NorthWestern (NWE) 10-K 19 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 14, 2014	Jun. 30, 2013
Entity Information [Line Items]	'	'	'
Entity Registrant Name	'NORTHWESTERN CORPORATION	'	'
Entity Central Index Key	'0000073088	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Amendment Flag	'false	'	'
Entity Common Stock, Shares Outstanding	'	38,767,473	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Public Float	'	'	$1,534,085,335

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues	'	'	'
Electric	$865,239	$805,554	$797,562
Gas	287,605	263,394	318,335
Other	1,675	1,394	1,419
Total Revenues	1,154,519	1,070,342	1,117,316
Operating Expenses	'	'	'
Cost of sales	479,546	395,434	494,559
Operating, general and administrative	285,569	269,966	267,160
Mountain States Transmission Intertie impairment	0	24,039	0
Property and other taxes	105,540	97,674	89,122
Depreciation	112,831	106,044	100,926
Total Operating Expenses	983,486	893,157	951,767
Operating Income	171,033	177,185	165,549
Interest Expense	-70,486	-65,062	-66,859
Other Income	7,737	4,372	3,931
Income Before Income Taxes	108,284	116,495	102,621
Income Tax Expense	-14,301	-18,089	-10,065
Net Income	$93,983	$98,406	$92,556
Average Common Shares Outstanding	38,144,852	36,847,427	36,258,463
Basic Earnings per Average Common Share	$2.46	$2.67	$2.55
Diluted Earnings per Average Common Share	$2.46	$2.66	$2.53

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net Income	$93,983	$98,406	$92,556
Other comprehensive (loss) income, net of tax:	'	'	'
Reclassification of net gains on derivative instruments to net income	-730	-732	-730
Reclassification of deferred tax liability on net gains on derivative instruments	0	0	-3,572
Postretirement medical liability adjustment	963	-553	-581
Foreign currency translation	166	-54	25
Total Other Comprehensive Income (Loss)	399	-1,339	-4,858
Comprehensive Income	$94,382	$97,067	$87,698

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
OPERATING ACTIVITIES:	'	'	'
Net Income	$93,983	$98,406	$92,556
Items not affecting cash:	'	'	'
Depreciation	112,831	106,044	100,926
Amortization of debt issue costs, discount and deferred hedge gain	2,039	369	1,032
Amortization of nonvested shares	2,404	2,759	2,133
Equity portion of allowance for funds used during construction	-5,050	-4,846	-1,877
(Gain) loss on disposition of assets	-721	-332	811
Deferred income taxes	54,617	51,890	64,065
Mountain States Transmission Intertie impairment	0	24,039	0
Gain on CELP arbitration decision	0	-47,894	0
Changes in current assets and liabilities:	'	'	'
Restricted cash	-196	6,016	146
Accounts receivable	-30,792	3,456	-3,847
Inventories	181	5,371	-8,831
Other current assets	-2,940	-1,856	-3,551
Accounts payable	6,235	10,976	-1,928
Accrued expenses	1,949	14,149	1,883
Regulatory assets	-2,846	-6,285	1,684
Regulatory liabilities	-2,019	15,241	16,020
Other noncurrent assets	-43,714	-27,362	-30,048
Other noncurrent liabilities	7,755	1,052	2,583
Cash provided by operating activities	193,716	251,193	233,757
INVESTING ACTIVITIES:	'	'	'
Property, plant, and equipment additions	-230,454	-219,234	-188,730
Asset acquisitions	-68,666	-103,241	0
Proceeds from sale of assets	3,766	262	209
Cash used in investing activities	-295,354	-322,213	-188,521
FINANCING ACTIVITIES:	'	'	'
Dividends on common stock	-57,684	-54,246	-51,909
Proceeds from issuance of common stock, net	56,825	28,477	0
Issuance of long-term debt	100,000	150,000	0
Repayment of long-term debt	-149	-3,945	-6,589
Line of credit borrowings	0	0	80,000
Line of credit repayments	0	0	-233,000
Issuances (repayments) of short-term borrowings, net	18,016	-44,000	166,934
Treasury stock activity	-1,042	-429	153
Financing costs	-7,593	-943	-1,131
Cash provided by (used in) financing activities	108,373	74,914	-45,542
Increase (Decrease) in Cash and Cash Equivalents	6,735	3,894	-306
Cash and Cash Equivalents, beginning of period	9,822	5,928	6,234
Cash and Cash Equivalents, end of period	$16,557	$9,822	$5,928

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current Assets:	'	'
Cash and cash equivalents	$16,557	$9,822
Restricted cash	6,896	6,700
Accounts receivable, net	174,913	143,695
Inventories	55,609	54,161
Regulatory assets	37,719	40,301
Deferred income taxes	14,301	37,143
Other	14,961	11,306
Total current assets	320,956	303,128
Property, plant, and equipment, net	2,690,128	2,435,590
Goodwill	355,128	355,128
Regulatory assets	316,952	367,890
Other noncurrent assets	32,096	23,797
Total assets	3,715,260	3,485,533
Current Liabilities:	'	'
Current maturities of capital leases	1,662	1,612
Short-term borrowings	140,950	122,934
Accounts payable	92,957	83,746
Accrued expenses	181,613	192,548
Regulatory liabilities	46,406	48,425
Total current liabilities	463,588	449,265
Long-term capital leases	29,895	31,562
Long-term debt	1,155,097	1,055,074
Deferred income taxes	395,333	363,928
Noncurrent regulatory liabilities	348,053	276,618
Other noncurrent liabilities	292,624	375,054
Total liabilities	2,684,590	2,551,501
Commitments and Contingencies (Note 20)	'	'
Shareholders' Equity:	'	'
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 42,340,173 and 38,745,624 respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	423	408
Treasury stock at cost	-91,744	-90,702
Paid-in capital	910,184	849,218
Retained earnings	209,091	172,791
Accumulated other comprehensive income	2,716	2,317
Total shareholders' equity	1,030,670	934,032
Total liabilities and shareholders' equity	$3,715,260	$3,485,533

CONSOLIDATED_BALANCE_SHEETS_PA

CONSOLIDATED BALANCE SHEETS PARENTHETICAL (Parentheticals) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Common stock, par or stated value per share	$0.01	$0.01
Common stock, shares authorized	200,000,000	200,000,000
Common Stock, shares issued	42,340,173	40,792,449
Common Stock, shares outstanding	38,745,624	37,221,344
Preferred stock, par or stated value per share	$0.01	$0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred Stock, shares issued	0	0

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (USD $)	Total	Common Stock	Paid-in Capital	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Income
In Thousands, except Per Share data, unless otherwise specified
Balance at Dec. 31, 2010	$820,347	$398	$813,878	($90,427)	$87,984	$8,514
Shares, Balance at Dec. 31, 2010	'	39,799	'	3,570	'	'
Increase (Decrease) in Shareholders' Equity [Roll Forward]	'	'	'	'	'	'
Net Income	92,556	0	0	0	92,556	0
Other comprehensive income:	'	'	'	'	'	'
Foreign currency translation adjustment	25	0	0	0	0	25
Reclassification of net gains on derivative instruments from OCI to net income, net of tax	-730	0	0	0	0	-730
Reclassification of deferred tax liability on net gains on derivative instruments	-3,572	'	'	'	'	-3,572
Postretirement medical liability adjustment	-581	0	0	0	0	-581
Stock based compensation, value	2,669	0	2,762	-93	0	0
Stock based compensation, shares	'	42	'	3	'	'
Issuance of shares, value	307	0	60	'	0	0
Issuance of shares, shares	'	0	'	'	'	'
Issuance of shares, value, treasury stock reissued	'	'	'	247	'	'
Issuance of shares, shares, treasury stock reissued	'	'	'	-10	'	'
Dividends on common stock	-51,909	0	0	0	-51,909	0
Dividends per share	$1.44	'	'	'	'	'
Balance at Dec. 31, 2011	859,112	398	816,700	-90,273	128,631	3,656
Shares, Balance at Dec. 31, 2011	'	39,841	'	3,563	'	'
Increase (Decrease) in Shareholders' Equity [Roll Forward]	'	'	'	'	'	'
Net Income	98,406	0	0	0	98,406	0
Other comprehensive income:	'	'	'	'	'	'
Foreign currency translation adjustment	-54	0	0	0	0	-54
Reclassification of net gains on derivative instruments from OCI to net income, net of tax	-732	0	0	0	0	-732
Reclassification of deferred tax liability on net gains on derivative instruments	0	'	'	'	'	'
Postretirement medical liability adjustment	-553	0	0	0	0	-553
Stock based compensation, value	3,133	1	3,925	-793	0	0
Stock based compensation, shares	'	136	'	22	'	'
Issuance of shares, value	28,966	9	28,593	'	0	0
Issuance of shares, shares	'	815	'	'	'	'
Issuance of shares, value, treasury stock reissued	'	'	'	364	'	'
Issuance of shares, shares, treasury stock reissued	'	'	'	-14	'	'
Dividends on common stock	-54,246	0	0	0	-54,246	0
Dividends per share	$1.48	'	'	'	'	'
Balance at Dec. 31, 2012	934,032	408	849,218	-90,702	172,791	2,317
Shares, Balance at Dec. 31, 2012	'	40,792	'	3,571	'	'
Increase (Decrease) in Shareholders' Equity [Roll Forward]	'	'	'	'	'	'
Net Income	93,983	0	0	0	93,983	0
Other comprehensive income:	'	'	'	'	'	'
Foreign currency translation adjustment	166	0	0	0	0	166
Reclassification of net gains on derivative instruments from OCI to net income, net of tax	-730	0	0	0	0	-730
Reclassification of deferred tax liability on net gains on derivative instruments	0	'	'	'	'	'
Postretirement medical liability adjustment	963	0	0	0	0	963
Stock based compensation, value	2,663	1	3,987	-1,325	0	0
Stock based compensation, shares	'	167	'	35	'	'
Issuance of shares, value	57,276	14	56,979	'	0	0
Issuance of shares, shares	'	1,381	'	'	'	'
Issuance of shares, value, treasury stock reissued	'	'	'	283	'	'
Issuance of shares, shares, treasury stock reissued	'	'	'	-11	'	'
Dividends on common stock	-57,683	0	0	0	-57,683	0
Dividends per share	$1.52	'	'	'	'	'
Balance at Dec. 31, 2013	$1,030,670	$423	$910,184	($91,744)	$209,091	$2,716
Shares, Balance at Dec. 31, 2013	'	42,340	'	3,595	'	'

Nature_of_Operations_and_Basis

Nature of Operations and Basis of Consolidation	12 Months Ended
	Dec. 31, 2013
Nature of Operations and Basis of Consolidation [Abstract]	'
Nature of Operations and Basis of Consolidation	'
	Nature of Operations and Basis of Consolidation
	NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and natural gas to approximately 678,200 customers in Montana, South Dakota and Nebraska. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have generated and distributed electricity and distributed natural gas in Montana since 2002.
	The Consolidated Financial Statements for the periods included herein have been prepared by NorthWestern Corporation (NorthWestern, we or us), pursuant to the rules and regulations of the SEC. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The accompanying Consolidated Financial Statements include our accounts together with those of our wholly and majority-owned or controlled subsidiaries. All intercompany balances and transactions have been eliminated from the Consolidated Financial Statements. Events occurring subsequent to December 31, 2013, have been evaluated as to their potential impact to the Consolidated Financial Statements through the date of issuance.
	Variable Interest Entities
	A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity's purpose and design and a company's ability to direct the activities of the entity that most significantly impact the entity's economic performance.
	Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain QF plants. We identified one QF contract that may constitute a VIE. We entered into a power purchase contract in 1984 with this 35 MW coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per MWH (energy payment). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $286.2 million through 2024. For further discussion of our gross QF liability, see Note 20 - Commitments and Contingencies. During the years ended December 31, 2013, 2012 and 2011 purchases from this QF were approximately $23.8 million, $21.0 million, and $18.4 million, respectively.

Significant_Accounting_Policie

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Significant Accounting Policies	'
	Significant Accounting Policies
	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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. Estimates are used for such items as long-lived asset values and impairment charges, long-lived asset useful lives, tax provisions, asset retirement obligations, uncollectible accounts, our QF liability, environmental costs, unbilled revenues and actuarially determined benefit costs. We revise the recorded estimates when we receive better information or when we can determine actual amounts. Those revisions can affect operating results.
	Revenue Recognition
	Customers are billed monthly on a cycle basis. To match revenues with associated expenses, we accrue unbilled revenues for electrical and natural gas services delivered to customers, but not yet billed at month-end.
	Cash Equivalents
	We consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents.
	Restricted Cash
	Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements.
	Accounts Receivable, Net
	Accounts receivable are net of allowances for uncollectible accounts of $4.5 million and $3.2 million at December 31, 2013 and December 31, 2012, respectively. Receivables include unbilled revenues of $74.3 million and $71.4 million at December 31, 2013 and December 31, 2012, respectively.
	Inventories
	Inventories are stated at average cost. Inventory consisted of the following (in thousands):
		December 31,
		2013		2012
	Materials and supplies	$	28,263	$	25,094
	Storage gas and fuel	27,346		29,067
		$	55,609	$	54,161
	Regulation of Utility Operations
	Our regulated operations are subject to the provisions of ASC 980, Regulated Operations (ASC 980). Regulated accounting is appropriate provided that (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise's cost of service, and (iii) in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be charged to and collected from customers.
	Our Consolidated Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. The economic effects of regulation can result in regulated companies recording costs that have been, or are expected to be, allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities).
	If we were required to terminate the application of these provisions to our regulated operations, all such deferred amounts would be recognized in the Consolidated Income Statements at that time. This would result in a charge to earnings, net of applicable income taxes, which could be material. In addition, we would determine any impairment to the carrying costs of deregulated plant and inventory assets.
	Derivative Financial Instruments
	We account for derivative instruments in accordance with ASC 815, Derivatives and Hedging. All derivatives are recognized in the Consolidated Balance Sheets at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair-value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash-flow hedge). For fair-value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash-flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in accumulated other comprehensive income (AOCI) and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For other derivative contracts that do not qualify or are not designated for hedge accounting, changes in the fair value of the derivatives are recognized in earnings each period. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the underlying nature of the hedged items.
	Revenues and expenses on contracts that qualify are designated as normal purchases and normal sales and are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but on an accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric and gas operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it were determined that a transaction designated as a normal purchase or a normal sale no longer met the exceptions, the fair value of the related contract would be reflected as an asset or liability and immediately recognized through earnings. See Note 9, Risk Management and Hedging Activities for further discussion of our derivative activity.
	Property, Plant and Equipment
	Property, plant and equipment are stated at original cost, including contracted services, direct labor and material, AFUDC, and indirect charges for engineering, supervision and similar overhead items. All expenditures for maintenance and repairs of utility property, plant and equipment are charged to the appropriate maintenance expense accounts. A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility plant. At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired and also for the net cost of removal. Also included in plant and equipment are assets under capital lease, which are stated at the present value of minimum lease payments.
	AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized currently from such allowance, it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. We determine the rate used to compute AFUDC in accordance with a formula established by the FERC. This rate averaged 8.1%, 8.0%, and 7.9%, for Montana for 2013, 2012, and 2011, respectively, and 8.1%, 8.0%, and 7.8% for South Dakota for 2013, 2012, and 2011, respectively. AFUDC capitalized totaled $8.2 million for the year ended December 31, 2013, $7.9 million for the year ended December 31, 2012 and $3.1 million for the year ended December 31, 2011 for Montana and South Dakota combined.
	We may require contributions in aid of construction from customers when we extend service. Amounts used from these contributions to fund capital additions were $6.3 million and $5.0 million for the years ended December 31, 2013 and 2012, respectively.
	We record provisions for depreciation at amounts substantially equivalent to calculations made on a straight-line method by applying various rates based on useful lives of the various classes of properties (ranging from three to 40 years) determined from engineering studies. As a percentage of the depreciable utility plant at the beginning of the year, our provision for depreciation of utility plant was approximately 3.2%, 3.3%, and 3.3% for 2013, 2012, and 2011, respectively. During the second quarter of 2013, we implemented revised depreciation rates to reflect the results of new depreciation studies, which reflect longer asset lives on our electric and natural gas assets in Montana, and electric assets in South Dakota.
	Depreciation rates include a provision for our share of the estimated costs to decommission three coal-fired generating plants at the end of the useful life of each plant. The annual provision for such costs is included in depreciation expense, while the accumulated provisions are included in noncurrent regulatory liabilities.
	Other Noncurrent Liabilities
	Other noncurrent liabilities consisted of the following (in thousands):
		December 31,
		2013		2012
	Pension and other employee benefits	$	57,140	$	148,384
	Future QF obligation, net	136,448		136,652
	Environmental	28,194		30,189
	Customer advances	27,371		34,681
	Other	43,471		25,148
		$	292,624	$	375,054
	Insurance Subsidiary
	Risk Partners Assurance, Ltd (Risk Partners) is a wholly owned non-United States insurance subsidiary established in 2001 to insure a portion of our workers' compensation, general liability and automobile liability risks. New policies have not been underwritten through this subsidiary since 2004. Claims that were incurred during that time period continue to be paid and managed by Risk Partners. Reserve requirements are established based on actuarial projections of ultimate losses. Any losses estimated to be paid within one year from the balance sheet date are classified as accrued expenses, while losses expected to be payable in later periods are included in other long-term liabilities. Risk Partners has purchased reinsurance policies through a third-party reinsurance company to transfer a portion of the insurance risk. Restricted cash held by this subsidiary was $2.7 million and $3.8 million as of December 31, 2013 and 2012, respectively.
	Income Taxes
	Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ from these estimates. The resolution of tax matters in a particular future period could have a material impact on our Consolidated Income Statements and provision for income taxes.
	Environmental Costs
	We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset if there is precedent for recovering similar costs from customers in rates. Otherwise, we expense the costs. If an environmental cost is related to facilities we currently use, such as pollution control equipment, then we may capitalize and depreciate the costs over the remaining life of the asset, assuming the costs are recoverable in future rates or future cash flows.
	Our remediation cost estimates are based on the use of an environmental consultant, our experience, our assessment of the current situation and the technology currently available for use in the remediation. We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated responsible parties, then we estimate and record only our share of the cost.
	Accounting Standards Issued
	In July 2013, the Financial Accounting Standards Board (FASB) issued guidance for the presentation of unrecognized tax benefits when a net operating loss carryforward or other tax credit carryforwards exist at the reporting date. If such a carryforward exists, the guidance generally requires an unrecognized tax benefit to be presented as a decrease in a deferred tax asset. Our current practice is consistent with this guidance.
	Accounting Standards Adopted
	In February 2013, the FASB issued guidance that requires disclosure of amounts reclassified out of accumulated other comprehensive income by component. Significant amounts are required to be presented by the respective line items of net income or should be cross-referenced to other disclosures. These disclosures may be presented on the income statement or in the notes to the financial statements. We adopted this standard during the first quarter of 2013 and have included the required disclosures in Note 14 - Comprehensive Income (Loss). The adoption of this standard did not have a material effect on our financial statement disclosures.
	Supplemental Cash Flow Information
		Year Ended December 31,
		2013		2012		2011
				(in thousands)
	Cash paid (received) for:
	Income taxes	$	50	$	2,944	$	(1,219	)
	Interest	57,789		51,271		52,328
	Significant non-cash transactions:
	Capital expenditures included in trade accounts payable	12,025		13,136		10,910

Acquisitions_and_Significant_E

Acquisitions and Significant Events Regulated Operations (Notes)	12 Months Ended
	Dec. 31, 2013
Regulated Operations [Abstract]	'
Schedule of Significant Events, Acquisitions and Disposals [Text Block]	'
	Acquisitions and Significant Events
	Hydro Transaction
	On September 26, 2013, we entered into an agreement with PPL Montana, LLC (PPL Montana), a wholly owned subsidiary of PPL Corporation, to purchase PPL Montana's hydro-electric generating facilities and associated assets located in Montana, which includes approximately 633 megawatts of hydro-electric generation capacity, for a purchase price of $900 million (Hydro Transaction). The purchase price will be subject to a number of adjustments, including the proration of operating expenses, the performance of planned capital expenditures, and the termination of certain power purchase agreements.
	The Hydro Transaction includes the Kerr Project, a 194 megawatt hydro-electric generating facility. The FERC license for the Kerr Project provides the Confederated Salish and Kootenai Tribes of the Flathead Reservation (CSKT) an option to acquire the facility between September 2015 and September 2025. We believe CSKT will exercise their option and acquire the Kerr Project in September 2015. PPL Montana and CSKT are currently involved in arbitration over the conveyance price of the Kerr Project. Under our agreement with PPL Montana, the $900 million purchase price includes a $30 million reference price to the Kerr Project. If CSKT exercises their option and ultimately pays more than $30 million for the Kerr Project, we will pay the difference to PPL Montana. If CSKT pays less than $30 million for the Kerr Project, PPL Montana will pay the difference to us.
	Completion of the Hydro Transaction is subject to customary conditions and approvals, including approval from the FERC, the MPSC, other appropriate state and federal agencies and as required by the Hart-Scott-Rodino Antitrust Improvements Act. In December 2013, we submitted an application with the MPSC to acquire these assets, and in January 2014, we submitted three applications with the FERC concerning the Hydro Transaction. For further information on these filings see Note 4 - Regulatory Matters. Either party may terminate the agreement if the closing does not occur by September 26, 2014; however, this date will be extended for an additional six months if any governmental approval is still pending. Assuming receipt of reasonably satisfactory regulatory approvals, we expect the Hydro Transaction to close in the second half of 2014.
	The permanent financing for the Hydro Transaction is anticipated to be a combination of long-term debt, new equity issuance and cash flows from operations. The Hydro Transaction is supported by a fully committed $900 million 364-day senior bridge credit facility (see Note 11 - Short-Term Borrowings and Credit Arrangements).
	During 2013, we incurred approximately $4.4 million of legal and professional fees associated with the Hydro Transaction and approximately $1.9 million of expenses related to the bridge credit facility.
	If the acquisition is completed during the second half of 2014, we expect to sell any excess generation in the market and provide revenue credits to our Montana retail customers until CSKT exercises their option to acquire the Kerr Project. If CSKT exercises their option to acquire the Kerr Project in September 2015, we will own approximately 60 percent of our average electric load serving requirements in Montana.
	Natural Gas Production Assets
	In December 2013, we completed the purchase of additional natural gas production interests in northern Montana's Bear Paw Basin for approximately $68.7 million net of cash acquired, subject to post-closing purchase price adjustments. This purchase includes an interest in the Havre Pipeline Company, LLC (Havre Pipeline), which represents approximately $6 million of pipeline assets. As of December 31, 2013, the amount of net proven developed producing reserves associated with the acquisition was estimated to be 57.5 billion cubic feet. We estimate the current annual production associated with this acquisition to be approximately 24 percent of our total annual natural gas load in Montana, which increases our total owned production to approximately 32 percent.
	MSTI Impairment
	The MSTI line was a proposed 500 kV transmission project from southwestern Montana to southeastern Idaho with a potential capacity of 1,500 MW. On October 2, 2012, Bonneville Power Administration (BPA) notified us that it had ranked other options ahead of MSTI to serve BPA's southern Idaho loads. This notification was in conjunction with the January 2012 Memorandum of Understanding between NorthWestern and BPA agreeing to explore the potential for MSTI to accommodate BPA's needs. Based on BPA's decision, continued market uncertainty, and permitting issues causing timeline delays, we determined that we would not further pursue development of MSTI at that time. As a result, we recorded an impairment charge of approximately $24.0 million in the Consolidated Income Statements during the third quarter of 2012, which was substantially all of the capitalized preliminary survey and investigative costs related to MSTI. During the first quarter of 2014, we withdrew various pending applications related to the siting and development of MSTI.
	Colstrip Energy Limited Partnership
	CELP is a QF with which we have a power purchase agreement (PPA) for approximately 306,600 MWH's annually through June 2024. Under the terms of the PPA with CELP, energy and capacity rates were fixed for the first fifteen years and beginning July 1, 2004, through the end of the contract, energy and capacity rates are to be determined each year pursuant to a formula, subject to annual review and approval by the MPSC. CELP filed a complaint against us and the MPSC in Montana district court in 2007, which contested the MPSC's orders.
	On November 1, 2012, an arbitration panel issued a final award in our favor. The final award confirmed that the rate methodology used by us for calculating the rates for the July 1, 2006 to July 1, 2011 period was consistent with the PPA and a previous final award issued by the same arbitration panel on October 30, 2009. Based on the clarity provided by the final award regarding the rate calculation for 2006 through the remainder of the PPA, we updated the calculation of our QF liability and recorded a pre-tax gain of $47.9 million within cost of sales in the Consolidated Income Statements during the fourth quarter of 2012. In April 2013, the MPSC issued a final order consistent with the arbitration panel's final award for the contract years July 1, 2006 through June 30, 2013.

Regulatory_Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2013
Regulated Operations [Abstract]	'
Regulatory Matters	'
	Regulatory Matters
	Hydro Transaction
	In December 2013, we submitted a filing with the MPSC requesting approval of the Hydro Transaction. The filing initiates the formal regulatory process necessary to complete the previously announced $900 million agreement, and includes a request to include the hydro assets in rate base and to issue the securities necessary to complete the purchase. The request is based on a return on equity of 10.0%, a capital structure of 52% debt and 48% equity, and an estimated rate base of $866 million. The MPSC has established a procedural schedule and we expect the MPSC to issue a decision during the second half of 2014.
	In January 2014, we made three separate applications with the FERC necessary for the Hydro Transaction, respectively seeking (1) approval of the asset transfer itself, (2) authorization to continue making wholesale power sales at market-based rates after the transaction and (3) approval to transfer the four associated FERC hydroelectric licenses. We anticipate that FERC will act before the June 30, 2014, requested action date for the first two applications. On January 17, 2014, the CSKT protested the third application to transfer the FERC hydro licenses on procedural grounds and asked FERC to reject the application with respect to the Kerr Project. PPL Montana responded to the CSKT’s motion on January 27, 2014, but FERC has yet to rule. We requested FERC action on this third application by April 30, 2014.
	Dave Gates Generating Station at Mill Creek (DGGS)
	As a result of a FERC ALJ nonbinding decision issued in September 2012, we have cumulative deferred revenue of approximately $24.5 million, which is subject to refund and recorded within current regulatory liabilities in the Consolidated Balance Sheets. The ALJ concluded we should allocate only a fraction of the costs we believe (based on past practice) should be allocated to FERC jurisdictional customers. The matter has been fully briefed before the FERC.
	We do not know when the FERC will consider the matter and issue its decision. The FERC is not obligated to follow any of the ALJ's findings and conclusions, and the FERC can accept or reject the decision in whole or in part. If the FERC upholds the ALJ's decision and a portion of the costs are effectively disallowed, we would be required to assess DGGS for impairment. If we disagree with a decision issued by the FERC, we may pursue full appellate rights through rehearing and appeal to a United States Circuit Court of Appeals, which could extend into 2015 or beyond. We continue to bill FERC jurisdictional customers interim rates that have been in effect since January 1, 2011. These interim rates are subject to refund plus interest pending final resolution at FERC.
	Montana Electric and Natural Gas Tracker Filings
	Each year we submit electric and natural gas tracker filings for recovery of supply costs for the 12-month period ended
	June 30 and for the projected supply costs for the next 12-month period. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our electric and natural gas supply procurement activities were prudent.
	In its April 2012 electric supply tracker order for the 2010/2011 tracker period, the MPSC had authorized us to include forecasted DSM lost revenues in future tracker filings. We had not recognized the entire forecasted amount for tracker periods since 2010/2011 as we were required to provide the MPSC with a detailed independent study supporting our requested DSM lost revenues.
	During October 2013, the MPSC approved an order related to our 2012 electric supply tracker filing (covering July 1, 2011 through June 30, 2012), which includes a decision on a review of an independent study related to our request for DSM lost revenues, addresses future DSM lost revenue recovery, and includes a decision on DGGS related incremental contract costs included in the 2012 filing. Based on the MPSC's October 2013 decision we recognized revenue of approximately $3.8 million related to prior periods (including $1.9 million related to calendar year 2012) that we had previously deferred pending outcome of the review of the study results.
	The order also includes a provision expressing concern with the policy of continuing to allow DSM lost revenue recovery, indicating that we bear the burden of demonstrating why any incremental DSM lost revenue recovery from the date of its order forward is reasonable and in the public interest. As of December 31, 2013, we have recognized approximately $7.1 million of DSM lost revenues for the 2012/ 2013 tracker period and approximately $3.6 million for the 2013/2014 tracker period. Based on the MPSC's order, we expect to be able to collect at least $7.1 million of DSM lost revenues for each annual tracker period; however, since the 2012/2013 annual tracker filing is still subject to final approval, the MPSC may ultimately require us to refund a portion of the DSM lost revenues we have recognized since July 2012. We do not expect the MPSC to issue a final order related to 2012/2013 DSM lost revenues until at least the first quarter of 2014.
	Last, the MPSC indicated that $1.4 million of incremental costs associated with regulation service acquired from third parties during a 2012 outage at DGGS were imprudently incurred, and disallowed recovery.
	While we recognized revenues and expenses consistent with the MPSC order, we appealed the MPSC's decision to the District Court in Montana in December 2013.
	Natural Gas Production Assets
	We purchased additional natural gas production interests in northern Montana's Bear Paw Basin during 2013 and 2012. We are collecting the cost of service for natural gas produced from these assets, including a return on our investment, through our natural gas supply tracker on an interim basis. As a result, we do not expect to file an application with the MPSC to place these assets in natural gas rate base until our next natural gas rate case. We are recognizing Bear Paw related revenue based on the precedent established by the MPSC's approval of Battle Creek in the fourth quarter of 2012. Since acquisition, we have recognized approximately $7.0 million of revenue that is subject to refund.

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
	We prepare our financial statements in accordance with the provisions of ASC 980, as discussed in Note 2 - Significant Accounting Policies. Pursuant to this guidance, certain expenses and credits, normally reflected in income as incurred, are deferred and recognized when included in rates and recovered from or refunded to the customers. Regulatory assets and liabilities are recorded based on management's assessment that it is probable that a cost will be recovered or that an obligation has been incurred. Accordingly, we have recorded the following major classifications of regulatory assets and liabilities that will be recognized in expenses and revenues in future periods when the matching revenues are collected or refunded. Of these regulatory assets and liabilities, energy supply costs are the only items earning a rate of return. The remaining regulatory items have corresponding assets and liabilities that will be paid for or refunded in future periods. Because these costs are recovered as paid, they do not earn a return. We have specific orders to cover approximately 97% of our regulatory assets and 93% of our regulatory liabilities.
		Note Reference	Remaining Amortization Period	December 31,
				2013		2012
				(in thousands)
	Pension	16	Undetermined	$	58,474	$	143,672
	Employee related benefits	16	Undetermined	17,700		20,911
	Distribution infrastructure projects		4 Years	12,543		15,679
	Environmental clean-up	20	Various	14,924		16,497
	Supply costs		1 Year	17,875		11,788
	Energy supply derivatives	9	1 Year	—		5,428
	Income taxes	13	Plant Lives	201,808		162,154
	Deferred financing costs		Various	13,919		13,944
	State & local taxes & fees		Various	6,582		8,337
	Other	—	Various	10,846		9,781
	Total regulatory assets			$	354,671	$	408,191
	Removal cost	7	Various	$	336,613	$	264,486
	Gas storage sales		26 Years	10,831		11,251
	Supply costs		1 Year	11,493		17,591
	Deferred revenue	4	1 Year	33,400		26,259
	Environmental clean-up		Various	1,194		1,395
	State & local taxes & fees		1 Year	551		537
	Other		Various	377		3,524
	Total regulatory liabilities			$	394,459	$	325,043
	Pension and Employee Related Benefits
	We recognize the unfunded portion of plan benefit obligations in the Consolidated Balance Sheets, which is remeasured at each year end, with a corresponding adjustment to regulatory assets/liabilities as the costs associated with these plans are recovered in rates. The portion of the regulatory asset related to our Montana pension plan will amortize as cash funding amounts exceed accrual expense under GAAP. The SDPUC allows recovery of pension costs on an accrual basis. The MPSC allows recovery of postretirement benefit costs on an accrual basis. The MPSC allows recovery of other employee related benefits on a cash basis.
	Montana Distribution System Infrastructure Project (DSIP)
	We have an accounting order to defer certain incremental operating and maintenance expenses associated with DSIP. Pursuant to the order, we deferred expenses incurred during 2011 and 2012 as a regulatory asset associated with the phase-in portion of the DSIP. These costs are being amortized into expense over five years beginning in 2013.
	Supply Costs
	The MPSC, SDPUC and NPSC have authorized the use of electric and natural gas supply cost trackers that enable us to track actual supply costs and either recover the under collection or refund the over collection to our customers. Accordingly, we have recorded a regulatory asset and liability to reflect the future recovery of under collections and refunding of over collections through the ratemaking process. We earn interest on electric and natural gas supply costs under collected, or apply interest in an over collection of 7.5%, in Montana; 10.6% and 7.8%, respectively, in South Dakota; and 8.5% for natural gas in Nebraska.
	Energy Supply Derivatives
	To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts. Certain contracts for the purchase of natural gas associated with our gas utility operations do not qualify for the normal purchase and normal sale scope exception (NPNS). We use the mark-to-market method of accounting for these derivative contracts as we do not elect hedge accounting. Upon settlement of these contracts, associated proceeds or costs are refunded to or collected from our customers consistent with regulatory requirements; therefore, we record a regulatory asset or liability based on changes in market value.
	Deferred Revenue
	We have deferred revenue associated with DGGS and DSM lost revenues, which may be subject to refund as we have open regulatory proceedings. See Note 4 - Regulatory Matters, for further information regarding these items.
	Environmental clean-up
	Environmental clean-up costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss the specific sites and clean-up requirements further in Note 20 - Commitments and Contingencies. Environmental clean-up costs are typically recoverable in customer rates when they are actually incurred. We record changes in the regulatory asset consistent with changes in our environmental liabilities. When cost projections become known and measurable, we coordinate with the appropriate regulatory authority to determine a recovery period.
	Income Taxes
	Tax assets primarily reflect the effects of plant related temporary differences such as flow-through of depreciation, repairs related deductions, removal costs, capitalized interest and contributions in aid of construction that we will recover or refund in future rates. We amortize these amounts as temporary differences reverse.
	Deferred Financing Costs
	Consistent with our historical regulatory treatment, a regulatory asset has been established to reflect the remaining deferred financing costs on long-term debt that has been replaced through the issuance of new debt. These amounts are amortized over the life of the new debt.
	State & Local Taxes & Fees (Montana Property Tax Tracker)
	Under Montana law, we are allowed to track the increases in the actual level of state and local taxes and fees and recover these amounts. The MPSC has authorized recovery in the property tax tracker of approximately 60% of the estimated increase in our local taxes and fees (primarily property taxes) as compared to the related amount included in rates during our last general rate case.
	Removal Cost
	The anticipated costs of removing assets upon retirement are provided for over the life of those assets as a component of depreciation expense. Our depreciation method, including cost of removal, is established by the respective regulatory commissions. Therefore, consistent with this regulated treatment, we reflect this accrual of removal costs for our regulated assets by increasing our regulatory liability. See Note 7 - Asset Retirement Obligations, for further information regarding this item.
	Gas Storage Sales
	A regulatory liability was established in 2000 and 2001 based on gains on cushion gas sales in Montana. This gain is being flowed to customers over a period that matches the depreciable life of surface facilities that were added to maintain deliverability from the field after the withdrawal of the gas. This regulatory liability is a reduction of rate base.

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
	The following table presents the major classifications of our property, plant and equipment (in thousands):
		Estimated Useful Life		December 31,
				2013				2012
		(years)		(in thousands)
	Land, land rights and easements	54 – 96		$	128,123			$	72,550
	Building and improvements	27 – 64		163,852				145,989
	Transmission, distribution, and storage	15 – 85		2,448,821				2,339,111
	Generation	25 – 50		533,450				506,017
	Plant acquisition adjustment	34		204,754				204,754
	Other	Feb-45		308,345				259,308
	Construction work in process	–—		104,891				121,360
				3,892,236				3,649,089
	Less accumulated depreciation			(1,202,108		)		(1,213,499		)
				$	2,690,128			$	2,435,590
	The plant acquisition adjustment is related to the inclusion of our interest in Colstrip Unit 4 in rate base and represents the costs associated with the purchase of our previously leased interest. The acquisition adjustment is being amortized on a straight-line basis over the estimated remaining useful life. Plant and equipment under capital lease were $25.6 million and $27.7 million as of December 31, 2013 and 2012, respectively, which included $25.1 million and $27.1 million as of December 31, 2013 and 2012, respectively, related to a long-term power supply contract with the owners of a natural gas fired peaking plant, which has been accounted for as a capital lease.
	Jointly Owned Electric Generating Plant
	We have an ownership interest in four base-load electric generating plants, all of which are coal fired and operated by other companies. We have an undivided interest in these facilities and are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated. Our interest in each plant is reflected in the Consolidated Balance Sheets on a pro rata basis and our share of operating expenses is reflected in the Consolidated Statements of Income. The participants each finance their own investment.
	Information relating to our ownership interest in these facilities is as follows (in thousands):
		Big Stone				Neal #4				Coyote			Colstrip Unit 4 (MT)
		(SD)				(IA)				(ND)
	December 31, 2013
	Ownership percentages	23.4		%		8.7		%		10		%	30		%
	Plant in service	$	61,186			$	57,633			$	46,003		$	290,163
	Accumulated depreciation	45,792				29,841				36,076			70,072
	December 31, 2012
	Ownership percentages	23.4		%		8.7		%		10		%	30		%
	Plant in service	$	61,084			$	30,009			$	46,188		$	290,607
	Accumulated depreciation	38,021				23,994				30,655			67,534

Asset_Retirement_Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligation	'
	Asset Retirement Obligations
	We are obligated to dispose of certain long-lived assets upon their abandonment. We recognize a liability for the legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event. We measure the liability at fair value when incurred and capitalize a corresponding amount as part of the book value of the related assets, which increases our property, plant and equipment and other noncurrent liabilities. The increase in the capitalized cost is included in determining depreciation expense over the estimated useful life of these assets. Since the fair value of the asset retirement obligation (ARO) is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period and recorded as a regulatory asset until the settlement of the liability. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement.
	Our AROs are primarily related to Department of Transportation requirements to cut, purge and cap retired natural gas pipeline segments, and our obligation to plug and abandon oil and gas wells at the end of their life. The following table presents the change in our gross conditional ARO (in thousands):
		December 31,
		2013			2012
	Liability at January 1,	$	9,283		$	6,292
	Accretion expense	745			473
	Liabilities incurred	8,829			2,466
	Liabilities settled	(27		)	(35		)
	Revisions to cash flows	2,056			87
	Liability at December 31,	$	20,886		$	9,283
	Liabilities incurred includes amounts related to the natural gas production assets acquired.
	Our regulated utility operations have previously recognized removal costs of transmission and distribution assets as a component of depreciation in accordance with regulatory treatment. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities. These amounts do not represent legal retirement obligations. As of December 31, 2013 and 2012, we have recognized accrued removal costs of $336.6 million and $264.5 million, respectively.
	We have identified removal liabilities related to our electric and natural gas transmission and distribution assets that have been installed on easements over property not owned by us. The easements are generally perpetual and only require remediation action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as we intend to utilize these properties indefinitely. In the event we decide to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2013
Goodwill [Abstract]	'
Goodwill	'
	Goodwill
	We completed our annual goodwill impairment test as of April 1, 2013 and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections.
	There were no changes in our goodwill during the year ended December 31, 2013. Goodwill by segment is as follows (in thousands):
		December 31,
		2013		2012
	Electric	$	241,100	$	241,100
	Natural gas	114,028		114,028
		$	355,128	$	355,128

Risk_Management_and_Hedging_Ac

Risk Management and Hedging Activities	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Risk Management and Hedging Activities	'
	Risk Management and Hedging Activities
	Nature of Our Business and Associated Risks
	We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. We rely on market purchases to fulfill a large portion of our electric and natural gas supply requirements within the Montana market. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations.
	Objectives and Strategies for Using Derivatives
	To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts, such as fixed-price forward purchase and sales contracts. The objective of these transactions is to fix the price for a portion of anticipated energy purchases to supply our customers. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide greater price stability for consumers. These commodity costs are included in our cost tracking mechanisms and are recoverable from customers subject to prudence reviews by the applicable state regulatory commissions. We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes consistent with regulatory guidelines. In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt.
	Accounting for Derivative Instruments
	We evaluate new and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: normal purchase normal sale; cash flow hedge; fair value hedge; and mark-to-market. Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria both at the time of designation and on an ongoing basis. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.
	Normal Purchases and Normal Sales
	We have applied the NPNS exception to most of our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no amounts recorded in the Consolidated Financial Statements at December 31, 2013 and 2012. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.
	Mark-to-Market Accounting
	Certain contracts for the purchase of natural gas associated with our gas utility operations do not qualify for NPNS. These are typically forward purchase contracts for natural gas where we lock in a fixed price, settle the contracts financially and do not take physical delivery of the natural gas. We use the mark-to-market method of accounting for these derivative contracts as we do not elect hedge accounting. Upon settlement of these contracts, associated proceeds or costs are refunded to or collected from our customers consistent with regulatory requirements; therefore, we record a regulatory asset or liability based on changes in market value.
	The following table represents the fair value and location of derivative instruments subject to mark-to-market accounting (in thousands). For more information on the determination of fair value see Note 10 - Fair Value Measurements.
				December 31,
	Mark-to-Market Transactions	Balance Sheet Location		2013				2012
	Natural gas net derivative liability	Accrued Expenses		$	—			$	5,428
	The following table represents the net change in fair value for these derivatives (in thousands):
		Unrealized gain recognized in
		Regulatory Assets
		December 31,
	Derivatives Subject to Regulatory Deferral	2013				2012
	Natural gas	$	5,428			$	14,884
	Credit Risk
	We are exposed to credit risk primarily through buying and selling electricity and natural gas to serve customers. Credit risk is the potential loss resulting from counterparty non-performance under an agreement. We manage credit risk with policies and procedures for, among other things, counterparty analysis and exposure measurement, monitoring and mitigation. We may request collateral or other security from our counterparties based on the assessment of creditworthiness and expected credit exposure. It is possible that volatility in commodity prices could cause us to have material credit risk exposures with one or more counterparties.
	We enter into commodity master enabling agreements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The agreements generally are: (1) Western Systems Power Pool agreements - standardized power purchase and sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements - standardized financial gas and electric contracts; (3) North American Energy Standards Board agreements - standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements - standardized power sales contracts in the electric industry.
	Many of our forward purchase contracts contain provisions that require us to maintain an investment grade credit rating from each of the major credit rating agencies. If our credit rating were to fall below investment grade, the counterparties could require immediate payment or demand immediate and ongoing full overnight collateralization on contracts in net liability positions.
	As of December 31, 2013, none of the forward purchase contracts that do not qualify for NPNS contain credit risk-related contingent features.
	Interest Rate Swaps Designated as Cash Flow Hedges
	If we enter into contracts to hedge the variability of cash flows related to forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. The relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified to earnings in the periods in which earnings are affected by the variability of the cash flows of the related hedged item. Any ineffective portion of all hedges would be recognized in current-period earnings. Cash flows related to these contracts are classified in the same category as the transaction being hedged.
	We have previously used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. These swaps were designated as cash flow hedges with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in AOCI. We reclassify these gains from AOCI into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these derivative instruments on the Consolidated Financial Statements (in thousands):
	Cash Flow Hedges		Location of Gain Reclassified from AOCI to Income		Amount of Gain Reclassified from AOCI into Income during the Year Ended
					31-Dec-13
	Interest rate contracts		Interest Expense		$	1,188
	Approximately $5.7 million of the pre-tax gain on these cash flow hedges is remaining in AOCI as of December 31, 2013, and we expect to reclassify approximately $1.2 million of pre-tax gains on these cash-flow hedges from AOCI into interest expense during the next twelve months. These gains relate to swaps previously terminated, and we have no current interest rate swaps outstanding.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	Fair Value Measurements
	Fair value is defined as 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 (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs.
	A fair value hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs has been established by the applicable accounting guidance. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows:
	•	Level 1 – Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities;
	•	Level 2 – Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date; and
	•	Level 3 – Significant inputs that are generally not observable from market activity.
	We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. Normal purchases and sales transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 9 - Risk Management and Hedging Activities for further discussion.
	We record transfers between levels of the fair value heirarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented.
	December 31, 2013		Quoted Prices in			Significant Other				Significant			Margin Cash Collateral		Total Net Fair Value
			Active Markets for			Observable Inputs				Unobservable Inputs			Offset
			Identical Assets or			(Level 2)				(Level 3)
			Liabilities (Level 1)
			(in thousands)
	Restricted cash		$	6,650		$	—			$	—		$	—	$	6,650
	Rabbi trust investments		16,477			—				—			—		16,477
	Total		$	23,127		$	—			$	—		$	—	$	23,127
	December 31, 2012
	Restricted cash		$	6,392		$	—			$	—		$	—	$	6,392
	Rabbi trust investments		10,522			—				—			—		10,522
	Derivative liability (1)		—			(5,428		)		—			—		(5,428		)
	Total		$	16,914		$	(5,428	)		$	—		$	—	$	11,486
	____________________________
	-1	The changes in the fair value of these derivatives are deferred as a regulatory asset or liability until the contracts are settled. Upon settlement, associated proceeds or costs are passed through the applicable cost tracking mechanism to customers.
	Restricted cash represents amounts held in money market mutual funds. Rabbi trust assets represent assets held for non-qualified deferred compensation plans, which consist of our common stock and actively traded mutual funds with quoted prices in active markets. Fair value for the commodity derivatives was determined using internal models based on quoted forward commodity prices. We consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The fair value measurement of liabilities also reflects the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Consideration of our own credit risk did not have a material impact on our fair value measurements.
	The table above disaggregates our derivative liability on a gross contract-by-contract basis as required and classifies each individual liability within the appropriate level in the fair value hierarchy, regardless of whether a particular contract is eligible for netting against other contracts. These gross balances are intended solely to provide information on sources of inputs to fair value and do not represent our actual credit exposure or net economic exposure. Increases and decreases in the gross components presented in each of the levels in this table also do not indicate changes in the level of derivative activities. Rather, the primary factors affecting the gross amounts are commodity prices.
	Financial Instruments
	The estimated fair value of financial instruments is summarized as follows (in thousands):
		December 31, 2013							December 31, 2012
		Carrying Amount			Fair Value				Carrying Amount			Fair Value
	Liabilities:
	Long-term debt	$	1,155,097		$	1,237,151			$	1,055,074		$	1,229,233
	Short-term borrowings consist of commercial paper and are not included in the table above as carrying value approximates fair value. The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange.
	We determined fair value for long-term debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy.

ShortTerm_Borrowings_and_Credi

Short-Term Borrowings and Credit Arrangements	12 Months Ended
	Dec. 31, 2013
Short-term Debt [Abstract]	'
Short-Term Debt	'
	Short-Term Borrowings and Credit Arrangements
	Short-Term Borrowings
	Short-term borrowings and the corresponding weighted average interest rates as of December 31 were as follows (dollars in millions, except for percentages):
			2013					2012
	Short-Term Debt		Balance			Interest Rate		Balance		Interest Rate
	Commercial Paper		$	141		0.41	%	$	122.9	0.53	%
	The following information relates to commercial paper for the years ended December 31 (dollars in millions):
		2013			2012
	Maximum short-term debt outstanding	$	199.9		$	166.9
	Average short-term debt outstanding	$	69		$	78.9
	Weighted-average interest rate	0.4		%	0.48		%
	Under our commercial paper program we may issue unsecured commercial paper notes on a private placement basis up to a maximum aggregate amount outstanding at any time of $250 million to provide an additional financing source for our short-term liquidity needs. The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue. Commercial paper issuances are supported by available capacity under our unsecured revolving credit facility.
	Unsecured Revolving Line of Credit
	On November 5, 2013, we amended and restated our $300 million unsecured revolving credit facility scheduled to expire on June 30, 2016, to extend the term to November 5, 2018. The facility has an accordion feature that allows us to increase the size up to $350 million. The facility does not amortize. The facility bears interest at the Eurodollar rate plus a credit spread, ranging from 0.88% to 1.75%, or a base rate, plus a margin of 0.0% to 0.75%. A total of eight banks participate in the facility, with no one bank providing more than 16% of the total availability. There were no direct borrowings or letters of credit outstanding as of December 31, 2013. Commitment fees for the unsecured revolving line of credit were $0.5 million for the years ended December 31, 2013 and 2012.
	The credit facility includes covenants that require us to meet certain financial tests, including a maximum debt to capitalization ratio not to exceed 65%. The facility also contains covenants which, among other things, limit our ability to engage in any consolidation or merger or otherwise liquidate or dissolve, dispose of property, and enter into transactions with affiliates. A default on the South Dakota or Montana First Mortgage Bonds would trigger a cross default on the credit facility; however a default on the credit facility would not trigger a default on any other obligations.
	Bridge Facility
	In November 2013, in connection with the Hydro Transaction, we entered into a $900 million 364-day senior bridge credit facility. The bridge facility may be used temporarily in a single draw to finance the Hydro Transaction and pay related fees and expenses in the event that permanent financing is not in place at the time of closing. Any advance under the bridge facility is subject to certain conditions including regulatory approval of the Hydro Transaction, and would be due and payable within one year of borrowing.
	The bridge facility does not amortize and is unsecured. The bridge facility, if drawn, bears interest at the Eurodollar rate, plus a margin of 0.88% to 1.75%, or a base rate, plus a margin of 0.0% to 0.75%. The applicable margin would be determined based on our then-current senior unsecured credit ratings. If our current unsecured credit ratings are unchanged at the time of closing, the applicable margin would be 1.25% for Eurodollar rate loans and 0.25% for base rate loans. There were no direct borrowings or letters of credit outstanding as of December 31, 2013. Commitment fees for the bridge facility were $0.2 million for the year ended December 31, 2013.
	The covenants in the bridge facility are substantially similar to those in our unsecured revolving line of credit. As of December 31, 2013, we are in compliance with our financial debt covenants.

LongTerm_Debt_and_Capital_Leas

Long-Term Debt and Capital Leases	12 Months Ended
	Dec. 31, 2013
Long-term Debt and Capital Lease Obligations [Abstract]	'
Long-term Debt And Capital Leases	'
	Long-Term Debt and Capital Leases
	Long-term debt and capital leases consisted of the following (in thousands):
			December 31,
		Due	2013			2012
	Unsecured Debt:
	Unsecured Revolving Line of Credit	2018	$	—		$	—
	Secured Debt:
	Mortgage bonds—
	South Dakota—6.05%	2018	55,000			55,000
	South Dakota—5.01%	2025	64,000			64,000
	South Dakota—4.15%	2042	30,000			30,000
	South Dakota—4.30%	2052	20,000			20,000
	South Dakota—4.85%	2043	50,000			—
	Montana—6.04%	2016	150,000			150,000
	Montana—6.34%	2019	250,000			250,000
	Montana—5.71%	2039	55,000			55,000
	Montana—5.01%	2025	161,000			161,000
	Montana—4.15%	2042	60,000			60,000
	Montana—4.30%	2052	40,000			40,000
	Montana—4.85%	2043	15,000			—
	Montana—3.99%	2028	35,000			—
	Pollution control obligations—
	Montana—4.65%	2023	170,205			170,205
	Other Long Term Debt:
	Discount on Notes and Bonds	—	(108		)	(131		)
			1,155,097			1,055,074
	Less current maturities		—			—
			$	1,155,097		$	1,055,074
	Capital Leases:
	Total Capital Leases	Various	$	31,557		$	33,174
	Less current maturities		(1,662		)	(1,612		)
			$	29,895		$	31,562
	Secured Debt
	First Mortgage Bonds and Pollution Control Obligations
	The South Dakota Mortgage Bonds are a series of general obligation bonds issued under our South Dakota indenture. All of such bonds are secured by substantially all of our South Dakota and Nebraska electric and natural gas assets.
	The Montana First Mortgage Bonds and Montana Pollution Control Obligations are secured by substantially all of our Montana electric and natural gas assets.
	In December 2013, we issued $65 million aggregate principal amount of Montana and South Dakota First Mortgage Bonds at a fixed interest rate of 4.85% maturing in 2043. At the same time, we also issued $35 million aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 3.99% maturing in 2028. The bonds are secured by our electric and natural gas assets in the respective jurisdictions. The bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended. Proceeds were used to fund a portion of our investment growth opportunities.
	As of December 31, 2013, we are in compliance with our financial debt covenants.
	Maturities of Long-Term Debt
	The aggregate minimum principal maturities of long-term debt and capital leases, during the next five years are $1.7 million in 2014, $1.7 million in 2015, $151.8 million in 2016, $2.0 million in 2017 and $57.1 million in 2018.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Income Taxes
	Income tax expense is comprised of the following (in thousands):
		Year Ended December 31,
		2013				2012				2011
	Federal
	Current	$	108			$	5,358			$	(159	)
	Deferred	18,150				13,197				18,618
	Investment tax credits	(335		)		(376		)		(424		)
	State
	Current	83				(1,411		)		(27		)
	Deferred	(3,705		)		1,321				(7,943		)
		$	14,301			$	18,089			$	10,065
	The following table reconciles our effective income tax rate to the federal statutory rate:
		Year Ended December 31,
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State income, net of federal provisions	(2.8	)		0.9			(5.5	)
	Flow-through repairs deductions	(16.4	)		(14.0	)		(13.1	)
	Production tax credits	(2.9	)		—			—
	Plant and depreciation of flow through items	(0.5	)		(1.1	)		(0.3	)
	Prior year permanent return to accrual adjustments	0.5			(1.6	)		(3.8	)
	Recognition of state net operating loss benefit / valuation allowance release	—			(2.1	)		(2.3	)
	Other, net	0.3			(1.6	)		(0.2	)
		13.2	%		15.5	%		9.8	%
	The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rate (in thousands):
		Year Ended December 31,
		2013				2012				2011
	Income Before Income Taxes	$	108,284			$	116,495			$	102,621
	Income tax calculated at 35% federal statutory rate	37,899				40,774				35,917
	Permanent or flow through adjustments:
	State income, net of federal provisions	(3,082		)		1,078				(5,673		)
	Flow-through repairs deductions	(17,763		)		(16,350		)		(13,425		)
	Production tax credits	(3,171		)		—				—
	Plant and depreciation of flow through items	(584		)		(1,281		)		(264		)
	Prior year permanent return to accrual adjustments	541				(1,901		)		(3,948		)
	Recognition of state net operating loss benefit / valuation allowance release	—				(2,398		)		(2,402		)
	Other, net	461				(1,833		)		(140		)
		$	(23,598	)		$	(22,685	)		$	(25,852	)
	Income tax expense	$	14,301			$	18,089			$	10,065
	Our effective tax rate differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of bonus depreciation deductions and production tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.
	Deferred income taxes relate primarily to the difference between book and tax methods of depreciating property, amortizing tax-deductible goodwill, the difference in the recognition of revenues and expenses for book and tax purposes, certain natural gas and electric costs which are deferred for book purposes but expensed currently for tax purposes, and NOL carry forwards. We have elected under Internal Revenue Code 46(f)(2) to defer investment tax credit benefits and amortize them against expense and customer billing rates over the book life of the underlying plant.
	The components of the net deferred income tax liability recognized in our Consolidated Balance Sheets are related to the following temporary differences (in thousands):
		December 31,
		2013				2012
	Pension / postretirement benefits	$	20,522			$	59,098
	Unbilled revenue	18,136				15,944
	NOL carryforward	16,758				—
	Reserves and accruals	12,097				12,457
	Customer advances	10,781				13,660
	Compensation accruals	10,409				11,303
	AMT credit carryforward	10,357				10,588
	Environmental liability	9,026				9,701
	Regulatory assets	7,248				—
	Production tax credit	3,171				—
	QF obligations	2,066				1,462
	Property taxes	796				18,025
	Regulatory liabilities	659				1,526
	Other, net	2,827				3,539
	Deferred Tax Asset	124,853				157,303
	Excess tax depreciation	(304,071		)		(278,051		)
	Goodwill amortization	(122,798		)		(118,313		)
	Flow through depreciation	(79,016		)		(63,551		)
	Regulatory assets	—				(24,173		)
Deferred Tax Liability	(505,885		)		(484,088		)
Deferred Tax Liability, net	$	(381,032	)		$	(326,785	)
At December 31, 2013 we estimate our total federal NOL carryforward to be approximately $325.7 million. If unused, our federal NOL carryforwards will expire as follows: $16.3 million in 2025; $95.5 million in 2028; $23.8 million in 2029; $127.5 million in 2031; and $62.6 million in 2033. We estimate our state NOL carryforward as of December 31, 2013 is approximately $243.5 million. If unused, our state NOL carryforwards will expire as follows: $74.0 million in 2015; $18.6 million in 2016; $101.2 million in 2018; and $49.7 million in 2020. We believe it is more likely than not that sufficient taxable income will be generated to utilize these NOL carryforwards.
Uncertain Tax Positions
We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The change in unrecognized tax benefits is as follows (in thousands):
	2013				2012				2011
Unrecognized Tax Benefits at January 1	$	113,291			$	131,949			$	120,859
Gross increases - tax positions in prior period	—				—				—
Gross decreases - tax positions in prior period	—				(1,766		)		(15,774		)
Gross increases - tax positions in current period	518				2,391				26,864
Gross decreases - tax positions in current period	(343		)		(19,283		)		—
Unrecognized Tax Benefits at December 31	$	113,466			$	113,291			$	131,949
Our unrecognized tax benefits include approximately $79.0 million related to tax positions as of each of December 31, 2013 and 2012 that, if recognized, would impact our annual effective tax rate. It is reasonably possible that a significant portion of our unrecognized tax benefits may decrease in the next twelve months.
Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the year ended December 31, 2013, we recognized approximately $0.4 million of interest in the Consolidated Statements of Income. As of December 31, 2013, we have $0.4 million of interest accrued in the Consolidated Balance Sheets. During the year ended December 31, 2012, we did not recognize any expense for interest or penalties, and did not have any amounts accrued as of December 31, 2012, for the payment of interest and penalties.
In September 2013, the IRS issued final tangible property regulations, which includes final guidance on a safe harbor method for determining the tax treatment of repair costs related to electric transmission and distribution property. The regulations are not effective until tax years beginning on or after January 1, 2014; however, certain portions require a tax accounting method change on a retroactive basis, thus requiring an adjustment related to fixed and real asset deferred taxes. Based on our preliminary analysis of the tangible property regulations, no material adjustments were recorded during 2013. We will continue to monitor the impact of any future changes to the tangible property regulations on our tax positions prospectively.
Our federal tax returns from 2000 forward remain subject to examination by the IRS.

Other_Comprehensive_Loss_Incom

Other Comprehensive (Loss) Income	12 Months Ended
	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]	'
Comprehensive Income (Loss) Note [Text Block]	'
	Other Comprehensive Income (Loss)
	The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands):
		December 31,
		2013												2012									2011
		Before-Tax Amount				Tax Benefit				Net-of-Tax Amount				Before-Tax Amount				Tax Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit			Net-of-Tax Amount
	Foreign currency translation adjustment	$	166			$	—			$	166			$	(54	)		—		$	(54	)	$	25		$	—		$	25
	Reclassification of net gains on derivative instruments to net income	(1,188		)		458				(730		)		(1,188		)		456		(732		)	(1,188		)	458			(730		)
	Reclassification of deferred tax liability on net gains on derivative instruments	—				—				—				—				—		—			—			(3,572		)	(3,572		)
	Pension and postretirement medical liability adjustment	1,568				(605		)		963				(897		)		344		(553		)	(736		)	155			(581		)
	Other comprehensive income (loss)	$	546			$	(147	)		$	399			$	(2,139	)		$	800	$	(1,339	)	$	(1,899	)	$	(2,959	)	$	(4,858	)
	Balances by classification included within AOCI on the Consolidated Balance Sheets are as follows, net of tax (in thousands):
		December 31, 2013				December 31, 2012
	Foreign currency translation	$	532			$	366
	Derivative instruments designated as cash flow hedges	3,513				4,243
	Pension and postretirement medical plans	(1,329		)		(2,292		)
	Accumulated other comprehensive income	2,716				2,317
	The following table displays the changes in AOCI by component, net of tax (in thousands):
				31-Dec-13
				Twelve Months Ended
		Affected Line Item in the Consolidated Statements of Income		Gains on Derivative Instruments Designated as Cash Flow Hedges				Pension and Postretirement Medical Plans				Foreign Currency Translation				Total
	Beginning balance			$	4,243			$	(2,292	)		$	366			$	2,317
	Other comprehensive income before reclassifications			—				—				166				$	166
	Amounts reclassified from accumulated other comprehensive income	Interest Expense		(730		)		—				—				$	(730	)
	Amounts reclassified from accumulated other comprehensive income			—				963				—				$	963
	Net current-period other comprehensive (loss) income			(730		)		963				166				399
	Ending balance			$	3,513			$	(1,329	)		$	532			$	2,716

Operating_Leases

Operating Leases	12 Months Ended
	Dec. 31, 2013
Leases [Abstract]	'
Operating Leases	'
	Operating Leases
	We lease vehicles, office equipment and facilities under various long-term operating leases. At December 31, 2013 future minimum lease payments for the next five years under non-cancelable lease agreements are as follows (in thousands):
	2014	1,655
	2015	1,260
	2016	796
	2017	434
	2018	40
	Lease and rental expense incurred was $2.0 million, $2.2 million and $2.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Employee_Benefit_Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Employee Benefit Plans	'
	Employee Benefit Plans
	Pension and Other Postretirement Benefit Plans
	We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for eligible employees, which includes two cash balance pension plans. The plan for our South Dakota and Nebraska employees is referred to as the NorthWestern Corporation pension plan, and the plan for our Montana employees is referred to as the NorthWestern Energy pension plan. We utilize a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are recognized into earnings only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. The Plan’s funded status is recognized as an asset or liability in our financial statements. See Note 5 - Regulatory Assets and Liabilities, for further discussion on how these costs are recovered through rates charged to our customers.
	Benefit Obligation and Funded Status
	Following is a reconciliation of the changes in plan benefit obligations and fair value of plan assets, and a statement of the funded status (in thousands):
		Pension Benefits								Other Postretirement Benefits
		December 31,								December 31,
		2013				2012				2013				2012
	Change in Benefit Obligation:
	Obligation at beginning of period	$	609,643			$	536,536			$	34,040			$	32,427
	Service cost	13,465				11,488				541				541
	Interest cost	22,719				23,823				877				1,167
	Actuarial (gain) loss	(54,671		)		59,071				(3,156		)		2,508
	Benefits paid	(23,290		)		(21,275		)		(2,218		)		(2,603		)
	Benefit obligation at end of period	$	567,866			$	609,643			$	30,084			$	34,040
	Change in Fair Value of Plan Assets:
	Fair value of plan assets at beginning of period	$	472,936			$	432,637			$	15,893			$	15,502
	Return on plan assets	55,006				49,874				2,662				1,789
	Employer contributions	11,700				11,700				1,846				1,205
	Benefits paid	(23,290		)		(21,275		)		(2,218		)		(2,603		)
	Fair value of plan assets at end of period	$	516,352			$	472,936			$	18,183			$	15,893
	Funded Status	$	(51,514	)		$	(136,707	)		$	(11,901	)		$	(18,147	)
	Amounts recognized in the balance sheet consist of:
	Current liability	—				—				(1,178		)		(1,082		)
	Noncurrent liability	(51,514		)		(136,707		)		(10,723		)		(17,065		)
	Net amount recognized	$	(51,514	)		$	(136,707	)		$	(11,901	)		$	(18,147	)
	Amounts recognized in regulatory assets consist of:
	Prior service (cost) credit	(748		)		(994		)		19,247				21,396
	Net actuarial loss	(71,777		)		(160,610		)		(4,807		)		(9,488		)
	Amounts recognized in AOCI consist of:
	Prior service cost	—				—				(1,302		)		(1,453		)
	Net actuarial gain	—				—				(971		)		(2,432		)
	Total	$	(72,525	)		$	(161,604	)		$	12,167			$	8,023
	The total projected benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were as follows (in millions):
		Pension Benefits
		December 31,
		2013				2012
	Projected benefit obligation	$	567.9			$	609.6
	Accumulated benefit obligation	565				606.2
	Fair value of plan assets	516.4				472.9
	Net Periodic Cost (Credit)
	The components of the net costs (credits) for our pension and other postretirement plans are as follows (in thousands):
		Pension Benefits												Other Postretirement Benefits
		December 31,												December 31,
		2013				2012				2011				2013				2012			2011
	Components of Net Periodic Benefit Cost
	Service cost	$	13,465			$	11,488			$	10,199			$	541			$	541		$	437
	Interest cost	22,719				23,823				24,394				877				1,167			1,348
	Expected return on plan assets	(32,491		)		(29,996		)		(30,462		)		(1,019		)		(1,021		)	(1,185		)
	Amortization of prior service cost (credit)	246				246				246				(1,998		)		(1,998		)	(1,998		)
	Recognized actuarial loss	11,648				8,646				2,516				1,271				790			658
	Net Periodic Benefit Cost (Credit)	$	15,587			$	14,207			$	6,893			$	(328	)		$	(521	)	$	(740	)
	For purposes of calculating the expected return on pension plan assets, the market-related value of assets is used, which is based upon fair value. The difference between actual plan asset returns and estimated plan asset returns are amortized equally over a period not to exceed five years.
	We estimate amortizations from regulatory assets into net periodic benefit cost during 2014 will be as follows (in thousands):
		Pension Benefits				Other
						Postretirement
						Benefits
	Prior service cost (credit)	$	246			$	(1,998	)
	Accumulated loss	2,226				310
	Actuarial Assumptions
	The measurement dates used to determine pension and other postretirement benefit measurements for the plans are December 31, 2013 and 2012. The actuarial assumptions used to compute net periodic pension cost and postretirement benefit cost are based upon information available as of the beginning of the year, specifically, market interest rates, past experience and management's best estimate of future economic conditions. Changes in these assumptions may impact future benefit costs and obligations. In computing future costs and obligations, we must make assumptions about such things as employee mortality and turnover, expected salary and wage increases, discount rate, expected return on plan assets, and expected future cost increases. Two of these assumptions have the most impact on the level of cost: (1) discount rate and (2) expected rate of return on plan assets.
	For 2013 and 2012, we set the discount rate using a yield curve analysis, which projects benefit cash flows into the future and then discounts those cash flows to the measurement date using a yield curve. This is done by constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year, projected benefit cash flow from our plans.
	In determining the expected long-term rate of return on plan assets, we review historical returns, the future expectations for returns for each asset class weighted by the target asset allocation of the pension and postretirement portfolios, and long-term inflation assumptions. During 2013, we changed the target asset allocation for our pension assets from 50% equity securities / 50% fixed income securities to 35% equity securities / 65% fixed income securities. Considering this information and future expectations for asset returns, we are reducing our long term rate of return on assets assumption from 7.00% for 2013 to 5.80% for 2014.
The health care cost trend rates are established through a review of actual recent cost trends and projected future trends. Our retiree medical trend assumptions are the best estimate of expected inflationary increases to our healthcare costs. Due to the relative size of our retiree population (under 800 members), the assumptions used are based upon both nationally expected trends and our specific expected trends. Our average increase remains consistent with the nationally expected trends.
The weighted-average assumptions used in calculating the preceding information are as follows:
	Pension Benefits						Other Postretirement Benefits
	December 31,						December 31,
	2013		2012		2011		2013		2012		2011
Discount rate	4.55-4.75	%	3.55-3.80	%	4.40-4.55	%	3.75-4.20	%	2.25-3.20	%	3.50-4.30	%
Expected rate of return on assets	7		7		7.25		7		7		7.25
Long-term rate of increase in compensation levels (nonunion)	3.58		3.58		3.58		3.58		3.58		3.58
Long-term rate of increase in compensation levels (union)	3.5		3.5		3.5		3.5		3.5		3.5
The postretirement benefit obligation is calculated assuming that health care costs increased by 8.25% in 2013 and the rate of increase in the per capita cost of covered health care benefits thereafter was assumed to decrease gradually by 0.25% per year to an ultimate trend of 4.5% by the year 2029. The company contribution toward the premium cost is capped, therefore future health care cost trend rates are expected to have a minimal impact on company costs and the accumulated postretirement benefit obligation.
Investment Strategy
Our investment goals with respect to managing the pension and other postretirement assets are to meet current and future benefit payment needs while maximizing total investment returns (income and appreciation) after inflation within the constraints of diversification, prudent risk taking, and the Prudent Man Rule of the Employee Retirement Income Security Act of 1974. Each plan is diversified across asset classes to achieve optimal balance between risk and return and between income and growth through capital appreciation. Our investment philosophy is based on the following:
•	Each plan should be substantially fully invested as long-term cash holdings reduce long-term rates of return;
•	It is prudent to diversify each plan across the major asset classes;
•	Equity investments provide greater long-term returns than fixed income investments, although with greater short-term volatility;
•	Fixed income investments of the plans should strongly correlate with the interest rate sensitivity of the plan’s aggregate liabilities in order to hedge the risk of change in interest rates negatively impacting the overall funded status;
•	Allocation to foreign equities increases the portfolio diversification and thereby decreases portfolio risk while providing for the potential for enhanced long-term returns;
•	Active management can reduce portfolio risk and potentially add value through security selection strategies;
•	A portion of plan assets should be allocated to passive, indexed management funds to provide for greater diversification and lower cost; and
•	It is appropriate to retain more than one investment manager, provided that such managers offer asset class or style diversification.
Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.
The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense. In the optimization study, assumptions are formulated about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes, and making adjustments to reflect future conditions expected to prevail over the study period. Based on this, the target asset allocation established, within an allowable range of plus or minus 5%, is as follows:
	Pension Benefits						Other Benefits
	December 31,						December 31,
	2013			2012			2013			2012
Domestic debt securities	60	%		40	%		40	%		40	%
International debt securities	5			10			—			—
Domestic equity securities	30			40			50			50
International equity securities	5			10			10			10
The actual allocation by plan is as follows:
	NorthWestern Energy Pension						NorthWestern Corporation Pension						NorthWestern Energy
													Health and Welfare
	December 31,						December 31,						December 31,
	2013			2012			2013			2012			2013			2012
Cash and cash equivalents	—	%		—	%		0.1	%		—	%		1.8	%		3.4	%
Domestic debt securities	58.6			39.5			64.7			38.3			38.6			37.8
International debt securities	4.9			9.9			4.9			10.6			0.3			—
Domestic equity securities	31.4			40.2			25.3			40.6			50.1			49.8
International equity securities	5.1			10.4			5			10.5			9.2			9
	100	%		100	%		100	%		100	%		100	%		100	%
Generally, the asset mix will be rebalanced to the target mix as individual portfolios approach their minimum or maximum levels. Debt securities consist of U.S. and international instruments. Core domestic portfolios can be invested in government, corporate, asset-backed and mortgage-backed obligation securities. While the portfolio may invest in high yield securities, the average quality must be rated at least “investment grade" by rating agencies. Performance of fixed income investments is measured by both traditional investment benchmarks as well as relative changes in the present value of the plan's liabilities. Equity investments consist primarily of U.S. stocks including large, mid and small cap stocks, which are diversified across investment styles such as growth and value. We also invest in international equities with exposure to developing and emerging markets. Derivatives, options and futures are permitted for the purpose of reducing risk but may not be used for speculative purposes.
Our plan assets are primarily invested in common collective trusts (CCTs), which are invested in equity and fixed income securities. In accordance with our investment policy, these pooled investment funds must have an adequate asset base relative to their asset class and be invested in a diversified manner and have a minimum of three years of verified investment performance experience or verified portfolio manager investment experience in a particular investment strategy and have management and oversight by an investment advisor registered with the SEC. Investments in a collective investment vehicle are valued by multiplying the investee company’s net asset value per share with the number of units or shares owned at the valuation date. Net asset value per share is determined by the trustee. Investments held by the CCT, including collateral invested for securities on loan, are valued on the basis of valuations furnished by a pricing service approved by the CCT’s investment manager, which determines valuations using methods based on quoted closing market prices on national securities exchanges, or at fair value as determined in good faith by the CCT’s investment manager if applicable. The funds do not contain any redemption restrictions. The direct holding of NorthWestern Corporation stock is not permitted; however, any holding in a diversified mutual fund or collective investment fund is permitted. In addition, the NorthWestern Corporation pension plan assets also include a participating group annuity contract in the John Hancock General Investment Account, which consists primarily of fixed-income securities. The participating group annuity contract is valued based on discounted cash flows of current yields of similar contracts with comparable duration based on the underlying fixed income investments.
The fair value of our plan assets at December 31, 2013, by asset category are as follows (in thousands):
Asset Category	Total				Quoted Market				Significant Observable Inputs				Significant Unobservable Inputs
					Prices in Active				Level 2				Level 3
					Markets for
					Identical Assets
					Level 1
Pension Plan Assets
Cash and cash equivalents	$	168			$	—			$	168			$	—
Equity securities: (1)
US small/mid cap growth	13,764				—				13,764				—
US small/mid cap value	13,664				—				13,664				—
US large cap growth	42,094				—				42,094				—
US large cap value	42,102				—				42,102				—
US large cap passive	47,227				—				47,227				—
Non-US core	20,015				—				20,015				—
Emerging markets	6,250				—				6,250				—
Fixed income securities:(2)
US core	82,639				—				82,639				—
US passive	44,762				—				44,762				—
Long duration	24,401				—				24,401				—
Long duration investment grade	32,700				—				32,700				—
Long duration passive	24,122				—				24,122				—
Opportunistic	5,876				—				5,876				—
Non-US passive	25,150				—				25,150				—
Active long corporate	83,147				—				83,147				—
Participating group annuity contract	8,271				—				8,271				—
	$	516,352			$	—			$	516,352			$	—
Other Postretirement Benefit Plan Assets
Cash and cash equivalents	$	318			$	—			$	318			$	—
Equity securities: (1)
US small/mid cap growth	751				—				751				—
US small/mid cap value	736				—				736				—
S&P 500 index	7,321				—				7,321				—
US large cap growth	98				—				98				—
US large cap value	98				—				98				—
US large cap passive	110				—				110				—
Non-US core	1,595				—				1,595				—
Emerging markets	85				—				85				—
Fixed income securities: (2)
Passive bond market	1,880				—				1,880				—
US core	4,390				—				4,390				—
US passive	107				—				107				—
Long duration	55				—				55				—
Long duration investment grade	79				—				79				—
Long duration passive	55				—				55				—
Opportunistic	261				—				261				—
Non-US passive	57				—				57				—
Active long corporate	187				—				187				—
	$	18,183			$	—			$	18,183			$	—
The fair value of our plan assets at December 31, 2012, by asset category are as follows (in thousands):
Asset Category	Total				Quoted Market				Significant Observable Inputs				Significant Unobservable Inputs
					Prices in Active				Level 2				Level 3
					Markets for
					Identical Assets
					Level 1
Pension Plan Assets
Cash and cash equivalents	$	508							$	508			$	—
Equity securities: (1)
US small/mid cap growth	16,229				—				16,229				—
US small/mid cap value	16,297				—				16,297				—
US large cap growth	49,811				—				49,811				—
US large cap value	51,655				—				51,655				—
US large cap passive	56,194				—				56,194				—
Non-US core	36,358				—				36,358				—
Emerging markets	12,713				—				12,713				—
Fixed income securities:(2)
US core opportunistic	90,742				—				90,742				—
US passive	48,710				—				48,710				—
Long duration	6,455				—				6,455				—
Long duration investment grade	7,091				—				7,091				—
Long duration passive	5,239				—				5,239				—
Non-US passive	46,856				—				46,856				—
Active long corporate	18,540				—				18,540				—
Participating group annuity contract	9,538				—				9,538				—
	$	472,936			$	—			$	472,936			$	—
Other Postretirement Benefit Plan Assets
Cash and cash equivalents	$	533			—				$	533			—
Equity securities: (1)
US small/mid cap growth	567				—				567				—
US small/mid cap value	567				—				567				—
S&P 500 index	6,360				—				6,360				—
US large cap growth	132				—				132				—
US large cap value	139				—				139				—
US large cap passive	151				—				151				—
Non-US core	1,323				—				1,323				—
Emerging markets	108				—				108				—
Fixed income securities: (2)
Passive bond market	1,205				—				1,205				—
US core opportunistic	4,440				—				4,440				—
US passive	138				—				138				—
Long duration	16				—				16				—
Long duration investment grade	21				—				21				—
Long duration passive	16				—				16				—
Non-US passive	124				—				124				—
Active long corporate	53				—				53				—
	$	15,893			$	—			$	15,893			$	—
_________________
-1	This category consists of active and passive managed equity funds, which are invested in multiple strategies to diversify risks and reduce volatility.
(2) This category consists of investment grade bonds of issuers from diverse industries, debt securities issued by international, national, state and local governments, and asset-backed securities. This includes both active and passive managed funds.
For further discussion of the three levels of the fair value hierarchy see Note 10 - Fair Value Measurements.
Cash Flows
In accordance with the Pension Protection Act of 2006 (PPA), and the relief provisions of the Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), we are required to meet minimum funding levels in order to avoid required contributions and benefit restrictions. We have elected to use asset smoothing provided by the WRERA, which allows the use of asset averaging, including expected returns (subject to certain limitations), for a 24-month period in the determination of funding requirements.
Based on the assumptions allowed under the PPA, WRERA, Treasury guidance and IRS guidance, we estimate that our minimum annual required contribution for 2014 will be approximately $10.2 million. Additional legislative or regulatory measures, as well as fluctuations in financial market conditions, may impact these funding requirements.
Due to the regulatory treatment of pension costs in Montana, pension expense through 2012 was calculated using the average of our actual and estimated funding amounts from 2005 through 2012. Pension expense for 2013 was based on actual contributions to the plan. Annual contributions to each of the pension plans are as follows (in thousands):
	2013				2012				2011
NorthWestern Energy Pension Plan (MT)	$	10,500			$	10,500			$	10,500
NorthWestern Pension Plan (SD)	1,200				1,200				1,200
	$	11,700			$	11,700			$	11,700
We estimate the plans will make future benefit payments to participants as follows (in thousands):
	Pension Benefits				Other Postretirement Benefits
2014	$	26,648			$	3,585
2015	27,855				3,494
2016	29,850				3,388
2017	31,016				3,237
2018	32,472				3,082
2019-2023	182,212				12,107
Defined Contribution Plan
Our defined contribution plan permits employees to defer receipt of compensation as provided in Section 401(k) of the Internal Revenue Code. Under the plan, employees may elect to direct a percentage of their gross compensation to be contributed to the plan. We contribute various percentage amounts of the employee's gross compensation contributed to the plan. Matching contributions for the year ended December 31, 2013, 2012 and 2011 were $7.8 million, $7.2 million, and $6.7 million, respectively.

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
	We grant stock-based awards through our 2005 Long-Term Incentive Plan (LTIP), which includes restricted stock awards and performance share awards. As of December 31, 2013, there were 662,507 shares of common stock remaining available for grants. The remaining vesting period for awards previously granted ranges from one to five years if the service and/or performance requirements are met. Nonvested shares do not receive dividend distributions. The long-term incentive plan provides for accelerated vesting in the event of a change in control.
	We account for our share-based compensation arrangements by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. The compensation cost is based on the fair value of the grant on the date it was awarded.
	Restricted Stock and Performance Share Awards
	Performance share awards were granted under the 2005 LTIP during 2013 and 2012. With these awards, shares will vest if, at the end of the three-year performance period, we have achieved certain performance goals and the individual remains employed by us. The exact number of shares issued will vary from 0% to 200% of the target award, depending on actual company performance relative to the performance goals. These awards contain both a market and performance based component. The performance goals for these awards are independent of each other and equally weighted, and are based on two metrics: (i) cumulative net income and average return on equity; and (ii) total shareholder return (TSR) relative to a peer group.
	Fair value is determined for each component of the performance share awards. The fair value of the net income component is estimated based upon the closing market price of our common stock as of the date of grant less the present value of expected dividends, multiplied by an estimated performance multiple determined on the basis of historical experience, which is subsequently trued up at vesting based on actual performance. The fair value of the TSR portion is estimated using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. The fair value of restricted stock is measured based upon the closing market price of our common stock as of the date of grant less the present value of expected dividends. The following summarizes the significant assumptions used to determine the fair value of performance shares and related compensation expense as well as the resulting estimated fair value of performance shares granted:
		2013		2012
	Risk-free interest rate	0.44	%	0.38	%
	Expected life, in years	3		3
	Expected volatility	16.3% to 25.4%		20.2% to 34.2%
	Dividend yield	3.9	%	4.1	%
	The risk-free interest rate was based on the U.S. Treasury yield of a three-year bond at the time of grant. The expected term of the performance shares is three years based on the performance cycle. Expected volatility was based on the historical volatility for the peer group. Both performance goals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares expected to vest.
	A summary of nonvested shares as of and changes during the year ended December 31, 2013, are as follows:
		Performance Share Awards				Restricted Stock Awards
		Shares		Weighted-Average Grant-Date		Shares		Weighted-Average Grant-Date
				Fair Value				Fair Value
	Beginning nonvested grants	186,755		$	22.64	1,000		$	24.77
	Granted	88,592		32.97		2,500		35.78
	Vested	(100,402	)	20.48		(3,500	)	32.63
	Forfeited	(1,299	)	25.33		—		—
	Remaining nonvested grants	173,646		$	29.14	—		$	—
	We recognized compensation expense of $2.4 million, $2.8 million, and $2.1 million for the years ended December 31, 2013, 2012, and 2011, respectively, and a related income tax benefit of $1.5 million, $0.4 million, and $1.6 million for the years ended December 31, 2013, 2012, and 2011, respectively. As of December 31, 2013, we had $3.0 million of unrecognized compensation cost related to the nonvested portion of outstanding awards, which is reflected as nonvested stock as a portion of additional paid in capital in our Statement of Common Shareholders' Equity. The cost is expected to be recognized over a weighted-average period of 2.3 years. The total fair value of shares vested was $2.2 million, $2.0 million, and $2.9 million for the years ended December 31, 2013, 2012 and 2011, respectively.
	Retirement/Retention Restricted Share Awards
	In December 2011, an executive retirement / retention program was established that provides for the annual grant of restricted share units. These awards are subject to a five-year performance and vesting period. The performance measure for these awards requires net income for the calendar year of at least three of the five full calendar years during the performance period to exceed net income for the calendar year the awards are granted. Once vested, the awards will be paid out in shares of common stock in five equal annual installments after a recipient has separated from service. The fair value of these awards is measured based upon the closing market price of our common stock as of the date of grant less the present value of expected dividends.
	A summary of nonvested shares as of and changes during the year ended December 31, 2013, are as follows:
		Shares		Weighted-Average Grant-Date
				Fair Value
	Beginning nonvested grants	17,537		$	27.7
	Granted	9,091		35.14
	Vested	—		—
	Forfeited	—		—
	Remaining nonvested grants	26,628		$	30.24
	Director's Deferred Compensation
	Nonemployee directors may elect to defer up to 100% of any qualified compensation that would be otherwise payable to him or her, subject to compliance with our 2005 Deferred Compensation Plan for Nonemployee Directors and Section 409A of the Internal Revenue Code. The deferred compensation may be invested in NorthWestern stock or in designated investment funds. Compensation deferred in a particular month is recorded as a deferred stock unit (DSU) on the first of the following month based on the closing price of NorthWestern stock or the designated investment fund. The DSUs are marked-to-market on a quarterly basis with an adjustment to director’s compensation expense. Based on the election of the nonemployee director, following separation from service on the Board, other than on account of death, he or she shall be paid a distribution either in a lump sum or in approximately equal installments over a designated number of years (not to exceed 10 years). During the years ended December 31, 2013, 2012 and 2011, DSUs issued to members of our Board totaled 33,837, 31,801 and 31,032, respectively. Total compensation expense attributable to the DSUs during the years ended December 31, 2013, 2012 and 2011 was approximately $3.6 million, $0.9 million and $2.3 million, respectively.

Common_Stock

Common Stock	12 Months Ended
	Dec. 31, 2013
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]	'
Common Stock	'
	Common Stock
	We have 250,000,000 shares authorized consisting of 200,000,000 shares of common stock with a $0.01 par value and 50,000,000 shares of preferred stock with a $0.01 par value. Of these shares, 2,265,957 shares of common stock are reserved for the incentive plan awards. For further detail of grants under this plan see Note 17 - Stock-Based Compensation.
	In April 2012, we entered into an Equity Distribution Agreement pursuant to which we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $100 million. During 2013, we issued 1,381,494 shares of our common stock at an average price of $41.61 per share, for net proceeds of $56.8 million. During the three months ended December 31, 2013, we issued 278,914 shares at an average price of $46.17, for net proceeds of $12.7 million, which is net of sales commissions of approximately $129,000, and other fees.
	Repurchase of Common Stock
	Shares tendered by employees to us to satisfy the employees' tax withholding obligations in connection with the vesting of restricted stock awards totaled 34,552 and 22,789 during the years ended December 31, 2013 and 2012, respectively, and are reflected in treasury stock. These shares were credited to treasury stock based on their fair market value on the vesting date.

Earnings_Per_Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Earnings Per Share	'
	Earnings Per Share
	Basic earnings per share are computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the potential dilution of common stock equivalent shares that could occur if unvested shares were to vest. Common stock equivalent shares are calculated using the treasury stock method, as applicable. The dilutive effect is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested restricted stock and performance share awards. Average shares used in computing the basic and diluted earnings per share are as follows:
		December 31,
		2013	2012
	Basic computation	38,144,852	36,847,427
	Dilutive effect of
	Restricted stock and performance share awards (1)	82,223	193,473
	Diluted computation	38,227,075	37,040,900
	_____________________
	(1)           Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies
	Qualifying Facilities Liability
	Our QF liability primarily consists of unrecoverable costs associated with three contracts covered under the PURPA. The QFs require us to purchase minimum amounts of energy at prices ranging from $74 to $136 per MWH through 2029. Our estimated gross contractual obligation related to the QFs is approximately $1.1 billion through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $0.9 billion through 2029. The present value of the remaining QF liability is recorded in our Consolidated Balance Sheets as a regulatory disallowance liability pursuant to ASC 980. The following summarizes the change in the QF liability (in thousands):
		December 31,
		2013			2012
	Beginning QF liability	$	136,652		$	184,187
	Gain on CELP arbitration decision	—			(47,894		)
	Unrecovered amount	(10,647		)	(12,014		)
	Interest expense	10,443			12,373
	Ending QF liability	$	136,448		$	136,652
	See Note 3 - Acquisitions and Significant Events for additional discussion related to the adjustment of the QF liability related to the CELP arbitration decision in 2012.
	The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands):
		Gross			Recoverable			Net
		Obligation			Amounts
	2014	$	67,283		$	56,025		$	11,258
	2015	69,606			56,598			13,008
	2016	71,598			57,188			14,410
	2017	73,622			57,789			15,833
	2018	75,688			58,401			17,287
	Thereafter	724,574			567,215			157,359
	Total	$	1,082,371		$	853,216		$	229,155
	Long Term Supply and Capacity Purchase Obligations
	We have entered into various commitments, largely purchased power, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 28 years. Costs incurred under these contracts were approximately $379.4 million, $340.8 million and $390.6 million for the years ended December 31, 2013, 2012, and 2011, respectively. As of December 31, 2013, our commitments under these contracts are $305.8 million in 2014, $202.6 million in 2015, $160.7 million in 2016, $136.7 million in 2017, $108.6 million in 2018, and $1,143.4 million thereafter. These commitments are not reflected in our Consolidated Financial Statements.
	Environmental Liabilities
	The operation of electric generating, transmission and distribution facilities, and gas gathering, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance.
	Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, the majority of our environmental reserve relates to the remediation of former manufactured gas plant sites owned by us. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred.
	Our liability for environmental remediation obligations is estimated to range between $27.3 million to $35.0 million, primarily for manufactured gas plants discussed below. As of December 31, 2013, we have a reserve of approximately $29.9 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our consolidated financial position or results of operations.
	Manufactured Gas Plants - Approximately $23.3 million of our environmental reserve accrual is related to manufactured gas plants. A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies and implementing remedial actions at the Aberdeen site pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources (DENR). Our current reserve for remediation costs at this site is approximately $12.0 million, and we estimate that approximately $9.0 million of this amount will be incurred during the next five years.
	We also own sites in North Platte, Kearney and Grand Island, Nebraska on which former manufactured gas facilities were located. In February 2011, the Nebraska Department of Environmental Quality (NDEQ) completed an Abbreviated Preliminary Assessment and Site Investigation Report for Grand Island, which recommended additional ground water testing. In April of 2012, we received a letter from NDEQ regarding a recently completed Vapor Intrusion Assessment Report and an invitation to join NDEQ's Voluntary Cleanup Program (VCP). We declined NDEQ's offer to join its VCP and committed to conducting a limited soil vapor investigation, which was completed in July 2012. We are currently working independently to fully characterize the nature and extent of impacts associated with the Grand Island former manufactured gas plant as well as the North Platte and Kearney sites. Our reserve estimate includes assumptions for site assessment and remedial action work. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations.
	In addition, we own or have responsibility for sites in Butte, Missoula and Helena, Montana on which former manufactured gas plants were located. An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. The Butte and Helena sites were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to soil and groundwater impacts. Voluntary soil and coal tar removals were conducted in the past at the Butte and Helena locations in accordance with MDEQ requirements. We have conducted additional groundwater monitoring at the Butte and Missoula sites and, at this time, we believe natural attenuation should address the conditions at these sites; however, additional groundwater monitoring will be necessary and additional monitoring wells will be installed at the Butte site. Monitoring of groundwater at the Helena site is ongoing and will be necessary for an extended period of time. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action at the Helena site or if any additional actions beyond monitored natural attenuation will be required.
	Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of emissions of greenhouse gases (GHG) including, most significantly, carbon dioxide. These actions include legislative proposals, Executive and Environmental Protection Agency (EPA) actions at the federal level, actions at the state level, and private party litigation relating to GHG emissions. Coal-fired plants have come under particular scrutiny due to their level of GHG emissions. We have joint ownership interests in four electric generating plants, all of which are coal fired and operated by other companies. We have undivided interests in these facilities and are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated.
	While numerous bills have been introduced that address climate change from different perspectives, including through direct regulation of GHG emissions, the establishment of cap and trade programs and the establishment of Federal renewable portfolio standards, Congress has not passed any federal climate change legislation and we cannot predict the timing or form of any potential legislation. In the absence of such legislation, EPA is presently regulating GHG emissions of the very largest emitters, including large power plants, under the Clean Air Act, and specifically under the Prevention of Significant Deterioration (PSD) pre-construction permit and Title V operating permit programs.
	On January 8, 2014, the EPA reproposed New Source Performance Standards (NSPS) that specify permissible levels of GHG emissions from newly-constructed fossil fuel-fired electric generating units. As directed by President Obama's June 25, 2013, Climate Action Plan, the EPA also intends to establish, pursuant to Section 111(d) of the Clean Air Act, carbon dioxide emissions standards for existing fossil fuel fired electric generating units. EPA plans to propose regulations and guidelines addressing GHG emissions for existing units by June 1, 2014, and finalize those guidelines by June 1, 2015. States must then submit their individual plans for reducing power plants' GHG emissions to EPA by June 30, 2016. Thus, it is possible that existing power plants may be required to comply with GHG performance standards as soon as July 2016.
	The U.S. Supreme Court is expected to hear oral arguments on February 24, 2014 on the challenge to EPA's GHG regulations, including the Tailoring Rule which limits the sources subject to GHG permitting requirements to the largest fossil-fueled power plants. It is conceivable that the Court could invalidate EPA's PSD and Title V Tailoring Rule, but still leave power plants subject to anticipated new and existing source performance standards for GHG.
	Physical impacts of climate change may present potential risks for severe weather, such as floods and tornadoes, in the locations where we operate or have interests. Furthermore, requirements to reduce GHG emissions from stationary sources could cause us to incur material costs of compliance and increase our costs of procuring electricity. In addition, we believe future legislation and regulations that affect GHG emissions from power plants are likely, although technology to efficiently capture, remove and/or sequester such emissions may not be available within a timeframe consistent with the implementation of such requirements. We cannot predict with any certainty whether these risks will have a material impact on our operations.
	Coal Combustion Residuals (CCRs) - In June 2010, the EPA proposed two approaches to regulating the disposal and management of CCRs under the Resource Conservation and Recovery Act (RCRA). CCRs include fly ash, bottom ash and scrubber wastes. Under one approach, the EPA would regulate CCRs as special wastes subject to regulation under subtitle C, the hazardous waste provisions, of RCRA. This approach would have significant impacts on coal-fired plants, and would require plants to retrofit their operations to comply with hazardous waste requirements from the generation of CCRs and associated waste waters through transportation and disposal. This could also have a negative impact on the beneficial use of CCRs and the current markets associated with such use. The second approach would regulate CCRs as a solid waste under Subtitle D of RCRA. This approach would only affect disposal, most significantly any wet disposal, of CCRs. In a January 2014 consent decree in the case Appalachian Voices v. McCarthy, the EPA agreed to take final action with respect to the CCR regulations by December 19, 2014. In addition, legislation has been introduced in Congress to regulate coal ash. We cannot predict at this time the final requirements of any CCR regulations or legislation and what impact, if any, they would have on us, but the costs of complying with any such requirements could be significant.
	Water Intakes and Discharges - Section 316(b) of the Federal Clean Water Act (CWA) requires that the location, design, construction and capacity of any cooling water intake structure reflect the “best available technology” for minimizing environmental impacts. Permits required for existing facilities are to be developed by the individual states using their best professional judgment until the EPA takes action to address several court decisions that rejected portions of previous rules and confirmed that the EPA has discretion to consider costs relative to benefits in developing cooling water intake structure regulations. In March 2011, the EPA proposed a rule to address impingement and entrainment of aquatic organisms at existing cooling water intake structures. Pursuant to a settlement agreement, the EPA was required to take final action on the regulations by January 14, 2014, but the EPA did not meet the settlement deadline and it is working to complete the final rule for cooling water intakes as soon as possible. When a final rule is issued and implemented, additional capital and/or increased operating costs may be required. The costs of complying with any such final water intake standards are not currently determinable, but could be significant.
	In April 2013, the EPA proposed CWA regulations to address mercury, arsenic, lead, and selenium in water discharged from power plants. The proposed regulations include a variety of options for whether and how these different waste streams should be treated. The EPA is expected to evaluate comments on all of these options prior to enacting final regulations. Under the proposed approach, new requirements for existing power plants would be phased in between 2017 and 2022. The EPA also announced its intention to align this CWA rule with the related rule for CCRs discussed above. The EPA is under a consent decree to take final action by May 22, 2014. The EPA estimates that over half of the existing power plants will not incur costs under any of the proposed options because many power plants already have the technology and procedures in place to meet the proposed pollution control standards; however, it is too early to determine whether the impacts of these rules will be material.
	Clean Air Act Rules and Associated Emission Control Equipment Expenditures
	The EPA has proposed or issued a number of rules under different provisions of the Clean Air Act that could require the installation of emission control equipment at the generation plants where we have joint ownership.
	The Clean Air Visibility Rule was issued by the EPA in June 2005, to address regional haze in national parks and wilderness areas across the United States. The Clean Air Visibility Rule requires the installation and operation of Best Available Retrofit Technology (BART) to achieve emissions reductions from designated sources (including certain electric generating units) that are deemed to cause or contribute to visibility impairment in such 'Class I' areas.
	In December 2011, the EPA issued a final rule relating to Mercury and Air Toxics Standards (MATS). Among other things, the MATS set stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. Facilities that are subject to the MATS must come into compliance within three years after the effective date of the rule (or by 2015) unless a one year extension is granted on a case-by-case basis. Numerous challenges to the MATS have been filed with the EPA and in Federal court and we cannot predict the outcome of such challenges.
	In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to reduce emissions from electric generating units that interfere with the ability of downwind states to achieve ambient air quality standards. Under CSAPR, significant reductions in emissions of nitrogen oxide (NOx) and sulfur dioxide (SO2) were to be required in certain states beginning in 2012. On December 10, 2013, the Supreme Court heard oral arguments on the review of the D.C. Circuit's 2012 decision which vacated the CSAPR.
	In October 2013, the Supreme Court denied certiorari in Luminant Generation Co v. EPA, which challenged the EPA’s current approach to regulating air emissions during startup, shutdown and malfunction (SSM) events. As a result, fossil fuel power plants may need to address SSM in their permits to reduce the risk of enforcement or citizen actions.
	In September 2012, a final Federal Implementation Plan for Montana was published in the Federal Register to address regional haze. As finalized, Colstrip Unit 4 does not have to improve removal efficiency for pollutants that contribute to regional haze. By 2018, Montana, or EPA, must develop a revised Plan that demonstrates reasonable progress toward eliminating man made emissions of visibility impairing pollutants, which could impact Colstrip Unit 4. In November 2012, National Parks Conservation Association, Montana Environmental Information Center, and Sierra Club jointly filed a petition for review of the Federal Implementation Plan in the U.S. Court of Appeals for the Ninth Circuit. Montana Environmental Information Center and Sierra Club have challenged the EPA's decision not to require any emissions reductions from Colstrip Units 3 and 4. At this time, we cannot predict or determine the timing or outcome of this petition.
	We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are or may become subject to various regulations that have been issued or proposed under the Clean Air Act, as discussed below.
	South Dakota. The South Dakota DENR determined that the Big Stone Plant, of which we have a 23.4% ownership, is subject to the BART requirements of the Regional Haze Rule. South Dakota DENR's State Implementation Plan (SIP) was approved by the EPA in May 2012. Under the SIP, the Big Stone plant must install and operate a new BART compliant air quality control system (AQCS) to reduce SO2, NOx and particulate emissions as expeditiously as practicable, but no later than five years after the EPA's approval of the SIP. The current project cost for the AQCS is estimated to be approximately $405 million (our share is 23.4%) and it is expected to be operational by 2016. As of December 31, 2013, we have capitalized costs of approximately $40.5 million related to this project.
	Our incremental capital expenditure projections include amounts related to our share of the BART at Big Stone based on current estimates. We could, however, face additional capital or financing costs. We will seek to recover any such costs through the regulatory process. The South Dakota Public Utilities Commission has historically allowed timely recovery of the costs of environmental improvements; however, there is no precedent on a project of this size.
	Based on the finalized MATS, Big Stone will meet the requirements by installing the AQCS system and using activated carbon injection for mercury control. In August 2013, the South Dakota DENR granted Big Stone a one year extension to comply with MATS, such that the new compliance deadline is April 16, 2016. New mercury emissions monitoring equipment will also be required.
	North Dakota. The North Dakota Regional Haze SIP requires the Coyote generating facility, of which we have 10% ownership, to reduce its NOx emissions. Coyote must install control equipment to limit its NOx emissions to 0.5 pounds per million Btu as calculated on a 30-day rolling average basis, including periods of start-up and shutdown, beginning on July 1, 2018. The current estimate of the total cost of the project is approximately $9.0 million (our share is 10.0%).
	Based on the finalized MATS, Coyote will meet the requirements by using activated carbon injection for mercury control.
	Iowa. The Neal #4 generating facility, of which we have an 8.7% ownership, is installing a scrubber, a baghouse, activated carbon and a selective non-catalytic reduction system to comply with national ambient air quality standards and the MATS. The plant began incurring costs in 2011 and the project was substantially completed in 2013. Our share (8.7%) of the capitalized costs related to this project were approximately $22.6 million.
	Montana. Colstrip Unit 4, a coal fired generating facility in which we have a 30% interest, is currently controlling emissions of mercury under regulations issued by the State of Montana, which are stricter than the Federal MATS. The owners do not believe additional equipment will be necessary to meet the MATS for mercury, and anticipate meeting all other expected MATS emissions limitations required by the rule without additional costs except those costs related to increased monitoring frequency. These additional costs are not expected to be significant.
	See 'Legal Proceedings - Colstrip Litigation' below for discussion of Sierra Club litigation.
	Other - We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.
	We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:
	•	We may not know all sites for which we are alleged or will be found to be responsible for remediation; and
	•	Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation.
	LEGAL PROCEEDINGS
	Colstrip Litigation
	On March 6, 2013, the Sierra Club and the MEIC (Plaintiffs) filed suit in the United States District Court for the District of Montana against the six individual owners of Colstrip, including us, as well as the operator or managing agent of the station. On September 27, 2013, Plaintiffs filed an Amended Complaint for Injunctive and Declaratory Relief. The original complaint included 39 claims for relief based upon alleged violations of the Clean Air Act and the Montana State Implementation Plan. The Amended Complaint drops claims associated with projects completed before 2001, the Title V claims and the opacity claims. There are now a total of 23 claims.
	In the Amended Complaint, Plaintiffs have identified physical changes made at Colstrip between 2001 and 2012, which they allege have increased emissions of SO2, NOx and particulate matter and were “major modifications” subject to permitting requirements under the Clean Air Act. They also have alleged violations of the requirements related to Part 70 Operating Permits. Plaintiffs seek injunctive and declaratory relief, civil penalties (including $100,000 of civil penalties to be used for beneficial environmental projects), and recovery of their attorney fees.
	On May 3, 2013, the Colstrip owners and operator filed a partial motion to dismiss, seeking dismissal of 36 of the 39 claims asserted in the original complaint. The motion was not ruled upon and the Colstrip owners filed a second motion to dismiss the Amended Complaint on October 11, 2013, incorporating parts of the first motion and supplementing it with new authorities and with regard to new claims contained in the Amended Complaint. The Court has not ruled on the second motion to dismiss.
On September 12, 2013, Plaintiffs filed a motion for partial summary judgment as to the applicable method for calculating emissions increases from modifications. The Court has not ruled on Plaintiffs’ motion for partial summary judgment.
We intend to vigorously defend this lawsuit. Due to the preliminary nature of the lawsuit, at this time, we cannot predict an outcome, nor is it reasonably possible to estimate the amount or range of loss, if any, that would be associated with an adverse decision.
Other Legal Proceedings
We are also subject to various other legal proceedings, governmental audits and claims that arise in the ordinary course of business. In the opinion of management, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows.

Segment_and_Related_Informatio

Segment and Related Information	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment and Related Information	'
	Segment and Related Information
	Our reportable business segments are primarily engaged in the electric and natural gas business. The remainder of our operations are presented as other, which is not considered a business unit. Other primarily consists of a remaining unregulated natural gas capacity contract, the wind down of our captive insurance subsidiary and our unallocated corporate costs.
	We evaluate the performance of these segments based on gross margin. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions.
	Financial data for the business segments are as follows (in thousands):
	December 31, 2013	Electric			Gas			Other			Eliminations		Total
	Operating revenues	$	865,239		287,605			$	1,675		$	—	$	1,154,519
	Cost of sales	358,688			120,858			—			—		479,546
	Gross margin	506,551			166,747			1,675			—		674,973
	Operating, general and administrative	195,100			78,822			11,647			—		285,569
	Property and other taxes	78,536			26,993			11			—		105,540
	Depreciation	89,728			23,070			33			—		112,831
	Operating income (loss)	143,187			37,862			(10,016		)	—		171,033
	Interest expense	(57,920		)	(9,993		)	(2,573		)	—		(70,486		)
	Other income	4,061			1,239			2,437			—		7,737
	Income tax (expense) benefit	(13,905		)	(4,134		)	3,738			—		(14,301		)
	Net income (loss)	$	75,423		$	24,974		$	(6,414	)	$	—	$	93,983
	Total assets	$	2,583,554		$	1,117,861		$	13,845		$	—	$	3,715,260
	Capital expenditures	$	198,032		$	32,422		$	—		$	—	$	230,454
	December 31, 2012	Electric			Gas			Other			Eliminations		Total
	Operating revenues	$	805,554		$	263,394		$	1,394		$	—	$	1,070,342
	Cost of sales	277,826			117,608			—			—		395,434
	Gross margin	527,728			145,786			1,394			—		674,908
	Operating, general and administrative	187,599			75,971			6,396			—		269,966
	MSTI impairment	24,039			—			—			—		24,039
	Property and other taxes	72,755			24,907			12			—		97,674
	Depreciation	86,559			19,452			33			—		106,044
	Operating income (loss)	156,776			25,456			(5,047		)	—		177,185
	Interest expense	(55,118		)	(9,063		)	(881		)	—		(65,062		)
	Other income	2,630			1,633			109			—		4,372
	Income tax (expense) benefit	(22,298		)	(692		)	4,901			—		(18,089		)
	Net income (loss)	$	81,990		$	17,334		$	(918	)	$	—	$	98,406
	Total assets	$	2,442,602		$	1,032,259		$	10,672		$	—	$	3,485,533
	Capital expenditures	$	178,325		$	40,909		$	—		$	—	$	219,234
	December 31, 2011	Electric			Gas			Other			Eliminations		Total
	Operating revenues	$	797,562		$	318,335		$	1,419		$	—	$	1,117,316
	Cost of sales	327,126			167,433			—			—		494,559
	Gross margin	470,436			150,902			1,419			—		622,757
	Operating, general and administrative	183,503			80,431			3,226			—		267,160
	Property and other taxes	66,425			22,686			11			—		89,122
	Depreciation	81,859			19,034			33			—		100,926
	Operating income (loss)	138,649			28,751			(1,851		)	—		165,549
	Interest expense	(54,394		)	(10,432		)	(2,033		)	—		(66,859		)
	Other income	2,563			1,258			110			—		3,931
	Income tax (expense) benefit	(14,049		)	(3,472		)	7,456			—		(10,065		)
	Net income	$	72,769		$	16,105		$	3,682		$	—	$	92,556
	Total assets	$	2,259,189		$	938,876		$	12,373		$	—	$	3,210,438
	Capital expenditures	$	146,576		$	42,154		$	—		$	—	$	188,730

Quarterly_Financial_Data_Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Quarterly Financial Data	'
	Quarterly Financial Data (Unaudited)
	Our quarterly financial information has not been audited, but, in management's opinion, includes all adjustments necessary for a fair presentation. Our business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations. Amounts presented are in thousands, except per share data:
	2013	First		Second		Third			Fourth
	Operating revenues	$	313,020	$	260,161	$	262,248		$	319,090
	Operating income	57,010		32,660		31,401			49,962
	Net income	$	37,902	$	14,341	$	15,647		$	26,093
	Average common shares outstanding	37,384		38,092		38,459			38,626
	Income per average common share (basic):
	Net income	$	1.01	$	0.37	$	0.41		$	0.67
	Income per average common share (diluted):
	Net income	$	1.01	$	0.37	$	0.4		$	0.68
	Dividends per share	$	0.38	$	0.38	$	0.38		$	0.38
	Stock price:
	High	$	40.35	$	43.17	$	45.85		$	47.18
	Low	35.06		38.12		39.08			41.31
	Quarter-end close	39.86		39.9		44.92			43.32
	2012	First		Second		Third			Fourth
	Operating revenues	$	309,100	$	244,603	$	235,866		$	280,773
	Operating income	55,033		28,720		4,409			89,024
	Net income (loss)	$	32,043	$	11,438	$	(3,772	)	$	58,697
	Average common shares outstanding	36,328		36,635		37,201			37,218
	Income per average common share (basic):
	Net income (loss)	$	0.88	$	0.31	$	(0.10	)	$	1.58
	Income per average common share (diluted):
	Net income (loss)	$	0.88	$	0.31	$	(0.10	)	$	1.57
	Dividends per share	$	0.37	$	0.37	$	0.37		$	0.37
	Stock price:
	High	$	36.39	$	37.05	$	37.96		$	36.7
	Low	34.22		33.72		35.44			32.98
	Quarter-end close	35.46		36.7		36.23			34.73
	We recorded a pre-tax gain of approximately $47.9 million within cost of sales in the Consolidated Income Statements during the fourth quarter of 2012 associated with the CELP arbitration decision. See Note 3 - Acquisitions and Significant Events for further detail.

Nature_of_Operations_and_Basis1

Nature of Operations and Basis of Consolidation (Policies)	12 Months Ended
	Dec. 31, 2013
Nature of Operations and Basis of Consolidation [Abstract]	'
Variable Interest Entities	'
	Variable Interest Entities
	A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity's purpose and design and a company's ability to direct the activities of the entity that most significantly impact the entity's economic performance.
	Certain long-term purchase power and tolling contracts may be considered variable interests. We have various long-term purchase power contracts with other utilities and certain QF plants. We identified one QF contract that may constitute a VIE. We entered into a power purchase contract in 1984 with this 35 MW coal-fired QF to purchase substantially all of the facility's capacity and electrical output over a substantial portion of its estimated useful life. We absorb a portion of the facility's variability through annual changes to the price we pay per MWH (energy payment). After making exhaustive efforts, we have been unable to obtain the information from the facility necessary to determine whether the facility is a VIE or whether we are the primary beneficiary of the facility. The contract with the facility contains no provision which legally obligates the facility to release this information. We have accounted for this QF contract as an executory contract. Based on the current contract terms with this QF, our estimated gross contractual payments aggregate approximately $286.2 million through 2024. For further discussion of our gross QF liability, see Note 20 - Commitments and Contingencies. During the years ended December 31, 2013, 2012 and 2011 purchases from this QF were approximately $23.8 million, $21.0 million, and $18.4 million, respectively.

Significant_Accounting_Policie1

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Use of Estimates	'
	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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. Estimates are used for such items as long-lived asset values and impairment charges, long-lived asset useful lives, tax provisions, asset retirement obligations, uncollectible accounts, our QF liability, environmental costs, unbilled revenues and actuarially determined benefit costs. We revise the recorded estimates when we receive better information or when we can determine actual amounts. Those revisions can affect operating results.
Revenue Recognition	'
	Revenue Recognition
	Customers are billed monthly on a cycle basis. To match revenues with associated expenses, we accrue unbilled revenues for electrical and natural gas services delivered to customers, but not yet billed at month-end.
Cash Equivalents	'
	Cash Equivalents
	We consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents.
Restricted Cash	'
	Restricted Cash
	Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements.
Accounts Receivable, Net	'
	Accounts Receivable, Net
	Accounts receivable are net of allowances for uncollectible accounts of $4.5 million and $3.2 million at December 31, 2013 and December 31, 2012, respectively. Receivables include unbilled revenues of $74.3 million and $71.4 million at December 31, 2013 and December 31, 2012, respectively.
Inventories	'
	Inventories
	Inventories are stated at average cost. Inventory consisted of the following (in thousands):
		December 31,
		2013		2012
	Materials and supplies	$	28,263	$	25,094
	Storage gas and fuel	27,346		29,067
		$	55,609	$	54,161
Regulation of Utility Operations	'
	Regulation of Utility Operations
	Our regulated operations are subject to the provisions of ASC 980, Regulated Operations (ASC 980). Regulated accounting is appropriate provided that (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise's cost of service, and (iii) in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be charged to and collected from customers.
	Our Consolidated Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. The economic effects of regulation can result in regulated companies recording costs that have been, or are expected to be, allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities).
	If we were required to terminate the application of these provisions to our regulated operations, all such deferred amounts would be recognized in the Consolidated Income Statements at that time. This would result in a charge to earnings, net of applicable income taxes, which could be material. In addition, we would determine any impairment to the carrying costs of deregulated plant and inventory assets.
Derivative Financial Instruments	'
	Derivative Financial Instruments
	We account for derivative instruments in accordance with ASC 815, Derivatives and Hedging. All derivatives are recognized in the Consolidated Balance Sheets at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair-value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash-flow hedge). For fair-value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash-flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in accumulated other comprehensive income (AOCI) and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For other derivative contracts that do not qualify or are not designated for hedge accounting, changes in the fair value of the derivatives are recognized in earnings each period. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the underlying nature of the hedged items.
	Revenues and expenses on contracts that qualify are designated as normal purchases and normal sales and are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but on an accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric and gas operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it were determined that a transaction designated as a normal purchase or a normal sale no longer met the exceptions, the fair value of the related contract would be reflected as an asset or liability and immediately recognized through earnings. See Note 9, Risk Management and Hedging Activities for further discussion of our derivative activity.
Property, Plant and Equipment	'
	Property, Plant and Equipment
	Property, plant and equipment are stated at original cost, including contracted services, direct labor and material, AFUDC, and indirect charges for engineering, supervision and similar overhead items. All expenditures for maintenance and repairs of utility property, plant and equipment are charged to the appropriate maintenance expense accounts. A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility plant. At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired and also for the net cost of removal. Also included in plant and equipment are assets under capital lease, which are stated at the present value of minimum lease payments.
	AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized currently from such allowance, it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. We determine the rate used to compute AFUDC in accordance with a formula established by the FERC. This rate averaged 8.1%, 8.0%, and 7.9%, for Montana for 2013, 2012, and 2011, respectively, and 8.1%, 8.0%, and 7.8% for South Dakota for 2013, 2012, and 2011, respectively. AFUDC capitalized totaled $8.2 million for the year ended December 31, 2013, $7.9 million for the year ended December 31, 2012 and $3.1 million for the year ended December 31, 2011 for Montana and South Dakota combined.
	We may require contributions in aid of construction from customers when we extend service. Amounts used from these contributions to fund capital additions were $6.3 million and $5.0 million for the years ended December 31, 2013 and 2012, respectively.
	We record provisions for depreciation at amounts substantially equivalent to calculations made on a straight-line method by applying various rates based on useful lives of the various classes of properties (ranging from three to 40 years) determined from engineering studies. As a percentage of the depreciable utility plant at the beginning of the year, our provision for depreciation of utility plant was approximately 3.2%, 3.3%, and 3.3% for 2013, 2012, and 2011, respectively. During the second quarter of 2013, we implemented revised depreciation rates to reflect the results of new depreciation studies, which reflect longer asset lives on our electric and natural gas assets in Montana, and electric assets in South Dakota.
	Depreciation rates include a provision for our share of the estimated costs to decommission three coal-fired generating plants at the end of the useful life of each plant. The annual provision for such costs is included in depreciation expense, while the accumulated provisions are included in noncurrent regulatory liabilities.
Insurance Subsidiary	'
	Insurance Subsidiary
	Risk Partners Assurance, Ltd (Risk Partners) is a wholly owned non-United States insurance subsidiary established in 2001 to insure a portion of our workers' compensation, general liability and automobile liability risks. New policies have not been underwritten through this subsidiary since 2004. Claims that were incurred during that time period continue to be paid and managed by Risk Partners. Reserve requirements are established based on actuarial projections of ultimate losses. Any losses estimated to be paid within one year from the balance sheet date are classified as accrued expenses, while losses expected to be payable in later periods are included in other long-term liabilities. Risk Partners has purchased reinsurance policies through a third-party reinsurance company to transfer a portion of the insurance risk. Restricted cash held by this subsidiary was $2.7 million and $3.8 million as of December 31, 2013 and 2012, respectively.
Income Taxes	'
	Income Taxes
	Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ from these estimates. The resolution of tax matters in a particular future period could have a material impact on our Consolidated Income Statements and provision for income taxes.
Environmental Costs	'
	Environmental Costs
	We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset if there is precedent for recovering similar costs from customers in rates. Otherwise, we expense the costs. If an environmental cost is related to facilities we currently use, such as pollution control equipment, then we may capitalize and depreciate the costs over the remaining life of the asset, assuming the costs are recoverable in future rates or future cash flows.
	Our remediation cost estimates are based on the use of an environmental consultant, our experience, our assessment of the current situation and the technology currently available for use in the remediation. We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated responsible parties, then we estimate and record only our share of the cost.

Significant_Accounting_Policie2

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Inventories	'
	Inventories are stated at average cost. Inventory consisted of the following (in thousands):
		December 31,
		2013		2012
	Materials and supplies	$	28,263	$	25,094
	Storage gas and fuel	27,346		29,067
		$	55,609	$	54,161
Other Noncurrent Liabilties	'
	Other noncurrent liabilities consisted of the following (in thousands):
		December 31,
		2013		2012
	Pension and other employee benefits	$	57,140	$	148,384
	Future QF obligation, net	136,448		136,652
	Environmental	28,194		30,189
	Customer advances	27,371		34,681
	Other	43,471		25,148
		$	292,624	$	375,054
Supplemental Cash Flow Information	'
	Supplemental Cash Flow Information
		Year Ended December 31,
		2013		2012		2011
				(in thousands)
	Cash paid (received) for:
	Income taxes	$	50	$	2,944	$	(1,219	)
	Interest	57,789		51,271		52,328
	Significant non-cash transactions:
	Capital expenditures included in trade accounts payable	12,025		13,136		10,910

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 And Liabilities	'
	We have specific orders to cover approximately 97% of our regulatory assets and 93% of our regulatory liabilities.
		Note Reference	Remaining Amortization Period	December 31,
				2013		2012
				(in thousands)
	Pension	16	Undetermined	$	58,474	$	143,672
	Employee related benefits	16	Undetermined	17,700		20,911
	Distribution infrastructure projects		4 Years	12,543		15,679
	Environmental clean-up	20	Various	14,924		16,497
	Supply costs		1 Year	17,875		11,788
	Energy supply derivatives	9	1 Year	—		5,428
	Income taxes	13	Plant Lives	201,808		162,154
	Deferred financing costs		Various	13,919		13,944
	State & local taxes & fees		Various	6,582		8,337
	Other	—	Various	10,846		9,781
	Total regulatory assets			$	354,671	$	408,191
	Removal cost	7	Various	$	336,613	$	264,486
	Gas storage sales		26 Years	10,831		11,251
	Supply costs		1 Year	11,493		17,591
	Deferred revenue	4	1 Year	33,400		26,259
	Environmental clean-up		Various	1,194		1,395
	State & local taxes & fees		1 Year	551		537
	Other		Various	377		3,524
	Total regulatory liabilities			$	394,459	$	325,043

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Major classifications of property, plant and equipment	'
	The following table presents the major classifications of our property, plant and equipment (in thousands):
		Estimated Useful Life		December 31,
				2013				2012
		(years)		(in thousands)
	Land, land rights and easements	54 – 96		$	128,123			$	72,550
	Building and improvements	27 – 64		163,852				145,989
	Transmission, distribution, and storage	15 – 85		2,448,821				2,339,111
	Generation	25 – 50		533,450				506,017
	Plant acquisition adjustment	34		204,754				204,754
	Other	Feb-45		308,345				259,308
	Construction work in process	–—		104,891				121,360
				3,892,236				3,649,089
	Less accumulated depreciation			(1,202,108		)		(1,213,499		)
				$	2,690,128			$	2,435,590
Schedule of jointly owned utility plants	'
	Information relating to our ownership interest in these facilities is as follows (in thousands):
		Big Stone				Neal #4				Coyote			Colstrip Unit 4 (MT)
		(SD)				(IA)				(ND)
	December 31, 2013
	Ownership percentages	23.4		%		8.7		%		10		%	30		%
	Plant in service	$	61,186			$	57,633			$	46,003		$	290,163
	Accumulated depreciation	45,792				29,841				36,076			70,072
	December 31, 2012
	Ownership percentages	23.4		%		8.7		%		10		%	30		%
	Plant in service	$	61,084			$	30,009			$	46,188		$	290,607
	Accumulated depreciation	38,021				23,994				30,655			67,534

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Schedule of Change in Asset Retirement Obligation	'
	The following table presents the change in our gross conditional ARO (in thousands):
		December 31,
		2013			2012
	Liability at January 1,	$	9,283		$	6,292
	Accretion expense	745			473
	Liabilities incurred	8,829			2,466
	Liabilities settled	(27		)	(35		)
	Revisions to cash flows	2,056			87
	Liability at December 31,	$	20,886		$	9,283

Goodwill_Tables

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2013
Goodwill [Abstract]	'
Schedule of Goodwill	'
	Goodwill by segment is as follows (in thousands):
		December 31,
		2013		2012
	Electric	$	241,100	$	241,100
	Natural gas	114,028		114,028
		$	355,128	$	355,128

Risk_Management_and_Hedging_Ac1

Risk Management and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Schedule of Derivative Instruments	'
	The following table represents the fair value and location of derivative instruments subject to mark-to-market accounting (in thousands). For more information on the determination of fair value see Note 10 - Fair Value Measurements.
				December 31,
	Mark-to-Market Transactions	Balance Sheet Location		2013				2012
	Natural gas net derivative liability	Accrued Expenses		$	—			$	5,428
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	'
	The following table represents the net change in fair value for these derivatives (in thousands):
		Unrealized gain recognized in
		Regulatory Assets
		December 31,
	Derivatives Subject to Regulatory Deferral	2013				2012
	Natural gas	$	5,428			$	14,884
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)	'
	The following table shows the effect of these derivative instruments on the Consolidated Financial Statements (in thousands):
	Cash Flow Hedges		Location of Gain Reclassified from AOCI to Income		Amount of Gain Reclassified from AOCI into Income during the Year Ended
					31-Dec-13
	Interest rate contracts		Interest Expense		$	1,188

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	'
	The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. Normal purchases and sales transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 9 - Risk Management and Hedging Activities for further discussion.
	We record transfers between levels of the fair value heirarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented.
	December 31, 2013		Quoted Prices in			Significant Other				Significant			Margin Cash Collateral		Total Net Fair Value
			Active Markets for			Observable Inputs				Unobservable Inputs			Offset
			Identical Assets or			(Level 2)				(Level 3)
			Liabilities (Level 1)
			(in thousands)
	Restricted cash		$	6,650		$	—			$	—		$	—	$	6,650
	Rabbi trust investments		16,477			—				—			—		16,477
	Total		$	23,127		$	—			$	—		$	—	$	23,127
	December 31, 2012
	Restricted cash		$	6,392		$	—			$	—		$	—	$	6,392
	Rabbi trust investments		10,522			—				—			—		10,522
	Derivative liability (1)		—			(5,428		)		—			—		(5,428		)
	Total		$	16,914		$	(5,428	)		$	—		$	—	$	11,486
	____________________________
	-1	The changes in the fair value of these derivatives are deferred as a regulatory asset or liability until the contracts are settled. Upon settlement, associated proceeds or costs are passed through the applicable cost tracking mechanism to customers.
Schedule of Estimated Fair Value of Financial Instruments	'
	The estimated fair value of financial instruments is summarized as follows (in thousands):
		December 31, 2013							December 31, 2012
		Carrying Amount			Fair Value				Carrying Amount			Fair Value
	Liabilities:
	Long-term debt	$	1,155,097		$	1,237,151			$	1,055,074		$	1,229,233

ShortTerm_Borrowings_and_Credi1

Short-Term Borrowings and Credit Arrangements (Tables)	12 Months Ended
	Dec. 31, 2013
Short-term Debt [Abstract]	'
Schedule of Short-term Debt	'
	Short-term borrowings and the corresponding weighted average interest rates as of December 31 were as follows (dollars in millions, except for percentages):
			2013					2012
	Short-Term Debt		Balance			Interest Rate		Balance		Interest Rate
	Commercial Paper		$	141		0.41	%	$	122.9	0.53	%
	The following information relates to commercial paper for the years ended December 31 (dollars in millions):
		2013			2012
	Maximum short-term debt outstanding	$	199.9		$	166.9
	Average short-term debt outstanding	$	69		$	78.9
	Weighted-average interest rate	0.4		%	0.48		%

LongTerm_Debt_and_Capital_Leas1

Long-Term Debt and Capital Leases (Tables)	12 Months Ended
	Dec. 31, 2013
Long-term Debt and Capital Lease Obligations [Abstract]	'
Schedule of Debt and Capital Leases	'
	Long-term debt and capital leases consisted of the following (in thousands):
			December 31,
		Due	2013			2012
	Unsecured Debt:
	Unsecured Revolving Line of Credit	2018	$	—		$	—
	Secured Debt:
	Mortgage bonds—
	South Dakota—6.05%	2018	55,000			55,000
	South Dakota—5.01%	2025	64,000			64,000
	South Dakota—4.15%	2042	30,000			30,000
	South Dakota—4.30%	2052	20,000			20,000
	South Dakota—4.85%	2043	50,000			—
	Montana—6.04%	2016	150,000			150,000
	Montana—6.34%	2019	250,000			250,000
	Montana—5.71%	2039	55,000			55,000
	Montana—5.01%	2025	161,000			161,000
	Montana—4.15%	2042	60,000			60,000
	Montana—4.30%	2052	40,000			40,000
	Montana—4.85%	2043	15,000			—
	Montana—3.99%	2028	35,000			—
	Pollution control obligations—
	Montana—4.65%	2023	170,205			170,205
	Other Long Term Debt:
	Discount on Notes and Bonds	—	(108		)	(131		)
			1,155,097			1,055,074
	Less current maturities		—			—
			$	1,155,097		$	1,055,074
	Capital Leases:
	Total Capital Leases	Various	$	31,557		$	33,174
	Less current maturities		(1,662		)	(1,612		)
			$	29,895		$	31,562

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Schedule Of Income Tax Expense Domestic	'
	Income tax expense is comprised of the following (in thousands):
		Year Ended December 31,
		2013				2012				2011
	Federal
	Current	$	108			$	5,358			$	(159	)
	Deferred	18,150				13,197				18,618
	Investment tax credits	(335		)		(376		)		(424		)
	State
	Current	83				(1,411		)		(27		)
	Deferred	(3,705		)		1,321				(7,943		)
		$	14,301			$	18,089			$	10,065
Schedule of Effective Income Tax Rate Reconciliation	'
	The following table reconciles our effective income tax rate to the federal statutory rate:
		Year Ended December 31,
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State income, net of federal provisions	(2.8	)		0.9			(5.5	)
	Flow-through repairs deductions	(16.4	)		(14.0	)		(13.1	)
	Production tax credits	(2.9	)		—			—
	Plant and depreciation of flow through items	(0.5	)		(1.1	)		(0.3	)
	Prior year permanent return to accrual adjustments	0.5			(1.6	)		(3.8	)
	Recognition of state net operating loss benefit / valuation allowance release	—			(2.1	)		(2.3	)
	Other, net	0.3			(1.6	)		(0.2	)
		13.2	%		15.5	%		9.8	%
	The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rate (in thousands):
		Year Ended December 31,
		2013				2012				2011
	Income Before Income Taxes	$	108,284			$	116,495			$	102,621
	Income tax calculated at 35% federal statutory rate	37,899				40,774				35,917
	Permanent or flow through adjustments:
	State income, net of federal provisions	(3,082		)		1,078				(5,673		)
	Flow-through repairs deductions	(17,763		)		(16,350		)		(13,425		)
	Production tax credits	(3,171		)		—				—
	Plant and depreciation of flow through items	(584		)		(1,281		)		(264		)
	Prior year permanent return to accrual adjustments	541				(1,901		)		(3,948		)
	Recognition of state net operating loss benefit / valuation allowance release	—				(2,398		)		(2,402		)
	Other, net	461				(1,833		)		(140		)
		$	(23,598	)		$	(22,685	)		$	(25,852	)
	Income tax expense	$	14,301			$	18,089			$	10,065
Schedule of Deferred Tax Assets and Liabilities	'
	The components of the net deferred income tax liability recognized in our Consolidated Balance Sheets are related to the following temporary differences (in thousands):
		December 31,
		2013				2012
	Pension / postretirement benefits	$	20,522			$	59,098
	Unbilled revenue	18,136				15,944
	NOL carryforward	16,758				—
	Reserves and accruals	12,097				12,457
	Customer advances	10,781				13,660
	Compensation accruals	10,409				11,303
	AMT credit carryforward	10,357				10,588
	Environmental liability	9,026				9,701
	Regulatory assets	7,248				—
	Production tax credit	3,171				—
	QF obligations	2,066				1,462
	Property taxes	796				18,025
	Regulatory liabilities	659				1,526
	Other, net	2,827				3,539
	Deferred Tax Asset	124,853				157,303
	Excess tax depreciation	(304,071		)		(278,051		)
	Goodwill amortization	(122,798		)		(118,313		)
	Flow through depreciation	(79,016		)		(63,551		)
	Regulatory assets	—				(24,173		)
	Deferred Tax Liability	(505,885		)		(484,088		)
	Deferred Tax Liability, net	$	(381,032	)		$	(326,785	)
Summary of Income Tax Contingencies	'
	The change in unrecognized tax benefits is as follows (in thousands):
		2013				2012				2011
	Unrecognized Tax Benefits at January 1	$	113,291			$	131,949			$	120,859
	Gross increases - tax positions in prior period	—				—				—
	Gross decreases - tax positions in prior period	—				(1,766		)		(15,774		)
	Gross increases - tax positions in current period	518				2,391				26,864
	Gross decreases - tax positions in current period	(343		)		(19,283		)		—
	Unrecognized Tax Benefits at December 31	$	113,466			$	113,291			$	131,949

Other_Comprehensive_Loss_Incom1

Other Comprehensive (Loss) Income (Tables)	12 Months Ended
	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]	'
Schedule of Comprehensive Income (Loss)	'
	The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands):
		December 31,
		2013												2012									2011
		Before-Tax Amount				Tax Benefit				Net-of-Tax Amount				Before-Tax Amount				Tax Benefit		Net-of-Tax Amount			Before-Tax Amount			Tax Benefit			Net-of-Tax Amount
	Foreign currency translation adjustment	$	166			$	—			$	166			$	(54	)		—		$	(54	)	$	25		$	—		$	25
	Reclassification of net gains on derivative instruments to net income	(1,188		)		458				(730		)		(1,188		)		456		(732		)	(1,188		)	458			(730		)
	Reclassification of deferred tax liability on net gains on derivative instruments	—				—				—				—				—		—			—			(3,572		)	(3,572		)
	Pension and postretirement medical liability adjustment	1,568				(605		)		963				(897		)		344		(553		)	(736		)	155			(581		)
	Other comprehensive income (loss)	$	546			$	(147	)		$	399			$	(2,139	)		$	800	$	(1,339	)	$	(1,899	)	$	(2,959	)	$	(4,858	)
Schedule of Accumulated Comprehensive Income (Loss)	'
	Balances by classification included within AOCI on the Consolidated Balance Sheets are as follows, net of tax (in thousands):
		December 31, 2013				December 31, 2012
	Foreign currency translation	$	532			$	366
	Derivative instruments designated as cash flow hedges	3,513				4,243
	Pension and postretirement medical plans	(1,329		)		(2,292		)
	Accumulated other comprehensive income	2,716				2,317
Reclassification out of Accumulated Other Comprehensive Income	'
	The following table displays the changes in AOCI by component, net of tax (in thousands):
				31-Dec-13
				Twelve Months Ended
		Affected Line Item in the Consolidated Statements of Income		Gains on Derivative Instruments Designated as Cash Flow Hedges				Pension and Postretirement Medical Plans				Foreign Currency Translation				Total
	Beginning balance			$	4,243			$	(2,292	)		$	366			$	2,317
	Other comprehensive income before reclassifications			—				—				166				$	166
	Amounts reclassified from accumulated other comprehensive income	Interest Expense		(730		)		—				—				$	(730	)
	Amounts reclassified from accumulated other comprehensive income			—				963				—				$	963
	Net current-period other comprehensive (loss) income			(730		)		963				166				399
	Ending balance			$	3,513			$	(1,329	)		$	532			$	2,716

Operating_Leases_Tables

Operating Leases (Tables)	12 Months Ended
	Dec. 31, 2013
Leases [Abstract]	'
Schedule of Future Minimum Payments for Operating Leases	'
	We lease vehicles, office equipment and facilities under various long-term operating leases. At December 31, 2013 future minimum lease payments for the next five years under non-cancelable lease agreements are as follows (in thousands):
	2014	1,655
	2015	1,260
	2016	796
	2017	434
	2018	40

Employee_Benefit_Plans_Tables

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Schedule of Changes in Projected Benefit Obligations	'
	Following is a reconciliation of the changes in plan benefit obligations and fair value of plan assets, and a statement of the funded status (in thousands):
		Pension Benefits								Other Postretirement Benefits
		December 31,								December 31,
		2013				2012				2013				2012
	Change in Benefit Obligation:
	Obligation at beginning of period	$	609,643			$	536,536			$	34,040			$	32,427
	Service cost	13,465				11,488				541				541
	Interest cost	22,719				23,823				877				1,167
	Actuarial (gain) loss	(54,671		)		59,071				(3,156		)		2,508
	Benefits paid	(23,290		)		(21,275		)		(2,218		)		(2,603		)
	Benefit obligation at end of period	$	567,866			$	609,643			$	30,084			$	34,040
	Change in Fair Value of Plan Assets:
	Fair value of plan assets at beginning of period	$	472,936			$	432,637			$	15,893			$	15,502
	Return on plan assets	55,006				49,874				2,662				1,789
	Employer contributions	11,700				11,700				1,846				1,205
	Benefits paid	(23,290		)		(21,275		)		(2,218		)		(2,603		)
	Fair value of plan assets at end of period	$	516,352			$	472,936			$	18,183			$	15,893
	Funded Status	$	(51,514	)		$	(136,707	)		$	(11,901	)		$	(18,147	)
	Amounts recognized in the balance sheet consist of:
	Current liability	—				—				(1,178		)		(1,082		)
	Noncurrent liability	(51,514		)		(136,707		)		(10,723		)		(17,065		)
	Net amount recognized	$	(51,514	)		$	(136,707	)		$	(11,901	)		$	(18,147	)
	Amounts recognized in regulatory assets consist of:
	Prior service (cost) credit	(748		)		(994		)		19,247				21,396
	Net actuarial loss	(71,777		)		(160,610		)		(4,807		)		(9,488		)
	Amounts recognized in AOCI consist of:
	Prior service cost	—				—				(1,302		)		(1,453		)
	Net actuarial gain	—				—				(971		)		(2,432		)
	Total	$	(72,525	)		$	(161,604	)		$	12,167			$	8,023
Schedule of Benefit Obligations in Excess of Fair Value of Plan Assets	'
	The total projected benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were as follows (in millions):
		Pension Benefits
		December 31,
		2013				2012
	Projected benefit obligation	$	567.9			$	609.6
	Accumulated benefit obligation	565				606.2
	Fair value of plan assets	516.4				472.9
Schedule of Defined Benefit Plans Disclosures	'
	The components of the net costs (credits) for our pension and other postretirement plans are as follows (in thousands):
		Pension Benefits												Other Postretirement Benefits
		December 31,												December 31,
		2013				2012				2011				2013				2012			2011
	Components of Net Periodic Benefit Cost
	Service cost	$	13,465			$	11,488			$	10,199			$	541			$	541		$	437
	Interest cost	22,719				23,823				24,394				877				1,167			1,348
	Expected return on plan assets	(32,491		)		(29,996		)		(30,462		)		(1,019		)		(1,021		)	(1,185		)
	Amortization of prior service cost (credit)	246				246				246				(1,998		)		(1,998		)	(1,998		)
	Recognized actuarial loss	11,648				8,646				2,516				1,271				790			658
	Net Periodic Benefit Cost (Credit)	$	15,587			$	14,207			$	6,893			$	(328	)		$	(521	)	$	(740	)
Schedule of Estimated Amortization of Regulatory Assets Into Net Periodic Benefit Costs	'
	We estimate amortizations from regulatory assets into net periodic benefit cost during 2014 will be as follows (in thousands):
		Pension Benefits				Other
						Postretirement
						Benefits
	Prior service cost (credit)	$	246			$	(1,998	)
	Accumulated loss	2,226				310
Schedule of Assumptions Used	'
	The weighted-average assumptions used in calculating the preceding information are as follows:
		Pension Benefits						Other Postretirement Benefits
		December 31,						December 31,
		2013		2012		2011		2013		2012		2011
	Discount rate	4.55-4.75	%	3.55-3.80	%	4.40-4.55	%	3.75-4.20	%	2.25-3.20	%	3.50-4.30	%
	Expected rate of return on assets	7		7		7.25		7		7		7.25
	Long-term rate of increase in compensation levels (nonunion)	3.58		3.58		3.58		3.58		3.58		3.58
	Long-term rate of increase in compensation levels (union)	3.5		3.5		3.5		3.5		3.5		3.5
Schedule of Pension And Postretirement Benefits Investment Strategy	'
	Based on this, the target asset allocation established, within an allowable range of plus or minus 5%, is as follows:
		Pension Benefits						Other Benefits
		December 31,						December 31,
		2013			2012			2013			2012
	Domestic debt securities	60	%		40	%		40	%		40	%
	International debt securities	5			10			—			—
	Domestic equity securities	30			40			50			50
	International equity securities	5			10			10			10
Schedule of Allocation of Plan Assets	'
	The actual allocation by plan is as follows:
		NorthWestern Energy Pension						NorthWestern Corporation Pension						NorthWestern Energy
														Health and Welfare
		December 31,						December 31,						December 31,
		2013			2012			2013			2012			2013			2012
	Cash and cash equivalents	—	%		—	%		0.1	%		—	%		1.8	%		3.4	%
	Domestic debt securities	58.6			39.5			64.7			38.3			38.6			37.8
	International debt securities	4.9			9.9			4.9			10.6			0.3			—
	Domestic equity securities	31.4			40.2			25.3			40.6			50.1			49.8
	International equity securities	5.1			10.4			5			10.5			9.2			9
		100	%		100	%		100	%		100	%		100	%		100	%
Schedule of Fair Value of Plan Assets by Category	'
	The fair value of our plan assets at December 31, 2013, by asset category are as follows (in thousands):
	Asset Category	Total				Quoted Market				Significant Observable Inputs				Significant Unobservable Inputs
						Prices in Active				Level 2				Level 3
						Markets for
						Identical Assets
						Level 1
	Pension Plan Assets
	Cash and cash equivalents	$	168			$	—			$	168			$	—
	Equity securities: (1)
	US small/mid cap growth	13,764				—				13,764				—
	US small/mid cap value	13,664				—				13,664				—
	US large cap growth	42,094				—				42,094				—
	US large cap value	42,102				—				42,102				—
	US large cap passive	47,227				—				47,227				—
	Non-US core	20,015				—				20,015				—
	Emerging markets	6,250				—				6,250				—
	Fixed income securities:(2)
	US core	82,639				—				82,639				—
	US passive	44,762				—				44,762				—
	Long duration	24,401				—				24,401				—
	Long duration investment grade	32,700				—				32,700				—
	Long duration passive	24,122				—				24,122				—
	Opportunistic	5,876				—				5,876				—
	Non-US passive	25,150				—				25,150				—
	Active long corporate	83,147				—				83,147				—
	Participating group annuity contract	8,271				—				8,271				—
		$	516,352			$	—			$	516,352			$	—
	Other Postretirement Benefit Plan Assets
	Cash and cash equivalents	$	318			$	—			$	318			$	—
	Equity securities: (1)
	US small/mid cap growth	751				—				751				—
	US small/mid cap value	736				—				736				—
	S&P 500 index	7,321				—				7,321				—
	US large cap growth	98				—				98				—
	US large cap value	98				—				98				—
	US large cap passive	110				—				110				—
	Non-US core	1,595				—				1,595				—
	Emerging markets	85				—				85				—
	Fixed income securities: (2)
	Passive bond market	1,880				—				1,880				—
	US core	4,390				—				4,390				—
	US passive	107				—				107				—
	Long duration	55				—				55				—
	Long duration investment grade	79				—				79				—
	Long duration passive	55				—				55				—
	Opportunistic	261				—				261				—
	Non-US passive	57				—				57				—
	Active long corporate	187				—				187				—
		$	18,183			$	—			$	18,183			$	—
	The fair value of our plan assets at December 31, 2012, by asset category are as follows (in thousands):
	Asset Category	Total				Quoted Market				Significant Observable Inputs				Significant Unobservable Inputs
						Prices in Active				Level 2				Level 3
						Markets for
						Identical Assets
						Level 1
	Pension Plan Assets
	Cash and cash equivalents	$	508							$	508			$	—
	Equity securities: (1)
	US small/mid cap growth	16,229				—				16,229				—
	US small/mid cap value	16,297				—				16,297				—
	US large cap growth	49,811				—				49,811				—
	US large cap value	51,655				—				51,655				—
	US large cap passive	56,194				—				56,194				—
Non-US core	36,358				—				36,358				—
Emerging markets	12,713				—				12,713				—
Fixed income securities:(2)
US core opportunistic	90,742				—				90,742				—
US passive	48,710				—				48,710				—
Long duration	6,455				—				6,455				—
Long duration investment grade	7,091				—				7,091				—
Long duration passive	5,239				—				5,239				—
Non-US passive	46,856				—				46,856				—
Active long corporate	18,540				—				18,540				—
Participating group annuity contract	9,538				—				9,538				—
	$	472,936			$	—			$	472,936			$	—
Other Postretirement Benefit Plan Assets
Cash and cash equivalents	$	533			—				$	533			—
Equity securities: (1)
US small/mid cap growth	567				—				567				—
US small/mid cap value	567				—				567				—
S&P 500 index	6,360				—				6,360				—
US large cap growth	132				—				132				—
US large cap value	139				—				139				—
US large cap passive	151				—				151				—
Non-US core	1,323				—				1,323				—
Emerging markets	108				—				108				—
Fixed income securities: (2)
Passive bond market	1,205				—				1,205				—
US core opportunistic	4,440				—				4,440				—
US passive	138				—				138				—
Long duration	16				—				16				—
Long duration investment grade	21				—				21				—
Long duration passive	16				—				16				—
Non-US passive	124				—				124				—
Active long corporate	53				—				53				—
	$	15,893			$	—			$	15,893			$	—
_________________
-1	This category consists of active and passive managed equity funds, which are invested in multiple strategies to diversify risks and reduce volatility.
(2) This category consists of investment grade bonds of issuers from diverse industries, debt securities issued by international, national, state and local governments, and asset-backed securities. This includes both active and passive managed funds.
Schedule of Pension Contributions	'
	Annual contributions to each of the pension plans are as follows (in thousands):
		2013				2012				2011
	NorthWestern Energy Pension Plan (MT)	$	10,500			$	10,500			$	10,500
	NorthWestern Pension Plan (SD)	1,200				1,200				1,200
		$	11,700			$	11,700			$	11,700
Schedule of Expected Benefit Payments	'
	We estimate the plans will make future benefit payments to participants as follows (in thousands):
		Pension Benefits				Other Postretirement Benefits
	2014	$	26,648			$	3,585
	2015	27,855				3,494
	2016	29,850				3,388
	2017	31,016				3,237
	2018	32,472				3,082
	2019-2023	182,212				12,107

StockBased_Compensation_Tables

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions	'
	The following summarizes the significant assumptions used to determine the fair value of performance shares and related compensation expense as well as the resulting estimated fair value of performance shares granted:
		2013		2012
	Risk-free interest rate	0.44	%	0.38	%
	Expected life, in years	3		3
	Expected volatility	16.3% to 25.4%		20.2% to 34.2%
	Dividend yield	3.9	%	4.1	%
Schedule of Nonvested Share Activity	'
	A summary of nonvested shares as of and changes during the year ended December 31, 2013, are as follows:
		Performance Share Awards				Restricted Stock Awards
		Shares		Weighted-Average Grant-Date		Shares		Weighted-Average Grant-Date
				Fair Value				Fair Value
	Beginning nonvested grants	186,755		$	22.64	1,000		$	24.77
	Granted	88,592		32.97		2,500		35.78
	Vested	(100,402	)	20.48		(3,500	)	32.63
	Forfeited	(1,299	)	25.33		—		—
	Remaining nonvested grants	173,646		$	29.14	—		$	—
Share-based Compensation Arrangement by Share-based Payment Award	'
Schedule of Nonvested Restricted Stock Units Activity	'
	A summary of nonvested shares as of and changes during the year ended December 31, 2013, are as follows:
		Shares		Weighted-Average Grant-Date
				Fair Value
	Beginning nonvested grants	17,537		$	27.7
	Granted	9,091		35.14
	Vested	—		—
	Forfeited	—		—
	Remaining nonvested grants	26,628		$	30.24

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Schedule of Weighted Average Number of Shares	'
	Average shares used in computing the basic and diluted earnings per share are as follows:
		December 31,
		2013	2012
	Basic computation	38,144,852	36,847,427
	Dilutive effect of
	Restricted stock and performance share awards (1)	82,223	193,473
	Diluted computation	38,227,075	37,040,900
	_____________________
	(1)           Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Schedule of Changes In Qualifying Facility Liability	'
	The following summarizes the change in the QF liability (in thousands):
		December 31,
		2013			2012
	Beginning QF liability	$	136,652		$	184,187
	Gain on CELP arbitration decision	—			(47,894		)
	Unrecovered amount	(10,647		)	(12,014		)
	Interest expense	10,443			12,373
	Ending QF liability	$	136,448		$	136,652
Schedule of Estimated Gross Contractual Obligation Less Amounts Recoverable Through Rates	'
	The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands):
		Gross			Recoverable			Net
		Obligation			Amounts
	2014	$	67,283		$	56,025		$	11,258
	2015	69,606			56,598			13,008
	2016	71,598			57,188			14,410
	2017	73,622			57,789			15,833
	2018	75,688			58,401			17,287
	Thereafter	724,574			567,215			157,359
	Total	$	1,082,371		$	853,216		$	229,155

Segment_and_Related_Informatio1

Segment and Related Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Schedule of Segment Reporting Information, by Segment	'
	Financial data for the business segments are as follows (in thousands):
	December 31, 2013	Electric			Gas			Other			Eliminations		Total
	Operating revenues	$	865,239		287,605			$	1,675		$	—	$	1,154,519
	Cost of sales	358,688			120,858			—			—		479,546
	Gross margin	506,551			166,747			1,675			—		674,973
	Operating, general and administrative	195,100			78,822			11,647			—		285,569
	Property and other taxes	78,536			26,993			11			—		105,540
	Depreciation	89,728			23,070			33			—		112,831
	Operating income (loss)	143,187			37,862			(10,016		)	—		171,033
	Interest expense	(57,920		)	(9,993		)	(2,573		)	—		(70,486		)
	Other income	4,061			1,239			2,437			—		7,737
	Income tax (expense) benefit	(13,905		)	(4,134		)	3,738			—		(14,301		)
	Net income (loss)	$	75,423		$	24,974		$	(6,414	)	$	—	$	93,983
	Total assets	$	2,583,554		$	1,117,861		$	13,845		$	—	$	3,715,260
	Capital expenditures	$	198,032		$	32,422		$	—		$	—	$	230,454
	December 31, 2012	Electric			Gas			Other			Eliminations		Total
	Operating revenues	$	805,554		$	263,394		$	1,394		$	—	$	1,070,342
	Cost of sales	277,826			117,608			—			—		395,434
	Gross margin	527,728			145,786			1,394			—		674,908
	Operating, general and administrative	187,599			75,971			6,396			—		269,966
	MSTI impairment	24,039			—			—			—		24,039
	Property and other taxes	72,755			24,907			12			—		97,674
	Depreciation	86,559			19,452			33			—		106,044
	Operating income (loss)	156,776			25,456			(5,047		)	—		177,185
	Interest expense	(55,118		)	(9,063		)	(881		)	—		(65,062		)
	Other income	2,630			1,633			109			—		4,372
	Income tax (expense) benefit	(22,298		)	(692		)	4,901			—		(18,089		)
	Net income (loss)	$	81,990		$	17,334		$	(918	)	$	—	$	98,406
	Total assets	$	2,442,602		$	1,032,259		$	10,672		$	—	$	3,485,533
	Capital expenditures	$	178,325		$	40,909		$	—		$	—	$	219,234
	December 31, 2011	Electric			Gas			Other			Eliminations		Total
	Operating revenues	$	797,562		$	318,335		$	1,419		$	—	$	1,117,316
	Cost of sales	327,126			167,433			—			—		494,559
	Gross margin	470,436			150,902			1,419			—		622,757
	Operating, general and administrative	183,503			80,431			3,226			—		267,160
	Property and other taxes	66,425			22,686			11			—		89,122
	Depreciation	81,859			19,034			33			—		100,926
	Operating income (loss)	138,649			28,751			(1,851		)	—		165,549
	Interest expense	(54,394		)	(10,432		)	(2,033		)	—		(66,859		)
	Other income	2,563			1,258			110			—		3,931
	Income tax (expense) benefit	(14,049		)	(3,472		)	7,456			—		(10,065		)
	Net income	$	72,769		$	16,105		$	3,682		$	—	$	92,556
	Total assets	$	2,259,189		$	938,876		$	12,373		$	—	$	3,210,438
	Capital expenditures	$	146,576		$	42,154		$	—		$	—	$	188,730

Quarterly_Financial_Data_Unaud1

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Schedule of Quarterly Financial Information	'
	Amounts presented are in thousands, except per share data:
	2013	First		Second		Third			Fourth
	Operating revenues	$	313,020	$	260,161	$	262,248		$	319,090
	Operating income	57,010		32,660		31,401			49,962
	Net income	$	37,902	$	14,341	$	15,647		$	26,093
	Average common shares outstanding	37,384		38,092		38,459			38,626
	Income per average common share (basic):
	Net income	$	1.01	$	0.37	$	0.41		$	0.67
	Income per average common share (diluted):
	Net income	$	1.01	$	0.37	$	0.4		$	0.68
	Dividends per share	$	0.38	$	0.38	$	0.38		$	0.38
	Stock price:
	High	$	40.35	$	43.17	$	45.85		$	47.18
	Low	35.06		38.12		39.08			41.31
	Quarter-end close	39.86		39.9		44.92			43.32
	2012	First		Second		Third			Fourth
	Operating revenues	$	309,100	$	244,603	$	235,866		$	280,773
	Operating income	55,033		28,720		4,409			89,024
	Net income (loss)	$	32,043	$	11,438	$	(3,772	)	$	58,697
	Average common shares outstanding	36,328		36,635		37,201			37,218
	Income per average common share (basic):
	Net income (loss)	$	0.88	$	0.31	$	(0.10	)	$	1.58
	Income per average common share (diluted):
	Net income (loss)	$	0.88	$	0.31	$	(0.10	)	$	1.57
	Dividends per share	$	0.37	$	0.37	$	0.37		$	0.37
	Stock price:
	High	$	36.39	$	37.05	$	37.96		$	36.7
	Low	34.22		33.72		35.44			32.98
	Quarter-end close	35.46		36.7		36.23			34.73

Nature_of_Operations_and_Basis2

Nature of Operations and Basis of Consolidation (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	watts
	customers
Number of customers	678,200	'	'
Number of megawatts of qualifying facility	35	'	'
Estimated aggregate gross contractual payments through 2024	$286.20	'	'
Variable interest entity, measure of activity, purchases	$23.80	$21	$18.40

Significant_Accounting_Policie3

Significant Accounting Policies Inventory (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accounting Policies [Abstract]	'	'
Materials and supplies	$28,263	$25,094
Storage gas and fuel	27,346	29,067
Total	$55,609	$54,161

Significant_Accounting_Policie4

Significant Accounting Policies Property plant equipment (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Line Items]	'	'	'
Interest costs, capitalized during period	$8.20	$7.90	$3.10
Contributions in aid of construction	$6.30	$5	'
Property, plant and equipment, disclosure of composite depreciation rate for plants in service	3.20%	3.30%	3.30%
Montana	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'
Allowance for funds used during construction, rate	8.10%	8.00%	7.90%
South Dakota	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'
Allowance for funds used during construction, rate	8.10%	8.00%	7.80%

Significant_Accounting_Policie5

Significant Accounting Policies Other Noncurrent Liabilities (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accounting Policies [Abstract]	'	'
Pension and other employee benefits	$57,140	$148,384
Future QF obligation, net	136,448	136,652
Environmental	28,194	30,189
Customer advances	27,371	34,681
Other	43,471	25,148
Total	$292,624	$375,054

Significant_Accounting_Policie6

Significant Accounting Policies Supplemental Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'
Income taxes, cash paid (received)	$50	$2,944	($1,219)
Interest, cash paid (received)	57,789	51,271	52,328
Capital expenditures included in trade accounts payable	$12,025	$13,136	$10,910

Significant_Accounting_Policie7

Significant Accounting Policies Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	days
Allowance for doubtful accounts receivable, current	$4,500,000	$3,200,000
Unbilled receivables,current	74,300,000	71,400,000
Restricted cash	6,896,000	6,700,000
Number of days or less of maturity to be considered cash equivalent	90	'
Risk Partners Assurance LTD [Member]	'	'
Restricted cash	$2,700,000	$3,800,000

Acquisitions_and_Significant_E1

Acquisitions and Significant Events Hydro-electric (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 26, 2013
		days
		watts
Hydro-electric Assets [Member]	'	'
Significant Acquisitions and Disposals [Line Items]	'	'
Megawatts of generation	'	633
Purchase price	'	$900
Owned average load serving requirement	'	60.00%
Bridge term loan facility	'	900
Bridge term loan facility agreement term	'	364
Transaction costs	4.4	'
Debt related commitment fees	1.9	'
Kerr Project [Member]	'	'
Significant Acquisitions and Disposals [Line Items]	'	'
Purchase price	'	$30

Acquisitions_and_Significant_E2

Acquisitions and Significant Events Oil and Gas (Details) (Montana Natural Gas Production Assets [Member], USD $)	1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
	MMcf
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'
Acquisition of oil and gas properties with proved reserves	$68.70
Proved developed reserves (volume) associated with acquisition	57.5
Estimated increase in oil and gas production	24.00%
Percent owned oil and gas production	32.00%
Havre Pipeline Company, LLC [Member]	'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'
Acquisition of oil and gas properties with proved reserves	$6

Acquisitions_and_Significant_E3

Acquisitions and Significant Events MSTI Impairment (Details) (USD $)	12 Months Ended			3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 30, 2012
				Mountain States Transmission [Member]
				watts
Long-Lived Assets to be Abandoned [Line Items]	'	'	'	'
Megawatts of capacity	'	'	'	1,500
Mountain States Transmission Intertie impairment	$0	$24,039	$0	$24,000

Colstrip_Energy_Limited_Partne

Colstrip Energy Limited Partnership (CELP) (Details) (USD $)	12 Months Ended			3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012
				Colstrip Energy Limited Partnership Rate Dispute [Member]
				watts
Contractual Settlements [Line Items]	'	'	'	'
Long-term Purchase Commitment, Minimum Quantity Required	'	'	'	306,600
Gain on CELP arbitration decision	$0	$47,894	$0	$47,900

Regulatory_Matters_Details

Regulatory Matters (Details) (USD $)	Dec. 31, 2013	Jun. 30, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Sep. 26, 2013
In Millions, unless otherwise specified		Dave Gates Generating Station [Member]	Demand-side management (DSM) lost revenues [Member]	Demand-side management (DSM) lost revenues [Member]	Revenue Subject to Refund [Member]	Revenue Subject to Refund [Member]	Deferred Revenue Related To Tracker Period 2012-2013 [Member]	Deferred Revenue Related To Tracker Period 2013-2014 [Member]	Hydro-electric Assets [Member]	Hydro-electric Assets [Member]
					Dave Gates Generating Station [Member]	Montana Natural Gas Production Assets [Member]	Demand-side management (DSM) lost revenues [Member]	Demand-side management (DSM) lost revenues [Member]
Regulatory Assets [Line Items]	'	'	'	'	'	'	'	'	'	'
Purchase price	'	'	'	'	'	'	'	'	'	$900
Return on equity	'	'	'	'	'	'	'	'	10.00%	'
Capitalized structure, percentage of equity	'	'	'	'	'	'	'	'	48.00%	'
Capitalized structure, percentage of debt	'	'	'	'	'	'	'	'	52.00%	'
Estimated rate base, Hydro Electric	'	'	'	'	'	'	'	'	866	'
Customer refund liability, current	'	'	'	'	24.5	7	'	'	'	'
Deferred revenue recognized	'	'	3.8	1.9	'	'	7.1	3.6	'	'
Demand side management lost revenue expected recovery	7.1	'	'	'	'	'	'	'	'	'
Disallowed costs for rate making purposes	'	$1.40	'	'	'	'	'	'	'	'

Regulatory_Assets_and_Liabilit2

Regulatory Assets and Liabilities (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory Assets [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	$354,671	$408,191
Regulatory Assets [Member] | Pension [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	58,474	143,672
Regulatory Assets [Member] | Employee related benefits [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	17,700	20,911
Regulatory Assets [Member] | Distribution infrastructure projects	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	12,543	15,679
Regulatory assets, remaining amortization period	'P4Y	'
Regulatory Assets [Member] | Environmental clean-up [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	14,924	16,497
Regulatory Assets [Member] | Supply costs [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	17,875	11,788
Regulatory assets, remaining amortization period	'P1Y	'
Regulatory Assets [Member] | Energy supply derivatives [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	0	5,428
Regulatory assets, remaining amortization period	'P1Y	'
Regulatory Assets [Member] | Income taxes [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	201,808	162,154
Regulatory Assets [Member] | Deferred financing costs [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	13,919	13,944
Regulatory Assets [Member] | State And Local Taxes And Fees [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	6,582	8,337
Regulatory Assets [Member] | Other [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory assets	10,846	9,781
Regulatory Liabilities [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory liabilities	394,459	325,043
Regulatory Liabilities [Member] | Removal cost	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory liabilities	336,613	264,486
Regulatory Liabilities [Member] | Gas storage sales	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory liabilities	10,831	11,251
Regulatory liability, remaining amortization period	'P26Y	'
Regulatory Liabilities [Member] | Supply costs [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory liabilities	11,493	17,591
Regulatory liability, remaining amortization period	'P1Y	'
Regulatory Liabilities [Member] | Deferred revenue [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory liabilities	33,400	26,259
Regulatory liability, remaining amortization period	'P1Y	'
Regulatory Liabilities [Member] | Environmental clean-up [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory liabilities	1,194	1,395
Regulatory liability, remaining amortization period	'Various	'
Regulatory Liabilities [Member] | State And Local Taxes And Fees [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory liabilities	551	537
Regulatory liability, remaining amortization period	'P1Y	'
Regulatory Liabilities [Member] | Other [Member]	'	'
Regulatory Assets And Liabilities [Line Items]	'	'
Regulatory liabilities	$377	$3,524

Regulatory_Assets_and_Liabilit3

Regulatory Assets and Liabilities Narrative (Details)	12 Months Ended
	Dec. 31, 2013
State And Local Taxes And Fees [Member]	'
Regulatory Assets And Liabilities [Line Items]	'
Percentage of estimated increase in local taxes and fees authorized for recovery by MPSC	60.00%
Electric Supply Costs [Member] | South Dakota	'
Regulatory Assets And Liabilities [Line Items]	'
Percentage of interest earned on electric and natural gas supply costs	10.60%
Natural Gas Supply Costs [Member] | South Dakota	'
Regulatory Assets And Liabilities [Line Items]	'
Percentage of interest earned on electric and natural gas supply costs	7.80%
Natural Gas Supply Costs [Member] | Nebraska	'
Regulatory Assets And Liabilities [Line Items]	'
Percentage of interest earned on electric and natural gas supply costs	8.50%
Supply costs [Member] | Montana	'
Regulatory Assets And Liabilities [Line Items]	'
Percentage of interest earned on electric and natural gas supply costs	7.50%
Regulatory Assets [Member]	'
Regulatory Assets And Liabilities [Line Items]	'
Required percentage of disclosure coverage of regulatory assets and liabilites	97.00%
Regulatory Liabilities [Member]	'
Regulatory Assets And Liabilities [Line Items]	'
Required percentage of disclosure coverage of regulatory assets and liabilites	93.00%

Property_Plant_and_Equipment_D

Property, Plant and Equipment (Details) (USD $)

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, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Land and improvements [Member]

Land and improvements [Member]

Building and improvements [Member]

Building and improvements [Member]

Tranmission, distribution and storage[Member]

Tranmission, distribution and storage[Member]

Generation [Member]

Generation [Member]

Plant Acquisition adjustment [Member]

Other [Member]

Other [Member]

Basin Capital Lease [Member]

Basin Capital Lease [Member]

Minimum [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Property, Plant and Equipment [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Land, land rights and easements

$128,123,000

$72,550,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Buildings and improvements

163,852,000

145,989,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Transmission, distribution and storage

2,448,821,000

2,339,111,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Generation

533,450,000

506,017,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Plant acquisition adjustment

204,754,000

204,754,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Other

308,345,000

259,308,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Construction work in progress

104,891,000

121,360,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Property, plant and equipment, gross

3,892,236,000

3,649,089,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Less accumulated depreciation

-1,202,108,000

-1,213,499,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Property, plant, and equipment, net

2,690,128,000

2,435,590,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Useful Life

'

'

'54 years

'96 years

'27 years

'64 years

'15 years

'85 years

'25 years

'50 years

'34 years

'2 years

'45 years

'

'

Property, plant, and equipment under capiltal leases

$25,600,000

$27,700,000

'

'

'

'

'

'

'

'

'

'

'

$25,100,000

$27,100,000

Property_Plant_and_Equipment_J

Property, Plant and Equipment Joint Ownership (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Jointly Owned Utility Plant Interests [Line Items]	'	'
Number of joint ownership interests in electric generating plants	4	'
Big Stone Generating Facility [Member]	'	'
Jointly Owned Utility Plant Interests [Line Items]	'	'
Ownership percentages	23.40%	23.40%
Plant in service	$61,186	$61,084
Accumulated depreciation	45,792	38,021
Neal 4 Generating Facility [Member]	'	'
Jointly Owned Utility Plant Interests [Line Items]	'	'
Ownership percentages	8.70%	8.70%
Plant in service	57,633	30,009
Accumulated depreciation	29,841	23,994
Coyote Generating Facility [Member]	'	'
Jointly Owned Utility Plant Interests [Line Items]	'	'
Ownership percentages	10.00%	10.00%
Plant in service	46,003	46,188
Accumulated depreciation	36,076	30,655
Colstrip Unit 4 [Member]	'	'
Jointly Owned Utility Plant Interests [Line Items]	'	'
Ownership percentages	30.00%	30.00%
Plant in service	290,163	290,607
Accumulated depreciation	$70,072	$67,534

Asset_Retirement_Obligation_Ro

Asset Retirement Obligation Rollforward (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'
Liability at January 1,	$9,283	$6,292
Accretion expense	745	473
Liabilities incurred	8,829	2,466
Liabilities settled	-27	-35
Revision to cash flows	2,056	87
Liability at Decembr 31,	$20,886	$9,283

Asset_Retirement_Obligation_Na

Asset Retirement Obligation Narrative (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Asset Retirement Obligation Disclosure [Abstract]	'	'
Accrued removal costs	$336.60	$264.50

Goodwill_Details

Goodwill (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Goodwill [Line Items]	'	'
Goodwill	$355,128	$355,128
Goodwill, Period Increase (Decrease)	0	0
Electric	'	'
Goodwill [Line Items]	'	'
Goodwill	241,100	241,100
Natural gas	'	'
Goodwill [Line Items]	'	'
Goodwill	$114,028	$114,028

Risk_Management_and_Hedging_Ac2

Risk Management and Hedging Activities (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
			Interest Rate Swap [Member]	Interest Rate Swap [Member]	Commodity Contract [Member]	Commodity Contract [Member]	Commodity Contract [Member]	Commodity Contract [Member]	Commodity Contract [Member]
			Interest Expense [Member]	Cash Flow Hedging [Member]	Forward Contracts [Member]	Forward Contracts [Member]	Forward Contracts [Member]	Forward Contracts [Member]	Forward Contracts [Member]
						Not Designated as Hedging Instrument [Member]	Not Designated as Hedging Instrument [Member]	Not Designated as Hedging Instrument [Member]	Not Designated as Hedging Instrument [Member]
								Accrued Liabilities [Member]	Accrued Liabilities [Member]
Derivative [Line Items]	'	'	'	'	'	'	'	'	'
Physical purchase and sale of gas and electricity at fixed prices	$0	$0	'	'	'	'	'	'	'
Natural gas net derivative liability	'	'	'	'	'	'	'	0	5,428,000
Natural gas, unrealized gain recognized in regulatory assets	'	'	'	'	'	5,428,000	14,884,000	'	'
Interest rate contracts, amount of gain reclassified from AOCI into income	'	'	1,188,000	'	'	'	'	'	'
Pre-tax gain on cash flow hedges remaining in AOCI	'	'	'	5,700,000	'	'	'	'	'
Pre-tax gain on cash flow hedge from AOCI to be reclassified during next 12 months	'	'	'	1,200,000	'	'	'	'	'
No swaps outstanding, interest rate fair value derivatives	0	0	'	'	'	'	'	'	'
None of the forward purchase contracts that do not qualify for NPNS contain credit risk-related contingent features	'	'	'	'	$0	'	'	'	'

Fair_Value_Measurements_Fair_V

Fair Value Measurements Fair Value Recurring Basis (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Level 1 to level 2 asset transfers, amount	$0	$0
Level 2 to level 1 assets, transfers, amount	0	0
Level 1 to level 2 liabilities transfers, amount	0	0
Level 2 to level 1 liabilities, transfers, amount	0	0
Fair Value, Measurements, Recurring [Member] | Total Net Fair Value [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Restricted cash	6,650	6,392
Rabbi trust investments	16,477	10,522
Derivative liability (1)	'	-5,428	[1]
Total	23,127	11,486
Fair Value, Measurements, Recurring [Member] | Quoted Prices In Active Markets for Identical Assets or Liabilities, Level 1 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Restricted cash	6,650	6,392
Rabbi trust investments	16,477	10,522
Derivative liability (1)	'	0	[1]
Total	23,127	16,914
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs, Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Restricted cash	0	0
Rabbi trust investments	0	0
Derivative liability (1)	'	-5,428	[1]
Total	0	-5,428
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs, Level 3 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Restricted cash	0	0
Rabbi trust investments	0	0
Derivative liability (1)	'	0	[1]
Total	0	0
Fair Value, Measurements, Recurring [Member] | Margin Cash Collateral Offset [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Restricted cash	0	0
Rabbi trust investments	0	0
Derivative liability (1)	'	0	[1]
Total	$0	$0
[1]	The changes in the fair value of these derivatives are deferred as a regulatory asset or liability until the contracts are settled. Upon settlement, associated proceeds or costs are passed through the applicable cost tracking mechanism to customers.

Fair_Value_Measurements_Fair_V1

Fair Value Measurements Fair Value Financial Instruments (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term debt, carrying value	$1,155,097	$1,055,074
Long-term debt, fair value	$1,237,151	$1,229,233

ShortTerm_Borrowings_and_Credi2

Short-Term Borrowings and Credit Arrangements (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Short-term Debt [Line Items]	'	'
Commercial Paper, Balance	$140,950,000	$122,934,000
Maximum borrowing capacity under commercial paper program	250,000,000	'
Short term borrowings maximum days outstanding	'270 days	'
Short-term Debt [Member]	'	'
Short-term Debt [Line Items]	'	'
Commercial Paper, Balance	141,000,000	122,900,000
Commercial Paper, Interest Rate	0.41%	0.53%
Maximum short-term debt outstanding	199,900,000	166,900,000
Average short-term debt outstanding	$69,000,000	$78,900,000
Weighted average interest rate	0.40%	0.48%

ShortTerm_Borrowings_and_Credi3

Short-Term Borrowings and Credit Arrangements Unsecured Revolving Line of Credit (Details) (Unsecured Revolving Line Of Credit [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
	numberofbanks
Line of Credit Facility [Line Items]	'	'
Current borrowing capacity	$300	'
Maximum borrowing capacity	350	'
Number of institutions participating in the credit facility	8	'
Maximum number of institutions participating in the credit faciltiy pertaining to maximum contributory percentage	1	'
Commitment fees	0.5	0.5
Letters of credit outstanding, amount	$0	'
Maximum [Member]	'	'
Line of Credit Facility [Line Items]	'	'
Maximum percentage of total availability provided by a single lender	16.00%	'
Maximum ratio of indebtedness to net capital threshold percentage	65.00%	'
Eurodollar [Member] | Minimum [Member]	'	'
Line of Credit Facility [Line Items]	'	'
Basis spread on variable rate	0.88%	'
Eurodollar [Member] | Maximum [Member]	'	'
Line of Credit Facility [Line Items]	'	'
Basis spread on variable rate	1.75%	'
Base Rate [Member] | Minimum [Member]	'	'
Line of Credit Facility [Line Items]	'	'
Basis spread on variable rate	0.00%	'
Base Rate [Member] | Maximum [Member]	'	'
Line of Credit Facility [Line Items]	'	'
Basis spread on variable rate	0.75%	'

ShortTerm_Borrowings_and_Credi4

Short-Term Borrowings and Credit Arrangements Bridge Loan (Details) (Bridge Loan [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Nov. 01, 2013
		days
Short-term Debt [Line Items]	'	'
Bridge term loan facility	'	$900
Bridge term loan facility agreement term	'	364
Commitment fees	$0.20	'
Eurodollar [Member] | Margin on credit spread [Member]	'	'
Short-term Debt [Line Items]	'	'
Basis spread on variable rate	1.25%	'
Eurodollar [Member] | Minimum [Member]	'	'
Short-term Debt [Line Items]	'	'
Basis spread on variable rate	0.88%	'
Eurodollar [Member] | Maximum [Member]	'	'
Short-term Debt [Line Items]	'	'
Basis spread on variable rate	1.75%	'
Base Rate [Member] | Margin on credit spread [Member]	'	'
Short-term Debt [Line Items]	'	'
Basis spread on variable rate	0.25%	'
Base Rate [Member] | Minimum [Member]	'	'
Short-term Debt [Line Items]	'	'
Basis spread on variable rate	0.00%	'
Base Rate [Member] | Maximum [Member]	'	'
Short-term Debt [Line Items]	'	'
Basis spread on variable rate	0.75%	'

LongTerm_Debt_and_Capital_Leas2

Long-Term Debt and Capital Leases Schedule of Debt (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'
Long-term debt	$1,155,097	$1,055,074
Less current maturities	0	0
Long-term debt, excluding current maturities	1,155,097	1,055,074
Capital Lease	'	'
Total Capital Leases	31,557	33,174
Less current maturities	-1,662	-1,612
Capital lease obligations, noncurrent	29,895	31,562
Unsecured Debt | Unsecured Revolving Line Of Credit	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	0	0
Maturity date	5-Nov-18	'
Secured Debt | South Dakota, 6.05%, Due 2018	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	55,000	55,000
Interest rate, stated percentage	6.05%	'
Maturity date	1-May-18	'
Secured Debt | South Dakota, 5.01%, Due 2025	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	64,000	64,000
Interest rate, stated percentage	5.01%	'
Maturity date	1-May-25	'
Secured Debt | South Dakota, 4.15%, Due 2042	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	30,000	30,000
Interest rate, stated percentage	4.15%	'
Maturity date	10-Aug-42	'
Secured Debt | South Dakota, 4.30%, Due 2052	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	20,000	20,000
Interest rate, stated percentage	4.30%	'
Maturity date	10-Aug-52	'
Secured Debt | South Dakota, 4.85% Due 2043	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	50,000	0
Interest rate, stated percentage	4.85%	'
Maturity date	19-Dec-43	'
Secured Debt | Montana, 6.04%, Due 2016	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	150,000	150,000
Interest rate, stated percentage	6.04%	'
Maturity date	1-Sep-16	'
Secured Debt | Montana, 6.34%, Due 2019	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	250,000	250,000
Interest rate, stated percentage	6.34%	'
Maturity date	1-Apr-19	'
Secured Debt | Montana, 5.71%, Due 2039	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	55,000	55,000
Interest rate, stated percentage	5.71%	'
Maturity date	15-Oct-39	'
Secured Debt | Montana, 5.01%, Due 2025	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	161,000	161,000
Interest rate, stated percentage	5.01%	'
Maturity date	1-May-25	'
Secured Debt | Montana, 4.15%, Due 2042	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	60,000	60,000
Interest rate, stated percentage	4.15%	'
Maturity date	10-Aug-42	'
Secured Debt | Montana, 4.30%, Due 2052	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	40,000	40,000
Interest rate, stated percentage	4.30%	'
Maturity date	10-Aug-52	'
Secured Debt | Montana 4.85%, Due 2043	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	15,000	0
Interest rate, stated percentage	4.85%	'
Maturity date	19-Dec-43	'
Secured Debt | Montana 3.99% Due 2028	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	35,000	0
Interest rate, stated percentage	3.99%	'
Maturity date	19-Dec-28	'
Secured Debt | Montana, 4.65%, Due 2023	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	170,205	170,205
Interest rate, stated percentage	4.65%	'
Maturity date	1-Aug-23	'
Unamortized Discount Premium, Net | Discount on Notes and Bonds	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	($108)	($131)

LongTerm_Debt_and_Capital_Leas3

Long-Term Debt and Capital Leases (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Maturities of Long-term Debt [Abstract]	'
2014	$1.70
2015	1.7
2016	151.8
2017	2
2018	$57.10

LongTerm_Debt_and_Capital_Leas4

Long-Term Debt and Capital Leases Schedule of Long-Term Debt (Details) (Secured Debt, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Secured Debt Montana and South Dakota due in 2028 and 2043 [Member]	'
Debt Instrument [Line Items]	'
Debt instrument, issuance date	19-Dec-13
Secured Debt Montana and South Dakota due 2043 [Member]	'
Debt Instrument [Line Items]	'
Debt instrument, face amount	65
Interest rate, stated percentage	4.85%
Maturity date	19-Dec-43
Secured Debt Montana Due 2028 [Member]	'
Debt Instrument [Line Items]	'
Debt instrument, face amount	35
Interest rate, stated percentage	3.99%
Maturity date	19-Dec-28

Income_Taxes_Narrative_Details

Income Taxes Narrative (Details) (Internal Revenue Service (IRS) [Member])	12 Months Ended
	Dec. 31, 2013
Internal Revenue Service (IRS) [Member]	'
Income Tax Contingency [Line Items]	'
Earliest year subject to examination	'2000

Income_Taxes_Domestic_Tax_Comp

Income Taxes Domestic Tax Components (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Federal	'	'	'
Current	$108	$5,358	($159)
Deferred	18,150	13,197	18,618
Investment tax credits	-335	-376	-424
State	'	'	'
Current	83	-1,411	-27
Deferred	-3,705	1,321	-7,943
Income tax expense (benefit)	$14,301	$18,089	$10,065

Income_Taxes_Effective_Rate_Re

Income Taxes Effective Rate Reconciliation (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Effective Income Tax Rate Reconciliation, Percent [Abstract]	'	'	'
Federal statutory rate	35.00%	35.00%	35.00%
State income, net of federal provisions	-2.80%	0.90%	-5.50%
Flow-through repair deduction	-16.40%	-14.00%	-13.10%
Production tax credits	-2.90%	0.00%	0.00%
Plant and depreciation of flow through items	-0.50%	-1.10%	-0.30%
Prior year permanent return to accrual adjustments	0.50%	-1.60%	-3.80%
Recognition of state net operating loss benefit / valuation allowance release	0.00%	-2.10%	-2.30%
Other, net	0.30%	-1.60%	-0.20%
Effective income tax rate	13.20%	15.50%	9.80%
Significant differences from Federal Statutory rate [Abstract]	'	'	'
Income (Loss) Before Income Taxes	$108,284	$116,495	$102,621
Income tax calculated at 35% federal statutory rate	37,899	40,774	35,917
Permanent or flow through adjutsments [Abstract]	'	'	'
State income, net of federal provisions	-3,082	1,078	-5,673
Flow-through repairs deductions	-17,763	-16,350	-13,425
Production tax credits	-3,171	0	0
Plant and depreciation of flow through items	-584	-1,281	-264
Prior year permanent return to accrual adjustments	541	-1,901	-3,948
Recognition of state net operating loss benefit / valuation allowance release	0	-2,398	-2,402
Other, net	461	-1,833	-140
Total of reconciling items	-23,598	-22,685	-25,852
Income tax expense (benefit)	$14,301	$18,089	$10,065

Income_Taxes_Deferred_Tax_Liab

Income Taxes Deferred Tax Liability (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred Tax Assets, [Abstract]	'	'
Pension / postretirement benefits	$20,522	$59,098
Unbilled revenue	18,136	15,944
NOL carryforward	16,758	0
Reserves and accruals	12,097	12,457
Customer advances	10,781	13,660
Compensation accruals	10,409	11,303
AMT credit carryforwards	10,357	10,588
Environmental liability	9,026	9,701
Regulatory assets	7,248	0
Production tax credits	3,171	0
QF obligations	2,066	1,462
Property taxes	796	18,025
Deferred tax assets, regulatory liability	659	1,526
Other, net	2,827	3,539
Deferred Tax Asset	124,853	157,303
Deferred Tax Liabilities, [Abstract]	'	'
Excess tax depreciation	-304,071	-278,051
Goodwill amortization	-122,798	-118,313
Flow through depreciation	-79,016	-63,551
Regulatory assets	0	-24,173
Deferred Tax Liability	-505,885	-484,088
Deferred Tax Liability, net	($381,032)	($326,785)

Income_Taxes_Operating_Loss_De

Income Taxes Operating Loss (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Domestic Tax Authority [Member]	'
Operating Loss Carryforwards [Line Items]	'
NOL carryforward	$325.70
State and Local Jurisdiction [Member]	'
Operating Loss Carryforwards [Line Items]	'
NOL carryforward	243.5
Year 2025 [Member] | Domestic Tax Authority [Member]	'
Operating Loss Carryforwards [Line Items]	'
NOL carryforwards, subject to expiration	16.3
Year 2028 [Member] | Domestic Tax Authority [Member]	'
Operating Loss Carryforwards [Line Items]	'
NOL carryforwards, subject to expiration	95.5
Year 2029 [Member] | Domestic Tax Authority [Member]	'
Operating Loss Carryforwards [Line Items]	'
NOL carryforwards, subject to expiration	23.8
Year 2031 [Member] | Domestic Tax Authority [Member]	'
Operating Loss Carryforwards [Line Items]	'
NOL carryforwards, subject to expiration	127.5
Year 2033 [Member] | Domestic Tax Authority [Member]	'
Operating Loss Carryforwards [Line Items]	'
NOL carryforwards, subject to expiration	62.6
Year 2015 [Member] | State and Local Jurisdiction [Member]	'
Operating Loss Carryforwards [Line Items]	'
NOL carryforwards, subject to expiration	74
Year 2016 [Member] | State and Local Jurisdiction [Member]	'
Operating Loss Carryforwards [Line Items]	'
NOL carryforwards, subject to expiration	18.6
Year 2018 [Member] | State and Local Jurisdiction [Member]	'
Operating Loss Carryforwards [Line Items]	'
NOL carryforwards, subject to expiration	101.2
Year 2020 [Member] | State and Local Jurisdiction [Member]	'
Operating Loss Carryforwards [Line Items]	'
NOL carryforwards, subject to expiration	$49.70

Income_Taxes_Uncertain_Tax_Pos

Income Taxes Uncertain Tax Positions (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Contingency [Line Items]	'	'	'
Unrecognized tax benefit more likely than not percentage threshold	50.00%	'	'
Unrecognized tax benefits that would impact effective tax rate	$79,000,000	$79,000,000	'
Interest and penalty expense	400,000	0	'
Accrual for interest and penalties	400,000	0	'
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'
Unrecognized Tax Benefits at January 1	113,291,000	131,949,000	120,859,000
Gross increases - tax positions in prior period	0	0	0
Gross decreases - tax positions in prior period	0	-1,766,000	-15,774,000
Gorss increases - tax positions in current period	518,000	2,391,000	26,864,000
Gross decreases - tax positions in current period	-343,000	-19,283,000	0
Unrecognized Tax Benefits at December 31	$113,466,000	$113,291,000	$131,949,000

Other_Comprehensive_Loss_Incom2

Other Comprehensive (Loss) Income (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Comprehensive Loss, Before Tax [Abstract]	'	'	'
Foreign currency translation adjustment	$166	($54)	$25
Reclassification of net gains on derivative instruments to net income	-1,188	-1,188	-1,188
Reclassification of deferred tax liability on net gains on derivative instruments	0	0	0
Pension and postretirement medical liability adjustment	1,568	-897	-736
Other comprehensive loss, before tax	546	-2,139	-1,899
Other Comprehensive Loss, Tax [Abstract]	'	'	'
Foreign currency translation adjustment	0	0	0
Reclassification of net gains on derivative instruments to net income	458	456	458
Reclassification of deferred tax liability on net gains on derivative instruments	0	0	-3,572
Pension and postretirement medical liability adjustment	-605	344	155
Other comprehensive loss, tax	-147	800	-2,959
Other Comprehensive Loss, Net of Tax [Abstract]	'	'	'
Foreign currency translation adjustment	166	-54	25
Reclassification of net gains on derivative instruments to net income	-730	-732	-730
Reclassification of deferred tax liability on net gains on derivative instruments	0	0	-3,572
Postretirement medical liability adjustment	963	-553	-581
Other comprehensive loss, net of tax	399	-1,339	-4,858
Accumulated Other Comprehensive Income, Net of Tax [Abstract]	'	'	'
Foreign currency translation	532	366	'
Derivative instruments designated as cash flow hedges	3,513	4,243	'
Pension and postretirement medical plans	-1,329	-2,292	'
Accumulated other comprehensive income	2,716	2,317	'
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]	'	'	'
Other Comprehensive Loss, Net of Tax [Abstract]	'	'	'
Foreign currency translation adjustment	0	'	'
Reclassification of net gains on derivative instruments to net income	-730	'	'
Postretirement medical liability adjustment	0	'	'
Other comprehensive loss, net of tax	-730	'	'
Accumulated Other Comprehensive Income, Net of Tax [Abstract]	'	'	'
Accumulated other comprehensive income	3,513	4,243	'
Accumulated Defined Benefit Plans Adjustment [Member]	'	'	'
Other Comprehensive Loss, Net of Tax [Abstract]	'	'	'
Foreign currency translation adjustment	0	'	'
Reclassification of net gains on derivative instruments to net income	0	'	'
Postretirement medical liability adjustment	963	'	'
Other comprehensive loss, net of tax	963	'	'
Accumulated Other Comprehensive Income, Net of Tax [Abstract]	'	'	'
Accumulated other comprehensive income	-1,329	-2,292	'
Foreign Currency Gain (Loss) [Member]	'	'	'
Other Comprehensive Loss, Net of Tax [Abstract]	'	'	'
Foreign currency translation adjustment	166	'	'
Reclassification of net gains on derivative instruments to net income	0	'	'
Postretirement medical liability adjustment	0	'	'
Other comprehensive loss, net of tax	166	'	'
Accumulated Other Comprehensive Income, Net of Tax [Abstract]	'	'	'
Accumulated other comprehensive income	$532	$366	'

Other_Comprehensive_Loss_Incom3

Other Comprehensive (Loss) Income Components of AOCI (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'	'	'
Beginning balance	$2,317	'	'
Other comprehensive income before reclassifications	166	-54	25
Reclassification of net gains on derivative instruments from OCI to net income, net of tax	-730	-732	-730
Amounts reclassified from accumulated other comprehensive income	963	-553	-581
Other comprehensive loss, net of tax	399	-1,339	-4,858
Ending balance	2,716	2,317	'
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]	'	'	'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'	'	'
Beginning balance	4,243	'	'
Other comprehensive income before reclassifications	0	'	'
Reclassification of net gains on derivative instruments from OCI to net income, net of tax	-730	'	'
Amounts reclassified from accumulated other comprehensive income	0	'	'
Other comprehensive loss, net of tax	-730	'	'
Ending balance	3,513	'	'
Accumulated Defined Benefit Plans Adjustment [Member]	'	'	'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'	'	'
Beginning balance	-2,292	'	'
Other comprehensive income before reclassifications	0	'	'
Reclassification of net gains on derivative instruments from OCI to net income, net of tax	0	'	'
Amounts reclassified from accumulated other comprehensive income	963	'	'
Other comprehensive loss, net of tax	963	'	'
Ending balance	-1,329	'	'
Foreign Currency Gain (Loss) [Member]	'	'	'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'	'	'
Beginning balance	366	'	'
Other comprehensive income before reclassifications	166	'	'
Reclassification of net gains on derivative instruments from OCI to net income, net of tax	0	'	'
Amounts reclassified from accumulated other comprehensive income	0	'	'
Other comprehensive loss, net of tax	166	'	'
Ending balance	$532	'	'

Operating_Leases_Details

Operating Leases (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]	'
2014	$1,655
2015	1,260
2016	796
2017	434
2018	$40

Operating_Leases_Narrative_Det

Operating Leases Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Leases [Abstract]	'	'	'
Lease and rental expense	$2	$2.20	$2.20

Employee_Benefit_Plans_Benefit

Employee Benefit Plans Benefit Obligation And Funded Status (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Plan, Defined Benefit [Member]	'	'
Change in Benefit Obligation:	'	'
Obligation beginning of period	$609,643,000	$536,536,000
Service cost	13,465,000	11,488,000
Interest cost	22,719,000	23,823,000
Actuarial (gain) loss	-54,671,000	59,071,000
Benefits paid	-23,290,000	-21,275,000
Benefit obligation end of period	567,866,000	609,643,000
Change in Fair Value of Plan Assets:	'	'
Benefits paid	-23,290,000	-21,275,000
Amounts recognized in balance sheet consist of:	'	'
Current liability	0	0
Noncurrent liability	-51,514,000	-136,707,000
Net amount recognized	-51,514,000	-136,707,000
Amounts recognized in AOCI consist of:	'	'
Prior service cost	0	0
Net actuarial gain	0	0
Total	-72,525,000	-161,604,000
Plans with Benefit Obligations in Excess of Plan Assets [Abstract]	'	'
Projected benefit obligation	567,900,000	609,600,000
Accumulated benefit obligation	565,000,000	606,200,000
Fair value of plan assets	516,400,000	472,900,000
Pension Plan, Defined Benefit [Member] | Pension Costs [Member]	'	'
Amounts recognized in regulatory assets consist of:	'	'
Prior service (cost) credit	-748,000	-994,000
Net actuarial loss	-71,777,000	-160,610,000
Pension Plan, Defined Benefit [Member] | Changes Measurement [Member]	'	'
Change in Benefit Obligation:	'	'
Benefits paid	-23,290,000	-21,275,000
Change in Fair Value of Plan Assets:	'	'
Fair value of plan assets at beginning of period	472,936,000	432,637,000
Return on plan assets	55,006,000	49,874,000
Employer contributions	11,700,000	11,700,000
Benefits paid	-23,290,000	-21,275,000
Fair value of plan assets at end of period	516,352,000	472,936,000
Funded Status	-51,514,000	-136,707,000
Other Postretirement Benefit Plan, Defined Benefit [Member]	'	'
Change in Benefit Obligation:	'	'
Obligation beginning of period	34,040,000	32,427,000
Service cost	541,000	541,000
Interest cost	877,000	1,167,000
Actuarial (gain) loss	-3,156,000	2,508,000
Benefits paid	-2,218,000	-2,603,000
Benefit obligation end of period	30,084,000	34,040,000
Change in Fair Value of Plan Assets:	'	'
Benefits paid	-2,218,000	-2,603,000
Amounts recognized in balance sheet consist of:	'	'
Current liability	-1,178,000	-1,082,000
Noncurrent liability	-10,723,000	-17,065,000
Net amount recognized	-11,901,000	-18,147,000
Amounts recognized in AOCI consist of:	'	'
Prior service cost	-1,302,000	-1,453,000
Net actuarial gain	-971,000	-2,432,000
Total	12,167,000	8,023,000
Other Postretirement Benefit Plan, Defined Benefit [Member] | Pension Costs [Member]	'	'
Amounts recognized in regulatory assets consist of:	'	'
Prior service (cost) credit	19,247,000	21,396,000
Net actuarial loss	-4,807,000	-9,488,000
Other Postretirement Benefit Plan, Defined Benefit [Member] | Changes Measurement [Member]	'	'
Change in Benefit Obligation:	'	'
Benefits paid	-2,218,000	-2,603,000
Change in Fair Value of Plan Assets:	'	'
Fair value of plan assets at beginning of period	15,893,000	15,502,000
Return on plan assets	2,662,000	1,789,000
Employer contributions	1,846,000	1,205,000
Benefits paid	-2,218,000	-2,603,000
Fair value of plan assets at end of period	18,183,000	15,893,000
Funded Status	($11,901,000)	($18,147,000)

Employee_Benefit_Plans_Net_Per

Employee Benefit Plans Net Periodic Costs (Details) (USD $)	12 Months Ended
In Thousands, 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	Dec. 31, 2014	Dec. 31, 2014
	Pension Plan, Defined Benefit [Member]	Pension Plan, Defined Benefit [Member]	Net Periodic Costs [Member]	Net Periodic Costs [Member]	Net Periodic Costs [Member]	Net Periodic Costs [Member]	Net Periodic Costs [Member]	Net Periodic Costs [Member]	Pension Costs [Member]	Pension Costs [Member]
			Pension Plan, Defined Benefit [Member]	Pension Plan, Defined Benefit [Member]	Pension Plan, Defined Benefit [Member]	Other Pension Plan, Postretirement or Supplemental Plans, Defined Benefit [Member]	Other Pension Plan, Postretirement or Supplemental Plans, Defined Benefit [Member]	Other Pension Plan, Postretirement or Supplemental Plans, Defined Benefit [Member]	Pension Plan, Defined Benefit [Member]	Other Pension Plan, Postretirement or Supplemental Plans, Defined Benefit [Member]
Components of Net Periodic Benefit Cost	'	'	'	'	'	'	'	'	'	'
Service cost	$13,465	$11,488	$13,465	$11,488	$10,199	$541	$541	$437	'	'
Interest cost	22,719	23,823	22,719	23,823	24,394	877	1,167	1,348	'	'
Expected return on plan assets	'	'	-32,491	-29,996	-30,462	-1,019	-1,021	-1,185	'	'
Amortization of prior service cost (credit)	'	'	246	246	246	-1,998	-1,998	-1,998	246	-1,998
Recognized actuarial loss	54,671	-59,071	11,648	8,646	2,516	1,271	790	658	'	'
Net Periodic Benefit Cost (Credit)	'	'	15,587	14,207	6,893	-328	-521	-740	'	'
Prior service cost (credit)	'	'	246	246	246	-1,998	-1,998	-1,998	246	-1,998
Accumulated gain	'	'	'	'	'	'	'	'	$2,226	$310

Employee_Benefit_Plans_Actuari

Employee Benefit Plans Actuarial Assumptions (Details)

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2014

Dec. 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

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

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

Participants

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Equity Securities [Member]

Equity Securities [Member]

Debt Securities [Member]

Debt Securities [Member]

Domestic [Member]

Domestic [Member]

Domestic [Member]

Domestic [Member]

Domestic [Member]

Domestic [Member]

Domestic [Member]

Domestic [Member]

Nonunion [Member]

Nonunion [Member]

Nonunion [Member]

Union [Member]

Union [Member]

Union [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Nonunion [Member]

Nonunion [Member]

Nonunion [Member]

Union [Member]

Union [Member]

Union [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Equity Securities [Member]

Equity Securities [Member]

Equity Securities [Member]

Equity Securities [Member]

Debt Securities [Member]

Debt Securities [Member]

Debt Securities [Member]

Debt Securities [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Pension Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Defined Benefit Plan, Target Plan Asset Allocations

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

35.00%

50.00%

65.00%

50.00%

30.00%

40.00%

50.00%

50.00%

60.00%

40.00%

40.00%

40.00%

Defined Benefit Plan, Target Plan Asset Allocations Range Maximum

'

5.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

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'

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'

'

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'

'

'

'

'

'

Defined Benefit Plan, Assets, Target Allocations [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

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'

'

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'

'

'

'

'

'

'

'

'

'

'

Number of members participating

'

800

'

'

'

'

'

'

'

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'

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'

'

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'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Discount rate

'

'

'

'

'

'

'

'

'

'

'

4.55%

3.55%

4.40%

4.75%

3.80%

4.55%

'

'

'

'

'

'

'

'

'

3.75%

2.25%

3.50%

4.20%

3.20%

4.30%

'

'

'

'

'

'

'

'

'

'

'

'

Expected rate of return on plan assets

5.80%

7.00%

7.00%

7.00%

7.25%

'

'

'

'

'

'

'

'

'

'

'

'

7.00%

7.00%

7.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term rate of increase in compensation levels

'

'

'

'

'

3.58%

3.58%

3.58%

3.50%

3.50%

3.50%

'

'

'

'

'

'

'

'

'

3.58%

3.58%

3.58%

3.50%

3.50%

3.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Health care cost trend rate assumed for current year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Health care cost trend rate decrease assumed for next fiscal year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Ultimate health care cost trend rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Year that rate reaches ultimate trend rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2029

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Employee_Benefit_Plans_Investm

Employee Benefit Plans Investment Strategy (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'
Target asset allocation allowable range of plus or minus	5.00%	'
Northwestern Energy Pension Plan Montana [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	100.00%	100.00%
Northwestern Pension Plan South Dakota [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	100.00%	100.00%
Northwestern Energy Health And Welfare [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	100.00%	100.00%
Cash and Cash Equivalents [Member] | Northwestern Energy Pension Plan Montana [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	0.00%	0.00%
Cash and Cash Equivalents [Member] | Northwestern Pension Plan South Dakota [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	0.10%	0.00%
Cash and Cash Equivalents [Member] | Northwestern Energy Health And Welfare [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	1.80%	3.40%
Debt Securities [Member] | Pension Plan, Defined Benefit [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation of investments by plan	65.00%	50.00%
Debt Securities [Member] | Pension Plan, Defined Benefit [Member] | Domestic [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation of investments by plan	60.00%	40.00%
Debt Securities [Member] | Pension Plan, Defined Benefit [Member] | International [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation of investments by plan	5.00%	10.00%
Debt Securities [Member] | Northwestern Energy Pension Plan Montana [Member] | Domestic [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	58.60%	39.50%
Debt Securities [Member] | Northwestern Energy Pension Plan Montana [Member] | International [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	4.90%	9.90%
Debt Securities [Member] | Northwestern Pension Plan South Dakota [Member] | Domestic [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	64.70%	38.30%
Debt Securities [Member] | Northwestern Pension Plan South Dakota [Member] | International [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	4.90%	10.60%
Debt Securities [Member] | Northwestern Energy Health And Welfare [Member] | Domestic [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	38.60%	37.80%
Debt Securities [Member] | Northwestern Energy Health And Welfare [Member] | International [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	0.30%	0.00%
Debt Securities [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | Domestic [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation of investments by plan	40.00%	40.00%
Debt Securities [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | International [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation of investments by plan	0.00%	0.00%
Equity Securities [Member] | Pension Plan, Defined Benefit [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation of investments by plan	35.00%	50.00%
Equity Securities [Member] | Pension Plan, Defined Benefit [Member] | Domestic [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation of investments by plan	30.00%	40.00%
Equity Securities [Member] | Pension Plan, Defined Benefit [Member] | International [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation of investments by plan	5.00%	10.00%
Equity Securities [Member] | Northwestern Energy Pension Plan Montana [Member] | Domestic [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	31.40%	40.20%
Equity Securities [Member] | Northwestern Energy Pension Plan Montana [Member] | International [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	5.10%	10.40%
Equity Securities [Member] | Northwestern Pension Plan South Dakota [Member] | Domestic [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	25.30%	40.60%
Equity Securities [Member] | Northwestern Pension Plan South Dakota [Member] | International [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	5.00%	10.50%
Equity Securities [Member] | Northwestern Energy Health And Welfare [Member] | Domestic [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	50.10%	49.80%
Equity Securities [Member] | Northwestern Energy Health And Welfare [Member] | International [Member]	'	'
Defined Benefit Plan, Actual Asset Allocations [Abstract]	'	'
Actual allocation of investments by plan	9.20%	9.00%
Equity Securities [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | Domestic [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation of investments by plan	50.00%	50.00%
Equity Securities [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | International [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation of investments by plan	10.00%	10.00%

Employee_Benefit_Plans_Fair_Va

Employee Benefit Plans Fair Value (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Cash and cash equivalents	$0		'		'
Available-for-sale securities	0		0		'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities [Member] | US Small Midcap Growth [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[1]	0	[1]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities [Member] | US Small Midcap Value [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[1]	0	[1]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities [Member] | US Large Cap Growth [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[1]	0	[1]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities [Member] | US Large Cap Value [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[1]	0	[1]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities [Member] | Non-US Core [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[1]	0	[1]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities [Member] | Emerging Markets [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[1]	0		'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Securities [Member] | US Large Cap Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[1]	0	[1]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Debt Securities [Member] | US Core [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[2]	0	[2]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Debt Securities [Member] | US Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[2]	0	[2]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Debt Securities [Member] | Long Duration [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[2]	0	[2]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Debt Securities [Member] | Long Duration Investment Grade [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0		0	[2]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Debt Securities [Member] | Long Duration Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[2]	0	[2]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Debt Securities [Member] | Opportunistic [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[2]	'		'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Debt Securities [Member] | Non-US Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[2]	0		'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Debt Securities [Member] | Active Long Corporate [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[2]	0		'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Debt Securities [Member] | Participating Group Annuity Contract [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[2]	0	[2]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Cash and cash equivalents	168		508		'
Available-for-sale securities	516,352		472,936		'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities [Member] | US Small Midcap Growth [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	13,764	[1]	16,229	[1]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities [Member] | US Small Midcap Value [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	13,664	[1]	16,297	[1]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities [Member] | US Large Cap Growth [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	42,094	[1]	49,811	[1]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities [Member] | US Large Cap Value [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	42,102	[1]	51,655	[1]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities [Member] | Non-US Core [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	20,015	[1]	36,358	[1]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities [Member] | Emerging Markets [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	6,250	[1]	12,713		'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Securities [Member] | US Large Cap Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	47,227	[1]	56,194	[1]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | Debt Securities [Member] | US Core [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	82,639	[2]	90,742	[2]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | Debt Securities [Member] | US Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	44,762	[2]	48,710	[2]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | Debt Securities [Member] | Long Duration [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	24,401	[2]	6,455	[2]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | Debt Securities [Member] | Long Duration Investment Grade [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	32,700		7,091	[2]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | Debt Securities [Member] | Long Duration Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	24,122		5,239	[2]	'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | Debt Securities [Member] | Opportunistic [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	5,876		'		'
Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member] | Debt Securities [Member] | Non-US Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	25,150	[2]	46,856	[2]	'
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	83,147	[2]	18,540		'
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[1]	0	[1]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Equity Securities [Member] | US Large Cap Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[1]	0	[1]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Debt Securities [Member] | Passive Bond Market [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[2]	0	[2]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Debt Securities [Member] | US Core [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[2]	0	[2]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Debt Securities [Member] | US Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[2]	0	[2]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Debt Securities [Member] | Long Duration [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0	[2]	0	[2]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Debt Securities [Member] | Long Duration Investment Grade [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0		0		'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Debt Securities [Member] | Long Duration Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0		0		'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Debt Securities [Member] | Opportunistic [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0		'		'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Debt Securities [Member] | Non-US Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0		0		'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Debt Securities [Member] | Active Long Corporate [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	0		0		'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Cash and cash equivalents	318		533		'
Available-for-sale securities	18,183		15,893		'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Equity Securities [Member] | US Small Midcap Growth [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	751	[1]	567	[1]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Equity Securities [Member] | US Small Midcap Value [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	736	[1]	567	[1]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Equity Securities [Member] | US Large Cap Growth [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	98	[1]	132	[1]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Equity Securities [Member] | US Large Cap Value [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	98	[1]	139	[1]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Equity Securities [Member] | Non-US Core [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	1,595	[1]	1,323	[1]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Equity Securities [Member] | Emerging Markets [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	85	[1]	108		'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Equity Securities [Member] | S&P 500 Index [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	7,321	[1]	6,360	[1]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Equity Securities [Member] | US Large Cap Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	110	[1]	151	[1]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Debt Securities [Member] | Passive Bond Market [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	1,880	[2]	1,205	[2]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Debt Securities [Member] | US Core [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	4,390	[2]	4,440	[2]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Debt Securities [Member] | US Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	107	[2]	138	[2]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Debt Securities [Member] | Long Duration [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	55	[2]	16	[2]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Debt Securities [Member] | Long Duration Investment Grade [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	79	[2]	21	[2]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Debt Securities [Member] | Long Duration Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	55	[2]	16	[2]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Debt Securities [Member] | Opportunistic [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	261	[2]	'		'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Debt Securities [Member] | Non-US Passive [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	57	[2]	124	[2]	'
Other Postretirement Benefit Plan, Defined Benefit [Member] | Estimate of Fair Value Measurement [Member] | Debt Securities [Member] | Active Long Corporate [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Available-for-sale securities	187	[2]	53	[2]	'
Defined Contribution Pension [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Defined Benefit Plan, Contributions by Employer	$7,800		$7,200		$6,700
[1]	This category consists of active and passive managed equity funds, which are invested in multiple strategies to diversify risks and reduce volatility.
[2]	This category consists of investment grade bonds of issuers from diverse industries, debt securities issued by international, national, state and local governments, and asset-backed securities. This includes both active and passive managed funds.

Employee_Benefit_Plans_Cash_Fl

Employee Benefit Plans Cash Flows (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension contributions	$11,700,000	$11,700,000	$11,700,000
Pension Plan, Defined Benefit [Member]	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Expected contributions to pension plans	10,200,000	'	'
Northwestern Energy Pension Plan Montana [Member]	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension contributions	10,500,000	10,500,000	10,500,000
Northwestern Pension Plan South Dakota [Member]	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Pension contributions	$1,200,000	$1,200,000	$1,200,000

Employee_Benefit_Plans_Estimat

Employee Benefit Plans Estimated Payments (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Pension Plan, Defined Benefit [Member]	'
Estimated Future Benefit Payments	'
2014	$26,648
2015	27,855
2016	29,850
2017	31,016
2018	32,472
2019-2023	182,212
Other Pension Plan, Postretirement or Supplemental Plans, Defined Benefit [Member]	'
Estimated Future Benefit Payments	'
2014	3,585
2015	3,494
2016	3,388
2017	3,237
2018	3,082
2019-2023	$12,107

Employee_Benefit_Plans_Narrati

Employee Benefit Plans Narrative (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Defined benefit plan percentage threshold of differences between actuarial assumptions and actual plan results that are greater than projected benefit or market value	10.00%	'	'
Defined Contribution Pension [Member]	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Employer contributions	$7,800	$7,200	$6,700

StockBased_Compensation_Detail

Stock-Based Compensation (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Number of shares available for grant	662,507	'	'
Compensation expense	$2.40	$2.80	$2.10
Compensation expense tax benefit	1.5	0.4	1.6
Compensation expense not yet recognized for nonvested awards	3	'	'
Nonvested awards, total compensation cost not yet recognized, period for recognition	'2 years 3 months 8 days	'	'
Shares vested in period, total fair value	2.2	2	2.9
Share-based Compensation, Significant Assumptions	'	'	'
Risk-free interest rate	0.44%	0.38%	'
Expected life, in years	'3 years	'3 years	'
Expected volatility, minimum	16.30%	20.20%	'
Expected volatility, maximum	25.40%	34.20%	'
Dividend yield	3.90%	4.10%	'
Deferred Stock Unit	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Maximum percentage of compensation to be deferred	100.00%	'	'
Maximum number of years for distribution payments	10	'	'
Deferred stock units issued during period, shares	33,837	31,801	31,032
Deferred stock units total compensation expense	$3.60	$0.90	$2.30
Performance Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Performance and vesting period	'3 years	'	'
Performance Shares [Member] | Minimum	'	'	'
Share-based Compensation, Significant Assumptions	'	'	'
Percent of shares issued based on company performance	0.00%	'	'
Performance Shares [Member] | Maximum	'	'	'
Share-based Compensation, Significant Assumptions	'	'	'
Percent of shares issued based on company performance	200.00%	'	'
Stock Compensation Plan [Member] | Minimum	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Performance and vesting period	'1 year	'	'
Stock Compensation Plan [Member] | Maximum	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Performance and vesting period	'5 years	'	'
Executive retirement/retention program [Member] | Restricted Stock [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Performance and vesting period	'5 years	'	'

StockBased_Compensation_Nonves

Stock-Based Compensation Nonvested (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013
Performance Shares [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]	'
Beginning nonvested grants (shares)	186,755
Granted (shares)	88,592
Vested (shares)	-100,402
Forfeited (shares)	-1,299
Remaining nonvested grants (shares)	173,646
Beginning nonvested (weighted-average grant date fair value)	$22.64
Granted (weighted-average grant date fair value)	$32.97
Vested (weighted-average grant date fair value)	$20.48
Forfeited (weighted-average grant date fair value)	$25.33
Remaining nonvested (weighted-average grant date fair value)	$29.14
Performance and vesting period	'3 years
Restricted Stock [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]	'
Beginning nonvested grants (shares)	1,000
Granted (shares)	2,500
Vested (shares)	-3,500
Forfeited (shares)	0
Remaining nonvested grants (shares)	0
Beginning nonvested (weighted-average grant date fair value)	$24.77
Granted (weighted-average grant date fair value)	$35.78
Vested (weighted-average grant date fair value)	$32.63
Forfeited (weighted-average grant date fair value)	$0
Remaining nonvested (weighted-average grant date fair value)	$0
Executive retirement/retention program [Member] | Restricted Stock [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]	'
Beginning nonvested grants (shares)	17,537
Granted (shares)	9,091
Vested (shares)	0
Forfeited (shares)	0
Remaining nonvested grants (shares)	26,628
Beginning nonvested (weighted-average grant date fair value)	$27.70
Granted (weighted-average grant date fair value)	$35.14
Vested (weighted-average grant date fair value)	$0
Forfeited (weighted-average grant date fair value)	$0
Remaining nonvested (weighted-average grant date fair value)	$30.24
Performance and vesting period	'5 years

Common_Stock_Common_Stock_Deta

Common Stock Common Stock (Details) (USD $)	12 Months Ended			3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2013	Jun. 30, 2012
				Equity Distribution Agreement [Member]	Equity Distribution Agreement [Member]	Equity Distribution Agreement [Member]
Class of Stock [Line Items]	'	'	'	'	'	'
Combined common and preferred stock, shares authorized	250,000,000	250,000,000	'	'	'	'
Common stock, shares authorized	200,000,000	200,000,000	'	'	'	'
Common stock, par or stated value per share	$0.01	$0.01	'	'	'	'
Preferred stock, shares authorized	50,000,000	50,000,000	'	'	'	'
Preferred stock, par or stated value per share	$0.01	$0.01	'	'	'	'
Common stock reserved for incentive plan awards	2,265,957	'	'	'	'	'
Common stock aggregate gross sales price, maximum	'	'	'	'	'	$100,000,000
Net proceeds from sale of stock	57,276,000	28,966,000	307,000	12,700,000	56,800,000	'
Sales commission and other fees	'	'	'	$129,000	'	'
Number of shares issued during the period under the Equity Distribution Agreement	'	'	'	278,914	1,381,494	'
Common stock average share price	'	'	'	$46.17	$41.61	'
Shares paid for tax withholding	34,552	22,789	'	'	'	'

Earnings_Per_Share_Details

Earnings Per Share (Details)

3 Months Ended

12 Months Ended

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

Basic computation

38,626,000

38,459,000

38,092,000

37,384,000

37,218,000

37,201,000

36,635,000

36,328,000

38,144,852

36,847,427

36,258,463

Restricted stock and performance share awards (1)

'

'

'

'

'

'

'

'

82,223

[1]

193,473

[1]

'

Diluted computation

'

'

'

'

'

'

'

'

38,227,075

37,040,900

'

[1]

Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.

Commitments_and_Contingencies_1

Commitments and Contingencies Qualifying Facilities Liability (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Ending QF liability	$136,448,000	$136,652,000
Qualifying Facility Contracts [Member]	'	'
Beginning QF liability	136,652,000	184,187,000
Gain on CELP arbitration decision	0	-47,894,000
Unrecovered amount	-10,647,000	-12,014,000
Interest expense	10,443,000	12,373,000
Ending QF liability	136,448,000	136,652,000
Qualifying Facility Contracts [Member] | Gross Obligation [Member]	'	'
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]	'	'
2014	67,283,000	'
2015	69,606,000	'
2016	71,598,000	'
2017	73,622,000	'
2018	75,688,000	'
Thereafter	724,574,000	'
Contractual obligation related to QF's	1,082,371,000	'
Qualifying Facility Contracts [Member] | Recoverable Amounts [Member]	'	'
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]	'	'
2014	56,025,000	'
2015	56,598,000	'
2016	57,188,000	'
2017	57,789,000	'
2018	58,401,000	'
Thereafter	567,215,000	'
Contractual obligation related to QF's	853,216,000	'
Qualifying Facility Contracts [Member] | Net Amount [Member]	'	'
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]	'	'
2014	11,258,000	'
2015	13,008,000	'
2016	14,410,000	'
2017	15,833,000	'
2018	17,287,000	'
Thereafter	157,359,000	'
Contractual obligation related to QF's	229,155,000	'
Qualifying Facility Contracts [Member] | Year 2029 [Member] | Gross Obligation [Member]	'	'
Recorded unconditional purchase obligation portion recoverable through rates	900,000,000	'
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]	'	'
Contractual obligation related to QF's	1,100,000,000	'
Qualifying Facility Contracts [Member] | Minimum [Member] | Year 2029 [Member]	'	'
Price per MWH of energy required to be purchased per QF agreement	74	'
Qualifying Facility Contracts [Member] | Maximum [Member] | Year 2029 [Member]	'	'
Price per MWH of energy required to be purchased per QF agreement	$136	'

Commitments_and_Contingencies_2

Commitments and Contingencies Long Term Supply and Capacity Purchase Obligations (Details) (Purchased Coal and Natural Gas Supply And Natural Gas Transportation Contracts [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Long-term Purchase Commitment [Line Items]	'	'	'
Long Term Purchase Committments Costs Incurred	$379,400,000	$340,800,000	$390,600,000
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]	'	'	'
2014	305,800,000	'	'
2015	202,600,000	'	'
2016	160,700,000	'	'
2017	136,700,000	'	'
2018	108,600,000	'	'
Thereafter	$1,143,400,000	'	'
Minimum [Member]	'	'	'
Long-term Purchase Commitment [Line Items]	'	'	'
Long Term Purchase Commitments Term In Years	'1 year	'	'
Maximum [Member]	'	'	'
Long-term Purchase Commitment [Line Items]	'	'	'
Long Term Purchase Commitments Term In Years	'28 years	'	'

Commitments_and_Contingencies_3

Commitments and Contingencies Environmental Liabilities (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jul. 01, 2018

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

In Millions, unless otherwise specified

Colstrip Unit 4 [Member]

Colstrip Unit 4 [Member]

Neal 4 Generating Facility [Member]

Neal 4 Generating Facility [Member]

Coyote Generating Facility [Member]

Coyote Generating Facility [Member]

Coyote Generating Facility [Member]

Big Stone Generating Facility [Member]

Big Stone Generating Facility [Member]

Environmental remediation obligations [Member]

Manufactured Gas Plants [Member]

Manufactured Gas Plants [Member]

Combined Manufacturing Sites [Member]

Aberdeen South Dakota Site [Member]

Environmental remediation obligation, minimum

'

'

'

'

'

'

'

'

'

$27.30

'

'

Environmental remediation obligation, maximum

'

'

'

'

'

'

'

'

'

35

'

'

Accrual for environmental loss contingencies

'

'

'

'

'

'

'

'

'

29.9

23.3

12

Environmental remediation obligation, to be incurred during next 5 years

'

'

'

'

'

'

'

'

'

'

'

9

Number of years for environmental remediation obligation to be incurred

'

'

'

'

'

'

'

'

'

'

'

'5 years

Environmental obligation, estimated capital expenditures

'

'

'

'

'

9

'

405

'

'

'

'

Jointly owned utility plant, proportionate ownership share

30.00%

30.00%

8.70%

8.70%

'

10.00%

10.00%

23.40%

23.40%

'

'

'

NOx emissions per million Btu

'

'

'

'

0.5

'

'

'

'

'

'

'

Capitalized costs, jointly owned utility plant

'

'

$22.60

'

'

'

'

$40.50

'

'

'

'

Segment_and_Related_Informatio2

Segment and Related Information (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, 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 Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Operating revenues	$319,090	$262,248	$260,161	$313,020	$280,773	$235,866	$244,603	$309,100	$1,154,519	$1,070,342	$1,117,316
Cost of sales	'	'	'	'	'	'	'	'	479,546	395,434	494,559
Gross margin	'	'	'	'	'	'	'	'	674,973	674,908	622,757
Operating, general and administrative	'	'	'	'	'	'	'	'	285,569	269,966	267,160
MSTI impairment	'	'	'	'	'	'	'	'	0	24,039	0
Property and other taxes	'	'	'	'	'	'	'	'	105,540	97,674	89,122
Depreciation	'	'	'	'	'	'	'	'	112,831	106,044	100,926
Operating Income	49,962	31,401	32,660	57,010	89,024	4,409	28,720	55,033	171,033	177,185	165,549
Interest expense	'	'	'	'	'	'	'	'	-70,486	-65,062	-66,859
Other income	'	'	'	'	'	'	'	'	7,737	4,372	3,931
Income tax (expense) benefit	'	'	'	'	'	'	'	'	-14,301	-18,089	-10,065
Net Income	26,093	15,647	14,341	37,902	58,697	-3,772	11,438	32,043	93,983	98,406	92,556
Total assets	3,715,260	'	'	'	3,485,533	'	'	'	3,715,260	3,485,533	3,210,438
Capital expenditures	'	'	'	'	'	'	'	'	230,454	219,234	188,730
Electric	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Operating revenues	'	'	'	'	'	'	'	'	865,239	805,554	797,562
Cost of sales	'	'	'	'	'	'	'	'	358,688	277,826	327,126
Gross margin	'	'	'	'	'	'	'	'	506,551	527,728	470,436
Operating, general and administrative	'	'	'	'	'	'	'	'	195,100	187,599	183,503
MSTI impairment	'	'	'	'	'	'	'	'	'	24,039	'
Property and other taxes	'	'	'	'	'	'	'	'	78,536	72,755	66,425
Depreciation	'	'	'	'	'	'	'	'	89,728	86,559	81,859
Operating Income	'	'	'	'	'	'	'	'	143,187	156,776	138,649
Interest expense	'	'	'	'	'	'	'	'	-57,920	-55,118	-54,394
Other income	'	'	'	'	'	'	'	'	4,061	2,630	2,563
Income tax (expense) benefit	'	'	'	'	'	'	'	'	-13,905	-22,298	-14,049
Net Income	'	'	'	'	'	'	'	'	75,423	81,990	72,769
Total assets	2,583,554	'	'	'	2,442,602	'	'	'	2,583,554	2,442,602	2,259,189
Capital expenditures	'	'	'	'	'	'	'	'	198,032	178,325	146,576
Gas	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Operating revenues	'	'	'	'	'	'	'	'	287,605	263,394	318,335
Cost of sales	'	'	'	'	'	'	'	'	120,858	117,608	167,433
Gross margin	'	'	'	'	'	'	'	'	166,747	145,786	150,902
Operating, general and administrative	'	'	'	'	'	'	'	'	78,822	75,971	80,431
MSTI impairment	'	'	'	'	'	'	'	'	'	0	'
Property and other taxes	'	'	'	'	'	'	'	'	26,993	24,907	22,686
Depreciation	'	'	'	'	'	'	'	'	23,070	19,452	19,034
Operating Income	'	'	'	'	'	'	'	'	37,862	25,456	28,751
Interest expense	'	'	'	'	'	'	'	'	-9,993	-9,063	-10,432
Other income	'	'	'	'	'	'	'	'	1,239	1,633	1,258
Income tax (expense) benefit	'	'	'	'	'	'	'	'	-4,134	-692	-3,472
Net Income	'	'	'	'	'	'	'	'	24,974	17,334	16,105
Total assets	1,117,861	'	'	'	1,032,259	'	'	'	1,117,861	1,032,259	938,876
Capital expenditures	'	'	'	'	'	'	'	'	32,422	40,909	42,154
Other Segments [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Operating revenues	'	'	'	'	'	'	'	'	1,675	1,394	1,419
Cost of sales	'	'	'	'	'	'	'	'	0	0	0
Gross margin	'	'	'	'	'	'	'	'	1,675	1,394	1,419
Operating, general and administrative	'	'	'	'	'	'	'	'	11,647	6,396	3,226
MSTI impairment	'	'	'	'	'	'	'	'	'	0	'
Property and other taxes	'	'	'	'	'	'	'	'	11	12	11
Depreciation	'	'	'	'	'	'	'	'	33	33	33
Operating Income	'	'	'	'	'	'	'	'	-10,016	-5,047	-1,851
Interest expense	'	'	'	'	'	'	'	'	-2,573	-881	-2,033
Other income	'	'	'	'	'	'	'	'	2,437	109	110
Income tax (expense) benefit	'	'	'	'	'	'	'	'	3,738	4,901	7,456
Net Income	'	'	'	'	'	'	'	'	-6,414	-918	3,682
Total assets	13,845	'	'	'	10,672	'	'	'	13,845	10,672	12,373
Capital expenditures	'	'	'	'	'	'	'	'	0	0	0
Eliminations	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Operating revenues	'	'	'	'	'	'	'	'	0	0	0
Cost of sales	'	'	'	'	'	'	'	'	0	0	0
Gross margin	'	'	'	'	'	'	'	'	0	0	0
Operating, general and administrative	'	'	'	'	'	'	'	'	0	0	0
MSTI impairment	'	'	'	'	'	'	'	'	'	0	'
Property and other taxes	'	'	'	'	'	'	'	'	0	0	0
Depreciation	'	'	'	'	'	'	'	'	0	0	0
Operating Income	'	'	'	'	'	'	'	'	0	0	0
Interest expense	'	'	'	'	'	'	'	'	0	0	0
Other income	'	'	'	'	'	'	'	'	0	0	0
Income tax (expense) benefit	'	'	'	'	'	'	'	'	0	0	0
Net Income	'	'	'	'	'	'	'	'	0	0	0
Total assets	0	'	'	'	0	'	'	'	0	0	0
Capital expenditures	'	'	'	'	'	'	'	'	$0	$0	$0

Quarterly_Financial_Data_Unaud2

Quarterly Financial Data (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except 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
Operating revenues	$319,090	$262,248	$260,161	$313,020	$280,773	$235,866	$244,603	$309,100	$1,154,519	$1,070,342	$1,117,316
Operating income	49,962	31,401	32,660	57,010	89,024	4,409	28,720	55,033	171,033	177,185	165,549
Net Income	$26,093	$15,647	$14,341	$37,902	$58,697	($3,772)	$11,438	$32,043	$93,983	$98,406	$92,556
Average Common Shares Outstanding	38,626,000	38,459,000	38,092,000	37,384,000	37,218,000	37,201,000	36,635,000	36,328,000	38,144,852	36,847,427	36,258,463
Income per average common share, (basic)	'	'	'	'	'	'	'	'	'	'	'
Net income (loss)	$0.67	$0.41	$0.37	$1.01	$1.58	($0.10)	$0.31	$0.88	$2.46	$2.67	$2.55
Income per average common share (diluted)	'	'	'	'	'	'	'	'	'	'	'
Net income (loss)	$0.68	$0.40	$0.37	$1.01	$1.57	($0.10)	$0.31	$0.88	$2.46	$2.66	$2.53
Dividends per share	$0.38	$0.38	$0.38	$0.38	$0.37	$0.37	$0.37	$0.37	$1.52	$1.48	$1.44
Quarter-end close	$43.32	$44.92	$39.90	$39.86	$34.73	$36.23	$36.70	$35.46	$43.32	$34.73	'
Maximum	'	'	'	'	'	'	'	'	'	'	'
Income per average common share (diluted)	'	'	'	'	'	'	'	'	'	'	'
Stock price	$47.18	$45.85	$43.17	$40.35	$36.70	$37.96	$37.05	$36.39	'	'	'
Minimum	'	'	'	'	'	'	'	'	'	'	'
Income per average common share (diluted)	'	'	'	'	'	'	'	'	'	'	'
Stock price	$41.31	$39.08	$38.12	$35.06	$32.98	$35.44	$33.72	$34.22	'	'	'

Quarterly_Financial_Data_Unaud3

Quarterly Financial Data (Unaudited) Narrative (Details) (Colstrip Energy Limited Partnership Rate Dispute [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012
Colstrip Energy Limited Partnership Rate Dispute [Member]	'
Effect of Fourth Quarter Events [Line Items]	'
Gain on CELP arbitration decision	$47.90