NorthWestern (NWE) 10-K 13 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 09, 2018	Jun. 30, 2016
Entity Information [Line Items]
Entity Registrant Name	NORTHWESTERN CORPORATION
Entity Central Index Key	73,088
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		49,397,196
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 2,957,686,000

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues
Electric	$ 1,037,053	$ 1,011,595	$ 944,428
Gas	268,599	245,652	269,871
Total Revenues	1,305,652	1,257,247	1,214,299
Operating Expenses
Cost of sales	410,349	400,973	372,864
Operating, general and administrative	305,137	302,893	297,475
Property and other taxes	162,614	148,098	133,442
Depreciation and depletion	166,137	159,336	144,702
Total Operating Expenses	1,044,237	1,011,300	948,483
Operating Income	261,415	245,947	265,816
Interest Expense, net	(92,263)	(94,970)	(92,153)
Other Income, net	6,919	5,548	7,583
Income Before Income Taxes	176,071	156,525	181,246
Income Tax (Expense) Benefit	(13,368)	7,647	(30,037)
Net Income	$ 162,703	$ 164,172	$ 151,209
Average Common Shares Outstanding	48,557,599	48,298,896	47,298,350
Basic Earnings per Average Common Share	$ 3.35	$ 3.40	$ 3.20
Diluted Earnings per Average Common Share	$ 3.34	$ 3.39	$ 3.17

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net Income	$ 162,703	$ 164,172	$ 151,209
Other comprehensive income (loss), net of tax:
Reclassification of net losses (gains) on derivative instruments	371	(1,338)	(698)
Postretirement medical liability adjustment	773	195	310
Foreign currency translation adjustment	(202)	25	558
Total Other Comprehensive Income (Loss)	942	(1,118)	170
Comprehensive Income	$ 163,645	$ 163,054	$ 151,379

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 8,473	$ 5,079
Restricted cash	3,556	4,426
Accounts receivable, net	182,282	159,556
Inventories	52,432	49,206
Regulatory assets	37,669	50,041
Other	11,947	11,887
Total current assets	296,359	280,195
Property, plant, and equipment, net	4,358,265	4,214,892
Goodwill	357,586	357,586
Regulatory assets	354,316	602,943
Other noncurrent assets	54,391	43,705
Total Assets	5,420,917	5,499,321
Current Liabilities:
Current maturities of capital leases	2,133	1,979
Short-term borrowings	319,556	300,811
Accounts payable	85,160	79,311
Accrued expenses	210,047	205,370
Regulatory liabilities	15,342	26,361
Total current liabilities	632,238	613,832
Long-term capital leases	22,213	24,346
Long-term debt	1,793,416	1,793,338
Deferred income taxes	340,729	575,582
Noncurrent regulatory liabilities	417,701	396,225
Other noncurrent liabilities	415,705	419,771
Total Liabilities	3,622,002	3,823,094
Commitments and Contingencies (Note 18)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 52,981,246 and 49,372,463, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	530	520
Treasury stock at cost	(96,376)	(95,769)
Paid-in capital	1,445,181	1,384,271
Retained earnings	458,352	396,919
Accumulated other comprehensive loss	(8,772)	(9,714)
Total Shareholders' Equity	1,798,915	1,676,227
Total Liabilities and Shareholders' Equity	$ 5,420,917	$ 5,499,321

CONSOLIDATED BALANCE SHEETS PAR

CONSOLIDATED BALANCE SHEETS PARENTHETICAL (Parentheticals) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
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	52,981,246	51,957,840
Common Stock, shares outstanding	49,372,463	48,331,675
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 CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
OPERATING ACTIVITIES:
Net Income	$ 162,703	$ 164,172	$ 151,209
Items not affecting cash:
Depreciation and depletion	166,137	159,336	144,702
Amortization of debt issue costs, discount and deferred hedge gain	4,794	2,117	2,258
Stock-based compensation costs	5,563	6,731	5,082
Equity portion of allowance for funds used during construction	(5,701)	(4,589)	(8,684)
Gain on disposition of assets	(415)	(15)	(20)
Deferred income taxes	12,363	(8,184)	33,886
Changes in current assets and liabilities:
Restricted cash	870	2,208	6,920
Accounts receivable	(22,726)	(5,146)	9,069
Inventories	(3,226)	4,252	1,636
Other current assets	827	(2,384)	5,514
Accounts payable	3,615	3,639	(11,169)
Accrued expenses	4,844	25,124	(22,738)
Regulatory assets	12,372	1,871	(3,974)
Regulatory liabilities	(11,019)	(54,629)	24,821
Other noncurrent assets	(14,780)	(7,311)	(5,584)
Other noncurrent liabilities	7,387	1,820	6,890
Cash Provided by Operating Activities	323,608	289,012	339,818
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(276,438)	(287,901)	(283,705)
Acquisitions	0	0	(146,668)
Proceeds from sale of assets	379	1,354	30,209
Change in restricted cash	0	0	16,108
Cash Used in Investing Activities	(276,059)	(286,547)	(384,056)
FINANCING ACTIVITIES:
Dividends on common stock	(101,270)	(95,765)	(90,058)
Proceeds from issuance of common stock, net	53,669	0	56,651
Issuance of long-term debt	250,000	249,660	270,000
Repayment of long-term debt	(250,000)	(225,205)	(150,025)
Issuances (repayments) of short-term borrowings, net	18,745	70,937	(37,966)
Treasury stock activity	1,083	(561)	(664)
Financing costs	(16,382)	(8,432)	(12,082)
Cash (Used In) Provided by Financing Activities	(44,155)	(9,366)	35,856
Net Increase (Decrease) in Cash and Cash Equivalents	3,394	(6,901)	(8,382)
Cash and Cash Equivalents, beginning of period	5,079	11,980	20,362
Cash and Cash Equivalents, end of period	$ 8,473	$ 5,079	$ 11,980

CONSOLIDATED STATEMENTS OF COMM

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Paid-in Capital	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Loss
Balance at Dec. 31, 2014	$ 1,477,783	$ 505	$ 1,313,844	$ (92,558)	$ 264,758	$ (8,766)
Shares, Balance at Dec. 31, 2014		50,522		3,607
Increase (Decrease) in Shareholders' Equity [Roll Forward]
Net Income	151,209	$ 0	0	$ 0	151,209	0
Foreign currency translation adjustment	558	0	0	0	0	558
Reclassification of net losses (gains) on derivative instruments from OCI to net income, net of tax	(698)	0	0	0	0	(698)
Postretirement medical liability adjustment, net of tax	310	0	0	0	0	310
Stock based compensation, value	2,489	$ 0	4,345	$ (1,856)	0	0
Stock based compensation, shares		167		10
Issuance of shares, value	58,581	$ 13	58,102		0	0
Issuance of shares, shares		1,100
Issuance of shares, value, treasury stock reissued				$ 466
Issuance of shares, shares, treasury stock reissued				0
Dividends on common stock	$ (90,058)	$ 0	0	$ 0	(90,058)	0
Dividends per share	$ 1.92
Balance at Dec. 31, 2015	$ 1,600,174	$ 518	1,376,291	$ (93,948)	325,909	(8,596)
Shares, Balance at Dec. 31, 2015		51,789		3,617
Increase (Decrease) in Shareholders' Equity [Roll Forward]
Net Income	164,172	$ 0	0	$ 0	164,172	0
Foreign currency translation adjustment	25	0	0	0	0	25
Reclassification of net losses (gains) on derivative instruments from OCI to net income, net of tax	(1,338)	0	0	0	0	(1,338)
Postretirement medical liability adjustment, net of tax	195	0	0	0	0	195
Stock based compensation, value	3,816	$ 0	6,690	$ (2,874)	0	0
Stock based compensation, shares		169		9
Issuance of shares, value	2,345	$ 2	1,290		0	0
Issuance of shares, shares		0
Issuance of shares, value, treasury stock reissued				$ 1,053
Issuance of shares, shares, treasury stock reissued				0
Dividends on common stock	$ (95,765)	$ 0	0	$ 0	(95,765)	0
Dividends per share	$ 2
Balance at Dec. 31, 2016	$ 1,676,227	$ 520	1,384,271	$ (95,769)	396,919	(9,714)
Shares, Balance at Dec. 31, 2016		51,958		3,626
Increase (Decrease) in Shareholders' Equity [Roll Forward]
Accounting standard adoption (1)	2,603	$ 0	0	$ 0	2,603	0
Net Income	162,703	0	0	0	162,703	0
Foreign currency translation adjustment	(202)	0	0	0	0	(202)
Reclassification of net losses (gains) on derivative instruments from OCI to net income, net of tax	371	0	0	0	0	(371)
Postretirement medical liability adjustment, net of tax	773	0	0	0	0	(773)
Stock based compensation, value	3,541		5,520	$ (1,979)	0	0
Stock based compensation, shares		134		0
Issuance of shares, value	56,772	$ 10	55,390		0	0
Issuance of shares, shares		889
Issuance of shares, value, treasury stock reissued				$ 1,372
Issuance of shares, shares, treasury stock reissued				(17)
Dividends on common stock	$ (101,270)	$ 0	0	$ 0	101,270	0
Dividends per share	$ 2.10
Balance at Dec. 31, 2017	$ 1,798,915	$ 530	$ 1,445,181	$ (96,376)	$ 458,352	$ (8,772)
Shares, Balance at Dec. 31, 2017		52,981		3,609

Nature of Operations and Basis

Nature of Operations and Basis of Consolidation	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations and Basis of Consolidation	(1) Nature of Operations and Basis of Consolidation NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and / or natural gas to approximately 718,300 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, 2017 , 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 $219.5 million through 2024 . For further discussion of our gross QF liability, see Note 18 - Commitments and Contingencies. During the years ended December 31, 2017 , 2016 and 2015 purchases from this QF were approximately $16.3 million , $25.5 million , and $24.3 million , respectively.

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Significant Accounting Policies	(2) 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, regulatory assets and liabilities, 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 electric 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 $2.9 million and $2.9 million at December 31, 2017 and December 31, 2016 , respectively. Receivables include unbilled revenues of $89.1 million and $80.4 million at December 31, 2017 and December 31, 2016 , respectively. Inventories Inventories are stated at average cost. Inventory consisted of the following (in thousands): December 31, 2017 2016 Materials and supplies $ 34,630 $ 31,602 Storage gas and fuel 17,802 17,604 Total Inventory $ 52,432 $ 49,206 Regulation of Utility Operations Our regulated operations are subject to the provisions of ASC 980, Regulated Operations. 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 deemed probable 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 Statements of Income 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 loss (AOCL) 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 are designated as normal purchases and normal sales 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 8 - 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. This rate averaged 7.2% , 7.2% , and 7.5% , for Montana and South Dakota for 2017 , 2016 , and 2015 , respectively. AFUDC capitalized totaled $8.5 million , $7.0 million , and $13.6 million for the years ended December 2017, 2016, and 2015, respectively, for Montana and South Dakota combined. 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 50 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 3.0% , 3.0% , and 3.3% for 2017 , 2016 , and 2015 , respectively. Depreciation rates include a provision for our share of the estimated costs to decommission our jointly owned plants at the end of the useful life. The annual provision for such costs is included in depreciation expense, while the accumulated provisions are included in noncurrent regulatory liabilities. Pension and Postretirement Benefits We have liabilities under defined benefit retirement plans and a postretirement plan that offers certain health care and life insurance benefits to eligible employees and their dependents. The costs of these plans are dependent upon numerous factors, assumptions and estimates, including determination of discount rate, expected return on plan assets, rate of future compensation increases, age and mortality and employment periods. In determining the projected benefit obligations and costs, assumptions can change from period to period and may result in material changes in the cost and liabilities we recognize. Other Noncurrent Liabilities Other noncurrent liabilities consisted of the following (in thousands): December 31, 2017 2016 Future QF obligation, net $ 132,786 $ 134,324 Pension and other employee benefits 111,202 120,122 Customer advances 45,376 40,209 Asset retirement obligations 39,286 39,402 Environmental 29,326 30,501 Other 57,729 55,213 Total Noncurrent Liabilities $ 415,705 $ 419,771 Income Taxes We follow the liability method in accounting for income taxes. Deferred income tax assets and liabilities represent the future effects on income taxes from temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized. 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 Revenue Recognition - In May 2014, the Financial Accounting Standards Board (FASB) issued accounting guidance on the recognition of revenue from contracts with customers, which will supersede nearly all existing revenue recognition guidance under GAAP. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. We adopted this standard for interim and annual periods beginning January 1, 2018, as required, and used the modified retrospective method of adoption. We have also elected to utilize certain practical expedients, which allow us to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Our revenues are primarily from tariff based sales, which are in the scope of the guidance. We provide gas and/or electricity to customers under these tariffs without a defined contractual term (at-will). As the revenue from these arrangements is equivalent to the electricity or gas supplied and billed in that period (including estimated billings), there will not be a shift in the timing or pattern of revenue recognition for such sales. We have also completed the evaluation of our other revenue streams, including those tied to longer term contractual commitments. These revenue streams have performance obligations that are satisfied at a point in time, and will also not have a shift in the timing or pattern of revenue recognition. Based on our analysis, we did not have a cumulative-effect adjustment to retained earnings at January 1, 2018. Disclosures in 2018 will include a reconciliation of results under the new revenue recognition guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods. We expect our disclosures to reflect our disaggregated revenue by segment for each geographical region. Retirement Benefits - In March 2017, the FASB issued new guidance on the presentation of net periodic costs related to benefit plans. The new guidance requires the service cost component of net periodic benefit cost to be included within operating income within the same line as other compensation expenses. All other components of net periodic benefit costs must be outside of operating income. In addition, the updated guidance permits only the service cost component of net periodic benefit costs to be capitalized to inventory or property, plant and equipment. This represents a change from current accounting and financial reporting, with presentation of the aggregate net periodic benefit costs on the income statement within operating income, and which permits all components of net periodic benefit costs to be capitalized. This guidance is effective for interim and annual periods beginning January 1, 2018. These amendments will be applied retrospectively for the presentation of the various components of net periodic benefit costs and prospectively for the change in eligible costs to be capitalized. As a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the current ratemaking treatment. Leases - In February 2016, the FASB issued revised guidance on accounting for leases. The new standard requires a lessee to recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term for all leases with terms longer than 12 months . Leases with a term of 12 months or less will be accounted for similar to existing guidance for operating leases. Recognition, measurement and presentation of expenses will depend on classification as a finance or operating lease. The new guidance will be effective for us for interim and annual periods beginning January 1, 2019 and early adoption is permitted. A modified retrospective transition approach is required for lessees for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. An additional transition approach allows an entity to not assess on transition whether any expired or existing land easements are, or contain, leases that were not previously accounted for as leases. We are currently evaluating the impact of adoption of this guidance. We do not have a significant amount of capital or operating leases. Therefore, based on our analysis to this point we do not expect this guidance to have a significant impact on our Consolidated Financial Statements and disclosures other than an expected increase in assets and liabilities. Statement of Cash Flows - In August 2016, the FASB issued guidance that addresses eight classification issues related to the presentation of cash receipts and cash payments in the statement of cash flows. The new guidance will be effective for us in our first quarter of 2018. The adoption of this guidance will not have a significant impact on our Statement of Cash Flows. In November 2016, the FASB issued guidance that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The new guidance will be effective for us in our first quarter of 2018. The adoption of this guidance will not have a significant impact on our Statement of Cash Flows. Supplemental Cash Flow Information Year Ended December 31, 2017 2016 2015 (in thousands) Cash paid (received) for: Income taxes $ 60 $ (2,922 ) $ (1,284 ) Interest 82,692 84,953 81,572 Significant non-cash transactions: Capital expenditures included in trade accounts payable 15,848 13,783 12,834

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
Regulatory Matters	(3) Regulatory Matters Montana QF Tariff Filing Under the Public Utility Regulatory Policies Act (PURPA), electric utilities are required, with exceptions, to purchase energy and capacity from independent power producers that are QFs. In May 2016, we filed an application for approval of a revised tariff for standard rates for small QFs ( 3 MW or less). In November 2017, the MPSC issued an order revising the QF tariff to establish a maximum contract length of 15 years and substantially lowering the rate for future QF contracts. In this order, the MPSC also upheld an initial decision to apply the contract term to our future owned and contracted electric supply resources. As a result of this order, we terminated our competitive solicitation process for 20-year resources to determine the lowest-cost / least-risk approach for addressing our intermittent capacity and reserve margin needs in Montana. We continue to evaluate the impact of this decision, as we have significant generation capacity deficits and negative reserve margins, and our 2016 resource plan identified price and reliability risks to our customers if we rely solely upon market purchases to address these capacity needs. In addition to our responsibility to meet peak demand, national reliability standards effective July 2016 require us to have even greater dispatchable generation capacity available and be capable of increasing or decreasing output to address the irregular nature of intermittent generation such as wind or solar. We expect to file our next electric supply resource procurement plan in late 2018. Cost Recovery Mechanisms Montana House Bill 193 / Electric Tracker - In April 2017, the Montana legislature passed House Bill 193 (HB 193), amending the statute that provided for mandatory recovery of our prudently incurred electric supply costs effective July 1, 2017. The revised statute gives the MPSC discretion whether to approve an electric supply cost adjustment mechanism. The MPSC initiated a process to develop a replacement electric supply cost adjustment mechanism, and in response, in July 2017, we filed a proposed electric PCCAM. Intervenor testimony was filed in November 2017, and in December 2017, the MPSC issued a Notice of Additional Issues stating that the range of options proposed by the parties was not sufficient and directing parties to consider alternatives incorporating risk-sharing features of other utilities in the region. We filed rebuttal testimony in February 2018, responsive to intervenor testimony and the MPSC's December 2017 Notice of Additional Issues addressing alternative risk-sharing mechanisms. A hearing is scheduled to begin May 31, 2018. If the MPSC approves a new mechanism, the MPSC may apply the mechanism to variable costs on a retroactive basis to the effective date of HB 193 (July 1, 2017). Montana Electric Tracker Open Dockets - 2015/2016 - 2016/2017 - Under the previous statutory tracker mechanism, each year we submitted an electric tracker filing 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, which were subject to a prudency review. In June 2017, the MPSC consolidated the supply costs portion of the 2016/2017 docket with the 2015/2016 docket. The rates for this consolidated docket were approved on an interim basis. The MPSC has not established a schedule regarding this docket under the prior statutory tracker. In addition, the MPSC consolidated the projected supply costs portion of the 2016/2017 docket with the PCCAM docket, discussed above. Montana Natural Gas Tracker - 2016/2017 - In May 2017, we filed our annual natural gas tracker filing for the 2016/2017 tracker period, which the MPSC approved on an interim basis. In December 2017, the MPSC issued a final order approving the natural gas interim rates. HB 193 does not impact our natural gas recovery mechanism. Montana Electric Tracker Litigation - 2012/2013 - 2013/2014 (Consolidated Docket) and 2014/2015 (2015 Tracker) - In 2016, we received two orders in separate electric tracker dockets filed with the MPSC, which, in total, resulted in a $12.4 million disallowance of costs, including interest. The first order (Consolidated Docket) included a disallowance of replacement power costs from a 2013 outage at Colstrip Unit 4 and certain modeling/planning costs. In September 2016, we appealed that order to the Montana District Court, arguing that the order was arbitrary and capricious and violated Montana law. We expect a decision on this appeal within the next 12 months . The second order (2015 Tracker), included a disallowance of certain portfolio modeling costs. In June 2016, we filed an appeal of the second order in Montana District Court arguing that the decision violated Montana law. We expect a decision in the next three to six months. Montana Property Tax Tracker - Under Montana law, we are allowed to track the changes in the actual level of state and local taxes and fees and recover the increase in taxes and fees, net of the associated income tax benefit. We submit an annual property tax tracker filing with the MPSC for an automatic rate adjustment, with rates typically effective January 1st of each year. The MPSC identified concerns with the amount of annual increases proposed by the Montana Department of Revenue. In June 2017, the MPSC adopted new rules to establish minimum filing requirements for our statutory property tax tracker filing. Some of the rules appear to be based on a narrow interpretation of the statutory language and suggest that the MPSC will challenge the amount and allocation of these taxes to customers. We filed our annual property tax tracker filing in December 2017. In January 2018, the MPSC issued an order in our 2017 filing reducing our recovery of these taxes by approximately $1.7 million by applying an alternate allocation methodology. This results in a lower allocation to our Montana electric retail customers and a higher property tax allocation to FERC transmission customers (we do not have a property tax tracker for FERC jurisdictional purposes). We submitted a motion for reconsideration of this order on February 8, 2018, and expect a decision by the end of the first quarter of 2018. Tax Cuts and Jobs Act The MPSC and SDPUC initiated dockets regarding the impact of the Tax Cuts and Jobs Act on customer rates beginning January 1, 2018. We are required to submit filings in Montana and South Dakota during the first quarter of 2018 with a proposal to address the effects of the lower statutory rate. We expect to provide a customer benefit as a result of the Tax Cuts and Jobs Act in each of our jurisdictions. FERC Filing - Dave Gates Generating Station at Mill Creek (DGGS) In May 2016, we received an order from the FERC denying a May 2014 request for rehearing and requiring us to make refunds. The request for rehearing challenged a September 2012 FERC Administrative Law Judge's (ALJ) initial decision regarding cost allocation at DGGS between retail and wholesale customers. The 2012 decision concluded that only a portion of these costs should be allocated to FERC jurisdictional customers. We had cumulative deferred revenue of approximately $27.3 million , consistent with the ALJ's initial decision, which was refunded to wholesale and choice customers in June 2016 in accordance with the FERC order. In June 2016, we filed a petition for review of the FERC's May 2016 order with the United States Circuit Court of Appeals for the District of Columbia Circuit (D.C. Circuit). A hearing was held on December 1, 2017. We expect a decision in this matter by the end of the second quarter of 2018.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2017
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets and Liabilities	(4) Regulatory Assets and Liabilities We prepare our Consolidated 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 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. Note Reference Remaining Amortization Period December 31, 2017 2016 (in thousands) Income taxes 12 Plant Lives $ 163,605 $ 411,546 Pension 14 Undetermined 115,504 127,133 Deferred financing costs Various 37,090 24,810 Employee related benefits 14 Undetermined 17,729 20,256 Supply costs 1 Year 13,398 16,809 State & local taxes & fees Various 10,896 17,838 Environmental clean-up 18 Various 12,399 13,601 Distribution infrastructure projects - — 3,136 Other — Various 21,364 17,855 Total Regulatory Assets $ 391,985 $ 652,984 Removal cost 6 Various $ 408,451 $ 386,373 Supply costs 1 Year 10,357 14,041 Gas storage sales 22 Years 9,149 9,569 Deferred revenue 3 1 Year 2,201 5,066 State & local taxes & fees 1 Year 1,520 1,154 Environmental clean-up Various 1,365 6,383 Total Regulatory Liabilities $ 433,043 $ 422,586 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. This reflects the estimated impact of the Tax Cuts and Job Acts enacted in December 2017. See Note 12 - Income Taxes for further discussion. 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. 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. 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 7.9% and 7.0% , respectively, in Montana; 7.2% and 7.8% , respectively, in South Dakota; and 8.5% for natural gas in Nebraska. State & Local Taxes & Fees (Montana Property Tax Tracker) Under Montana law, we are allowed to track the changes in the actual level of state and local taxes and fees and recover the increase in rates, less the amount allocated to FERC jurisdictional customers and net of the related income tax benefit. 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 18 - 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. 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, which began in 2013 and concluded in 2017. Removal Cost The anticipated costs of removing assets upon retirement are collected from customers in advance of removal activity 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 6 - 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. Deferred Revenue We have deferred revenue associated with DGGS and Gas Production, which may be subject to refund as we have open regulatory proceedings. See Note 3 - Regulatory Matters, for further information regarding these items.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	(5) Property, Plant and Equipment The following table presents the major classifications of our property, plant and equipment (in thousands): Estimated Useful Life December 31, 2017 2016 (years) (in thousands) Land, land rights and easements 53 – 96 $ 148,507 $ 138,963 Building and improvements 27 – 64 242,038 225,003 Transmission, distribution, and storage 15 – 85 3,163,463 2,933,788 Generation 25 – 50 1,187,346 1,167,525 Plant acquisition adjustment 25 – 50 685,417 685,417 Other 2 – 45 521,711 472,264 Construction work in process –— 69,902 116,995 Total property, plant and equipment 6,018,384 5,739,955 Less accumulated depreciation (1,660,119 ) (1,525,063 ) Net property, plant and equipment $ 4,358,265 $ 4,214,892 The plant acquisition adjustment balance above includes an amount related to our Beethoven wind project acquired in 2015, our hydro generating assets acquired in 2014, and the inclusion of our interest in Colstrip Unit 4 in rate base in 2009. The acquisition adjustment is being amortized on a straight-line basis over the estimated remaining useful life of each related asset in depreciation expense. Plant and equipment under capital lease were $17.5 million and $19.3 million as of December 31, 2017 and 2016 , respectively, which included $17.1 million and $19.1 million as of December 31, 2017 and 2016 , 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 (SD) Neal #4 (IA) Coyote (ND) Colstrip Unit 4 (MT) December 31, 2017 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 153,682 $ 60,859 $ 49,968 $ 307,712 Accumulated depreciation 40,706 30,446 37,605 85,481 December 31, 2016 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 153,623 $ 60,491 $ 50,802 $ 297,289 Accumulated depreciation 38,894 29,235 37,099 77,513

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	(6) 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 relate to the reclamation and removal costs at our jointly-owned coal-fired generation facilities, 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, 2017 2016 Liability at January 1, $ 39,402 $ 35,532 Accretion expense 2,062 1,885 Liabilities incurred — 164 Liabilities settled (61 ) — Revisions to cash flows (2,117 ) 1,821 Liability at December 31, $ 39,286 $ 39,402 In addition, 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. We also identified AROs associated with our hydroelectric generating facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the Consolidated Financial Statements. We collect removal costs in rates for certain transmission and distribution assets that do not have associated AROs. 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. The recorded amounts of costs collected from customers through depreciation rates are classified as a regulatory liability in recognition of the fact that we have collected these amounts that will be used in the future to fund asset retirement costs and do not represent legal retirement obligations. See Note 4 - Regulatory Assets and Liabilities for removal costs recorded as regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2017 and 2016 .

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	(7) Goodwill We completed our annual goodwill impairment test as of April 1, 2017 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. Goodwill by segment is as follows (in thousands): December 31, 2017 2016 Electric $ 243,558 $ 243,558 Natural gas 114,028 114,028 Total Goodwill $ 357,586 $ 357,586

Risk Management and Hedging Act

Risk Management and Hedging Activities	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management and Hedging Activities	(8) 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 portion of our electric and natural gas supply requirements. 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. 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. 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 (NPNS); 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 scope exception to 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 unrealized amounts recorded in the Consolidated Financial Statements at December 31, 2017 and 2016 . 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. Credit Risk 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 limit credit risk in our commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. We are exposed to credit risk through buying and selling electricity and natural gas to serve customers. 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. Interest Rate Swaps Designated as Cash Flow Hedges We have previously used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. We have no interest rate swaps outstanding. 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 AOCL. We reclassify these gains from AOCL into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these interest rate swaps previously terminated on the Consolidated Financial Statements (in thousands): Cash Flow Hedges Location of Amount Reclassified from AOCL to Income Amount Reclassified from AOCL into Income during the Year Ended December 31, 2017 Interest rate contracts Interest Expense $ 613 A pre-tax loss of approximately $16.5 million is remaining in AOCL as of December 31, 2017 , and we expect to reclassify approximately $0.6 million of pre-tax losses from AOCL into interest expense during the next twelve months. These amounts relate to terminated swaps.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	(9) 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. Applicable accounting guidance establishes a 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. 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. Due to the short-term nature of cash and cash equivalents, accounts receivable, net, accounts payable, and short-term borrowings, the carrying amount of each such items approximate fair value. 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. NPNS transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 8 - Risk Management and Hedging Activities for further discussion. We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented. December 31, 2017 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Margin Cash Collateral Offset Total Net Fair Value (in thousands) Restricted cash $ 2,648 $ — $ — $ — $ 2,648 Rabbi trust investments 28,135 — — — 28,135 Total $ 30,783 $ — $ — $ — $ 30,783 December 31, 2016 Restricted cash $ 4,164 $ — $ — $ — $ 4,164 Rabbi trust investments 25,064 — — — 25,064 Total $ 29,228 $ — $ — $ — $ 29,228 Restricted cash represents amounts held in money market mutual funds. Rabbi trust investments 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. Financial Instruments The estimated fair value of financial instruments is summarized as follows (in thousands): December 31, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 1,793,416 $ 1,901,915 $ 1,793,338 $ 1,852,052 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.

Short-Term Borrowings and Credi

Short-Term Borrowings and Credit Arrangements	12 Months Ended
	Dec. 31, 2017
Short-term Debt [Abstract]
Short-Term Debt	(10) 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): 2017 2016 Short-Term Debt Balance Interest Rate Balance Interest Rate Commercial Paper $ 319.6 1.75 % $ 300.8 1.07 % The following information relates to commercial paper for the years ended December 31 (dollars in millions): 2017 2016 Maximum short-term debt outstanding $ 332.5 $ 300.8 Average short-term debt outstanding $ 251.7 $ 210.7 Weighted-average interest rate 1.35 % 0.86 % 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 $340 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 December 12, 2016, we amended and restated our existing revolving credit facility to, among other things, increase the size of the facility to $400 million (from $350 million ) and extend the maturity date to December 12, 2021 (from November 5, 2018). We retained an accordion feature that allows us to increase the size to $450 million with the consent of the lenders. The facility does not amortize and is unsecured. The facility bears interest at the lower of prime or available rates tied to the Eurodollar rate plus a credit spread, ranging from 0.875% to 1.75% . 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, 2017 . Commitment fees for the unsecured revolving line of credit were $0.5 million and $0.4 million for the years ended December 31, 2017 and 2016 . 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.

Long-Term Debt and Capital Leas

Long-Term Debt and Capital Leases	12 Months Ended
	Dec. 31, 2017
Long-term Debt and Capital Lease Obligations [Abstract]
Long-term Debt And Capital Leases	(11) Long-Term Debt and Capital Leases Long-term debt and capital leases consisted of the following (in thousands): December 31, Due 2017 2016 Unsecured Debt: Unsecured Revolving Line of Credit 2021 $ — $ — Secured Debt: Mortgage bonds— 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 50,000 South Dakota—4.22% 2044 30,000 30,000 South Dakota—4.26% 2040 70,000 70,000 South Dakota—2.80% 2026 60,000 60,000 South Dakota—2.66% 2026 45,000 45,000 Montana—6.34% 2019 — 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 15,000 Montana—3.99% 2028 35,000 35,000 Montana—4.176% 2044 450,000 450,000 Montana—3.11% 2025 75,000 75,000 Montana—4.11% 2045 125,000 125,000 Montana—4.03% 2047 250,000 — Pollution control obligations— Montana—2.00% 2023 144,660 144,660 Other Long Term Debt: New Market Tax Credit Financing—1.146% 2046 26,977 26,977 Discount on Notes and Bonds and Debt Issuance Costs, Net — (13,221 ) (13,299 ) $ 1,793,416 $ 1,793,338 Less current maturities — — Total Long-Term Debt $ 1,793,416 $ 1,793,338 Capital Leases: Total Capital Leases Various $ 24,346 $ 26,325 Less current maturities (2,133 ) (1,979 ) Total Long-Term Capital Leases $ 22,213 $ 24,346 Secured Debt First Mortgage Bonds and Pollution Control Obligations The South Dakota First 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 November 2017 , we issued $250 million aggregate principal amount of Montana First Mortgage Bonds, at a fixed interest rate of 4.03% maturing in 2047 . The bonds are secured by our electric and natural gas assets in Montana. The bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended. Proceeds were used to redeem our 6.34% , $250 million of Montana First Mortgage Bonds due 2019 . In August 2016 , the City of Forsyth, Rosebud County, Montana issued $144.7 million aggregate principal amount of Pollution Control Revenue Refunding Bonds on our behalf. The bonds were issued at a fixed interest rate of 2.00% maturing in 2023 . The proceeds of the issuance were loaned to us pursuant to a Loan Agreement and have been used to partially fund the redemption of the 4.65% , $170.2 million City of Forsyth Pollution Control Revenue Refunding Bonds due 2023 (Prior Bonds) issued on our behalf. We paid the remaining portion of the Prior Bonds with available funds. Our obligation under the Loan Agreement is secured by the issuance of $144.7 million of Montana First Mortgage Bonds. These bonds are secured by our electric and natural gas assets in Montana and Wyoming. The City of Forsyth bonds were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended. In June 2016 , we issued $60 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.80% maturing in 2026 . Proceeds were used to redeem our 6.05% , $55 million South Dakota First Mortgage Bonds due 2018 . In addition, in September 2016 , we issued $45.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 2.66% maturing in 2026 . Proceeds from this issuance were used for general corporate purposes. Both series of these bonds are secured by our electric and natural gas assets in South Dakota, Nebraska, North Dakota, and Iowa and were issued in transactions exempt from the registration requirements of the Securities Act of 1933, as amended. As of December 31, 2017 , we are in compliance with our financial debt covenants. Other Long-Term Debt The New Market Tax Credit (NMTC) financing is pursuant to Section 45D of the Internal Revenue Code of 1986 as amended, which was issued in association with a tax credit program related to the development and construction of a new office building in Butte, Montana. This financing agreement is structured with unrelated third party financial institutions (the Investor) and their wholly-owned community development entities (CDEs) in connection with our participation in qualified transactions under the NMTC program. Upon closing of this transaction in 2014, we entered into two loans totaling $27.0 million payable to the CDEs sponsoring the project, and provided an $18.2 million investment. In exchange for substantially all of the benefits derived from the tax credits, the Investor contributed approximately $8.8 million to the project. The NMTC is subject to recapture for a period of seven years . If the expected tax benefits are delivered without risk of recapture to the Investor and our performance obligation is relieved, we expect $7.9 million of the loan to be forgiven in July 2021 . If we do not meet the conditions for loan forgiveness, we would be required to repay $27.0 million and would concurrently receive the return of our $18.2 million investment. As we are the primary beneficiary of the entities created in relation to the NMTC transaction, they have been consolidated as variable interest entities. The loans of $27.0 million are recorded in long-term debt and the investment of $18.2 million is recorded in other noncurrent assets in the Consolidated Balance Sheets. Maturities of Long-Term Debt The aggregate minimum principal maturities of long-term debt and capital leases, during the next five years are $2.1 million in 2018 , $2.3 million in 2019 , $2.5 million in 2020 , $2.7 million in 2021 and $2.9 million in 2022 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	(12) Income Taxes Income tax expense (benefit) is comprised of the following (in thousands): Year Ended December 31, 2017 2016 2015 Federal Current $ 806 $ 723 $ (3,527 ) Deferred 17,378 (2,054 ) 33,031 Investment tax credits 166 (196 ) (232 ) State Current 33 10 (90 ) Deferred (5,015 ) (6,130 ) 855 Income Tax Expense (Benefit) $ 13,368 $ (7,647 ) $ 30,037 The following table reconciles our effective income tax rate to the federal statutory rate: Year Ended December 31, 2017 2016 2015 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal provisions (1.9 ) (2.4 ) 0.1 Flow-through repairs deductions (17.3 ) (26.3 ) (13.3 ) Production tax credits (6.3 ) (7.0 ) (3.2 ) Plant and depreciation of flow through items (1.3 ) (2.9 ) (1.6 ) Share-based compensation (0.2 ) (1.1 ) — Prior year permanent return to accrual adjustments (0.3 ) (0.1 ) 0.1 Other, net (0.1 ) (0.1 ) (0.5 ) Effective tax rate 7.6 % (4.9 )% 16.6 % The following table summarizes the significant differences in income tax expense (benefit) based on the differences between our effective tax rate and the federal statutory rate (in thousands): Year Ended December 31, 2017 2016 2015 Income Before Income Taxes 176,071 156,525 181,246 Income tax calculated at 35% federal statutory rate 61,625 54,784 63,436 Permanent or flow through adjustments: State tax income, net of federal provisions (3,258 ) (3,714 ) 301 Flow-through repairs deductions (30,490 ) (41,111 ) (24,079 ) Production tax credits (11,032 ) (10,941 ) (5,721 ) Plant and depreciation of flow through items (2,208 ) (4,604 ) (2,893 ) Share-based compensation (363 ) (1,646 ) — Prior year permanent return to accrual adjustments (629 ) (128 ) 207 Other, net (277 ) (287 ) (1,214 ) (48,257 ) (62,431 ) (33,399 ) Income Tax Expense (Benefit) 13,368 (7,647 ) 30,037 During the twelve months ended December 31, 2016 , we recorded an income tax benefit of approximately $17.0 million due to the adoption of a tax accounting method change related to the costs to repair generation assets, which allowed us to take a current tax deduction for a significant amount of repair costs that were previously capitalized for tax purposes. Approximately $12.5 million of this deduction related to 2015 and prior tax years. This is reflected in the flow-through repairs deductions line due to the regulatory treatment. Tax Cuts and Jobs Act On December 22, 2017, the Tax Cuts and Jobs Act was signed into law, which enacts significant changes to U.S. tax and related laws. The primary impact to us is a reduction of the federal corporate income tax rate from 35% to 21% effective January 1, 2018. We revalued our net deferred tax liability as of December 31, 2017 based on the reduction in the overall future tax impact expected to be realized at the lower tax rate. This resulted in a reduction in our net deferred tax liability of approximately $321 million , which was offset in regulatory assets and liabilities. Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits. The lower statutory tax rate will reduce the impact of these deductions. 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. 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, 2017 2016 NOL carryforward $ 68,840 $ 72,964 Production tax credit 28,067 17,034 Pension / postretirement benefits 26,887 45,847 AMT credit carryforward 13,599 13,599 Compensation accruals 12,113 18,715 Customer advances 11,949 15,837 Unbilled revenue 5,944 12,743 Environmental liability 5,821 9,698 Interest rate hedges 4,323 7,192 Reserves and accruals 1,126 1,121 Property taxes 432 3,767 QF obligations 234 1,025 Regulatory liabilities 114 2,290 Other, net 1,138 3,173 Deferred Tax Asset 180,587 225,005 Excess tax depreciation (356,938 ) (459,588 ) Goodwill amortization (117,971 ) (168,165 ) Flow through depreciation (45,998 ) (160,604 ) Regulatory assets (409 ) (12,230 ) Deferred Tax Liability (521,316 ) (800,587 ) Deferred Tax Liability, net $ (340,729 ) $ (575,582 ) The revaluation of deferred income taxes reflects our estimate of the impact of the Tax Cuts and Jobs Act. We will continue to evaluate subsequent regulations and interpretations and assumptions made, which could materially change our estimate. 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 Section 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. At December 31, 2017 we estimate our total federal NOL carryforward to be approximately $420.8 million prior to consideration of unrecognized tax benefits. If unused, our federal NOL carryforwards will expire as follows: $105.2 million in 2031 ; $13.3 million in 2033 ; $73.3 million in 2034 ; $174.6 million in 2036 and $54.4 million in 2037 . We estimate our state NOL carryforward as of December 31, 2017 is approximately $315.7 million . If unused, our state NOL carryforwards will expire as follows: $67.0 million in 2018 ; $10.5 million in 2020 ; $58.3 million in 2021 ; $135.9 million in 2023 and $44.0 million in 2024 . 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): 2017 2016 2015 Unrecognized Tax Benefits at January 1 $ 88,429 $ 92,387 $ 95,929 Gross increases - tax positions in prior period — — 44 Gross decreases - tax positions in prior period (22,973 ) — (2,903 ) Gross increases - tax positions in current period — — 494 Gross decreases - tax positions in current period (7,983 ) (3,958 ) (1,177 ) Lapse of statute of limitations — — — Unrecognized Tax Benefits at December 31 $ 57,473 $ 88,429 $ 92,387 The reduction in unrecognized tax benefits during the twelve months ended December 31, 2017 reflects the effect of the lower statutory rate in the Tax Cuts and Jobs Act. Our unrecognized tax benefits include approximately $47.8 million and $66.5 million related to tax positions as of December 31, 2017 and 2016 , respectively that, if recognized, would impact our annual effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months. Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. During the years ended December 31, 2017 and 2016, we recognized $0.8 million and $0.7 million , respectively, of expense for interest and penalties in the Consolidated Statements of Income. As of December 31, 2017 and 2016, we had $1.5 million and $0.7 million , respectively, of interest accrued in the Consolidated Balance Sheets. Our federal tax returns from 2000 forward remain subject to examination by the IRS.

Comprehensive Loss

Comprehensive Loss	12 Months Ended
	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Comprehensive Income (Loss) Note [Text Block]	(13) 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, 2017 2016 2015 Before-Tax Amount Tax Expense Net-of-Tax Amount Before-Tax Amount Tax Benefit (Expense) Net-of-Tax Amount Before-Tax Amount Tax Benefit (Expense) Net-of-Tax Amount Foreign currency translation adjustment $ (202 ) $ — $ (202 ) $ 25 — $ 25 $ 558 $ — $ 558 Reclassification of net losses (gains) on derivative instruments 613 (242 ) 371 (2,169 ) 831 (1,338 ) (1,125 ) 427 (698 ) Postretirement medical liability adjustment 1,257 (484 ) 773 317 (122 ) 195 504 (194 ) 310 Other comprehensive income (loss) $ 1,668 $ (726 ) $ 942 $ (1,827 ) $ 709 $ (1,118 ) $ (63 ) $ 233 $ 170 Balances by classification included within accumulated other comprehensive loss (AOCL) on the Consolidated Balance Sheets are as follows, net of tax (in thousands): December 31, 2017 2016 Foreign currency translation $ 1,178 $ 1,380 Derivative instruments designated as cash flow hedges (9,981 ) (10,352 ) Postretirement medical plans 31 (742 ) Accumulated other comprehensive loss $ (8,772 ) $ (9,714 ) The following table displays the changes in AOCL by component, net of tax (in thousands): December 31, 2017 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (10,352 ) $ (742 ) $ 1,380 $ (9,714 ) Other comprehensive income before reclassifications — — (202 ) (202 ) Amounts reclassified from AOCL Interest Expense 371 — — 371 Amounts reclassified from AOCL — 773 — 773 Net current-period other comprehensive income (loss) 371 773 (202 ) 942 Ending Balance $ (9,981 ) $ 31 $ 1,178 $ (8,772 ) December 31, 2016 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (9,014 ) $ (937 ) $ 1,355 $ (8,596 ) Other comprehensive income before reclassifications — — 25 25 Amounts reclassified from AOCL Interest Expense (1,338 ) — — (1,338 ) Amounts reclassified from AOCL — 195 — 195 Net current-period other comprehensive (loss) income (1,338 ) 195 25 (1,118 ) Ending Balance $ (10,352 ) $ (742 ) $ 1,380 $ (9,714 )

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Employee Benefit Plans	(14) 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. The pension plan for our South Dakota and Nebraska employees is referred to as the NorthWestern Corporation plan, and the pension plan for our Montana employees is referred to as the NorthWestern Energy 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 Consolidated Financial Statements. See Note 4 - 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, 2017 2016 2017 2016 Change in benefit obligation: Obligation at beginning of period $ 646,032 $ 628,883 $ 26,217 $ 28,652 Service cost 10,994 11,759 456 492 Interest cost 25,633 26,210 715 795 Actuarial loss (gain) 41,719 7,006 (1,884 ) (71 ) Settlements — — 390 390 Benefits paid (27,582 ) (27,826 ) (2,973 ) (4,041 ) Benefit Obligation at End of Period $ 696,796 $ 646,032 $ 22,921 $ 26,217 Change in Fair Value of Plan Assets: Fair value of plan assets at beginning of period $ 524,637 $ 500,044 $ 18,605 $ 17,972 Return on plan assets 80,253 39,719 2,690 1,277 Employer contributions 9,200 12,700 2,058 3,397 Benefits paid (27,582 ) (27,826 ) (2,973 ) (4,041 ) Fair value of plan assets at end of period $ 586,508 $ 524,637 $ 20,380 $ 18,605 Funded Status $ (110,288 ) $ (121,395 ) $ (2,541 ) $ (7,612 ) Amounts Recognized in the Balance Sheet Consist of: Noncurrent asset 2,535 — 5,061 — Total Assets 2,535 — 5,061 — Current liability — — (3,353 ) (1,789 ) Noncurrent liability (112,823 ) (121,395 ) (4,249 ) (5,823 ) Total Liabilities (112,823 ) (121,395 ) (7,602 ) (7,612 ) Net amount recognized $ (110,288 ) $ (121,395 ) $ (2,541 ) $ (7,612 ) Amounts Recognized in Regulatory Assets Consist of: Prior service (cost) credit (4 ) (9 ) 9,955 11,988 Net actuarial loss (105,545 ) (127,953 ) (1,735 ) (4,739 ) Amounts recognized in AOCL consist of: Prior service cost — — (698 ) (849 ) Net actuarial gain — — 1,079 38 Total $ (105,549 ) $ (127,962 ) $ 8,601 $ 6,438 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, 2017 2016 Projected benefit obligation $ 634.4 $ 646.0 Accumulated benefit obligation 634.4 643.6 Fair value of plan assets 522.7 524.6 ____________________ As of December 31, 2017, the fair value of the NorthWestern Corporation pension plan assets exceed the total projected and accumulated benefit obligation and are therefore excluded from this table. 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, 2017 2016 2015 2017 2016 2015 Components of Net Periodic Benefit Cost Service cost $ 10,994 $ 11,759 $ 12,362 $ 456 $ 492 $ 526 Interest cost 25,633 26,210 26,174 715 795 786 Expected return on plan assets (23,964 ) (28,248 ) (31,561 ) (846 ) (1,042 ) (969 ) Amortization of prior service cost (credit) 4 246 246 (1,882 ) (1,882 ) (1,882 ) Recognized actuarial loss 7,837 9,888 10,634 318 315 385 Settlement loss recognized — — — 390 390 390 Net Periodic Benefit Cost (Credit) $ 20,504 $ 19,855 $ 17,855 $ (849 ) $ (932 ) $ (764 ) 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 2018 will be as follows (in thousands): Pension Benefits Other Postretirement Benefits Prior service credit (cost) $ (4 ) $ 1,882 Accumulated loss (4,286 ) 78 Actuarial Assumptions The measurement dates used to determine pension and other postretirement benefit measurements for the plans are December 31, 2017 and 2016 . 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. We set the discount rate using a yield curve analysis. This analysis includes constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year, projected benefit cash flow from our plans. The decrease in discount rate during 2017 increased our projected benefit obligation by approximately $43.6 million . 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. Based on the target asset allocation for our pension assets and future expectations for asset returns, we increased our long term rate of return on assets assumption for NorthWestern Energy Pension Plan to 4.97% and decreased our assumption on the NorthWestern Corporation Pension Plan to 4.47% for 2018. The weighted-average assumptions used in calculating the preceding information are as follows: Pension Benefits Other Postretirement Benefits December 31, December 31, 2017 2016 2015 2017 2016 2015 Discount rate 3.50-3.60 % 3.95-4.10 % 4.15-4.30 % 3.20-3.30 % 3.40-3.55 % 3.60-3.75 % Expected rate of return on assets 4.70 5.80 5.80 4.70 5.80 5.80 Long-term rate of increase in compensation levels (nonunion) 2.89 3.28 3.58 2.89 3.28 3.58 Long-term rate of increase in compensation levels (union) 2.03 3.20 3.50 2.03 3.20 3.50 The postretirement benefit obligation is calculated assuming that health care costs increase by a 5.00% fixed rate. 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: NorthWestern Energy Pension NorthWestern Corporation Pension NorthWestern Energy Health and Welfare December 31, December 31, December 31, 2017 2016 2017 2016 2017 2016 Domestic debt securities 55.0 % 55.0 % 70.0 % 65.0 % 40.0 % 40.0 % International debt securities 4.0 5.0 2.5 5.0 — — Domestic equity securities 16.5 34.0 11.0 25.0 50.0 50.0 International equity securities 24.5 6.0 16.5 5.0 10.0 10.0 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, 2017 2016 2017 2016 2017 2016 Cash and cash equivalents 0.1 % — % — % 0.1 % 1.5 % 1.0 % Domestic debt securities 54.5 53.4 70.0 64.4 35.2 37.0 International debt securities 4.0 4.6 2.5 4.4 — — Domestic equity securities 16.7 36.0 11.1 26.0 53.4 52.6 International equity securities 24.7 6.0 16.4 5.1 9.9 9.4 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % 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. 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. We expect to continue to make contributions to the pension plans in 2018 and future years that reflect the minimum requirements and discretionary amounts consistent with the amounts recovered in rates. Additional legislative or regulatory measures, as well as fluctuations in financial market conditions, may impact our funding requirements. Due to the regulatory treatment of pension costs in Montana, pension expense for 2017, 2016 and 2015 was based on actual contributions to the plan. Annual contributions to each of the pension plans are as follows (in thousands): 2017 2016 2015 NorthWestern Energy Pension Plan (MT) $ 8,000 $ 11,500 $ 9,000 NorthWestern Corporation Pension Plan (SD and NE) 1,200 1,200 1,200 $ 9,200 $ 12,700 $ 10,200 We estimate the plans will make future benefit payments to participants as follows (in thousands): Pension Benefits Other Postretirement Benefits 2018 $ 30,326 $ 3,353 2019 31,721 2,927 2020 33,452 2,714 2021 34,703 2,502 2022 35,997 2,254 2023-2027 200,820 7,607 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, 2017 , 2016 and 2015 were $10.0 million , $9.8 million , and $9.5 million .

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	(15) Stock-Based Compensation We grant stock-based awards through our Amended and Restated Equity Compensation Plan (ECP), which includes restricted stock awards and performance share awards. In 2014, an additional 600,000 shares of common stock were authorized by the shareholders for issuance under the ECP. As of December 31, 2017 , there were 822,695 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. Performance Unit Awards Performance unit awards are granted annually under the ECP. These awards vest at the end of the three -year performance period if 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 market- and performance-based components. The performance goals are independent of each other and equally weighted, and are based on two metrics: (i) EPS growth level 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 unit awards. The fair value of the earnings per share 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 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: 2017 2016 Risk-free interest rate 1.50 % 0.85 % Expected life, in years 3 3 Expected volatility 17.0% to 22.7% 17.1% to 22.1% Dividend yield 3.7 % 3.4 % 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, 2017 , are as follows: Performance Unit Awards Shares Weighted-Average Grant-Date Fair Value Beginning nonvested grants 175,257 $ 46.35 Granted 93,108 47.99 Vested (87,438 ) 42.47 Forfeited (5,459 ) 47.60 Remaining nonvested grants 175,468 $ 49.11 We recognized compensation expense of $3.9 million , $5.3 million , and $4.4 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively, and a related income tax expense of $0.4 million , $1.8 million , and $1.8 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. As of December 31, 2017 , we had $5.5 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 Statements of Common Shareholders' Equity. The cost is expected to be recognized over a weighted-average period of 2 years. The total fair value of shares vested was $3.7 million , $3.5 million , and $2.8 million for the years ended December 31, 2017 , 2016 and 2015 , 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, 2017 , are as follows: Shares Weighted-Average Grant-Date Fair Value Beginning nonvested grants 62,591 $ 41.14 Granted 13,394 52.20 Vested (8,445 ) 27.42 Forfeited — — Remaining nonvested grants 67,540 $ 43.09 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, 2017 , 2016 and 2015 , DSUs issued to members of our Board totaled 54,920 , 28,338 and 35,030 , respectively. Total compensation expense attributable to the DSUs during the years ended December 31, 2017 , 2016 and 2015 was approximately $2.9 million , $2.4 million and $1.3 million , respectively.

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2017
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Common Stock	(16) 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, 2,865,957 shares of common stock are reserved for the incentive plan awards. For further detail of grants under this plan see Note 15 - Stock-Based Compensation. In September 2017, we entered into an Equity Distribution Agreement with Merrill Lynch, Pierce, Fenner, & Smith, Incorporated and J. P. Morgan Securities LLC, collectively the sales agents, 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 2017, we sold 888,938 shares of our common stock at an average price of $61.30 per share. Proceeds received were approximately $53.7 million , which are net of sales commissions paid of approximately $0.8 million and other fees. During the three months ended December 31, 2017, we issued 805,169 shares at an average price of $61.48 , for net proceeds of $48.9 million , which is net of sales commissions of approximately $0.6 million 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 34,208 and 49,514 during the years ended December 31, 2017 and 2016 , 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, 2017
Earnings Per Share [Abstract]
Earnings Per Share	(17) 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, 2017 2016 Basic computation 48,557,599 48,298,896 Dilutive effect of Performance and restricted share awards (1) 97,722 176,166 Diluted computation 48,655,321 48,475,062 _____________________ (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. We adopted the provisions of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016. Under this ASU, the assumed proceeds from applying the treasury stock method when computing earnings per share no longer includes the amount of excess tax benefits or deficiencies that used to be recognized as additional paid-in capital. This change in the treasury stock method was made on a prospective basis, with adjustments reflected as of January 1, 2016. The changes to the treasury stock method required by this ASU increased dilutive shares by 22,044 shares for the year ended December 31, 2016.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(18) Commitments and Contingencies Qualifying Facilities Liability Our QF liability primarily consists of unrecoverable costs associated with three contracts covered under the PURPA. These contracts require us to purchase minimum amounts of energy at prices ranging from $61 to $136 per MWH through 2029 . Our estimated gross contractual obligation related to these contracts is approximately $807.4 million through 2029 . A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $625.6 million through 2029 . The present value of the remaining liability is recorded in other noncurrent liabilities in our Consolidated Balance Sheets. The following summarizes the change in the liability (in thousands): December 31, 2017 2016 Beginning QF liability $ 134,324 $ 138,310 Unrecovered amount (12,009 ) (14,829 ) Interest expense 10,471 10,843 Ending QF liability $ 132,786 $ 134,324 The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands): Gross Obligation Recoverable Amounts Net 2018 76,703 58,401 18,302 2019 78,836 59,020 19,816 2020 80,984 59,647 21,337 2021 82,941 60,136 22,805 2022 84,948 60,639 24,309 Thereafter 403,009 327,773 75,236 Total $ 807,421 $ 625,616 $ 181,805 Long Term Supply and Capacity Purchase Obligations We have entered into various commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 26 years. Costs incurred under these contracts are included in Cost of Sales in the Consolidated Statements of Income and were approximately $228.4 million , $216.8 million and $241.6 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. As of December 31, 2017 , our commitments under these contracts are $190.6 million in 2018 , $179.0 million in 2019 , $134.8 million in 2020 , $113.9 million in 2021 , $116.0 million in 2022 , and $1.3 billion thereafter. These commitments are not reflected in our Consolidated Financial Statements. Hydroelectric License Commitments With the Hydro Transaction, we assumed two Memoranda of Understanding (MOUs) existing with state, federal and private entities. The MOUs are periodically updated and renewed and require us to implement plans to mitigate the impact of the projects on fish, wildlife and their habitats, and to increase recreational opportunities. The MOUs were created to maximize collaboration between the parties and enhance the possibility to receive matching funds from relevant federal agencies. Under these MOUs, we have a remaining commitment to spend approximately $20.0 million between 2018 and 2040 . These commitments are not reflected in our Consolidated Financial Statements. ENVIRONMENTAL LIABILITIES AND REGULATION Environmental Matters The operation of electric generating, transmission and distribution facilities, and gas gathering, storage, 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 and is estimated to range between $26.7 million to $31.2 million . As of December 31, 2017 , we have a reserve of approximately $30.3 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. 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. 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 $23.5 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, implementing remedial actions pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources, and conducting ongoing monitoring and operation and maintenance activities. As of December 31, 2017 , the reserve for remediation costs at this site is approximately $9.6 million , and we estimate that approximately $4.6 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. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska 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. The Butte and Helena sites, both listed as high priority sites on Montana's state superfund list, were placed into the Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to soil and groundwater impacts. Soil and coal tar were removed at the sites in accordance with the MDEQ requirements. Groundwater monitoring is conducted semiannually at both sites. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remedial actions and/or investigations, if any, at the Butte site. In August 2016, the MDEQ sent us a Notice of Potential Liability and Request for Remedial Action regarding the Helena site. In September 2017, we submitted a Draft Remedial Investigation Work Plan for the Helena site, based on the request of the MDEQ. Comments from the MDEQ are expected in the first quarter of 2018. An investigation conducted at the Missoula site did not require remediation activities, but required preparation of a groundwater monitoring plan. Monitoring wells have been installed and groundwater is monitored semiannually. At the request of Missoula Valley Water Quality District (MVWQD), a draft risk assessment was prepared for the Missoula site and presented to the MVWQD. We and the MVWQD agreed additional site investigation work is appropriate. Analytical results from an October 2016 sampling exceeded the Montana Maximum Contaminant Level for benzene and/or total cyanide in certain monitoring wells. These results were forwarded to MVWQD which shared the same with the MDEQ. MDEQ requested that MVWQD file a formal complaint with MDEQ's Enforcement Division, which MVWQD filed in July 2017. This is expected to prompt MDEQ to reevaluate its position concerning listing the Missoula site on the State of Montana's superfund list. New landowners purchased a portion of the Missoula site using funding provided by a third party. The terms of the funding require the new landowners to address environmental issues. The new landowners contacted us and we addressed their immediate concerns. After researching historical ownership we have identified another potentially responsible party with whom we have initiated communications regarding the site. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, if any, at the Missoula site. Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of GHG including, most significantly, carbon dioxide (CO 2 ). 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 coal-fired electric generating plants, all of which are operated by other companies. We 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 new and existing sources of GHG emissions through regulations. EPA is currently reviewing its existing regulations as a result of an Executive Order issued by President Trump on March 28, 2017 (the Executive Order) instructing all federal agencies to review all regulations and other policies (specifically including the Clean Power Plan, which is discussed in further detail below) that burden the development or use of domestically produced energy resources and suspend, revise or rescind those that pose an undue burden beyond that required to protect the public interest. As a result of the Executive Order review, on October 10, 2017, the EPA proposed to repeal the Clean Power Plan (CPP). Subsequently, the EPA issued an Advance Notice of Proposed Rulemaking, soliciting information on systems of emission reduction that comply with EPA's interpretation of the Clean Air Act, for a possible replacement of the CPP, which was published in the Federal Register on December 28, 2017. The CPP was published in October 2015 and was intended to establish GHG performance standards for existing power plants under Clean Air Act Section 111(d). The CPP established CO2 emission performance standards for existing electric utility steam generating units and natural gas combined cycle units. In its repeal proposal, EPA indicated that it had not yet determined whether it will promulgate a new rule to replace the CPP and the form, if any, such a replacement would take. Following the issuance of the CPP in October 2015, judicial appeals were filed in the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), including an appeal by us. The United States Supreme Court (Supreme Court) issued a stay pending resolution of the appeals by the D.C. Circuit. The D.C. Circuit filed an order on November 9, 2017, holding the case in abeyance for 60 days. On January 10, 2018, EPA filed a status report requesting the D.C. Circuit continue to hold the case in abeyance pending conclusion of its rulemaking. In addition, administrative requests for reconsideration of the CPP were filed with the EPA, including one filed by us in December 2015. We requested the EPA reconsider the CPP, in part, on the grounds that the CO 2 reductions in the CPP applicable to Montana were substantially greater than the reductions the EPA had originally proposed. The EPA denied the petition for reconsideration on January 11, 2017, and we appealed that denial to the D.C. Circuit on March 13, 2017. The EPA has also requested that this case be held in abeyance. We cannot predict what, if any, action the D.C. Circuit may take in either of these two cases, particularly in light of the EPA’s proposal to repeal the CPP. If the CPP ultimately is not repealed, survives the legal challenges described above, and is implemented as written, or if a replacement to the CPP is adopted with similar requirements, it could result in significant additional compliance costs that would affect our future results of operations and financial position if such costs are not recovered through regulated rates. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from any GHG regulations that, in our view, disproportionately impacts customers in our region. Future additional environmental requirements could cause us to incur material costs of compliance, increase our costs of procuring electricity, decrease transmission revenue and impact cost recovery. Technology to efficiently capture, remove and/or sequester such GHG emissions may not be available within a timeframe consistent with the implementation of any such requirements. Physical impacts of climate change also may present potential risks for severe weather, such as droughts, fires, floods, ice storms and tornadoes, in the locations where we operate or have interests. These potential risks may impact costs for electric and natural gas supply and maintenance of generation, distribution, and transmission facilities. 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 in which we have joint ownership. On January 10, 2017, the EPA published amendments to the requirements under the Clean Air Act for state plans for protection of visibility. Among other things, these amendments revised the process and requirements for the state implementation plans and extended the due date for the next periodic comprehensive regional haze state implementation plan revisions from 2018 to 2021. Therefore, by 2021, 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 March 2017, we filed a Petition for Review of these amendments with the D.C. Circuit, which was consolidated with other petitions challenging the final rule. The EPA has not responded to our petition. On January 19, 2018, EPA advised the D.C. Circuit that it intended to initiate rulemaking to revisit the amendment, and asked that the case be held in abeyance. On January 30, 2018, the D.C. Circuit granted the EPA's request to hold the case in abeyance pending further order of the Court. Jointly Owned Plants - We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa and Montana that are or may become subject to the various regulations discussed above that have been issued or proposed. Regarding the CPP, as discussed above, we cannot predict the impact of the CPP on us until there is a definitive judicial decision or administrative action by the EPA repealing or significantly changing the CPP. 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 Billings, Montana Refinery Outage Claim On January 25, 2014, an electrical outage on our 50kV lines supplying power to the ExxonMobil refinery in Billings, Montana caused the refinery to shut down for an extended period. On January 13, 2016, a second electrical outage shut down the ExxonMobil refinery for about nine days. On January 22, 2016, ExxonMobil filed suit against NorthWestern in U.S. District Court in Billings, Montana, seeking unspecified compensatory and punitive damages arising from both outages. ExxonMobil claimed property damages and economic losses of approximately $84.9 million to $95.6 million . We reported the refinery's claims and lawsuit to our liability insurance carriers under our liability insurance coverage, which has a $2.0 million per occurrence retention. We also brought third-party complaints against the City of Billings and General Electric International, Inc. alleging that they were responsible in whole or in part for the outages. Following the completion of fact and expert witness discovery, the parties participated in mediation on November 16, 2017, which resulted in a settlement of all claims. The parties filed a stipulation for dismissal with prejudice, and on December 21, 2017, the court dismissed all claims and third-party claims with prejudice and ordered each party to pay their own costs and fees. Our liability insurance carriers have reimbursed us for the amount of the settlement, less our retention amounts. Pacific Northwest Solar Litigation Pacific Northwest Solar, LLC (PNWS) is an Oregon solar QF developer with which we began negotiating in early 2016 to purchase capacity and energy at our avoided cost under the QF-1 option 1(a) standard rates in accordance with PURPA as implemented by the FERC and the MPSC. On June 16, 2016, however, the MPSC entered a Notice of Commission Action (MPSC Notice) suspending the availability of QF-1 option 1(a) standard rates for solar projects greater than 100 kW, which included the various projects proposed by PNWS. The MPSC exempted from the suspension any contracts at the standard tariff rate with solar QFs greater than 100 kW, but no larger than 3 MW, if prior to the date of the MPSC Notice, the QF had submitted a signed power purchase agreement and had executed an interconnection agreement. PNWS had not obtained interconnection agreements for any of its projects as of June 16, 2016, so based on the MPSC Notice and subsequent July 25, 2016 Order 7500 of like effect from the MPSC, we discontinued further negotiations with PNWS. In November 2016, PNWS sued us in state court seeking unspecified damages for breach of contract and other relief, including a judicial declaration that some or all of the 21 proposed power purchase agreements were in effect. We removed the state lawsuit to the United States District Court for the District of Montana. On July 19, 2017, we entered into a partial settlement agreement with PNWS that resolved some but not all of PNWS' litigation claims. As a result of that settlement, on August 14, 2017, PNWS amended its original complaint to include four, rather than 21, power purchase agreements. Currently pending before the United States District Court are our motion to dismiss, our motion for partial summary judgment, and PNWS’s motion for summary judgment on its request for declaratory relief regarding the four power purchase agreements. We dispute the remaining claims in PNWS’ lawsuit and intend to vigorously defend those claims. This matter is in the initial stages, and we cannot predict an outcome or estimate the amount or range of loss that would result from an adverse outcome in the remaining claims. State of Montana - Riverbed Rents On April 1, 2016, the State of Montana (State) filed a complaint on remand (the State's Complaint) with the Montana First Judicial District Court (State District Court), naming us, along with Talen as defendants. The State claims it owns the riverbeds underlying 10 of our hydroelectric facilities (dams, along with reservoirs and tailraces) on the Missouri, Madison and Clark Fork Rivers, and seeks rents for Talen’s and our use and occupancy of such lands. The facilities at issue in the litigation include the Hebgen, Madison, Hauser, Holter, Black Eagle, Rainbow, Cochrane, Ryan, and Morony facilities on the Missouri and Madison Rivers and the Thompson Falls facility on the Clark Fork River. We acquired these facilities from Talen in November 2014. The litigation has a long prior history, which culminated with a 2012 decision by the United States Supreme Court holding that the Montana Supreme Court erred in not considering a segment-by-segment approach to determine navigability and relying on present day recreational use of the rivers. It also held that what it referred to as the Great Falls Reach "at least from the head of the first waterfall to the foot of the last" was not navigable for title purposes, and thus the State did not own the riverbeds in that segment. The United States Supreme Court remanded the case to the Montana Supreme Court for further proceedings not inconsistent with its opinion. Following the 2012 remand, the case laid dormant for four years until the State's Complaint was filed with the State District Court. On April 20, 2016, we removed the case from State District Court to the United States District Court for the District of Montana (Federal District Court). The State filed a motion to remand and following briefing and argument, on October 10, 2017, the Federal District Court Judge entered an order denying the State’s motion. As the State's Complaint included a claim that the State owned the riverbeds in the Great Falls Reach, on October 16, 2017, we and Talen renewed our earlier filed motions seeking to dismiss the portion of the State's Complaint concerning the Great Falls Reach in light of the United States Supreme Court’s decision. The motions to dismiss have been fully briefed and are awaiting decision. We dispute the State’s claims and intend to vigorously defend the lawsuit. This matter is in the initial stages, and we cannot predict an outcome. If the Federal District Court determines the riverbeds under all 10 of the hydroelectric facilities are navigable (including the five hydroelectric facilities on the Great Falls Reach) and if it calculates damages as the State District Court did in 2008, we estimate the annual rents could be approximately $7 million commencing in November 2014, when we acquired the facilities. We anticipate that any obligation to pay the State rent for use and occupancy of the riverbeds would be recoverable in rates from customers, although there can be no assurances that the MPSC would approve any such recovery. Wilde Claims On October 10, 2017, Martin Wilde, a Montana resident and wind developer, and three entities with which he is affiliated, commenced a lawsuit against the MPSC, each individual commissioner of the MPSC (in each of their official and individual capacities), and us in the Montana Eighth Judicial District Court (Eighth District Court). The Wilde lawsuit alleges that the MPSC collaborated with NorthWestern to set discriminatory rates and contract durations for QF developers. The plaintiffs seek power purchase agreements at $45.19 per megawatt hour for a 25 -year term or, as an alternative remedy to the alleged discrimination, a reduction in NorthWestern’s rates by $17.03 per megawatt hour. The Wilde lawsuit also seeks compensatory damages of not less than $4.8 million , various forms of declaratory relief, injunctive relief, unspecified damages, and punitive damages. On October 20, 2017, the Eighth District Court conducted a hearing on the Wilde plaintiffs' application for a preliminary injunction to stop the defendants from the alleged ongoing discrimination that harms development of renewable energy in Montana. At the hearing’s conclusion, the court did not rule on the requested injunction but orally ordered post-hearing briefs. On November 11, 2017, Mr. Wilde died in a farming accident, and the Eighth District Court subsequently issued a stay in the proceeding through February 13, 2018. The plaintiff's attorney has asked for an additional 60-day stay. We have received no indication whether or not Mr. Wilde’s estate or the other plaintiff entities will continue the litigation after the stay expires. 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 Information

Segment and Related Information	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment and Related Information	(19) 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 primarily consists of 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 for the twelve months ended are as follows (in thousands): December 31, 2017 Electric Gas Other Eliminations Total Operating revenues $ 1,037,053 $ 268,599 $ — $ — $ 1,305,652 Cost of sales 334,029 76,320 — — 410,349 Gross margin 703,024 192,279 — — 895,303 Operating, general and administrative 223,474 81,620 43 — 305,137 Property and other taxes 127,391 35,214 9 — 162,614 Depreciation and depletion 136,556 29,548 33 — 166,137 Operating income (loss) 215,603 45,897 (85 ) — 261,415 Interest expense, net (82,454 ) (5,920 ) (3,889 ) — (92,263 ) Other income, net 3,984 1,985 950 — 6,919 Income tax (expense) benefit (7,424 ) (6,684 ) 740 — (13,368 ) Net income (loss) $ 129,709 $ 35,278 $ (2,284 ) $ — $ 162,703 Total assets $ 4,346,484 $ 1,071,847 $ 2,586 $ — $ 5,420,917 Capital expenditures $ 226,077 $ 50,361 $ — $ — $ 276,438 December 31, 2016 Electric Gas Other Eliminations Total Operating revenues $ 1,011,595 $ 245,652 $ — $ — $ 1,257,247 Cost of sales 332,817 68,156 — — 400,973 Gross margin 678,778 177,496 — — 856,274 Operating, general and administrative 216,736 86,713 (556 ) — 302,893 Property and other taxes 115,583 32,505 10 — 148,098 Depreciation and depletion 130,236 29,067 33 — 159,336 Operating income 216,223 29,211 513 — 245,947 Interest expense, net (86,038 ) (6,589 ) (2,343 ) — (94,970 ) Other income, net 3,246 1,329 973 — 5,548 Income tax benefits (expense) 7,392 (1,687 ) 1,942 — 7,647 Net income $ 140,823 $ 22,264 $ 1,085 $ — $ 164,172 Total assets $ 4,363,848 $ 1,129,355 $ 6,118 $ — $ 5,499,321 Capital expenditures $ 236,014 $ 51,887 $ — $ — $ 287,901 December 31, 2015 Electric Gas Other Eliminations Total Operating revenues $ 944,428 $ 269,871 $ — $ — $ 1,214,299 Cost of sales 281,251 91,613 — — 372,864 Gross margin 663,177 178,258 — — 841,435 Operating, general and administrative 233,416 84,219 (20,160 ) — 297,475 Property and other taxes 104,264 29,168 10 — 133,442 Depreciation and depletion 115,701 28,968 33 — 144,702 Operating income 209,796 35,903 20,117 — 265,816 Interest expense, net (79,044 ) (11,433 ) (1,676 ) — (92,153 ) Other income, net 6,300 1,821 (538 ) — 7,583 Income tax expense (19,950 ) (3,752 ) (6,335 ) — (30,037 ) Net income $ 117,102 $ 22,539 $ 11,568 $ — $ 151,209 Total assets $ 4,185,192 $ 1,072,613 $ 6,890 $ — $ 5,264,695 Capital expenditures $ 234,451 $ 49,254 $ — $ — $ 283,705

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data	(20) 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: 2017 First Second Third Fourth Operating revenues $ 367,312 $ 283,859 $ 309,933 $ 344,548 Operating income 85,144 43,695 61,546 71,030 Net income $ 56,567 $ 21,830 $ 36,412 $ 47,894 Average common shares outstanding 48,386 48,451 48,487 48,902 Income per average common share: Basic $ 1.17 $ 0.45 $ 0.75 $ 0.98 Diluted $ 1.17 $ 0.44 $ 0.75 $ 0.98 Dividends per share $ 0.525 $ 0.525 $ 0.525 $ 0.525 Stock price: High $ 59.41 $ 63.86 $ 61.80 $ 64.47 Low 55.65 58.16 56.87 56.44 Quarter-end close 58.70 61.02 56.94 59.70 2016 First Second Third Fourth Operating revenues $ 332,539 $ 293,120 $ 300,998 $ 330,590 Operating income 61,933 63,742 56,116 64,156 Net income (1) $ 39,867 $ 35,569 $ 44,605 $ 44,131 Average common shares outstanding 48,242 48,309 48,315 48,329 Income per average common share: Basic $ 0.83 $ 0.74 $ 0.92 $ 0.91 Diluted $ 0.82 $ 0.73 $ 0.92 $ 0.92 Dividends per share $ 0.50 $ 0.50 $ 0.50 $ 0.50 Stock price: High $ 62.22 $ 63.30 $ 63.75 $ 59.13 Low 52.16 55.34 56.18 53.85 Quarter-end close 61.75 63.07 57.53 56.87 ____________________ (1) We adopted the provisions of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016, which resulted in the recognition of $1.8 million in excess tax benefits. In accordance with the guidance, the $1.8 million impact of this adoption is reflected as of January 1, 2016, which resulted in an increase in net income and earnings per share for the three months ended March 31, 2016 above.

Nature of Operations and Basi28

Nature of Operations and Basis of Consolidation (Policies)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [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 $219.5 million through 2024 . For further discussion of our gross QF liability, see Note 18 - Commitments and Contingencies. During the years ended December 31, 2017 , 2016 and 2015 purchases from this QF were approximately $16.3 million , $25.5 million , and $24.3 million , respectively.

Significant Accounting Polici29

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
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, regulatory assets and liabilities, 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 electric 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 $2.9 million and $2.9 million at December 31, 2017 and December 31, 2016 , respectively. Receivables include unbilled revenues of $89.1 million and $80.4 million at December 31, 2017 and December 31, 2016 , respectively.
Regulation of Utility Operations	Regulation of Utility Operations Our regulated operations are subject to the provisions of ASC 980, Regulated Operations. 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 deemed probable 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 Statements of Income 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 loss (AOCL) 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 are designated as normal purchases and normal sales 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 8 - 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. This rate averaged 7.2% , 7.2% , and 7.5% , for Montana and South Dakota for 2017 , 2016 , and 2015 , respectively. AFUDC capitalized totaled $8.5 million , $7.0 million , and $13.6 million for the years ended December 2017, 2016, and 2015, respectively, for Montana and South Dakota combined. 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 50 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 3.0% , 3.0% , and 3.3% for 2017 , 2016 , and 2015 , respectively. Depreciation rates include a provision for our share of the estimated costs to decommission our jointly owned plants at the end of the useful life. The annual provision for such costs is included in depreciation expense, while the accumulated provisions are included in noncurrent regulatory liabilities.
Income Taxes	Income Taxes We follow the liability method in accounting for income taxes. Deferred income tax assets and liabilities represent the future effects on income taxes from temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized. 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.
Accounting Standards Issued	Accounting Standards Issued Revenue Recognition - In May 2014, the Financial Accounting Standards Board (FASB) issued accounting guidance on the recognition of revenue from contracts with customers, which will supersede nearly all existing revenue recognition guidance under GAAP. Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect the payment to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. We adopted this standard for interim and annual periods beginning January 1, 2018, as required, and used the modified retrospective method of adoption. We have also elected to utilize certain practical expedients, which allow us to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Our revenues are primarily from tariff based sales, which are in the scope of the guidance. We provide gas and/or electricity to customers under these tariffs without a defined contractual term (at-will). As the revenue from these arrangements is equivalent to the electricity or gas supplied and billed in that period (including estimated billings), there will not be a shift in the timing or pattern of revenue recognition for such sales. We have also completed the evaluation of our other revenue streams, including those tied to longer term contractual commitments. These revenue streams have performance obligations that are satisfied at a point in time, and will also not have a shift in the timing or pattern of revenue recognition. Based on our analysis, we did not have a cumulative-effect adjustment to retained earnings at January 1, 2018. Disclosures in 2018 will include a reconciliation of results under the new revenue recognition guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods. We expect our disclosures to reflect our disaggregated revenue by segment for each geographical region. Retirement Benefits - In March 2017, the FASB issued new guidance on the presentation of net periodic costs related to benefit plans. The new guidance requires the service cost component of net periodic benefit cost to be included within operating income within the same line as other compensation expenses. All other components of net periodic benefit costs must be outside of operating income. In addition, the updated guidance permits only the service cost component of net periodic benefit costs to be capitalized to inventory or property, plant and equipment. This represents a change from current accounting and financial reporting, with presentation of the aggregate net periodic benefit costs on the income statement within operating income, and which permits all components of net periodic benefit costs to be capitalized. This guidance is effective for interim and annual periods beginning January 1, 2018. These amendments will be applied retrospectively for the presentation of the various components of net periodic benefit costs and prospectively for the change in eligible costs to be capitalized. As a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the current ratemaking treatment. Leases - In February 2016, the FASB issued revised guidance on accounting for leases. The new standard requires a lessee to recognize in the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term for all leases with terms longer than 12 months . Leases with a term of 12 months or less will be accounted for similar to existing guidance for operating leases. Recognition, measurement and presentation of expenses will depend on classification as a finance or operating lease. The new guidance will be effective for us for interim and annual periods beginning January 1, 2019 and early adoption is permitted. A modified retrospective transition approach is required for lessees for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. An additional transition approach allows an entity to not assess on transition whether any expired or existing land easements are, or contain, leases that were not previously accounted for as leases. We are currently evaluating the impact of adoption of this guidance. We do not have a significant amount of capital or operating leases. Therefore, based on our analysis to this point we do not expect this guidance to have a significant impact on our Consolidated Financial Statements and disclosures other than an expected increase in assets and liabilities. Statement of Cash Flows - In August 2016, the FASB issued guidance that addresses eight classification issues related to the presentation of cash receipts and cash payments in the statement of cash flows. The new guidance will be effective for us in our first quarter of 2018. The adoption of this guidance will not have a significant impact on our Statement of Cash Flows. In November 2016, the FASB issued guidance that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The new guidance will be effective for us in our first quarter of 2018. The adoption of this guidance will not have a significant impact on our Statement of Cash Flows.

Significant Accounting Polici30

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Inventories	Inventories Inventories are stated at average cost. Inventory consisted of the following (in thousands): December 31, 2017 2016 Materials and supplies $ 34,630 $ 31,602 Storage gas and fuel 17,802 17,604 Total Inventory $ 52,432 $ 49,206
Other Noncurrent Liabilties	Other noncurrent liabilities consisted of the following (in thousands): December 31, 2017 2016 Future QF obligation, net $ 132,786 $ 134,324 Pension and other employee benefits 111,202 120,122 Customer advances 45,376 40,209 Asset retirement obligations 39,286 39,402 Environmental 29,326 30,501 Other 57,729 55,213 Total Noncurrent Liabilities $ 415,705 $ 419,771
Supplemental Cash Flow Information	Supplemental Cash Flow Information Year Ended December 31, 2017 2016 2015 (in thousands) Cash paid (received) for: Income taxes $ 60 $ (2,922 ) $ (1,284 ) Interest 82,692 84,953 81,572 Significant non-cash transactions: Capital expenditures included in trade accounts payable 15,848 13,783 12,834

Regulatory Assets and Liabili31

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets And Liabilities	Note Reference Remaining Amortization Period December 31, 2017 2016 (in thousands) Income taxes 12 Plant Lives $ 163,605 $ 411,546 Pension 14 Undetermined 115,504 127,133 Deferred financing costs Various 37,090 24,810 Employee related benefits 14 Undetermined 17,729 20,256 Supply costs 1 Year 13,398 16,809 State & local taxes & fees Various 10,896 17,838 Environmental clean-up 18 Various 12,399 13,601 Distribution infrastructure projects - — 3,136 Other — Various 21,364 17,855 Total Regulatory Assets $ 391,985 $ 652,984 Removal cost 6 Various $ 408,451 $ 386,373 Supply costs 1 Year 10,357 14,041 Gas storage sales 22 Years 9,149 9,569 Deferred revenue 3 1 Year 2,201 5,066 State & local taxes & fees 1 Year 1,520 1,154 Environmental clean-up Various 1,365 6,383 Total Regulatory Liabilities $ 433,043 $ 422,586

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 (years) (in thousands) Land, land rights and easements 53 – 96 $ 148,507 $ 138,963 Building and improvements 27 – 64 242,038 225,003 Transmission, distribution, and storage 15 – 85 3,163,463 2,933,788 Generation 25 – 50 1,187,346 1,167,525 Plant acquisition adjustment 25 – 50 685,417 685,417 Other 2 – 45 521,711 472,264 Construction work in process –— 69,902 116,995 Total property, plant and equipment 6,018,384 5,739,955 Less accumulated depreciation (1,660,119 ) (1,525,063 ) Net property, plant and equipment $ 4,358,265 $ 4,214,892
Schedule of jointly owned utility plants	Information relating to our ownership interest in these facilities is as follows (in thousands): Big Stone (SD) Neal #4 (IA) Coyote (ND) Colstrip Unit 4 (MT) December 31, 2017 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 153,682 $ 60,859 $ 49,968 $ 307,712 Accumulated depreciation 40,706 30,446 37,605 85,481 December 31, 2016 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 153,623 $ 60,491 $ 50,802 $ 297,289 Accumulated depreciation 38,894 29,235 37,099 77,513

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 Liability at January 1, $ 39,402 $ 35,532 Accretion expense 2,062 1,885 Liabilities incurred — 164 Liabilities settled (61 ) — Revisions to cash flows (2,117 ) 1,821 Liability at December 31, $ 39,286 $ 39,402

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	Goodwill by segment is as follows (in thousands): December 31, 2017 2016 Electric $ 243,558 $ 243,558 Natural gas 114,028 114,028 Total Goodwill $ 357,586 $ 357,586

Risk Management and Hedging A35

Risk Management and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)	The following table shows the effect of these interest rate swaps previously terminated on the Consolidated Financial Statements (in thousands): Cash Flow Hedges Location of Amount Reclassified from AOCL to Income Amount Reclassified from AOCL into Income during the Year Ended December 31, 2017 Interest rate contracts Interest Expense $ 613

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented. December 31, 2017 Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Margin Cash Collateral Offset Total Net Fair Value (in thousands) Restricted cash $ 2,648 $ — $ — $ — $ 2,648 Rabbi trust investments 28,135 — — — 28,135 Total $ 30,783 $ — $ — $ — $ 30,783 December 31, 2016 Restricted cash $ 4,164 $ — $ — $ — $ 4,164 Rabbi trust investments 25,064 — — — 25,064 Total $ 29,228 $ — $ — $ — $ 29,228
Schedule of Estimated Fair Value of Financial Instruments	The estimated fair value of financial instruments is summarized as follows (in thousands): December 31, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 1,793,416 $ 1,901,915 $ 1,793,338 $ 1,852,052

Short-Term Borrowings and Cre37

Short-Term Borrowings and Credit Arrangements (Tables)	12 Months Ended
	Dec. 31, 2017
Line of Credit Facility [Line Items]
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): 2017 2016 Short-Term Debt Balance Interest Rate Balance Interest Rate Commercial Paper $ 319.6 1.75 % $ 300.8 1.07 % The following information relates to commercial paper for the years ended December 31 (dollars in millions): 2017 2016 Maximum short-term debt outstanding $ 332.5 $ 300.8 Average short-term debt outstanding $ 251.7 $ 210.7 Weighted-average interest rate 1.35 % 0.86 %

Long-Term Debt and Capital Le38

Long-Term Debt and Capital Leases (Tables)	12 Months Ended
	Dec. 31, 2017
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 2017 2016 Unsecured Debt: Unsecured Revolving Line of Credit 2021 $ — $ — Secured Debt: Mortgage bonds— 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 50,000 South Dakota—4.22% 2044 30,000 30,000 South Dakota—4.26% 2040 70,000 70,000 South Dakota—2.80% 2026 60,000 60,000 South Dakota—2.66% 2026 45,000 45,000 Montana—6.34% 2019 — 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 15,000 Montana—3.99% 2028 35,000 35,000 Montana—4.176% 2044 450,000 450,000 Montana—3.11% 2025 75,000 75,000 Montana—4.11% 2045 125,000 125,000 Montana—4.03% 2047 250,000 — Pollution control obligations— Montana—2.00% 2023 144,660 144,660 Other Long Term Debt: New Market Tax Credit Financing—1.146% 2046 26,977 26,977 Discount on Notes and Bonds and Debt Issuance Costs, Net — (13,221 ) (13,299 ) $ 1,793,416 $ 1,793,338 Less current maturities — — Total Long-Term Debt $ 1,793,416 $ 1,793,338 Capital Leases: Total Capital Leases Various $ 24,346 $ 26,325 Less current maturities (2,133 ) (1,979 ) Total Long-Term Capital Leases $ 22,213 $ 24,346

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule Of Income Tax Expense Domestic	Income tax expense (benefit) is comprised of the following (in thousands): Year Ended December 31, 2017 2016 2015 Federal Current $ 806 $ 723 $ (3,527 ) Deferred 17,378 (2,054 ) 33,031 Investment tax credits 166 (196 ) (232 ) State Current 33 10 (90 ) Deferred (5,015 ) (6,130 ) 855 Income Tax Expense (Benefit) $ 13,368 $ (7,647 ) $ 30,037
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, 2017 2016 2015 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax, net of federal provisions (1.9 ) (2.4 ) 0.1 Flow-through repairs deductions (17.3 ) (26.3 ) (13.3 ) Production tax credits (6.3 ) (7.0 ) (3.2 ) Plant and depreciation of flow through items (1.3 ) (2.9 ) (1.6 ) Share-based compensation (0.2 ) (1.1 ) — Prior year permanent return to accrual adjustments (0.3 ) (0.1 ) 0.1 Other, net (0.1 ) (0.1 ) (0.5 ) Effective tax rate 7.6 % (4.9 )% 16.6 % The following table summarizes the significant differences in income tax expense (benefit) based on the differences between our effective tax rate and the federal statutory rate (in thousands): Year Ended December 31, 2017 2016 2015 Income Before Income Taxes 176,071 156,525 181,246 Income tax calculated at 35% federal statutory rate 61,625 54,784 63,436 Permanent or flow through adjustments: State tax income, net of federal provisions (3,258 ) (3,714 ) 301 Flow-through repairs deductions (30,490 ) (41,111 ) (24,079 ) Production tax credits (11,032 ) (10,941 ) (5,721 ) Plant and depreciation of flow through items (2,208 ) (4,604 ) (2,893 ) Share-based compensation (363 ) (1,646 ) — Prior year permanent return to accrual adjustments (629 ) (128 ) 207 Other, net (277 ) (287 ) (1,214 ) (48,257 ) (62,431 ) (33,399 ) Income Tax Expense (Benefit) 13,368 (7,647 ) 30,037
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, 2017 2016 NOL carryforward $ 68,840 $ 72,964 Production tax credit 28,067 17,034 Pension / postretirement benefits 26,887 45,847 AMT credit carryforward 13,599 13,599 Compensation accruals 12,113 18,715 Customer advances 11,949 15,837 Unbilled revenue 5,944 12,743 Environmental liability 5,821 9,698 Interest rate hedges 4,323 7,192 Reserves and accruals 1,126 1,121 Property taxes 432 3,767 QF obligations 234 1,025 Regulatory liabilities 114 2,290 Other, net 1,138 3,173 Deferred Tax Asset 180,587 225,005 Excess tax depreciation (356,938 ) (459,588 ) Goodwill amortization (117,971 ) (168,165 ) Flow through depreciation (45,998 ) (160,604 ) Regulatory assets (409 ) (12,230 ) Deferred Tax Liability (521,316 ) (800,587 ) Deferred Tax Liability, net $ (340,729 ) $ (575,582 )
Summary of Income Tax Contingencies	The change in unrecognized tax benefits is as follows (in thousands): 2017 2016 2015 Unrecognized Tax Benefits at January 1 $ 88,429 $ 92,387 $ 95,929 Gross increases - tax positions in prior period — — 44 Gross decreases - tax positions in prior period (22,973 ) — (2,903 ) Gross increases - tax positions in current period — — 494 Gross decreases - tax positions in current period (7,983 ) (3,958 ) (1,177 ) Lapse of statute of limitations — — — Unrecognized Tax Benefits at December 31 $ 57,473 $ 88,429 $ 92,387

Comprehensive Loss (Tables)

Comprehensive Loss (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Before-Tax Amount Tax Expense Net-of-Tax Amount Before-Tax Amount Tax Benefit (Expense) Net-of-Tax Amount Before-Tax Amount Tax Benefit (Expense) Net-of-Tax Amount Foreign currency translation adjustment $ (202 ) $ — $ (202 ) $ 25 — $ 25 $ 558 $ — $ 558 Reclassification of net losses (gains) on derivative instruments 613 (242 ) 371 (2,169 ) 831 (1,338 ) (1,125 ) 427 (698 ) Postretirement medical liability adjustment 1,257 (484 ) 773 317 (122 ) 195 504 (194 ) 310 Other comprehensive income (loss) $ 1,668 $ (726 ) $ 942 $ (1,827 ) $ 709 $ (1,118 ) $ (63 ) $ 233 $ 170
Accumulated Other Comprehensive Income [Table Text Block]	Balances by classification included within accumulated other comprehensive loss (AOCL) on the Consolidated Balance Sheets are as follows, net of tax (in thousands): December 31, 2017 2016 Foreign currency translation $ 1,178 $ 1,380 Derivative instruments designated as cash flow hedges (9,981 ) (10,352 ) Postretirement medical plans 31 (742 ) Accumulated other comprehensive loss $ (8,772 ) $ (9,714 )
Schedule of Accumulated Comprehensive Income (Loss)	The following table displays the changes in AOCL by component, net of tax (in thousands): December 31, 2017 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (10,352 ) $ (742 ) $ 1,380 $ (9,714 ) Other comprehensive income before reclassifications — — (202 ) (202 ) Amounts reclassified from AOCL Interest Expense 371 — — 371 Amounts reclassified from AOCL — 773 — 773 Net current-period other comprehensive income (loss) 371 773 (202 ) 942 Ending Balance $ (9,981 ) $ 31 $ 1,178 $ (8,772 ) December 31, 2016 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (9,014 ) $ (937 ) $ 1,355 $ (8,596 ) Other comprehensive income before reclassifications — — 25 25 Amounts reclassified from AOCL Interest Expense (1,338 ) — — (1,338 ) Amounts reclassified from AOCL — 195 — 195 Net current-period other comprehensive (loss) income (1,338 ) 195 25 (1,118 ) Ending Balance $ (10,352 ) $ (742 ) $ 1,380 $ (9,714 )

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [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, 2017 2016 2017 2016 Change in benefit obligation: Obligation at beginning of period $ 646,032 $ 628,883 $ 26,217 $ 28,652 Service cost 10,994 11,759 456 492 Interest cost 25,633 26,210 715 795 Actuarial loss (gain) 41,719 7,006 (1,884 ) (71 ) Settlements — — 390 390 Benefits paid (27,582 ) (27,826 ) (2,973 ) (4,041 ) Benefit Obligation at End of Period $ 696,796 $ 646,032 $ 22,921 $ 26,217 Change in Fair Value of Plan Assets: Fair value of plan assets at beginning of period $ 524,637 $ 500,044 $ 18,605 $ 17,972 Return on plan assets 80,253 39,719 2,690 1,277 Employer contributions 9,200 12,700 2,058 3,397 Benefits paid (27,582 ) (27,826 ) (2,973 ) (4,041 ) Fair value of plan assets at end of period $ 586,508 $ 524,637 $ 20,380 $ 18,605 Funded Status $ (110,288 ) $ (121,395 ) $ (2,541 ) $ (7,612 ) Amounts Recognized in the Balance Sheet Consist of: Noncurrent asset 2,535 — 5,061 — Total Assets 2,535 — 5,061 — Current liability — — (3,353 ) (1,789 ) Noncurrent liability (112,823 ) (121,395 ) (4,249 ) (5,823 ) Total Liabilities (112,823 ) (121,395 ) (7,602 ) (7,612 ) Net amount recognized $ (110,288 ) $ (121,395 ) $ (2,541 ) $ (7,612 ) Amounts Recognized in Regulatory Assets Consist of: Prior service (cost) credit (4 ) (9 ) 9,955 11,988 Net actuarial loss (105,545 ) (127,953 ) (1,735 ) (4,739 ) Amounts recognized in AOCL consist of: Prior service cost — — (698 ) (849 ) Net actuarial gain — — 1,079 38 Total $ (105,549 ) $ (127,962 ) $ 8,601 $ 6,438
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, 2017 2016 Projected benefit obligation $ 634.4 $ 646.0 Accumulated benefit obligation 634.4 643.6 Fair value of plan assets 522.7 524.6
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, 2017 2016 2015 2017 2016 2015 Components of Net Periodic Benefit Cost Service cost $ 10,994 $ 11,759 $ 12,362 $ 456 $ 492 $ 526 Interest cost 25,633 26,210 26,174 715 795 786 Expected return on plan assets (23,964 ) (28,248 ) (31,561 ) (846 ) (1,042 ) (969 ) Amortization of prior service cost (credit) 4 246 246 (1,882 ) (1,882 ) (1,882 ) Recognized actuarial loss 7,837 9,888 10,634 318 315 385 Settlement loss recognized — — — 390 390 390 Net Periodic Benefit Cost (Credit) $ 20,504 $ 19,855 $ 17,855 $ (849 ) $ (932 ) $ (764 )
Schedule of Estimated Amortization of Regulatory Assets Into Net Periodic Benefit Costs	We estimate amortizations from regulatory assets into net periodic benefit cost during 2018 will be as follows (in thousands): Pension Benefits Other Postretirement Benefits Prior service credit (cost) $ (4 ) $ 1,882 Accumulated loss (4,286 ) 78
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, 2017 2016 2015 2017 2016 2015 Discount rate 3.50-3.60 % 3.95-4.10 % 4.15-4.30 % 3.20-3.30 % 3.40-3.55 % 3.60-3.75 % Expected rate of return on assets 4.70 5.80 5.80 4.70 5.80 5.80 Long-term rate of increase in compensation levels (nonunion) 2.89 3.28 3.58 2.89 3.28 3.58 Long-term rate of increase in compensation levels (union) 2.03 3.20 3.50 2.03 3.20 3.50
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: NorthWestern Energy Pension NorthWestern Corporation Pension NorthWestern Energy Health and Welfare December 31, December 31, December 31, 2017 2016 2017 2016 2017 2016 Domestic debt securities 55.0 % 55.0 % 70.0 % 65.0 % 40.0 % 40.0 % International debt securities 4.0 5.0 2.5 5.0 — — Domestic equity securities 16.5 34.0 11.0 25.0 50.0 50.0 International equity securities 24.5 6.0 16.5 5.0 10.0 10.0
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, 2017 2016 2017 2016 2017 2016 Cash and cash equivalents 0.1 % — % — % 0.1 % 1.5 % 1.0 % Domestic debt securities 54.5 53.4 70.0 64.4 35.2 37.0 International debt securities 4.0 4.6 2.5 4.4 — — Domestic equity securities 16.7 36.0 11.1 26.0 53.4 52.6 International equity securities 24.7 6.0 16.4 5.1 9.9 9.4 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % 100.0 %
Schedule of Pension Contributions	Annual contributions to each of the pension plans are as follows (in thousands): 2017 2016 2015 NorthWestern Energy Pension Plan (MT) $ 8,000 $ 11,500 $ 9,000 NorthWestern Corporation Pension Plan (SD and NE) 1,200 1,200 1,200 $ 9,200 $ 12,700 $ 10,200
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 2018 $ 30,326 $ 3,353 2019 31,721 2,927 2020 33,452 2,714 2021 34,703 2,502 2022 35,997 2,254 2023-2027 200,820 7,607

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
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: 2017 2016 Risk-free interest rate 1.50 % 0.85 % Expected life, in years 3 3 Expected volatility 17.0% to 22.7% 17.1% to 22.1% Dividend yield 3.7 % 3.4 %
Schedule of Nonvested Share Activity	A summary of nonvested shares as of and changes during the year ended December 31, 2017 , are as follows: Performance Unit Awards Shares Weighted-Average Grant-Date Fair Value Beginning nonvested grants 175,257 $ 46.35 Granted 93,108 47.99 Vested (87,438 ) 42.47 Forfeited (5,459 ) 47.60 Remaining nonvested grants 175,468 $ 49.11
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, 2017 , are as follows: Shares Weighted-Average Grant-Date Fair Value Beginning nonvested grants 62,591 $ 41.14 Granted 13,394 52.20 Vested (8,445 ) 27.42 Forfeited — — Remaining nonvested grants 67,540 $ 43.09

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 Basic computation 48,557,599 48,298,896 Dilutive effect of Performance and restricted share awards (1) 97,722 176,166 Diluted computation 48,655,321 48,475,062 _____________________ (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, 2017
Commitments and Contingencies Disclosure [Abstract]
Schedule of Changes In Qualifying Facility Liability	The following summarizes the change in the liability (in thousands): December 31, 2017 2016 Beginning QF liability $ 134,324 $ 138,310 Unrecovered amount (12,009 ) (14,829 ) Interest expense 10,471 10,843 Ending QF liability $ 132,786 $ 134,324
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 Obligation Recoverable Amounts Net 2018 76,703 58,401 18,302 2019 78,836 59,020 19,816 2020 80,984 59,647 21,337 2021 82,941 60,136 22,805 2022 84,948 60,639 24,309 Thereafter 403,009 327,773 75,236 Total $ 807,421 $ 625,616 $ 181,805

Segment and Related Informati45

Segment and Related Information (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Financial data for the business segments for the twelve months ended are as follows (in thousands): December 31, 2017 Electric Gas Other Eliminations Total Operating revenues $ 1,037,053 $ 268,599 $ — $ — $ 1,305,652 Cost of sales 334,029 76,320 — — 410,349 Gross margin 703,024 192,279 — — 895,303 Operating, general and administrative 223,474 81,620 43 — 305,137 Property and other taxes 127,391 35,214 9 — 162,614 Depreciation and depletion 136,556 29,548 33 — 166,137 Operating income (loss) 215,603 45,897 (85 ) — 261,415 Interest expense, net (82,454 ) (5,920 ) (3,889 ) — (92,263 ) Other income, net 3,984 1,985 950 — 6,919 Income tax (expense) benefit (7,424 ) (6,684 ) 740 — (13,368 ) Net income (loss) $ 129,709 $ 35,278 $ (2,284 ) $ — $ 162,703 Total assets $ 4,346,484 $ 1,071,847 $ 2,586 $ — $ 5,420,917 Capital expenditures $ 226,077 $ 50,361 $ — $ — $ 276,438 December 31, 2016 Electric Gas Other Eliminations Total Operating revenues $ 1,011,595 $ 245,652 $ — $ — $ 1,257,247 Cost of sales 332,817 68,156 — — 400,973 Gross margin 678,778 177,496 — — 856,274 Operating, general and administrative 216,736 86,713 (556 ) — 302,893 Property and other taxes 115,583 32,505 10 — 148,098 Depreciation and depletion 130,236 29,067 33 — 159,336 Operating income 216,223 29,211 513 — 245,947 Interest expense, net (86,038 ) (6,589 ) (2,343 ) — (94,970 ) Other income, net 3,246 1,329 973 — 5,548 Income tax benefits (expense) 7,392 (1,687 ) 1,942 — 7,647 Net income $ 140,823 $ 22,264 $ 1,085 $ — $ 164,172 Total assets $ 4,363,848 $ 1,129,355 $ 6,118 $ — $ 5,499,321 Capital expenditures $ 236,014 $ 51,887 $ — $ — $ 287,901 December 31, 2015 Electric Gas Other Eliminations Total Operating revenues $ 944,428 $ 269,871 $ — $ — $ 1,214,299 Cost of sales 281,251 91,613 — — 372,864 Gross margin 663,177 178,258 — — 841,435 Operating, general and administrative 233,416 84,219 (20,160 ) — 297,475 Property and other taxes 104,264 29,168 10 — 133,442 Depreciation and depletion 115,701 28,968 33 — 144,702 Operating income 209,796 35,903 20,117 — 265,816 Interest expense, net (79,044 ) (11,433 ) (1,676 ) — (92,153 ) Other income, net 6,300 1,821 (538 ) — 7,583 Income tax expense (19,950 ) (3,752 ) (6,335 ) — (30,037 ) Net income $ 117,102 $ 22,539 $ 11,568 $ — $ 151,209 Total assets $ 4,185,192 $ 1,072,613 $ 6,890 $ — $ 5,264,695 Capital expenditures $ 234,451 $ 49,254 $ — $ — $ 283,705

Quarterly Financial Data (Una46

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Amounts presented are in thousands, except per share data: 2017 First Second Third Fourth Operating revenues $ 367,312 $ 283,859 $ 309,933 $ 344,548 Operating income 85,144 43,695 61,546 71,030 Net income $ 56,567 $ 21,830 $ 36,412 $ 47,894 Average common shares outstanding 48,386 48,451 48,487 48,902 Income per average common share: Basic $ 1.17 $ 0.45 $ 0.75 $ 0.98 Diluted $ 1.17 $ 0.44 $ 0.75 $ 0.98 Dividends per share $ 0.525 $ 0.525 $ 0.525 $ 0.525 Stock price: High $ 59.41 $ 63.86 $ 61.80 $ 64.47 Low 55.65 58.16 56.87 56.44 Quarter-end close 58.70 61.02 56.94 59.70 2016 First Second Third Fourth Operating revenues $ 332,539 $ 293,120 $ 300,998 $ 330,590 Operating income 61,933 63,742 56,116 64,156 Net income (1) $ 39,867 $ 35,569 $ 44,605 $ 44,131 Average common shares outstanding 48,242 48,309 48,315 48,329 Income per average common share: Basic $ 0.83 $ 0.74 $ 0.92 $ 0.91 Diluted $ 0.82 $ 0.73 $ 0.92 $ 0.92 Dividends per share $ 0.50 $ 0.50 $ 0.50 $ 0.50 Stock price: High $ 62.22 $ 63.30 $ 63.75 $ 59.13 Low 52.16 55.34 56.18 53.85 Quarter-end close 61.75 63.07 57.53 56.87

Nature of Operations and Basi47

Nature of Operations and Basis of Consolidation (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)wattscustomers	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Number of customers | customers	718,300
Number of megawatts of qualifying facility | watts	35
Estimated aggregate gross contractual payments through 2024	$ 219.5
Variable interest entity, measure of activity, purchases	$ 16.3	$ 25.5	$ 24.3

Significant Accounting Polici48

Significant Accounting Policies Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)Months	Dec. 31, 2016USD ($)
Allowance for doubtful accounts receivable, current	$ 2.9	$ 2.9
Unbilled receivables,current	$ 89.1	$ 80.4
Number of months or less of maturity to be considered cash equivalent | Months	3

Significant Accounting Polici49

Significant Accounting Policies Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Materials and supplies	$ 34,630	$ 31,602
Storage gas and fuel	17,802	17,604
Total Inventory	$ 52,432	$ 49,206

Significant Accounting Polici50

Significant Accounting Policies Property plant equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Allowance for funds used during construction, rate	7.20%	7.20%	7.50%
AFUDC capitalized during period	$ 8.5	$ 7	$ 13.6
Property, plant and equipment, disclosure of composite depreciation rate for plant in service	3.00%	3.00%	3.30%
Minimum [Member] | Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	3 years
Maximum [Member] | Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	50 years

Significant Accounting Polici51

Significant Accounting Policies Other Noncurrent Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Future QF obligation, net	$ 132,786	$ 134,324
Pension and other employee benefits	111,202	120,122
Customer advances	45,376	40,209
Asset retirement obligations	39,286	39,402	$ 35,532
Environmental	29,326	30,501
Other	57,729	55,213
Total Noncurrent Liabilities	$ 415,705	$ 419,771

Significant Accounting Polici52

Significant Accounting Policies Supplemental Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Income taxes, cash paid (received)	$ 60	$ (2,922)	$ (1,284)
Interest, cash paid	82,692	84,953	81,572
Capital expenditures included in trade accounts payable	$ 15,848	$ 13,783	$ 12,834

Regulatory Matters (Details)

Regulatory Matters (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2017	Dec. 31, 2016
Dave Gates Generating Station [Member]
Regulatory Assets [Line Items]
Deferred revenue, refund payments	$ 27.3
Electric Supply Costs
Regulatory Assets [Line Items]
Disallowed electric tracker costs			$ 12.4
Montana Property Tax Tracker [Member]
Regulatory Assets [Line Items]
Disallowed property tax costs		$ 1.7

Regulatory Assets and Liabili54

Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Regulatory Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	$ 391,985	$ 652,984
Regulatory Assets [Member] | Income taxes
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	163,605	411,546
Regulatory Assets [Member] | Pension
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	115,504	127,133
Regulatory Assets [Member] | Deferred financing costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	37,090	24,810
Regulatory Assets [Member] | Employee related benefits
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	17,729	20,256
Regulatory Assets [Member] | Supply costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	$ 13,398	16,809
Regulatory assets, remaining amortization period	1 year
Regulatory Assets [Member] | State And Local Taxes And Fees
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	$ 10,896	17,838
Regulatory Assets [Member] | Environmental clean-up
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	12,399	13,601
Regulatory Assets [Member] | Distribution infrastructure projects
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	0	3,136
Regulatory Assets [Member] | Other
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	21,364	17,855
Regulatory Liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	433,043	422,586
Regulatory Liabilities [Member] | Removal cost
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	408,451	386,373
Regulatory Liabilities [Member] | Supply costs
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 10,357	14,041
Regulatory liability, remaining amortization period	1 year
Regulatory Liabilities [Member] | Gas storage sales
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 9,149	9,569
Regulatory liability, remaining amortization period	22 years
Regulatory Liabilities [Member] | Deferred Revenue
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 2,201	5,066
Regulatory liability, remaining amortization period	1 year
Regulatory Liabilities [Member] | State And Local Taxes And Fees
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 1,520	1,154
Regulatory liability, remaining amortization period	1 year
Regulatory Liabilities [Member] | Environmental clean-up
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 1,365	$ 6,383

Regulatory Assets and Liabili55

Regulatory Assets and Liabilities Narrative (Details)	12 Months Ended
	Dec. 31, 2017
Electric Supply Costs | Montana
Regulatory Assets And Liabilities [Line Items]
Percentage of interest earned on electric and natural gas supply costs	7.90%
Electric Supply Costs | South Dakota
Regulatory Assets And Liabilities [Line Items]
Percentage of interest earned on electric and natural gas supply costs	7.20%
Natural Gas Supply Costs | Montana
Regulatory Assets And Liabilities [Line Items]
Percentage of interest earned on electric and natural gas supply costs	7.00%
Natural Gas Supply Costs | 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 | Nebraska
Regulatory Assets And Liabilities [Line Items]
Percentage of interest earned on electric and natural gas supply costs	8.50%

Property, Plant and Equipment56

Property, Plant and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Land, land rights and easements	$ 148,507	$ 138,963
Buildings and improvements	242,038	225,003
Transmission, distribution and storage	3,163,463	2,933,788
Generation	1,187,346	1,167,525
Plant acquisition adjustment	685,417	685,417
Other	521,711	472,264
Construction work in progress	69,902	116,995
Total property, plant and equipment	6,018,384	5,739,955
Less accumulated depreciation	(1,660,119)	(1,525,063)
Net property, plant, and equipment	4,358,265	4,214,892
Property, plant, and equipment under capital leases	$ 17,500	19,300
Land and improvements [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	53 years
Land and improvements [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	96 years
Building and improvements [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	27 years
Building and improvements [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	64 years
Tranmission, distribution and storage[Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	15 years
Tranmission, distribution and storage[Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	85 years
Generation [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	25 years
Generation [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	50 years
Plant Acquisition adjustment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	25 years
Plant Acquisition adjustment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	50 years
Other [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	2 years
Other [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	45 years
Basin Capital Lease [Member]
Property, Plant and Equipment [Line Items]
Property, plant, and equipment under capital leases	$ 17,100	$ 19,100

Property, Plant and Equipment J

Property, Plant and Equipment Joint Ownership (Details) $ in Thousands	Dec. 31, 2017USD ($)plants	Dec. 31, 2016USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Number of joint ownership interests in electric generating plants | plants	4
Big Stone Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentages	23.40%	23.40%
Plant in service	$ 153,682	$ 153,623
Accumulated depreciation	$ 40,706	$ 38,894
Neal 4 Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentages	8.70%	8.70%
Plant in service	$ 60,859	$ 60,491
Accumulated depreciation	$ 30,446	$ 29,235
Coyote Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentages	10.00%	10.00%
Plant in service	$ 49,968	$ 50,802
Accumulated depreciation	$ 37,605	$ 37,099
Colstrip Unit 4 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentages	30.00%	30.00%
Plant in service	$ 307,712	$ 297,289
Accumulated depreciation	$ 85,481	$ 77,513

Asset Retirement Obligations Ro

Asset Retirement Obligations Rollforward (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at January 1,	$ 39,402	$ 35,532
Accretion expense	2,062	1,885
Liabilities incurred	0	164
Liabilities settled	(61)	0
Revision to cash flows	(2,117)	1,821
Liability at December 31,	$ 39,286	$ 39,402

Asset Retirement Obligations Na

Asset Retirement Obligations Narrative (Details)	Dec. 31, 2017USD ($)
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations no amounts are recognized related to Hydro	$ 0

Goodwill (Details)

Goodwill (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Line Items]
No impairment identified	$ 0
Goodwill	357,586,000	$ 357,586,000
Electric
Goodwill [Line Items]
Goodwill	243,558,000	243,558,000
Natural gas
Goodwill [Line Items]
Goodwill	$ 114,028,000	$ 114,028,000

Risk Management and Hedging A61

Risk Management and Hedging Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Physical purchase and sale of gas and electricity at fixed prices	$ 0	$ 0
Pre-tax gain on cash flow hedge from AOCL to be reclassified during next 12 months	600
No swaps outstanding, interest rate fair value derivatives	0	$ 0
Interest Rate Swap [Member]
Derivative [Line Items]
Pre-tax loss on cash flow hedges remaining in AOCL	16,500
Interest Rate Swap [Member] | Interest Expense [Member]
Derivative [Line Items]
Interest rate contracts, amount of gain reclassified from AOCL into income	$ 613

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Recurring Basis (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
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
Transfers into and out of Level 3	0	0
Fair Value, Measurements, Recurring [Member] | Total Net Fair Value
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	2,648	4,164
Rabbi trust investments	28,135	25,064
Total	30,783	29,228
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	2,648	4,164
Rabbi trust investments	28,135	25,064
Total	30,783	29,228
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
Total	0	0
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
Total	0	0
Margin Cash Collateral Offset | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	0	0
Rabbi trust investments	0	0
Total	$ 0	$ 0

Fair Value Measurements Fair 63

Fair Value Measurements Fair Value Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, carrying value	$ 1,793,416	$ 1,793,338
Long-term debt, fair value	$ 1,901,915	$ 1,852,052

Short-Term Borrowings and Cre64

Short-Term Borrowings and Credit Arrangements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Short-term Debt [Line Items]
Commercial Paper, Balance	$ 319,556	$ 300,811
Maximum aggregate amount issuable at any time under commercial paper program	$ 340,000
Short term borrowings maximum days outstanding	270
Short-term Debt [Member]
Short-term Debt [Line Items]
Commercial Paper, Balance	$ 319,600	$ 300,800
Commercial Paper, Interest Rate	1.75%	1.07%
Maximum short-term debt outstanding	$ 332,500	$ 300,800
Average short-term debt outstanding	$ 251,700	$ 210,700
Weighted average interest rate	1.35%	0.86%

Short Term Borrowings - Unsecur

Short Term Borrowings - Unsecured Revolving Line of Credit (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)numberofbanks	Dec. 31, 2016USD ($)
Amended Terms And Conditions [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 400
Line of credit facility, expiration date	Dec. 12, 2021
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 350
Letters of credit outstanding, amount	$ 0
Unsecured Revolving Line Of Credit [Member]
Line of Credit Facility [Line Items]
Number of institutions participating in the credit facility | numberofbanks	8
Number of institutions participating in the credit faciltiy pertaining to maximum contributory percentage | numberofbanks	1
Line of credit facility, maximum percentage of total availability provided by a single lender	16.00%
Commitment fees	$ 0.5	$ 0.4
Maximum ratio of indebtedness to net capital threshold percentage	65.00%
Unsecured Revolving Line Of Credit, Maximun Outstanding Under Accordian Feature [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 450
Eurodollar [Member] | Minimum [Member] | Unsecured Revolving Line Of Credit [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.875%
Eurodollar [Member] | Maximum [Member] | Unsecured Revolving Line Of Credit [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.75%

Long-Term Debt and Capital Le66

Long-Term Debt and Capital Leases Schedule of Debt (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt	$ 1,793,416	$ 1,793,338
Less current maturities	0	0
Long-term debt, excluding current maturities	1,793,416	1,793,338
Capital Lease
Total Capital Leases	24,346	26,325
Less current maturities	(2,133)	(1,979)
Capital lease obligations, noncurrent	22,213	24,346
Unsecured Debt | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Long-term debt	$ 0	0
Maturity date	Dec. 12, 2021
Secured Debt | South Dakota, 5.01%, Due 2025
Debt Instrument [Line Items]
Long-term debt	$ 64,000	64,000
Maturity date	May 1, 2025
Interest rate, stated percentage	5.01%
Secured Debt | South Dakota, 4.15%, Due 2042
Debt Instrument [Line Items]
Long-term debt	$ 30,000	30,000
Maturity date	Aug. 10, 2042
Interest rate, stated percentage	4.15%
Secured Debt | South Dakota, 4.30%, Due 2052
Debt Instrument [Line Items]
Long-term debt	$ 20,000	20,000
Maturity date	Aug. 10, 2052
Interest rate, stated percentage	4.30%
Secured Debt | South Dakota, 4.85% Due 2043
Debt Instrument [Line Items]
Long-term debt	$ 50,000	50,000
Maturity date	Dec. 19, 2043
Interest rate, stated percentage	4.85%
Secured Debt | South Dakota, 4.22% Due 2044
Debt Instrument [Line Items]
Long-term debt	$ 30,000	30,000
Maturity date	Dec. 19, 2044
Interest rate, stated percentage	4.22%
Secured Debt | South Dakota, 4.26% Due 2040
Debt Instrument [Line Items]
Long-term debt	$ 70,000	70,000
Maturity date	Sep. 29, 2040
Interest rate, stated percentage	4.26%
Secured Debt | South Dakota, 2.80%, Due 2026
Debt Instrument [Line Items]
Long-term debt	$ 60,000	$ 60,000
Maturity date	Jun. 15, 2026	Jun. 15, 2026
Interest rate, stated percentage	2.80%	2.80%
Secured Debt | South Dakota, 2.66%, Due 2026
Debt Instrument [Line Items]
Long-term debt	$ 45,000	$ 45,000
Maturity date	Sep. 30, 2026	Sep. 30, 2026
Interest rate, stated percentage	2.66%	2.66%
Secured Debt | Montana, 6.34%, Due 2019
Debt Instrument [Line Items]
Long-term debt	$ 0	$ 250,000
Maturity date	Apr. 1, 2019
Interest rate, stated percentage	6.34%
Secured Debt | Montana, 5.71%, Due 2039
Debt Instrument [Line Items]
Long-term debt	$ 55,000	55,000
Maturity date	Oct. 15, 2039
Interest rate, stated percentage	5.71%
Secured Debt | Montana, 5.01%, Due 2025
Debt Instrument [Line Items]
Long-term debt	$ 161,000	161,000
Maturity date	May 1, 2025
Interest rate, stated percentage	5.01%
Secured Debt | Montana, 4.15%, Due 2042
Debt Instrument [Line Items]
Long-term debt	$ 60,000	60,000
Maturity date	Aug. 10, 2042
Interest rate, stated percentage	4.15%
Secured Debt | Montana, 4.30%, Due 2052
Debt Instrument [Line Items]
Long-term debt	$ 40,000	40,000
Maturity date	Aug. 10, 2052
Interest rate, stated percentage	4.30%
Secured Debt | Montana 4.85%, Due 2043
Debt Instrument [Line Items]
Long-term debt	$ 15,000	15,000
Maturity date	Dec. 19, 2043
Interest rate, stated percentage	4.85%
Secured Debt | Montana 3.99% Due 2028
Debt Instrument [Line Items]
Long-term debt	$ 35,000	35,000
Maturity date	Dec. 19, 2028
Interest rate, stated percentage	3.99%
Secured Debt | Montana 4.176% Due 2044
Debt Instrument [Line Items]
Long-term debt	$ 450,000	450,000
Maturity date	Nov. 15, 2044
Interest rate, stated percentage	4.176%
Secured Debt | Montana 3.11%, Due 2025
Debt Instrument [Line Items]
Long-term debt	$ 75,000	75,000
Maturity date	Jul. 1, 2025
Interest rate, stated percentage	3.11%
Secured Debt | Montana 4.11%, Due 2045
Debt Instrument [Line Items]
Long-term debt	$ 125,000	125,000
Maturity date	Jul. 1, 2045
Interest rate, stated percentage	4.11%
Secured Debt | Montana 4.03%, Due 2047
Debt Instrument [Line Items]
Long-term debt	$ 250,000	0
Maturity date	Nov. 6, 2047
Interest rate, stated percentage	4.03%
Secured Debt | Montana 2.00% Due 2023
Debt Instrument [Line Items]
Long-term debt	$ 144,660	$ 144,660
Maturity date	Aug. 1, 2023	Aug. 1, 2023
Interest rate, stated percentage	2.00%	2.00%
Secured Debt | New Market Tax Credit Financing-1.146%, Due 2046
Debt Instrument [Line Items]
Long-term debt	$ 26,977	$ 26,977
Maturity date	Jul. 1, 2046
Interest rate, stated percentage	1.146%
Discount on Notes and Bonds and Debt Issuance Costs, Net
Debt Instrument [Line Items]
Discount on notes and bonds and debt issuance costs, net	$ (13,221)	$ (13,299)

Long-Term Debt and Capital Le67

Long-Term Debt and Capital Leases Schedule of Long-Term Debt (Details) - Secured Debt - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Montana 4.03%, Due 2047
Debt Instrument [Line Items]
Debt instrument, face amount	$ 250
Debt Instrument, issuance date	Nov. 6, 2017
Interest rate, stated percentage	4.03%
Maturity date	Nov. 6, 2047
Montana, 6.34%, Due 2019
Debt Instrument [Line Items]
Repurchased face amount, debt instrument	$ 250
Interest rate, stated percentage	6.34%
Maturity date	Apr. 1, 2019
Montana 2.00% Due 2023
Debt Instrument [Line Items]
Debt instrument, face amount		$ 144.7
Debt Instrument, issuance date		Aug. 11, 2016
Debt issued by third party		$ 144.7
Interest rate, stated percentage	2.00%	2.00%
Maturity date	Aug. 1, 2023	Aug. 1, 2023
Montana 4.65%, Due 2023
Debt Instrument [Line Items]
Repurchased face amount, debt instrument		$ 170.2
Interest rate, stated percentage	4.65%	4.65%
Maturity date	Aug. 1, 2023	Aug. 1, 2023
South Dakota, 2.80%, Due 2026
Debt Instrument [Line Items]
Debt instrument, face amount		$ 60
Debt Instrument, issuance date		Jun. 15, 2016
Interest rate, stated percentage	2.80%	2.80%
Maturity date	Jun. 15, 2026	Jun. 15, 2026
South Dakota, 6.05%, Due 2018
Debt Instrument [Line Items]
Repurchased face amount, debt instrument		$ 55
Interest rate, stated percentage	6.05%	6.05%
Maturity date	May 1, 2018	May 1, 2018
South Dakota, 2.66%, Due 2026
Debt Instrument [Line Items]
Debt instrument, face amount		$ 45
Interest rate, stated percentage	2.66%	2.66%
Maturity date	Sep. 30, 2026	Sep. 30, 2026

Long-Term Debt and Capital Le68

Long-Term Debt and Capital Leases Other Long-term Debt (Details) $ in Millions	1 Months Ended	3 Months Ended
	Jul. 31, 2021USD ($)	Sep. 30, 2014USD ($)numberofbanks
New Market Tax Credit [Member]
Debt Instrument [Line Items]
New Market Tax Credit (NMTC) financing		$ 27
New Market Tax Credit Financing
Debt Instrument [Line Items]
Number of loans related to NMTC | numberofbanks		2
Investments		$ 18.2
Investment in New Market Tax Credit Program		$ 8.8
Number of years subject to recapture		7 years
Scenario, Forecast [Member] | New Market Tax Credit Financing
Debt Instrument [Line Items]
Debt Instrument, decrease, forgiveness	$ 7.9

Long-Term Debt and Capital Le69

Long-Term Debt and Capital Leases (Details) $ in Millions	Dec. 31, 2017USD ($)
Maturities of Long-term Debt [Abstract]
2,018	$ 2.1
2,019	2.3
2,020	2.5
2,021	2.7
2,022	$ 2.9

Income Taxes Narrative (Details

Income Taxes Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Contingency [Line Items]
Federal statutory rate		35.00%	35.00%	35.00%
Other income tax benefit			$ 17
Tax benefit related to prior years			$ 12.5
Decrease in deferred tax liability due to federal rate change		$ 321
Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Earliest year subject to examination		2,000
Scenario, Forecast [Member]
Income Tax Contingency [Line Items]
Federal statutory rate	21.00%

Income Taxes Domestic Tax Compo

Income Taxes Domestic Tax Components (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Federal
Current	$ 806	$ 723	$ (3,527)
Deferred	17,378	(2,054)	33,031
Investment tax credits	166	(196)	(232)
State
Current	33	10	(90)
Deferred	(5,015)	(6,130)	855
Income Tax Expense (Benefit)	$ 13,368	$ (7,647)	$ 30,037

Income Taxes Effective Rate Rec

Income Taxes Effective Rate Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Federal statutory rate	35.00%	35.00%	35.00%
State income tax, net of federal provisions	(1.90%)	(2.40%)	0.10%
Flow-through repairs deductions	(17.30%)	(26.30%)	(13.30%)
Production tax credits	(6.30%)	(7.00%)	(3.20%)
Plant and depreciation of flow through items	(1.30%)	(2.90%)	(1.60%)
Share-based compensation	(0.20%)	(1.10%)	(0.00%)
Prior year permanent return to accrual adjustments	(0.30%)	(0.10%)	0.10%
Other, net	(0.10%)	(0.10%)	(0.50%)
Effective tax rate	7.60%	(4.90%)	16.60%
Income Before Income Taxes	$ 176,071	$ 156,525	$ 181,246
Income tax calculated at 35% federal statutory rate	61,625	54,784	63,436
State tax income, net of federal provisions	(3,258)	(3,714)	301
Flow-through repairs deductions	(30,490)	(41,111)	(24,079)
Production tax credits	(11,032)	(10,941)	(5,721)
Plant and depreciation of flow through items	(2,208)	(4,604)	(2,893)
Share-based compensation	(363)	(1,646)	0
Prior year permanent return to accrual adjustments	(629)	(128)	207
Other, net	(277)	(287)	(1,214)
Total reconciling items	(48,257)	(62,431)	(33,399)
Income Tax Expense (Benefit)	$ 13,368	$ (7,647)	$ 30,037

Income Taxes Deferred Tax Liabi

Income Taxes Deferred Tax Liability (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred Tax Assets, [Abstract]
NOL carryforward	$ 68,840	$ 72,964
Production tax credit	28,067	17,034
Pension / postretirement benefits	26,887	45,847
AMT credit carryforward	13,599	13,599
Compensation accruals	12,113	18,715
Customer advances	11,949	15,837
Unbilled revenue	5,944	12,743
Environmental liability	5,821	9,698
Interest rate hedges	4,323	7,192
Reserves and accruals	1,126	1,121
Property taxes	432	3,767
QF obligations	234	1,025
Regulatory liabilities	114	2,290
Other, net	1,138	3,173
Deferred Tax Asset	180,587	225,005
Deferred Tax Liabilities, [Abstract]
Excess tax depreciation	(356,938)	(459,588)
Goodwill amortization	(117,971)	(168,165)
Flow through depreciation	(45,998)	(160,604)
Regulatory assets	(409)	(12,230)
Deferred Tax Liability	(521,316)	(800,587)
Deferred Tax Liability, net	$ (340,729)	$ (575,582)

Income Taxes Operating Loss (De

Income Taxes Operating Loss (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Domestic Tax Authority [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforward	$ 420.8
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforward	315.7
Year 2031 [Member] | Domestic Tax Authority [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforwards, subject to expiration	$ 105.2
NOL carryforwards, expiration date	Dec. 31, 2031
Year 2033 [Member] | Domestic Tax Authority [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforwards, subject to expiration	$ 13.3
NOL carryforwards, expiration date	Dec. 31, 2033
Year 2034 [Member] | Domestic Tax Authority [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforwards, subject to expiration	$ 73.3
NOL carryforwards, expiration date	Dec. 31, 2034
Year 2036 [Member] | Domestic Tax Authority [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforwards, subject to expiration	$ 174.6
NOL carryforwards, expiration date	Dec. 31, 2036
Year 2037 [Member] | Domestic Tax Authority [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforwards, subject to expiration	$ 54.4
NOL carryforwards, expiration date	Dec. 31, 2037
Year 2018 [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforwards, subject to expiration	$ 67
NOL carryforwards, expiration date	Dec. 31, 2018
Year 2020 [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforwards, subject to expiration	$ 10.5
NOL carryforwards, expiration date	Dec. 31, 2020
Year 2021 [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforwards, subject to expiration	$ 58.3
NOL carryforwards, expiration date	Dec. 31, 2021
Year 2023 [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforwards, subject to expiration	$ 135.9
NOL carryforwards, expiration date	Dec. 31, 2023
Year 2024 [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforwards, subject to expiration	$ 44
NOL carryforwards, expiration date	Dec. 31, 2024

Income Taxes Uncertain Tax Posi

Income Taxes Uncertain Tax Positions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Contingency [Line Items]
Income tax penalties and interest expense	$ 800	$ 700
Accrual for interest and penalties	$ 1,500	700
Unrecognized tax benefit more likely than not percentage threshold	50.00%
Unrecognized tax benefits that would impact effective tax rate	$ 47,800	66,500
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits at January 1	88,429	92,387	$ 95,929
Gross increases - tax positions in prior period	0	0	44
Gross decreases - tax positions in prior period	(22,973)	0	(2,903)
Gross increases - tax positions in current period	0	0	494
Gross decreases - tax positions in current period	(7,983)	(3,958)	(1,177)
Lapse of statute of limitations	0	0	0
Unrecognized Tax Benefits at December 31	$ 57,473	$ 88,429	$ 92,387

Comprehensive Loss (Details)

Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Comprehensive Income (Loss), Before Tax [Abstract]
Foreign currency translation adjustment	$ (202)	$ 25	$ 558
Reclassification of net losses (gains) on derivative instruments	613	(2,169)	(1,125)
Postretirement medical liability adjustment	1,257	317	504
Other comprehensive income (loss)	1,668	(1,827)	(63)
Other Comprehensive Income (Loss), Tax [Abstract]
Foreign currency translation adjustment	0	0	0
Reclassification of net losses (gains) on derivative instruments	(242)	831	427
Postretirement medical liability adjustment	(484)	(122)	(194)
Other comprehensive income (loss)	(726)	709	233
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Foreign currency translation adjustment	(202)	25	558
Reclassification of net losses (gains) on derivative instruments	371	(1,338)	(698)
Postretirement medical liability adjustment	773	195	310
Other comprehensive income (loss)	942	(1,118)	$ 170
Accumulated Other Comprehensive Income, Net of Tax [Abstract]
Foreign currency translation	1,178	1,380
Derivative instruments designated as cash flow hedges	(9,981)	(10,352)
Pension and postretirement medical plans	31	(742)
Accumulated other comprehensive loss	$ (8,772)	$ (9,714)

Comprehensive Loss Components o

Comprehensive Loss Components of AOCI (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Beginning balance	$ (9,714)
Net current-period other comprehensive (loss) income	942	$ (1,118)	$ 170
Ending Balance	(8,772)	(9,714)
Total
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Beginning balance	(9,714)	(8,596)
Other comprehensive income before reclassifications	(202)	25
Amounts reclassified from AOCL	773	195
Net current-period other comprehensive (loss) income	942	(1,118)
Ending Balance	(8,772)	(9,714)	(8,596)
Total | Interest Expense [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amounts reclassified from AOCL	371	(1,338)
Foreign Currency Translation
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Beginning balance	1,380	1,355
Other comprehensive income before reclassifications	(202)	25
Amounts reclassified from AOCL	0	0
Net current-period other comprehensive (loss) income	(202)	25
Ending Balance	1,178	1,380	1,355
Foreign Currency Translation | Interest Expense [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amounts reclassified from AOCL	0	0
Pension and Postretirement Medical Plans
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Beginning balance	(742)	(937)
Other comprehensive income before reclassifications	0	0
Amounts reclassified from AOCL	773	195
Net current-period other comprehensive (loss) income	773	195
Ending Balance	31	(742)	(937)
Pension and Postretirement Medical Plans | Interest Expense [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amounts reclassified from AOCL	0	0
Interest Rate Derivative Instruments Designated as Cash Flow Hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Beginning balance	(10,352)	(9,014)
Other comprehensive income before reclassifications	0	0
Amounts reclassified from AOCL	0	0
Net current-period other comprehensive (loss) income	371	(1,338)
Ending Balance	(9,981)	(10,352)	$ (9,014)
Interest Rate Derivative Instruments Designated as Cash Flow Hedges | Interest Expense [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amounts reclassified from AOCL	$ 371	$ (1,338)

Employee Benefit Plans Benefit

Employee Benefit Plans Benefit Obligation And Funded Status (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Plan [Member]
Change in Benefit Obligation:
Obligation at beginning of period	$ 646,032	$ 628,883
Service cost	10,994	11,759
Interest cost	25,633	26,210
Actuarial loss (gain)	41,719	7,006
Settlements	0	0
Benefits Paid	(27,582)	(27,826)
Benefit Obligation at End of Period	696,796	646,032	$ 628,883
Change in Fair Value of Plan Assets:
Employer contributions	10,000	9,800	9,500
Amounts Recognized in the Balance Sheet Consist of:
Noncurrent asset	2,535	0
Total Assets	2,535	0
Current liability	0	0
Noncurrent liability	(112,823)	(121,395)
Total Liabilities	(112,823)	(121,395)
Net amount recognized	(110,288)	(121,395)
Amounts recognized in AOCL consist of:
Prior service cost	0	0
Net actuarial gain	0	0
Total	(105,549)	(127,962)
Plans with Benefit Obligations in Excess of Plan Assets [Abstract]
Projected benefit obligation	634,400	646,000
Accumulated benefit obligation	634,400	643,600
Fair value of plan assets	522,700	524,600
Pension Plan [Member] | Pension Costs [Member]
Amounts Recognized in Regulatory Assets Consist of:
Prior service (cost) credit	(4)	(9)
Net actuarial loss	(105,545)	(127,953)
Pension Plan [Member] | Changes Measurement [Member]
Change in Fair Value of Plan Assets:
Fair value of plan assets at beginning of period	524,637	500,044
Return on plan assets	80,253	39,719
Employer contributions	9,200	12,700
Benefits Paid	(27,582)	(27,826)
Fair value of plan assets at end of period	586,508	524,637	500,044
Funded Status	(110,288)	(121,395)
Other Postretirement Benefits Plan [Member]
Change in Benefit Obligation:
Obligation at beginning of period	26,217	28,652
Service cost	456	492
Interest cost	715	795
Actuarial loss (gain)	(1,884)	(71)
Settlements	390	390
Benefits Paid	(2,973)	(4,041)
Benefit Obligation at End of Period	22,921	26,217	28,652
Amounts Recognized in the Balance Sheet Consist of:
Noncurrent asset	5,061	0
Total Assets	5,061	0
Current liability	(3,353)	(1,789)
Noncurrent liability	(4,249)	(5,823)
Total Liabilities	(7,602)	(7,612)
Net amount recognized	(2,541)	(7,612)
Amounts recognized in AOCL consist of:
Prior service cost	(698)	(849)
Net actuarial gain	1,079	38
Total	8,601	6,438
Other Postretirement Benefits Plan [Member] | Pension Costs [Member]
Amounts Recognized in Regulatory Assets Consist of:
Prior service (cost) credit	9,955	11,988
Net actuarial loss	(1,735)	(4,739)
Other Postretirement Benefits Plan [Member] | Changes Measurement [Member]
Change in Fair Value of Plan Assets:
Fair value of plan assets at beginning of period	18,605	17,972
Return on plan assets	2,690	1,277
Employer contributions	2,058	3,397
Benefits Paid	(2,973)	(4,041)
Fair value of plan assets at end of period	20,380	18,605	$ 17,972
Funded Status	$ (2,541)	$ (7,612)

Employee Benefit Plans Net Peri

Employee Benefit Plans Net Periodic Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Plan [Member]
Components of Net Periodic Benefit Cost
Service cost		$ 10,994	$ 11,759
Interest cost		25,633	26,210
Recognized actuarial loss		(41,719)	(7,006)
Settlements		0	0
Net Periodic Costs [Member] | Pension Plan [Member]
Components of Net Periodic Benefit Cost
Service cost		10,994	11,759	$ 12,362
Interest cost		25,633	26,210	26,174
Expected return on plan assets		(23,964)	(28,248)	(31,561)
Amortization of prior service cost (credit)		4	246	246
Recognized actuarial loss		7,837	9,888	10,634
Settlements		0	0	0
Net Periodic Benefit Cost (Credit)		20,504	19,855	17,855
Net Periodic Costs [Member] | Other Pension, Postretirement and Supplemental Plans [Member]
Components of Net Periodic Benefit Cost
Service cost		456	492	526
Interest cost		715	795	786
Expected return on plan assets		(846)	(1,042)	(969)
Amortization of prior service cost (credit)		(1,882)	(1,882)	(1,882)
Recognized actuarial loss		318	315	385
Settlements		390	390	390
Net Periodic Benefit Cost (Credit)		$ (849)	$ (932)	$ (764)
Scenario, Forecast [Member] | Net Periodic Costs [Member] | Pension Plan [Member]
Components of Net Periodic Benefit Cost
Prior service credit (cost)	$ (4)
Scenario, Forecast [Member] | Net Periodic Costs [Member] | Other Pension, Postretirement and Supplemental Plans [Member]
Components of Net Periodic Benefit Cost
Prior service credit (cost)	1,882
Scenario, Forecast [Member] | Pension Costs [Member] | Pension Plan [Member]
Components of Net Periodic Benefit Cost
Accumulated loss	(4,286)
Scenario, Forecast [Member] | Pension Costs [Member] | Other Pension, Postretirement and Supplemental Plans [Member]
Components of Net Periodic Benefit Cost
Accumulated loss	$ 78

Employee Benefit Plans Actuaria

Employee Benefit Plans Actuarial Assumptions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Increase in projected benefit obligation due to change in discount rate		$ 43.6
Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected rate of return on assets		4.70%	5.80%	5.80%
Pension Plan [Member] | Nonunion [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Long-term rate of increase in compensation levels		2.89%	3.28%	3.58%
Pension Plan [Member] | Union [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Long-term rate of increase in compensation levels		2.03%	3.20%	3.50%
Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		3.50%	3.95%	4.15%
Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		3.60%	4.10%	4.30%
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected rate of return on assets		4.70%	5.80%	5.80%
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Health care cost trend rate assumed for next year		5.00%
Other Postretirement Benefits Plan [Member] | Nonunion [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Long-term rate of increase in compensation levels		2.89%	3.28%	3.58%
Other Postretirement Benefits Plan [Member] | Union [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Long-term rate of increase in compensation levels		2.03%	3.20%	3.50%
Other Postretirement Benefits Plan [Member] | Minimum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		3.20%	3.40%	3.60%
Other Postretirement Benefits Plan [Member] | Maximum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		3.30%	3.55%	3.75%
Scenario, Forecast [Member] | NorthWestern Corporation Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected rate of return on assets	4.47%
Scenario, Forecast [Member] | NorthWestern Energy Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected rate of return on assets	4.97%

Employee Benefit Plans Investme

Employee Benefit Plans Investment Strategy (Details)	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation of investments by plan	5.00%
Montana | Pension Plan [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	100.00%	100.00%
Montana | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	100.00%	100.00%
Montana | Cash and Cash Equivalents [Member] | Pension Plan [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	0.10%	0.00%
Montana | Cash and Cash Equivalents [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	1.50%	1.00%
Montana | Debt Securities [Member] | Pension Plan [Member] | Domestic [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation of investments by plan	55.00%	55.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	54.50%	53.40%
Montana | Debt Securities [Member] | Pension Plan [Member] | International [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation of investments by plan	4.00%	5.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	4.00%	4.60%
Montana | Debt Securities [Member] | Other Postretirement Benefits Plan [Member] | Domestic [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation of investments by plan	40.00%	40.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	35.20%	37.00%
Montana | Debt Securities [Member] | Other Postretirement Benefits Plan [Member] | International [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation of investments by plan	0.00%	0.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	0.00%	0.00%
Montana | Equity Securities [Member] | Pension Plan [Member] | Domestic [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation of investments by plan	16.50%	34.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	16.70%	36.00%
Montana | Equity Securities [Member] | Pension Plan [Member] | International [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation of investments by plan	24.50%	6.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	24.70%	6.00%
Montana | Equity Securities [Member] | Other Postretirement Benefits Plan [Member] | Domestic [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation of investments by plan	50.00%	50.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	53.40%	52.60%
Montana | Equity Securities [Member] | Other Postretirement Benefits Plan [Member] | International [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation of investments by plan	10.00%	10.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	9.90%	9.40%
South Dakota | Pension Plan [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	100.00%	100.00%
South Dakota | Cash and Cash Equivalents [Member] | Pension Plan [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	0.00%	0.10%
South Dakota | Debt Securities [Member] | Pension Plan [Member] | Domestic [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation of investments by plan	70.00%	65.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	70.00%	64.40%
South Dakota | Debt Securities [Member] | Pension Plan [Member] | International [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation of investments by plan	2.50%	5.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	2.50%	4.40%
South Dakota | Equity Securities [Member] | Pension Plan [Member] | Domestic [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation of investments by plan	11.00%	25.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	11.10%	26.00%
South Dakota | Equity Securities [Member] | Pension Plan [Member] | International [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Target allocation of investments by plan	16.50%	5.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	16.40%	5.10%

Employee Benefit Plans Cash Flo

Employee Benefit Plans Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension contributions	$ 9,200	$ 12,700	$ 10,200
Montana | Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension contributions	8,000	11,500	9,000
South Dakota | Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension contributions	$ 1,200	$ 1,200	$ 1,200

Employee Benefit Plans Estimate

Employee Benefit Plans Estimated Payments (Details) $ in Thousands	Dec. 31, 2017USD ($)
Pension Plan [Member]
Estimated Future Benefit Payments
2,018	$ 30,326
2,019	31,721
2,020	33,452
2,021	34,703
2,022	35,997
2023-2027	200,820
Other Pension, Postretirement and Supplemental Plans [Member]
Estimated Future Benefit Payments
2,018	3,353
2,019	2,927
2,020	2,714
2,021	2,502
2,022	2,254
2023-2027	$ 7,607

Employee Benefit Plans Narrativ

Employee Benefit Plans Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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%
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Matching employer contributions	$ 10	$ 9.8	$ 9.5

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense		$ 3.9	$ 5.3	$ 4.4
Compensation expense tax (expense) benefit	$ (1.8)	(0.4)	(1.8)	(1.8)
Compensation expense not yet recognized for nonvested awards		$ 5.5
Nonvested awards, total compensation cost not yet recognized, period for recognition		2 years
Shares vested in period, total fair value		$ 3.7	$ 3.5	$ 2.8
Share-based Compensation, Significant Assumptions
Risk-free interest rate		1.50%	0.85%
Expected life, in years		3 years	3 years
Expected volatility, minimum		17.00%	17.10%
Expected volatility, maximum		22.70%	22.10%
Dividend yield		3.70%	3.40%
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance and vesting period		3 years
Performance Shares [Member] | Minimum [Member]
Share-based Compensation, Significant Assumptions
Percent of shares issued based on company performance		0.00%
Performance Shares [Member] | Maximum [Member]
Share-based Compensation, Significant Assumptions
Percent of shares issued based on company performance		200.00%
Stock Compensation Plan [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance and vesting period		1 year
Stock Compensation Plan [Member] | Maximum [Member]
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
Deferred Stock Unit [Member]
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 | shares		54,920	28,338	35,030
Deferred stock units total compensation expense		$ 2.9	$ 2.4	$ 1.3
Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized | shares					600,000
Number of shares available for grant | shares		822,695

Stock-Based Compensation Nonves

Stock-Based Compensation Nonvested (Details) shares in Thousands	12 Months Ended
	Dec. 31, 2017$ / sharesshares
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Beginning nonvested grants (shares) | shares	175,257
Granted (shares) | shares	93,108
Vested (shares) | shares	(87,438)
Forfeited (shares) | shares	(5,459)
Remaining nonvested grants (shares) | shares	175,468
Beginning nonvested (weighted-average grant date fair value) | $ / shares	$ 46.35
Granted (weighted-average grant date fair value) | $ / shares	47.99
Vested (weighted-average grant date fair value) | $ / shares	42.47
Forfeited (weighted-average grant date fair value) | $ / shares	47.60
Remaining nonvested (weighted-average grant date fair value) | $ / shares	$ 49.11
Performance and vesting period	3 years
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) | shares	62,591
Granted (shares) | shares	13,394
Vested (shares) | shares	(8,445)
Forfeited (shares) | shares	0
Remaining nonvested grants (shares) | shares	67,540
Beginning nonvested (weighted-average grant date fair value) | $ / shares	$ 41.14
Granted (weighted-average grant date fair value) | $ / shares	52.20
Vested (weighted-average grant date fair value) | $ / shares	27.42
Forfeited (weighted-average grant date fair value) | $ / shares	0
Remaining nonvested (weighted-average grant date fair value) | $ / shares	$ 43.09
Performance and vesting period	5 years

Common Stock Common Stock (Deta

Common Stock Common Stock (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2017
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	200,000,000
Common stock, par or stated value per share	$ 0.01	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000	50,000,000
Preferred stock, par or stated value per share	$ 0.01	$ 0.01	$ 0.01
Common stock reserved for incentive plan awards	2,865,957	2,865,957
Net proceeds from sale of stock		$ 56,772	$ 2,345	$ 58,581
Shares paid for tax withholding		34,208	49,514
Equity Distribution Agreement [Member]
Class of Stock [Line Items]
Net proceeds from sale of stock	$ 48,900	$ 53,700
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs	$ 600	$ 800
Common stock average share price	$ 61.48	$ 61.30
Common Stock Aggregate Gross Sales Price Maximum					$ 100,000
Stock Issued During Period, Shares, Period Increase (Decrease)	805,169	888,938

Earnings Per Share (Details)

Earnings Per Share (Details) - shares	3 Months Ended									12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016		Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Basic computation	48,902,000	48,487,000	48,451,000	48,386,000	48,329,000	48,315,000	48,309,000	48,242,000		48,557,599		48,298,896	47,298,350
Performance share awards (1)								22,044	[1]	97,722	[1]	176,166
Diluted computation										48,655,321		48,475,062
[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. We adopted the provisions of ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, during the fourth quarter of 2016. Under this ASU, the assumed proceeds from applying the treasury stock method when computing earnings per share no longer includes the amount of excess tax benefits or deficiencies that used to be recognized as additional paid-in capital. This change in the treasury stock method was made on a prospective basis, with adjustments reflected as of January 1, 2016. The changes to the treasury stock method required by this ASU increased dilutive shares by 22,044 shares for the year ended December 31, 2016.

Commitments and Contingencies Q

Commitments and Contingencies Qualifying Facilities Liability (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Beginning QF liability	$ 134,324,000
Ending QF liability	$ 132,786,000	$ 134,324,000
Qualifying Facility Contracts [Member]
Long-term purchase commitment through year 2029	2029 years
Beginning QF liability	$ 134,324,000	138,310,000
Unrecovered amount	(12,009,000)	(14,829,000)
Interest expense	10,471,000	10,843,000
Ending QF liability	132,786,000	$ 134,324,000
Qualifying Facility Contracts [Member] | Minimum [Member]
Price per MWH of energy required to be purchased per QF agreement	61
Qualifying Facility Contracts [Member] | Maximum [Member]
Price per MWH of energy required to be purchased per QF agreement	136
Qualifying Facility Contracts [Member] | Gross Obligation [Member]
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
2,018	76,703,000
2,019	78,836,000
2,020	80,984,000
2,021	82,941,000
2,022	84,948,000
Thereafter	403,009,000
Contractual obligation related to QF's	807,421,000
Qualifying Facility Contracts [Member] | Recoverable Amounts [Member]
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
2,018	58,401,000
2,019	59,020,000
2,020	59,647,000
2,021	60,136,000
2,022	60,639,000
Thereafter	327,773,000
Contractual obligation related to QF's	625,616,000
Qualifying Facility Contracts [Member] | Net Amount [Member]
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
2,018	18,302,000
2,019	19,816,000
2,020	21,337,000
2,021	22,805,000
2,022	24,309,000
Thereafter	75,236,000
Contractual obligation related to QF's	$ 181,805,000

Commitments and Contingencies L

Commitments and Contingencies Long Term Supply and Capacity Purchase Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Purchased Coal and Natural Gas Supply And Natural Gas Transportation Contracts [Member]
Long-term Purchase Commitment [Line Items]
Long term purchase committments costs incurred	$ 228.4	$ 216.8	$ 241.6
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
2,018	190.6
2,019	179
2,020	134.8
2,021	113.9
2,022	116
Thereafter	$ 1,300
Purchased Coal and Natural Gas Supply And Natural Gas Transportation Contracts [Member] | Minimum [Member]
Long-term Purchase Commitment [Line Items]
Long term purchase commitments term	1 year
Purchased Coal and Natural Gas Supply And Natural Gas Transportation Contracts [Member] | Maximum [Member]
Long-term Purchase Commitment [Line Items]
Long term purchase commitments term	26
Hydroelectric License Commitments [Member]
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
Hydro MOU commitment	$ 20
Hydroelectric License Commitments [Member] | Minimum [Member]
Long-term Purchase Commitment [Line Items]
Long term purchase commitments term	2,018
Hydroelectric License Commitments [Member] | Maximum [Member]
Long-term Purchase Commitment [Line Items]
Long term purchase commitments term	2,040

Commitments and Contingencies E

Commitments and Contingencies Environmental Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Colstrip Unit 4 [Member]
Jointly owned utility plant, proportionate ownership share	30.00%	30.00%
Coyote Generating Facility [Member]
Jointly owned utility plant, proportionate ownership share	10.00%	10.00%
Environmental remediation obligations [Member]
Environmental remediation obligation, minimum	$ 26.7
Environmental remediation obligation, maximum	31.2
Accrual for environmental loss contingencies	30.3
Aberdeen South Dakota Site [Member] | Manufactured Gas Plants [Member]
Accrual for environmental loss contingencies	9.6
Environmental remediation obligation, to be incurred during next 5 years	$ 4.6
Number of years for environmental remediation obligation to be incurred	five
Combined Manufacturing Sites [Member] | Manufactured Gas Plants [Member]
Accrual for environmental loss contingencies	$ 23.5

Commitments and Contingencies92

Commitments and Contingencies Legal Proceedings (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2017
Refinery outage [Member]
Loss Contingencies [Line Items]
Plant outage number of days	9 days
Liability insurance coverage, retention amount		$ 2
Refinery outage [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Damages sought		84.9
Refinery outage [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Damages sought		95.6
Riverbed Rents [Member]
Loss Contingencies [Line Items]
Annual riverbed rent exposure		$ 7

Segment and Related Informati93

Segment and Related Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Operating revenues	$ 344,548	$ 309,933	$ 283,859	$ 367,312	$ 330,590	$ 300,998	$ 293,120	$ 332,539	$ 1,305,652	$ 1,257,247	$ 1,214,299
Cost of sales									410,349	400,973	372,864
Gross margin									895,303	856,274	841,435
Operating, general and administrative									305,137	302,893	297,475
Property and other taxes									162,614	148,098	133,442
Depreciation and depletion									166,137	159,336	144,702
Operating Income	71,030	61,546	43,695	85,144	64,156	56,116	63,742	61,933	261,415	245,947	265,816
Interest expense, net									(92,263)	(94,970)	(92,153)
Other income, net									6,919	5,548	7,583
Income tax (expense) benefit									(13,368)	7,647	(30,037)
Net Income	47,894	$ 36,412	$ 21,830	$ 56,567	44,131	$ 44,605	$ 35,569	$ 39,867	162,703	164,172	151,209
Total assets	5,420,917				5,499,321				5,420,917	5,499,321	5,264,695
Capital expenditures									276,438	287,901	283,705
Electric
Segment Reporting Information [Line Items]
Operating revenues									1,037,053	1,011,595	944,428
Cost of sales									334,029	332,817	281,251
Gross margin									703,024	678,778	663,177
Operating, general and administrative									223,474	216,736	233,416
Property and other taxes									127,391	115,583	104,264
Depreciation and depletion									136,556	130,236	115,701
Operating Income									215,603	216,223	209,796
Interest expense, net									(82,454)	(86,038)	(79,044)
Other income, net									3,984	3,246	6,300
Income tax (expense) benefit									(7,424)	7,392	(19,950)
Net Income									129,709	140,823	117,102
Total assets	4,346,484				4,363,848				4,346,484	4,363,848	4,185,192
Capital expenditures									226,077	236,014	234,451
Gas
Segment Reporting Information [Line Items]
Operating revenues									268,599	245,652	269,871
Cost of sales									76,320	68,156	91,613
Gross margin									192,279	177,496	178,258
Operating, general and administrative									81,620	86,713	84,219
Property and other taxes									35,214	32,505	29,168
Depreciation and depletion									29,548	29,067	28,968
Operating Income									45,897	29,211	35,903
Interest expense, net									(5,920)	(6,589)	(11,433)
Other income, net									1,985	1,329	1,821
Income tax (expense) benefit									(6,684)	(1,687)	(3,752)
Net Income									35,278	22,264	22,539
Total assets	1,071,847				1,129,355				1,071,847	1,129,355	1,072,613
Capital expenditures									50,361	51,887	49,254
Other Segments [Member]
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									43	(556)	(20,160)
Property and other taxes									9	10	10
Depreciation and depletion									33	33	33
Operating Income									(85)	513	20,117
Interest expense, net									(3,889)	(2,343)	(1,676)
Other income, net									950	973	(538)
Income tax (expense) benefit									740	1,942	(6,335)
Net Income									(2,284)	1,085	11,568
Total assets	2,586				6,118				2,586	6,118	6,890
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
Property and other taxes									0	0	0
Depreciation and depletion									0	0	0
Operating Income									0	0	0
Interest expense, net									0	0	0
Other income, net									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 (Una94

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenues	$ 344,548	$ 309,933	$ 283,859	$ 367,312	$ 330,590	$ 300,998	$ 293,120	$ 332,539	$ 1,305,652	$ 1,257,247	$ 1,214,299
Operating income	71,030	61,546	43,695	85,144	64,156	56,116	63,742	61,933	261,415	245,947	265,816
Net Income	$ 47,894	$ 36,412	$ 21,830	$ 56,567	$ 44,131	$ 44,605	$ 35,569	$ 39,867	$ 162,703	$ 164,172	$ 151,209
Average Common Shares Outstanding	48,902,000	48,487,000	48,451,000	48,386,000	48,329,000	48,315,000	48,309,000	48,242,000	48,557,599	48,298,896	47,298,350
Dividends per share	$ 0.525	$ 0.525	$ 0.525	$ 0.525	$ 0.50	$ 0.50	$ 0.50	$ 0.50	$ 2.10	$ 2	$ 1.92
Quarter-end close	59.70	56.94	61.02	58.70	56.87	57.53	63.07	61.75	59.70	56.87
Income per average common share
Net income basic	0.98	0.75	0.45	1.17	0.91	0.92	0.74	0.83	3.35	3.40	3.20
Net income diluted	0.98	0.75	0.44	1.17	0.92	0.92	0.73	0.82	$ 3.34	$ 3.39	$ 3.17
Maximum [Member]
Stock price	64.47	61.80	63.86	59.41	59.13	63.75	63.30	62.22
Minimum [Member]
Stock price	$ 56.44	$ 56.87	$ 58.16	$ 55.65	$ 53.85	$ 56.18	$ 55.34	$ 52.16

Quarterly Financial Data (Una95

Quarterly Financial Data (Unaudited) Narrative (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Effect of Fourth Quarter Events [Line Items]
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	$ 1.8	$ 0.4	$ 1.8	$ 1.8