with customer contracts.
The tables below show the amounts related to cash flow hedges recorded in OCI and in earnings:
		Unrealized Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
(Millions)		2011
Natural gas contracts		$	(2.3	)
Electric contracts		3.8
Total		$	1.5
		Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
(Millions)		Income Statement Presentation		2013				2012				2011
Settled/Realized
Natural gas contracts		Nonregulated revenue		$	—			$	—			$	(9.3	)
Electric contracts		Nonregulated revenue		—				—				4.2
Interest rate swaps *		Interest expense		(1.1		)		(1.1		)		(1.1		)
Hedge Designation Discontinued
Natural gas contracts		Nonregulated revenue		—				—				(0.3		)
Interest rate swaps		Interest expense		—				—				(0.2		)
Total				$	(1.1	)		$	(1.1	)		$	(6.7	)
*	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 are being reclassified to interest expense over the life of the related debt.
		Gain (Loss) Recognized in Income on Derivative Instruments
		(Ineffective Portion and Amount Excluded from Effectiveness Testing)
(Millions)		Income Statement Presentation		2011
Natural gas contracts		Nonregulated revenue		$	0.3
Electric contracts		Nonregulated revenue		(0.3		)
Total				$	—

ACQUISITIONS

ACQUISITIONS	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
ACQUISITIONS	'
	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 is subject to state and federal regulatory approvals. The purchase price will be based on book value as of the closing date, and will be around $11 million. This acquisition is expected to close later in 2014 and will not be material to us.
	Acquisition of Compass Energy Services
	In May 2013, Integrys Energy Services acquired all of the equity interests of Compass Energy Services, Inc. and its wholly-owned subsidiary (Compass), a nonregulated retail natural gas business supplying commercial and industrial customers primarily in the Mid Atlantic and Ohio regions. This transaction expanded Integrys Energy Services' retail natural gas presence and provides a solid foundation for future growth in these regions.
	This acquisition was not material to us. Integrys Energy Services paid $12.4 million to acquire this business. In addition, under the terms of the purchase agreement, the former owners of Compass are eligible to receive additional cash consideration of up to $8.0 million (but no less than $3.0 million), based upon the financial performance of Compass over the five-year period beginning in May 2013 and ending in April 2018. Integrys Energy Services recorded a liability of $7.8 million related to this contingent consideration.
	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
	Inventories		$	0.7
	Assets from risk management activities (current)		15.1
	Other current assets		1.1
	Assets from risk management activities (long-term)		9.3
	Other long-term assets		6.1
	Total assets acquired		$	32.3
	Liabilities assumed
	Liabilities from risk management activities (current)		$	8.3
	Other current liabilities		0.5
	Liabilities from risk management activities (long-term)		3.4
	Total liabilities assumed		$	12.2
	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 9, 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 will be amortized over a nine-year period, beginning January 1, 2014.
	The purchase was originally financed with a combination of short-term debt and cash provided by operations. WPS replaced the short-term debt with a portion of the proceeds from its 4.752% Senior Notes issued in November 2013. See Note 12, Long-Term Debt, for more information.
	WPS received regulatory approval to defer incremental costs associated with the purchase of the facility. Operating costs for the Fox Energy Center subsequent to the date of acquisition are included in our income statement. Due to regulatory deferral, these costs did not impact net income. 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.
	Acquisition of Compressed Natural Gas Fueling Business
	On September 1, 2011, we acquired two compressed natural gas fueling businesses through our newly formed, indirect wholly owned subsidiary, ITF. The total consideration paid for the acquisition of Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle) was $49.6 million. The total cash payment for this transaction was $42.6 million, which was net of cash acquired of approximately $7 million. In 2012, we received $1.3 million as a result of post-closing working capital adjustments.
	Trillium and Pinnacle designed, built, maintained, owned and/or operated compressed natural gas fueling stations in multiple states. In addition, Pinnacle manufactured and sold a patented method to pressurize compressed natural gas.
	See Note 9, Goodwill and Other Intangible Assets, for more information related to this acquisition.

DISCONTINUED_OPERATIONS

DISCONTINUED OPERATIONS	12 Months Ended
	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]	'
DISCONTINUED OPERATIONS	'
	Discontinued Operations
	Discontinued Operations at Holding Company and Other Segment
	During 2013, 2012, and 2011, we recorded a $5.9 million after-tax gain, a $1.8 million after-tax gain, and a $0.5 million after-tax loss, 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.
	Discontinued Operations at Integrys Energy Services Segment
	Potential Sale of Combined Locks Energy Center
	Integrys Energy Services is currently pursuing the sale of the Combined Locks Energy Center (Combined Locks), a natural gas-fired co-generation facility located in Wisconsin, as part of its long-term energy asset strategy. An agreement to sell Combined Locks is expected to be entered into during the first half of 2014.
	The carrying values of the major classes of assets related to Combined Locks classified as held for sale on the balance sheets were as follows at December 31:
	(Millions)		2013				2012
	Inventories		$	0.5			$	0.5
	Property, plant, and equipment, net of accumulated depreciation of $ – and $0.5, respectively		0.2				2
	Total assets		$	0.7			$	2.5
	The following table shows the components of discontinued operations related to Combined Locks recorded on the income statements:
	(Millions)		2013				2012			2011
	Nonregulated revenues		$	(0.1	)		$	0.3		$	7.9
	Nonregulated cost of sales		(0.2		)		(0.5		)	(2.0		)
	Operating and maintenance expense		(2.1		)		(0.5		)	(0.7		)
	Depreciation and amortization expense		—				(0.2		)	(0.3		)
	Taxes other than income taxes		—				(0.1		)	(0.2		)
	Income (loss) before taxes		(2.4		)		(1.0		)	4.7
	(Provision) benefit for income taxes		1.1				0.4			(1.8		)
	Discontinued operations, net of tax		$	(1.3	)		$	(0.6	)	$	2.9
	Sale of WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC
	In March 2013, WPS Empire State, Inc., a subsidiary of Integrys Energy Services, sold all of the membership interests of WPS Beaver Falls Generation, LLC (Beaver Falls) and WPS Syracuse Generation, LLC (Syracuse), both of which owned natural gas-fired generation plants located in the state of New York. The cash proceeds from the sale were $1.6 million. The sale agreement also included a potential annual payment to Integrys Energy Services for a four-year period following the sale based on a certain level of earnings achieved by the buyer (an earn-out). Integrys Energy Services 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 carrying values of the major classes of assets and liabilities related to Beaver Falls and Syracuse classified as held for sale on the balance sheet were as follows:
			As of the Closing Date				As of
	(Millions)		in March 2013				31-Dec-12
	Inventories		$	1.8			$	1.8
	Other current assets		0.2				—
	Property, plant, and equipment		5.7				5.7
	Other long-term assets		0.1				0.1
	Total assets		$	7.8			$	7.6
	Total liabilities – other current liabilities		$	0.4			$	0.2
	In conjunction with the sale, the buyer assumed certain derivative contracts from WPS Empire State, Inc. Integrys Energy Services maintained these contracts to satisfy certain capacity obligations for its retail electric business and sales to external counterparties. The carrying value of the derivative contract liabilities assumed by the buyer was $6.8 million at closing.
	The following table shows the components of discontinued operations related to Beaver Falls and Syracuse recorded on the income statements:
	(Millions)		2013				2012			2011
	Nonregulated revenues		$	1.2			$	0.6		$	5
	Nonregulated cost of sales		(0.9		)		(2.0		)	(2.3		)
	Operating and maintenance expense		0.4			*	(3.5		)	(3.3		)
	Depreciation and amortization expense		—				(0.6		)	(0.7		)
	Taxes other than income taxes		(0.3		)		(1.4		)	(0.9		)
	Miscellaneous income		—				0.3			—
	Income (loss) before taxes		0.4				(6.6		)	(2.2		)
	(Provision) benefit for income taxes		(0.2		)		2.6			0.9
	Discontinued operations, net of tax		$	0.2			$	(4.0	)	$	(1.3	)
	*	Includes a $1.0 million gain on sale at closing
	The sale of Beaver Falls and Syracuse may generate immaterial cash flows from a four-year annual earn-out payment. In addition, Integrys Energy Services will continue to settle certain forward financial natural gas swaps under contracts that existed at the time of sale. These settlements will generate cash flows, of which the majority will expire within two years of the sale, and are not considered significant to the overall operations of Beaver Falls and Syracuse. Integrys Energy Services also maintained derivative contracts with Beaver Falls and Syracuse to satisfy certain capacity obligations for its retail electric business and sales to external counterparties. However, a significant portion of these obligations have been novated to the buyer. Integrys Energy Services does not have the ability to significantly influence the operating or financial policies of Beaver Falls and Syracuse and also does not have significant continuing involvement in the operations of Beaver Falls and Syracuse. Therefore, the continuing cash flows discussed above are not considered direct cash flows of Beaver Falls and Syracuse.
	Sale of WPS Westwood Generation, LLC
	In November 2012, Sunbury Holdings, LLC, a subsidiary of Integrys Energy Services, sold all of the membership interests of WPS Westwood Generation, LLC (Westwood), a waste coal generation plant located in Pennsylvania. The cash proceeds related to the sale were $2.6 million. Integrys Energy Services also received a $4.0 million note receivable from the buyer with a seven and one-half year term. Integrys Energy Services 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 carrying values of the major classes of assets and liabilities related to Westwood classified as held for sale on the balance sheet were as follows:
			As of the Closing Date
	(Millions)		in November 2012
	Inventories		$	1
	Current assets from risk management activities		0.1
	Property, plant, and equipment		5.5
	Other long-term assets		1.1
	Total assets		$	7.7
	Total liabilities – long-term liabilities from risk management activities		$	0.1
	The following table shows the components of discontinued operations related to Westwood recorded on the income statements:
	(Millions)		2012				2011
	Nonregulated revenues		$	9.2			$	12.4
	Nonregulated cost of sales		(4.4		)		(5.6		)
	Operating and maintenance expense		(14.3		)	*	(5.7		)
	Depreciation and amortization expense		(1.0		)		(1.4		)
Taxes other than income taxes		(0.2		)		(0.2		)
Miscellaneous income		—				0.1
Interest expense		(0.7		)		(0.6		)
Loss before taxes		(11.4		)		(1.0		)
Benefit for income taxes		4.5				0.3
Discontinued operations, net of tax		$	(6.9	)		$	(0.7	)
*	Includes a $0.6 million loss on sale at closing
Integrys Energy Services will receive interest income for seven and one-half years from the sale date related to the note receivable from the buyer. Integrys Energy Services does not have the ability to significantly influence the operating or financial policies of Westwood and also does not have significant continuing involvement in the operations of Westwood. Therefore, the continuing cash flows discussed above are not considered direct cash flows of Westwood.
Sale of Energy Management Consulting Business
During 2011, Integrys Energy Services recorded a $0.1 million after-tax gain in discontinued operations when contingent payments were earned related to the 2009 sale of its energy management consulting business.

PROPERTY_PLANT_AND_EQUIPMENT

PROPERTY, PLANT, AND EQUIPMENT	12 Months Ended
	Dec. 31, 2013
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)		2013		2012
	Electric utility		$	3,558.90	$	3,095.80
	Natural gas utility		5,428.50		5,050.80
	Total utility plant		8,987.40		8,146.60
	Less: Accumulated depreciation		3,160.90		3,006.10
	Net		5,826.50		5,140.50
	Construction work in progress		353.3		203.1
	Plant to be retired, net *		14.4		—
	Net utility plant		6,194.20		5,343.60
	Nonutility plant		142.3		120.2
	Less: Accumulated depreciation		81.6		72.3
	Net		60.7		47.9
	Construction work in progress		38		19.6
	Net nonutility plant		98.7		67.5
	Integrys Energy Services energy assets		109.8		92
	Integrys Energy Services other		19.7		17.9
	Other nonregulated		26.2		14
	Total nonregulated property, plant, and equipment		155.7		123.9
	Less: Accumulated depreciation		46.4		36.3
	Net		109.3		87.6
	Construction work in progress		8.3		3.2
	Net nonregulated property, plant, and equipment		117.6		90.8
	Total property, plant, and equipment		$	6,410.50	$	5,501.90
	*	In connection with the WPS Consent Decree with the EPA, early retirement of the Weston 1, Pulliam 5, and Pulliam 6 generating units was probable at December 31, 2013. 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 15, Commitments and Contingencies, for more information regarding the Consent Decree.
	We evaluate property, plant, and equipment for impairment whenever indicators of impairment exist. During 2011, Integrys Energy Services recorded a pre-tax noncash impairment loss of $4.6 million related to its Winnebago Energy Center, a landfill-gas-to-electric facility. The impairment charge resulted from lower estimated future cash flows and was primarily driven by forward energy and capacity prices. The impairment charge was reported as part of operating and maintenance expense in the income statement. The fair value of the facility was determined primarily using the income approach, which was based on discounted cash flows that were derived from internal forecasts. These forecasts considered externally supplied forward energy and capacity pricing curves as well as renewable energy credits. Other assumptions included forecasted operating expenses, forecasted capital additions, anticipated working capital requirements, and the discount rate. The 7.5% discount rate used represented the estimated cost of capital for the facility and was also based upon the cash flow period used for the fair value assessment.
	See Note 4, Discontinued Operations for additional impairment losses recorded in discontinued operations at Integrys Energy Services 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, 2013
Jointly owned utility facilities	'
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, 2013:
	(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	$	576.8		$	172.8		$	41.8
	Accumulated depreciation	$	(114.6	)	$	(111.6	)	$	(28.3	)
	Construction work in progress	$	2.2		$	194.8		$	0.3
	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, 2013
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)		2013		2012		See Note
	Regulatory assets (1) (2)
	Environmental remediation costs (net of insurance recoveries) (3)		$	653	$	689.7	15
	Unrecognized pension and other postretirement benefit costs (4)		428.8		810		17
	Merger and acquisition related pension and other postretirement benefit costs (5)		98.3		110.1
	Asset retirement obligations		89.5		73.9		13
	Income tax related items		55.3		47.6		14
	Termination of a tolling agreement with Fox Energy Company LLC		50		—		3
	Crane Creek production tax credits (6)		33.6		34.9
	De Pere Energy Center (7)		23.8		26.2
	Unamortized loss on reacquired debt (8)		18.5		18.2		1(n)
	Energy efficiency programs (9)		18		16.7
	Energy costs receivable through rate adjustments (10)		16		18.1
	Derivatives		11.8		30.7		1(h)
	Pension and other postretirement costs receivable through rate adjustments (11)		9.4		—		26
	Decoupling		9.3		10.6		26
	Other		26.7		37.9
	Total regulatory assets		$	1,542.00	$	1,924.60
	Balance Sheet Presentation
	Current assets		$	129.4	$	110.8
	Long-term assets		1,412.60		1,813.80
	Total regulatory assets		$	1,542.00	$	1,924.60
	-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 and UPPCO; unrecognized pension and other postretirement benefit costs at PGL and NSG; merger and acquisition related pension and other postretirement benefit costs at PGL and NSG; unamortized loss on reacquired debt at NSG, PGL, UPPCO and WPS; WPS energy efficiency programs; energy costs receivable through rate adjustments at MERC and WPS; asset retirement obligations and derivatives at all utilities; and decoupling at MGU and UPPCO. However, these regulatory assets are expected to be recovered from customers in future rates.
	(3)	As of December 31, 2013, we had not yet made cash expenditures for $600.8 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 Integrys Energy Group's 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 through 2019 for the portion related to other postretirement benefit costs.
	(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)	Prior to WPS purchasing the De Pere Energy Center in 2002, WPS had a long-term power purchase contract with the De Pere Energy Center 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.
	(8)	Amounts are recovered over the term of the replacement debt as authorized by the various commissions.
	(9)	Represents amounts recoverable from customers related to programs at the utility subsidiaries designed to meet energy efficiency standards.
	(10)	Represents the under-collection of energy costs that will be recovered from customers in the future.
	(11)	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)		2013		2012		See Note
	Regulatory liabilities
	Removal costs (1)		$	335.3	$	318.4
	Decoupling		51.7		15.9		26
	Unrecognized pension and other postretirement benefit costs		30.2		17.7		17
	Energy costs refundable through rate adjustments (2)		27.2		44.4
	Energy efficiency programs (3)		19.6		8.8
	Uncollectible expense		10.1		10		26
	Crane Creek depreciation deferral (4)		9		9.4
	Derivatives		6.6		4.3		1(h)
	Fox Energy Center (5)		5.6		—		3
	Other		7.1		7.2
	Total regulatory liabilities		$	502.4	$	436.1
	Balance Sheet Presentation
	Current liabilities		$	101.5	$	65.6
	Long-term liabilities		400.9		370.5
	Total regulatory liabilities		$	502.4	$	436.1
	(1)	Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment.
	(2)	Represents the over-collection of energy costs that will be refunded to customers in the future.
	(3)	Represents amounts refundable to customers related to programs at the utility subsidiaries designed to meet energy efficiency standards.
	(4)	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.
	(5)	Represents the deferral of incremental costs associated with WPS owning and operating the Fox Energy Center, which was purchased in March 2013. The deferral does not include an allowance for earnings on shareholders' investment of $26.7 million, in accordance with GAAP requirements, which has created the net regulatory liability.

EQUITY_METHOD_INVESTMENTS

EQUITY METHOD INVESTMENTS	12 Months Ended
	Dec. 31, 2013
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, 2013, and 2012 were as follows:
	(Millions)	2013		2012
	ATC	$	508.4	$	476.6
	INDU Solar Holdings, LLC	24.7		27.5
	WRPC	7		7.3
	Other	0.8		0.8
	Equity method investments	$	540.9	$	512.2
	ATC
	Our electric transmission investment segment consists of WPS Investments LLC’s ownership interest in ATC, which was approximately 34% at December 31, 2013. 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)	2013		2012		2011
	Balance at the beginning of period	$	476.6	$	439.4	$	416.3
	Add: Earnings from equity method investment	89.1		85.3		79.1
	Add: Capital contributions	13.7		20.4		8.5
	Less: Dividends received	71		68.5		64.5
	Balance at the end of period	$	508.4	$	476.6	$	439.4
	The regulated electric utilities provide construction and other services to ATC and receive network transmission services from ATC. The related party transactions recorded by the regulated electric utilities during the years ended December 31 were as follows:
	(Millions)	2013		2012		2011
	Total charges to ATC for services and construction	$	11.3	$	12.5	$	13.5
	Total costs for network transmission service provided by ATC	104.9		100.3		102.7
	INDU Solar Holdings, LLC
	Integrys Solar, LLC, a subsidiary of Integrys Energy Services, 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)	2013		2012		2011
	Balance at the beginning of period	$	27.5	$	28.4	$	0.1
	Add: Earnings (loss) from equity method investment	1.3		1.1		(0.7		)
	Add: Capital contributions	—		7		29
	Less: Return of capital to partners	4.1		9		—
	Balance at the end of period	$	24.7	$	27.5	$	28.4
	WRPC
	WPS owns 50% of the stock of WRPC, which operates two hydroelectric plants and an oil-fired combustion turbine. Half of the energy output of the hydroelectric plants is sold to WPS, and the remainder is sold to Wisconsin Power and Light. The electric power from the combustion turbine is 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)	2013		2012		2011
	Balance at the beginning of period	$	7.3	$	7.7	$	8.1
	Add: Earnings from equity method investment	1		0.8		0.9
	Less: Dividends received	1.3		1.2		1.3
	Balance at the end of period	$	7	$	7.3	$	7.7
	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)	2013		2012		2011
	Charges to WRPC for operations	$	0.9	$	0.8	$	0.7
	Purchases of energy from WRPC	3.7		5		4.9
	Net proceeds from WRPC sales of energy to MISO	—		2.9		4.7
	Financial Data
	Combined financial data of our significant equity method investments, ATC, INDU Solar Holdings, LLC, and WRPC, are included in the tables below:
	(Millions)	2013		2012		2011
	Income statement data
	Revenues	$	642	$	618.3	$	575.5
	Operating expenses	306.2		292.1		269.6
	Other expense	83.7		85.1		81.5
	Net income	$	252.1	$	241.1	$	224.4
	Earnings from equity method investments	$	91.4	$	87.2	$	79.4
	(Millions)	31-Dec-13		31-Dec-12
	Balance sheet data
	Current assets	$	90.2	$	81.1
	Noncurrent assets	3,587.20		3,347.40
	Total assets	$	3,677.40	$	3,428.50
	Current liabilities	$	383.6	$	253
	Long-term debt	1,559.10		1,559.50
	Other noncurrent liabilities	134.4		103.5
	Shareholders’ equity	1,600.30		1,512.50
	Total liabilities and shareholders’ equity	$	3,677.40	$	3,428.50

GOODWILL_AND_OTHER_INTANGIBLE_

GOODWILL AND OTHER INTANGIBLE ASSETS	12 Months Ended
	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]	'
GOODWILL AND OTHER INTANGIBLE ASSETS	'
	Goodwill and Other Intangible Assets
	The following table shows changes to our gross amount of goodwill and accumulated impairment losses by segment for the years ended December 31, 2013, and 2012:
			Natural Gas Utility						Integrys Energy Services				Holding Company and Other						Total
	(Millions)		2013			2012			2013		2012		2013			2012			2013			2012
	Balance as of January 1
	Gross goodwill		$	933.5		$	933.5		$	6.6	$	6.6	$	15.8		$	15.9		$	955.9		$	956
	Accumulated impairment losses		(297.6		)	(297.6		)	—		—		—			—			(297.6		)	(297.6		)
	Net goodwill		635.9			635.9			6.6		6.6		15.8			15.9			658.3			658.4
	Adjustment to Trillium and Pinnacle purchase price		—			—			—		—		—			(0.1		)	—			(0.1		)
	Adjustment to ITF patents/intellectual property *		—			—			—		—		3.8			—			3.8			—
	Balance as of December 31
	Gross goodwill		933.5			933.5			6.6		6.6		19.6			15.8			959.7			955.9
	Accumulated impairment losses		(297.6		)	(297.6		)	—		—		—			—			(297.6		)	(297.6		)
	Net goodwill		$	635.9		$	635.9		$	6.6	$	6.6	$	19.6		$	15.8		$	662.1		$	658.3
	*	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 2013, annual impairment tests were completed at all of our reporting units that carried a goodwill balance. No impairments resulted from these tests.
	The identifiable intangible assets other than goodwill listed below are part of other current and long-term assets on the balance sheets. An insignificant amount was recorded as assets held for sale on the balance sheets.
			31-Dec-13								31-Dec-12
	(Millions)		Gross Carrying			Accumulated			Net Carrying		Gross Carrying		Accumulated			Net Carrying
			Amount			Amortization			Amount		Amount		Amortization			Amount
	Amortized intangible assets
	Customer-related (1)		$	26.8		$	(15.7	)	$	11.1	$	22.4	$	(14.7	)	$	7.7
	Contractual service agreements (2)		15.6			(1.8		)	13.8		—		—			—
	Renewable energy credits (3)		8.4			—			8.4		3.1		—			3.1
	Compressed natural gas fueling contract assets (4)		5.6			(2.7		)	2.9		5.6		(1.3		)	4.3
	Customer-owned equipment modifications (5)		4			(0.9		)	3.1		4		(0.5		)	3.5
	Natural gas and electric contract assets (6)		3.9			(0.5		)	3.4		—		—			—
	Nonregulated easements (7)		3.7			(1.1		)	2.6		3.8		(0.9		)	2.9
	Patents/intellectual property (8)		3.4			(0.5		)	2.9		7.2		(0.3		)	6.9
	Other		0.5			(0.3		)	0.2		0.5		(0.2		)	0.3
	Total		$	71.9		$	(23.5	)	$	48.4	$	46.6	$	(17.9	)	$	28.7
	Unamortized intangible assets
	MGU trade name		$	5.2		$	—		$	5.2	$	5.2	$	—		$	5.2
	Trillium trade name (9)		3.5			—			3.5		3.5		—			3.5
	Pinnacle trade name (9)		1.5			—			1.5		1.5		—			1.5
	Total intangible assets		$	82.1		$	(23.5	)	$	58.6	$	56.8	$	(17.9	)	$	38.9
	(1)	Represents customer relationship assets associated with PELLC’s former nonregulated retail natural gas and electric operations, ITF's compressed natural gas fueling operations, and Compass Energy Services. See Note 3, Acquisitions, for more information regarding Integrys Energy Services' acquisition of Compass Energy Services. The remaining weighted-average amortization period for customer-related intangible assets at December 31, 2013, was approximately 11 years.
	(2)	Represents contractual service agreements related to maintenance on the combustion turbine generators at the Fox Energy Center. The remaining amortization period for these intangible assets at December 31, 2013, was approximately six years.
	(3)	Used at Integrys Energy Services to comply with state Renewable Portfolio Standards and to support customer commitments.
	(4)	Represents the fair value of ITF contracts acquired in September 2011. The remaining amortization period at December 31, 2013, was approximately seven years.
	(5)	Relates to modifications made by Integrys Energy Services 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, 2013, of approximately ten years.
	(6)	Represents the fair value of certain natural gas and electric customer contracts acquired by Integrys Energy Services during 2013 that were not considered to be derivative instruments. The remaining amortization period for these intangible assets at December 31, 2013, was approximately four years.
	(7)	Relates to easements supporting a pipeline at Integrys Energy Services. The easements are amortized on a straight-line basis, with a remaining amortization period at December 31, 2013, of approximately ten years.
	(8)	Represents the fair value of patents/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, 2013, was approximately nine years.
	(9)	Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle) are wholly owned subsidiaries of ITF.
	Amortization expense recorded as a component of nonregulated cost of sales in the statements of income for the years ended December 31, 2013, 2012, and 2011, was $2.1 million, $2.5 million, and $1.3 million, respectively.
	Amortization expense recorded as a component of depreciation and amortization expense in the statements of income for the years ended December 31, 2013, 2012, and 2011, was $4.2 million, $2.5 million, and $3.4 million, respectively.
	An insignificant amount of amortization expense was recorded in discontinued operations for the years ended December 31, 2013, 2012, and 2011.
	Amortization expense for the next five fiscal years is estimated to be:
			For the Year Ending December 31
	(Millions)		2014			2015			2016		2017		2018
	Amortization to be recorded in nonregulated cost of sales		$	3.4		$	2		$	1.1	$	0.9	$	0.8
	Amortization to be recorded in depreciation and amortization expense		4.3			4.2			4		3.9		3.8

LEASES

LEASES	12 Months Ended
	Dec. 31, 2013
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 $12.8 million, $12.4 million, and $12.6 million in 2013, 2012, and 2011, respectively. Future minimum rental obligations under noncancelable operating leases are payable as follows:
	Year ending December 31	Payments
	(Millions)
	2014	$	6.7
	2015	6.4
	2016	6.4
	2017	7.4
	2018	7.3
	Later years	59.4
	Total	$	93.6

SHORTTERM_DEBT_AND_LINES_OF_CR

SHORT-TERM DEBT AND LINES OF CREDIT	12 Months Ended
	Dec. 31, 2013
Short-term Debt [Abstract]	'
SHORT-TERM DEBT AND LINES OF CREDIT	'
	Short-Term Debt and Lines of Credit
	Information about our short-term borrowings was as follows:
	(Millions, except percentages)		2013				2012				2011
	Commercial paper
	Amount outstanding at December 31 (1)		$	326			$	482.4			$	303.3
	Average interest rate on amount outstanding at December 31		0.22%				0.4		%		0.31		%
	Average amount outstanding during the year (2)		$	378.4			$	326.3			$	134.9
	Short-term notes payable (3)
	Average amount outstanding during the year (2)		$	130.4		(4)	$	—			$	3.6
	(1)	Maturity dates ranged from January 2, 2014, through January 27, 2014.
	(2)	Based on daily outstanding balances during the year.
	(3)	We did not have short-term notes payable outstanding at December 31, 2013, 2012, and 2011.
	(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		2013				2012
	Revolving credit facility (Integrys Energy Group)		5/17/14		$	275			$	275
	Revolving credit facility (Integrys Energy Group)		5/17/16		200				200
	Revolving credit facility (Integrys Energy Group)		6/13/17		635				635
	Revolving credit facility (WPS)		5/17/14		135				135
	Revolving credit facility (WPS)		6/13/17		115				115
	Revolving credit facility (PGL)		6/13/17		250				250
	Total short-term credit capacity				$	1,610.00			$	1,610.00
	Less:
	Letters of credit issued inside credit facilities				$	52.4			$	25.5
	Commercial paper outstanding				326				482.4
	Available capacity under existing agreements				$	1,231.60			$	1,102.10
	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, 2013
Debt Disclosure [Abstract]	'
LONG-TERM DEBT	'
	Long-Term Debt
						31-Dec
	(Millions)					2013			2012
	WPS First Mortgage Bonds (1)
		Series		Year Due
		7.125	%	2023		$	0.1		$	0.1
	WPS Senior Notes (1) (2)
		Series		Year Due
		4.8	%	2013		—			125
		3.95	%	2013		—			22
		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			—
	PGL First and Refunding Mortgage Bonds (3)
		Series		Year Due
		KK, 5.00%		2033		—			50
		NN-2, 4.625%		2013		—			75
		QQ, 4.875%		2038	Mandatory interest reset date on November 1, 2018	75			75
		RR, 4.30%		2035	Mandatory interest reset date on June 1, 2016	50			50
		SS, 7.00%		2013		—			45
		TT, 8.00%		2018		5			5
		UU, 4.63%		2019		75			75
		VV, 2.125%		2030	Mandatory interest reset date on July 1, 2014	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			—
		AAA, 3.96%		2043		220			—
	NSG First Mortgage Bonds (4)
		Series		Year Due
		N-2, 4.625%		2013		—			40
		O, 7.00%		2013		—			6.5
		P, 3.43%		2027		28			28
		Q, 3.96%		2043		54			—
	Integrys Energy Group Unsecured Senior Notes (5)
		Series		Year Due
		7.27	%	2014		100			100
		8	%	2016		55			55
		4.17	%	2020		250			250
	Integrys Energy Group Unsecured Junior Subordinated Notes (6)
		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			—
	Total					3,056.90			2,246.40
	Unamortized discount on debt					(0.7		)	(1.2		)
	Total debt					3,056.20			2,245.20
	Less current portion					100			313.5
	Total long-term debt					$	2,956.20		$	1,931.70
	-1	WPS's First Mortgage Bonds and Senior Notes are subject to the terms and conditions of WPS's First Mortgage Indenture. 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.
	-2	In December 2013, WPS’s $125.0 million of 4.80% Senior Notes matured, and the outstanding principal balance was repaid.
	In November 2013, WPS issued $450.0 million of 4.752% Senior Notes. These notes are due in November 2044.
	In February 2013, WPS’s $22.0 million of 3.95% Senior Notes matured, and the outstanding principal balance was repaid.
	-3	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 and the City of Chicago have 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 2013, PGL’s $45.0 million 7.00% Series SS First and Refunding Mortgage Bonds matured, and the outstanding principal balance was repaid.
	In August 2013, PGL issued $220.0 million of 3.96% Series AAA First and Refunding Mortgage Bonds. These bonds are due in August 2043.
	In May 2013, PGL’s $75.0 million 4.625% Series NN-2 First and Refunding Mortgage Bonds matured, and the outstanding principal balance was repaid.
	In April 2013, PGL bought back its $50.0 million of 5.00% Series KK First and Refunding Mortgage Bonds that were due in February 2033. In the same month, PGL issued $50.0 million of 4.00% Series ZZ First and Refunding Mortgage Bonds. These bonds are due in February 2033.
	-4	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.
	NSG has used 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 NSG. In return, NSG issued equal principal amounts of certain collateralized First Mortgage Bonds.
In November 2013, NSG’s $6.5 million 7.00% Series O First Mortgage Bonds matured, and the outstanding principal balance was repaid.
In May 2013, NSG’s $40.0 million 4.625% Series N-2 First Mortgage Bonds matured, and the outstanding principal balance was repaid. In the same month, NSG issued $54.0 million of 3.96% Series Q First Mortgage Bonds. These Bonds are due in May 2043.
-5	In June 2014, our 7.27% Unsecured Senior Notes will mature. As a result, the $100.0 million balance of these notes was included in the current portion of long-term debt on our balance sheet at December 31, 2013.
-6	In August 2013, we issued $400.0 million of Junior Subordinated Notes. These notes are considered hybrid instruments with a combination of debt and equity characteristics. Interest is payable quarterly at the stated rate of 6.00% for the first ten years, after which time it changes to a floating rate. These notes are due in August 2073.
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.
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
2014		$	100
2015		125
2016		105
2017		125
2018		5
Later years		2,596.90
Total		$	3,056.90

ASSET_RETIREMENT_OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2013
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. Integrys Energy Services 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, 2013:
	(Millions)		Utilities				Integrys Energy Services		Total
	Asset retirement obligations at December 31, 2010		$	320.9			$	—	$	320.9
	Accretion		17.1				—		17.1
	Additions and revisions to estimated cash flows		64.4			*	0.5		64.9
	Settlements		(5.7		)		—		(5.7		)
	Asset retirement obligations at December 31, 2011		396.7				0.5		397.2
	Accretion		20.3				0.1		20.4
	Additions and revisions to estimated cash flows		(2.4		)		1.6		(0.8		)
	Settlements		(5.6		)		—		(5.6		)
	Asset retirement obligations at December 31, 2012		409				2.2		411.2
	Accretion		20.8				0.1		20.9
	Additions and revisions to estimated cash flows		70.1			*	0.5		70.6
	Settlements		(11.2		)		—		(11.2		)
	Asset retirement obligations at December 31, 2013		$	488.7			$	2.8	$	491.5
	*	Revisions were made to estimated cash flows related to asset retirement obligations primarily due to an increase in the weighted average cost to retire a foot of natural gas distribution pipe at PGL.

INCOME_TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2013
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)		2013				2012
	Deferred income tax assets
	Tax credit carryforwards		$	113.5			$	105.1
	Price risk management		13				59.6
	Other		98.5				76.5
	Total deferred income tax assets		$	225			$	241.2
	Valuation allowance		(8.2		)		(7.2		)
	Net deferred income tax assets		$	216.8			$	234
	Deferred income tax liabilities
	Plant-related		$	1,373.80			$	1,215.70
	Employee benefits		79.6				49.1
	Regulatory deferrals		78.8				60.8
	Other		43.5				47.9
	Total deferred income tax liabilities		$	1,575.70			$	1,373.50
	Total net deferred income tax liabilities		$	1,358.90			$	1,139.50
	Balance sheet presentation
	Current deferred income tax assets		$	31.4			$	64.3
	Long-term deferred income tax liabilities		1,390.30				1,203.80
	Net deferred income tax liabilities		$	1,358.90			$	1,139.50
	Deferred tax credit carryforwards at December 31, 2013, included $73.9 million of alternative minimum tax credits, which can be carried forward indefinitely. Other deferred tax credit carryforwards included $20.9 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 2032. Deferred tax credit carryforwards also included $15.2 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 2020. We also had $3.5 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, 2013, we had deferred income tax assets of $45.4 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 $16.4 million reflecting 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 2032 as follows:
	2020 through 2025	$6.3 million
	2026 through 2031	$9.2 million
	2032	$46.3 million
	Valuation allowances are established for certain state operating losses and foreign tax credits 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, 2013, the entire valuation allowance was related to noncurrent deferred income tax assets. There was no significant change in the valuation allowance during 2013.
	Regulated utilities record certain adjustments related to deferred income taxes to regulatory assets and liabilities. As the related temporary differences reverse, the regulated 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 $51.6 million and $42.1 million at December 31, 2013, and 2012, respectively. See Note 7, Regulatory Assets and Liabilities, for more information.
	Income Before Taxes
	Income before taxes includes the following components of foreign and domestic income:
			For the Years Ended December 31
	(Millions)		2013				2012				2011
	Domestic		$	560.8			$	443.9			$	363.4
	Foreign		—				(0.1		)		(0.1		)
	Total income before taxes		$	560.8			$	443.8			$	363.3
	Provision for Income Taxes
	The components of the provision for income taxes were as follows:
	(Millions)		2013				2012				2011
	Current provision
	Federal		$	7.8			$	3.5			$	(44.2	)
	State		5.9				0.4				6
	Foreign		0.1				(0.1		)		(0.2		)
	Total current provision		13.8				3.8				(38.4		)
	Deferred provision
	Federal		174.8				128.3				158.7
	State		14.9				20.1				14.6
	Foreign		—				—				0.1
	Total deferred provision		189.7				148.4				173.4
	Investment tax credits, net		8.4				5.2				(1.1		)
	Penalties		(0.1		)		(0.3		)		0.7
	Unrecognized tax benefits		0.4				(3.0		)		0.9
	Interest		(1.4		)		(4.3		)		(2.2		)
	Total provision for income taxes related to continuing operations		210.8				149.8				133.3
	Total provision for income taxes related to discontinued operations		(6.9		)		(9.3		)		1.1
	Total		$	203.9			$	140.5			$	134.4
	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 before taxes.
			2013							2012						2011
	(Millions, except for percentages)		Rate			Amount				Rate			Amount			Rate		Amount
	Statutory federal income tax		35	%		$	196.3			35	%		$	155.4		35	%	$	127.2
	State income taxes, net		3.9			21.8				4.8			21.1			5.3		19.1
	Federal tax credits		(0.1	)		(0.5		)		(1.7	)		(7.6		)	(2.0	)	(7.1		)
Benefits and compensation		(0.7	)		(4.2		)		(2.1	)		(9.4		)	(2.3	)	(8.4		)
Other differences, net		(0.5	)		(2.6		)		(2.2	)		(9.7		)	0.7		2.5
Effective income tax		37.6	%		$	210.8			33.8	%		$	149.8		36.7	%	$	133.3
Unrecognized Tax Benefits
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
(Millions)		2013				2012				2011
Balance at January 1		$	11.3			$	22.4			$	30.4
Increase related to tax positions taken in prior years		2.2				0.9				3.1
Decrease related to tax positions taken in prior years		(8.7		)		(6.7		)		(1.6		)
Increase related to tax positions taken in current year		0.3				0.6				0.9
Decrease related to settlements		(1.5		)		(5.7		)		(9.4		)
Decrease related to lapse of statutes		—				(0.2		)		(1.0		)
Balance at December 31		$	3.6			$	11.3			$	22.4
We had accrued interest of $0.8 million and accrued penalties of $0.4 million related to unrecognized tax benefits at December 31, 2013. We had accrued interest of $2.5 million and accrued penalties of $2.0 million related to unrecognized tax benefits at December 31, 2012.
Our effective tax rate could be affected by recognition of $1.9 million of unrecognized tax benefits related to continuing operations in periods after December 31, 2013. Also, our provision for income taxes could be affected by recognition of $0.5 million of unrecognized tax benefits related to discontinued operations in periods after December 31, 2013.
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. During 2013, the IRS completed its examinations of 2009 and 2010.
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, 2013, we were subject to examination by state or local tax authorities for the 2008 through 2012 tax years in our major state operating jurisdictions as follows:
State		Year
Illinois		2008
Michigan		2008
Minnesota		2011
Wisconsin		2009
During 2013, the Minnesota taxing authority initiated and completed its examination of the 2005 through 2010 tax years, and the Michigan taxing authority initiated its examination of the 2008 through 2011 tax years. During 2013, the Illinois taxing authority completed its examination of the 2007 tax year, which resulted in an adjustment to the provision for income taxes, of which a large portion was reported as discontinued operations. This settlement, combined with other certain state income tax examinations and a remeasurement of uncertain tax positions, decreased our liability for unrecognized tax benefits by $6.5 million. We reduced the provision for income taxes related to these items, of which a large portion was reported as discontinued operations.
As of December 31, 2013, we were subject to examination by foreign income tax authorities for the 2008 through 2012 tax years. With a few exceptions, we are no longer subject to foreign income tax examinations by tax authorities for years prior to 2008.
In the next 12 months, it is also reasonably possible that we and our subsidiaries will settle open examinations in multiple taxing jurisdictions related to tax years prior to 2011, resulting in a further decrease in unrecognized tax benefits of as much as $0.9 million.

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
COMMITMENTS AND CONTINGENCIES	'
	Commitments and Contingencies
	(a) Unconditional Purchase Obligations and Purchase Order Commitments
	We and our subsidiaries routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. The regulated natural gas utilities have obligations to distribute and sell natural gas to their customers, and the regulated electric utilities have obligations to distribute and sell electricity to their customers. The utilities expect to recover costs related to these obligations in future customer rates. Additionally, the majority of the energy supply contracts entered into by Integrys Energy Services are to meet its contractual obligations to deliver energy to customers. The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2013, including those of our subsidiaries.
						Payments Due By Period
	(Millions)		Date Contracts Extend Through	Total Amounts Committed		2014		2015		2016		2017		2018		Later Years
	Natural gas utility supply and transportation		2028	$	845.9	$	181.2	$	169.6	$	158.4	$	122	$	71.7	$	143
	Electric utility
	Purchased power *		2029	772.3		80.6		32.8		28.8		27.6		27		575.5
	Coal supply and transportation		2018	99.5		46.3		31		12		6.7		3.5		—
	Nonregulated electricity and natural gas supply		2020	697.9		492.8		145.2		49.9		8.1		1.5		0.4
	Total			$	2,415.60	$	800.9	$	378.6	$	249.1	$	164.4	$	103.7	$	718.9
	*	Includes minimum future commitments for UPPCO related to power purchase contracts of $9.9 million for the years 2014 to 2023. In January 2014, we announced an agreement to sell UPPCO. See Note 29, Subsequent Event, for more information.
	We and our subsidiaries also had commitments of $909.0 million in the form of purchase orders issued to various vendors at December 31, 2013, that relate to normal business operations, including construction projects. Included in this amount are purchase orders issued to various vendors of UPPCO for $12.2 million.
	(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 (various options, including capital projects, are available), 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. As of December 31, 2013, the early retirement of certain Weston and Pulliam units mentioned in the Consent Decree was considered probable. See Note 5, Property, Plant, and Equipment, for more information.
	WPS received approval from the PSCW in its 2014 rate order to recover prudently incurred 2014 costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. We also believe that prudently incurred costs after 2014 will be recoverable from customers based on past precedent with the PSCW.
	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, 2013. 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 (Joint Owners) 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 (various options, including capital projects, are available), 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, 2013, 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.
	Weston Title V Air Permit:
	In November 2010, the WDNR provided a draft revised permit for the Weston 4 plant. WPS objected to proposed changes in mercury limits and requirements on the boilers as beyond the authority of the WDNR and met with the WDNR to resolve these issues. In September 2011, the WDNR issued an updated draft revised permit and a request for public comments. Due to the significance of the changes to the draft revised permit, the WDNR re-issued the draft revised permit for additional comments in February 2013. In July 2012, Clean Wisconsin filed a lawsuit against the WDNR alleging failure to issue or delay in issuing the Weston Title V permit. WPS and the WDNR both filed motions to dismiss Clean Wisconsin's lawsuit, which the Court granted in February 2013. Clean Wisconsin appealed this decision but voluntarily filed a dismissal of its appeal in July 2013, closing the lawsuit. The dismissal resulted from the WDNR sending the proposed permit to the EPA for action. Later in July 2013, the WDNR issued the 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 Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also filed Petitions for Review and requests for contested case proceedings regarding various aspects of the permit. In October 2013, the WDNR granted all parties' requests for contested case proceedings, except one issue where they asked for clarifying information from WPS. The Petitions for Review, by all parties, have been stayed pending the resolution of the contested cases.
	Mercury and Interstate Air Quality Rules
	Mercury:
	The State of Wisconsin's mercury rule requires 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 will be required to reduce mercury emissions by 90% from the historical baseline. Reductions can be phased in and the 90% target delayed until 2021 if additional sulfur dioxide and nitrogen oxide reductions are implemented. By 2015, electric generating units above 25 megawatts, but less than 150 megawatts, must reduce their mercury emissions to a level defined by the Best Available Control Technology rule. As of December 31, 2013, WPS estimated capital costs of approximately $8 million for its wholly owned plants to achieve the required reductions. The capital costs are expected to be recovered in future rates.
	In December 2011, the EPA issued the final Utility Mercury and Air Toxics Standards (MATS), which will regulate emissions of mercury and other hazardous air pollutants beginning in 2015. The State of Wisconsin is in the process of revising the state mercury rule to be consistent with the MATS rule. We are currently evaluating options for achieving the emission limits specified in this rule, but we do not anticipate the cost of compliance to be significant. We expect to recover future compliance costs 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 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. In October 2012, the EPA and several other parties filed petitions for a rehearing of the D.C. Circuit's decision, which the D.C. Circuit denied in January 2013. In March 2013, the EPA requested that the United States Supreme Court (Supreme Court) review the D.C. Circuit's rejection of CSAPR. In June 2013, the Supreme Court agreed to review the case.
	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), and the EPA has not revised it to reflect the reinstatement of CAIR. Although particulate emissions also contribute to visibility impairment, the WDNR's modeling has shown the impairment to be so insignificant that additional capital expenditures on controls may not be warranted.
	Due to the uncertainty surrounding this rulemaking, we are currently unable to predict whether WPS will have to purchase additional emission allowances, idle or abandon certain units, or change how certain units are operated. WPS expects to recover any future compliance costs in future rates. The potential impact on Integrys Energy Services is not expected to be material.
	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. They are coordinating the investigation and cleanup of the sites subject to EPA jurisdiction under what is called a "multi-site" 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 sheets include liabilities of $599.7 million that we have estimated and accrued for as of December 31, 2013, 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, 2013, cash expenditures for environmental remediation not yet recovered in rates were $49.3 million. Our balance sheets also include a regulatory asset of $649.0 million at December 31, 2013, which is net of insurance recoveries received of $65.2 million, 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.

GUARANTEES

GUARANTEES	12 Months Ended
	Dec. 31, 2013
Guarantees [Abstract]	'
GUARANTEES	'
	Guarantees
	The following table shows our outstanding guarantees:
			Total Amounts Committed		Expiration
	(Millions)		at December 31, 2013		Less Than 1 Year		1 to 3 Years		Over 3 Years
	Guarantees supporting commodity transactions of subsidiaries (1)		$	597.4	$	375.1	$	2.2	$	220.1
	Standby letters of credit (2)		55.8		45.1		10.6		0.1
	Surety bonds (3)		21.9		21.9		—		—
	Other guarantees (4)		56.3		1.2		1.5		53.6
	Total guarantees		$	731.4	$	443.3	$	14.3	$	273.8
	(1)	Consists of (a) $430.3 million, $5.0 million, and $2.0 million to support the business operations of Integrys Energy Services, IBS, and UPPCO, respectively, and (b) $111.5 million and $48.6 million related to natural gas supply at MERC and MGU, 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 $53.8 million issued to support Integrys Energy Services’ operations and $2.0 million issued to support ITF, MERC, MGU, NSG, PGL, UPPCO, 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) $35.0 million to support Integrys Energy Services' future payment obligations related to its distributed solar generation projects. This guarantee is not reflected on our balance sheets; (b) $10.0 million related to the sale agreement for Integrys Energy Services’ Texas retail marketing business, which included a number of customary representations, warranties, and indemnification provisions. 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) $3.0 million related to the sale of WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC. Integrys Energy Services' guaranteed the buyer's performance under certain derivative contracts that the buyer assumed from WPS Empire State, Inc. in conjunction with the sale. See Note 4, Discontinued Operations, for more information; (d) $2.4 million related to the performance of an operating and maintenance agreement by ITF; and (e) $5.9 million related to other indemnifications primarily for workers compensation coverage. The amounts discussed in items (c) through (e) above are not reflected on our balance sheets.

EMPLOYEE_BENEFIT_PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2013
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. Our defined benefit pension plans were closed to all new hires as of February 16, 2012. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013.
	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 following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets:
			Pension Benefits						Other Benefits
	(Millions)		2013			2012			2013			2012
	Change in benefit obligation
	Obligation at January 1		$	1,784.90		$	1,563.10		$	621		$	576.8
	Service cost		30.2			46			24.9			20.8
	Interest cost		71.2			78			24.8			28.5
	Plan amendments		—			—			0.2			—
	Actuarial (gain) loss, net		(153.1		)	196.6			(73.4		)	14.3
	Participant contributions		—			—			10.6			10.6
	Benefit payments		(91.5		)	(98.8		)	(34.0		)	(32.1		)
	Federal subsidy on benefits paid		—			—			2.2			2.1
	Obligation at December 31		$	1,641.70		$	1,784.90		$	576.3		$	621
	Change in fair value of plan assets
	Fair value of plan assets at January 1		$	1,348.10		$	1,099.50		$	424.4		$	285.5
	Actual return on plan assets		205.4			173.6			57.8			46.3
	Employer contributions		65.7			173.8			11.3			114.1
	Participant contributions		—			—			10.6			10.6
	Benefit payments		(91.5		)	(98.8		)	(34.0		)	(32.1		)
	Fair value of plan assets at December 31		$	1,527.70		$	1,348.10		$	470.1		$	424.4
	Funded Status at December 31		$	(114.0	)	$	(436.8	)	$	(106.2	)	$	(196.6	)
	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)		2013			2012			2013			2012
	Current liabilities		$	9		$	7.9		$	0.2		$	0.3
	Long-term liabilities		105			428.9			106			196.3
	Total liabilities		$	114		$	436.8		$	106.2		$	196.6
	The accumulated benefit obligation for the defined benefit pension plans was $1,489.1 million and $1,594.7 million at December 31, 2013, and 2012, respectively.
	Information for the qualified pension plans with an accumulated benefit obligation in excess of plan assets is presented in the following table as of December 31:
	(Millions)		2013			2012
	Projected benefit obligation		$	65.4		$	1,784.90
	Accumulated benefit obligation		63			1,594.70
	Fair value of plan assets		—			1,348.10
	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)		2013			2012			2013			2012
	Accumulated other comprehensive loss (pre-tax) (1)
	Net actuarial loss		$	33.3		$	59.1		$	0.7		$	1.3
	Prior service costs (credits)		—			0.2			(0.2		)	(0.6		)
	Total		$	33.3		$	59.3		$	0.5		$	0.7
	Net regulatory assets (2)
	Net actuarial loss		$	399.3		$	683.1		$	8.9		$	117.3
	Prior service costs (credits)		2.4			6.2			(12.0		)	(14.3		)
	Total		$	401.7		$	689.3		$	(3.1	)	$	103
	-1	Amounts related to the nonregulated entities are included in accumulated other comprehensive loss.
	-2	Amounts related to the regulated utilities are recorded as regulatory assets or liabilities.
	The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2014:
	(Millions)		Pension Benefits			Other Benefits
	Net actuarial losses		$	34.6		$	2.5
	Prior service costs (credits)		0.6			(2.4		)
	Total 2014 – estimated amortization		$	35.2		$	0.1
	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)		2013			2012			2011			2013			2012			2011
	Service cost		$	30.2		$	46		$	41.4		$	24.9		$	20.8		$	19
	Interest cost		71.2			78			80.1			24.8			28.5			29.5
	Expected return on plan assets		(105.5		)	(107.9		)	(100.0		)	(30.6		)	(28.2		)	(21.4		)
	Amortization of transition obligation		—			—			—			—			0.3			0.3
	Amortization of prior service cost (credit)		4			5			5.3			(2.5		)	(3.4		)	(3.9		)
Amortization of net actuarial loss		56.7			34			18.1			8.4			6.6			4
Net periodic benefit cost		$	56.6		$	55.1		$	44.9		$	25		$	24.6		$	27.5
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
		2013		2012	2013		2012
Discount rate		4.92%		4.07%	4.83%		3.96%
Rate of compensation increase		4.24%		4.25%	N/A		N/A
Assumed medical cost trend rate		N/A		N/A	6.50%		7.00%
Ultimate trend rate		N/A		N/A	5.00%		5.00%
Year ultimate trend rate is reached		N/A		N/A	2019		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
		2013		2012	2011
Discount rate		4.07%		5.10%	5.80%
Expected return on assets		8.00%		8.25%	8.25%
Rate of compensation increase		4.25%		4.25%	4.26%
		Other Benefits
		2013		2012	2011
Discount rate		3.96%		4.94%	5.66%
Expected return on assets		8.00%		8.25%	8.25%
Assumed medical cost trend rate (under age 65)		7.00%		7.00%	7.50%
Ultimate trend rate		5.00%		5.00%	5.00%
Year ultimate trend rate is reached		2019		2016	2016
Assumed medical cost trend rate (over age 65)		7.00%		7.50%	8.00%
Ultimate trend rate		5.00%		5.50%	5.50%
Year ultimate trend rate is reached		2019		2016	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 2014, the expected return on assets assumption for the plans is 8.00%.
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, 2013, 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		$	8.2		$	(6.5	)
Effect on the health care component of the accumulated postretirement benefit obligation		80.6			(65.5		)
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. Our 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. The target asset allocations for pension and other postretirement benefit plans that have significant assets are: 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(v), 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 table provides the fair values of our investments by asset class:
		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		(6.1		)	(37.9		)	(0.1		)	(44.1		)	6.1			37.9			0.1		44.1
invested as pension assets (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.
		December 31, 2012
		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		$	6.4		$	25.3		$	—		$	31.7		$	—		$	9.5		$	—	$	9.5
Equity securities:
United States equity		167.9			403			—			570.9			27.8			129			—		156.8
International equity		96			300.4			—			396.4			15.6			92.9			—		108.5
Fixed income securities:
United States government		—			100.3			—			100.3			112.7			—			—		112.7
Foreign government		—			20.4			4.1			24.5			—			—			—		—
Corporate debt		—			197.3			1			198.3			—			—			—		—
Asset-backed securities		—			56.5			0.1			56.6			—			—			—		—
Other		—			11.3			—			11.3			1.1			—			—		1.1
		270.3			1,114.50			5.2			1,390.00			157.2			231.4			—		388.6
401(h) other benefit plan assets		(7.1		)	(29.3		)	(0.1		)	(36.5		)	7.1			29.3			0.1		36.5
invested as pension assets (1)
Total (2)		$	263.2		$	1,085.20		$	5.1		$	1,353.50		$	164.3		$	260.7		$	0.1	$	425.1
-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 table sets 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			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	)
(Millions)		Foreign Government Debt			Corporate Debt			Asset-Backed Securities			Total
Beginning balance at January 1, 2012		$	5.7		$	2.1		$	—		$	7.8
Net realized and unrealized gains (losses)		0.5			0.2			—			0.7
Purchases		1.2			0.5			—			1.7
Sales		(2.0		)	(0.4		)	—			(2.4		)
Transfers into Level 3		—			—			0.1			0.1
Transfers out of Level 3		(1.3		)	(1.4		)	—			(2.7		)
Ending balance at December 31, 2012		$	4.1		$	1		$	0.1		$	5.2
Net unrealized losses related to assets still held at the end of the period		$	0.3		$	0.1		$	—		$	0.4
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 $72.3 million to our pension plans and $11.9 million to our other postretirement benefit plans in 2014, dependent upon various factors affecting us, including our liquidity position and tax law changes.
The following table shows the payments, reflecting expected future service, that we expect to make for pension and other postretirement benefits. In addition, the table shows the expected federal subsidies, provided under the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which will partially offset other postretirement benefits.
(Millions)		Pension Benefits			Other Benefits			Federal Subsidies
2014		$	125.1		$	30		$	2.2
2015		123.3			32.5			2.3
2016		126.1			35			2.5
2017		129.3			37.5			2.6
2018		125.9			39.9			2.7
2019 through 2023		657.6			234.1			15.8
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 3.8 million shares of our common stock (market value of $206.4 million) at December 31, 2013. 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 $36.4 million in 2013, $19.1 million in 2012, and $17.0 million in 2011.
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 our 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 $24.8 million at December 31, 2013, and $23.9 million at December 31, 2012.
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 $53.4 million at December 31, 2013, and $42.9 million at December 31, 2012. The costs incurred under this arrangement were $6.5 million in 2013, $3.1 million in 2012, and $2.1 million in 2011.
The deferred compensation programs are 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 $23.0 million at December 31, 2013, and $17.7 million at December 31, 2012.

STOCKBASED_COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2013
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 tax benefit recognized in income for the years ended December 31:
	(Millions)		2013				2012			2011
	Stock options		$	1.8			$	2		$	1.8
	Performance stock rights		2.7				5			3.5
	Restricted shares and restricted share units		10.2				9.7			6.1
	Nonemployee director deferred stock units		0.9				1			1
	Total stock-based compensation expense		$	15.6			$	17.7		$	12.4
	Deferred income tax benefit		$	6.2			$	7.1		$	5
	No stock-based compensation cost was capitalized during 2013, 2012, and 2011.
	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:
			2013 Grant		2012 Grant		2011 Grant
	Weighted-average fair value per stock option		$6.03		$6.30		$6.57
	Expected term		5 years		5 years		5 years
	Risk-free interest rate		0.18% – 2.11%		0.17% – 2.18%		0.27% – 3.90%
	Expected dividend yield		5.33%		5.28%		5.34%
	Expected volatility		24%		25%		25%
	A summary of stock option activity for 2013, and information related to outstanding and exercisable stock options at December 31, 2013, 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, 2012		2,046,355			$	49.25
	Granted		319,234			56
	Exercised		(797,705	)		48.56
	Forfeited		(15,510	)		56
	Expired		(2,000	)		44.73
	Outstanding at December 31, 2013		1,550,374			$	50.93		6.2		$	6.6
	Exercisable at December 31, 2013		810,086			$	49.96		4.6		$	4.3
	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, 2013. This is calculated as the difference between our closing stock price on December 31, 2013, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during 2013, 2012, and 2011 was $9.0 million, $11.0 million, and $2.8 million, respectively. The actual tax benefit realized for the tax deductions from these option exercises was $3.6 million during 2013, $4.4 million during 2012, and not significant during 2011.
	As of December 31, 2013, $1.0 million of compensation cost related to unvested and outstanding stock options was expected to be recognized over a weighted-average period of 2.4 years.
	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:
			2013		2012		2011
	Risk-free interest rate		0.13% – 1.27%		0.17% – 1.27%		0.00% – 1.27%
	Expected dividend yield		5.28% – 5.34%		5.18% – 5.34%		5.28% – 5.34%
	Expected volatility		15% – 36%		14% – 36%		21% – 36%
	A summary of the 2013 activity related to performance stock rights accounted for as equity awards is presented below:
			Performance			Weighted-Average
			Stock Rights			Fair Value *
	Outstanding at December 31, 2012		108,314			$	65.38
	Granted		22,636			48.5
	Award modifications		28,789			39.8
	Distributed		(94,758	)		72.36
	Adjustment for final payout		21,867			72.36
	Forfeited		(1,099	)		48.5
	Outstanding at December 31, 2013		85,749			$	46.62
	*	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 2013, 2012, and 2011 was $48.50, $52.70, and $49.21 per performance stock right, respectively.
	A summary of the 2013 activity related to performance stock rights accounted for as liability awards is presented below:
			Performance
			Stock Rights
	Outstanding at December 31, 2012		189,093
	Granted		90,496
	Award modifications		(28,789	)
	Distributed		(61,753	)
	Adjustment for final payout		14,255
	Forfeited		(4,398	)
	Outstanding at December 31, 2013		198,904
	The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of December 31, 2013, was $29.77 per performance stock right.
	As of December 31, 2013, $1.3 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 1.7 years.
	The total intrinsic value of performance stock rights distributed during 2013, 2012, and 2011 was $8.8 million, $4.7 million, and $6.3 million, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance stock rights during 2013, 2012, and 2011 was $3.6 million, $1.9 million, and $2.5 million, respectively.
Restricted Shares and Restricted Share Units
A summary of the 2013 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, 2012		505,690			$	48.38
Granted		196,894			55.93
Dividend equivalents		24,089			52.2
Vested and released		(208,682	)		46.36
Forfeited		(6,690	)		52.56
Outstanding at December 31, 2013		511,301			$	52.24
As of December 31, 2013, $10.2 million of 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 and restricted share unit awards vested and released during 2013, 2012, and 2011 was $11.7 million, $10.7 million, and $7.5 million, respectively. The actual tax benefit realized for the tax deductions from the vesting and release of restricted shares and restricted share units during 2013, 2012, and 2011 was $4.7 million, $4.3 million, and $3.0 million, respectively.
The weighted-average grant date fair value of restricted share units awarded during 2013, 2012, and 2011 was $55.93, $53.24, and $49.39 per unit, respectively.

COMMON_EQUITY

COMMON EQUITY	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity Note [Abstract]	'
COMMON EQUITY	'
	Common Equity
	We had the following changes to issued common stock:
	Balance at December 31, 2010		77,781,685
	Shares issued
	Stock-based compensation		204,331
	Stock Investment Plan		149,470
	Employee Stock Ownership Plan		105,845
	Rabbi trust shares		48,788
	Restricted stock shares cancelled		(2,213	)
	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
	*	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 (1)		Purchasing shares on the open market
	02/05/2013 – 02/04/2014		Issued new shares (2)
	05/01/2011 – 02/04/2013		Purchased shares on the open market
	01/01/2011 – 04/30/2011		Issued new shares (2)
	(1)	The decision was made in conjunction with the announcement of the proposed sale of UPPCO. See Note 29, Subsequent Event, for more information.
	(2)	These stock issuances increased equity $79.8 million and $22.2 million in 2013 and 2011, respectively.
	The following table reconciles common shares issued and outstanding:
			2013							2012
			Shares			Average Cost *				Shares			Average Cost *
	Common stock issued		79,919,176							78,287,906
	Less:
	Deferred compensation rabbi trust		473,796			$	48.5			385,439			$	46.03
	Total common shares outstanding		79,445,380							77,902,467
	*	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)		2013				2012				2011
	Numerator:
	Net income from continuing operations		$	350			$	294			$	230
	Discontinued operations, net of tax		4.8				(9.7		)		0.5
	Preferred stock dividends of subsidiary		(3.1		)		(3.1		)		(3.1		)
	Noncontrolling interest in subsidiaries		0.1				0.2				—
	Net income attributed to common shareholders — basic		$	351.8			$	281.4			$	227.4
	Effect of dilutive securities
	Deferred compensation		(0.1		)		—				—
	Net income attributed to common shareholders — diluted		$	351.7			$	281.4			$	227.4
	Denominator:
	Average shares of common stock — basic		79.5				78.6				78.6
	Effect of dilutive securities
	Stock-based compensation		0.4				0.5				0.5
	Deferred compensation		0.2				0.2				—
	Average shares of common stock — diluted		80.1				79.3				79.1
	Earnings per common share
	Basic		$	4.43			$	3.58			$	2.89
	Diluted		4.39				3.55				2.87
	The calculation of diluted earnings per share excluded the following weighted-average outstanding securities that had an anti-dilutive effect:
	(Millions)		2013			2012			2011
	Stock-based compensation		0.3			0.7			0.7
	Deferred compensation		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 regulated utility subsidiaries to transfer funds to us in the form of dividends. Our regulated 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.
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, 2013, these covenants restricted the payment of any dividends beyond the amount allowed under our subsidiary requirements described above.
As of December 31, 2013, total restricted net assets were $1,848.7 million. Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $143.1 million at December 31, 2013.
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.
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 2013, capital transactions with subsidiaries were as follows (in millions):
Subsidiary		Dividends To Parent				Return Of				Equity Contributions
						Capital To Parent				From Parent
ITF (1)		$	—			$	—			$	44.3
MERC		—				21				13
MGU		—				12.5				8
NSG (2)		12				—				—
UPPCO		—				6.5				—
WPS		108.6				35				200
WPS Investments, LLC (3)		71				—				13.6
Total		$	191.6			$	75			$	278.9
(1)	ITF is a direct wholly owned subsidiary of PELLC. As a result, it makes distributions to PELLC, and receives equity contributions from PELLC. Subject to applicable law, PELLC does not have any dividend restrictions or limitations on distributions to us.
(2)	NSG is a direct wholly owned subsidiary of PELLC. As a result, it makes distributions to PELLC, and receives equity contributions from PELLC. Subject to applicable law, PELLC does not have any dividend restrictions or limitations on distributions to us.
(3)	WPS Investments, LLC is a consolidated subsidiary that is jointly owned by us, WPS, and UPPCO. At December 31, 2013, we had an 86.22% ownership interest, while WPS and UPPCO had an 11.36% and 2.42% ownership interest, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2013, all equity contributions to WPS Investments, LLC were made solely by us.

PREFERRED_STOCK_OF_SUBSIDIARY

PREFERRED STOCK OF SUBSIDIARY (WPS)	12 Months Ended
	Dec. 31, 2013
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)	2013			2012
	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 our 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.

ACCUMULATED_OTHER_COMPREHENSIV

ACCUMULATED OTHER COMPREHENSIVE LOSS	12 Months Ended
	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]	'
ACCUMULATED OTHER COMPREHENSIVE LOSS	'
	Accumulated Other Comprehensive Loss
	The following table show the changes, net of tax, to our accumulated other comprehensive loss during the year ended December 31, 2013:
	Year Ended December 31, 2013								Accumulated Other Comprehensive Loss
	(Millions)		Cash Flow Hedges			Defined Benefit Plans
	Beginning 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 current period other comprehensive income		2.1			15.6			17.7
	Ending balance at December 31, 2013		$	(3.1	)	$	(20.1	)	$	(23.2	)
	The following table shows the reclassifications out of accumulated other comprehensive loss during the year ended December 31, 2013:
	(Millions)		Amount Reclassified			Affected Line Item in the Statements of Income
	Losses on cash flow hedges
	Utility commodity derivative contracts		$	0.2		Operating and maintenance expense (1)
	Nonregulated commodity derivative contracts		3.7			Nonregulated revenues
	Interest rate hedges		1.1			Interest expense
			5			Total before tax
			3.6			Tax expense
			1.4			Net of tax
	Defined benefit plans
	Amortization of prior service costs		4.3			(2)
	Amortization of net actuarial gains		(0.2		)	(2)
			4.1			Total before tax
			1.7			Tax expense
			2.4			Net of tax
	Total reclassifications		$	3.8
	(1)	This item relates to changes in the price of natural gas used to support utility operations.
	(2)	These items are included in the computation of net periodic benefit cost. See Note 17, Employee Benefit Plans, for more information.

VARIABLE_INTEREST_ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
	Dec. 31, 2013
Variable interest entities	'
VARIABLE INTEREST ENTITIES	'
	Variable Interest Entities
	Consolidated Variable Interest Entities
	In 2012, ITF formed AMP Trillium LLC as a joint venture with AMP Americas LLC. ITF owns 30% and AMP Americas LLC owns 70% of the joint venture. The joint venture was established to own and operate compressed natural gas fueling stations. The preferred source of capital funding for the joint venture is loans from ITF. We determined that the joint venture is a variable interest entity and that ITF is the primary beneficiary, which requires us to consolidate the assets, liabilities, and statements of income of the joint venture. At December 31, 2013, and December 31, 2012, our variable interests in the joint venture included an insignificant equity investment and insignificant receivables. Our maximum exposure to loss as a result of this joint venture was not significant. The carrying amounts of AMP Trillium LLC assets and liabilities included on our balance sheets were also not significant.
	In 2011, ITF formed Integrys PTI CNG Fuels LLC as a joint venture with Paper Transport Inc. The joint venture was established to own and operate compressed natural gas fueling stations. ITF and Paper Transport Inc. each initially owned 50% of the joint venture. We determined that the joint venture is a variable interest entity and that ITF was the primary beneficiary, which required us to consolidated the assets, liabilities, and statements of income of the joint venture. At December 31, 2012, our variable interests in the joint venture included an insignificant equity investment and insignificant receivables. The carrying amounts of Integrys PTI CNG Fuels LLC assets and liabilities included on our December 31, 2012, balance sheet were also not significant. In June 2013, ITF purchased Paper Transport Inc.'s 50% ownership interest of the joint venture, and it became a wholly owned subsidiary.
	Unconsolidated Variable Interest Entities
	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 compressed natural gas 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 don't have the power to direct its activities. We instead account for this variable interest entity as an equity method investment. At December 31, 2013, the assets and liabilities on our balance sheet related to our involvement with this variable interest entity consisted of insignificant receivables. Our maximum exposure to loss as a result of involvement with this variable interest entity was also not significant.
	We have a variable interest in an entity through a power purchase agreement at UPPCO that reimburses an independent power producing entity for coal costs relating to purchased energy. There is no obligation to purchase energy under this agreement. This contract for 17.5 megawatts of capacity expires in 2014. For a variety of reasons, including qualitative factors such as the length of the remaining term of the contract compared with the remaining life of the plant and the fact that we do not have the power to direct the operations and maintenance of the facility, we determined we are not the primary beneficiary of this variable interest entity and that consolidation is not required. At December 31, 2013, and December 31, 2012, the assets and liabilities on our balance sheets that related to our involvement with this variable interest entity pertained to working capital accounts and represented the amounts we owed for current deliveries of power. We have not guaranteed any debt or provided any equity support, liquidity arrangements, performance guarantees, or other commitments associated with the contract. Our maximum exposure to loss as a result of involvement with this variable interest entity was not significant.
	We also had a variable interest in Fox Energy Company LLC through a power purchase agreement at WPS that contained a tolling arrangement related to the cost of fuel. In connection with the purchase of Fox Energy Company LLC in March 2013, WPS paid $50.0 million for the early termination of this 500-megawatt agreement. See Note 3, Acquisitions, for more information regarding this purchase. We evaluated this variable interest entity for possible consolidation and determined that consolidation was not required since we were not the primary beneficiary of the variable interest entity. The assets and liabilities on our December 31, 2012, balance sheet that related to our involvement with this variable interest entity pertained to working capital accounts and represented the amounts we owed for current deliveries of power.

FAIR_VALUE

FAIR VALUE	12 Months Ended
	Dec. 31, 2013
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-13
	(Millions)		Level 1			Level 2				Level 3				Total
	Assets
	Risk Management Assets
	Utility Segments
	Natural gas contracts		$	2.4		$	7.7			$	—			$	10.1
	Financial transmission rights (FTRs)		—			—				2.1				2.1
	Petroleum product contracts		0.1			—				—				0.1
	Coal contracts		—			—				0.2				0.2
	Nonregulated Segments
	Natural gas contracts		16.3			35.2				35.6				87.1
	Electric contracts		65.1			134.9				15.9				215.9
	Total Risk Management Assets		$	83.9		$	177.8			$	53.8			$	315.5
	Investment in exchange-traded funds		$	15.9		$	—			$	—			$	15.9
	Liabilities
	Risk Management Liabilities
	Utility Segments
	Natural gas contracts		$	0.5		$	0.6			$	—			$	1.1
	FTRs		—			—				0.3				0.3
	Coal contracts		—			—				2.7				2.7
	Nonregulated Segments
	Natural gas contracts		14.3			22				25.2				61.5
	Electric contracts		98.8			58.7				3.5				161
	Total Risk Management Liabilities		$	113.6		$	81.3			$	31.7			$	226.6
	Contingent consideration related to the acquisition of Compass Energy Services (Compass) *		$	—		$	—			$	7.8			$	7.8
	*	See Note 3, Acquisitions, for more information.
			31-Dec-12
	(Millions)		Level 1			Level 2				Level 3				Total
	Assets
	Risk Management Assets
	Utility Segments
	Natural gas contracts		$	0.3		$	3.1			$	—			$	3.4
	FTRs		—			—				2.1				2.1
	Petroleum product contracts		0.2			—				—				0.2
	Coal contracts		—			—				2.5				2.5
	Nonregulated Segments
	Natural gas contracts		21.4			36.4				5.4				63.2
	Electric contracts		48.4			61.3				9.6				119.3
	Total Risk Management Assets		$	70.3		$	100.8			$	19.6			$	190.7
	Investment in exchange-traded funds		$	11.8		$	—			$	—			$	11.8
	Liabilities
	Risk Management Liabilities
	Utility Segments
	Natural gas contracts		$	1.1		$	14.1			$	—			$	15.2
	FTRs		—			—				0.1				0.1
	Coal contracts		—			—				9				9
	Nonregulated Segments
	Natural gas contracts		17.7			36.9				1.5				56.1
	Electric contracts		54.9			91.1				13.9				159.9
	Total Risk Management Liabilities		$	73.7		$	142.1			$	24.5			$	240.3
	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 2, Risk Management Activities, for more information on derivative instruments.
	The following tables show net risk management assets (liabilities) transferred between the levels of the fair value hierarchy:
			Nonregulated Segments — Natural Gas Contracts
			Year Ended December 31, 2013											Year Ended December 31, 2012
	(Millions)		Level 1			Level 2				Level 3				Level 1				Level 2				Level 3
	Transfers into Level 1 from		N/A			$	—			$	—			N/A				$	—			$	—
	Transfers into Level 2 from		$	—		N/A				—				$	—			N/A				2
	Transfers into Level 3 from		—			7.1				N/A				—				3.7				N/A
			Nonregulated Segments — Electric Contracts
			Year Ended December 31, 2013										Year Ended December 31, 2012
(Millions)		Level 1			Level 2				Level 3			Level 1				Level 2				Level 3
Transfers into Level 1 from		N/A			$	—			(0.3	)		N/A				$	—			$	—
Transfers into Level 2 from		$	—		N/A				7.3			$	—			N/A				(13.0		)
Transfers into Level 3 from		(0.2		)	8.7				N/A			—				(7.9		)		N/A
The significant unobservable inputs used in the valuations that resulted in categorization within Level 3 were as follows at December 31, 2013. The amounts and percentages 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
Utility Segments
FTRs		$	2.1		$	0.3			Market-based		Forward market prices ($/megawatt-month) (1)		$174.52
Coal contracts		0.2			2.7				Market-based		Forward market prices ($/ton) (2)		$11.73 — $14.30
Nonregulated Segments
Natural gas contracts		35.6			25.2				Market-based		Forward market prices ($/dekatherm) (3)		($1.53) — $17.30
											Probability of default(4)		11.6% — 51.0 %
Electric contracts		15.9			3.5				Market-based		Forward market prices ($/megawatt-hours) (3)		($3.30) — $9.25
											Probability of default(4)		26	%
											Option volatilities(5)		14.8% — 199.9 %
											Monthly curve shaping(6)		(33.3	)%
Contingent consideration related to the acquisition of Compass		N/A			7.8				Income-based		Growth rate(7)		(13.2)% — 49.3 %
(1)	Represents forward market prices developed using historical cleared pricing data from MISO.
(2)	Represents third-party forward market pricing.
(3)	Represents unobservable basis spreads developed using historical settled prices that are applied to observable market prices at various natural gas and electric locations, as well as unobservable adjustments made to extend observable market prices beyond the quoted period through the end of the transaction term.
(4)	Based on Moody's one-year counterparty default percentages.
(5)	Represents the range of volatilities used in the valuation of options. Volatilities are derived from an internal model using volatility curves from third parties.
(6)	Represents adjustments made to forward market price curves to disaggregate average prices of multiple periods into discrete monthly prices.
(7)	Represents the range of assumed growth rates of earnings before interest, taxes, and amortization.
Significant changes in historical settlement prices, forward commodity prices, and option volatilities would result in a directionally similar significant change in fair value. Significant changes in probability of default would result in a significant directionally opposite change in fair value. Changes in the adjustments to prices related to monthly curve shaping would affect fair value differently depending on their direction. A significant decrease in the growth rate used to value the contingent consideration would result in a directionally similar significant change in fair value. A significant increase in the growth rate would not have a significant impact on the fair value as the contingent consideration is limited to $8.0 million.
The following tables set forth a reconciliation of changes in the fair value of items categorized as Level 3 measurements:
2013		Nonregulated Segments											Utility Segments
(Millions)		Natural Gas			Electric				Contingent Consideration*				FTRs				Coal Contracts				Total
Balance at the beginning of the period		$	3.9		$	(4.3	)		$	—			$	2			$	(6.5	)		$	(4.9	)
Net realized and unrealized gains (losses) included in earnings		(1.8		)	14				(0.1		)		2				—				14.1
Net unrealized gains (losses) recorded as regulatory assets or liabilities		—			—				—				(0.3		)		0.4				0.1
Purchases		7.4			6				(7.7		)		4.9				—				10.6
Sales		—			(1.1		)		—				(0.2		)		—				(1.3		)
Settlements		(6.2		)	(3.7		)		—				(6.6		)		3.6				(12.9		)
Net transfers into Level 3		7.1			8.5				—				—				—				15.6
Net transfers out of Level 3		—			(7.0		)		—				—				—				(7.0		)
Balance at the end of the period		$	10.4		$	12.4			$	(7.8	)		$	1.8			$	(2.5	)		$	14.3
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period		$	(1.8	)	$	14			$	—			$	—			$	—			$	12.2
*	Represents the contingent consideration related to the acquisition of Compass. See Note 3, Acquisitions, for more information.
2012		Nonregulated Segments							Utility Segments
(Millions)		Natural Gas			Electric				FTRs				Coal Contracts				Total
Balance at the beginning of the period		$	8.3		$	(11.5	)		$	2.2			$	(6.9	)		$	(7.9	)
Net realized and unrealized gains (losses) included in earnings		3.8			(14.5		)	*	1.8				—				(8.9		)	*
Net unrealized gains recorded as regulatory assets or liabilities		—			—				0.2				5.8				6
Purchases		—			7.8				4.9				—				12.7
Sales		—			—				(0.1		)		—				(0.1		)
Settlements		(9.9		)	8.8				(7.0		)		(5.4		)		(13.5		)
Net transfers into Level 3		3.7			(7.9		)		—				—				(4.2		)
Net transfers out of Level 3		(2.0		)	13				—				—				11
Balance at the end of the period		$	3.9		$	(4.3	)		$	2			$	(6.5	)		$	(4.9	)
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period		$	3.8		$	(14.5	)	*	$	—			$	—			$	(10.7	)	*
*	Includes a $1.2 million net unrealized loss reported as discontinued operations. See Note 4, Discontinued Operations, for more information.
2011		Nonregulated Segments							Utility Segments
(Millions)		Natural Gas			Electric				FTRs				Coal Contracts				Total
Balance at the beginning of the period		$	30.2		$	(14.9	)		$	2.9			$	2.5			$	20.7
Net realized and unrealized gains (losses) included in earnings		32.3			(20.7		)	*	(1.7		)		—				9.9			*
Net unrealized losses recorded as regulatory assets or liabilities		—			—				(1.7		)		(8.0		)		(9.7		)
Net unrealized gains included in other comprehensive loss		—			0.6				—				—				0.6
Purchases		—			2.2				5.9				—				8.1
Sales		—			—				(0.1		)		—				(0.1		)
Settlements		(30.4		)	7				(3.1		)		(1.4		)		(27.9		)
Net transfers into Level 3		0.6			(5.9		)		—				—				(5.3		)
Net transfers out of Level 3		(24.4		)	20.2				—				—				(4.2		)
Balance at the end of the period		$	8.3		$	(11.5	)		$	2.2			$	(6.9	)		$	(7.9	)
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period		$	32.3		$	(20.7	)	*	$	—			$	—			$	11.6		*
*	Includes a $0.5 million net unrealized gain reported as discontinued operations. See Note 4, Discontinued Operations, for more information.
Realized and unrealized gains and losses included in earnings related to Integrys Energy Services’ risk management assets and liabilities are recorded through nonregulated revenue or nonregulated cost of sales on the statements of income, depending on the nature of the instrument. Unrealized gains and losses on Level 3 derivatives at the utilities 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 utility cost of fuel, natural gas, and purchased power 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-13							December 31, 2012
(Millions)		Carrying Amount			Fair Value				Carrying Amount				Fair Value
Long-term debt		$	3,056.20		$	3,031.60			$	2,245.20			$	2,425.80
Preferred stock of subsidiary		51.1			61.2				51.1				52.7

ADVERTISING_COSTS

ADVERTISING COSTS	12 Months Ended
	Dec. 31, 2013
Marketing and Advertising Expense [Abstract]	'
ADVERTISING COSTS	'
	Advertising Costs
	Capitalized direct-response advertising costs, net of accumulated amortization, totaled $5.2 million and $5.5 million as of December 31, 2013, and December 31, 2012, respectively. We did not record any significant impairments during the years ended December 31, 2013, 2012, and 2011.
	The amortization of direct-response advertising costs was $5.7 million, $3.8 million, and $1.5 million for the years ended December 31, 2013, 2012, and 2011, respectively.
	Other advertising expense was $8.5 million, $7.1 million, and $7.4 million for the years ended December 31, 2013, 2012, and 2011, respectively.

MISCELLANEOUS_INCOME

MISCELLANEOUS INCOME	12 Months Ended
	Dec. 31, 2013
Other Income and Expenses [Abstract]	'
MISCELLANEOUS INCOME	'
	Miscellaneous Income
	Total miscellaneous income was as follows at December 31:
	(Millions)	2013		2012		2011
	Equity portion of AFUDC	$	10.8	$	2.9	$	0.7
	Seams elimination charge adjustment (SECA) settlement at Integrys Energy Services	5.7		—		—
	Federal excise tax credit	4.1		—		—
	Key executive life insurance income for retired employees	2.2		2.6		2.3
	Gains (losses) on exchange-traded funds held at IBS	2.2		1.3		(0.1		)
	Other	4.8		2.5		2.4
	Total miscellaneous income	$	29.8	$	9.3	$	5.3

REGULATORY_ENVIRONMENT

REGULATORY ENVIRONMENT	12 Months Ended
	Dec. 31, 2013
Regulated Operations [Abstract]	'
REGULATORY ENVIRONMENT	'
	Regulatory Environment
	Wisconsin
	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 consists of a rate increase, offset by a portion of estimated fuel cost over-collections from customers in 2013 of the same amount. Retail electric rates were further decreased by 2012 decoupling over-collections to be returned to customers in 2014. Additionally, the retail electric rate decrease includes the deferral of the difference between the 2012 fuel refund and the 2013 rate increase discussed below. The retail natural gas rate impact consists 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 include 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 15, Commitments and Contingencies, for more information. Additionally, the order requires WPS to terminate its existing 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 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. The order reflected a 10.30% return on common equity and a common equity ratio of 51.61% in WPS's regulatory capital structure. 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 (CSAPR) 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 new 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 continued to include 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.
	2012 Rates
	In December 2011, the PSCW issued a final written order for WPS, effective January 1, 2012. The order authorized a retail electric rate increase of $8.1 million and required a retail natural gas rate decrease of $7.2 million. The retail electric rate increase was driven by projected increases in fuel and purchased power costs. However, to the extent that actual fuel and purchased power costs exceeded a 2% variance from costs included in rates, they were deferred for recovery or refund in a future rate proceeding. The rate order allowed for the netting of the 2010 electric decoupling under-collection with the 2011 electric decoupling over-collection and reflected reduced contributions to the Focus on Energy Program. The rate order also allowed for the deferral of direct CSAPR compliance costs, including carrying costs.
	Michigan
	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 requires MGU to terminate its existing 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 will not cover variations in volumes due to actual weather being different from rate case-assumed weather. The rate order also terminates MGU's existing 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 reflect a 10.15% return on common equity and a common equity ratio of 56.74% in UPPCO's regulatory capital structure. The order requires UPPCO to terminate its existing decoupling mechanism after December 31, 2013. In addition, the order requires 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. If these metrics are not achieved, or if the minimum spending level is not reached, the company may be required to refund certain amounts to customers.
	2012 UPPCO Rates
	In December 2011, the MPSC issued a final written order for UPPCO, effective January 1, 2012. The order authorized a retail electric rate increase of $4.2 million. The rates reflect a 10.20% return on common equity and a common equity ratio of 54.90% in UPPCO's regulatory capital structure. The order stated that if UPPCO filed a rate case in 2013, the earliest effective date for new final rates or self-implemented rates would be January 1, 2014. Additionally, the order required UPPCO to terminate its existing decoupling mechanism, effective December 31, 2011, and replace it with a new decoupling mechanism based on total margins, beginning January 1, 2013. The new decoupling mechanism does not cover variations in volumes due to actual weather being different from rate case-assumed weather. It includes an annual 1.5% cap based on distribution revenues approved in the rate case. UPPCO had no decoupling mechanism in place during 2012.
	In April 2012, the State of Michigan Court of Appeals ruled in a Detroit Edison proceeding that the MPSC did not have authority to approve electric decoupling mechanisms. This decision was not appealed. As a result of this ruling, UPPCO expensed $1.5 million in the first quarter of 2012 related to electric decoupling amounts previously deferred for regulatory recovery. However, in August 2012, the MPSC issued an order stating it had the authority to approve UPPCO's decoupling mechanism, as UPPCO's decoupling mechanism was authorized pursuant to an MPSC-approved settlement agreement. Therefore, in the third quarter of 2012, UPPCO reversed the $1.5 million previously expensed in the first quarter of 2012.
	Illinois
	2015 Rate Cases
	In February 2014, PGL and NSG filed applications with the ICC to increase retail natural gas rates $128.9 million and $7.1 million, respectively, with rates expected to be effective in early 2015. Both PGL's and NSG's requests reflect a 10.25% return on common equity. The requests reflect a target common equity ratio of 50.41% for NSG and 50.31% for PGL in their respective regulatory capital structures. The proposed retail natural gas rate increases are primarily driven by increased capital investments, in particular for main replacement, a loss in revenues as a result of lower projected sales volumes, increased costs of debt and common equity, and increased operating expenses. The increase in operating expenses relates to pipeline safety and other compliance work, a general wage increase, higher depreciation costs, and higher invested capital taxes. PGL's application also includes adjustments for the effects of its new Qualifying Infrastructure Plant rider, as discussed below. PGL and NSG proposed no changes to the continued use of their decoupling mechanisms and uncollectible expense true-up mechanisms.
	Qualifying Infrastructure Plant (QIP) Rider
	In July 2013, Illinois Public Act 98-0057 (formerly Senate Bill 2266), The Natural Gas Consumer, Safety & Reliability Act, became law. The Act gives PGL a cost recovery mechanism for Illinois natural gas infrastructure upgrades that will be collected through a surcharge on customer bills. Later in July 2013, the ICC adopted emergency rules to implement the law, and in December 2013, issued an order to adopt permanent rules replacing the emergency rules. 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, and the ICC approved the tariff in January 2014. The rider 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 reflect a 9.28% return on common equity and a common equity ratio of 50.43% in its regulatory capital structure. The rates for NSG reflect a 9.28% return on common equity and a common equity ratio of 50.32% in its regulatory capital structure. The rate order also allowed PGL and NSG to continue the use of their decoupling mechanisms, as affirmed by the Illinois Appellate Court (Court).
	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 Court.
	2012 Rates
	In January 2012, the ICC issued a final written order, effective January 21, 2012. The order authorized a retail natural gas rate increase of $57.8 million for PGL and $1.9 million for NSG. The rates for PGL reflected a 9.45% return on common equity and a common equity ratio of 49.00% in PGL's regulatory capital structure. The rates for NSG reflected a 9.45% return on common equity and a common equity ratio of 50.00% in NSG's regulatory capital structure. The rate order also approved a permanent decoupling mechanism.
	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 mechanism 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 mechanism 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 mechanism. 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. The Illinois Supreme Court granted the request in September 2013. The Illinois Supreme Court has no deadline by which it must act. Decoupling amounts recorded in 2012 were fully recovered and amounts in 2013 will be refunded to customers in 2014. Decoupling amounts in 2014 will continue to be accrued, absent an adverse Illinois Supreme Court decision.
	Minnesota
	2014 Rate Case
	In September 2013, MERC filed an application with the MPUC to increase retail natural gas distribution rates by $14.2 million. MERC's request reflects a 10.75% return on common equity and a common equity ratio of 50.31% in its regulatory capital structure. The request was primarily driven by general inflation, property taxes, improvements to customer service programs, efforts to expand the customer base which would have a positive rate effect in the future, and operating and maintenance projects to ensure reliability and safety for customers.
	In December 2013, the MPUC approved an interim rate order authorizing MERC a retail natural gas rate increase of $10.5 million, effective January 1, 2014. The interim rates reflect a 9.70% return on common equity and a common equity ratio of 50.31% in MERC's regulatory capital structure. The interim rate increase is subject to refund pending the final rate order, which is expected in the fourth quarter of 2014.
	2011 Rates
	In July 2012, the MPUC approved a final written order for MERC, 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.

SEGMENTS_OF_BUSINESS

SEGMENTS OF BUSINESS	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
SEGMENTS OF BUSINESS	'
	Segments of Business
	At December 31, 2013, we reported five segments, which are described below.
	•	The natural gas utility segment includes the regulated natural gas utility operations of MERC, MGU, NSG, PGL, and WPS.
	•	The electric utility segment includes the regulated electric utility operations of UPPCO and WPS.
	•	The electric transmission investment segment includes our approximate 34% ownership interest in ATC. ATC is a federally regulated electric transmission company.
	•	Integrys Energy Services is a diversified nonregulated retail energy supply and services company that primarily sells electricity and natural gas in deregulated markets. In addition, Integrys Energy Services invests in energy assets with renewable attributes, primarily distributed solar assets.
	•	The holding company and other segment includes the operations of the Integrys Energy Group holding company, ITF, 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
	2013 (Millions)		Natural Gas			Electric			Electric		Total			Integrys			Holding			Reconciling			Integrys
			Utility			Utility			Transmission		Regulated			Energy			Company			Eliminations			Energy Group
									Investment		Operations			Services			and Other						Consolidated
	Income Statement
	External revenues		$	2,093.60		$	1,332.00		$	—	$	3,425.60		$	2,166.20		$	42.8		$	—		$	5,634.60
	Intersegment revenues		11.4			0.1			—		11.5			1.3			1.4			(14.2		)	—
	Depreciation and amortization expense		136			98.6			—		234.6			11.4			21.1			(0.5		)	266.6
	Earnings from equity method investments		—			—			89.1		89.1			1.3			1.1			—			91.5
	Miscellaneous income		1.2			9.8			—		11			8.5			23.6			(13.3		)	29.8
	Interest expense		50.2			36.4			—		86.6			2			52.9			(13.3		)	128.2
	Provision (benefit) for income taxes		78.9			67.3			35.2		181.4			48			(18.6		)	—			210.8
	Net income (loss) from continuing operations		124			113.4			53.9		291.3			79.4			(20.7		)	—			350
	Discontinued operations		—			—			—		—			(1.1		)	5.9			—			4.8
	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			78.3			(14.7		)	—			351.8
	Total assets		5,672.00			3,514.40			508.5		9,694.90			989.2			1,345.90			(786.5		)	11,243.50
	Cash expenditures for long-lived assets		370			615			—		985			15.8			60			—			1,060.80
			Regulated Operations											Nonutility and Nonregulated
														Operations
	2012 (Millions)		Natural Gas Utility			Electric			Electric		Total			Integrys			Holding			Reconciling			Integrys
						Utility			Transmission		Regulated			Energy			Company			Eliminations			Energy Group
									Investment		Operations			Services			and Other						Consolidated
	Income Statement
	External revenues		$	1,662.10		$	1,297.40		$	—	$	2,959.50		$	1,217.60		$	35.3		$	—		$	4,212.40
	Intersegment revenues		9.9			—			—		9.9			0.9			1.9			(12.7		)	—
	Depreciation and amortization expense		131.8			89			—		220.8			10.3			20.1			(0.5		)	250.7
	Earnings from equity method investments		—			—			85.3		85.3			1.1			0.8			—			87.2
	Miscellaneous income		0.6			2.6			—		3.2			1.1			20.9			(15.9		)	9.3
	Interest expense		47.3			35.9			—		83.2			2.1			50.8			(15.9		)	120.2
	Provision (benefit) for income taxes		61.4			49.4			32.9		143.7			25.8			(19.7		)	—			149.8
	Net income (loss) from continuing operations		94			110.4			52.4		256.8			52.6			(15.4		)	—			294
	Discontinued operations		—			—			—		—			(11.5		)	1.8			—			(9.7		)
	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			41.1			(13.4		)	—			281.4
	Total assets		5,446.20			3,041.30			476.6		8,964.10			749.2			1,267.80			(653.7		)	10,327.40
	Cash expenditures for long-lived assets		375.1			163.9			—		539			30.9			24.4			—			594.3
			Regulated Operations											Nonutility and Nonregulated
														Operations
	2011 (Millions)		Natural Gas Utility			Electric			Electric		Total			Integrys			Holding			Reconciling			Integrys
						Utility			Transmission		Regulated			Energy			Company			Eliminations			Energy Group
									Investment		Operations			Services			and Other						Consolidated
	Income Statement
	External revenues		$	1,987.20		$	1,307.30		$	—	$	3,294.50		$	1,372.00		$	19.4		$	—		$	4,685.90
	Intersegment revenues		10.8			—			—		10.8			1.1			1.5			(13.4		)	—
	Depreciation and amortization expense		126.1			88.5			—		214.6			10.3			23.3			(0.5		)	247.7
	Earnings (losses) from equity method investments		—			—			79.1		79.1			(0.7		)	1			—			79.4
	Miscellaneous income		2.2			0.8			—		3			1			18.3			(17.0		)	5.3
	Interest expense		48.4			41.8			—		90.2			1.7			53.3			(17.0		)	128.2
	Provision (benefit) for income taxes		61.2			59.2			31.3		151.7			(7.7		)	(10.7		)	—			133.3
	Net income (loss) from continuing operations		103.9			103			47.8		254.7			(7.1		)	(17.6		)	—			230
	Discontinued operations		—			—			—		—			1			(0.5		)	—			0.5
Preferred stock dividends of subsidiary		(0.6		)	(2.5		)	—		(3.1		)	—			—			—			(3.1		)
Net income (loss) attributed to common shareholders		103.3			100.5			47.8		251.6			(6.1		)	(18.1		)	—			227.4
Total assets		5,033.00			2,982.90			439.4		8,455.30			891.5			1,215.30			(578.9		)	9,983.20
Cash expenditures for long-lived assets		199.3			84.1			—		283.4			16.7			10			—			310.1

QUARTERLY_FINANCIAL_INFORMATIO

QUARTERLY FINANCIAL INFORMATION (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)	'
	Quarterly Financial Information (Unaudited)
	(Millions, except per share amounts)		First Quarter		Second Quarter			Third Quarter			Fourth Quarter		Total
	2013
	Total 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
	2012
	Total revenues		$	1,247.90	$	839.6		$	927.7		$	1,197.20	$	4,212.40
	Operating income		153.1		87.1			108.5			118.8		467.5
	Net income from continuing operations		98.8		51.7			74.3			69.2		294
	Net income		99.7		49.6			66.3			68.7		284.3
	Net income attributed to common shareholders		98.9		48.8			65.7			68		281.4
	Earnings per common share (basic) *
	Net income from continuing operations		$	1.25	$	0.65		$	0.94		$	0.87	$	3.7
	Discontinued operations, net of tax		0.01		(0.03		)	(0.10		)	—		(0.12		)
	Earnings per common share (basic)		1.26		0.62			0.84			0.87		3.58
	Earnings per common share (diluted) *
	Net income from continuing operations		1.24		0.65			0.93			0.86		3.67
	Discontinued operations, net of tax		0.01		(0.03		)	(0.10		)	—		(0.12		)
	Earnings per common share (diluted)		1.25		0.62			0.83			0.86		3.55
	*	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. Earnings per share for the individual quarters differ by insignificant amounts from previously reported amounts due to the classification of certain asset groups as discontinued operations. See Note 4, Discontinued Operations, for more information.
	Because of various factors, the quarterly results of operations are not necessarily comparable.

SUBSEQUENT_EVENT

SUBSEQUENT EVENT	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
SUBSEQUENT EVENT	'
	Subsequent Event
	In January 2014, we reached a definitive agreement to sell all of the stock of UPPCO to Balfour Beatty Infrastructure Partners LP (BBIP) for approximately $298.8 million. This price is subject to adjustments for various items, including working capital, pension contributions, and the reimbursement of any capital expenditures made by UPPCO in 2014 prior to the sale. BBIP had approached us in early 2013 about the potential sale, and we came to an agreement in January 2014 that was approved by our Board of Directors. The transaction is subject to regulatory approvals and is expected to close later in 2014. Following the sale, we will provide various administrative and operational services to UPPCO during a transition period of 18 to 30 months.
	The following table shows the balances of the assets and liabilities of UPPCO that are included in the disposal group:
	(Millions)	31-Dec-13
	Current assets	$	26.5
	Property, plant, and equipment, net of accumulated depreciation of $88.9 million	193.8
	Other long-term assets	51.5
	Total assets	$	271.8
	Current liabilities	$	21.2
	Long-term liabilities	$	32.4
	Total liabilities	$	53.6

SCHEDULE_I_CONDENSED_PARENT_CO

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS	12 Months Ended
	Dec. 31, 2013
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)	2013				2012			2011
	Operating expense	$	8.2			$	6		$	5.9
	Operating loss	(8.2		)		(6.0		)	(5.9		)
	Equity earnings from subsidiaries	397.1				332.4			275.5
	Miscellaneous income	18.5				21.2			24.2
	Interest expense	52.1				50			52.2
	Other income	363.5				303.6			247.5
	Income before taxes	355.3				297.6			241.6
	Provision for income taxes	8.3				6.5			14.7
	Net income from continuing operations	347				291.1			226.9
	Discontinued operations from Parent Company, net of tax	0.6				1.4			(0.2		)
	Discontinued operations from subsidiaries, net of tax	4.2				(11.1		)	0.7
	Net income attributed to common shareholders	$	351.8			$	281.4		$	227.4
	Average shares of common stock
	Basic	79.5				78.6			78.6
	Diluted	80.1				79.3			79.1
	Earnings (loss) per common share (basic)
	Net income from continuing operations	$	4.37			$	3.7		$	2.89
	Discontinued operations, net of tax	0.06				(0.12		)	—
	Earnings per common share (basic)	$	4.43			$	3.58		$	2.89
	Earnings (loss) per common share (diluted)
	Net income from continuing operations	$	4.33			$	3.67		$	2.87
	Discontinued operations, net of tax	0.06				(0.12		)	—
	Earnings per common share (diluted)	$	4.39			$	3.55		$	2.87
	The accompanying notes to Integrys Energy Group's parent company financial statements are an integral part of these statements.
	B. STATEMENTS OF COMPREHENSIVE INCOME
	Year Ended December 31
	(Millions)	2013			2012			2011
	Net income attributed to common shareholders	351.8			281.4			227.4
	Other comprehensive income, net of tax:
	Cash flow hedges
	Unrealized net gains (losses) arising during period, net of tax of $ - million, $0.1 million, and	0.6			(0.1	)		0.3
	$(0.3) million, respectively
	Reclassification of net (gains) losses to net income, net of tax of $2.0 million, $(1.0) million, and	(0.9	)		2.1			1.1
	$0.2 million, respectively
	Cash flow hedges, net	(0.3	)		2			1.4
	Defined benefit plans
	Pension and other postretirement benefit adjustments arising during period, net of tax of $ - million,	1.1			0.9			—
	$(0.9) million, and $(0.7) million, respectively
	Amortization of pension and other postretirement benefit costs included in net periodic benefit cost,	(0.5	)		(0.1	)		0.2
	net of tax of $0.9 million, $0.4 million, and $0.1 million, respectively
	Defined benefit pension plans, net	0.6			0.8			0.2
	Other comprehensive income (loss) from subsidiaries, net of tax	17.4			(1.2	)		0.6
	Other comprehensive income, net of tax	17.7			1.6			2.2
	Comprehensive income attributed to common shareholders	369.5			283			229.6
	The accompanying notes to Integrys Energy Group's parent company financial statements are an integral part of these statements.
	C. BALANCE SHEETS
	At December 31
	(Millions)	2013				2012
	Assets
	Cash and cash equivalents	$	0.3			$	2.6
	Accounts receivable from related parties	32.2				32.2
	Interest receivable from related parties	4.1				4.7
	Deferred income taxes	0.6				1
	Notes receivable from related parties	84.9				34.5
	Current portion of long-term notes receivable from related parties	10				72
	Other current assets	47.8				39.4
	Current assets	179.9				186.4
Total investments in subsidiaries, at equity	4,268.50				3,839.30
Notes receivable from related parties	224.3				171.2
Property and equipment, net of accumulated depreciation of $1.4 and $1.2, respectively	4.5				4.7
Receivables from related parties	18.3				17.3
Deferred income taxes	22.3				28.1
Other long-term assets	43.9				31.7
Total assets	$	4,761.70			$	4,278.70
Liabilities and Equity
Short-term notes payable to related parties	$	165.7			$	258
Short-term debt	123.2				208.4
Current portion of long-term debt	100				—
Accounts payable to related parties	0.9				1
Interest payable to related parties	—				0.1
Accounts payable	1.2				0.6
Deferred income taxes	6.4				6
Other current liabilities	2.8				6.8
Current liabilities	400.2				480.9
Long-term debt	974.7				674.7
Deferred income taxes	110.1				81.3
Other long-term liabilities	15.4				16
Long-term liabilities	1,100.20				772
Total common shareholders' equity	3,261.30				3,025.80
Total liabilities and equity	$	4,761.70			$	4,278.70
The accompanying notes to Integrys Energy Group's parent company financial statements are an integral part of these statements.
D. STATEMENTS OF CASH FLOWS
Year Ended December 31
(Millions)	2013				2012			2011
Operating Activities
Net income attributed to common shareholders	$	351.8			$	281.4		$	227.4
Adjustments to reconcile net income to net cash provided by operating activities
Discontinued operations, net of tax	(4.8		)		9.7			(0.5		)
Equity earnings from subsidiaries	(397.1		)		(332.4		)	(275.5		)
Dividends from subsidiaries	169.6				163.9			461.3
Deferred income taxes	26.2				8.6			29.2
Other	4				4.2			3.5
Changes in working capital
Accounts receivable	(0.7		)		0.4			(0.6		)
Accounts receivable from related parties	0.6				1			0.9
Receivable from related parties	—				—			13.8
Other current assets	(7.9		)		29			12.8
Accounts payable	0.6				(0.5		)	—
Accounts payable to related parties	(0.2		)		(0.4		)	(5.0		)
Other current liabilities	(2.9		)		(3.2		)	15.9
Net cash provided by operating activities	139.2				161.7			483.2
Investing Activities
Short-term notes receivable from related parties	(50.4		)		(12.1		)	33.3
Issuance of long-term notes receivable from related parties	(35.0		)		—			(10.0		)
Repayment of long-term notes receivables from related parties	44.5				1.3			1.3
Equity contributions to subsidiaries	(234.6		)		(89.9		)	(63.2		)
Return of capital from subsidiaries	75				110.5			229.8
Net cash provided by (used for) investing activities	(200.5		)		9.8			191.2
Financing Activities
Commercial paper, net	(85.2		)		115.8			92.6
Short-term notes payable to related parties	(92.3		)		76.2			(305.2		)
Repayment of long-term notes payable to related parties	—				(21.0		)	(325.0		)
Issuance of long-term debt	400				—			—
Repayment of long-term debt	—				(100.0		)	(30.2		)
Proceeds from stock option exercises	38.7				55.8			10.3
Shares purchased for stock-based compensation	—				(75.3		)	(9.1		)
Issuance of common stock	19.2				—			7.3
Dividends paid on common stock	(202.6		)		(211.9		)	(206.4		)
Other	(18.8		)		(10.4		)	(7.4		)
Net cash provided by (used for) financing activities	59				(170.8		)	(773.1		)
Change in cash and cash equivalents	(2.3		)		0.7			(98.7		)
Cash and cash equivalents at beginning of year	2.6				1.9			100.6
Cash and cash equivalents at end of year	$	0.3			$	2.6		$	1.9
Cash paid for interest	$	44.4			$	44.4		$	44.6
Cash paid for interest - related parties	0.7				1.4			6.8
Cash received for income taxes	(3.0		)		(24.1		)	(46.3		)
The accompanying notes to Integrys Energy Group's 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 Form 10-K. The consolidated financial statements of Integrys Energy Group reflect certain businesses as discontinued operations. The condensed Parent Company statements of income and statements of cash flows report the earnings and cash flows 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.
Significant noncash transactions were:
(Millions)	2013				2012			2011
Equity issued for reinvested dividends	$	12			$	—		$	5.4
Equity issued for stock-based compensation plans	16.3				—			10.6
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 2—Fair Value of Financial Instruments – Related Parties
The following table shows the financial instruments included on the Balance Sheets of Integrys Energy Group Parent Company that are not recorded at fair value.
	2013							2012
(Millions)	Carrying Amount				Fair Value			Carrying Amount			Fair Value
Long-term notes receivable from related parties	$	224.3			$	238.5		$	171.2		$	202.1
Current portion of long-term notes receivable from related parties	10				10.2			72			73.4
Note 3—Short-term Notes Receivable – Related Parties
(Millions)	2013				2012
TEGE	23.5				—
MGU	21.8				—
MERC	20.5				15.2
IBS	10.2				—
UPPCO	8.9				11.9
ITF	—				7.4
Total	$	84.9			$	34.5
Note 4—Long-term Notes Receivable – Related Parties
(Millions)	Series		Year Due		2013			2012
WPS Leasing	8.76%		2015		$	2.4		$	2.8
	7.35%		2016		3.9			4.4
UPPCO	5.25%		2013		—			15
	6.06%		2017		15			15
	3.35%		2018		10			10
	5.04%		2020		15			15
	3.99%		2023		20			—
MERC	6.03%		2013		—			29
	6.16%		2016		29			29
	6.40%		2021		29			29
	3.99%		2023		29			—
MGU	5.72%		2013		—			28
	5.76%		2016		28			28
	5.98%		2021		28			28
	3.00%		2023		15			—
IBS	6.87%		2014		10			10
Total notes receivable - related parties					$	234.3		$	243.2
Less current portion					$	10		$	72
Total long-term notes receivable - related parties					$	224.3		$	171.2
Note 5—Short-term Notes Payable – Related Parties
(Millions)	2013				2012
PELLC	165.7				201.6
TEGE	—				49.4
IBS	—				7
Total	$	165.7			$	258

SCHEDULE_II_VALUATION_AND_QUAL

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS	12 Months Ended
	Dec. 31, 2013
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, 2013, 2012, and 2011
	(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
	2011		$	41.9	$	35	$	1.5	$	31.3	$	47.1
	2012		$	47.1	$	26.2	$	4.8	$	34.6	$	43.5
	2013		$	43.5	$	34.4	$	4.7	$	32.8	$	49.8
	-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, 2013
Accounting Policies [Abstract]	'
Nature of Operations	'
	(a) Nature of Operations—We are a holding company whose primary wholly owned subsidiaries at December 31, 2013, included MERC, MGU, NSG, PGL, UPPCO, WPS, IBS, Integrys Energy Services, and ITF. Of these subsidiaries, six are regulated natural gas and/or electric utilities (MERC, MGU, NSG, PGL, UPPCO, and WPS). IBS is a centralized service company, Integrys Energy Services is a nonregulated retail energy supply and services company, and ITF is a nonregulated compressed natural gas fueling business. In addition, we have an approximate 34% interest in ATC.
	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 term "utility" refers to the regulated activities of the electric and natural gas utility companies, while the term "nonutility" refers to the activities of the electric and natural gas utility companies that are not regulated. The term "nonregulated" refers to activities at Integrys Energy Services, ITF, the Integrys Energy Group holding company, and the PELLC holding company.
Consolidated Basis of Presentation	'
	(b) Consolidated Basis of Presentation—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 8, Equity Method Investments, for more information.
Use of Estimates	'
	(c) 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	'
	(d) 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	'
	(e) Revenue 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, 2013 and 2012, our unbilled revenues were $438.2 million and $298.2 million, respectively.
	At December 31, 2013, there were no customers or industries that accounted for more than 10% of our revenues.
	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 2013 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.
	•	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, NSG, and MGU included riders for cost recovery or refund of bad debts based on the difference between actual bad debt write-offs (as defined in the latest rate order) and the amount recovered in rates. MGU's rider was terminated after December 31, 2013.
	•	The rates of all of our utilities included decoupling mechanisms. These mechanisms differ state by state and allow utilities to recover or refund differences between the applicable actual and authorized margins. See Note 26, Regulatory Environment, for more information on decoupling.
	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 and UPPCO both sell and purchase power in the MISO market. If WPS or UPPCO is a net seller in a particular hour, the net amount is reported as revenue. If WPS or UPPCO is a net purchaser in a particular hour, the net amount is 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.
	See Note 1(g), Risk Management Activities, for more information on the classification of certain unrealized gains and losses on derivative instruments in revenues.
Inventories	'
	(f) 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 regulated 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 26% of total inventories at December 31, 2013, and 30% of total inventories at December 31, 2012. The estimated replacement cost of natural gas in inventory at December 31, 2013, and December 31, 2012, exceeded the LIFO cost by $151.7 million and $95.3 million, respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per dekatherm of $4.77 at December 31, 2013, and $3.58 at December 31, 2012.
	Inventories at Integrys Energy Services are valued at the lower of cost or market. As a result, Integrys Energy Services recorded net write-downs of $3.6 million, $3.4 million, and $11.6 million in 2013, 2012, and 2011, respectively.
Risk Management Activities	'
	(g) 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 2, 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 unless the derivative contracts contain an other-than-insignificant financing element, in which case the cash flows are classified within financing activities.
	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 shown separately as collateral on deposit, and cash collateral received from others is reflected in other current liabilities.
Emission Allowances	'
	(h) Emission Allowances—Integrys Energy Services accounts for emission allowances as intangible assets, with cash inflows and outflows related to purchases and sales of emission allowances recorded as investing activities in the statements of cash flows. 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	'
	(i) 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, repair, replacement, and renewal costs associated with items not qualifying as units of property are considered 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		2013		2012			2011
	MERC (1)		1.88	%	3.07	%		3.1	%
	MGU (2)		1.93	%	2.71	%		2.73	%
	NSG		2.44	%	2.43	%		2.42	%
	PGL		3.19	%	3.16	%		3.18	%
	UPPCO		3.29	%	3.31	%		3.33	%
	WPS – Electric		2.79	%	2.87	%		2.88	%
	WPS – Natural gas		2.19	%	2.21	%		2.22	%
	-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, repair, 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 5, Property, Plant, and Equipment, for more information.
AFUDC and capitalized interest	'
	(j) 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 2013, WPS's average AFUDC retail rate was 8.61%, and its average AFUDC wholesale rate was 2.64%. 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 2013, 2012, or 2011.
	Total AFUDC was as follows for the years ended December 31:
			2013			2012				2011
	Allowance for equity funds used during construction		$	10.8		$	2.9			$	0.7
	Allowance for borrowed funds used during construction		4.1			1				0.3
	Our nonregulated subsidiaries capitalize interest for construction projects. However, the nonregulated subsidiaries did not capitalize significant interest during 2013, 2012, and 2011.
Regulatory Assets and Liabilities	'
	(k) 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 7, Regulatory Assets and Liabilities, for more information.
Investments in Exchange-Traded Funds	'
	(l) Investments in Exchange-Traded Funds—We have investments in exchange-traded funds which are classified as trading securities for accounting purposes. These investments are used to offset gains and losses related to our deferred compensation obligations. As we do not intend to sell these investments in the near term, they are included in other long-term assets on our balance sheets. The net unrealized gains (losses) included in earnings related to the investments still held at the end of the period were $1.9 million, $1.0 million, and $(0.1) million for the years ended December 31, 2013, 2012, and 2011, respectively.
Asset impairment	'
	(m) Asset Impairment—Goodwill and other intangible assets with indefinite lives are not amortized, but 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 9, 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.
	Integrys Energy Services evaluates emission allowances for impairment by comparing the expected undiscounted future cash flows to the carrying amount. When allowances are expected to be used for generation, the allowances are grouped with the related power plant in the impairment evaluation.
Retirement of Debt	'
	(n) 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	'
	(o) 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 13, Asset Retirement Obligations, for more information.
Environmental remediation costs	'
	(p) 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 15, 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 possible 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 regulated 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 to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.
Income taxes	'
	(q) 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 regulated 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 14, Income Taxes, for more information regarding accounting for income taxes.
Guarantees	'
	(r) Guarantees—Integrys Energy Group follows the guidance of the of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. See Note 16, Guarantees, for more information.
Employee Benefits	'
	(s) 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. 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 regulated 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 segments record changes in the funded status in accumulated other comprehensive income. The regulated 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 17, Employee Benefit Plans, for more information.
Stock-Based Compensation	'
	(t) Stock-Based Compensation—In May 2010, our shareholders approved the 2010 Omnibus Incentive Compensation Plan (2010 Omnibus Plan). Under the provisions of the 2010 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 remaining or forfeited under prior plans. No more than 900,000 shares of stock, plus shares remaining or forfeited under prior plans, can be granted as full value shares in the form of performance shares, restricted stock, or restricted stock units. 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, 2013, stock options, performance stock rights, and restricted share units were outstanding under the various 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. Generally, 25% of the stock options granted vest and become exercisable each year on the anniversary of the grant date. For accounting purposes, stock options granted to retirement-eligible employees vest over a shorter period; however, there is no acceleration of when the options become exercisable. Under the provisions of the 2010 Omnibus Plan, no single employee who is our chief executive officer or 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 during any calendar year.
	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. No single employee who is our chief executive officer or one of our other three highest compensated officers (including officers of our subsidiaries) can receive a payout in excess of 250,000 performance shares during any calendar year. 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 Shares and Restricted Share Units
	Restricted shares and 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. During 2011, the last of the outstanding restricted shares vested. Only restricted share units remain outstanding at December 31, 2013. 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. Prior to January 1, 2013, under the terms of the agreement, these awards vested immediately, and therefore were expensed on the grant date. Beginning in 2013, these awards generally vest over one year. Therefore, the expense for these awards is recognized pro-rata over the year in which the grant occurs.
Earnings Per Share	'
	(u) 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, 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	'
	(v) 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. These assumptions include the risks inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model.
	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.
	We primarily determine fair value using a market-based approach that uses observable market inputs where available, and internally developed inputs only when observable market data is not readily available. For the unobservable inputs, consideration is given to the assumptions that market participants would use in valuing the asset or liability. These factors include not only the credit standing of the counterparties involved, but also the impact of our nonperformance risk on our liabilities.
	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 include inputs related to market price risk (commodity or interest rate), price volatility (for option contracts), and price correlation (for cross commodity contracts). These inputs are available through multiple sources, including exchanges and brokers. 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:
	•	While forward price curves may have been based on observable information, significant assumptions may have been made regarding monthly shaping and locational basis differentials.
	•	Certain transactions were valued using price curves that extended beyond an observable period. Assumptions were made to extrapolate prices from the last observable period through the end of the transaction term, primarily through the use of historically settled data or correlations to other 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 trading 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 the levels of the fair value hierarchy primarily due to changes in the source of data used to construct price curves as a result of changes in market liquidity. 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 23, Fair Value, for more information.
Advertising Costs	'
	(w) Advertising Costs—We expense all advertising costs as incurred, except for those capitalized as direct-response advertising. Costs associated with certain natural gas and electric direct-response advertising campaigns at Integrys Energy Services were capitalized and reported as other long-term assets on the balance sheets. The capitalized costs result in probable future benefits and were incurred to solicit sales to customers who could be shown to have responded specifically to the advertising. The asset balances for each of the direct-response advertising cost pools are reviewed quarterly for impairment. Direct-response advertising costs are amortized to operating and maintenance expense over the estimated period of benefit, which is approximately two years.
New Accounting Pronouncements	'
	(x) New Accounting Pronouncements—
	Recently Issued Accounting Guidance Not Yet Effective
	Accounting Standards Update (ASU) 2013-04, "Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date," was issued in February 2013. The guidance requires an entity to measure obligations under these arrangements, for which the total amount of the obligation is fixed at the reporting date, as the sum of the reporting entity's portion and any additional amount it expects to pay on behalf of its co-obligors. The guidance also requires additional disclosures about the nature and amount of the obligations. The guidance is effective for us for the reporting period ending March 31, 2014. Adoption of this guidance is not expected to have a significant impact on our financial statements.
	ASU 2013-11, "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists," was issued in July 2013. The guidance states that an unrecognized tax benefit should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. However, there are certain exceptions under which the unrecognized tax benefit would be presented in the balance sheet as a liability. The guidance is effective for us for the reporting period ending March 31, 2014. Adoption of this guidance is not expected to have a significant impact on our financial statements.
	ASU 2014-01, "Accounting for Investments in Qualified Affordable Housing Projects," was issued in January 2014. 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. 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, 2013
Accounting Policies [Abstract]	'
Schedule of significant noncash transactions	'
	Significant noncash transactions were:
	(Millions)		2013			2012				2011
	Construction costs funded through accounts payable		$	108.5		$	92.4			$	58.6
	Portion of Westwood sale financed with note receivable (1)		—			4				—
	Equity issued for stock-based compensation plans		16.3			—				10.6
	Equity issued for employee stock ownership plan		14.3			—				5.2
	Equity issued for reinvested dividends		12			—				5.4
	Contingent consideration related to the acquisition of Compass Energy Services (2)		7.8			—				—
	(1)	See Note 4, Discontinued Operations, for more information.
	-2	See Note 3, Acquisitions, for more information on the contingent consideration.
Schedule of annual utility composite depreciation rates	'
	Annual utility composite depreciation rates are shown below:
	Annual Utility Composite Depreciation Rates		2013		2012			2011
	MERC (1)		1.88	%	3.07	%		3.1	%
	MGU (2)		1.93	%	2.71	%		2.73	%
	NSG		2.44	%	2.43	%		2.42	%
	PGL		3.19	%	3.16	%		3.18	%
	UPPCO		3.29	%	3.31	%		3.33	%
	WPS – Electric		2.79	%	2.87	%		2.88	%
	WPS – Natural gas		2.19	%	2.21	%		2.22	%
	-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:
			2013			2012				2011
	Allowance for equity funds used during construction		$	10.8		$	2.9			$	0.7
	Allowance for borrowed funds used during construction		4.1			1				0.3

RISK_MANAGEMENT_ACTIVITIES_Tab

RISK MANAGEMENT ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2013
Risk management activities	'
Assets and liabilities from risk management activities	'
	The following tables show our assets and liabilities from risk management activities:
					31-Dec-13
	(Millions)		Balance Sheet Presentation		Assets from				Liabilities from
					Risk Management Activities				Risk Management Activities
	Utility Segments
	Nonhedge derivatives
	Natural gas contracts		Current		$	8.3			$	1
	Natural gas contracts		Long-term		1.8				0.1
	Financial transmission rights (FTRs)		Current		2.1				0.3
	Petroleum product contracts		Current		0.1				—
	Coal contracts		Current		—				1.9
	Coal contracts		Long-term		0.2				0.8
	Nonregulated Segments
	Nonhedge derivatives
	Natural gas contracts		Current		57.6				42.9
	Natural gas contracts		Long-term		29.5				18.6
	Electric contracts		Current		172				117.7
	Electric contracts		Long-term		43.9				43.3
			Current		240.1				163.8
			Long-term		75.4				62.8
	Total				$	315.5			$	226.6
					December 31, 2012
	(Millions)		Balance Sheet Presentation		Assets from				Liabilities from
					Risk Management Activities				Risk Management Activities
	Utility Segments
	Nonhedge derivatives
	Natural gas contracts		Current		$	2.5			$	14
	Natural gas contracts		Long-term		0.9				0.8
	FTRs		Current		2.1				0.1
	Petroleum product contracts		Current		0.2				—
	Coal contracts		Current		0.3				4.7
	Coal contracts		Long-term		2.2				4.3
	Cash flow hedges
	Natural gas contracts		Current		—				0.4
	Nonregulated Segments
	Nonhedge derivatives
	Natural gas contracts		Current		51.7				48.5
	Natural gas contracts		Long-term		11.5				7.6
	Electric contracts		Current		88.6				114.2
	Electric contracts		Long-term		30.7				45.7
			Current		145.4				181.9
			Long-term		45.3				58.4
	Total				$	190.7			$	240.3
Potential effect of netting arrangements on financial position 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-13
	(Millions)		Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
	Derivative assets subject to master netting or similar arrangements
	Utility segments		$	12.3			$	2.1			$	10.2
	Nonregulated segments		301.9				178.1				123.8
	Total		314.2				180.2				134
	Derivative assets not subject to master netting or similar arrangements		1.3								1.3
	Total risk management assets		$	315.5							$	135.3
	Derivative liabilities subject to master netting or similar arrangements
	Utility segments		$	1.4			$	1.4			$	—
	Nonregulated segments		222.1				178.1				44
	Total		223.5				179.5				44
	Derivative liabilities not subject to master netting or similar arrangements		3.1								3.1
	Total risk management liabilities		$	226.6							$	47.1
			31-Dec-12
	(Millions)		Gross Amount				Potential Effects of Netting, Including Cash Collateral				Net Amount
	Derivative assets subject to master netting or similar arrangements
	Utility segments		$	5.7			$	3			$	2.7
	Nonregulated segments		182.5				145.4				37.1
	Total		188.2				148.4				39.8
	Derivative assets not subject to master netting or similar arrangements		2.5								2.5
	Total risk management assets		$	190.7							$	42.3
	Derivative liabilities subject to master netting or similar arrangements
	Utility segments		$	15.3			$	3.8			$	11.5
	Nonregulated segments		215.4				159.8				55.6
	Total		230.7				163.6				67.1
	Derivative liabilities not subject to master netting or similar arrangements		9.6								9.6
	Total risk management liabilities		$	240.3							$	76.7
Cash collateral positions	'
	The following table shows our cash collateral positions:
	(Millions)		31-Dec-13				December 31, 2012
	Cash collateral provided to others:
	Related to contracts under master netting or similar arrangements		$	37.6			$	39.9
	Other		1.1				1.1
	Cash collateral received from others related to contracts under master netting or similar arrangements		0.7				0.2
Derivatives with credit risk-related contingent features that were in a liability position	'
	The following table shows the aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a liability position:
	(Millions)		31-Dec-13				December 31, 2012
	Utility segments		$	0.6			$	14
	Nonregulated segments		76.7				108.9
Collateral requirements related to credit-risk related contingent features in 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, our collateral requirement would have been as follows:
	(Millions)		31-Dec-13				December 31, 2012
	Collateral that would have been required:
	Utility segments		$	—			$	10.1
	Nonregulated segments		197.6				173.8
	Collateral already satisfied:
	Nonregulated segments — Letters of credit		4.5				3.2
	Collateral remaining:
	Utility segments		—				10.1
	Nonregulated segments		193.1				170.6
Non-hedge derivatives | Utility segments	'
Risk management activities	'
Notional volumes of outstanding derivative contracts	'
	The utilities had the following notional volumes of outstanding derivative contracts:
			31-Dec-13									December 31, 2012
	(Millions, except barrels)		Purchases			Sales			Other Transactions			Purchases			Sales	Other Transactions
	Natural gas (therms)		3,124.80			29.3			N/A			1,072.60			0.1	N/A
	FTRs (kilowatt-hours)		N/A			N/A			3,633.10			N/A			N/A	4,057.20
	Petroleum products (barrels)		102,811.00			14,000.00			N/A			62,811.00			—	N/A
	Coal (tons)		4.8			—			N/A			5.1			—	N/A
Unrealized gains (losses) related to derivatives	'
	The table below shows the unrealized gains (losses) recorded related to derivative contracts at the utilities:
	(Millions)		Financial Statement Presentation		2013				2012				2011
	Natural gas		Balance Sheet — Regulatory assets (current)		$	13.4			$	24.6			$	(11.3	)
	Natural gas		Balance Sheet — Regulatory assets (long-term)		2.3				8.3				(7.6		)
	Natural gas		Balance Sheet — Regulatory liabilities (current)		4.6				(7.8		)		8.4
	Natural gas		Balance Sheet — Regulatory liabilities (long-term)		0.3				0.3				—
	Natural gas		Income Statement — Utility cost of fuel, natural gas, and purchased power		—				0.2				—
	Natural gas		Income Statement — Operating and maintenance expense		0.1				—				—
	FTRs		Balance Sheet — Regulatory assets (current)		0.1				0.1				(0.4		)
	FTRs		Balance Sheet — Regulatory liabilities (current)		(0.4		)		0.1				(1.3		)
	Petroleum		Balance Sheet — Regulatory assets (current)		—				0.1				(0.1		)
	Petroleum		Balance Sheet — Regulatory liabilities (current)		0.1				—				—
	Petroleum		Income Statement — Operating and maintenance expense		0.1				—				(0.1		)
	Coal		Balance Sheet — Regulatory assets (current)		(0.9		)		(2.2		)		(1.3		)
	Coal		Balance Sheet — Regulatory assets (long-term)		3.5				0.1				(4.4		)
	Coal		Balance Sheet — Regulatory liabilities (current)		(0.2		)		0.3				—
	Coal		Balance Sheet — Regulatory liabilities (long-term)		(2.0		)		2.2				(3.7		)
Non-hedge derivatives | Nonregulated segments	'
Risk management activities	'
Notional volumes of outstanding derivative contracts	'
	Integrys Energy Services had the following notional volumes of outstanding derivative contracts:
			31-Dec-13						December 31, 2012
	(Millions)		Purchases			Sales			Purchases			Sales
	Commodity
	Natural gas (therms)		1,199.90			1,065.40			782			679
	Electric (kilowatt-hours)		49,186.30			30,813.80			54,127.60			31,809.60
	Foreign exchange (Canadian dollars)		—			—			0.4			0.4
Gains (losses) related to derivatives	'
	Gains (losses) related to derivative contracts are recognized currently in earnings, as shown in the table below:
	(Millions)		Income Statement Presentation		2013				2012				2011
	Natural gas		Nonregulated revenue		$	36.7			$	6.8			$	14
	Natural gas		Nonregulated cost of sales		(27.6		)		—				—
	Natural gas		Nonregulated revenue (reclassified from accumulated OCI) *		(0.3		)		(2.0		)		(2.3		)
	Electric		Nonregulated revenue		73.6				(2.0		)		(79.0		)
	Electric		Nonregulated cost of sales		10.8				—				—
	Electric		Nonregulated revenue (reclassified from accumulated OCI) *		(3.4		)		(4.3		)		(1.7		)
	Total				$	89.8			$	(1.5	)		$	(69.0	)
	*	Represents amounts reclassified from accumulated other comprehensive loss (OCI) related to cash flow hedges that were dedesignated in prior periods.
Cash flow hedges | Nonregulated segments	'
Risk management activities	'
Unrealized gain (loss) recorded in Other Comprehensive Income (Loss)	'
			Unrealized Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)
	(Millions)		2011
	Natural gas contracts		$	(2.3	)
	Electric contracts		3.8
	Total		$	1.5
Gain (loss) reclassified from Accumulated Other Comprehensive Loss into Income	'
			Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
	(Millions)		Income Statement Presentation		2013				2012				2011
	Settled/Realized
	Natural gas contracts		Nonregulated revenue		$	—			$	—			$	(9.3	)
	Electric contracts		Nonregulated revenue		—				—				4.2
	Interest rate swaps *		Interest expense		(1.1		)		(1.1		)		(1.1		)
	Hedge Designation Discontinued
	Natural gas contracts		Nonregulated revenue		—				—				(0.3		)
	Interest rate swaps		Interest expense		—				—				(0.2		)
	Total				$	(1.1	)		$	(1.1	)		$	(6.7	)
	*	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 are being reclassified to interest expense over the life of the related debt.
Gain (loss) recorded in Income (ineffective portion and amount excluded from effectiveness testing)	'
			Gain (Loss) Recognized in Income on Derivative Instruments
			(Ineffective Portion and Amount Excluded from Effectiveness Testing)
	(Millions)		Income Statement Presentation		2011
	Natural gas contracts		Nonregulated revenue		$	0.3
	Electric contracts		Nonregulated revenue		(0.3		)
	Total				$	—

ACQUISITIONS_Tables

ACQUISITIONS (Tables)	12 Months Ended
	Dec. 31, 2013
Compass Energy Services Inc	'
Acquisitions	'
Schedule of Purchase Price Allocation [Table Text Block]	'
	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
	Inventories		$	0.7
	Assets from risk management activities (current)		15.1
	Other current assets		1.1
	Assets from risk management activities (long-term)		9.3
	Other long-term assets		6.1
	Total assets acquired		$	32.3
	Liabilities assumed
	Liabilities from risk management activities (current)		$	8.3
	Other current liabilities		0.5
	Liabilities from risk management activities (long-term)		3.4
	Total liabilities assumed		$	12.2
Fox Energy Company LLC	'
Acquisitions	'
Schedule of Purchase Price Allocation [Table Text Block]	'
	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 9, Goodwill and Other Intangible Assets, for more information.

DISCONTINUED_OPERATIONS_Tables

DISCONTINUED OPERATIONS (Tables)	12 Months Ended
	Dec. 31, 2013
Combined Locks Energy Center	'
Discontinued operations	'
Carrying values of major classes of assets and liabilities classified as held for sale on balance sheets	'
	The carrying values of the major classes of assets related to Combined Locks classified as held for sale on the balance sheets were as follows at December 31:
	(Millions)		2013				2012
	Inventories		$	0.5			$	0.5
	Property, plant, and equipment, net of accumulated depreciation of $ – and $0.5, respectively		0.2				2
	Total assets		$	0.7			$	2.5
Components of discontinued operations recorded on the income statements	'
	The following table shows the components of discontinued operations related to Combined Locks recorded on the income statements:
	(Millions)		2013				2012			2011
	Nonregulated revenues		$	(0.1	)		$	0.3		$	7.9
	Nonregulated cost of sales		(0.2		)		(0.5		)	(2.0		)
	Operating and maintenance expense		(2.1		)		(0.5		)	(0.7		)
	Depreciation and amortization expense		—				(0.2		)	(0.3		)
	Taxes other than income taxes		—				(0.1		)	(0.2		)
	Income (loss) before taxes		(2.4		)		(1.0		)	4.7
	(Provision) benefit for income taxes		1.1				0.4			(1.8		)
	Discontinued operations, net of tax		$	(1.3	)		$	(0.6	)	$	2.9
WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC	'
Discontinued operations	'
Carrying values of major classes of assets and liabilities classified as held for sale on balance sheets	'
	The carrying values of the major classes of assets and liabilities related to Beaver Falls and Syracuse classified as held for sale on the balance sheet were as follows:
			As of the Closing Date				As of
	(Millions)		in March 2013				31-Dec-12
	Inventories		$	1.8			$	1.8
	Other current assets		0.2				—
	Property, plant, and equipment		5.7				5.7
	Other long-term assets		0.1				0.1
	Total assets		$	7.8			$	7.6
	Total liabilities – other current liabilities		$	0.4			$	0.2
Components of discontinued operations recorded on the income statements	'
	The following table shows the components of discontinued operations related to Beaver Falls and Syracuse recorded on the income statements:
	(Millions)		2013				2012			2011
	Nonregulated revenues		$	1.2			$	0.6		$	5
	Nonregulated cost of sales		(0.9		)		(2.0		)	(2.3		)
	Operating and maintenance expense		0.4			*	(3.5		)	(3.3		)
	Depreciation and amortization expense		—				(0.6		)	(0.7		)
	Taxes other than income taxes		(0.3		)		(1.4		)	(0.9		)
	Miscellaneous income		—				0.3			—
	Income (loss) before taxes		0.4				(6.6		)	(2.2		)
	(Provision) benefit for income taxes		(0.2		)		2.6			0.9
	Discontinued operations, net of tax		$	0.2			$	(4.0	)	$	(1.3	)
	*	Includes a $1.0 million gain on sale at closing
WPS Westwood Generation, LLC	'
Discontinued operations	'
Carrying values of major classes of assets and liabilities classified as held for sale on balance sheets	'
	The carrying values of the major classes of assets and liabilities related to Westwood classified as held for sale on the balance sheet were as follows:
			As of the Closing Date
	(Millions)		in November 2012
	Inventories		$	1
	Current assets from risk management activities		0.1
	Property, plant, and equipment		5.5
	Other long-term assets		1.1
	Total assets		$	7.7
	Total liabilities – long-term liabilities from risk management activities		$	0.1
Components of discontinued operations recorded on the income statements	'
	The following table shows the components of discontinued operations related to Westwood recorded on the income statements:
	(Millions)		2012				2011
	Nonregulated revenues		$	9.2			$	12.4
	Nonregulated cost of sales		(4.4		)		(5.6		)
	Operating and maintenance expense		(14.3		)	*	(5.7		)
	Depreciation and amortization expense		(1.0		)		(1.4		)
	Taxes other than income taxes		(0.2		)		(0.2		)
	Miscellaneous income		—				0.1
	Interest expense		(0.7		)		(0.6		)
	Loss before taxes		(11.4		)		(1.0		)
	Benefit for income taxes		4.5				0.3
	Discontinued operations, net of tax		$	(6.9	)		$	(0.7	)
	*	Includes a $0.6 million loss on sale at closing

PROPERTY_PLANT_AND_EQUIPMENT_T

PROPERTY, PLANT, AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2013
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)		2013		2012
	Electric utility		$	3,558.90	$	3,095.80
	Natural gas utility		5,428.50		5,050.80
	Total utility plant		8,987.40		8,146.60
	Less: Accumulated depreciation		3,160.90		3,006.10
	Net		5,826.50		5,140.50
	Construction work in progress		353.3		203.1
	Plant to be retired, net *		14.4		—
	Net utility plant		6,194.20		5,343.60
	Nonutility plant		142.3		120.2
	Less: Accumulated depreciation		81.6		72.3
	Net		60.7		47.9
	Construction work in progress		38		19.6
	Net nonutility plant		98.7		67.5
	Integrys Energy Services energy assets		109.8		92
	Integrys Energy Services other		19.7		17.9
	Other nonregulated		26.2		14
	Total nonregulated property, plant, and equipment		155.7		123.9
	Less: Accumulated depreciation		46.4		36.3
	Net		109.3		87.6
	Construction work in progress		8.3		3.2
	Net nonregulated property, plant, and equipment		117.6		90.8
	Total property, plant, and equipment		$	6,410.50	$	5,501.90
	*	In connection with the WPS Consent Decree with the EPA, early retirement of the Weston 1, Pulliam 5, and Pulliam 6 generating units was probable at December 31, 2013. 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 15, Commitments and Contingencies, for more information regarding the Consent Decree.

JOINTLY_OWNED_UTILITY_FACILITI1

JOINTLY OWNED UTILITY FACILITIES (Tables)	12 Months Ended
	Dec. 31, 2013
Jointly owned utility facilities	'
Schedule of WPS's share of significant jointly owned electric generating facilities	'
	The amounts were as follows at December 31, 2013:
	(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	$	576.8		$	172.8		$	41.8
	Accumulated depreciation	$	(114.6	)	$	(111.6	)	$	(28.3	)
	Construction work in progress	$	2.2		$	194.8		$	0.3

REGULATORY_ASSETS_AND_LIABILIT1

REGULATORY ASSETS AND LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2013
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)		2013		2012		See Note
	Regulatory assets (1) (2)
	Environmental remediation costs (net of insurance recoveries) (3)		$	653	$	689.7	15
	Unrecognized pension and other postretirement benefit costs (4)		428.8		810		17
	Merger and acquisition related pension and other postretirement benefit costs (5)		98.3		110.1
	Asset retirement obligations		89.5		73.9		13
	Income tax related items		55.3		47.6		14
	Termination of a tolling agreement with Fox Energy Company LLC		50		—		3
	Crane Creek production tax credits (6)		33.6		34.9
	De Pere Energy Center (7)		23.8		26.2
	Unamortized loss on reacquired debt (8)		18.5		18.2		1(n)
	Energy efficiency programs (9)		18		16.7
	Energy costs receivable through rate adjustments (10)		16		18.1
	Derivatives		11.8		30.7		1(h)
	Pension and other postretirement costs receivable through rate adjustments (11)		9.4		—		26
	Decoupling		9.3		10.6		26
	Other		26.7		37.9
	Total regulatory assets		$	1,542.00	$	1,924.60
	Balance Sheet Presentation
	Current assets		$	129.4	$	110.8
	Long-term assets		1,412.60		1,813.80
	Total regulatory assets		$	1,542.00	$	1,924.60
	-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 and UPPCO; unrecognized pension and other postretirement benefit costs at PGL and NSG; merger and acquisition related pension and other postretirement benefit costs at PGL and NSG; unamortized loss on reacquired debt at NSG, PGL, UPPCO and WPS; WPS energy efficiency programs; energy costs receivable through rate adjustments at MERC and WPS; asset retirement obligations and derivatives at all utilities; and decoupling at MGU and UPPCO. However, these regulatory assets are expected to be recovered from customers in future rates.
	(3)	As of December 31, 2013, we had not yet made cash expenditures for $600.8 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 Integrys Energy Group's 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 through 2019 for the portion related to other postretirement benefit costs.
	(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)	Prior to WPS purchasing the De Pere Energy Center in 2002, WPS had a long-term power purchase contract with the De Pere Energy Center 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.
	(8)	Amounts are recovered over the term of the replacement debt as authorized by the various commissions.
	(9)	Represents amounts recoverable from customers related to programs at the utility subsidiaries designed to meet energy efficiency standards.
	(10)	Represents the under-collection of energy costs that will be recovered from customers in the future.
	(11)	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)		2013		2012		See Note
	Regulatory liabilities
	Removal costs (1)		$	335.3	$	318.4
	Decoupling		51.7		15.9		26
	Unrecognized pension and other postretirement benefit costs		30.2		17.7		17
	Energy costs refundable through rate adjustments (2)		27.2		44.4
	Energy efficiency programs (3)		19.6		8.8
	Uncollectible expense		10.1		10		26
	Crane Creek depreciation deferral (4)		9		9.4
	Derivatives		6.6		4.3		1(h)
	Fox Energy Center (5)		5.6		—		3
	Other		7.1		7.2
	Total regulatory liabilities		$	502.4	$	436.1
	Balance Sheet Presentation
	Current liabilities		$	101.5	$	65.6
	Long-term liabilities		400.9		370.5
	Total regulatory liabilities		$	502.4	$	436.1
	(1)	Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment.
	(2)	Represents the over-collection of energy costs that will be refunded to customers in the future.
	(3)	Represents amounts refundable to customers related to programs at the utility subsidiaries designed to meet energy efficiency standards.
	(4)	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.
	(5)	Represents the deferral of incremental costs associated with WPS owning and operating the Fox Energy Center, which was purchased in March 2013. The deferral does not include an allowance for earnings on shareholders' investment of $26.7 million, in accordance with GAAP requirements, which has created the net regulatory liability.

EQUITY_METHOD_INVESTMENTS_Tabl

EQUITY METHOD INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule of equity method investments	'
Schedule of carrying amount of investments accounted for under the equity method	'
	Investments in corporate joint ventures and other companies accounted for under the equity method at December 31, 2013, and 2012 were as follows:
	(Millions)	2013		2012
	ATC	$	508.4	$	476.6
	INDU Solar Holdings, LLC	24.7		27.5
	WRPC	7		7.3
	Other	0.8		0.8
	Equity method investments	$	540.9	$	512.2
ATC, INDU Solar Holdings, LLC, and WRPC	'
Schedule of 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, and WRPC, are included in the tables below:
	(Millions)	2013		2012		2011
	Income statement data
	Revenues	$	642	$	618.3	$	575.5
	Operating expenses	306.2		292.1		269.6
	Other expense	83.7		85.1		81.5
	Net income	$	252.1	$	241.1	$	224.4
	Earnings from equity method investments	$	91.4	$	87.2	$	79.4
Summarized balance sheet data of significant equity method investments	'
	(Millions)	31-Dec-13		31-Dec-12
	Balance sheet data
	Current assets	$	90.2	$	81.1
	Noncurrent assets	3,587.20		3,347.40
	Total assets	$	3,677.40	$	3,428.50
	Current liabilities	$	383.6	$	253
	Long-term debt	1,559.10		1,559.50
	Other noncurrent liabilities	134.4		103.5
	Shareholders’ equity	1,600.30		1,512.50
	Total liabilities and shareholders’ equity	$	3,677.40	$	3,428.50
ATC	'
Schedule of equity method investments	'
Schedule of changes to Integrys Energy Group's equity method investment	'
	The following table shows changes to our investment in ATC during the years ended December 31:
	(Millions)	2013		2012		2011
	Balance at the beginning of period	$	476.6	$	439.4	$	416.3
	Add: Earnings from equity method investment	89.1		85.3		79.1
	Add: Capital contributions	13.7		20.4		8.5
	Less: Dividends received	71		68.5		64.5
	Balance at the end of period	$	508.4	$	476.6	$	439.4
Schedule of related party transactions	'
	The related party transactions recorded by the regulated electric utilities during the years ended December 31 were as follows:
	(Millions)	2013		2012		2011
	Total charges to ATC for services and construction	$	11.3	$	12.5	$	13.5
	Total costs for network transmission service provided by ATC	104.9		100.3		102.7
INDU Solar Holdings, LLC	'
Schedule of equity method investments	'
Schedule of changes to Integrys Energy Group's equity method investment	'
	The following table shows changes to our investment in INDU Solar Holdings, LLC during the years ended December 31:
	(Millions)	2013		2012		2011
	Balance at the beginning of period	$	27.5	$	28.4	$	0.1
	Add: Earnings (loss) from equity method investment	1.3		1.1		(0.7		)
	Add: Capital contributions	—		7		29
	Less: Return of capital to partners	4.1		9		—
	Balance at the end of period	$	24.7	$	27.5	$	28.4
WRPC	'
Schedule of equity method investments	'
Schedule of changes to Integrys Energy Group's equity method investment	'
	The following table shows changes to our investment in WRPC during the years ended December 31:
	(Millions)	2013		2012		2011
	Balance at the beginning of period	$	7.3	$	7.7	$	8.1
	Add: Earnings from equity method investment	1		0.8		0.9
	Less: Dividends received	1.3		1.2		1.3
	Balance at the end of period	$	7	$	7.3	$	7.7
Schedule of related party transactions	'
	The related party transactions recorded by WPS during the years ended December 31 were as follows:
	(Millions)	2013		2012		2011
	Charges to WRPC for operations	$	0.9	$	0.8	$	0.7
	Purchases of energy from WRPC	3.7		5		4.9
	Net proceeds from WRPC sales of energy to MISO	—		2.9		4.7

GOODWILL_AND_OTHER_INTANGIBLE_1

GOODWILL AND OTHER INTANGIBLE ASSETS (Tables)	12 Months Ended
	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]	'
Schedule of changes to the carrying amount of goodwill	'
	The following table shows changes to our gross amount of goodwill and accumulated impairment losses by segment for the years ended December 31, 2013, and 2012:
			Natural Gas Utility						Integrys Energy Services				Holding Company and Other						Total
	(Millions)		2013			2012			2013		2012		2013			2012			2013			2012
	Balance as of January 1
	Gross goodwill		$	933.5		$	933.5		$	6.6	$	6.6	$	15.8		$	15.9		$	955.9		$	956
	Accumulated impairment losses		(297.6		)	(297.6		)	—		—		—			—			(297.6		)	(297.6		)
	Net goodwill		635.9			635.9			6.6		6.6		15.8			15.9			658.3			658.4
	Adjustment to Trillium and Pinnacle purchase price		—			—			—		—		—			(0.1		)	—			(0.1		)
	Adjustment to ITF patents/intellectual property *		—			—			—		—		3.8			—			3.8			—
	Balance as of December 31
	Gross goodwill		933.5			933.5			6.6		6.6		19.6			15.8			959.7			955.9
	Accumulated impairment losses		(297.6		)	(297.6		)	—		—		—			—			(297.6		)	(297.6		)
	Net goodwill		$	635.9		$	635.9		$	6.6	$	6.6	$	19.6		$	15.8		$	662.1		$	658.3
	*	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.
Identifiable intangible assets other than goodwill	'
			31-Dec-13								31-Dec-12
	(Millions)		Gross Carrying			Accumulated			Net Carrying		Gross Carrying		Accumulated			Net Carrying
			Amount			Amortization			Amount		Amount		Amortization			Amount
	Amortized intangible assets
	Customer-related (1)		$	26.8		$	(15.7	)	$	11.1	$	22.4	$	(14.7	)	$	7.7
	Contractual service agreements (2)		15.6			(1.8		)	13.8		—		—			—
	Renewable energy credits (3)		8.4			—			8.4		3.1		—			3.1
	Compressed natural gas fueling contract assets (4)		5.6			(2.7		)	2.9		5.6		(1.3		)	4.3
	Customer-owned equipment modifications (5)		4			(0.9		)	3.1		4		(0.5		)	3.5
	Natural gas and electric contract assets (6)		3.9			(0.5		)	3.4		—		—			—
	Nonregulated easements (7)		3.7			(1.1		)	2.6		3.8		(0.9		)	2.9
	Patents/intellectual property (8)		3.4			(0.5		)	2.9		7.2		(0.3		)	6.9
	Other		0.5			(0.3		)	0.2		0.5		(0.2		)	0.3
	Total		$	71.9		$	(23.5	)	$	48.4	$	46.6	$	(17.9	)	$	28.7
	Unamortized intangible assets
	MGU trade name		$	5.2		$	—		$	5.2	$	5.2	$	—		$	5.2
	Trillium trade name (9)		3.5			—			3.5		3.5		—			3.5
	Pinnacle trade name (9)		1.5			—			1.5		1.5		—			1.5
	Total intangible assets		$	82.1		$	(23.5	)	$	58.6	$	56.8	$	(17.9	)	$	38.9
	(1)	Represents customer relationship assets associated with PELLC’s former nonregulated retail natural gas and electric operations, ITF's compressed natural gas fueling operations, and Compass Energy Services. See Note 3, Acquisitions, for more information regarding Integrys Energy Services' acquisition of Compass Energy Services. The remaining weighted-average amortization period for customer-related intangible assets at December 31, 2013, was approximately 11 years.
	(2)	Represents contractual service agreements related to maintenance on the combustion turbine generators at the Fox Energy Center. The remaining amortization period for these intangible assets at December 31, 2013, was approximately six years.
	(3)	Used at Integrys Energy Services to comply with state Renewable Portfolio Standards and to support customer commitments.
	(4)	Represents the fair value of ITF contracts acquired in September 2011. The remaining amortization period at December 31, 2013, was approximately seven years.
	(5)	Relates to modifications made by Integrys Energy Services 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, 2013, of approximately ten years.
	(6)	Represents the fair value of certain natural gas and electric customer contracts acquired by Integrys Energy Services during 2013 that were not considered to be derivative instruments. The remaining amortization period for these intangible assets at December 31, 2013, was approximately four years.
	(7)	Relates to easements supporting a pipeline at Integrys Energy Services. The easements are amortized on a straight-line basis, with a remaining amortization period at December 31, 2013, of approximately ten years.
	(8)	Represents the fair value of patents/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, 2013, was approximately nine years.
	(9)	Trillium USA (Trillium) and Pinnacle CNG Systems (Pinnacle) are wholly owned subsidiaries of ITF.
Intangible asset amortization expense for the next five fiscal years	'
	Amortization expense for the next five fiscal years is estimated to be:
			For the Year Ending December 31
	(Millions)		2014			2015			2016		2017		2018
	Amortization to be recorded in nonregulated cost of sales		$	3.4		$	2		$	1.1	$	0.9	$	0.8
	Amortization to be recorded in depreciation and amortization expense		4.3			4.2			4		3.9		3.8

LEASES_Tables

LEASES (Tables)	12 Months Ended
	Dec. 31, 2013
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)
	2014	$	6.7
	2015	6.4
	2016	6.4
	2017	7.4
	2018	7.3
	Later years	59.4
	Total	$	93.6

SHORTTERM_DEBT_AND_LINES_OF_CR1

SHORT-TERM DEBT AND LINES OF CREDIT (Tables)	12 Months Ended
	Dec. 31, 2013
Short-term Debt [Abstract]	'
Schedule of short-term borrowings	'
	Information about our short-term borrowings was as follows:
	(Millions, except percentages)		2013				2012				2011
	Commercial paper
	Amount outstanding at December 31 (1)		$	326			$	482.4			$	303.3
	Average interest rate on amount outstanding at December 31		0.22%				0.4		%		0.31		%
	Average amount outstanding during the year (2)		$	378.4			$	326.3			$	134.9
	Short-term notes payable (3)
	Average amount outstanding during the year (2)		$	130.4		(4)	$	—			$	3.6
	(1)	Maturity dates ranged from January 2, 2014, through January 27, 2014.
	(2)	Based on daily outstanding balances during the year.
	(3)	We did not have short-term notes payable outstanding at December 31, 2013, 2012, and 2011.
	(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		2013				2012
	Revolving credit facility (Integrys Energy Group)		5/17/14		$	275			$	275
	Revolving credit facility (Integrys Energy Group)		5/17/16		200				200
	Revolving credit facility (Integrys Energy Group)		6/13/17		635				635
	Revolving credit facility (WPS)		5/17/14		135				135
	Revolving credit facility (WPS)		6/13/17		115				115
	Revolving credit facility (PGL)		6/13/17		250				250
	Total short-term credit capacity				$	1,610.00			$	1,610.00
	Less:
	Letters of credit issued inside credit facilities				$	52.4			$	25.5
	Commercial paper outstanding				326				482.4
	Available capacity under existing agreements				$	1,231.60			$	1,102.10

LONGTERM_DEBT_Tables

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Disclosure of long-term debt instruments	'
						31-Dec
	(Millions)					2013			2012
	WPS First Mortgage Bonds (1)
		Series		Year Due
		7.125	%	2023		$	0.1		$	0.1
	WPS Senior Notes (1) (2)
		Series		Year Due
		4.8	%	2013		—			125
		3.95	%	2013		—			22
		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			—
	PGL First and Refunding Mortgage Bonds (3)
		Series		Year Due
		KK, 5.00%		2033		—			50
		NN-2, 4.625%		2013		—			75
		QQ, 4.875%		2038	Mandatory interest reset date on November 1, 2018	75			75
		RR, 4.30%		2035	Mandatory interest reset date on June 1, 2016	50			50
		SS, 7.00%		2013		—			45
		TT, 8.00%		2018		5			5
		UU, 4.63%		2019		75			75
		VV, 2.125%		2030	Mandatory interest reset date on July 1, 2014	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			—
		AAA, 3.96%		2043		220			—
	NSG First Mortgage Bonds (4)
		Series		Year Due
		N-2, 4.625%		2013		—			40
		O, 7.00%		2013		—			6.5
		P, 3.43%		2027		28			28
		Q, 3.96%		2043		54			—
	Integrys Energy Group Unsecured Senior Notes (5)
		Series		Year Due
		7.27	%	2014		100			100
		8	%	2016		55			55
		4.17	%	2020		250			250
	Integrys Energy Group Unsecured Junior Subordinated Notes (6)
		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			—
	Total					3,056.90			2,246.40
	Unamortized discount on debt					(0.7		)	(1.2		)
	Total debt					3,056.20			2,245.20
	Less current portion					100			313.5
	Total long-term debt					$	2,956.20		$	1,931.70
	-1	WPS's First Mortgage Bonds and Senior Notes are subject to the terms and conditions of WPS's First Mortgage Indenture. 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.
	-2	In December 2013, WPS’s $125.0 million of 4.80% Senior Notes matured, and the outstanding principal balance was repaid.
	In November 2013, WPS issued $450.0 million of 4.752% Senior Notes. These notes are due in November 2044.
	In February 2013, WPS’s $22.0 million of 3.95% Senior Notes matured, and the outstanding principal balance was repaid.
	-3	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 and the City of Chicago have 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 2013, PGL’s $45.0 million 7.00% Series SS First and Refunding Mortgage Bonds matured, and the outstanding principal balance was repaid.
	In August 2013, PGL issued $220.0 million of 3.96% Series AAA First and Refunding Mortgage Bonds. These bonds are due in August 2043.
	In May 2013, PGL’s $75.0 million 4.625% Series NN-2 First and Refunding Mortgage Bonds matured, and the outstanding principal balance was repaid.
	In April 2013, PGL bought back its $50.0 million of 5.00% Series KK First and Refunding Mortgage Bonds that were due in February 2033. In the same month, PGL issued $50.0 million of 4.00% Series ZZ First and Refunding Mortgage Bonds. These bonds are due in February 2033.
	-4	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.
	NSG has used 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 NSG. In return, NSG issued equal principal amounts of certain collateralized First Mortgage Bonds.
	In November 2013, NSG’s $6.5 million 7.00% Series O First Mortgage Bonds matured, and the outstanding principal balance was repaid.
In May 2013, NSG’s $40.0 million 4.625% Series N-2 First Mortgage Bonds matured, and the outstanding principal balance was repaid. In the same month, NSG issued $54.0 million of 3.96% Series Q First Mortgage Bonds. These Bonds are due in May 2043.
-5	In June 2014, our 7.27% Unsecured Senior Notes will mature. As a result, the $100.0 million balance of these notes was included in the current portion of long-term debt on our balance sheet at December 31, 2013.
-6	In August 2013, we issued $400.0 million of Junior Subordinated Notes. These notes are considered hybrid instruments with a combination of debt and equity characteristics. Interest is payable quarterly at the stated rate of 6.00% for the first ten years, after which time it changes to a floating rate. These notes are due in August 2073.
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
	2014		$	100
	2015		125
	2016		105
	2017		125
	2018		5
	Later years		2,596.90
	Total		$	3,056.90

ASSET_RETIREMENT_OBLIGATIONS_T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Disclosure of changes in asset retirement obligations	'
	The following table shows changes to our asset retirement obligations through December 31, 2013:
	(Millions)		Utilities				Integrys Energy Services		Total
	Asset retirement obligations at December 31, 2010		$	320.9			$	—	$	320.9
	Accretion		17.1				—		17.1
	Additions and revisions to estimated cash flows		64.4			*	0.5		64.9
	Settlements		(5.7		)		—		(5.7		)
	Asset retirement obligations at December 31, 2011		396.7				0.5		397.2
	Accretion		20.3				0.1		20.4
	Additions and revisions to estimated cash flows		(2.4		)		1.6		(0.8		)
	Settlements		(5.6		)		—		(5.6		)
	Asset retirement obligations at December 31, 2012		409				2.2		411.2
	Accretion		20.8				0.1		20.9
	Additions and revisions to estimated cash flows		70.1			*	0.5		70.6
	Settlements		(11.2		)		—		(11.2		)
	Asset retirement obligations at December 31, 2013		$	488.7			$	2.8	$	491.5
	*	Revisions were made to estimated cash flows related to asset retirement obligations primarily due to an increase in the weighted average cost to retire a foot of natural gas distribution pipe at PGL.

INCOME_TAXES_Tables

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Schedule of principal components of deferred income tax assets and liabilities recognized in the balance sheets	'
	(Millions)	2013				2012
	Deferred income tax assets
	Tax credit carryforwards	$	113.5			$	105.1
	Price risk management	13				59.6
	Other	98.5				76.5
	Total deferred income tax assets	$	225			$	241.2
	Valuation allowance	(8.2		)		(7.2		)
	Net deferred income tax assets	$	216.8			$	234
	Deferred income tax liabilities
	Plant-related	$	1,373.80			$	1,215.70
	Employee benefits	79.6				49.1
	Regulatory deferrals	78.8				60.8
	Other	43.5				47.9
	Total deferred income tax liabilities	$	1,575.70			$	1,373.50
	Total net deferred income tax liabilities	$	1,358.90			$	1,139.50
	Balance sheet presentation
	Current deferred income tax assets	$	31.4			$	64.3
	Long-term deferred income tax liabilities	1,390.30				1,203.80
	Net deferred income tax liabilities	$	1,358.90			$	1,139.50
Schedule of components of foreign and domestic income included in income before taxes	'
	Income before taxes includes the following components of foreign and domestic income:
		For the Years Ended December 31
	(Millions)	2013				2012				2011
	Domestic	$	560.8			$	443.9			$	363.4
	Foreign	—				(0.1		)		(0.1		)
	Total income before taxes	$	560.8			$	443.8			$	363.3
Schedule of components of the provision for income tax expense	'
	The components of the provision for income taxes were as follows:
	(Millions)	2013				2012				2011
	Current provision
	Federal	$	7.8			$	3.5			$	(44.2	)
	State	5.9				0.4				6
	Foreign	0.1				(0.1		)		(0.2		)
	Total current provision	13.8				3.8				(38.4		)
	Deferred provision
	Federal	174.8				128.3				158.7
	State	14.9				20.1				14.6
	Foreign	—				—				0.1
	Total deferred provision	189.7				148.4				173.4
	Investment tax credits, net	8.4				5.2				(1.1		)
	Penalties	(0.1		)		(0.3		)		0.7
	Unrecognized tax benefits	0.4				(3.0		)		0.9
	Interest	(1.4		)		(4.3		)		(2.2		)
	Total provision for income taxes related to continuing operations	210.8				149.8				133.3
	Total provision for income taxes related to discontinued operations	(6.9		)		(9.3		)		1.1
	Total	$	203.9			$	140.5			$	134.4
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 before taxes.
		2013							2012						2011
	(Millions, except for percentages)	Rate			Amount				Rate			Amount			Rate		Amount
	Statutory federal income tax	35	%		$	196.3			35	%		$	155.4		35	%	$	127.2
	State income taxes, net	3.9			21.8				4.8			21.1			5.3		19.1
	Federal tax credits	(0.1	)		(0.5		)		(1.7	)		(7.6		)	(2.0	)	(7.1		)
	Benefits and compensation	(0.7	)		(4.2		)		(2.1	)		(9.4		)	(2.3	)	(8.4		)
	Other differences, net	(0.5	)		(2.6		)		(2.2	)		(9.7		)	0.7		2.5
	Effective income tax	37.6	%		$	210.8			33.8	%		$	149.8		36.7	%	$	133.3
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)	2013				2012				2011
	Balance at January 1	$	11.3			$	22.4			$	30.4
	Increase related to tax positions taken in prior years	2.2				0.9				3.1
	Decrease related to tax positions taken in prior years	(8.7		)		(6.7		)		(1.6		)
	Increase related to tax positions taken in current year	0.3				0.6				0.9
	Decrease related to settlements	(1.5		)		(5.7		)		(9.4		)
	Decrease related to lapse of statutes	—				(0.2		)		(1.0		)
	Balance at December 31	$	3.6			$	11.3			$	22.4
Schedule of the earliest open tax years that were subject to examination by state taxing authorities by major operating jurisdictions	'
	As of December 31, 2013, we were subject to examination by state or local tax authorities for the 2008 through 2012 tax years in our major state operating jurisdictions as follows:
	State	Year
	Illinois	2008
	Michigan	2008
	Minnesota	2011
	Wisconsin	2009

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013, including those of our subsidiaries.
						Payments Due By Period
	(Millions)		Date Contracts Extend Through	Total Amounts Committed		2014		2015		2016		2017		2018		Later Years
	Natural gas utility supply and transportation		2028	$	845.9	$	181.2	$	169.6	$	158.4	$	122	$	71.7	$	143
	Electric utility
	Purchased power *		2029	772.3		80.6		32.8		28.8		27.6		27		575.5
	Coal supply and transportation		2018	99.5		46.3		31		12		6.7		3.5		—
	Nonregulated electricity and natural gas supply		2020	697.9		492.8		145.2		49.9		8.1		1.5		0.4
	Total			$	2,415.60	$	800.9	$	378.6	$	249.1	$	164.4	$	103.7	$	718.9
	*	Includes minimum future commitments for UPPCO related to power purchase contracts of $9.9 million for the years 2014 to 2023. In January 2014, we announced an agreement to sell UPPCO. See Note 29, Subsequent Event, for more information.

GUARANTEES_Tables

GUARANTEES (Tables)	12 Months Ended
	Dec. 31, 2013
Guarantees [Abstract]	'
Schedule of outstanding guarantees	'
	The following table shows our outstanding guarantees:
			Total Amounts Committed		Expiration
	(Millions)		at December 31, 2013		Less Than 1 Year		1 to 3 Years		Over 3 Years
	Guarantees supporting commodity transactions of subsidiaries (1)		$	597.4	$	375.1	$	2.2	$	220.1
	Standby letters of credit (2)		55.8		45.1		10.6		0.1
	Surety bonds (3)		21.9		21.9		—		—
	Other guarantees (4)		56.3		1.2		1.5		53.6
	Total guarantees		$	731.4	$	443.3	$	14.3	$	273.8
	(1)	Consists of (a) $430.3 million, $5.0 million, and $2.0 million to support the business operations of Integrys Energy Services, IBS, and UPPCO, respectively, and (b) $111.5 million and $48.6 million related to natural gas supply at MERC and MGU, 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 $53.8 million issued to support Integrys Energy Services’ operations and $2.0 million issued to support ITF, MERC, MGU, NSG, PGL, UPPCO, 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) $35.0 million to support Integrys Energy Services' future payment obligations related to its distributed solar generation projects. This guarantee is not reflected on our balance sheets; (b) $10.0 million related to the sale agreement for Integrys Energy Services’ Texas retail marketing business, which included a number of customary representations, warranties, and indemnification provisions. 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) $3.0 million related to the sale of WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC. Integrys Energy Services' guaranteed the buyer's performance under certain derivative contracts that the buyer assumed from WPS Empire State, Inc. in conjunction with the sale. See Note 4, Discontinued Operations, for more information; (d) $2.4 million related to the performance of an operating and maintenance agreement by ITF; and (e) $5.9 million related to other indemnifications primarily for workers compensation coverage. The amounts discussed in items (c) through (e) above are not reflected on our balance sheets.

EMPLOYEE_BENEFIT_PLANS_Tables

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2013
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)		2013			2012			2013			2012
	Change in benefit obligation
	Obligation at January 1		$	1,784.90		$	1,563.10		$	621		$	576.8
	Service cost		30.2			46			24.9			20.8
	Interest cost		71.2			78			24.8			28.5
	Plan amendments		—			—			0.2			—
	Actuarial (gain) loss, net		(153.1		)	196.6			(73.4		)	14.3
	Participant contributions		—			—			10.6			10.6
	Benefit payments		(91.5		)	(98.8		)	(34.0		)	(32.1		)
	Federal subsidy on benefits paid		—			—			2.2			2.1
	Obligation at December 31		$	1,641.70		$	1,784.90		$	576.3		$	621
	Change in fair value of plan assets
	Fair value of plan assets at January 1		$	1,348.10		$	1,099.50		$	424.4		$	285.5
	Actual return on plan assets		205.4			173.6			57.8			46.3
	Employer contributions		65.7			173.8			11.3			114.1
	Participant contributions		—			—			10.6			10.6
	Benefit payments		(91.5		)	(98.8		)	(34.0		)	(32.1		)
	Fair value of plan assets at December 31		$	1,527.70		$	1,348.10		$	470.1		$	424.4
	Funded Status at December 31		$	(114.0	)	$	(436.8	)	$	(106.2	)	$	(196.6	)
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)		2013			2012			2013			2012
	Current liabilities		$	9		$	7.9		$	0.2		$	0.3
	Long-term liabilities		105			428.9			106			196.3
	Total liabilities		$	114		$	436.8		$	106.2		$	196.6
Information for pension plans with an accumulated benefit obligation in excess of plan assets	'
	Information for the qualified pension plans with an accumulated benefit obligation in excess of plan assets is presented in the following table as of December 31:
	(Millions)		2013			2012
	Projected benefit obligation		$	65.4		$	1,784.90
	Accumulated benefit obligation		63			1,594.70
	Fair value of plan assets		—			1,348.10
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)		2013			2012			2013			2012
	Accumulated other comprehensive loss (pre-tax) (1)
	Net actuarial loss		$	33.3		$	59.1		$	0.7		$	1.3
	Prior service costs (credits)		—			0.2			(0.2		)	(0.6		)
	Total		$	33.3		$	59.3		$	0.5		$	0.7
	Net regulatory assets (2)
	Net actuarial loss		$	399.3		$	683.1		$	8.9		$	117.3
	Prior service costs (credits)		2.4			6.2			(12.0		)	(14.3		)
	Total		$	401.7		$	689.3		$	(3.1	)	$	103
	-1	Amounts related to the nonregulated entities are included in accumulated other comprehensive loss.
	-2	Amounts related to the regulated utilities are recorded as 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 2014:
	(Millions)		Pension Benefits			Other Benefits
	Net actuarial losses		$	34.6		$	2.5
	Prior service costs (credits)		0.6			(2.4		)
	Total 2014 – estimated amortization		$	35.2		$	0.1
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)		2013			2012			2011			2013			2012			2011
	Service cost		$	30.2		$	46		$	41.4		$	24.9		$	20.8		$	19
	Interest cost		71.2			78			80.1			24.8			28.5			29.5
	Expected return on plan assets		(105.5		)	(107.9		)	(100.0		)	(30.6		)	(28.2		)	(21.4		)
	Amortization of transition obligation		—			—			—			—			0.3			0.3
	Amortization of prior service cost (credit)		4			5			5.3			(2.5		)	(3.4		)	(3.9		)
	Amortization of net actuarial loss		56.7			34			18.1			8.4			6.6			4
	Net periodic benefit cost		$	56.6		$	55.1		$	44.9		$	25		$	24.6		$	27.5
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
			2013		2012	2013		2012
	Discount rate		4.92%		4.07%	4.83%		3.96%
	Rate of compensation increase		4.24%		4.25%	N/A		N/A
	Assumed medical cost trend rate		N/A		N/A	6.50%		7.00%
	Ultimate trend rate		N/A		N/A	5.00%		5.00%
	Year ultimate trend rate is reached		N/A		N/A	2019		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
			2013		2012	2011
	Discount rate		4.07%		5.10%	5.80%
	Expected return on assets		8.00%		8.25%	8.25%
	Rate of compensation increase		4.25%		4.25%	4.26%
			Other Benefits
			2013		2012	2011
	Discount rate		3.96%		4.94%	5.66%
	Expected return on assets		8.00%		8.25%	8.25%
	Assumed medical cost trend rate (under age 65)		7.00%		7.00%	7.50%
	Ultimate trend rate		5.00%		5.00%	5.00%
	Year ultimate trend rate is reached		2019		2016	2016
	Assumed medical cost trend rate (over age 65)		7.00%		7.50%	8.00%
	Ultimate trend rate		5.00%		5.50%	5.50%
	Year ultimate trend rate is reached		2019		2016	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, 2013, 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		$	8.2		$	(6.5	)
	Effect on the health care component of the accumulated postretirement benefit obligation		80.6			(65.5		)
Investments recorded at fair value, by asset class	'
	The following table provides the fair values of our investments by asset class:
			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		(6.1		)	(37.9		)	(0.1		)	(44.1		)	6.1			37.9			0.1		44.1
	invested as pension assets (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.
			December 31, 2012
			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		$	6.4		$	25.3		$	—		$	31.7		$	—		$	9.5		$	—	$	9.5
	Equity securities:
	United States equity		167.9			403			—			570.9			27.8			129			—		156.8
	International equity		96			300.4			—			396.4			15.6			92.9			—		108.5
	Fixed income securities:
	United States government		—			100.3			—			100.3			112.7			—			—		112.7
	Foreign government		—			20.4			4.1			24.5			—			—			—		—
	Corporate debt		—			197.3			1			198.3			—			—			—		—
	Asset-backed securities		—			56.5			0.1			56.6			—			—			—		—
	Other		—			11.3			—			11.3			1.1			—			—		1.1
			270.3			1,114.50			5.2			1,390.00			157.2			231.4			—		388.6
	401(h) other benefit plan assets		(7.1		)	(29.3		)	(0.1		)	(36.5		)	7.1			29.3			0.1		36.5
	invested as pension assets (1)
	Total (2)		$	263.2		$	1,085.20		$	5.1		$	1,353.50		$	164.3		$	260.7		$	0.1	$	425.1
	-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 table sets 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			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	)
	(Millions)		Foreign Government Debt			Corporate Debt			Asset-Backed Securities			Total
	Beginning balance at January 1, 2012		$	5.7		$	2.1		$	—		$	7.8
	Net realized and unrealized gains (losses)		0.5			0.2			—			0.7
	Purchases		1.2			0.5			—			1.7
	Sales		(2.0		)	(0.4		)	—			(2.4		)
	Transfers into Level 3		—			—			0.1			0.1
	Transfers out of Level 3		(1.3		)	(1.4		)	—			(2.7		)
	Ending balance at December 31, 2012		$	4.1		$	1		$	0.1		$	5.2
	Net unrealized losses related to assets still held at the end of the period		$	0.3		$	0.1		$	—		$	0.4
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. In addition, the table shows the expected federal subsidies, provided under the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which will partially offset other postretirement benefits.
	(Millions)		Pension Benefits			Other Benefits			Federal Subsidies
	2014		$	125.1		$	30		$	2.2
	2015		123.3			32.5			2.3
	2016		126.1			35			2.5
	2017		129.3			37.5			2.6
	2018		125.9			39.9			2.7
	2019 through 2023		657.6			234.1			15.8

STOCKBASED_COMPENSATION_Tables

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2013
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 tax benefit recognized in income for the years ended December 31:
	(Millions)		2013				2012			2011
	Stock options		$	1.8			$	2		$	1.8
	Performance stock rights		2.7				5			3.5
	Restricted shares and restricted share units		10.2				9.7			6.1
	Nonemployee director deferred stock units		0.9				1			1
	Total stock-based compensation expense		$	15.6			$	17.7		$	12.4
	Deferred income tax benefit		$	6.2			$	7.1		$	5
Schedule of weighted-average fair values per stock option 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:
			2013 Grant		2012 Grant		2011 Grant
	Weighted-average fair value per stock option		$6.03		$6.30		$6.57
	Expected term		5 years		5 years		5 years
	Risk-free interest rate		0.18% – 2.11%		0.17% – 2.18%		0.27% – 3.90%
	Expected dividend yield		5.33%		5.28%		5.34%
	Expected volatility		24%		25%		25%
Summary of stock option activity and information related to outstanding and exercisable stock options	'
	A summary of stock option activity for 2013, and information related to outstanding and exercisable stock options at December 31, 2013, 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, 2012		2,046,355			$	49.25
	Granted		319,234			56
	Exercised		(797,705	)		48.56
	Forfeited		(15,510	)		56
	Expired		(2,000	)		44.73
	Outstanding at December 31, 2013		1,550,374			$	50.93		6.2		$	6.6
	Exercisable at December 31, 2013		810,086			$	49.96		4.6		$	4.3
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:
			2013		2012		2011
	Risk-free interest rate		0.13% – 1.27%		0.17% – 1.27%		0.00% – 1.27%
	Expected dividend yield		5.28% – 5.34%		5.18% – 5.34%		5.28% – 5.34%
	Expected volatility		15% – 36%		14% – 36%		21% – 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 2013 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, 2012		505,690			$	48.38
	Granted		196,894			55.93
	Dividend equivalents		24,089			52.2
	Vested and released		(208,682	)		46.36
	Forfeited		(6,690	)		52.56
	Outstanding at December 31, 2013		511,301			$	52.24
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 2013 activity related to performance stock rights accounted for as equity awards is presented below:
			Performance			Weighted-Average
			Stock Rights			Fair Value *
	Outstanding at December 31, 2012		108,314			$	65.38
	Granted		22,636			48.5
	Award modifications		28,789			39.8
	Distributed		(94,758	)		72.36
	Adjustment for final payout		21,867			72.36
	Forfeited		(1,099	)		48.5
	Outstanding at December 31, 2013		85,749			$	46.62
	*	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 2013 activity related to performance stock rights accounted for as liability awards is presented below:
			Performance
			Stock Rights
	Outstanding at December 31, 2012		189,093
	Granted		90,496
	Award modifications		(28,789	)
	Distributed		(61,753	)
	Adjustment for final payout		14,255
	Forfeited		(4,398	)
	Outstanding at December 31, 2013		198,904

COMMON_EQUITY_Tables

COMMON EQUITY (Tables)	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity Note [Abstract]	'
Roll Forward of Issued Common Stock	'
	We had the following changes to issued common stock:
	Balance at December 31, 2010		77,781,685
	Shares issued
	Stock-based compensation		204,331
	Stock Investment Plan		149,470
	Employee Stock Ownership Plan		105,845
	Rabbi trust shares		48,788
	Restricted stock shares cancelled		(2,213	)
	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
	*	We did not issue equity during 2012.
Schedule Of Common Stock Activity To Meet Requirements Of Stock Investment Plan And Certain 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 (1)		Purchasing shares on the open market
	02/05/2013 – 02/04/2014		Issued new shares (2)
	05/01/2011 – 02/04/2013		Purchased shares on the open market
	01/01/2011 – 04/30/2011		Issued new shares (2)
	(1)	The decision was made in conjunction with the announcement of the proposed sale of UPPCO. See Note 29, Subsequent Event, for more information.
	(2)	These stock issuances increased equity $79.8 million and $22.2 million in 2013 and 2011, respectively.
Reconciliation of shares issued and outstanding	'
	The following table reconciles common shares issued and outstanding:
			2013							2012
			Shares			Average Cost *				Shares			Average Cost *
	Common stock issued		79,919,176							78,287,906
	Less:
	Deferred compensation rabbi trust		473,796			$	48.5			385,439			$	46.03
	Total common shares outstanding		79,445,380							77,902,467
	*	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)		2013				2012				2011
	Numerator:
	Net income from continuing operations		$	350			$	294			$	230
	Discontinued operations, net of tax		4.8				(9.7		)		0.5
	Preferred stock dividends of subsidiary		(3.1		)		(3.1		)		(3.1		)
	Noncontrolling interest in subsidiaries		0.1				0.2				—
	Net income attributed to common shareholders — basic		$	351.8			$	281.4			$	227.4
	Effect of dilutive securities
	Deferred compensation		(0.1		)		—				—
	Net income attributed to common shareholders — diluted		$	351.7			$	281.4			$	227.4
	Denominator:
	Average shares of common stock — basic		79.5				78.6				78.6
	Effect of dilutive securities
	Stock-based compensation		0.4				0.5				0.5
	Deferred compensation		0.2				0.2				—
	Average shares of common stock — diluted		80.1				79.3				79.1
	Earnings per common share
	Basic		$	4.43			$	3.58			$	2.89
	Diluted		4.39				3.55				2.87
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	'
	The calculation of diluted earnings per share excluded the following weighted-average outstanding securities that had an anti-dilutive effect:
	(Millions)		2013			2012			2011
	Stock-based compensation		0.3			0.7			0.7
	Deferred compensation		0.1			—			—
Capital transactions with subsidiaries	'
	During 2013, capital transactions with subsidiaries were as follows (in millions):
	Subsidiary		Dividends To Parent				Return Of				Equity Contributions
							Capital To Parent				From Parent
	ITF (1)		$	—			$	—			$	44.3
	MERC		—				21				13
	MGU		—				12.5				8
	NSG (2)		12				—				—
	UPPCO		—				6.5				—
	WPS		108.6				35				200
	WPS Investments, LLC (3)		71				—				13.6
	Total		$	191.6			$	75			$	278.9
	(1)	ITF is a direct wholly owned subsidiary of PELLC. As a result, it makes distributions to PELLC, and receives equity contributions from PELLC. Subject to applicable law, PELLC does not have any dividend restrictions or limitations on distributions to us.
	(2)	NSG is a direct wholly owned subsidiary of PELLC. As a result, it makes distributions to PELLC, and receives equity contributions from PELLC. Subject to applicable law, PELLC does not have any dividend restrictions or limitations on distributions to us.
	(3)	WPS Investments, LLC is a consolidated subsidiary that is jointly owned by us, WPS, and UPPCO. At December 31, 2013, we had an 86.22% ownership interest, while WPS and UPPCO had an 11.36% and 2.42% ownership interest, respectively. Distributions from WPS Investments, LLC are made to the owners based on their respective ownership percentages. During 2013, all equity contributions to WPS Investments, LLC were made solely by us.

PREFERRED_STOCK_OF_SUBSIDIARY_

PREFERRED STOCK OF SUBSIDIARY (Tables) (WPS, Preferred stock)	12 Months Ended
	Dec. 31, 2013
WPS | Preferred stock	'
Schedule of outstanding shares of preferred stock of subsidiary	'
	Outstanding shares owned by third parties were as follows at December 31:
	(Millions, except share amounts)	2013			2012
	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

ACCUMULATED_OTHER_COMPREHENSIV1

ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)	12 Months Ended
	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]	'
Schedule of changes, net of tax, in accumulated other comprehensive loss	'
	The following table show the changes, net of tax, to our accumulated other comprehensive loss during the year ended December 31, 2013:
	Year Ended December 31, 2013								Accumulated Other Comprehensive Loss
	(Millions)		Cash Flow Hedges			Defined Benefit Plans
	Beginning 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 current period other comprehensive income		2.1			15.6			17.7
	Ending balance at December 31, 2013		$	(3.1	)	$	(20.1	)	$	(23.2	)
Schedule of reclassifications out of accumulated other comprehensive loss	'
	The following table shows the reclassifications out of accumulated other comprehensive loss during the year ended December 31, 2013:
	(Millions)		Amount Reclassified			Affected Line Item in the Statements of Income
	Losses on cash flow hedges
	Utility commodity derivative contracts		$	0.2		Operating and maintenance expense (1)
	Nonregulated commodity derivative contracts		3.7			Nonregulated revenues
	Interest rate hedges		1.1			Interest expense
			5			Total before tax
			3.6			Tax expense
			1.4			Net of tax
	Defined benefit plans
	Amortization of prior service costs		4.3			(2)
	Amortization of net actuarial gains		(0.2		)	(2)
			4.1			Total before tax
			1.7			Tax expense
			2.4			Net of tax
	Total reclassifications		$	3.8
	(1)	This item relates to changes in the price of natural gas used to support utility operations.
	(2)	These items are included in the computation of net periodic benefit cost. See Note 17, Employee Benefit Plans, for more information.

FAIR_VALUE_Tables

FAIR VALUE (Tables)	12 Months Ended
	Dec. 31, 2013
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-13
	(Millions)		Level 1			Level 2				Level 3				Total
	Assets
	Risk Management Assets
	Utility Segments
	Natural gas contracts		$	2.4		$	7.7			$	—			$	10.1
	Financial transmission rights (FTRs)		—			—				2.1				2.1
	Petroleum product contracts		0.1			—				—				0.1
	Coal contracts		—			—				0.2				0.2
	Nonregulated Segments
	Natural gas contracts		16.3			35.2				35.6				87.1
	Electric contracts		65.1			134.9				15.9				215.9
	Total Risk Management Assets		$	83.9		$	177.8			$	53.8			$	315.5
	Investment in exchange-traded funds		$	15.9		$	—			$	—			$	15.9
	Liabilities
	Risk Management Liabilities
	Utility Segments
	Natural gas contracts		$	0.5		$	0.6			$	—			$	1.1
	FTRs		—			—				0.3				0.3
	Coal contracts		—			—				2.7				2.7
	Nonregulated Segments
	Natural gas contracts		14.3			22				25.2				61.5
	Electric contracts		98.8			58.7				3.5				161
	Total Risk Management Liabilities		$	113.6		$	81.3			$	31.7			$	226.6
	Contingent consideration related to the acquisition of Compass Energy Services (Compass) *		$	—		$	—			$	7.8			$	7.8
	*	See Note 3, Acquisitions, for more information.
			31-Dec-12
	(Millions)		Level 1			Level 2				Level 3				Total
	Assets
	Risk Management Assets
	Utility Segments
	Natural gas contracts		$	0.3		$	3.1			$	—			$	3.4
	FTRs		—			—				2.1				2.1
	Petroleum product contracts		0.2			—				—				0.2
	Coal contracts		—			—				2.5				2.5
	Nonregulated Segments
	Natural gas contracts		21.4			36.4				5.4				63.2
	Electric contracts		48.4			61.3				9.6				119.3
	Total Risk Management Assets		$	70.3		$	100.8			$	19.6			$	190.7
	Investment in exchange-traded funds		$	11.8		$	—			$	—			$	11.8
	Liabilities
	Risk Management Liabilities
	Utility Segments
	Natural gas contracts		$	1.1		$	14.1			$	—			$	15.2
	FTRs		—			—				0.1				0.1
	Coal contracts		—			—				9				9
	Nonregulated Segments
	Natural gas contracts		17.7			36.9				1.5				56.1
	Electric contracts		54.9			91.1				13.9				159.9
	Total Risk Management Liabilities		$	73.7		$	142.1			$	24.5			$	240.3
Schedule of transfers between the levels of the fair value hierarchy	'
	The following tables show net risk management assets (liabilities) transferred between the levels of the fair value hierarchy:
			Nonregulated Segments — Natural Gas Contracts
			Year Ended December 31, 2013											Year Ended December 31, 2012
	(Millions)		Level 1			Level 2				Level 3				Level 1				Level 2				Level 3
	Transfers into Level 1 from		N/A			$	—			$	—			N/A				$	—			$	—
	Transfers into Level 2 from		$	—		N/A				—				$	—			N/A				2
	Transfers into Level 3 from		—			7.1				N/A				—				3.7				N/A
			Nonregulated Segments — Electric Contracts
			Year Ended December 31, 2013										Year Ended December 31, 2012
	(Millions)		Level 1			Level 2				Level 3			Level 1				Level 2				Level 3
	Transfers into Level 1 from		N/A			$	—			(0.3	)		N/A				$	—			$	—
	Transfers into Level 2 from		$	—		N/A				7.3			$	—			N/A				(13.0		)
	Transfers into Level 3 from		(0.2		)	8.7				N/A			—				(7.9		)		N/A
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, 2013. The amounts and percentages 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
	Utility Segments
	FTRs		$	2.1		$	0.3			Market-based		Forward market prices ($/megawatt-month) (1)		$174.52
	Coal contracts		0.2			2.7				Market-based		Forward market prices ($/ton) (2)		$11.73 — $14.30
	Nonregulated Segments
	Natural gas contracts		35.6			25.2				Market-based		Forward market prices ($/dekatherm) (3)		($1.53) — $17.30
												Probability of default(4)		11.6% — 51.0 %
	Electric contracts		15.9			3.5				Market-based		Forward market prices ($/megawatt-hours) (3)		($3.30) — $9.25
												Probability of default(4)		26	%
												Option volatilities(5)		14.8% — 199.9 %
												Monthly curve shaping(6)		(33.3	)%
	Contingent consideration related to the acquisition of Compass		N/A			7.8				Income-based		Growth rate(7)		(13.2)% — 49.3 %
	(1)	Represents forward market prices developed using historical cleared pricing data from MISO.
	(2)	Represents third-party forward market pricing.
	(3)	Represents unobservable basis spreads developed using historical settled prices that are applied to observable market prices at various natural gas and electric locations, as well as unobservable adjustments made to extend observable market prices beyond the quoted period through the end of the transaction term.
	(4)	Based on Moody's one-year counterparty default percentages.
	(5)	Represents the range of volatilities used in the valuation of options. Volatilities are derived from an internal model using volatility curves from third parties.
	(6)	Represents adjustments made to forward market price curves to disaggregate average prices of multiple periods into discrete monthly prices.
	(7)	Represents the range of assumed growth rates of earnings before interest, taxes, and amortization.
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:
	2013		Nonregulated Segments											Utility Segments
	(Millions)		Natural Gas			Electric				Contingent Consideration*				FTRs				Coal Contracts				Total
	Balance at the beginning of the period		$	3.9		$	(4.3	)		$	—			$	2			$	(6.5	)		$	(4.9	)
	Net realized and unrealized gains (losses) included in earnings		(1.8		)	14				(0.1		)		2				—				14.1
	Net unrealized gains (losses) recorded as regulatory assets or liabilities		—			—				—				(0.3		)		0.4				0.1
	Purchases		7.4			6				(7.7		)		4.9				—				10.6
	Sales		—			(1.1		)		—				(0.2		)		—				(1.3		)
	Settlements		(6.2		)	(3.7		)		—				(6.6		)		3.6				(12.9		)
	Net transfers into Level 3		7.1			8.5				—				—				—				15.6
	Net transfers out of Level 3		—			(7.0		)		—				—				—				(7.0		)
	Balance at the end of the period		$	10.4		$	12.4			$	(7.8	)		$	1.8			$	(2.5	)		$	14.3
	Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period		$	(1.8	)	$	14			$	—			$	—			$	—			$	12.2
	*	Represents the contingent consideration related to the acquisition of Compass. See Note 3, Acquisitions, for more information.
	2012		Nonregulated Segments							Utility Segments
	(Millions)		Natural Gas			Electric				FTRs				Coal Contracts				Total
	Balance at the beginning of the period		$	8.3		$	(11.5	)		$	2.2			$	(6.9	)		$	(7.9	)
	Net realized and unrealized gains (losses) included in earnings		3.8			(14.5		)	*	1.8				—				(8.9		)	*
	Net unrealized gains recorded as regulatory assets or liabilities		—			—				0.2				5.8				6
	Purchases		—			7.8				4.9				—				12.7
	Sales		—			—				(0.1		)		—				(0.1		)
	Settlements		(9.9		)	8.8				(7.0		)		(5.4		)		(13.5		)
	Net transfers into Level 3		3.7			(7.9		)		—				—				(4.2		)
	Net transfers out of Level 3		(2.0		)	13				—				—				11
	Balance at the end of the period		$	3.9		$	(4.3	)		$	2			$	(6.5	)		$	(4.9	)
	Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period		$	3.8		$	(14.5	)	*	$	—			$	—			$	(10.7	)	*
	*	Includes a $1.2 million net unrealized loss reported as discontinued operations. See Note 4, Discontinued Operations, for more information.
	2011		Nonregulated Segments							Utility Segments
	(Millions)		Natural Gas			Electric				FTRs				Coal Contracts				Total
	Balance at the beginning of the period		$	30.2		$	(14.9	)		$	2.9			$	2.5			$	20.7
	Net realized and unrealized gains (losses) included in earnings		32.3			(20.7		)	*	(1.7		)		—				9.9			*
	Net unrealized losses recorded as regulatory assets or liabilities		—			—				(1.7		)		(8.0		)		(9.7		)
	Net unrealized gains included in other comprehensive loss		—			0.6				—				—				0.6
	Purchases		—			2.2				5.9				—				8.1
	Sales		—			—				(0.1		)		—				(0.1		)
	Settlements		(30.4		)	7				(3.1		)		(1.4		)		(27.9		)
	Net transfers into Level 3		0.6			(5.9		)		—				—				(5.3		)
	Net transfers out of Level 3		(24.4		)	20.2				—				—				(4.2		)
	Balance at the end of the period		$	8.3		$	(11.5	)		$	2.2			$	(6.9	)		$	(7.9	)
	Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period		$	32.3		$	(20.7	)	*	$	—			$	—			$	11.6		*
	*	Includes a $0.5 million net unrealized gain reported as discontinued operations. See Note 4, Discontinued Operations, for more information.
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-13							December 31, 2012
	(Millions)		Carrying Amount			Fair Value				Carrying Amount				Fair Value
	Long-term debt		$	3,056.20		$	3,031.60			$	2,245.20			$	2,425.80
	Preferred stock of subsidiary		51.1			61.2				51.1				52.7

MISCELLANEOUS_INCOME_Tables

MISCELLANEOUS INCOME (Tables)	12 Months Ended
	Dec. 31, 2013
Other Income and Expenses [Abstract]	'
Components of miscellaneous income	'
	Total miscellaneous income was as follows at December 31:
	(Millions)	2013		2012		2011
	Equity portion of AFUDC	$	10.8	$	2.9	$	0.7
	Seams elimination charge adjustment (SECA) settlement at Integrys Energy Services	5.7		—		—
	Federal excise tax credit	4.1		—		—
	Key executive life insurance income for retired employees	2.2		2.6		2.3
	Gains (losses) on exchange-traded funds held at IBS	2.2		1.3		(0.1		)
	Other	4.8		2.5		2.4
	Total miscellaneous income	$	29.8	$	9.3	$	5.3

SEGMENTS_OF_BUSINESS_Tables

SEGMENTS OF BUSINESS (Tables)	12 Months Ended
	Dec. 31, 2013
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
	2013 (Millions)	Natural Gas			Electric			Electric		Total			Integrys			Holding			Reconciling			Integrys
		Utility			Utility			Transmission		Regulated			Energy			Company			Eliminations			Energy Group
								Investment		Operations			Services			and Other						Consolidated
	Income Statement
	External revenues	$	2,093.60		$	1,332.00		$	—	$	3,425.60		$	2,166.20		$	42.8		$	—		$	5,634.60
	Intersegment revenues	11.4			0.1			—		11.5			1.3			1.4			(14.2		)	—
	Depreciation and amortization expense	136			98.6			—		234.6			11.4			21.1			(0.5		)	266.6
	Earnings from equity method investments	—			—			89.1		89.1			1.3			1.1			—			91.5
	Miscellaneous income	1.2			9.8			—		11			8.5			23.6			(13.3		)	29.8
	Interest expense	50.2			36.4			—		86.6			2			52.9			(13.3		)	128.2
	Provision (benefit) for income taxes	78.9			67.3			35.2		181.4			48			(18.6		)	—			210.8
	Net income (loss) from continuing operations	124			113.4			53.9		291.3			79.4			(20.7		)	—			350
	Discontinued operations	—			—			—		—			(1.1		)	5.9			—			4.8
	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			78.3			(14.7		)	—			351.8
	Total assets	5,672.00			3,514.40			508.5		9,694.90			989.2			1,345.90			(786.5		)	11,243.50
	Cash expenditures for long-lived assets	370			615			—		985			15.8			60			—			1,060.80
		Regulated Operations											Nonutility and Nonregulated
													Operations
	2012 (Millions)	Natural Gas Utility			Electric			Electric		Total			Integrys			Holding			Reconciling			Integrys
					Utility			Transmission		Regulated			Energy			Company			Eliminations			Energy Group
								Investment		Operations			Services			and Other						Consolidated
	Income Statement
	External revenues	$	1,662.10		$	1,297.40		$	—	$	2,959.50		$	1,217.60		$	35.3		$	—		$	4,212.40
	Intersegment revenues	9.9			—			—		9.9			0.9			1.9			(12.7		)	—
	Depreciation and amortization expense	131.8			89			—		220.8			10.3			20.1			(0.5		)	250.7
	Earnings from equity method investments	—			—			85.3		85.3			1.1			0.8			—			87.2
	Miscellaneous income	0.6			2.6			—		3.2			1.1			20.9			(15.9		)	9.3
	Interest expense	47.3			35.9			—		83.2			2.1			50.8			(15.9		)	120.2
	Provision (benefit) for income taxes	61.4			49.4			32.9		143.7			25.8			(19.7		)	—			149.8
	Net income (loss) from continuing operations	94			110.4			52.4		256.8			52.6			(15.4		)	—			294
	Discontinued operations	—			—			—		—			(11.5		)	1.8			—			(9.7		)
	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			41.1			(13.4		)	—			281.4
	Total assets	5,446.20			3,041.30			476.6		8,964.10			749.2			1,267.80			(653.7		)	10,327.40
	Cash expenditures for long-lived assets	375.1			163.9			—		539			30.9			24.4			—			594.3
		Regulated Operations											Nonutility and Nonregulated
													Operations
	2011 (Millions)	Natural Gas Utility			Electric			Electric		Total			Integrys			Holding			Reconciling			Integrys
					Utility			Transmission		Regulated			Energy			Company			Eliminations			Energy Group
								Investment		Operations			Services			and Other						Consolidated
	Income Statement
	External revenues	$	1,987.20		$	1,307.30		$	—	$	3,294.50		$	1,372.00		$	19.4		$	—		$	4,685.90
	Intersegment revenues	10.8			—			—		10.8			1.1			1.5			(13.4		)	—
	Depreciation and amortization expense	126.1			88.5			—		214.6			10.3			23.3			(0.5		)	247.7
	Earnings (losses) from equity method investments	—			—			79.1		79.1			(0.7		)	1			—			79.4
	Miscellaneous income	2.2			0.8			—		3			1			18.3			(17.0		)	5.3
	Interest expense	48.4			41.8			—		90.2			1.7			53.3			(17.0		)	128.2
	Provision (benefit) for income taxes	61.2			59.2			31.3		151.7			(7.7		)	(10.7		)	—			133.3
	Net income (loss) from continuing operations	103.9			103			47.8		254.7			(7.1		)	(17.6		)	—			230
	Discontinued operations	—			—			—		—			1			(0.5		)	—			0.5
	Preferred stock dividends of subsidiary	(0.6		)	(2.5		)	—		(3.1		)	—			—			—			(3.1		)
	Net income (loss) attributed to common shareholders	103.3			100.5			47.8		251.6			(6.1		)	(18.1		)	—			227.4
	Total assets	5,033.00			2,982.90			439.4		8,455.30			891.5			1,215.30			(578.9		)	9,983.20
	Cash expenditures for long-lived assets	199.3			84.1			—		283.4			16.7			10			—			310.1

QUARTERLY_FINANCIAL_INFORMATIO1

QUARTERLY FINANCIAL INFORMATION (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Schedule of quarterly financial information (Unaudited)	'
	(Millions, except per share amounts)		First Quarter		Second Quarter			Third Quarter			Fourth Quarter		Total
	2013
	Total 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
	2012
	Total revenues		$	1,247.90	$	839.6		$	927.7		$	1,197.20	$	4,212.40
	Operating income		153.1		87.1			108.5			118.8		467.5
	Net income from continuing operations		98.8		51.7			74.3			69.2		294
	Net income		99.7		49.6			66.3			68.7		284.3
	Net income attributed to common shareholders		98.9		48.8			65.7			68		281.4
	Earnings per common share (basic) *
	Net income from continuing operations		$	1.25	$	0.65		$	0.94		$	0.87	$	3.7
	Discontinued operations, net of tax		0.01		(0.03		)	(0.10		)	—		(0.12		)
	Earnings per common share (basic)		1.26		0.62			0.84			0.87		3.58
	Earnings per common share (diluted) *
	Net income from continuing operations		1.24		0.65			0.93			0.86		3.67
	Discontinued operations, net of tax		0.01		(0.03		)	(0.10		)	—		(0.12		)
	Earnings per common share (diluted)		1.25		0.62			0.83			0.86		3.55
	*	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. Earnings per share for the individual quarters differ by insignificant amounts from previously reported amounts due to the classification of certain asset groups as discontinued operations. See Note 4, Discontinued Operations, for more information.

SUBSEQUENT_EVENT_Tables

SUBSEQUENT EVENT (Tables)	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
Balances of the assets and liabilities included in the disposal group	'
	The following table shows the balances of the assets and liabilities of UPPCO that are included in the disposal group:
	(Millions)	31-Dec-13
	Current assets	$	26.5
	Property, plant, and equipment, net of accumulated depreciation of $88.9 million	193.8
	Other long-term assets	51.5
	Total assets	$	271.8
	Current liabilities	$	21.2
	Long-term liabilities	$	32.4
	Total liabilities	$	53.6

SUMMARY_OF_SIGNIFICANT_ACCOUNT3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES NATURE OF OPERATIONS (Details)	Dec. 31, 2013
	subsidiary
Accounting Policies [Abstract]	'
Number of Regulated Electric and/or Natural Gas Utilities	6
ATC	'
Schedule of equity method investments	'
Ownership interest (as a percent)	34.00%

SUMMARY_OF_SIGNIFICANT_ACCOUNT4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES CASH AND CASH EQUIVALENTS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash and Cash Equivalents	'	'	'
Maximum term of original maturity to classify instruments as cash equivalent	'3 months	'	'
Cash Flow, Noncash Investing and Financing Activities	'	'	'
Construction costs funded through accounts payable	$108.50	$92.40	$58.60
Portion of Westwood sale financed with note receivable	0	4	0
Equity issued for stock-based compensation plans	16.3	0	10.6
Equity issued for employee stock ownership plan	14.3	0	5.2
Equity issued for reinvested dividends	12	0	5.4
Contingent consideration related to the acquisition of Compass Energy Services	$7.80	$0	$0

SUMMARY_OF_SIGNIFICANT_ACCOUNT5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES REVENUE AND CUSTOMER RECEIVABLES (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013
In Millions, unless otherwise specified			WPS	Customer concentration risk
				customer
				industry
Revenue from external customers	'	'	'	'
Unbilled revenues	$438.20	$298.20	'	'
Customers that account for more than 10% of revenues	'	'	'	0
Industries that account for more than 10% of revenues	'	'	'	0
Threshold percentage of revenues from major customers or industries	'	'	'	10.00%
Percentage price variance from rate case-approved fuel and purchased power costs before deferral is required	'	'	2.00%	'

SUMMARY_OF_SIGNIFICANT_ACCOUNT6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES INVENTORIES (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Percentage of total inventories stated on a LIFO basis	30.00%	'	'
PGL and NSG [Member]	'	'	'
Amount by which estimated replacement cost of natural gas in inventory exceeded LIFO cost	$151.70	$95.30	'
Natural Gas Price Benchmark	4.77	3.58	'
Integrys Energy Services	'	'	'
Inventory Write-down	$3.60	$3.40	$11.60

SUMMARY_OF_SIGNIFICANT_ACCOUNT7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PROPERTY, PLANT, AND EQUIPMENT (Details) (USD $)

12 Months Ended

3 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Software

Software

MERC

MERC

MERC

MERC

MGU

MGU

MGU

MGU

NSG

NSG

NSG

PGL

PGL

PGL

UPPCO

UPPCO

UPPCO

WPS

WPS

WPS

WPS

WPS

WPS

Minimum

Maximum

Minnesota Public Utilities Commission (MPUC)

Michigan Public Service Commission (MPSC)

Electric

Electric

Electric

Natural gas

Natural gas

Natural gas

Property, plant, and equipment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual utility composite depreciation rate (as a percent)

'

'

1.88%

3.07%

3.10%

'

1.93%

2.71%

2.73%

'

2.44%

2.43%

2.42%

3.19%

3.16%

3.18%

3.29%

3.31%

3.33%

2.79%

2.87%

2.88%

2.19%

2.21%

2.22%

Useful life

'3 years

'15 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reduction to depreciation expense

'

'

'

'

'

$2

'

'

'

$2.50

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

SUMMARY_OF_SIGNIFICANT_ACCOUNT8

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AFUDC AND CAPITALIZED INTEREST (Details) (WPS, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	$10.80	$2.90	$0.70
Allowance for borrowed funds used during construction	$4.10	$1	$0.30
Retail	'	'	'
AFUDC and capitalized interest	'	'	'
Average AFUDC rate (as a percent)	8.61%	'	'
Wholesale	'	'	'
AFUDC and capitalized interest	'	'	'
Average AFUDC rate (as a percent)	2.64%	'	'

SUMMARY_OF_SIGNIFICANT_ACCOUNT9

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES INVESTMENTS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Trading Securities [Abstract]	'	'	'
Trading Securities, Change in Unrealized Holding Gain (Loss)	$1.90	$1	($0.10)

Recovered_Sheet1

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES INCOME TAXES (Details) (Minimum)	12 Months Ended
	Dec. 31, 2013
Minimum	'
Income taxes	'
Threshold ownership percentage used to determine subsidiary inclusion in consolidated income tax return	80.00%

Recovered_Sheet2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES EMPLOYEE BENEFITS (Details)	12 Months Ended
	Dec. 31, 2013
Employee benefits	'
Recognition period for transition obligation related 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_Sheet3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES STOCK-BASED COMPENSATION (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Stock Options	'
Information related to share based awards	'
Maximum term of awards	'10 years
Percent vesting on each year on the anniversary of the grant date (as a percent)	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
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	'
Period of historical volatility used to estimate expected volatility	'1 year
Amount of performance payout (as a percent)	0.00%
Performance Stock Rights | Maximum	'
Information related to share based awards	'
Period of historical volatility used to estimate expected volatility	'3 years
Amount of performance payout (as a percent)	200.00%
Restricted Shares and Restricted Share Units	'
Information related to share based awards	'
Vesting period	'4 years
Percent vesting on each year on the anniversary of the grant date (as a percent)	25.00%
Percentage value of award that can be deferred into deferred compensation plan	80.00%
2010 Omnibus Incentive Compensation Plan	'
Information related to share based awards	'
Number of shares authorized for grant	3,000,000
2010 Omnibus Incentive Compensation Plan | Performance Stock Rights, Restricted Shares, and Restricted Share Units	'
Information related to share based awards	'
Number of shares authorized for grant	900,000
2010 Omnibus Incentive Compensation Plan | Stock Options	'
Information related to share based awards	'
Number of highest paid officers of entity or its subsidiary that cannot be granted awards in excess of a set amount	3
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
2010 Omnibus Incentive Compensation Plan | Performance Stock Rights	'
Information related to share based awards	'
Number of highest paid officers of entity or its subsidiary that cannot be granted awards in excess of a set amount	3
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

Recovered_Sheet4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ADVERTISING COSTS (Details)	12 Months Ended
	Dec. 31, 2013
Marketing and Advertising Expense [Abstract]	'
Advertising Costs, Capitalized Direct Response, Advertising Amortization Period	'2 years

RISK_MANAGEMENT_ACTIVITIES_Det

RISK MANAGEMENT ACTIVITIES (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Derivative assets and liabilities from risk management activities	'	'
Current assets from risk management activities	$240.10	$145.40
Long-term assets from risk management activities	75.4	45.3
Risk Management Assets	315.5	190.7
Current liabilities from risk management activities	163.8	181.9
Long-term liabilities from risk management activities	62.8	58.4
Risk Management Liabilities	226.6	240.3
Non-hedge derivatives | Utility segments | Natural gas contracts	'	'
Derivative assets and liabilities from risk management activities	'	'
Current assets from risk management activities	8.3	2.5
Long-term assets from risk management activities	1.8	0.9
Current liabilities from risk management activities	1	14
Long-term liabilities from risk management activities	0.1	0.8
Non-hedge derivatives | Utility segments | FTRs	'	'
Derivative assets and liabilities from risk management activities	'	'
Current assets from risk management activities	2.1	2.1
Current liabilities from risk management activities	0.3	0.1
Non-hedge derivatives | Utility segments | Petroleum product contracts	'	'
Derivative assets and liabilities from risk management activities	'	'
Current assets from risk management activities	0.1	0.2
Current liabilities from risk management activities	0	0
Non-hedge derivatives | Utility segments | Coal contracts	'	'
Derivative assets and liabilities from risk management activities	'	'
Current assets from risk management activities	0	0.3
Long-term assets from risk management activities	0.2	2.2
Current liabilities from risk management activities	1.9	4.7
Long-term liabilities from risk management activities	0.8	4.3
Non-hedge derivatives | Nonregulated segments | Natural gas contracts	'	'
Derivative assets and liabilities from risk management activities	'	'
Current assets from risk management activities	57.6	51.7
Long-term assets from risk management activities	29.5	11.5
Current liabilities from risk management activities	42.9	48.5
Long-term liabilities from risk management activities	18.6	7.6
Non-hedge derivatives | Nonregulated segments | Electric contracts	'	'
Derivative assets and liabilities from risk management activities	'	'
Current assets from risk management activities	172	88.6
Long-term assets from risk management activities	43.9	30.7
Current liabilities from risk management activities	117.7	114.2
Long-term liabilities from risk management activities	43.3	45.7
Cash flow hedges | Utility segments | Natural gas contracts	'	'
Derivative assets and liabilities from risk management activities	'	'
Current assets from risk management activities	'	0
Current liabilities from risk management activities	'	$0.40

RISK_MANAGEMENT_ACTIVITIES_Det1

RISK MANAGEMENT ACTIVITIES (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Assets	'	'
Derivative assets subject to master netting or similar arrangements, gross amount	$314.20	$188.20
Potential effects of netting, including cash collateral	180.2	148.4
Derivative assets subject to master netting or similar arrangements, net amount	134	39.8
Derivative assets not subject to master netting or similar arrangements	1.3	2.5
Risk Management Assets	315.5	190.7
Total Risk Management Assets, Net Amount	135.3	42.3
Liabilities	'	'
Derivative liabilities subject to master netting or similar arrangements, gross amount	223.5	230.7
Potential effects of netting, including cash collateral	179.5	163.6
Derivative liabilities subject to master netting or similar arrangements, net amount	44	67.1
Derivative liabilities not subject to master netting or similar arrangements	3.1	9.6
Risk Management Liabilities	226.6	240.3
Total Risk Management Liabilities, Net Amount	47.1	76.7
Utility segments	'	'
Assets	'	'
Derivative assets subject to master netting or similar arrangements, gross amount	12.3	5.7
Potential effects of netting, including cash collateral	2.1	3
Derivative assets subject to master netting or similar arrangements, net amount	10.2	2.7
Liabilities	'	'
Derivative liabilities subject to master netting or similar arrangements, gross amount	1.4	15.3
Potential effects of netting, including cash collateral	1.4	3.8
Derivative liabilities subject to master netting or similar arrangements, net amount	0	11.5
Nonregulated segments	'	'
Assets	'	'
Derivative assets subject to master netting or similar arrangements, gross amount	301.9	182.5
Potential effects of netting, including cash collateral	178.1	145.4
Derivative assets subject to master netting or similar arrangements, net amount	123.8	37.1
Liabilities	'	'
Derivative liabilities subject to master netting or similar arrangements, gross amount	222.1	215.4
Potential effects of netting, including cash collateral	178.1	159.8
Derivative liabilities subject to master netting or similar arrangements, net amount	$44	$55.60

RISK_MANAGEMENT_ACTIVITIES_Det2

RISK MANAGEMENT ACTIVITIES (Details 3) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Risk management activities	'	'
Cash collateral provided to others, related to contracts under master netting or similar arrangements	$37.60	$39.90
Cash collateral provided to others, other	1.1	1.1
Cash collateral received from others related to contracts under master netting or similar arrangements	0.7	0.2
Utility segments	'	'
Risk management activities	'	'
Aggregate fair value of derivative instruments with credit risk-related contingent features that were is a liability position	0.6	14
Collateral that would have been required	0	10.1
Collateral remaining	0	10.1
Nonregulated segments	'	'
Risk management activities	'	'
Aggregate fair value of derivative instruments with credit risk-related contingent features that were is a liability position	76.7	108.9
Collateral that would have been required	197.6	173.8
Collateral already satisfied, letters of credit	4.5	3.2
Collateral remaining	$193.10	$170.60

RISK_MANAGMENT_ACTIVITIES_Deta

RISK MANAGMENT ACTIVITIES (Details 4) (Utility segments)	Dec. 31, 2013	Dec. 31, 2012
	Btu	Btu
Purchases | Natural gas contracts	'	'
Risk management activities	'	'
Notional volume of outstanding non-hedge derivative contracts (therms)	3,124,800,000	1,072,600,000
Purchases | Petroleum product contracts	'	'
Risk management activities	'	'
Notional volume of outstanding non-hedge derivative contracts (barrels)	102,811	62,811
Purchases | Coal contracts	'	'
Risk management activities	'	'
Notional volume of outstanding non-hedge derivative contracts (tons)	4,800,000	5,100,000
Sales | Natural gas contracts	'	'
Risk management activities	'	'
Notional volume of outstanding non-hedge derivative contracts (therms)	29,300,000	100,000
Sales | Petroleum product contracts	'	'
Risk management activities	'	'
Notional volume of outstanding non-hedge derivative contracts (barrels)	14,000	0
Sales | Coal contracts	'	'
Risk management activities	'	'
Notional volume of outstanding non-hedge derivative contracts (tons)	0	0
Other transactions | FTRs	'	'
Risk management activities	'	'
Notional volume of outstanding non-hedge derivative contracts (kwh)	3,633,100,000	4,057,200,000

RISK_MANAGEMENT_ACTIVITIES_Det3

RISK MANAGEMENT ACTIVITIES (Details 5) (Utility segments, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Natural gas contracts | Balance Sheet - Regulatory assets (current)	'	'	'
Risk management activities	'	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	$13.40	$24.60	($11.30)
Natural gas contracts | Balance Sheet - Regulatory assets (long-term)	'	'	'
Risk management activities	'	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	2.3	8.3	-7.6
Natural gas contracts | Balance Sheet - Regulatory liabilities (current)	'	'	'
Risk management activities	'	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	4.6	-7.8	8.4
Natural gas contracts | Balance Sheet - Regulatory liabilities (long-term)	'	'	'
Risk management activities	'	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	0.3	0.3	0
Natural gas contracts | Income Statement - Utility cost of fuel, natural gas and purchased power	'	'	'
Risk management activities	'	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	0	0.2	0
Natural gas contracts | Income Statement - Operating and maintenance expense	'	'	'
Risk management activities	'	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	0.1	0	0
FTRs | Balance Sheet - Regulatory assets (current)	'	'	'
Risk management activities	'	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	0.1	0.1	-0.4
FTRs | Balance Sheet - Regulatory liabilities (current)	'	'	'
Risk management activities	'	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	-0.4	0.1	-1.3
Petroleum product contracts | Balance Sheet - Regulatory assets (current)	'	'	'
Risk management activities	'	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	0	0.1	-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	0
Petroleum product contracts | Income Statement - Operating and maintenance expense	'	'	'
Risk management activities	'	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	0.1	0	-0.1
Coal contracts | Balance Sheet - Regulatory assets (current)	'	'	'
Risk management activities	'	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	-0.9	-2.2	-1.3
Coal contracts | Balance Sheet - Regulatory assets (long-term)	'	'	'
Risk management activities	'	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	3.5	0.1	-4.4
Coal contracts | Balance Sheet - Regulatory liabilities (current)	'	'	'
Risk management activities	'	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	-0.2	0.3	0
Coal contracts | Balance Sheet - Regulatory liabilities (long-term)	'	'	'
Risk management activities	'	'	'
Unrealized gain (loss) related to non-hedge derivative contracts	($2)	$2.20	($3.70)

RISK_MANAGEMENT_ACTIVITIES_Det4

RISK MANAGEMENT ACTIVITIES (Details 6) (Nonregulated segments, CAD)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified	Btu	Btu
Purchases | Natural gas contracts	'	'
Risk management activities	'	'
Notional volume of outstanding non-hedge derivative contracts (therms)	1,199,900,000	782,000,000
Purchases | Electric contracts	'	'
Risk management activities	'	'
Notional volume of outstanding non-hedge derivative contracts (kwh)	49,186,300,000	54,127,600,000
Purchases | Foreign exchange contracts	'	'
Risk management activities	'	'
Notional volume of outstanding foreign exchange non-hedge derivative contracts, monetary (in Canadian dollars)	0	0.4
Sales | Natural gas contracts	'	'
Risk management activities	'	'
Notional volume of outstanding non-hedge derivative contracts (therms)	1,065,400,000	679,000,000
Sales | Electric contracts	'	'
Risk management activities	'	'
Notional volume of outstanding non-hedge derivative contracts (kwh)	30,813,800,000	31,809,600,000
Sales | Foreign exchange contracts	'	'
Risk management activities	'	'
Notional volume of outstanding foreign exchange non-hedge derivative contracts, monetary (in Canadian dollars)	0	0.4

RISK_MANAGEMENT_ACTIVITIES_Det5

RISK MANAGEMENT ACTIVITIES (Details 7) (Nonregulated segments, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Risk management activities	'	'	'
Gains (losses) recorded related to non-hedge derivatives (total)	$89.80	($1.50)	($69)
Natural gas contracts | Nonregulated revenue	'	'	'
Risk management activities	'	'	'
Gains (losses) recorded related to non-hedge derivatives	36.7	6.8	14
Natural gas contracts | Nonregulated cost of sales	'	'	'
Risk management activities	'	'	'
Gains (losses) recorded related to non-hedge derivatives	-27.6	0	0
Natural gas contracts | Nonregulated revenue (reclassified from Accumulated OCI)	'	'	'
Risk management activities	'	'	'
Gains (losses) recorded related to non-hedge derivatives (prior cash flow hedge)	-0.3	-2	-2.3
Electric contracts | Nonregulated revenue	'	'	'
Risk management activities	'	'	'
Gains (losses) recorded related to non-hedge derivatives	73.6	-2	-79
Electric contracts | Nonregulated cost of sales	'	'	'
Risk management activities	'	'	'
Gains (losses) recorded related to non-hedge derivatives	10.8	0	0
Electric contracts | Nonregulated revenue (reclassified from Accumulated OCI)	'	'	'
Risk management activities	'	'	'
Gains (losses) recorded related to non-hedge derivatives (prior cash flow hedge)	($3.40)	($4.30)	($1.70)

RISK_MANAGEMENT_ACTIVITIES_Det6

RISK MANAGEMENT ACTIVITIES (Details 8) (Nonregulated segments, Cash flow hedges, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Risk management activities	'	'	'
Unrealized Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	'	'	$1.50
Gain (loss) Reclassified from Accumulated OCI into Income	-1.1	-1.1	-6.7
Gain (Loss) Recognized in Income on Derivative Instruments (Ineffective Portion and Amount Excluded from Effectiveness Testing)	'	'	0
Natural gas contracts	'	'	'
Risk management activities	'	'	'
Unrealized Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	'	'	-2.3
Natural gas contracts | Nonregulated revenue	'	'	'
Risk management activities	'	'	'
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	0	0	-9.3
Gain (Loss) on Discontinuation of Price Risk Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net	0	0	-0.3
Gain (Loss) Recognized in Income on Derivative Instruments (Ineffective Portion and Amount Excluded from Effectiveness Testing)	'	'	0.3
Electric contracts	'	'	'
Risk management activities	'	'	'
Unrealized Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	'	'	3.8
Electric contracts | Nonregulated revenue	'	'	'
Risk management activities	'	'	'
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	0	0	4.2
Gain (Loss) Recognized in Income on Derivative Instruments (Ineffective Portion and Amount Excluded from Effectiveness Testing)	'	'	-0.3
Interest rate swaps | Interest expense	'	'	'
Risk management activities	'	'	'
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	-1.1	-1.1	-1.1
Gain (Loss) on Discontinuation of Price Risk Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net	$0	$0	($0.20)

ACQUISITIONS_Details

ACQUISITIONS (Details) (USD $)

12 Months Ended

1 Months Ended

1 Months Ended

0 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Nov. 30, 2013

Dec. 31, 2013

31-May-13

31-May-13

31-May-13

Mar. 31, 2013

Sep. 02, 2011

Dec. 31, 2012

WPS

WPS

Alliant Energy Corporation's Natural Gas Distribution Business in Southeast Minnesota

Compass Energy Services Inc

Compass Energy Services Inc

Compass Energy Services Inc

Fox Energy Company LLC

Trillium USA and Pinnacle CNG Systems

Trillium USA and Pinnacle CNG Systems

Senior Notes, 4.752% due 2044

Senior Notes, 4.752% due 2044

MERC

Integrys Energy Services

Integrys Energy Services

Integrys Energy Services

WPS

Integrys Energy Group, Inc.

Integrys Energy Group, Inc.

Minimum

Maximum

MW

business

Acquisitions

'

'

'

'

'

'

'

'

'

'

'

'

Estimated purchase price

'

'

'

'

'

$11

'

'

'

'

'

'

Amount paid for the acquisition

'

'

'

'

'

'

12.4

'

'

391.6

'

'

Contingent Consideration

'

'

'

'

'

'

'

3

8

'

'

'

Period of financial performance of acquiree as basis for contingent consideration

'

'

'

'

'

'

'5 years

'

'

'

'

'

Liabilities recorded related to contingent consideration

'

'

'

'

'

'

7.8

'

'

'

'

'

Assets acquired

'

'

'

'

'

'

'

'

'

'

'

'

Inventories

'

'

'

'

'

'

0.7

'

'

3

'

'

Assets from risk management activities (current)

'

'

'

'

'

'

15.1

'

'

'

'

'

Other current assets

'

'

'

'

'

'

1.1

'

'

0.4

'

'

Assets from risk management activities (long-term)

'

'

'

'

'

'

9.3

'

'

'

'

'

Property, plant, and equipment

'

'

'

'

'

'

'

'

'

374.4

'

'

Other long-term assets

'

'

'

'

'

'

6.1

'

'

15.6

'

'

Total assets acquired

'

'

'

'

'

'

32.3

'

'

393.4

'

'

Liabilities assumed

'

'

'

'

'

'

'

'

'

'

'

'

Accounts payable

'

'

'

'

'

'

'

'

'

1.8

'

'

Liabilities from risk management activities (current)

'

'

'

'

'

'

8.3

'

'

'

'

'

Other current liabilities

'

'

'

'

'

'

0.5

'

'

'

'

'

Liabilities from risk management activities (long-term)

'

'

'

'

'

'

3.4

'

'

'

'

'

Total liabilities assumed

'

'

'

'

'

'

12.2

'

'

1.8

'

'

Capacity of Fox Energy Center (in megawatts)

'

'

'

'

'

'

'

'

'

593

'

'

Contracted capacity under tolling arrangement (in megawatts)

'

'

'

'

'

'

'

'

'

500

'

'

Contract termination fee related to tolling arrangement

-50

0

0

'

'

'

'

'

'

50

'

'

Amortization period of regulatory asset

'

'

'

'

'

'

'

'

'

'9 years

'

'

Interest rate stated percentage

'

'

'

4.75%

4.75%

'

'

'

'

'

'

'

Number of businesses acquired

'

'

'

'

'

'

'

'

'

'

2

'

Total consideration paid

'

'

'

'

'

'

'

'

'

'

49.6

'

Total cash paid net of cash acquired

391.6

0

0

'

'

'

'

'

'

'

42.6

'

Cash acquired

'

'

'

'

'

'

'

'

'

'

$7

$1.30

DISCONTINUED_OPERATIONS_Detail

DISCONTINUED OPERATIONS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discontinued operations	'	'	'
Discontinued operations, net of tax	$4.80	($9.70)	$0.50
Holding Company and Other	'	'	'
Discontinued operations	'	'	'
Discontinued operations, net of tax	$5.90	$1.80	($0.50)

DISCONTINUED_OPERATIONS_Detail1

DISCONTINUED OPERATIONS (Details 2) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2011

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Nov. 30, 2012

Dec. 31, 2012

Dec. 31, 2011

Sep. 30, 2012

Integrys Energy Services

Integrys Energy Services

Integrys Energy Services

Integrys Energy Services

Integrys Energy Services

Integrys Energy Services

Integrys Energy Services

Integrys Energy Services

Integrys Energy Services

Integrys Energy Services

Integrys Energy Services

Integrys Energy Services

Combined Locks Energy Center

Combined Locks Energy Center

Combined Locks Energy Center

Energy Management Consulting Business

WPS Empire State, Inc

WPS Empire State, Inc

WPS Empire State, Inc

WPS Empire State, Inc

Sunbury Holdings, LLC

Sunbury Holdings, LLC

Sunbury Holdings, LLC

Sunbury Holdings, LLC

WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC

WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC

WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC

WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC

WPS Westwood Generation, LLC

WPS Westwood Generation, LLC

WPS Westwood Generation, LLC

WPS Westwood Generation, LLC

Discontinued operations

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash proceeds related to sale

'

'

'

'

'

'

'

$1.60

'

'

'

$2.60

'

'

'

Earn-out mechanism period

'

'

'

'

'

'

'

'4 years

'

'

'

'

'

'

'

Pre-tax impairment loss

'

'

'

'

'

'

'

'

'

1.1

'

'

'

'

8.4

After-tax impairment loss

'

'

'

'

'

'

'

'

'

0.7

'

'

'

'

5

Carrying value of the derivative contract liabilities assumed by the buyer

'

'

'

'

'

'

'

6.8

'

'

'

'

'

'

'

Period from the sale of discontinued operations within which cash flows will expire

'

'

'

'

'

'

'

'2 years

'

'

'

'

'

'

'

Note receivable from the buyer

'

'

'

'

'

'

'

'

'

'

'

4

'

'

'

Term of note receivable from the buyer

'

'

'

'

'

'

'

'

'

'

'

'7 years 6 months

'

'

'

Assets and liabilities classified as held for sale on balance sheets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Inventories

'

'

'

0.5

0.5

'

'

1.8

'

1.8

'

1

'

'

'

Current assets from risk management activities

'

'

'

'

'

'

'

'

'

'

'

0.1

'

'

'

Other current assets

'

'

'

'

'

'

'

0.2

'

0

'

'

'

'

'

Property, plant, and equipment, net of accumulated depreciation

'

'

'

0.2

2

'

'

5.7

'

5.7

'

5.5

'

'

'

Accumulated depreciation

'

'

'

0

0.5

'

'

'

'

'

'

'

'

'

'

Other long-term assets

'

'

'

'

'

'

'

0.1

'

0.1

'

1.1

'

'

'

Total assets

'

'

'

0.7

2.5

'

'

7.8

'

7.6

'

7.7

'

'

'

Other current liabilities

'

'

'

'

'

'

'

0.4

'

0.2

'

'

'

'

'

Long-term liabilities from risk management activities

'

'

'

'

'

'

'

'

'

'

'

0.1

'

'

'

Components of discontinued operations recorded in income statements

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Nonregulated revenues

'

'

'

-0.1

0.3

7.9

'

'

1.2

0.6

5

'

9.2

12.4

'

Nonregulated cost of sales

'

'

'

-0.2

-0.5

-2

'

'

-0.9

-2

-2.3

'

-4.4

-5.6

'

Operating and maintenance expense

'

'

'

-2.1

-0.5

-0.7

'

'

0.4

-3.5

-3.3

'

-14.3

-5.7

'

Depreciation and amortization expense

'

'

'

0

-0.2

-0.3

'

'

0

-0.6

-0.7

'

-1

-1.4

'

Taxes other than income taxes

'

'

'

0

-0.1

-0.2

'

'

-0.3

-1.4

-0.9

'

-0.2

-0.2

'

Miscellaneous income

'

'

'

'

'

'

'

'

0

0.3

0

'

0

0.1

'

Interest expense

'

'

'

'

'

'

'

'

'

'

'

'

-0.7

-0.6

'

Income (loss) before taxes

'

'

'

-2.4

-1

4.7

'

'

0.4

-6.6

-2.2

'

-11.4

-1

'

(Provision) benefit for income taxes

6.9

9.3

-1.1

1.1

0.4

-1.8

'

'

-0.2

2.6

0.9

'

4.5

0.3

'

Discontinued operations, net of tax

4.8

-9.7

0.5

-1.3

-0.6

2.9

0.1

'

0.2

-4

-1.3

'

-6.9

-0.7

'

Gain (loss) on sale at closing

'

'

'

'

'

'

'

'

$1

'

'

'

($0.60)

'

'

PROPERTY_PLANT_AND_EQUIPMENT_D

PROPERTY, PLANT, AND EQUIPMENT (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

In Millions, unless otherwise specified

Nonutility operations

Nonutility operations

Nonregulated operations

Nonregulated operations

Nonregulated operations

Nonregulated operations

Nonregulated operations

Nonregulated operations

Nonregulated operations

Nonregulated operations

Nonregulated operations

Regulated operations

Regulated operations

Regulated operations

Regulated operations

Regulated operations

Regulated operations

Holding Company and Other

Holding Company and Other

Integrys Energy Services

Integrys Energy Services

Integrys Energy Services

Integrys Energy Services

Integrys Energy Services

Holding Company and Other

Holding Company and Other

Electric Utility

Electric Utility

Natural Gas Utility

Natural Gas Utility

Energy assets

Energy assets

Other

Other

Winnebago Energy Center

Property, plant, and equipment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Property, plant, and equipment, gross

'

'

$142.30

$120.20

$155.70

$123.90

$109.80

$92

$19.70

$17.90

'

$26.20

$14

$8,987.40

$8,146.60

$3,558.90

$3,095.80

$5,428.50

$5,050.80

Less: Accumulated depreciation

3,325.80

3,114.70

81.6

72.3

46.4

36.3

'

'

'

'

'

'

'

3,160.90

3,006.10

'

'

'

'

Net property, plant, and equipment excluding construction work in progress

'

'

60.7

47.9

109.3

87.6

'

'

'

'

'

'

'

5,826.50

5,140.50

'

'

'

'

Construction work in progress

'

'

38

19.6

8.3

3.2

'

'

'

'

'

'

'

353.3

203.1

'

'

'

'

Plant to be retired, net

'

'

'

'

'

'

'

'

'

'

'

'

'

14.4

0

'

'

'

'

Property, plant and equipment, net

6,410.50

5,501.90

98.7

67.5

117.6

90.8

'

'

'

'

'

'

'

6,194.20

5,343.60

'

'

'

'

Pre-tax noncash impairment loss

'

'

'

'

'

'

'

'

'

'

$4.60

'

'

'

'

'

'

'

'

Discount rate used for the impairment analysis (as a percent)

'

'

'

'

'

'

'

'

'

'

7.50%

'

'

'

'

'

'

'

'

JOINTLY_OWNED_UTILITY_FACILITI2

JOINTLY OWNED UTILITY FACILITIES (Details) (WPS, USD $)	Dec. 31, 2013
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	$576.80
Accumulated depreciation	-114.6
Construction work in progress	2.2
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	172.8
Accumulated depreciation	-111.6
Construction work in progress	194.8
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	41.8
Accumulated depreciation	-28.3
Construction work in progress	$0.30

REGULATORY_ASSETS_AND_LIABILIT2

REGULATORY ASSETS AND LIABILITIES (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory assets	'	'
Current assets	$129.40	$110.80
Long-term assets	1,412.60	1,813.80
Total regulatory assets	1,542	1,924.60
Other disclosures	'	'
Environmental remediation liabilities	600.8	651.5
Environmental remediation costs (net of insurance recoveries)	'	'
Regulatory assets	'	'
Total regulatory assets	653	689.7
Other disclosures	'	'
Environmental remediation liabilities	600.8	'
Unrecognized pension and other postretirement benefit costs	'	'
Regulatory assets	'	'
Total regulatory assets	428.8	810
Merger and acquisition related pension and other postretirement benefit costs	'	'
Regulatory assets	'	'
Total regulatory assets	98.3	110.1
Asset retirement obligations	'	'
Regulatory assets	'	'
Total regulatory assets	89.5	73.9
Income tax related items	'	'
Regulatory assets	'	'
Total regulatory assets	55.3	47.6
Termination of a tolling agreement with Fox Energy Company LLC	'	'
Regulatory assets	'	'
Total regulatory assets	50	0
Crane Creek production tax credits	'	'
Regulatory assets	'	'
Total regulatory assets	33.6	34.9
Other disclosures	'	'
Period over which the grant received will be reflected in income through reduction of depreciation and amortization expense	'12 years	'
De Pere Energy Center	'	'
Regulatory assets	'	'
Total regulatory assets	23.8	26.2
Unamortized loss on reacquired debt	'	'
Regulatory assets	'	'
Total regulatory assets	18.5	18.2
Energy efficiency programs	'	'
Regulatory assets	'	'
Total regulatory assets	18	16.7
Energy costs receivable through rate adjustments	'	'
Regulatory assets	'	'
Total regulatory assets	16	18.1
Derivatives	'	'
Regulatory assets	'	'
Total regulatory assets	11.8	30.7
Pension and other postretirement costs receivable through rate adjustments	'	'
Regulatory assets	'	'
Total regulatory assets	9.4	0
Decoupling	'	'
Regulatory assets	'	'
Total regulatory assets	9.3	10.6
Other	'	'
Regulatory assets	'	'
Total regulatory assets	$26.70	$37.90

REGULATORY_ASSETS_AND_LIABILIT3

REGULATORY ASSETS AND LIABILITIES (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Regulatory liabilities	'	'
Current liabilities	$101.50	$65.60
Long-term liabilties	400.9	370.5
Total regulatory liabilities	502.4	436.1
Removal costs	'	'
Regulatory liabilities	'	'
Total regulatory liabilities	335.3	318.4
Decoupling	'	'
Regulatory liabilities	'	'
Total regulatory liabilities	51.7	15.9
Unrecognized pension and other postretirement benefit costs	'	'
Regulatory liabilities	'	'
Total regulatory liabilities	30.2	17.7
Energy costs refundable through rate adjustments	'	'
Regulatory liabilities	'	'
Total regulatory liabilities	27.2	44.4
Energy efficiency programs	'	'
Regulatory liabilities	'	'
Total regulatory liabilities	19.6	8.8
Uncollectible expense	'	'
Regulatory liabilities	'	'
Total regulatory liabilities	10.1	10
Crane Creek depreciation deferral	'	'
Regulatory liabilities	'	'
Total regulatory liabilities	9	9.4
Derivatives	'	'
Regulatory liabilities	'	'
Total regulatory liabilities	6.6	4.3
Fox Energy Center	'	'
Regulatory liabilities	'	'
Total regulatory liabilities	5.6	0
Other disclosures	'	'
Amount of allowance for earnings on equity capitalized for rate making purposes	26.7	'
Other	'	'
Regulatory liabilities	'	'
Total regulatory liabilities	$7.10	$7.20

EQUITY_METHOD_INVESTMENTS_Deta

EQUITY METHOD INVESTMENTS (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Millions, unless otherwise specified
Investments in affiliates, at equity method	'	'	'	'
Equity method investments	$540.90	$512.20	'	'
ATC	'	'	'	'
Investments in affiliates, at equity method	'	'	'	'
Equity method investments	508.4	476.6	439.4	416.3
INDU Solar Holdings, LLC	'	'	'	'
Investments in affiliates, at equity method	'	'	'	'
Equity method investments	24.7	27.5	28.4	0.1
WRPC	'	'	'	'
Investments in affiliates, at equity method	'	'	'	'
Equity method investments	7	7.3	7.7	8.1
Other	'	'	'	'
Investments in affiliates, at equity method	'	'	'	'
Equity method investments	$0.80	$0.80	'	'

EQUITY_METHOD_INVESTMENTS_Deta1

EQUITY METHOD INVESTMENTS (Details 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in equity method investments	'	'	'
Equity method investments balance at beginning of period	$512.20	'	'
Earnings from equity method investments	91.5	87.2	79.4
Add: Capital contributions	13.7	27.4	37.6
Equity method investments balance at end of period	540.9	512.2	'
ATC	'	'	'
Investments in affiliates, at equity method	'	'	'
Equity method investment, ownership interest (as a percent)	34.00%	'	'
Changes in equity method investments	'	'	'
Equity method investments balance at beginning of period	476.6	439.4	416.3
Earnings from equity method investments	89.1	85.3	79.1
Add: Capital contributions	13.7	20.4	8.5
Less: Dividends received	71	68.5	64.5
Equity method investments balance at end of period	508.4	476.6	439.4
INDU Solar Holdings, LLC	'	'	'
Investments in affiliates, at equity method	'	'	'
Equity method investment, ownership interest (as a percent)	50.00%	'	'
Changes in equity method investments	'	'	'
Equity method investments balance at beginning of period	27.5	28.4	0.1
Earnings from equity method investments	1.3	1.1	-0.7
Add: Capital contributions	0	7	29
Less: Return of capital to partners	4.1	9	0
Equity method investments balance at end of period	24.7	27.5	28.4
WRPC	'	'	'
Investments in affiliates, at equity method	'	'	'
Equity method investment, ownership interest (as a percent)	50.00%	'	'
Changes in equity method investments	'	'	'
Equity method investments balance at beginning of period	7.3	7.7	8.1
Earnings from equity method investments	1	0.8	0.9
Less: Dividends received	1.3	1.2	1.3
Equity method investments balance at end of period	$7	$7.30	$7.70

EQUITY_METHOD_INVESTMENTS_Deta2

EQUITY METHOD INVESTMENTS (Details 3) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
ATC	'	'	'
Related party transactions	'	'	'
Revenues from services provided to related party	$11.30	$12.50	$13.50
Expenses related to services received from related party	104.9	100.3	102.7
WRPC	'	'	'
Related party transactions	'	'	'
Revenues from services provided to related party	0.9	0.8	0.7
Expenses related to services received from related party	3.7	5	4.9
Net amounts received from (advanced to) related party	$0	$2.90	$4.70
Number of hydroelectric plants operated	2	'	'
Portion of the energy output sold to WPS	50.00%	'	'
Remaining portion of the energy output sold to Wisconsin Power and Light	50.00%	'	'

EQUITY_METHOD_INVESTMENTS_Deta3

EQUITY METHOD INVESTMENTS (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income statement data	'	'	'
Earnings from equity method investments	$91.50	$87.20	$79.40
ATC, INDU Solar Holdings, LLC, and WRPC	'	'	'
Income statement data	'	'	'
Revenues	642	618.3	575.5
Operating expenses	306.2	292.1	269.6
Other expense	83.7	85.1	81.5
Net income	252.1	241.1	224.4
Earnings from equity method investments	91.4	87.2	79.4
Balance sheet data	'	'	'
Current assets	90.2	81.1	'
Noncurrent assets	3,587.20	3,347.40	'
Total assets	3,677.40	3,428.50	'
Current liabilities	383.6	253	'
Long-term debt	1,559.10	1,559.50	'
Other noncurrent liabilities	134.4	103.5	'
Shareholders' equity	1,600.30	1,512.50	'
Total liabilities and shareholders' equity	$3,677.40	$3,428.50	'

GOODWILL_AND_OTHER_INTANGIBLE_2

GOODWILL AND OTHER INTANGIBLE ASSETS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Changes in the gross carrying amount of goodwill and accumulated impairment losses	'	'
Balance at the beginning of the period, gross goodwill	$955.90	$956
Balance at the beginning of the period, accumulated impairment losses	-297.6	-297.6
Balance at the beginning of the period, net goodwill	658.3	658.4
Adjustment to Trillium and Pinnacle purchase price	0	-0.1
Adjustment to ITF patents/intellectual property	3.8	0
Balance at the end of the period, gross goodwill	959.7	955.9
Balance at the end of the period, accumulated impairment losses	-297.6	-297.6
Balance at the end of the period, net goodwill	662.1	658.3
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	-297.6	-297.6
Balance at the beginning of the period, net goodwill	635.9	635.9
Adjustment to Trillium and Pinnacle purchase price	0	0
Adjustment to ITF patents/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	-297.6	-297.6
Balance at the end of the period, net goodwill	635.9	635.9
Integrys Energy Services	'	'
Changes in the gross carrying amount of goodwill and accumulated impairment losses	'	'
Balance at the beginning of the period, gross goodwill	6.6	6.6
Balance at the beginning of the period, accumulated impairment losses	0	0
Balance at the beginning of the period, net goodwill	6.6	6.6
Adjustment to Trillium and Pinnacle purchase price	0	0
Adjustment to ITF patents/intellectual property	0	0
Balance at the end of the period, gross goodwill	6.6	6.6
Balance at the end of the period, accumulated impairment losses	0	0
Balance at the end of the period, net goodwill	6.6	6.6
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	15.8	15.9
Balance at the beginning of the period, accumulated impairment losses	0	0
Balance at the beginning of the period, net goodwill	15.8	15.9
Adjustment to Trillium and Pinnacle purchase price	0	-0.1
Adjustment to ITF patents/intellectual property	3.8	0
Balance at the end of the period, gross goodwill	19.6	15.8
Balance at the end of the period, accumulated impairment losses	0	0
Balance at the end of the period, net goodwill	$19.60	$15.80

GOODWILL_AND_OTHER_INTANGIBLE_3

GOODWILL AND OTHER INTANGIBLE ASSETS (Details 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	$71.90	$46.60	'
Accumulated amortization of intangible assets	-23.5	-17.9	'
Amortized intangible assets, net	48.4	28.7	'
Unamortized intangible assets	'	'	'
Total intangible assets, gross	82.1	56.8	'
Total intangible assets, net	58.6	38.9	'
Amortization expense for the next five fiscal years	'	'	'
Future amortization expense period	'5 years	'	'
Nonregulated cost of sales	'	'	'
Amortized intangible assets	'	'	'
Amortization expense	2.1	2.5	1.3
Amortization expense for the next five fiscal years	'	'	'
Amortization expense, 2014	3.4	'	'
Amortization expense, 2015	2	'	'
Amortization expense, 2016	1.1	'	'
Amortization expense, 2017	0.9	'	'
Amortization expense, 2018	0.8	'	'
Depreciation and amortization	'	'	'
Amortized intangible assets	'	'	'
Amortization expense	4.2	2.5	3.4
Amortization expense for the next five fiscal years	'	'	'
Amortization expense, 2014	4.3	'	'
Amortization expense, 2015	4.2	'	'
Amortization expense, 2016	4	'	'
Amortization expense, 2017	3.9	'	'
Amortization expense, 2018	3.8	'	'
Customer-related	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	26.8	22.4	'
Accumulated amortization of intangible assets	-15.7	-14.7	'
Amortized intangible assets, net	11.1	7.7	'
Weighted-average amortization period	'P11Y	'	'
Contractual service agreements	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	15.6	0	'
Accumulated amortization of intangible assets	-1.8	0	'
Amortized intangible assets, net	13.8	0	'
Weighted-average amortization period	'P6Y	'	'
Renewable energy credits	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	8.4	3.1	'
Accumulated amortization of intangible assets	0	0	'
Amortized intangible assets, net	8.4	3.1	'
Compressed natural gas fueling contract assets	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	5.6	5.6	'
Accumulated amortization of intangible assets	-2.7	-1.3	'
Amortized intangible assets, net	2.9	4.3	'
Weighted-average amortization period	'P7Y	'	'
Customer-owned equipment modifications	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	4	4	'
Accumulated amortization of intangible assets	-0.9	-0.5	'
Amortized intangible assets, net	3.1	3.5	'
Weighted-average amortization period	'P10Y	'	'
Natural gas and electric contract assets	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	3.9	0	'
Accumulated amortization of intangible assets	-0.5	0	'
Amortized intangible assets, net	3.4	0	'
Weighted-average amortization period	'P4Y	'	'
Nonregulated easements	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	3.7	3.8	'
Accumulated amortization of intangible assets	-1.1	-0.9	'
Amortized intangible assets, net	2.6	2.9	'
Weighted-average amortization period	'P10Y	'	'
Patents/intellectual property	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	3.4	7.2	'
Accumulated amortization of intangible assets	-0.5	-0.3	'
Amortized intangible assets, net	2.9	6.9	'
Weighted-average amortization period	'P9Y	'	'
Other amortized intangible assets	'	'	'
Amortized intangible assets	'	'	'
Amortized intangible assets, carrying amount, gross	0.5	0.5	'
Accumulated amortization of intangible assets	-0.3	-0.2	'
Amortized intangible assets, net	0.2	0.3	'
Trade name | MGU	'	'	'
Unamortized intangible assets	'	'	'
Unamortized intangible asset, carrying amount	5.2	5.2	'
Trade name | Trillium	'	'	'
Unamortized intangible assets	'	'	'
Unamortized intangible asset, carrying amount	3.5	3.5	'
Trade name | Pinnacle	'	'	'
Unamortized intangible assets	'	'	'
Unamortized intangible asset, carrying amount	$1.50	$1.50	'

LEASES_Details

LEASES (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Leases [Abstract]	'	'	'
Rental expense attributable to operating leases	$12.80	$12.40	$12.60
Future minimum rental obligations under non-cancelable operating leases	'	'	'
2014	6.7	'	'
2015	6.4	'	'
2016	6.4	'	'
2017	7.4	'	'
2018	7.3	'	'
Later years	59.4	'	'
Total payments	$93.60	'	'

SHORTTERM_DEBT_AND_LINES_OF_CR2

SHORT-TERM DEBT AND LINES OF CREDIT (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Nov. 30, 2013
Short-term borrowings	'	'	'	'
Short-term borrowings outstanding	$326	$482.40	'	'
Commercial paper	'	'	'	'
Short-term borrowings	'	'	'	'
Short-term borrowings outstanding	326	482.4	303.3	'
Average interest rate (as a percent)	0.22%	0.40%	0.31%	'
Average amount of short-term borrowings outstanding	378.4	326.3	134.9	'
Short-term notes payable	'	'	'	'
Short-term borrowings	'	'	'	'
Short-term borrowings outstanding	'	'	'	200
Average amount of short-term borrowings outstanding	$130.40	$0	$3.60	'

SHORTTERM_DEBT_AND_LINES_OF_CR3

SHORT-TERM DEBT AND LINES OF CREDIT (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Short-term borrowings	'	'	'
Total short-term credit capacity	$1,610	$1,610	'
Letters of credit issued inside credit facilities	52.4	25.5	'
Short-term borrowings outstanding	326	482.4	'
Available capacity under existing agreements	1,231.60	1,102.10	'
Maximum	'	'	'
Short-term borrowings	'	'	'
Debt to capitalization ratio required to be maintained (as a percent)	65.00%	'	'
Integrys Energy Group, Inc.	'	'	'
Short-term borrowings	'	'	'
Short-term borrowings outstanding	123.2	208.4	'
Integrys Energy Group, Inc. | Maximum	'	'	'
Short-term borrowings	'	'	'
Debt to capitalization ratio required to be maintained (as a percent)	65.00%	'	'
WPS | Maximum	'	'	'
Short-term borrowings	'	'	'
Debt to capitalization ratio required to be maintained (as a percent)	65.00%	'	'
PGL | Maximum	'	'	'
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	275	275	'
Revolving credit facility maturing on May 17, 2014 | WPS	'	'	'
Short-term borrowings	'	'	'
Total short-term credit capacity	135	135	'
Revolving credit facility maturing on May 17, 2016 | Integrys Energy Group, Inc.	'	'	'
Short-term borrowings	'	'	'
Total short-term credit capacity	200	200	'
Revolving credit facility maturing on June 13, 2017 | Integrys Energy Group, Inc.	'	'	'
Short-term borrowings	'	'	'
Total short-term credit capacity	635	635	'
Revolving credit facility maturing on June 13, 2017 | WPS	'	'	'
Short-term borrowings	'	'	'
Total short-term credit capacity	115	115	'
Revolving credit facility maturing on June 13, 2017 | PGL	'	'	'
Short-term borrowings	'	'	'
Total short-term credit capacity	250	250	'
Commercial paper	'	'	'
Short-term borrowings	'	'	'
Short-term borrowings outstanding	$326	$482.40	$303.30

LONGTERM_DEBT_Details

LONG-TERM DEBT (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Feb. 28, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Nov. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Apr. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

31-May-13

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Nov. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Apr. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Aug. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

31-May-13

Dec. 31, 2013

Dec. 31, 2012

Nov. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

31-May-13

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Aug. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

In Millions, unless otherwise specified

Maximum

WPS

WPS

WPS

WPS

WPS

WPS

WPS

WPS

WPS

WPS

WPS

WPS

WPS

WPS

WPS

WPS

WPS

WPS

WPS

WPS

WPS

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

PGL

NSG

NSG

NSG

NSG

NSG

NSG

NSG

NSG

NSG

NSG

NSG

Integrys Energy Group, Inc.

Integrys Energy Group, Inc.

Integrys Energy Group, Inc.

Integrys Energy Group, Inc.

Integrys Energy Group, Inc.

Integrys Energy Group, Inc.

Integrys Energy Group, Inc.

Integrys Energy Group, Inc.

Integrys Energy Group, Inc.

Integrys Energy Group, Inc.

Integrys Energy Group, Inc.

Integrys Energy Group, Inc.

Integrys Energy Group, Inc.

Integrys Energy Group, Inc.

Integrys Energy Group, Inc.

Maximum

First Mortgage

First Mortgage

Senior Notes, 4.80% due 2013

Senior Notes, 4.80% due 2013

Senior Notes, 3.95% due 2013

Senior Notes, 3.95% due 2013

Senior Notes, 3.95% due 2013

Senior Notes, 6.375% due 2015

Senior Notes, 6.375% due 2015

Senior Notes, 5.65% due 2017

Senior Notes, 5.65% due 2017

Senior Notes, 6.08% due 2028

Senior Notes, 6.08% due 2028

Senior Notes, 5.55% due 2036

Senior Notes, 5.55% due 2036

Senior Notes, 3.671% due 2042

Senior Notes, 3.671% due 2042

Senior Notes, 4.752% due 2044

Senior Notes, 4.752% due 2044

Senior Notes, 4.752% due 2044

Maximum

Fixed First and Refunding Mortgage Bonds, Series KK, 5.00% bonds due 2033

Fixed First and Refunding Mortgage Bonds, Series KK, 5.00% bonds due 2033

Fixed First and Refunding Mortgage Bonds, Series KK, 5.00% bonds due 2033

Fixed First and Refunding Mortgage Bonds, Series NN-2, 4.625% bonds due 2013

Fixed First and Refunding Mortgage Bonds, Series NN-2, 4.625% bonds due 2013

Fixed First and Refunding Mortgage Bonds, Series NN-2, 4.625% bonds due 2013

Fixed First and Refunding Mortgage Bonds, Series QQ, 4.875% bonds due 2038

Fixed First and Refunding Mortgage Bonds, Series QQ, 4.875% bonds due 2038

Fixed First and Refunding Mortgage Bonds, Series RR, 4.30% bonds due 2035

Fixed First and Refunding Mortgage Bonds, Series RR, 4.30% bonds due 2035

Fixed First and Refunding Mortgage Bonds, Series SS, 7.00% bonds due 2013

Fixed First and Refunding Mortgage Bonds, Series SS, 7.00% bonds due 2013

Fixed First and Refunding Mortgage Bonds, Series SS, 7.00% bonds due 2013

Fixed First and Refunding Mortgage Bonds, Series TT, 8.00% bonds due 2018

Fixed First and Refunding Mortgage Bonds, Series TT, 8.00% bonds due 2018

Fixed First and Refunding Mortgage Bonds, Series UU, 4.63% bonds due 2019

Fixed First and Refunding Mortgage Bonds, Series UU, 4.63% bonds due 2019

Fixed First and Refunding Mortgage Bonds, Series VV, 2.125% bonds due 2030

Fixed First and Refunding Mortgage Bonds, Series VV, 2.125% bonds due 2030

Fixed First and Refunding Mortgage Bonds, Series WW, 2.625% bonds due 2033

Fixed First and Refunding Mortgage Bonds, Series WW, 2.625% bonds due 2033

Fixed First and Refunding Mortgage Bonds, Series XX, 2.21% bonds due 2016

Fixed First and Refunding Mortgage Bonds, Series XX, 2.21% bonds due 2016

Fixed First and Refunding Mortgage Bonds, Series YY, 3.98% bonds due 2042

Fixed First and Refunding Mortgage Bonds, Series YY, 3.98% bonds due 2042

Fixed First and Refunding Mortgage Bonds, Series ZZ, 4.0% bonds due 2033

Fixed First and Refunding Mortgage Bonds, Series ZZ, 4.0% bonds due 2033

Fixed First and Refunding Mortgage Bonds, Series ZZ, 4.0% bonds due 2033

Fixed First and Refunding Mortgage Bonds, Series AAA, 3.96% bonds due 2043

Fixed First and Refunding Mortgage Bonds, Series AAA, 3.96% bonds due 2043

Fixed First and Refunding Mortgage Bonds, Series AAA, 3.96% bonds due 2043

First Mortgage Series N-2, 4.625% bonds due 2013

First Mortgage Series N-2, 4.625% bonds due 2013

First Mortgage Series N-2, 4.625% bonds due 2013

First Mortgage Series O, 7.00% bonds due 2013

First Mortgage Series O, 7.00% bonds due 2013

First Mortgage Series O, 7.00% bonds due 2013

First Mortgage Series P, 3.43% bonds due 2027

First Mortgage Series P, 3.43% bonds due 2027

First Mortgage Series Q, 3.96% bonds due 2043

First Mortgage Series Q, 3.96% bonds due 2043

First Mortgage Series Q, 3.96% bonds due 2043

Maximum

Unsecured Senior Notes, 7.27% due 2014

Unsecured Senior Notes, 7.27% due 2014

Unsecured Senior Notes, 8.00% due 2016

Unsecured Senior Notes, 8.00% due 2016

Unsecured Senior Notes, 4.17% due 2020

Unsecured Senior Notes, 4.17% due 2020

Junior Subordinated Notes, 6.11% due 2066

Junior Subordinated Notes, 6.11% due 2066

Junior Subordinated Notes, 6.11% due 2066

Junior Subordinated Notes, 6.00% due 2073

Junior Subordinated Notes, 6.00% due 2073

Junior Subordinated Notes, 6.00% due 2073

Maximum

LONG-TERM DEBT

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'

'

Interest rate stated percentage

'

'

'

'

7.13%

'

4.80%

'

3.95%

3.95%

'

6.38%

'

5.65%

'

6.08%

'

5.55%

'

3.67%

'

4.75%

4.75%

'

'

5.00%

5.00%

'

4.63%

4.63%

'

4.88%

'

4.30%

'

7.00%

7.00%

'

8.00%

'

4.63%

'

2.13%

'

2.63%

'

2.21%

'

3.98%

'

4.00%

4.00%

'

3.96%

3.96%

'

4.63%

4.63%

'

7.00%

7.00%

'

3.43%

'

3.96%

3.96%

'

'

'

'

7.27%

'

8.00%

'

4.17%

'

6.11%

'

'

6.00%

6.00%

'

Total

$3,056.90

$2,246.40

'

'

$0.10

$0.10

$0

$125

'

$0

$22

$125

$125

$125

$125

$50

$50

$125

$125

$300

$300

'

$450

$0

'

'

$0

$50

'

$0

$75

$75

$75

$50

$50

'

$0

$45

$5

$5

$75

$75

$50

$50

$50

$50

$50

$50

$100

$100

'

$50

$0

'

$220

$0

'

$0

$40

'

$0

$6.50

$28

$28

'

$54

$0

'

'

'

$100

$100

$55

$55

$250

$250

$269.80

$269.80

'

'

$400

$0

Unamortized discount on debt

-0.7

-1.2

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Total debt

3,056.20

2,245.20

'

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Less current portion

100

313.5

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100

0

'

100

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'

Total long-term debt

2,956.20

1,931.70

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

974.7

674.7

'

'

'

'

'

'

'

'

'

'

'

'

'

Principal balance repaid

'

'

'

'

'

'

125

'

22

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50

'

'

75

'

'

'

'

'

'

45

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

40

'

'

6.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of debt issued

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$450

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$50

'

'

$220

'

'

'

'

'

'

'

'

'

'

$54

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$400

'

'

Maximum percentage of notes that can be redeemed or repurchased without replacement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

Debt to capitalization ratio required to be maintained (as a percent)

'

'

65.00%

65.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

65.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

65.00%

'

'

'

'

'

'

'

'

'

'

'

'

LONGTERM_DEBT_Details_2

LONG-TERM DEBT (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Schedule of all principal debt payment amounts related to bond maturities	'	'
2014	$100	'
2015	125	'
2016	105	'
2017	125	'
2018	5	'
Later years	2,596.90	'
Total	$3,056.90	$2,246.40

ASSET_RETIREMENT_OBLIGATIONS_D

ASSET RETIREMENT OBLIGATIONS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in asset retirement obligations	'	'	'
Asset retirement obligations at the beginning of the period	$411.20	$397.20	$320.90
Accretion	20.9	20.4	17.1
Additions and revisions to estimated cash flows	70.6	-0.8	64.9
Settlements	-11.2	-5.6	-5.7
Asset retirement obligations at the end of the period	491.5	411.2	397.2
Utility segments	'	'	'
Changes in asset retirement obligations	'	'	'
Asset retirement obligations at the beginning of the period	409	396.7	320.9
Accretion	20.8	20.3	17.1
Additions and revisions to estimated cash flows	70.1	-2.4	64.4
Settlements	-11.2	-5.6	-5.7
Asset retirement obligations at the end of the period	488.7	409	396.7
Nonregulated segments | Integrys Energy Services	'	'	'
Changes in asset retirement obligations	'	'	'
Asset retirement obligations at the beginning of the period	2.2	0.5	0
Accretion	0.1	0.1	0
Additions and revisions to estimated cash flows	0.5	1.6	0.5
Settlements	0	0	0
Asset retirement obligations at the end of the period	$2.80	$2.20	$0.50

INCOME_TAXES_Details

INCOME TAXES (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Deferred income tax assets	'	'	'
Tax credit carryforwards	$113.50	$105.10	'
Price risk management	13	59.6	'
Other	98.5	76.5	'
Total deferred income tax assets	225	241.2	'
Valuation allowance	-8.2	-7.2	'
Net deferred income tax assets	216.8	234	'
Deferred income tax liabilities	'	'	'
Plant-related	1,373.80	1,215.70	'
Employee benefits	79.6	49.1	'
Regulatory deferrals	78.8	60.8	'
Other	43.5	47.9	'
Total deferred income tax liabilities	1,575.70	1,373.50	'
Balance sheet presentation	'	'	'
Current deferred income tax assets	31.4	64.3	'
Long-term deferred income tax liabilities	1,390.30	1,203.80	'
Net deferred income tax liabilities	1,358.90	1,139.50	'
Income taxes, additional disclosures	'	'	'
Deferred tax credit carryforwards of alternative minimum tax credits	73.9	'	'
Deferred tax credit carryforwards of general business credits	20.9	'	'
Deferred tax credit carryforwards of foreign tax credits	15.2	'	'
Deferred tax credit carryforwards of state tax credits	3.5	'	'
Deferred income tax assets reflecting federal operating loss carryforwards	45.4	'	'
Deferred income tax assets reflecting state operating loss carryforwards	16.4	'	'
Deferred tax assets expiring between 2020 and 2032	'	'	'
2020 through 2025	6.3	'	'
2026 through 2031	9.2	'	'
2032	46.3	'	'
Net regulatory asset for regulatory tax effects	51.6	42.1	'
Components of foreign and domestic income included in income before taxes	'	'	'
Domestic	560.8	443.9	363.4
Foreign	0	-0.1	-0.1
Income before taxes	560.8	443.8	363.3
Current provision	'	'	'
Federal	7.8	3.5	-44.2
State	5.9	0.4	6
Foreign	0.1	-0.1	-0.2
Total current provision	13.8	3.8	-38.4
Deferred provision	'	'	'
Federal	174.8	128.3	158.7
State	14.9	20.1	14.6
Foreign	0	0	0.1
Total deferred provision	189.7	148.4	173.4
Investment tax credits, net	8.4	5.2	-1.1
Penalties	-0.1	-0.3	0.7
Unrecognized tax benefits	0.4	-3	0.9
Interest	-1.4	-4.3	-2.2
Total provision for income taxes related to continuing operations	210.8	149.8	133.3
Total provision for income taxes related to discontiued operations	-6.9	-9.3	1.1
Total	$203.90	$140.50	$134.40
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_Details_2

INCOME TAXES (Details 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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)	3.90%	4.80%	5.30%
Federal tax credits (as a percent)	-0.10%	-1.70%	-2.00%
Benefits and compensation (as a percent)	-0.70%	-2.10%	-2.30%
Other differences, net (as a percent)	-0.50%	-2.20%	0.70%
Effective income tax rate (as a percent)	37.60%	33.80%	36.70%
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement	'	'	'
Statutory federal income tax	$196.30	$155.40	$127.20
State income taxes, net	21.8	21.1	19.1
Federal tax credits	-0.5	-7.6	-7.1
Benefits and compensation	-4.2	-9.4	-8.4
Other differences, net	-2.6	-9.7	2.5
Effective income tax	210.8	149.8	133.3
Reconciliation of the beginning and ending amount of unrecognized tax benefits	'	'	'
Balance at the beginning of the period	11.3	22.4	30.4
Increase related to tax positions taken in prior years	2.2	0.9	3.1
Decrease related to tax positions taken in prior years	-8.7	-6.7	-1.6
Increase related to tax positions taken in current year	0.3	0.6	0.9
Decrease related to settlements	-1.5	-5.7	-9.4
Decrease related to lapse of statutes	0	-0.2	-1
Balance at the end of the period	3.6	11.3	22.4
Unrecognized tax benefits, additional disclosures	'	'	'
Accrued interest related to unrecognized tax benefits	0.8	2.5	'
Accrued penalties related to unrecognized tax benefits	0.4	2	'
Unrecognized tax benefits related to continuing operations that could affect our effective tax rate, if recognized	1.9	'	'
Unrecognized tax benefits related to discontinued operations that could affect our provision for income taxes, if recognized	0.5	'	'
Decrease in liability for unrecognized tax benefits related to effective settlement and remeasurement of uncertain tax positions	6.5	'	'
Reasonable possibility of decrease in unrecognized tax benefits with the next 12 months due to settlement of open examinations	$0.90	'	'

COMMITMENTS_AND_CONTINGENCIES_1

COMMITMENTS AND CONTINGENCIES (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Minimum future commitments for purchase obligations	'
Total Amounts Committed	$2,415.60
2014	800.9
2015	378.6
2016	249.1
2017	164.4
2018	103.7
Later Years	718.9
Purchase Orders	909
Natural gas utility supply and transportation | Regulated operations | Natural Gas Utility	'
Minimum future commitments for purchase obligations	'
Total Amounts Committed	845.9
2014	181.2
2015	169.6
2016	158.4
2017	122
2018	71.7
Later Years	143
Purchased power | Regulated operations | Electric Utility	'
Minimum future commitments for purchase obligations	'
Total Amounts Committed	772.3
2014	80.6
2015	32.8
2016	28.8
2017	27.6
2018	27
Later Years	575.5
Coal supply and transportation | Regulated operations | Electric Utility	'
Minimum future commitments for purchase obligations	'
Total Amounts Committed	99.5
2014	46.3
2015	31
2016	12
2017	6.7
2018	3.5
Later Years	0
Nonregulated electricity and natural gas supply | Nonutility and nonregulated operations | Integrys Energy Services	'
Minimum future commitments for purchase obligations	'
Total Amounts Committed	697.9
2014	492.8
2015	145.2
2016	49.9
2017	8.1
2018	1.5
Later Years	0.4
UPPCO | Regulated operations | Electric Utility	'
Minimum future commitments for purchase obligations	'
Purchase Orders	12.2
UPPCO | Purchased power | Regulated operations | Electric Utility	'
Minimum future commitments for purchase obligations	'
Total Amounts Committed	$9.90

COMMITMENTS_AND_CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Details 2) (USD $)	12 Months Ended	1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Mar. 31, 2013	Jun. 30, 2013	Dec. 31, 2013
	Manufactured Gas Plant Remediation	WPS	WPS	WPS
	Natural Gas Utility	Weston and Pulliam Plants	Columbia And Edgewater	Mercury emission
	site	Electric Utility	Electric Utility	Electric Utility
				MW
Air Permitting Violation Claims	'	'	'	'
Beneficial environmental project amount	'	$6	$1.30	'
Civil penalty and/or legal fees	'	1.2	0.4	'
Mercury and Interstate Air Quality Rules	'	'	'	'
Percentage mercury 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 is required by 2015 (in MW)	'	'	'	150
Percentage mercury reduction by 2015, required by the State of Wisconsin's mercury rule, for electric generating units above 150 MW	'	'	'	90.00%
Level of electric generating units above which a reduction in mercury emissions is required by the Best Available Control Technology rule (in MW)	'	'	'	25
Highest level of electric generating units for which a reduction in mercury emissions is required by the Best Available Control Technology rule (in MW)	'	'	'	150
Estimated capital cost to achieve required emission reduction	'	'	'	8
Manufactured Gas Plant Remediation	'	'	'	'
Number of environmental remediation sites	53	'	'	'
Number of environmental remediation sites transferred to the EPA Superfund Alternative Sites Program	20	'	'	'
Estimated and accrued future undiscounted investigation and cleanup costs for all sites	599.7	'	'	'
Cash expenditures for environmental remediation not yet recovered in rates	49.3	'	'	'
Regulatory assets recorded for cash and estimated future remediation expenditures, net of insurance recoveries received	649	'	'	'
Insurance recoveries received	$65.20	'	'	'

GUARANTEES_Details

GUARANTEES (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Guarantees	'
Total guarantees	$731.40
Guarantees expiring in less than 1 year	443.3
Guarantees expiring within 1 to 3 years	14.3
Guarantees with expiration over 3 years	273.8
Guarantees supporting commodity transactions of subsidiaries	'
Guarantees	'
Total guarantees	597.4
Guarantees expiring in less than 1 year	375.1
Guarantees expiring within 1 to 3 years	2.2
Guarantees with expiration over 3 years	220.1
Guarantees supporting commodity transactions of subsidiaries | Integrys Energy Services	'
Guarantees	'
Total guarantees	430.3
Guarantees supporting commodity transactions of subsidiaries | MERC	'
Guarantees	'
Total guarantees	111.5
Guarantees supporting commodity transactions of subsidiaries | IBS	'
Guarantees	'
Total guarantees	5
Guarantees supporting commodity transactions of subsidiaries | MGU	'
Guarantees	'
Total guarantees	48.6
Guarantees supporting commodity transactions of subsidiaries | UPPCO	'
Guarantees	'
Total guarantees	2
Standby letters of credit	'
Guarantees	'
Total guarantees	55.8
Guarantees expiring in less than 1 year	45.1
Guarantees expiring within 1 to 3 years	10.6
Guarantees with expiration over 3 years	0.1
Standby letters of credit | Integrys Energy Services	'
Guarantees	'
Total guarantees	53.8
Standby letters of credit | ITF, MERC, MGU, NSG, PGL, UPPCO, and WPS	'
Guarantees	'
Total guarantees	2
Surety bonds	'
Guarantees	'
Total guarantees	21.9
Guarantees expiring in less than 1 year	21.9
Guarantees expiring within 1 to 3 years	0
Guarantees with expiration over 3 years	0
Other guarantees	'
Guarantees	'
Total guarantees	56.3
Guarantees expiring in less than 1 year	1.2
Guarantees expiring within 1 to 3 years	1.5
Guarantees with expiration over 3 years	53.6
Other guarantees | Integrys Energy Services	'
Guarantees	'
Total guarantees	35
Other guarantees | Integrys Energy Services | Texas Retail Electric Marketing Business	'
Guarantees	'
Total guarantees	10
Other guarantees | Integrys Energy Services | WPS Beaver Falls Generation, LLC and WPS Syracuse Generation, LLC	'
Guarantees	'
Total guarantees	3
Other guarantees | ITF	'
Guarantees	'
Total guarantees	2.4
Indemnification and workers' compensation coverage	'
Guarantees	'
Total guarantees	$5.90

EMPLOYEE_BENEFIT_PLANS_Details

EMPLOYEE BENEFIT PLANS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans	'	'	'
Long-term liabilities	$211	$625.20	'
Pension Benefits	'	'	'
Change in benefit obligation	'	'	'
Obligation at January 1	1,784.90	1,563.10	'
Service cost	30.2	46	41.4
Interest cost	71.2	78	80.1
Plan amendments	0	0	'
Actuarial (gain) loss, net	-153.1	196.6	'
Participant contributions	0	0	'
Benefit payments	-91.5	-98.8	'
Federal subsidy on benefits paid	0	0	'
Obligation at December 31	1,641.70	1,784.90	1,563.10
Change in fair value of plan assets	'	'	'
Fair value of plan assets at January 1	1,348.10	1,099.50	'
Actual return on plan assets	205.4	173.6	'
Employer contributions	65.7	173.8	'
Participant contributions	0	0	'
Benefit payments	-91.5	-98.8	'
Fair value of plan assets at December 31	1,527.70	1,348.10	1,099.50
Funded status at December 31	-114	-436.8	'
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans	'	'	'
Current liabilities	9	7.9	'
Long-term liabilities	105	428.9	'
Total liabilities	114	436.8	'
Accumulated benefit obligation	1,489.10	1,594.70	'
Information for pension plans with an accumulated benefit obligation in excess of plan assets	'	'	'
Projected benefit obligation	65.4	1,784.90	'
Accumulated benefit obligation	63	1,594.70	'
Fair value of plan assets	0	1,348.10	'
Other Benefits	'	'	'
Change in benefit obligation	'	'	'
Obligation at January 1	621	576.8	'
Service cost	24.9	20.8	19
Interest cost	24.8	28.5	29.5
Plan amendments	0.2	0	'
Actuarial (gain) loss, net	-73.4	14.3	'
Participant contributions	10.6	10.6	'
Benefit payments	-34	-32.1	'
Federal subsidy on benefits paid	2.2	2.1	'
Obligation at December 31	576.3	621	576.8
Change in fair value of plan assets	'	'	'
Fair value of plan assets at January 1	424.4	285.5	'
Actual return on plan assets	57.8	46.3	'
Employer contributions	11.3	114.1	'
Participant contributions	10.6	10.6	'
Benefit payments	-34	-32.1	'
Fair value of plan assets at December 31	470.1	424.4	285.5
Funded status at December 31	-106.2	-196.6	'
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans	'	'	'
Current liabilities	0.2	0.3	'
Long-term liabilities	106	196.3	'
Total liabilities	$106.20	$196.60	'

EMPLOYEE_BENEFIT_PLANS_Details1

EMPLOYEE BENEFIT PLANS (Details 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits	'	'	'
Net regulatory assets	'	'	'
Net actuarial losses	$34.60	'	'
Prior service costs (credits)	0.6	'	'
Total 2014 - estimated amortization	35.2	'	'
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)	'	'	'
Service cost	30.2	46	41.4
Interest cost	71.2	78	80.1
Expected return on plan assets	-105.5	-107.9	-100
Amortization of transition obligation	0	0	0
Amortization of prior service cost (credit)	4	5	5.3
Amortization of net actuarial loss	56.7	34	18.1
Net periodic benefit cost	56.6	55.1	44.9
Pension Benefits | Nonregulated segments	'	'	'
Accumulated other comprehensive loss (pre-tax)	'	'	'
Net actuarial loss	33.3	59.1	'
Prior service costs (credits)	0	0.2	'
Total	33.3	59.3	'
Pension Benefits | Utility segments	'	'	'
Net regulatory assets	'	'	'
Net actuarial loss	399.3	683.1	'
Prior service costs (credits)	2.4	6.2	'
Total	401.7	689.3	'
Other Benefits	'	'	'
Net regulatory assets	'	'	'
Net actuarial losses	2.5	'	'
Prior service costs (credits)	-2.4	'	'
Total 2014 - estimated amortization	0.1	'	'
Components of net periodic benefit cost (including amounts capitalized to the balance sheets)	'	'	'
Service cost	24.9	20.8	19
Interest cost	24.8	28.5	29.5
Expected return on plan assets	-30.6	-28.2	-21.4
Amortization of transition obligation	0	0.3	0.3
Amortization of prior service cost (credit)	-2.5	-3.4	-3.9
Amortization of net actuarial loss	8.4	6.6	4
Net periodic benefit cost	25	24.6	27.5
Other Benefits | Nonregulated segments	'	'	'
Accumulated other comprehensive loss (pre-tax)	'	'	'
Net actuarial loss	0.7	1.3	'
Prior service costs (credits)	-0.2	-0.6	'
Total	0.5	0.7	'
Other Benefits | Utility segments	'	'	'
Net regulatory assets	'	'	'
Net actuarial loss	8.9	117.3	'
Prior service costs (credits)	-12	-14.3	'
Total	($3.10)	$103	'

EMPLOYEE_BENEFIT_PLANS_Details2

EMPLOYEE BENEFIT PLANS (Details 3) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity securities	'	'	'
Target asset allocations	'	'	'
Target asset allocations (as a percent)	70.00%	'	'
Fixed income securities	'	'	'
Target asset allocations	'	'	'
Target asset allocations (as a percent)	30.00%	'	'
Pension Benefits | Benefit obligations	'	'	'
Weighted average assumptions used	'	'	'
Discount rate	4.92%	4.07%	'
Rate of compensation increase	4.24%	4.25%	'
Pension Benefits | Net periodic benefit costs	'	'	'
Weighted average assumptions used	'	'	'
Discount rate	4.07%	5.10%	5.80%
Expected return on plan assets	8.00%	8.25%	8.25%
Rate of compensation	4.25%	4.25%	4.26%
Other Benefits	'	'	'
Weighted average assumptions used	'	'	'
Expected return on assets assumption for the next fiscal year	8.00%	'	'
Effects of a one-percentage-point change in assumed health care cost trend rates	'	'	'
Effect of one-percentage-point increase on total of service and interest cost components of net periodic health care benefit cost	8.2	'	'
Effect of one-percentage-point decrease on total of service and interest cost components of net periodic health care benefit cost	-6.5	'	'
Effect of one-percentage-point increase on the health care component of the accumulated benefit obligation	80.6	'	'
Effect of one-percentage-point decrease on the health care component of the accumulated benefit obligation	-65.5	'	'
Other Benefits | Benefit obligations	'	'	'
Weighted average assumptions used	'	'	'
Discount rate	4.83%	3.96%	'
Assumed medical cost trend rate (as a percent)	6.50%	7.00%	'
Ultimate trend rate (as a percent)	5.00%	5.00%	'
Year ultimate trend rate is reached	'2019	'2019	'
Assumed dental cost trend rate (as a percent)	5.00%	5.00%	'
Other Benefits | Net periodic benefit costs	'	'	'
Weighted average assumptions used	'	'	'
Assumed dental cost trend rate (as a percent)	5.00%	5.00%	5.00%
Discount rate	3.96%	4.94%	5.66%
Expected return on plan assets	8.00%	8.25%	8.25%
Other Benefits | Under age 65 | Net periodic benefit costs	'	'	'
Weighted average assumptions used	'	'	'
Assumed medical cost trend rate (as a percent)	7.00%	7.00%	7.50%
Ultimate trend rate (as a percent)	5.00%	5.00%	5.00%
Year ultimate trend rate is reached	'2019	'2016	'2016
Other Benefits | Over age 65 | Net periodic benefit costs	'	'	'
Weighted average assumptions used	'	'	'
Assumed medical cost trend rate (as a percent)	7.00%	7.50%	8.00%
Ultimate trend rate (as a percent)	5.00%	5.50%	5.50%
Year ultimate trend rate is reached	'2019	'2016	'2016

EMPLOYEE_BENEFIT_PLANS_Details3

EMPLOYEE BENEFIT PLANS (Details 4) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	$1,570.60	$1,390	'
401(h) other benefit plan assets invested as pension assets	-44.1	-36.5	'
Total	1,526.50	1,353.50	'
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	38.6	31.7	'
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	545.5	570.9	'
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	543.1	396.4	'
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	93.6	100.3	'
Pension Plan Assets | Foreign government 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	19.3	24.5	'
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	251.3	198.3	'
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	56.6	'
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	17.4	11.3	'
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	216.5	270.3	'
401(h) other benefit plan assets invested as pension assets	-6.1	-7.1	'
Total	210.4	263.2	'
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	2	6.4	'
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	100.4	167.9	'
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	114.1	96	'
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	0	0	'
Pension Plan Assets | Level 1 | Foreign government 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 | 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	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	1,350.40	1,114.50	'
401(h) other benefit plan assets invested as pension assets	-37.9	-29.3	'
Total	1,312.50	1,085.20	'
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	36.6	25.3	'
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	445.1	403	'
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	429	300.4	'
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	93.6	100.3	'
Pension Plan Assets | Level 2 | Foreign government 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	16.9	20.4	'
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	250	197.3	'
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	56.5	'
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	17.4	11.3	'
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	3.7	5.2	7.8
401(h) other benefit plan assets invested as pension assets	-0.1	-0.1	'
Total	3.6	5.1	'
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 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	2.4	4.1	5.7
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	1.3	1	2.1
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	0
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	425.5	388.6	'
401(h) other benefit plan assets invested as pension assets	44.1	36.5	'
Total	469.6	425.1	'
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	4	9.5	'
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	153.6	156.8	'
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	145	108.5	'
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	121.9	112.7	'
Other Benefit Plan Assets | Foreign government 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 | 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	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	1.1	'
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	163.1	157.2	'
401(h) other benefit plan assets invested as pension assets	6.1	7.1	'
Total	169.2	164.3	'
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	0	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	21.4	27.8	'
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	19.5	15.6	'
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	121.2	112.7	'
Other Benefit Plan Assets | Level 1 | Foreign government 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 | 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	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	1.1	'
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	262.4	231.4	'
401(h) other benefit plan assets invested as pension assets	37.9	29.3	'
Total	300.3	260.7	'
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	4	9.5	'
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	132.2	129	'
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	125.5	92.9	'
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	0.7	0	'
Other Benefit Plan Assets | Level 2 | Foreign government 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 | 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	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	0.1	0.1	'
Total	0.1	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 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 | 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	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_Details4

EMPLOYEE BENEFIT PLANS (Details 5) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of changes in the fair value of pension plan assets	'	'	'
Transfers into Level 3	$15.60	($4.20)	($5.30)
Transfers out of Level 3	7	-11	4.2
Pension Benefits	'	'	'
Reconciliation of changes in the fair value of pension plan assets	'	'	'
Beginning balance at January 1	1,390	'	'
Net realized and unrealized gains (losses)	205.4	173.6	'
Ending balance at December 31	1,570.60	1,390	'
Pension Benefits | Level 3	'	'	'
Reconciliation of changes in the fair value of pension plan assets	'	'	'
Beginning balance at January 1	5.2	7.8	'
Net realized and unrealized gains (losses)	-0.7	0.7	'
Purchases	0.6	1.7	'
Sales	-2.4	-2.4	'
Transfers into Level 3	1.4	0.1	'
Transfers out of Level 3	-0.4	-2.7	'
Ending balance at December 31	3.7	5.2	'
Net realized and unrealized gains (losses)	-0.5	0.4	'
Pension Benefits | Foreign government debt	'	'	'
Reconciliation of changes in the fair value of pension plan assets	'	'	'
Ending balance at December 31	19.3	24.5	'
Pension Benefits | Foreign government debt | Level 3	'	'	'
Reconciliation of changes in the fair value of pension plan assets	'	'	'
Beginning balance at January 1	4.1	5.7	'
Net realized and unrealized gains (losses)	-0.3	0.5	'
Purchases	0.6	1.2	'
Sales	-2	-2	'
Transfers into Level 3	0	0	'
Transfers out of Level 3	0	-1.3	'
Ending balance at December 31	2.4	4.1	'
Net realized and unrealized gains (losses)	-0.2	0.3	'
Pension Benefits | Corporate debt	'	'	'
Reconciliation of changes in the fair value of pension plan assets	'	'	'
Ending balance at December 31	251.3	198.3	'
Pension Benefits | Corporate debt | Level 3	'	'	'
Reconciliation of changes in the fair value of pension plan assets	'	'	'
Beginning balance at January 1	1	2.1	'
Net realized and unrealized gains (losses)	-0.4	0.2	'
Purchases	0	0.5	'
Sales	-0.4	-0.4	'
Transfers into Level 3	1.4	0	'
Transfers out of Level 3	-0.3	-1.4	'
Ending balance at December 31	1.3	1	'
Net realized and unrealized gains (losses)	-0.3	0.1	'
Pension Benefits | Asset-backed securities	'	'	'
Reconciliation of changes in the fair value of pension plan assets	'	'	'
Ending balance at December 31	61.8	56.6	'
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	0	'
Net realized and unrealized gains (losses)	0	0	'
Purchases	0	0	'
Sales	0	0	'
Transfers into Level 3	0	0.1	'
Transfers out of Level 3	-0.1	0	'
Ending balance at December 31	0	0.1	'
Net realized and unrealized gains (losses)	0	0	'
Pension Benefits | Other	'	'	'
Reconciliation of changes in the fair value of pension plan assets	'	'	'
Ending balance at December 31	17.4	11.3	'
Pension Benefits | Other | Level 3	'	'	'
Reconciliation of changes in the fair value of pension plan assets	'	'	'
Ending balance at December 31	$0	$0	'

EMPLOYEE_BENEFIT_PLANS_Details5

EMPLOYEE BENEFIT PLANS (Details 6) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Expected federal subsidies which will partially offset other postretirement benefits	'	'	'
2014	($2.20)	'	'
2015	-2.3	'	'
2016	-2.5	'	'
2017	-2.6	'	'
2018	-2.7	'	'
2019 through 2023	-15.8	'	'
Defined Contribution Benefit Plans	'	'	'
Shares of the entity's common stock held under employee stock ownership plan (ESOP)	3.8	'	'
Market value of shares of the entity's common stock held under employee stock ownership plan (ESOP)	206.4	'	'
Total costs incurred for defined contribution benefit plans	36.4	19.1	17
Deferred compensation plans	'	'	'
Percentage of director fees that can be deferred by nonemployee directors	100.00%	'	'
Deferred compensation obligation classified as an equity instrument	24.8	23.9	'
Deferred compensation obligation associated with deferrals that allow for distribution in cash	53.4	42.9	'
Costs incurred under deferred compensation arrangement	6.5	3.1	2.1
Total costs of the entity's common stock held in the Rabbi Trust	23	17.7	'
Pension Benefits	'	'	'
Employee Benefit Plans	'	'	'
Expected contributions to the plans during the next fiscal year	72.3	'	'
Expected payments, reflecting expected future service	'	'	'
2014	125.1	'	'
2015	123.3	'	'
2016	126.1	'	'
2017	129.3	'	'
2018	125.9	'	'
2019 through 2023	657.6	'	'
Other Benefits	'	'	'
Employee Benefit Plans	'	'	'
Expected contributions to the plans during the next fiscal year	11.9	'	'
Expected payments, reflecting expected future service	'	'	'
2014	30	'	'
2015	32.5	'	'
2016	35	'	'
2017	37.5	'	'
2018	39.9	'	'
2019 through 2023	$234.10	'	'

STOCKBASED_COMPENSATION_Detail

STOCK-BASED COMPENSATION (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Information related to share based awards	'	'	'
Total stock-based compensation expense	$15.60	$17.70	$12.40
Deferred income tax benefit	6.2	7.1	5
Stock-based compensation cost capitalized	0	0	0
Stock Options	'	'	'
Information related to share based awards	'	'	'
Total stock-based compensation expense	1.8	2	1.8
Performance Stock Rights	'	'	'
Information related to share based awards	'	'	'
Total stock-based compensation expense	2.7	5	3.5
Restricted Shares and Restricted Share Units	'	'	'
Information related to share based awards	'	'	'
Total stock-based compensation expense	10.2	9.7	6.1
Nonemployee Director Deferred Stock Units	'	'	'
Information related to share based awards	'	'	'
Total stock-based compensation expense	$0.90	$1	$1

STOCKBASED_COMPENSATION_Detail1

STOCK-BASED COMPENSATION (Details 2) (Stock Options, USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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)	$6.03	$6.30	$6.57
Expected term	'5 years	'5 years	'5 years
Risk-free interest rate, minimum (as a percent)	0.18%	0.17%	0.27%
Risk-free interest rate, maximum (as a percent)	2.11%	2.18%	3.90%
Expected dividend yield (as a percent)	5.33%	5.28%	5.34%
Expected volatility (as a percent)	24.00%	25.00%	25.00%
Stock Options	'	'	'
Outstanding, at the beginning of the period (in shares)	2,046,355	'	'
Granted, (in shares)	319,234	'	'
Exercised (in shares)	-797,705	'	'
Forfeited (in shares)	-15,510	'	'
Expired (in shares)	-2,000	'	'
Outstanding, at the end of the period (in shares)	1,550,374	2,046,355	'
Exercisable at the end of the period (in shares)	810,086	'	'
Weighted-Average Exercise Price	'	'	'
Outstanding at the beginning of the period (in dollars per share)	$49.25	'	'
Granted (in dollars per share)	$56	'	'
Exercised (in dollars per share)	$48.56	'	'
Forfeited (in dollars per share)	$56	'	'
Expired (in dollars per share)	$44.73	'	'
Outstanding at the end of the period (in dollars per share)	$50.93	$49.25	'
Exercisable at the end of the period (in dollars per share)	$49.96	'	'
Weighted-Average Remaining Contractual Life (in Years)	'	'	'
Outstanding at the end of the period	'6 years 2 months	'	'
Exercisable at the end of period	'4 years 7 months	'	'
Aggregate Intrinsic Value	'	'	'
Outstanding at the end of the period (in dollars)	$6.60	'	'
Exercisable at the end of the period (in dollars)	4.3	'	'
Options exercised (in dollars)	9	11	2.8
Additional disclosures	'	'	'
Tax benefit realized for the tax deductions from option exercises	3.6	4.4	'
Compensation cost not yet recognized	$1	'	'
Weighted-average period over which compensation cost is to be recognized	'2 years 5 months	'	'

STOCKBASED_COMPENSATION_Detail2

STOCK-BASED COMPENSATION (Details 3) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Performance Stock Rights	'	'	'
Assumptions incorporated into the valuation models	'	'	'
Risk-free interest rate, minimum (as a percent)	0.13%	0.17%	0.00%
Risk-free interest rate, maximum (as a percent)	1.27%	1.27%	1.27%
Expected volatility, minimum (as a percent)	15.00%	14.00%	21.00%
Expected volatility rate, maximum (as a percent)	36.00%	36.00%	36.00%
Additional disclosures	'	'	'
Compensation cost not yet recognized	$1.30	'	'
Weighted-average period over which compensation cost is to be recognized	'1 year 8 months	'	'
Total intrinsic value of performance stock rights distributed during the period	8.8	4.7	6.3
Tax benefit realized from the distribution of shares	3.6	1.9	2.5
Performance Stock Rights | Minimum	'	'	'
Assumptions incorporated into the valuation models	'	'	'
Expected dividend yield (as a percent)	5.28%	5.18%	5.28%
Performance Stock Rights | Maximum	'	'	'
Assumptions incorporated into the valuation models	'	'	'
Expected dividend yield (as a percent)	5.34%	5.34%	5.34%
Performance Stock Rights Accounted For As Equity Awards	'	'	'
Equity Instruments Other Than Options Roll Forward	'	'	'
Outstanding at the beginning of the period (in shares)	108,314	'	'
Granted (in shares)	22,636	'	'
Award modifications (in shares)	28,789	'	'
Distributed (in shares)	-94,758	'	'
Adjustment for final payout (in shares)	21,867	'	'
Forfeited (in shares)	-1,099	'	'
Outstanding at the end of period (in shares)	85,749	108,314	'
Weighted-Average Fair Value	'	'	'
Outstanding at the beginning of the period (in dollars per share)	$65.38	'	'
Granted (in dollars per share)	$48.50	$52.70	$49.21
Award modifications (in dollars per share)	$39.80	'	'
Distributed (in dollars per share)	$72.36	'	'
Adjustment for final payout (in dollars per shares)	$72.36	'	'
Forfeited (in dollars per share)	$48.50	'	'
Outstanding at the end of the period (in dollars per share)	$46.62	$65.38	'
Performance Stock Rights Accounted For As Liability Awards	'	'	'
Equity Instruments Other Than Options Roll Forward	'	'	'
Outstanding at the beginning of the period (in shares)	189,093	'	'
Granted (in shares)	90,496	'	'
Award modifications (in shares)	-28,789	'	'
Distributed (in shares)	-61,753	'	'
Adjustment for final payout (in shares)	14,255	'	'
Forfeited (in shares)	-4,398	'	'
Outstanding at the end of period (in shares)	198,904	'	'
Weighted-Average Fair Value	'	'	'
Outstanding at end of the period, fair value as of the reporting date (in dollars per share)	$29.77	'	'
Restricted Share Units	'	'	'
Equity Instruments Other Than Options Roll Forward	'	'	'
Outstanding at the beginning of the period (in shares)	505,690	'	'
Granted (in shares)	196,894	'	'
Dividend equivalents (in shares)	24,089	'	'
Vested and released (in shares)	-208,682	'	'
Forfeited (in shares)	-6,690	'	'
Outstanding at the end of period (in shares)	511,301	505,690	'
Weighted-Average Fair Value	'	'	'
Outstanding at the beginning of the period (in dollars per share)	$48.38	'	'
Granted (in dollars per share)	$55.93	$53.24	$49.39
Dividend equivalents (in dollars per share)	$52.20	'	'
Vested and released (in dollars per share)	$46.36	'	'
Forfeited (in dollars per share)	$52.56	'	'
Outstanding at the end of the period (in dollars per share)	$52.24	$48.38	'
Additional disclosures	'	'	'
Compensation cost not yet recognized	10.2	'	'
Weighted-average period over which compensation cost is to be recognized	'2 years 3 months	'	'
Restricted Shares and Restricted Share Units	'	'	'
Additional disclosures	'	'	'
Total intrinsic value of restricted share units vested and released	11.7	10.7	7.5
Tax benefit realized from the distribution of shares	$4.70	$4.30	$3

COMMON_EQUITY_Details

COMMON EQUITY (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes to issued common stock	'	'	'
Common stock issued, balance at beginning of the period	78,287,906	78,287,906	77,781,685
Shares issued - Stock-based compensation	972,718	'	204,331
Shares issued - Stock Investment Plan	298,532	'	149,470
Shares issued - Employee Stock Ownership Plan	248,724	'	105,845
Shares issued - Rabbi trust Shares	111,296	'	48,788
Restricted stock shares cancelled	'	'	-2,213
Common stock issued, balance at end of the period	79,919,176	78,287,906	78,287,906
Value of stock issuance	$79.80	$0	$22.20

COMMON_EQUITY_Details_2

COMMON EQUITY (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Reconciliation of shares outstanding	'	'	'	'
Common stock, shares issued	79,919,176	78,287,906	78,287,906	77,781,685
Deferred compensation rabbi trust (in shares)	473,796	385,439	'	'
Average cost of shares in the rabbi trust (in dollars per share)	$48.50	$46.03	'	'
Total common shares outstanding	79,445,380	77,902,467	'	'

COMMON_EQUITY_Details_3

COMMON EQUITY (Details 3) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Numerator:	'	'	'	'	'	'	'	'	'	'	'
Net income from continuing operations	$132.30	$39.40	($3.90)	$182.20	$69.20	$74.30	$51.70	$98.80	$350	$294	$230
Discontinued operations, net of tax	'	'	'	'	'	'	'	'	4.8	-9.7	0.5
Preferred stock dividends of subsidiary	'	'	'	'	'	'	'	'	-3.1	-3.1	-3.1
Noncontrolling interest in subsidiaries	'	'	'	'	'	'	'	'	0.1	0.2	0
Net income attributed to common shareholders	131.6	38.1	-5.4	187.5	68	65.7	48.8	98.9	351.8	281.4	227.4
Dilutive Securities, Effect on Basic Earnings Per Share	'	'	'	'	'	'	'	'	-0.1	0	0
Net income (loss) attributed to common shareholders, diluted	'	'	'	'	'	'	'	'	$351.70	$281.40	$227.40
Denominator:	'	'	'	'	'	'	'	'	'	'	'
Average shares of common stock - basic	'	'	'	'	'	'	'	'	79.5	78.6	78.6
Effect of dilutive securities - Stock-based compensation (in shares)	'	'	'	'	'	'	'	'	0.4	0.5	0.5
Effect of dilutive securities - Deferred compensation (in shares)	'	'	'	'	'	'	'	'	0.2	0.2	0
Average shares of common stock - diluted	'	'	'	'	'	'	'	'	80.1	79.3	79.1
Earnings (Loss) per common share	'	'	'	'	'	'	'	'	'	'	'
Basic (in dollars per share)	$1.64	$0.48	($0.07)	$2.38	$0.87	$0.84	$0.62	$1.26	$4.43	$3.58	$2.89
Diluted (in dollars per share)	$1.63	$0.47	($0.07)	$2.37	$0.86	$0.83	$0.62	$1.25	$4.39	$3.55	$2.87
Disclosure of antidilutive shares	'	'	'	'	'	'	'	'	'	'	'
Document Fiscal Year Focus	'	'	'	'	'	'	'	'	'2013	'	'
Stock-based compensation	'	'	'	'	'	'	'	'	'	'	'
Disclosure of antidilutive shares	'	'	'	'	'	'	'	'	'	'	'
Antidilutive shares excluded from calculation of diluted earnings per share	'	'	'	'	'	'	'	'	0.3	0.7	0.7
Deferred compensation	'	'	'	'	'	'	'	'	'	'	'
Disclosure of antidilutive shares	'	'	'	'	'	'	'	'	'	'	'
Antidilutive shares excluded from calculation of diluted earnings per share	'	'	'	'	'	'	'	'	0.1	0	0

COMMON_EQUITY_Details_4

COMMON EQUITY (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Dividend Payment Restrictions	'
Total restricted net assets	1,848.70
Equity in undistributed earnings of 50% or less owned investees accounted for by the equity method	143.1
Maximum	'
Dividend Payment Restrictions	'
Debt to capitalization ratio required to be maintained (as a percent)	65.00%
Equity method investment, ownership interest (as a percent)	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
PGL | Maximum	'
Dividend Payment Restrictions	'
Debt to capitalization ratio required to be maintained (as a percent)	65.00%
WPS | Maximum	'
Dividend Payment Restrictions	'
Percentage of common stockholders equity to total capitalization for dividend payment restrictions	25.00%
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 | Public Service Commission of Wisconsin (PSCW)	'
Dividend Payment Restrictions	'
Common equity ratio required to be maintained (as a percent)	51.00%

COMMON_EQUITY_Details_5

COMMON EQUITY (Details 5) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Capital Transactions with Subsidiaries	'
Dividends to parent	$191.60
Return of capital to parent	75
Equity contributions from parent	278.9
ITF	'
Capital Transactions with Subsidiaries	'
Dividends to parent	0
Return of capital to parent	0
Equity contributions from parent	44.3
MERC	'
Capital Transactions with Subsidiaries	'
Dividends to parent	0
Return of capital to parent	21
Equity contributions from parent	13
MGU	'
Capital Transactions with Subsidiaries	'
Dividends to parent	0
Return of capital to parent	12.5
Equity contributions from parent	8
NSG	'
Capital Transactions with Subsidiaries	'
Dividends to parent	12
Return of capital to parent	0
Equity contributions from parent	0
UPPCO	'
Capital Transactions with Subsidiaries	'
Dividends to parent	0
Return of capital to parent	6.5
Equity contributions from parent	0
WPS	'
Capital Transactions with Subsidiaries	'
Dividends to parent	108.6
Return of capital to parent	35
Equity contributions from parent	200
WPS Investments, LLC	'
Capital Transactions with Subsidiaries	'
Dividends to parent	71
Return of capital to parent	0
Equity contributions from parent	$13.60
WPS Investments, LLC	'
Capital Transactions with Subsidiaries	'
Ownership interest (as a percent)	86.22%
WPS Investments, LLC | UPPCO	'
Capital Transactions with Subsidiaries	'
Ownership interest (as a percent)	2.42%
WPS Investments, LLC | WPS	'
Capital Transactions with Subsidiaries	'
Ownership interest (as a percent)	11.36%

PREFERRED_STOCK_OF_SUBSIDIARY_1

PREFERRED STOCK OF SUBSIDIARY (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
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

ACCUMULATED_OTHER_COMPREHENSIV2

ACCUMULATED OTHER COMPREHENSIVE LOSS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Changes in accumulated other comprehensive loss	'
Accumulated other comprehensive loss, balance at beginning of period	($40.90)
Other comprehensive income before reclassifications	13.9
Amounts reclassified out of accumulated other comprehensive loss	3.8
Net current period other comprehensive income	17.7
Accumulated other comprehensive loss, balance at end of period	-23.2
Cash flow hedges	'
Changes in accumulated other comprehensive loss	'
Accumulated other comprehensive loss, balance at beginning of period	-5.2
Other comprehensive income before reclassifications	0.7
Amounts reclassified out of accumulated other comprehensive loss	1.4
Net current period other comprehensive income	2.1
Accumulated other comprehensive loss, balance at end of period	-3.1
Defined benefit plans	'
Changes in accumulated other comprehensive loss	'
Accumulated other comprehensive loss, balance at beginning of period	-35.7
Other comprehensive income before reclassifications	13.2
Amounts reclassified out of accumulated other comprehensive loss	2.4
Net current period other comprehensive income	15.6
Accumulated other comprehensive loss, balance at end of period	($20.10)

ACCUMULATED_OTHER_COMPREHENSIV3

ACCUMULATED OTHER COMPREHENSIVE LOSS (Details 2) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Amount reclassified out of AOCI	'	'	'	'	'	'	'	'	'	'	'
Operating and maintenance expense	'	'	'	'	'	'	'	'	$1,192.30	$1,031.30	$1,024.80
Nonregulated revenues	'	'	'	'	'	'	'	'	-2,209	-1,252.90	-1,391.40
Interest expense	'	'	'	'	'	'	'	'	128.2	120.2	128.2
Total before taxes	'	'	'	'	'	'	'	'	-560.8	-443.8	-363.3
Tax expense	'	'	'	'	'	'	'	'	-210.8	-149.8	-133.3
Net of tax	-132.3	-39.4	3.9	-182.2	-69.2	-74.3	-51.7	-98.8	-350	-294	-230
Amount reclassified	'	'	'	'	'	'	'	'	'	'	'
Amount reclassified out of AOCI	'	'	'	'	'	'	'	'	'	'	'
Net of tax	'	'	'	'	'	'	'	'	3.8	'	'
Utility segments	'	'	'	'	'	'	'	'	'	'	'
Amount reclassified out of AOCI	'	'	'	'	'	'	'	'	'	'	'
Interest expense	'	'	'	'	'	'	'	'	86.6	83.2	90.2
Tax expense	'	'	'	'	'	'	'	'	-181.4	-143.7	-151.7
Net of tax	'	'	'	'	'	'	'	'	-291.3	-256.8	-254.7
Losses on cash flow hedges | Amount reclassified	'	'	'	'	'	'	'	'	'	'	'
Amount reclassified out of AOCI	'	'	'	'	'	'	'	'	'	'	'
Total before taxes	'	'	'	'	'	'	'	'	5	'	'
Tax expense	'	'	'	'	'	'	'	'	3.6	'	'
Net of tax	'	'	'	'	'	'	'	'	1.4	'	'
Losses on cash flow hedges | Commodity derivative contracts | Utility segments | Amount reclassified	'	'	'	'	'	'	'	'	'	'	'
Amount reclassified out of AOCI	'	'	'	'	'	'	'	'	'	'	'
Operating and maintenance expense	'	'	'	'	'	'	'	'	0.2	'	'
Losses on cash flow hedges | Commodity derivative contracts | Nonregulated segments | Amount reclassified	'	'	'	'	'	'	'	'	'	'	'
Amount reclassified out of AOCI	'	'	'	'	'	'	'	'	'	'	'
Nonregulated revenues	'	'	'	'	'	'	'	'	3.7	'	'
Losses on cash flow hedges | Interest rate hedges | Amount reclassified	'	'	'	'	'	'	'	'	'	'	'
Amount reclassified out of AOCI	'	'	'	'	'	'	'	'	'	'	'
Interest expense	'	'	'	'	'	'	'	'	1.1	'	'
Defined benefit plans | Amount reclassified	'	'	'	'	'	'	'	'	'	'	'
Amount reclassified out of AOCI	'	'	'	'	'	'	'	'	'	'	'
Amortization of prior service costs	'	'	'	'	'	'	'	'	4.3	'	'
Amortization of net actuarial gains	'	'	'	'	'	'	'	'	-0.2	'	'
Total before taxes	'	'	'	'	'	'	'	'	4.1	'	'
Tax expense	'	'	'	'	'	'	'	'	1.7	'	'
Net of tax	'	'	'	'	'	'	'	'	$2.40	'	'

VARIABLE_INTEREST_ENTITIES_Det

VARIABLE INTEREST ENTITIES (Details) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

UPPCO

WPS

AMP Trillium LLC

AMP Trillium LLC

PTI CNG Fuels LLC

PTI CNG Fuels LLC

PTI CNG Fuels LLC

EVO Trillium LLC

EVO Trillium LLC

MW

Fox Energy Company LLC

ITF

Other venturer's ownership

ITF

ITF

Other venturer's ownership

ITF

Other venturer's ownership

MW

Variable interest entity

'

'

'

'

'

'

'

'

'

'

'

'

Variable interest entity ownership interest (as a percent)

'

'

'

'

'

30.00%

70.00%

'

50.00%

50.00%

15.00%

85.00%

Remaining percentage ownership interest acquired (as a percent)

'

'

'

'

'

'

'

50.00%

'

'

'

'

Obligations to purchase energy under power purchase agreement (in megawatts)

'

'

'

0

'

'

'

'

'

'

'

'

Contracted capacity under a power purchase agreement (in megawatts)

'

'

'

17.5

500

'

'

'

'

'

'

'

Contract termination fee related to tolling arrangement

($50)

$0

$0

'

$50

'

'

'

'

'

'

'

FAIR_VALUE_Details

FAIR VALUE (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Assets	'	'
Risk Management Assets	$315.50	$190.70
Liabilities	'	'
Risk Management Liabilities	226.6	240.3
Fair value measurements on a recurring basis | Level 1	'	'
Assets	'	'
Risk Management Assets	83.9	70.3
Liabilities	'	'
Risk Management Liabilities	113.6	73.7
Fair value measurements on a recurring basis | Level 2	'	'
Assets	'	'
Risk Management Assets	177.8	100.8
Liabilities	'	'
Risk Management Liabilities	81.3	142.1
Fair value measurements on a recurring basis | Level 3	'	'
Assets	'	'
Risk Management Assets	53.8	19.6
Liabilities	'	'
Risk Management Liabilities	31.7	24.5
Fair value measurements on a recurring basis | Total, Fair value	'	'
Assets	'	'
Risk Management Assets	315.5	190.7
Liabilities	'	'
Risk Management Liabilities	226.6	240.3
Fair value measurements on a recurring basis | Utility segments | Natural gas contracts | Level 1	'	'
Assets	'	'
Risk Management Assets	2.4	0.3
Liabilities	'	'
Risk Management Liabilities	0.5	1.1
Fair value measurements on a recurring basis | Utility segments | Natural gas contracts | Level 2	'	'
Assets	'	'
Risk Management Assets	7.7	3.1
Liabilities	'	'
Risk Management Liabilities	0.6	14.1
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	0
Fair value measurements on a recurring basis | Utility segments | Natural gas contracts | Total, Fair value	'	'
Assets	'	'
Risk Management Assets	10.1	3.4
Liabilities	'	'
Risk Management Liabilities	1.1	15.2
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	2.1	2.1
Liabilities	'	'
Risk Management Liabilities	0.3	0.1
Fair value measurements on a recurring basis | Utility segments | FTRs | Total, Fair value	'	'
Assets	'	'
Risk Management Assets	2.1	2.1
Liabilities	'	'
Risk Management Liabilities	0.3	0.1
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Level 1	'	'
Assets	'	'
Risk Management Assets	0.1	0.2
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Level 2	'	'
Assets	'	'
Risk Management Assets	0	0
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Level 3	'	'
Assets	'	'
Risk Management Assets	0	0
Fair value measurements on a recurring basis | Utility segments | Petroleum product contracts | Total, Fair value	'	'
Assets	'	'
Risk Management Assets	0.1	0.2
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	0
Fair value measurements on a recurring basis | Utility segments | Coal contracts | Level 3	'	'
Assets	'	'
Risk Management Assets	0.2	2.5
Liabilities	'	'
Risk Management Liabilities	2.7	9
Fair value measurements on a recurring basis | Utility segments | Coal contracts | Total, Fair value	'	'
Assets	'	'
Risk Management Assets	0.2	2.5
Liabilities	'	'
Risk Management Liabilities	2.7	9
Fair value measurements on a recurring basis | Nonregulated segments | Level 1	'	'
Assets	'	'
Investment in exchange-traded funds	15.9	11.8
Liabilities	'	'
Contingent Consideration	0	'
Fair value measurements on a recurring basis | Nonregulated segments | Level 2	'	'
Assets	'	'
Investment in exchange-traded funds	0	0
Liabilities	'	'
Contingent Consideration	0	'
Fair value measurements on a recurring basis | Nonregulated segments | Level 3	'	'
Assets	'	'
Investment in exchange-traded funds	0	0
Liabilities	'	'
Contingent Consideration	7.8	'
Fair value measurements on a recurring basis | Nonregulated segments | Total, Fair value	'	'
Assets	'	'
Investment in exchange-traded funds	15.9	11.8
Liabilities	'	'
Contingent Consideration	7.8	'
Fair value measurements on a recurring basis | Nonregulated segments | Natural gas contracts | Level 1	'	'
Assets	'	'
Risk Management Assets	16.3	21.4
Liabilities	'	'
Risk Management Liabilities	14.3	17.7
Fair value measurements on a recurring basis | Nonregulated segments | Natural gas contracts | Level 2	'	'
Assets	'	'
Risk Management Assets	35.2	36.4
Liabilities	'	'
Risk Management Liabilities	22	36.9
Fair value measurements on a recurring basis | Nonregulated segments | Natural gas contracts | Level 3	'	'
Assets	'	'
Risk Management Assets	35.6	5.4
Liabilities	'	'
Risk Management Liabilities	25.2	1.5
Fair value measurements on a recurring basis | Nonregulated segments | Natural gas contracts | Total, Fair value	'	'
Assets	'	'
Risk Management Assets	87.1	63.2
Liabilities	'	'
Risk Management Liabilities	61.5	56.1
Fair value measurements on a recurring basis | Nonregulated segments | Electric contracts | Level 1	'	'
Assets	'	'
Risk Management Assets	65.1	48.4
Liabilities	'	'
Risk Management Liabilities	98.8	54.9
Fair value measurements on a recurring basis | Nonregulated segments | Electric contracts | Level 2	'	'
Assets	'	'
Risk Management Assets	134.9	61.3
Liabilities	'	'
Risk Management Liabilities	58.7	91.1
Fair value measurements on a recurring basis | Nonregulated segments | Electric contracts | Level 3	'	'
Assets	'	'
Risk Management Assets	15.9	9.6
Liabilities	'	'
Risk Management Liabilities	3.5	13.9
Fair value measurements on a recurring basis | Nonregulated segments | Electric contracts | Total, Fair value	'	'
Assets	'	'
Risk Management Assets	215.9	119.3
Liabilities	'	'
Risk Management Liabilities	$161	$159.90

FAIR_VALUE_Details_2

FAIR VALUE (Details 2) (Fair value measurements on a recurring basis, Nonregulated segments, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Natural gas contracts	'	'
Transfers between the levels of the fair value hierarchy	'	'
Transfers into Level 2 from Level 1	$0	$0
Transfers into Level 3 from Level 1	0	0
Transfers into Level 1 from Level 2	0	0
Transfers into Level 3 from Level 2	7.1	3.7
Transfers into Level 1 from Level 3	0	0
Transfers into Level 2 from Level 3	0	2
Electric contracts	'	'
Transfers between the levels of the fair value hierarchy	'	'
Transfers into Level 2 from Level 1	0	0
Transfers into Level 3 from Level 1	-0.2	0
Transfers into Level 1 from Level 2	0	0
Transfers into Level 3 from Level 2	8.7	-7.9
Transfers into Level 1 from Level 3	-0.3	0
Transfers into Level 2 from Level 3	$7.30	($13)

FAIR_VALUE_Details_3

FAIR VALUE (Details 3) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

In Millions, unless otherwise specified

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Fair value measurements on a recurring basis

Level 3

Level 3

Utility segments

Utility segments

Utility segments

Utility segments

Utility segments

Utility segments

Utility segments

Utility segments

Utility segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Nonregulated segments

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

Level 3

FTRs

FTRs

FTRs

Coal contracts

Coal contracts

Coal contracts

Coal contracts

Natural gas contracts

Natural gas contracts

Maximum

Valuation Technique: Market-based

Contingent consideration

Contingent consideration

Natural gas contracts

Natural gas contracts

Natural gas contracts

Natural gas contracts

Electric contracts

Electric contracts

Electric contracts

Electric contracts

Electric contracts

Valuation Technique: Market-based

Valuation Technique: Market-based

Valuation Technique: Market-based

Valuation Technique: Income-based

Valuation Technique: Income-based

Valuation Technique: Market-based

Valuation Technique: Market-based

Valuation Technique: Market-based

Valuation Technique: Market-based

Valuation Technique: Market-based

Weighted Average

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

Fair Value Inputs, Assets and Liabilities, Quantitative Information

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Risk Management Assets

$315.50

$190.70

$53.80

$19.60

$2.10

$2.10

'

$0.20

$2.50

'

'

$0

$0

'

'

'

'

'

$35.60

$5.40

'

'

$15.90

$9.60

'

'

'

Risk Management Liabilities

226.6

240.3

31.7

24.5

0.3

0.1

'

2.7

9

'

'

0

0

'

'

'

'

'

25.2

1.5

'

'

3.5

13.9

'

'

'

Contingent Consideration

'

'

'

'

'

'

'

'

'

'

'

'

'

$7.80

$8

'

'

'

'

'

'

'

'

'

'

'

'

Fair Value Inputs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Forward market prices (in dollars per megawatt-month, ton, dekatherm, or megawatt-hours)

'

'

'

'

'

'

174.52

'

'

11.73

14.3

'

'

'

'

'

'

'

'

'

-1.53

17.3

'

'

'

-3.3

9.25

Probability of default (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11.60%

51.00%

'

'

26.00%

'

'

Counterparty default time period (in years)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

Option volatilities (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

14.80%

199.90%

Monthly curve shaping (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-33.30%

'

'

Growth rate (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-13.20%

49.30%

'

'

'

'

'

'

'

'

'

FAIR_VALUE_Details_4

FAIR VALUE (Details 4) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	($4.90)	($7.90)	$20.70
Net realized and unrealized gains (losses) included in earnings	14.1	-8.9	9.9
Net unrealized gains (losses) recorded as regulatory assets or liabilities	0.1	6	-9.7
Net unrealized gains included in other comprehensive loss	'	'	0.6
Purchases	10.6	12.7	8.1
Sales	-1.3	-0.1	-0.1
Settlements	-12.9	-13.5	-27.9
Net transfers into Level 3	15.6	-4.2	-5.3
Net transfers out of Level 3	-7	11	-4.2
Balance at the end of the period	14.3	-4.9	-7.9
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	12.2	-10.7	11.6
Nonregulated segments | Contingent consideration	'	'	'
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 (losses) included in earnings	-0.1	'	'
Net unrealized gains (losses) recorded as regulatory assets or liabilities	0	'	'
Purchases	-7.7	'	'
Sales	0	'	'
Settlements	0	'	'
Net transfers into Level 3	0	'	'
Net transfers out of Level 3	0	'	'
Balance at the end of the period	-7.8	'	'
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	0	'	'
Nonregulated segments | 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	3.9	8.3	30.2
Net realized and unrealized gains (losses) included in earnings	-1.8	3.8	32.3
Net unrealized gains (losses) recorded as regulatory assets or liabilities	0	0	0
Net unrealized gains included in other comprehensive loss	'	'	0
Purchases	7.4	0	0
Sales	0	0	0
Settlements	-6.2	-9.9	-30.4
Net transfers into Level 3	7.1	3.7	0.6
Net transfers out of Level 3	0	-2	-24.4
Balance at the end of the period	10.4	3.9	8.3
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	-1.8	3.8	32.3
Nonregulated segments | Electric 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	-4.3	-11.5	-14.9
Net realized and unrealized gains (losses) included in earnings	14	-14.5	-20.7
Net unrealized gains (losses) recorded as regulatory assets or liabilities	0	0	0
Net unrealized gains included in other comprehensive loss	'	'	0.6
Purchases	6	7.8	2.2
Sales	-1.1	0	0
Settlements	-3.7	8.8	7
Net transfers into Level 3	8.5	-7.9	-5.9
Net transfers out of Level 3	-7	13	20.2
Balance at the end of the period	12.4	-4.3	-11.5
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	14	-14.5	-20.7
Net unrealized gain (loss) related to discontinued operations	'	-1.2	0.5
Utility segments	'	'	'
Changes in the fair value of items measured on a recurring basis and categorized as Level 3 measurements	'	'	'
Impact on earnings of unrealized gains (losses) on level 3 instruments	0	0	0
Utility segments | 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	2	2.2	2.9
Net realized and unrealized gains (losses) included in earnings	2	1.8	-1.7
Net unrealized gains (losses) recorded as regulatory assets or liabilities	-0.3	0.2	-1.7
Net unrealized gains included in other comprehensive loss	'	'	0
Purchases	4.9	4.9	5.9
Sales	-0.2	-0.1	-0.1
Settlements	-6.6	-7	-3.1
Net transfers into Level 3	0	0	0
Net transfers out of Level 3	0	0	0
Balance at the end of the period	1.8	2	2.2
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	0	0	0
Utility segments | 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	-6.5	-6.9	2.5
Net realized and unrealized gains (losses) included in earnings	0	0	0
Net unrealized gains (losses) recorded as regulatory assets or liabilities	0.4	5.8	-8
Net unrealized gains included in other comprehensive loss	'	'	0
Purchases	0	0	0
Sales	0	0	0
Settlements	3.6	-5.4	-1.4
Net transfers into Level 3	0	0	0
Net transfers out of Level 3	0	0	0
Balance at the end of the period	-2.5	-6.5	-6.9
Net unrealized gains (losses) included in earnings related to instruments still held at the end of the period	$0	$0	$0

FAIR_VALUE_Details_5

FAIR VALUE (Details 5) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Financial instruments not recorded at fair value	'	'
Long-term debt	$3,056.20	$2,245.20
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	3,056.20	2,245.20
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	3,031.60	2,425.80
Preferred stock of subsidiary – $100 par value; 1,000,000 shares authorized; 511,882 shares issued; 510,495 shares outstanding	$61.20	$52.70

ADVERTISING_COSTS_Details

ADVERTISING COSTS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Marketing and Advertising Expense [Abstract]	'	'	'
Capitalized direct-response advertising costs, net of accumulated amortization	$5.20	$5.50	'
Amortization of direct-response advertising costs	5.7	3.8	1.5
Other advertising expense	$8.50	$7.10	$7.40

MISCELLANEOUS_INCOME_Details

MISCELLANEOUS INCOME (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Component of Other Income, Nonoperating [Line Items]	'	'	'
Total miscellaneous income	$29.80	$9.30	$5.30
Equity portion of AFUDC	'	'	'
Component of Other Income, Nonoperating [Line Items]	'	'	'
Total miscellaneous income	10.8	2.9	0.7
Seams elimination charge adjustment (SECA) settlement at Integrys Energy Services	'	'	'
Component of Other Income, Nonoperating [Line Items]	'	'	'
Total miscellaneous income	5.7	0	0
Federal excise tax credit	'	'	'
Component of Other Income, Nonoperating [Line Items]	'	'	'
Total miscellaneous income	4.1	0	0
Key executive life insurance income for retired employees	'	'	'
Component of Other Income, Nonoperating [Line Items]	'	'	'
Total miscellaneous income	2.2	2.6	2.3
Gains (losses) on exchange-traded funds held at IBS	'	'	'
Component of Other Income, Nonoperating [Line Items]	'	'	'
Total miscellaneous income	2.2	1.3	-0.1
Other	'	'	'
Component of Other Income, Nonoperating [Line Items]	'	'	'
Total miscellaneous income	$4.80	$2.50	$2.40

REGULATORY_ENVIRONMENT_Details

REGULATORY ENVIRONMENT (Details) (USD $)

1 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jan. 31, 2013

Mar. 31, 2013

Nov. 30, 2013

Dec. 31, 2013

Dec. 31, 2011

Sep. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Jun. 30, 2013

Jan. 31, 2012

Jan. 31, 2012

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2013

Jul. 31, 2012

Feb. 28, 2014

Feb. 28, 2014

Public Service Commission of Wisconsin (PSCW)

Public Service Commission of Wisconsin (PSCW)

Public Service Commission of Wisconsin (PSCW)

Public Service Commission of Wisconsin (PSCW)

Public Service Commission of Wisconsin (PSCW)

Public Service Commission of Wisconsin (PSCW)

Public Service Commission of Wisconsin (PSCW)

Public Service Commission of Wisconsin (PSCW)

Michigan Public Service Commission (MPSC)

Michigan Public Service Commission (MPSC)

Michigan Public Service Commission (MPSC)

Michigan Public Service Commission (MPSC)

Michigan Public Service Commission (MPSC)

Michigan Public Service Commission (MPSC)

Michigan Public Service Commission (MPSC)

Illinois Commerce Commission (ICC)

Illinois Commerce Commission (ICC)

Illinois Commerce Commission (ICC)

Illinois Commerce Commission (ICC)

Illinois Commerce Commission (ICC)

Illinois Commerce Commission (ICC)

Minnesota Public Utilities Commission (MPUC)

Minnesota Public Utilities Commission (MPUC)

Minnesota Public Utilities Commission (MPUC)

Minnesota Public Utilities Commission (MPUC)

Subsequent Event

Subsequent Event

2014 Rates

2013 Rates

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

Retail electric rate case

Retail electric rate case

Retail electric rate case

MGU

MGU

Retail natural gas rate case

Retail electric rate case

Retail electric rate case

Retail electric rate case

Retail electric rate case

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

MERC

Retail natural gas rate case

Retail natural gas rate case

Retail natural gas rate case

Illinois Commerce Commission (ICC)

Illinois Commerce Commission (ICC)

Rate order

Rate order

2014 Rates

2013 Rates

2012 Rates

2014 Rates

2013 Rates

2012 Rates

2014 Rates

2014 Rates

2012 Rates

2012 Rates

2012 Rates

2013 Rates

2013 Rates

2013 Rates

2013 Rates

2012 Rates

2012 Rates

2014 Rates

2014 Rates

2011 Rates

Retail natural gas rate case

Retail natural gas rate case

WPS

WPS

Rate order

Rate order

Rate order

Rate order

Rate order

Rate order

Rate order

Rate order

Rate order

Rate order

Rate order

Rate order

Rate order

Rate order

Rate order

Rate order

Rate order

Entity's original rate request

Interim rate order

Rate order

2015 Rates

2015 Rates

WPS

WPS

WPS

WPS

WPS

WPS

MGU

UPPCO

UPPCO

UPPCO

UPPCO

NSG

NSG

PGL

PGL

NSG

PGL

MERC

MERC

MERC

Entity's original rate request

Entity's original rate request

NSG

PGL

Regulatory Proceedings:

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual increase (decrease) in rates for customers

'

'

$4

($3.40)

($7.20)

($12.80)

$28.50

$8.10

'

'

$4.50

$5.80

$4.20

'

'

'

$6.60

'

$57.20

$1.90

$57.80

'

$14.20

$10.50

$11

$7.10

$128.90

Return on common equity percent reflected in rates of customers

10.20%

10.30%

'

'

'

'

'

'

'

'

10.25%

10.15%

10.20%

'

'

'

9.28%

'

9.28%

9.45%

9.45%

'

10.75%

9.70%

9.70%

10.25%

10.25%

Percent of capital structure composed of common equity

50.14%

51.61%

'

'

'

'

'

'

'

'

48.62%

56.74%

54.90%

'

'

'

50.32%

'

50.43%

50.00%

49.00%

'

50.31%

50.31%

50.48%

50.41%

50.31%

Estimated fuel refund

'

'

'

'

'

'

20.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deferral related to pension and other employee benefit costs

'

'

'

2.1

'

'

7.3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Recovery of income tax amounts previously expensed related to the Federal Health Care Reform Act

'

5.9

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual cap for decoupling

'

'

'

8

'

'

14

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage variance from the cost of fuel and purchased power included in rates

'

'

'

'

'

'

'

2.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reversal of disallowance of depreciation expense associated with the retirement of certain assets

'

'

'

'

'

'

'

'

2.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reduction to depreciation expense

'

'

'

'

'

'

'

'

'

2.5

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

Annual percent cap on decoupling based on distribution revenues approved in the rate case

'

'

'

'

'

'

'

'

'

'

'

'

1.50%

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

Previously deferred decoupling amounts expensed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.5

'

'

'

'

'

'

'

'

'

'

'

'

Reversal of expense due to reinstatement of electric decoupling

'

'

'

'

'

'

'

'

'

'

'

'

'

1.5

'

'

'

'

'

'

'

'

'

'

'

'

'

Trial basis period for decoupling mechanism

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

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'3 years

'

'

Adjustment to annual increase (decrease) in rates for customers

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$0.10

'

$2.60

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SEGMENTS_OF_BUSINESS_Details

SEGMENTS OF BUSINESS (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
									segment
Segment reporting information	'	'	'	'	'	'	'	'	'	'	'
Number of reportable segments	'	'	'	'	'	'	'	'	5	'	'
External revenues	$1,710.70	$1,129.70	$1,116	$1,678.20	$1,197.20	$927.70	$839.60	$1,247.90	$5,634.60	$4,212.40	$4,685.90
Intersegment revenues	'	'	'	'	'	'	'	'	0	0	0
Depreciation and amortization expense	'	'	'	'	'	'	'	'	266.6	250.7	247.7
Earnings from equity method investments	'	'	'	'	'	'	'	'	91.5	87.2	79.4
Miscellaneous income	'	'	'	'	'	'	'	'	29.8	9.3	5.3
Interest expense	'	'	'	'	'	'	'	'	128.2	120.2	128.2
Provision for income taxes	'	'	'	'	'	'	'	'	210.8	149.8	133.3
Net income (loss) from continuing operations	132.3	39.4	-3.9	182.2	69.2	74.3	51.7	98.8	350	294	230
Discontinued operations, net of tax	'	'	'	'	'	'	'	'	4.8	-9.7	0.5
Preferred stock dividends of subsidiary	'	'	'	'	'	'	'	'	-3.1	-3.1	-3.1
Noncontrolling interest in subsidiaries	'	'	'	'	'	'	'	'	0.1	0.2	0
Net income attributed to common shareholders	131.6	38.1	-5.4	187.5	68	65.7	48.8	98.9	351.8	281.4	227.4
Total assets	11,243.50	'	'	'	10,327.40	'	'	'	11,243.50	10,327.40	9,983.20
Cash expenditures for long-lived assets	'	'	'	'	'	'	'	'	1,060.80	594.3	310.1
ATC	'	'	'	'	'	'	'	'	'	'	'
Segment reporting information	'	'	'	'	'	'	'	'	'	'	'
Equity method investment, ownership interest (as a percent)	34.00%	'	'	'	'	'	'	'	34.00%	'	'
Earnings from equity method investments	'	'	'	'	'	'	'	'	89.1	85.3	79.1
Holding Company and Other	'	'	'	'	'	'	'	'	'	'	'
Segment reporting information	'	'	'	'	'	'	'	'	'	'	'
Discontinued operations, net of tax	'	'	'	'	'	'	'	'	5.9	1.8	-0.5
Reconciling Eliminations	'	'	'	'	'	'	'	'	'	'	'
Segment reporting information	'	'	'	'	'	'	'	'	'	'	'
External revenues	'	'	'	'	'	'	'	'	0	0	0
Intersegment revenues	'	'	'	'	'	'	'	'	-14.2	-12.7	-13.4
Depreciation and amortization expense	'	'	'	'	'	'	'	'	-0.5	-0.5	-0.5
Earnings from equity method investments	'	'	'	'	'	'	'	'	0	0	0
Miscellaneous income	'	'	'	'	'	'	'	'	-13.3	-15.9	-17
Interest expense	'	'	'	'	'	'	'	'	-13.3	-15.9	-17
Provision for income taxes	'	'	'	'	'	'	'	'	0	0	0
Net income (loss) from continuing operations	'	'	'	'	'	'	'	'	0	0	0
Discontinued operations, net of tax	'	'	'	'	'	'	'	'	0	0	0
Preferred stock dividends of subsidiary	'	'	'	'	'	'	'	'	0	0	0
Noncontrolling interest in subsidiaries	'	'	'	'	'	'	'	'	0	0	'
Net income attributed to common shareholders	'	'	'	'	'	'	'	'	0	0	0
Total assets	-786.5	'	'	'	-653.7	'	'	'	-786.5	-653.7	-578.9
Cash expenditures for long-lived assets	'	'	'	'	'	'	'	'	0	0	0
Regulated operations	'	'	'	'	'	'	'	'	'	'	'
Segment reporting information	'	'	'	'	'	'	'	'	'	'	'
External revenues	'	'	'	'	'	'	'	'	3,425.60	2,959.50	3,294.50
Intersegment revenues	'	'	'	'	'	'	'	'	11.5	9.9	10.8
Depreciation and amortization expense	'	'	'	'	'	'	'	'	234.6	220.8	214.6
Earnings from equity method investments	'	'	'	'	'	'	'	'	89.1	85.3	79.1
Miscellaneous income	'	'	'	'	'	'	'	'	11	3.2	3
Interest expense	'	'	'	'	'	'	'	'	86.6	83.2	90.2
Provision for income taxes	'	'	'	'	'	'	'	'	181.4	143.7	151.7
Net income (loss) from continuing operations	'	'	'	'	'	'	'	'	291.3	256.8	254.7
Discontinued operations, net of tax	'	'	'	'	'	'	'	'	0	0	0
Preferred stock dividends of subsidiary	'	'	'	'	'	'	'	'	-3.1	-3.1	-3.1
Noncontrolling interest in subsidiaries	'	'	'	'	'	'	'	'	0	0	'
Net income attributed to common shareholders	'	'	'	'	'	'	'	'	288.2	253.7	251.6
Total assets	9,694.90	'	'	'	8,964.10	'	'	'	9,694.90	8,964.10	8,455.30
Cash expenditures for long-lived assets	'	'	'	'	'	'	'	'	985	539	283.4
Regulated operations | Natural Gas Utility	'	'	'	'	'	'	'	'	'	'	'
Segment reporting information	'	'	'	'	'	'	'	'	'	'	'
External revenues	'	'	'	'	'	'	'	'	2,093.60	1,662.10	1,987.20
Intersegment revenues	'	'	'	'	'	'	'	'	11.4	9.9	10.8
Depreciation and amortization expense	'	'	'	'	'	'	'	'	136	131.8	126.1
Earnings from equity method investments	'	'	'	'	'	'	'	'	0	0	0
Miscellaneous income	'	'	'	'	'	'	'	'	1.2	0.6	2.2
Interest expense	'	'	'	'	'	'	'	'	50.2	47.3	48.4
Provision for income taxes	'	'	'	'	'	'	'	'	78.9	61.4	61.2
Net income (loss) from continuing operations	'	'	'	'	'	'	'	'	124	94	103.9
Discontinued operations, net of tax	'	'	'	'	'	'	'	'	0	0	0
Preferred stock dividends of subsidiary	'	'	'	'	'	'	'	'	-0.6	-0.6	-0.6
Noncontrolling interest in subsidiaries	'	'	'	'	'	'	'	'	0	0	'
Net income attributed to common shareholders	'	'	'	'	'	'	'	'	123.4	93.4	103.3
Total assets	5,672	'	'	'	5,446.20	'	'	'	5,672	5,446.20	5,033
Cash expenditures for long-lived assets	'	'	'	'	'	'	'	'	370	375.1	199.3
Regulated operations | Electric Utility	'	'	'	'	'	'	'	'	'	'	'
Segment reporting information	'	'	'	'	'	'	'	'	'	'	'
External revenues	'	'	'	'	'	'	'	'	1,332	1,297.40	1,307.30
Intersegment revenues	'	'	'	'	'	'	'	'	0.1	0	0
Depreciation and amortization expense	'	'	'	'	'	'	'	'	98.6	89	88.5
Earnings from equity method investments	'	'	'	'	'	'	'	'	0	0	0
Miscellaneous income	'	'	'	'	'	'	'	'	9.8	2.6	0.8
Interest expense	'	'	'	'	'	'	'	'	36.4	35.9	41.8
Provision for income taxes	'	'	'	'	'	'	'	'	67.3	49.4	59.2
Net income (loss) from continuing operations	'	'	'	'	'	'	'	'	113.4	110.4	103
Discontinued operations, net of tax	'	'	'	'	'	'	'	'	0	0	0
Preferred stock dividends of subsidiary	'	'	'	'	'	'	'	'	-2.5	-2.5	-2.5
Noncontrolling interest in subsidiaries	'	'	'	'	'	'	'	'	0	0	'
Net income attributed to common shareholders	'	'	'	'	'	'	'	'	110.9	107.9	100.5
Total assets	3,514.40	'	'	'	3,041.30	'	'	'	3,514.40	3,041.30	2,982.90
Cash expenditures for long-lived assets	'	'	'	'	'	'	'	'	615	163.9	84.1
Regulated operations | Electric Transmission Investment	'	'	'	'	'	'	'	'	'	'	'
Segment reporting information	'	'	'	'	'	'	'	'	'	'	'
External revenues	'	'	'	'	'	'	'	'	0	0	0
Intersegment revenues	'	'	'	'	'	'	'	'	0	0	0
Depreciation and amortization expense	'	'	'	'	'	'	'	'	0	0	0
Earnings from equity method investments	'	'	'	'	'	'	'	'	89.1	85.3	79.1
Miscellaneous income	'	'	'	'	'	'	'	'	0	0	0
Interest expense	'	'	'	'	'	'	'	'	0	0	0
Provision for income taxes	'	'	'	'	'	'	'	'	35.2	32.9	31.3
Net income (loss) from continuing operations	'	'	'	'	'	'	'	'	53.9	52.4	47.8
Discontinued operations, net of tax	'	'	'	'	'	'	'	'	0	0	0
Preferred stock dividends of subsidiary	'	'	'	'	'	'	'	'	0	0	0
Noncontrolling interest in subsidiaries	'	'	'	'	'	'	'	'	0	0	'
Net income attributed to common shareholders	'	'	'	'	'	'	'	'	53.9	52.4	47.8
Total assets	508.5	'	'	'	476.6	'	'	'	508.5	476.6	439.4
Cash expenditures for long-lived assets	'	'	'	'	'	'	'	'	0	0	0
Nonutility and nonregulated operations | Integrys Energy Services	'	'	'	'	'	'	'	'	'	'	'
Segment reporting information	'	'	'	'	'	'	'	'	'	'	'
External revenues	'	'	'	'	'	'	'	'	2,166.20	1,217.60	1,372
Intersegment revenues	'	'	'	'	'	'	'	'	1.3	0.9	1.1
Depreciation and amortization expense	'	'	'	'	'	'	'	'	11.4	10.3	10.3
Earnings from equity method investments	'	'	'	'	'	'	'	'	1.3	1.1	-0.7
Miscellaneous income	'	'	'	'	'	'	'	'	8.5	1.1	1
Interest expense	'	'	'	'	'	'	'	'	2	2.1	1.7
Provision for income taxes	'	'	'	'	'	'	'	'	48	25.8	-7.7
Net income (loss) from continuing operations	'	'	'	'	'	'	'	'	79.4	52.6	-7.1
Discontinued operations, net of tax	'	'	'	'	'	'	'	'	-1.1	-11.5	1
Preferred stock dividends of subsidiary	'	'	'	'	'	'	'	'	0	0	0
Noncontrolling interest in subsidiaries	'	'	'	'	'	'	'	'	0	0	'
Net income attributed to common shareholders	'	'	'	'	'	'	'	'	78.3	41.1	-6.1
Total assets	989.2	'	'	'	749.2	'	'	'	989.2	749.2	891.5
Cash expenditures for long-lived assets	'	'	'	'	'	'	'	'	15.8	30.9	16.7
Nonutility and nonregulated operations | Holding Company and Other	'	'	'	'	'	'	'	'	'	'	'
Segment reporting information	'	'	'	'	'	'	'	'	'	'	'
External revenues	'	'	'	'	'	'	'	'	42.8	35.3	19.4
Intersegment revenues	'	'	'	'	'	'	'	'	1.4	1.9	1.5
Depreciation and amortization expense	'	'	'	'	'	'	'	'	21.1	20.1	23.3
Earnings from equity method investments	'	'	'	'	'	'	'	'	1.1	0.8	1
Miscellaneous income	'	'	'	'	'	'	'	'	23.6	20.9	18.3
Interest expense	'	'	'	'	'	'	'	'	52.9	50.8	53.3
Provision for income taxes	'	'	'	'	'	'	'	'	-18.6	-19.7	-10.7
Net income (loss) from continuing operations	'	'	'	'	'	'	'	'	-20.7	-15.4	-17.6
Discontinued operations, net of tax	'	'	'	'	'	'	'	'	5.9	1.8	-0.5
Preferred stock dividends of subsidiary	'	'	'	'	'	'	'	'	0	0	0
Noncontrolling interest in subsidiaries	'	'	'	'	'	'	'	'	0.1	0.2	'
Net income attributed to common shareholders	'	'	'	'	'	'	'	'	-14.7	-13.4	-18.1
Total assets	1,345.90	'	'	'	1,267.80	'	'	'	1,345.90	1,267.80	1,215.30
Cash expenditures for long-lived assets	'	'	'	'	'	'	'	'	$60	$24.40	$10

QUARTERLY_FINANCIAL_INFORMATIO2

QUARTERLY FINANCIAL INFORMATION (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	$1,710.70	$1,129.70	$1,116	$1,678.20	$1,197.20	$927.70	$839.60	$1,247.90	$5,634.60	$4,212.40	$4,685.90
Operating income (loss)	226.2	55.3	-6.9	293.1	118.8	108.5	87.1	153.1	567.7	467.5	406.8
Net income (loss) from continuing operations	132.3	39.4	-3.9	182.2	69.2	74.3	51.7	98.8	350	294	230
Net income (loss)	132.4	38.8	-4.7	188.3	68.7	66.3	49.6	99.7	354.8	284.3	230.5
Net income (loss) attributed to common shareholders	$131.60	$38.10	($5.40)	$187.50	$68	$65.70	$48.80	$98.90	$351.80	$281.40	$227.40
Earnings (loss) per common share (basic)	'	'	'	'	'	'	'	'	'	'	'
Net income (loss) from continuing operations (in dollars per share)	$1.64	$0.49	($0.06)	$2.30	$0.87	$0.94	$0.65	$1.25	$4.37	$3.70	$2.89
Discontinued operations, net of tax (in dollars per share)	$0	($0.01)	($0.01)	$0.08	$0	($0.10)	($0.03)	$0.01	$0.06	($0.12)	$0
Earnings per common share (basic) (in dollars per share)	$1.64	$0.48	($0.07)	$2.38	$0.87	$0.84	$0.62	$1.26	$4.43	$3.58	$2.89
Earnings (loss) per common share (diluted)	'	'	'	'	'	'	'	'	'	'	'
Net income (loss) from continuing operations (in dollars per share)	$1.63	$0.48	($0.06)	$2.29	$0.86	$0.93	$0.65	$1.24	$4.33	$3.67	$2.87
Discontinued operations, net of tax (in dollars per share)	$0	($0.01)	($0.01)	$0.08	$0	($0.10)	($0.03)	$0.01	$0.06	($0.12)	$0
Earnings per common share (diluted) (in dollars per share)	$1.63	$0.47	($0.07)	$2.37	$0.86	$0.83	$0.62	$1.25	$4.39	$3.55	$2.87

SUBSEQUENT_EVENT_Details

SUBSEQUENT EVENT (Details) (Upper Peninsula Power Company, Inc., Electric, USD $)	Jan. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Disclosures related to the disposal	'	'
Expected proceeds from sale	$298.80	'
Balances of the assets and liabilities included in the disposal group	'	'
Current assets	'	26.5
Property, plant, and equipment, net of accumulated depreciation	'	193.8
Accumulated depreciation	'	88.9
Other long-term assets	'	51.5
Total assets	'	271.8
Current liabilities	'	21.2
Long-term liabilities	'	32.4
Total liabilities	'	$53.60
Minimum	'	'
Disclosures related to the disposal	'	'
Transition period for administrative and operational services	'18 months	'
Maximum	'	'
Disclosures related to the disposal	'	'
Transition period for administrative and operational services	'30 months	'

SCHEDULE_I_CONDENSED_PARENT_CO1

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS STATEMENTS OF INCOME (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Financial Statements, Captions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Operating income	$226.20	$55.30	($6.90)	$293.10	$118.80	$108.50	$87.10	$153.10	$567.70	$467.50	$406.80
Equity earnings from subsidiaries	'	'	'	'	'	'	'	'	91.5	87.2	79.4
Miscellaneous income	'	'	'	'	'	'	'	'	29.8	9.3	5.3
Interest expense	'	'	'	'	'	'	'	'	128.2	120.2	128.2
Other expense	'	'	'	'	'	'	'	'	-6.9	-23.7	-43.5
Income before taxes	'	'	'	'	'	'	'	'	560.8	443.8	363.3
Provision for income taxes	'	'	'	'	'	'	'	'	210.8	149.8	133.3
Net income from continuing operations	132.3	39.4	-3.9	182.2	69.2	74.3	51.7	98.8	350	294	230
Net income attributed to common shareholders	131.6	38.1	-5.4	187.5	68	65.7	48.8	98.9	351.8	281.4	227.4
Average shares of common stock	'	'	'	'	'	'	'	'	'	'	'
Basic (in shares)	'	'	'	'	'	'	'	'	79.5	78.6	78.6
Diluted (in shares)	'	'	'	'	'	'	'	'	80.1	79.3	79.1
Earnings (loss) per common share (basic)	'	'	'	'	'	'	'	'	'	'	'
Net income from continuing operations (in dollars per share)	$1.64	$0.49	($0.06)	$2.30	$0.87	$0.94	$0.65	$1.25	$4.37	$3.70	$2.89
Discontinued operations, net of tax (in dollars per share)	$0	($0.01)	($0.01)	$0.08	$0	($0.10)	($0.03)	$0.01	$0.06	($0.12)	$0
Earnings per common share (basic) (in dollars per share)	$1.64	$0.48	($0.07)	$2.38	$0.87	$0.84	$0.62	$1.26	$4.43	$3.58	$2.89
Earnings (loss) per common share (diluted)	'	'	'	'	'	'	'	'	'	'	'
Net income from continuing operations (in dollars per share)	$1.63	$0.48	($0.06)	$2.29	$0.86	$0.93	$0.65	$1.24	$4.33	$3.67	$2.87
Discontinued operations, net of tax (in dollars per share)	$0	($0.01)	($0.01)	$0.08	$0	($0.10)	($0.03)	$0.01	$0.06	($0.12)	$0
Earnings per common share (diluted) (in dollars per share)	$1.63	$0.47	($0.07)	$2.37	$0.86	$0.83	$0.62	$1.25	$4.39	$3.55	$2.87
Integrys Energy Group, Inc.	'	'	'	'	'	'	'	'	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Operating expense	'	'	'	'	'	'	'	'	8.2	6	5.9
Operating income	'	'	'	'	'	'	'	'	-8.2	-6	-5.9
Equity earnings from subsidiaries	'	'	'	'	'	'	'	'	397.1	332.4	275.5
Miscellaneous income	'	'	'	'	'	'	'	'	18.5	21.2	24.2
Interest expense	'	'	'	'	'	'	'	'	52.1	50	52.2
Other expense	'	'	'	'	'	'	'	'	363.5	303.6	247.5
Income before taxes	'	'	'	'	'	'	'	'	355.3	297.6	241.6
Provision for income taxes	'	'	'	'	'	'	'	'	8.3	6.5	14.7
Net income from continuing operations	'	'	'	'	'	'	'	'	347	291.1	226.9
Discontinued operations from Parent Company, net of tax	'	'	'	'	'	'	'	'	0.6	1.4	-0.2
Discontinued operations from subsidiaries, net of tax	'	'	'	'	'	'	'	'	4.2	-11.1	0.7
Net income attributed to common shareholders	'	'	'	'	'	'	'	'	$351.80	$281.40	$227.40
Average shares of common stock	'	'	'	'	'	'	'	'	'	'	'
Basic (in shares)	'	'	'	'	'	'	'	'	79.5	78.6	78.6
Diluted (in shares)	'	'	'	'	'	'	'	'	80.1	79.3	79.1
Earnings (loss) per common share (basic)	'	'	'	'	'	'	'	'	'	'	'
Net income from continuing operations (in dollars per share)	'	'	'	'	'	'	'	'	$4.37	$3.70	$2.89
Discontinued operations, net of tax (in dollars per share)	'	'	'	'	'	'	'	'	$0.06	($0.12)	$0
Earnings per common share (basic) (in dollars per share)	'	'	'	'	'	'	'	'	$4.43	$3.58	$2.89
Earnings (loss) per common share (diluted)	'	'	'	'	'	'	'	'	'	'	'
Net income from continuing operations (in dollars per share)	'	'	'	'	'	'	'	'	$4.33	$3.67	$2.87
Discontinued operations, net of tax (in dollars per share)	'	'	'	'	'	'	'	'	$0.06	($0.12)	$0
Earnings per common share (diluted) (in dollars per share)	'	'	'	'	'	'	'	'	$4.39	$3.55	$2.87

SCHEDULE_I_CONDENSED_PARENT_CO2

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS STATEMENTS OF COMPREHENSIVE INCOME (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Financial Statements, Captions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Net income (loss) attributed to common shareholders	$131.60	$38.10	($5.40)	$187.50	$68	$65.70	$48.80	$98.90	$351.80	$281.40	$227.40
Cash flow hedges	'	'	'	'	'	'	'	'	'	'	'
Unrealized net gains (losses) arising during period, net of tax of $ – million, $0.1 million, and $(0.3) million, respectively	'	'	'	'	'	'	'	'	0.7	-0.2	1.5
Unrealized net gains (losses) arising during period, tax	'	'	'	'	'	'	'	'	0.1	-0.1	0.4
Reclassification of net (gains) losses to net income, net of tax of $2.0 million, $(1.0) million, and $0.2 million, respectively	'	'	'	'	'	'	'	'	1.4	6.5	7.4
Reclassification of net losses to net income, tax	'	'	'	'	'	'	'	'	3.6	2	4.4
Cash flow hedges, net	'	'	'	'	'	'	'	'	2.1	6.3	8.9
Defined benefit plans	'	'	'	'	'	'	'	'	'	'	'
Pension and other postretirement benefit costs arising during the period, net of tax of $ - million, $(0.9) million, and $(0.7) million, respectively	'	'	'	'	'	'	'	'	13.2	-6.1	-7.5
Pension and other postretirement benefit costs arising during period, tax	'	'	'	'	'	'	'	'	8.9	-4.4	-5.7
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $0.9 million, $0.4 million, and $0.1 million, respectively	'	'	'	'	'	'	'	'	2.4	1.4	0.8
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, tax	'	'	'	'	'	'	'	'	1.7	1	0.6
Defined benefit plans, net	'	'	'	'	'	'	'	'	15.6	-4.7	-6.7
Other comprehensive income, net of tax	'	'	'	'	'	'	'	'	17.7	1.6	2.2
Comprehensive income attributed to common shareholders	'	'	'	'	'	'	'	'	369.5	283	229.6
Integrys Energy Group, Inc.	'	'	'	'	'	'	'	'	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Net income (loss) attributed to common shareholders	'	'	'	'	'	'	'	'	351.8	281.4	227.4
Cash flow hedges	'	'	'	'	'	'	'	'	'	'	'
Unrealized net gains (losses) arising during period, net of tax of $ – million, $0.1 million, and $(0.3) million, respectively	'	'	'	'	'	'	'	'	0.6	-0.1	0.3
Unrealized net gains (losses) arising during period, tax	'	'	'	'	'	'	'	'	0	0.1	-0.3
Reclassification of net (gains) losses to net income, net of tax of $2.0 million, $(1.0) million, and $0.2 million, respectively	'	'	'	'	'	'	'	'	-0.9	2.1	1.1
Reclassification of net losses to net income, tax	'	'	'	'	'	'	'	'	2	-1	0.2
Cash flow hedges, net	'	'	'	'	'	'	'	'	-0.3	2	1.4
Defined benefit plans	'	'	'	'	'	'	'	'	'	'	'
Pension and other postretirement benefit costs arising during the period, net of tax of $ - million, $(0.9) million, and $(0.7) million, respectively	'	'	'	'	'	'	'	'	1.1	0.9	0
Pension and other postretirement benefit costs arising during period, tax	'	'	'	'	'	'	'	'	0	-0.9	-0.7
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, net of tax of $0.9 million, $0.4 million, and $0.1 million, respectively	'	'	'	'	'	'	'	'	-0.5	-0.1	0.2
Amortization of pension and other postretirement benefit costs included in net periodic benefit cost, tax	'	'	'	'	'	'	'	'	0.9	0.4	0.1
Defined benefit plans, net	'	'	'	'	'	'	'	'	0.6	0.8	0.2
Other comprehensive income (loss) from subsidiaries, net of tax	'	'	'	'	'	'	'	'	17.4	-1.2	0.6
Other comprehensive income, net of tax	'	'	'	'	'	'	'	'	17.7	1.6	2.2
Comprehensive income attributed to common shareholders	'	'	'	'	'	'	'	'	$369.50	$283	$229.60

SCHEDULE_I_CONDENSED_PARENT_CO3

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS BALANCE SHEETS (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Millions, unless otherwise specified
Assets	'	'	'	'
Cash and cash equivalents	$22.30	$27.40	$28.10	$179
Other current assets	55.8	38.6	'	'
Current assets	1,972.20	1,659.10	'	'
Property and equipment, net of accumulated depreciation of $1,4 and $1.2, respectively	6,410.50	5,501.90	'	'
Accumulated depreciation	3,325.80	3,114.70	'	'
Other long-term assets	169.8	136.8	'	'
Total assets	11,243.50	10,327.40	9,983.20	'
Liabilities and Equity	'	'	'	'
Short-term debt	326	482.4	'	'
Current portion of long-term debt	100	313.5	'	'
Accounts payable	613.2	457.7	'	'
Other current liabilities	231.3	229	'	'
Current liabilities	1,622.10	1,813.30	'	'
Long-term debt	2,956.20	1,931.70	'	'
Deferred income taxes	1,390.30	1,203.80	'	'
Other long-term liabilities	136.9	135.7	'	'
Long-term liabilities	6,308	5,437.30	'	'
Total common shareholders’ equity	3,261.30	3,025.80	'	'
Total liabilities and equity	11,243.50	10,327.40	'	'
Integrys Energy Group, Inc.	'	'	'	'
Assets	'	'	'	'
Cash and cash equivalents	0.3	2.6	1.9	100.6
Accounts receivable from related parties	32.2	32.2	'	'
Interest Receivable from related parties	4.1	4.7	'	'
Deferred income taxes	0.6	1	'	'
Notes receivable from related parties	84.9	34.5	'	'
Current portion of long-term notes receivable from related parties	10	72	'	'
Other current assets	47.8	39.4	'	'
Current assets	179.9	186.4	'	'
Total investments in subsidiaries, at equity	4,268.50	3,839.30	'	'
Notes receivable from related parties	224.3	171.2	'	'
Property and equipment, net of accumulated depreciation of $1,4 and $1.2, respectively	4.5	4.7	'	'
Accumulated depreciation	1.4	1.2	'	'
Receivables from related parties	18.3	17.3	'	'
Deferred income taxes	22.3	28.1	'	'
Other long-term assets	43.9	31.7	'	'
Total assets	4,761.70	4,278.70	'	'
Liabilities and Equity	'	'	'	'
Short-term notes payable to related parties	165.7	258	'	'
Short-term debt	123.2	208.4	'	'
Current portion of long-term debt	100	0	'	'
Accounts payable to related parties	0.9	1	'	'
Interest payable to related parties	0	0.1	'	'
Accounts payable	1.2	0.6	'	'
Deferred income taxes	6.4	6	'	'
Other current liabilities	2.8	6.8	'	'
Current liabilities	400.2	480.9	'	'
Long-term debt	974.7	674.7	'	'
Deferred income taxes	110.1	81.3	'	'
Other long-term liabilities	15.4	16	'	'
Long-term liabilities	1,100.20	772	'	'
Total common shareholders’ equity	3,261.30	3,025.80	'	'
Total liabilities and equity	$4,761.70	$4,278.70	'	'

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating activities	'	'	'
Net income (loss) attributed to common shareholders	$351.80	$281.40	$227.40
Adjustments to reconcile net income to net cash provided by operating activities	'	'	'
Discontinued operations, net of tax	-4.8	9.7	-0.5
Equity earnings from subsidiaries	-19.2	-17.5	-14.8
Dividends from subsidiaries	191.6	'	'
Other	41	20.1	45.9
Changes in working capital	'	'	'
Accounts receivable	-358.8	-26.2	93.4
Other current assets	-42	6.1	55.3
Accounts payable	143.1	22	-37.3
Other current liabilities	45.1	23.1	-86.8
Net cash provided by operating activities	555	569	717.8
Investing activities	'	'	'
Net cash used for investing activities	-1,024.30	-605	-393.5
Financing activities	'	'	'
Issuance of long-term debt	1,174	428	50
Repayment of long-term debt	-363.5	-278.2	-565.8
Proceeds from stock option exercises	38.7	55.8	10.3
Shares purchased for stock-based compensation	-2	-89.9	-17
Dividends paid on common stock	-202.6	-211.9	-206.4
Other	-16.6	-1	-7.5
Net cash provided by (used for) financing activities	462.7	55.1	-478.1
Net change in cash and cash equivalents	-5.1	-0.7	-150.9
Cash and cash equivalents at beginning of year	27.4	28.1	179
Cash and cash equivalents at end of year	22.3	27.4	28.1
Supplemental cash flow information	'	'	'
Cash paid for interest	116.1	109.7	130.7
Cash received for income taxes	-4.8	-47.6	-80
Integrys Energy Group, Inc.	'	'	'
Operating activities	'	'	'
Net income (loss) attributed to common shareholders	351.8	281.4	227.4
Adjustments to reconcile net income to net cash provided by operating activities	'	'	'
Discontinued operations, net of tax	-4.8	9.7	-0.5
Equity earnings from subsidiaries	-397.1	-332.4	-275.5
Dividends from subsidiaries	169.6	163.9	461.3
Deferred income taxes	26.2	8.6	29.2
Other	4	4.2	3.5
Changes in working capital	'	'	'
Accounts receivable	-0.7	0.4	-0.6
Accounts receivable from related parties	0.6	1	0.9
Receivable from related parties	0	0	13.8
Other current assets	-7.9	29	12.8
Accounts payable	0.6	-0.5	0
Accounts payable to related parties	-0.2	-0.4	-5
Other current liabilities	-2.9	-3.2	15.9
Net cash provided by operating activities	139.2	161.7	483.2
Investing activities	'	'	'
Short-term notes receivable from related parties	-50.4	-12.1	33.3
Issuance of long-term notes receivable from related parties	-35	0	-10
Repayment of long-term notes receivable from related parties	44.5	1.3	1.3
Equity contributions to subsidiaries	-234.6	-89.9	-63.2
Return of capital from subsidiaries	75	110.5	229.8
Net cash used for investing activities	-200.5	9.8	191.2
Financing activities	'	'	'
Commercial paper, net	-85.2	115.8	92.6
Short-term notes payable to related parties	-92.3	76.2	-305.2
Repayment of long-term notes payable to related parties	0	-21	-325
Issuance of long-term debt	400	0	0
Repayment of long-term debt	0	-100	-30.2
Proceeds from stock option exercises	38.7	55.8	10.3
Shares purchased for stock-based compensation	0	-75.3	-9.1
Issuance of common stock	19.2	0	7.3
Dividends paid on common stock	-202.6	-211.9	-206.4
Other	-18.8	-10.4	-7.4
Net cash provided by (used for) financing activities	59	-170.8	-773.1
Net change in cash and cash equivalents	-2.3	0.7	-98.7
Cash and cash equivalents at beginning of year	2.6	1.9	100.6
Cash and cash equivalents at end of year	0.3	2.6	1.9
Supplemental cash flow information	'	'	'
Cash paid for interest	44.4	44.4	44.6
Cash paid for interest - related parties	0.7	1.4	6.8
Cash received for income taxes	($3)	($24.10)	($46.30)

SCHEDULE_I_CONDENSED_PARENT_CO5

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash and Cash Equivalents	'	'	'
Maximum term of original maturity to classify instruments as cash equivalent	'3 months	'	'
Cash Flow, Noncash Investing and Financing Activities	'	'	'
Equity issued for reinvested dividends	$12	$0	$5.40
Equity issued for stock-based compensation plans	16.3	0	10.6
Integrys Energy Group, Inc.	'	'	'
Cash and Cash Equivalents	'	'	'
Maximum term of original maturity to classify instruments as cash equivalent	'3 months	'	'
Cash Flow, Noncash Investing and Financing Activities	'	'	'
Equity issued for reinvested dividends	12	0	5.4
Equity issued for stock-based compensation plans	$16.30	$0	$10.60

SCHEDULE_I_CONDENSED_PARENT_CO6

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS FAIR VALUE OF FINANCIAL INSTRUMENTS - RELATED PARTIES (Details) (Integrys Energy Group, Inc., USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Financial instruments not recorded at fair value	'	'
Long-term notes receivable from related parties	$224.30	$171.20
Current portion of long-term notes receivable from related parties	10	72
Carrying Amount	'	'
Financial instruments not recorded at fair value	'	'
Long-term notes receivable from related parties	224.3	171.2
Current portion of long-term notes receivable from related parties	10	72
Fair value	'	'
Financial instruments not recorded at fair value	'	'
Long-term notes receivable from related parties	238.5	202.1
Current portion of long-term notes receivable from related parties	$10.20	$73.40

SCHEDULE_I_CONDENSED_PARENT_CO7

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS SHORT-TERM NOTES RECEIVABLE - RELATED PARTIES (Details) (Integrys Energy Group, Inc., USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
SHORT-TERM NOTES RECEIVABLE - RELATED PARTIES	'	'
Short-term notes receivable from related parties	$84.90	$34.50
Integrys Energy Services	'	'
SHORT-TERM NOTES RECEIVABLE - RELATED PARTIES	'	'
Short-term notes receivable from related parties	23.5	0
MGU	'	'
SHORT-TERM NOTES RECEIVABLE - RELATED PARTIES	'	'
Short-term notes receivable from related parties	21.8	0
MERC	'	'
SHORT-TERM NOTES RECEIVABLE - RELATED PARTIES	'	'
Short-term notes receivable from related parties	20.5	15.2
IBS	'	'
SHORT-TERM NOTES RECEIVABLE - RELATED PARTIES	'	'
Short-term notes receivable from related parties	10.2	0
UPPCO	'	'
SHORT-TERM NOTES RECEIVABLE - RELATED PARTIES	'	'
Short-term notes receivable from related parties	8.9	11.9
ITF	'	'
SHORT-TERM NOTES RECEIVABLE - RELATED PARTIES	'	'
Short-term notes receivable from related parties	$0	$7.40

SCHEDULE_I_CONDENSED_PARENT_CO8

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS LONG-TERM NOTES RECEIVABLE - RELATED PARTIES (Details) (Integrys Energy Group, Inc., USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES	'	'
Total notes receivable from related parties	$234.30	$243.20
Less current portion	10	72
Long-term notes receivable from related parties	224.3	171.2
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	2.4	2.8
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	3.9	4.4
UPPCO | Notes Receivable 5.25 Percent Due 2013	'	'
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES	'	'
Interest rate stated percentage	5.25%	'
Total notes receivable from related parties	0	15
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	15	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	10	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	15	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	20	0
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	0
MERC | Notes Receivable 6.03 Percent Due 2013	'	'
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES	'	'
Interest rate stated percentage	6.03%	'
Total notes receivable from related parties	0	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
MGU | Notes Receivable 5.72 Percent Due 2013	'	'
LONG-TERM NOTES RECEIVABLE - RELATED PARTIES	'	'
Interest rate stated percentage	5.72%	'
Total notes receivable from related parties	0	28
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	0
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	$10	$10

SCHEDULE_I_CONDENSED_PARENT_CO9

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS SHORT-TERM NOTES PAYABLE - RELATED PARTIES (Details) (Integrys Energy Group, Inc., USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
SHORT-TERM NOTES PAYABLE - RELATED PARTIES	'	'
Short-term notes payable to related parties	$165.70	$258
PELLC	'	'
SHORT-TERM NOTES PAYABLE - RELATED PARTIES	'	'
Short-term notes payable to related parties	165.7	201.6
Integrys Energy Services	'	'
SHORT-TERM NOTES PAYABLE - RELATED PARTIES	'	'
Short-term notes payable to related parties	0	49.4
IBS	'	'
SHORT-TERM NOTES PAYABLE - RELATED PARTIES	'	'
Short-term notes payable to related parties	$0	$7

SCHEDULE_II_VALUATION_AND_QUAL1

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Allowance for doubtful accounts	'	'	'
Balance at beginning of year	$43.50	$47.10	$41.90
Charged to expense	34.4	26.2	35
Charged to other accounts	4.7	4.8	1.5
Deductions	32.8	34.6	31.3
Balance at end of year	$49.80	$43.50	$47.10