NorthWestern (NWE) 10-Q 25 Apr 18 2018 Q1 Quarterly report Financial data

Document and Document Entity In

Document and Document Entity Information - USD ($)	3 Months Ended
	Mar. 31, 2018	Apr. 20, 2018	Dec. 31, 2017
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-Q
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		49,475,077
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 2,957,686,000

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues
Electric	$ 238,342,000	$ 266,239,000
Gas	103,160,000	101,073,000
Total Revenues	341,502,000	367,312,000
Operating Expenses
Cost of sales	96,077,000	119,817,000
Operating, general and administrative	74,345,000	78,334,000
Property and other taxes	42,813,000	39,928,000
Depreciation and depletion	43,755,000	41,461,000
Total Operating Expenses	256,990,000	279,540,000
Operating Income	84,512,000	87,772,000
Interest Expense, net	(22,970,000)	(23,400,000)
Other Expense, net	(1,129,000)	(1,128,000)
Income Before Income Taxes	60,413,000	63,244,000
Income Tax Expense	(1,914,000)	(6,677,000)
Net Income	$ 58,499,000	$ 56,567,000
Average Common Shares Outstanding	49,416,230	48,385,738
Basic Earnings per Average Common Share	$ 1.18	$ 1.17
Diluted Earnings per Average Common Share	1.18	1.17
Dividends Declared per Common Share	$ 0.550	$ 0.525

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Comprehensive Income (Loss)
Net Income	$ 58,499	$ 56,567
Other comprehensive income, net of tax:
Foreign currency translation	95	51
Reclassification of net losses on derivative instruments	113	93
Total Other Comprehensive Income	208	144
Comprehensive Income	$ 58,707	$ 56,711

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEET - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 4,742	$ 8,473
Restricted cash	6,158	3,556
Accounts receivable, net	170,270	182,282
Inventories	43,714	52,432
Regulatory assets	24,461	37,669
Other	8,689	11,947
Total current assets	258,034	296,359
Property, plant, and equipment, net	4,364,803	4,358,265
Goodwill	357,586	357,586
Regulatory assets	366,383	354,316
Other noncurrent assets	53,612	54,391
Total Assets	5,400,418	5,420,917
Current Liabilities:
Current maturities of capital leases	2,173	2,133
Short-term borrowings	0	319,556
Accounts payable	54,762	85,160
Accrued expenses	251,849	210,047
Regulatory liabilities	17,547	15,342
Total current liabilities	326,331	632,238
Long-term capital leases	21,660	22,213
Long-term debt	2,016,571	1,793,416
Deferred income taxes	354,792	340,729
Noncurrent regulatory liabilities	431,267	417,701
Other noncurrent liabilities	415,174	415,705
Total Liabilities	3,565,795	3,622,002
Commitments and Contingencies (Note 10)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 53,051,959 and 49,473,185 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	531	530
Treasury stock at cost	(95,872)	(96,376)
Paid-in capital	1,448,622	1,445,181
Retained earnings	492,049	458,352
Accumulated other comprehensive loss	(10,707)	(8,772)
Total Shareholders' Equity	1,834,623	1,798,915
Total Liabilities and Shareholders' Equity	$ 5,400,418	$ 5,420,917

CONDENSED CONSOLIDATED BALANCE5

CONDENSED CONSOLIDATED BALANCE SHEET PARENTHETICAL	Mar. 31, 2018$ / sharesshares
Common Stock, Par or Stated Value Per Share | $ / shares	$ 0.01
Common Stock, Shares Authorized	200,000,000
Common Stock, Shares, Issued	53,051,959
Common Stock, Shares, Outstanding	49,473,185
Preferred Stock, Par or Stated Value Per Share | $ / shares	$ 0.01
Preferred Stock, Shares Authorized	50,000,000
Preferred Stock, Shares Issued	0
Preferred Stock, Shares Outstanding	0

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
OPERATING ACTIVITIES:
Net Income	$ 58,499	$ 56,567
Items not affecting cash:
Depreciation and depletion	43,755	41,461
Amortization of debt issue costs, discount and deferred hedge gain	1,171	1,201
Stock-based compensation costs	2,496	2,332
Equity portion of allowance for funds used during construction	(618)	(984)
Loss (gain) on disposition of assets	15	(86)
Deferred income taxes	2,143	5,410
Changes in current assets and liabilities:
Accounts receivable	12,012	17,004
Inventories	8,718	6,929
Other current assets	3,258	2,386
Accounts payable	(21,605)	(15,806)
Accrued expenses	41,802	33,306
Regulatory assets	13,208	17,004
Regulatory liabilities	2,205	(7,330)
Other noncurrent assets	(1,505)	(3,301)
Other noncurrent liabilities	7,474	1,108
Cash Provided by Operating Activities	173,028	157,201
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(52,005)	(51,519)
Proceeds from sale of assets	0	76
Cash Used in Investing Activities	(52,005)	(51,443)
FINANCING ACTIVITIES:
Treasury stock activity	1,574	(872)
Dividends on common stock	(26,945)	(25,194)
Line of credit borrowings	578,000	0
Line of credit repayments	(355,000)	0
Repayments of short-term borrowings, net	(319,556)	(71,910)
Financing costs	(225)	(2)
Cash Used in Financing Activities	(122,152)	(97,978)
(Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash	(1,129)	7,780
Cash, Cash Equivalents, and Restricted Cash, beginning of period	12,029	9,505
Cash, Cash Equivalents, and Restricted Cash, end of period	10,900	17,285
Cash paid during the period for:
Income taxes	55	61
Interest	12,172	11,242
Significant non-cash transactions:
Capital expenditures included in accounts payable	$ 7,135	$ 6,788

CONSOLIDATED STATEMENTS OF SHAR

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY Statement - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]
Balance, shares at Dec. 31, 2016		51,958		3,626
Balance, beginning of period at Dec. 31, 2016	$ 1,676,227	$ 520	$ 1,384,271	$ (95,769)	$ 396,919	$ (9,714)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	56,567	0	0	0	56,567	0
Foreign currency translation adjustment	51	0	0	0	0	51
Reclassification of net losses on derivative instruments from OCI to net income, net of tax	93	$ 0	0	$ 0	0	93
Stock based compensation, shares		127		15
Stock based compensation, value	1,459	$ 1	2,929	$ (1,471)	0	0
Dividends on common stock	$ (25,194)	0	0	0	(25,194)	0
Dividends per share	$ 0.525
Balance, end of period at Mar. 31, 2017	$ 1,709,203	$ 521	1,387,200	$ (97,240)	428,292	(9,570)
Balance, shares at Mar. 31, 2017		52,085		3,641
Balance, shares at Dec. 31, 2017		52,981		3,609
Balance, beginning of period at Dec. 31, 2017	1,798,915	$ 530	1,445,181	$ (96,376)	458,352	(8,772)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	58,499	0	0	0	58,499	0
Foreign currency translation adjustment	95	0	0	0	0	95
Reclassification of net losses on derivative instruments from OCI to net income, net of tax	113	$ 0	0	$ 0	0	113
Stock based compensation, shares		71		(30)
Stock based compensation, value	1,817	$ 1	2,485	$ (669)	0	0
Issuance of shares		0
Issuance of shares, value	2,129	$ 0	956	$ 1,173	0	0
Issuance of shares, treasury stock				0
Dividends on common stock	$ (26,945)	0	0	$ 0	(26,945)	0
Dividends per share	$ 0.550
Balance, end of period at Mar. 31, 2018	$ 1,834,623	$ 531	1,448,622	$ (95,872)	492,049	(10,707)
Balance, shares at Mar. 31, 2018		53,052		3,579
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Reclassification of certain tax effects from AOCL	$ 0	$ 0	$ 0	$ 0	$ (2,143)	$ 2,143

Nature of Operations and Basis

Nature of Operations and Basis of Consolidation	3 Months Ended
	Mar. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block]	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. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (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 unaudited Condensed Consolidated Financial Statements (Financial Statements) reflect all adjustments (which unless otherwise noted are normal and recurring in nature) that are, in the opinion of management, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Events occurring subsequent to March 31, 2018 , have been evaluated as to their potential impact to the Financial Statements through the date of issuance. The Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, management believes that the condensed disclosures provided are adequate to make the information presented not misleading. Management recommends that these unaudited Financial Statements be read in conjunction with the audited financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2017 . 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 qualifying co-generation facilities and qualifying small power production facilities (QF). We identified one QF contract that may constitute a VIE. We entered into a 40 -year power purchase contract in 1984 with this 35 megawatt (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 megawatt hour (MWH). 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 $212.7 million through 2024 . Accounting Standards Adopted Revenue Recognition - In May 2014, the Financial Accounting Standards Board (FASB) issued accounting guidance on the recognition of revenue from contracts with customers, which supersedes 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 as of January 1, 2018, as required, and used the modified retrospective method of adoption, with no material impact on our financial statements or internal controls. 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. We completed a comprehensive review of contracts and their associated terms and conditions. Based on this analysis, we did not have a cumulative-effect adjustment to retained earnings at January 1, 2018. See Note 2 - Revenue from Contracts with Customers, for additional disclosures including revenue recognition policies and our disaggregated revenue by segment for each geographical region. Retirement Benefits - On January 1, 2018, we adopted Accounting Standards Update (ASU) 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, as issued by the FASB. Under this ASU, companies are required to disaggregate the current service cost component from the other components of net periodic benefit cost and present it with other current compensation costs for related employees in the income statement and present the other components elsewhere in the income statement and outside of income from operations. In addition, only the service cost component of net periodic benefit cost is eligible for capitalization. ASU 2017-07 was applied on a modified retrospective basis for the presentation of the other components of net periodic benefit cost in the Condensed Consolidated Statements of Income. Using the allowed practical expedient, we applied the amounts disclosed in the “Employee Benefit Plans” note to the 2017 Consolidated Financial Statements for the restatement of comparative information. The impact of the adoption of this guidance resulted in the reclassification of the other components of net benefit cost from operating, general, and administrative expense to other expense, net in the Condensed Consolidated Statements of Income. The following table summarizes the adjustments made to conform prior period classifications to the new guidance (in thousands): Three Months Ended March 31, 2017 As Reported Effect of Accounting Change As Adjusted Operating, general and administrative $ 80,962 $ (2,628 ) $ 78,334 Other Income (Expense), net 1,500 (2,628 ) (1,128 ) As Reported Effect of Accounting Change As Adjusted Year Ended December 31, 2017 Operating, general and administrative $ 305,137 $ (10,334 ) $ 294,803 Other Income (Expense), net 6,919 (10,334 ) (3,415 ) Year Ended December 31, 2016 Operating, general and administrative $ 302,893 $ (9,030 ) $ 293,863 Other Income (Expense), net 5,548 (9,030 ) (3,482 ) Year Ended December 31, 2015 Operating, general and administrative $ 297,475 $ (6,757 ) $ 290,718 Other Income (Expense), net 7,583 (6,757 ) 826 ASU 2017-07 was applied prospectively for the capitalization of related costs in assets and did not have a material impact. 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. 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. We adopted this standard as of January 1, 2018, with no material impact to our Condensed Consolidated Statements of Cash Flows, and although the guidance requires retrospective treatment, we did not have any cash receipts or payments during the prior year that needed to be reclassified. 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. Amounts generally described as restricted cash should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. We adopted this standard as of January 1, 2018 with retrospective application. For the three months ended March 31, 2017 , this change resulted in a $4.4 million increase and a $4.9 million increase in cash, cash equivalents and restricted cash at the beginning and end of the period on our Condensed Consolidated Statements of Cash Flows, respectively. In addition, removing the change in restricted cash from operating activities in the Condensed Consolidated Statements of Cash Flows resulted in an increase of $0.4 million in our cash provided by operating activities for the three months ended March 31, 2017 . The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the Condensed Consolidated Balance Sheets that sum to the total of the same such amounts shown in the Condensed Consolidated Statements of Cash Flows (in thousands): March 31, 2018 December 31, 2017 March 31, 2017 December 31, 2016 December 31, 2015 Cash and cash equivalents $ 4,742 $ 8,473 $ 12,433 $ 5,079 $ 11,980 Restricted cash 6,158 3,556 4,852 4,426 6,634 Total cash, cash equivalents, and restricted cash shown in the Condensed Consolidated Statements of Cash Flows $ 10,900 $ 12,029 $ 17,285 $ 9,505 $ 18,614 Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements. Stranded Tax Effects in Accumulated Other Comprehensive Loss - In February 2018, the FASB issued guidance to allow a one-time reclassification from accumulated other comprehensive loss (AOCL) to retained earnings for stranded tax effects resulting from the new tax reform legislation. The amount of the reclassification is calculated on the basis of the difference between the historical and newly enacted tax rates for deferred tax liabilities and assets related to items within AOCL. This amendment is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Early adoption is permitted, including adoption in any interim reporting period for which financial statements have not yet been issued. We early adopted this guidance during the first quarter of 2018, through a reclassification of $2.1 million of stranded tax effects from AOCL to retained earnings. Adoption of this guidance did not have a material impact on our condensed consolidated financial position, results of operations or cash flows. Accounting Standards Issued 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 Financial Statements and disclosures other than an expected increase in assets and liabilities.

Revenue from Contracts with Cus

Revenue from Contracts with Customers (Notes)	3 Months Ended
	Mar. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	Revenue from Contracts with Customers Accounting Policy Our revenues are primarily from tariff based sales. 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. 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. Nature of Goods and Services We currently provide retail electric and natural gas services to three primary customer classes. Our largest customer class consists of residential customers, which include single private dwellings and individual apartments. Our commercial customers consist primarily of main street businesses, and our industrial customers consist primarily of manufacturing and processing businesses that turn raw materials into products. Electric Segment - Our regulated electric utility business primarily provides generation, transmission, and distribution services to our customers in our Montana and South Dakota jurisdictions. We transfer control and recognize revenue when electricity is delivered to the customer. Payments on our tariff based sales are generally due in 20 - 30 days after the billing date. Natural Gas Segment - Our regulated natural gas utility business primarily provides production, storage, transmission and distribution services to our customers in our Montana, South Dakota, and Nebraska jurisdictions. We transfer control and recognize revenue when natural gas is delivered to the customer. Payments on our tariff based sales are generally due in 20 - 30 days after the billing date. Disaggregation of Revenue The following table disaggregates our revenue by major source and customer class (in millions): Three Months Ended March 31, 2018 March 31, 2017 Electric Natural Gas Total Electric Natural Gas Total Montana $ 87.2 $ 40.9 $ 128.1 $ 90.8 $ 43.8 $ 134.6 South Dakota 18.7 11.4 30.1 17.3 10.8 28.1 Nebraska — 11.4 11.4 — 9.0 9.0 Residential 105.9 63.7 169.6 108.1 63.6 171.7 Montana 83.6 20.6 104.2 88.1 21.9 110.0 South Dakota 24.0 7.9 31.9 22.4 7.4 29.8 Nebraska — 6.1 6.1 — 4.9 4.9 Commercial 107.6 34.6 142.2 110.5 34.2 144.7 Industrial 10.8 0.5 11.3 10.9 0.5 11.4 Lighting, Governmental, and Irrigation 5.0 0.5 5.5 5.2 0.5 5.7 Total Customer Revenues 229.3 99.3 328.6 234.7 98.8 333.5 Other Tariff and Contract Based Revenues 17.8 10.3 28.1 37.4 11.1 48.5 Total Revenue from Contracts with Customers 247.1 109.6 356.7 272.1 109.9 382.0 Regulatory amortization (8.8 ) (6.4 ) (15.2 ) (5.9 ) (8.8 ) (14.7 ) Total Revenues $ 238.3 $ 103.2 $ 341.5 $ 266.2 $ 101.1 $ 367.3

Regulatory Matters

Regulatory Matters	3 Months Ended
	Mar. 31, 2018
Regulated Operations [Abstract]
Public Utilities Disclosure [Text Block]	Regulatory Matters Tax Cuts and Jobs Act In December 2017, H.R.1 (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. Each of our regulatory jurisdictions initiated dockets regarding the impact of the Tax Cuts and Jobs Act on customer rates. Our Montana and South Dakota jurisdictional filings are discussed below. We do not expect the required FERC or Nebraska filings to be significant. In each of our jurisdictions, we expect the Tax Cuts and Jobs Act related credits to continue and be subject to true-up until base rates are reset in a general rate case filing. As of March 31, 2018, we have deferred revenue of approximately $7.3 million associated with the impacts of the Tax Cuts and Jobs Act. This estimate is based upon an expected annual revenue reduction of approximately $15 million to $20 million , which is our expected income tax expense reduction in 2018. For purposes of the filings discussed below, we have also calculated the customer benefit using an alternate method based on historic test periods. This alternate calculation could result in an additional reduction in revenue ranging from approximately $8 million to $12 million , which would reduce net income. We cannot predict how each jurisdiction may calculate the amount of credits due to customers. Montana - In March 2018, we submitted a filing to the Montana Public Service Commission (MPSC) calculating the estimated benefit of the Tax Cuts and Jobs Act related savings to customers using two alternative methods. The first method was calculated based on the expected income tax expense reduction in 2018, with no impact to net income. The second method, was calculated by revising the electric and natural gas revenue requirements in the last applicable test years. For our electric customers, we proposed to use 50% of the benefit as a direct refund to customers, and to use the other 50% to remove trees outside our electric transmission and distribution lines rights of way, which pose a risk of unfavorable events on our system including disruption of service, property damage, and / or forest fires. For our natural gas customers, we proposed to use the benefit as a direct refund to customers. A procedural schedule has not been established in this docket. South Dakota - In April 2018, we submitted a filing with the South Dakota Public Utilities Commission (SDPUC) calculating the estimated benefit of the Tax Cuts and Jobs Act related savings to customers based on the expected income tax expense reduction in 2018, with no impact to net income. We also presented a calculation revising the electric and natural gas revenue requirements in the last applicable test years. We proposed to either refund the benefit to customers, or to hold this amount in a regulatory liability to provide rate moderation in our next electric and natural gas rate cases, at the SDPUC’s option. The SDPUC has not established a procedural schedule in this docket. Montana QF Tariff Filing Under the Public Utility Regulatory Policies Act (PURPA), electric utilities are required, with certain 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. We, as well as the QFs, sought judicial review of the November 2017 order. 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 order, as we have significant generation capacity deficits and negative reserve margins, and our 2015 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 transmission-related 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 Power Cost and Credit Adjustment Mechanism (PCCAM). In December 2017, after the intervenors filed testimony, 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 testimony in February 2018, responsive to both the intervenors' testimony and the MPSC's Notice of Additional Issues addressing alternative risk-sharing mechanisms. Intervenors filed testimony on the Notice of Additional Issues in March 2018. 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 current-period 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 consolidated 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 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. 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 nine months. The second order (2015 Tracker), included a disallowance of approximately $0.4 million of 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. In March 2018, the Montana District Court upheld our appeal of the disallowance of these costs. The Court remanded the matter to the MPSC and directed the MPSC to issue an order to restore the modeling costs to the deferred account from which the MPSC ordered it be removed. On April 10, 2018, the MPSC voted not to appeal the Montana District Court’s decision. 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. In January 2018, the MPSC issued an order in our 2017 filing applying an alternate allocation methodology both prospectively and retroactively, which reduces our annual recovery of these taxes by approximately $1.7 million . The change in methodology results in a lower property tax allocation to our Montana electric retail customers and a higher property tax allocation to Federal Energy Regulatory Commission (FERC) transmission customers (we do not have a property tax tracker for FERC jurisdictional purposes). We sought reconsideration of the retroactive application of this change in methodology. On April 5, 2018, the MPSC voted to apply the change on a prospective basis only. We expect to receive a written order during the second quarter of 2018. 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). In March 2018, the D.C. Circuit denied all of our requests.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	Income Taxes The primary impact of the Tax Cuts and Jobs Act is a reduction of the federal corporate income tax rate from 35% to 21% effective January 1, 2018. We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate 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 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. We revalued our deferred tax assets and liabilities as of December 31, 2017, which reflected our estimate of the impact of the Tax Cuts and Jobs Act. We will continue to evaluate subsequent regulations, clarifications and interpretations with the assumptions made, which could materially change our estimate. The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rate (in thousands): Three Months Ended March 31, 2018 2017 Income Before Income Taxes $ 60,413 $ 63,244 Income tax calculated at federal statutory rate 12,687 21.0 % 22,135 35.0 % Permanent or flow through adjustments: State income, net of federal provisions 732 1.2 (834 ) (1.3 ) Flow-through repairs deductions (6,586 ) (10.9 ) (8,797 ) (13.9 ) Production tax credits (3,888 ) (6.4 ) (3,831 ) (6.1 ) Plant and depreciation of flow through items (916 ) (1.6 ) (1,440 ) (2.3 ) Share-based compensation 275 0.5 (399 ) (0.6 ) Other, net (390 ) (0.6 ) (157 ) (0.2 ) (10,773 ) (17.8 ) (15,458 ) (24.4 ) Income Tax Expense $ 1,914 3.2 % $ 6,677 10.6 % 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. We have unrecognized tax benefits of approximately $56.5 million as of March 31, 2018 , including approximately $47.7 million that, if recognized, would impact our 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 three months ended March 31, 2018 and 2017 , we recognized $0.3 million and $0.1 million , respectively, of expense for interest and penalties in the Condensed Consolidated Statements of Income. As of March 31, 2018 and December 31, 2017 , we had $1.7 million and $1.5 million , respectively, of interest accrued in the Condensed Consolidated Balance Sheets. Our federal tax returns from 2000 forward remain subject to examination by the IRS.

Goodwill

Goodwill	3 Months Ended
	Mar. 31, 2018
Goodwill [Abstract]
Goodwill Disclosure [Text Block]	Goodwill There were no changes in our goodwill during the three months ended March 31, 2018 . Goodwill by segment is as follows for both March 31, 2018 and December 31, 2017 (in thousands): Electric $ 243,558 Natural gas 114,028 Total $ 357,586

Comprehensive Income (Loss)

Comprehensive Income (Loss)	3 Months Ended
	Mar. 31, 2018
Statement of Comprehensive Income [Abstract]
Comprehensive Income (Loss) Note [Text Block]	Comprehensive Income The following tables display the components of Other Comprehensive Income, after-tax, and the related tax effects (in thousands): Three Months Ended March 31, 2018 March 31, 2017 Before-Tax Amount Tax Expense Net-of-Tax Amount Before-Tax Amount Tax Expense Net-of-Tax Amount Foreign currency translation adjustment $ 95 $ — $ 95 $ 51 $ — $ 51 Reclassification of net losses on derivative instruments 153 (40 ) 113 153 (60 ) 93 Other comprehensive income $ 248 $ (40 ) $ 208 $ 204 $ (60 ) $ 144 Balances by classification included within accumulated other comprehensive loss (AOCL) on the Condensed Consolidated Balance Sheets are as follows, net of tax (in thousands): March 31, 2018 December 31, 2017 Foreign currency translation $ 1,273 $ 1,178 Derivative instruments designated as cash flow hedges (9,868 ) (9,981 ) Reclassification of certain tax effects from AOCL (2,143 ) — Postretirement medical plans 31 31 Accumulated other comprehensive loss $ (10,707 ) $ (8,772 ) The following tables display the changes in AOCL by component, net of tax (in thousands): Three Months Ended March 31, 2018 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (9,981 ) $ 31 $ 1,178 $ (8,772 ) Other comprehensive income before reclassifications — — 95 95 Amounts reclassified from AOCL Interest Expense 113 — — 113 Net current-period other comprehensive income 113 — 95 208 Reclassification of certain tax effects from AOCL (2,150 ) 7 — (2,143 ) Ending balance $ (12,018 ) $ 38 $ 1,273 $ (10,707 ) Three Months Ended March 31, 2017 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (10,352 ) $ (742 ) $ 1,380 (9,714 ) Other comprehensive income before reclassifications — — 51 51 Amounts reclassified from AOCL Interest Expense 93 — — 93 Net current-period other comprehensive income 93 — 51 144 Ending balance $ (10,259 ) $ (742 ) $ 1,431 $ (9,570 )

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2018
Segment Reporting Information [Line Items]
Segment Reporting Disclosure [Text Block]	Segment 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 are as follows (in thousands): Three Months Ended March 31, 2018 Electric Gas Other Eliminations Total Operating revenues $ 238,342 $ 103,160 $ — $ — $ 341,502 Cost of sales 57,273 38,804 — — 96,077 Gross margin 181,069 64,356 — — 245,425 Operating, general and administrative 54,648 21,219 (1,522 ) — 74,345 Property and other taxes 33,493 9,318 2 — 42,813 Depreciation and depletion 36,153 7,594 8 — 43,755 Operating income 56,775 26,225 1,512 — 84,512 Interest expense (19,520 ) (1,854 ) (1,596 ) — (22,970 ) Other income (expense) 490 108 (1,727 ) — (1,129 ) Income tax (expense) benefit (498 ) (2,226 ) 810 — (1,914 ) Net income (loss) $ 37,247 $ 22,253 $ (1,001 ) $ — $ 58,499 Total assets $ 4,319,798 $ 1,065,103 $ 15,517 $ — $ 5,400,418 Capital expenditures $ 42,898 $ 9,107 $ — $ — $ 52,005 Three Months Ended March 31, 2017 Electric Gas Other Eliminations Total Operating revenues $ 266,239 $ 101,073 $ — $ — $ 367,312 Cost of sales 85,385 34,432 — — 119,817 Gross margin 180,854 66,641 — — 247,495 Operating, general and administrative (1) 56,720 20,900 714 — 78,334 Property and other taxes 31,161 8,764 3 — 39,928 Depreciation and depletion 34,070 7,383 8 — 41,461 Operating income (loss) 58,903 29,594 (725 ) — 87,772 Interest expense (21,037 ) (1,546 ) (817 ) — (23,400 ) Other (expense) income (1) (1,193 ) (501 ) 566 — (1,128 ) Income tax (expense) benefit (2,887 ) (6,951 ) 3,161 — (6,677 ) Net income $ 33,786 $ 20,596 $ 2,185 $ — $ 56,567 Total assets $ 4,388,267 $ 1,106,062 $ 5,972 $ — $ 5,500,301 Capital expenditures $ 41,041 $ 10,478 $ — $ — $ 51,519 ______________ (1) We adopted ASU 2017-07 on January 1, 2018. As a result, we recorded the non-service cost component of net periodic benefit cost within other expense, net. We adopted this standard retrospectively and $1.9 million and $0.7 million , respectively, were reclassified from electric and gas operating, general and administrative expenses to other expense, net for the three months ended March 31, 2017 , to conform to current period presentation.

Earnings Per Share

Earnings Per Share	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Earnings Per Share [Text Block]	Earnings Per Share Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution of common stock equivalent shares that could occur if all 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 performance share awards. Average shares used in computing the basic and diluted earnings per share are as follows: Three Months Ended March 31, 2018 March 31, 2017 Basic computation 49,416,230 48,385,738 Dilutive effect of: Performance share awards (1) 67,622 117,658 Diluted computation 49,483,852 48,503,396 _______ (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. The dilutive share calculation for 2018 excludes 34,913 shares under outstanding performance share awards because the inclusion of these awards would have been antidilutive under the treasury stock method.

Employee Benefit Plans

Employee Benefit Plans	3 Months Ended
	Mar. 31, 2018
Retirement Benefits [Abstract]
Pension and Other Postretirement Benefits Disclosure [Text Block]	Employee Benefit Plans We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for eligible employees. Net periodic benefit cost (income) for our pension and other postretirement plans consists of the following (in thousands): Pension Benefits Other Postretirement Benefits Three Months Ended March 31, Three Months Ended March 31, 2018 2017 2018 2017 Components of Net Periodic Benefit Cost (Income) Service cost $ 3,204 $ 3,130 $ 112 $ 128 Interest cost 6,108 6,429 147 180 Expected return on plan assets (7,060 ) (6,008 ) (239 ) (213 ) Amortization of prior service cost 1 2 (471 ) (471 ) Recognized actuarial loss 1,072 1,975 (20 ) 78 Net Periodic Benefit Cost (Income) $ 3,325 $ 5,528 $ (471 ) $ (298 ) We adopted ASU 2017-07 on January 1, 2018. As a result, we recorded the non-service cost component of net periodic benefit cost within other expense, net. This standard requires retrospective adoptions, which resulted in a $2.6 million reclassification from operating, general and administrative expenses to other expense, net for the three months ended March 31, 2017 , to conform to current period presentation.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure [Text Block]	Commitments and Contingencies 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 and $31.2 million . As of March 31, 2018 , we have a reserve of approximately $30.0 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 $23.2 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 March 31, 2018 , the reserve for remediation costs at this site is approximately $9.4 million , and we estimate that approximately $4.4 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 second 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 greenhouse gas (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 CO 2 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, petitions for review were filed in the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), including a petition by us. The United States Supreme Court (Supreme Court) issued a stay pending resolution of the case by the D.C. Circuit. Following issuance of the Executive Order, the EPA has requested the D.C. Circuit to hold the case in abeyance. The D.C. Circuit has incrementally granted those requests, most recently in an order issued on March 1, 2018, holding the case in abeyance for 60 days. 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 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. While 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 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 seek enforcement and/or damages related to four of the 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 those 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 Litigation 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 plaintiffs allege 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 plaintiffs also seek 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 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 and set deadlines for answers and dispositive motions. On November 11, 2017, Mr. Wilde died in a farming accident, and, at plaintiffs’ request, the Eighth District Court has stayed the proceeding through May 11, 2018. 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.

Nature of Operations and Basi18

Nature of Operations and Basis of Consolidation Cash, Cash Equivalents, and Restricted Cash (Tables)	3 Months Ended
	Mar. 31, 2018
Cash, Cash Equivalents, and Restricted Cash [Abstract]
Cash and Cash Equivalents Disclosure [Text Block]	The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the Condensed Consolidated Balance Sheets that sum to the total of the same such amounts shown in the Condensed Consolidated Statements of Cash Flows (in thousands): March 31, 2018 December 31, 2017 March 31, 2017 December 31, 2016 December 31, 2015 Cash and cash equivalents $ 4,742 $ 8,473 $ 12,433 $ 5,079 $ 11,980 Restricted cash 6,158 3,556 4,852 4,426 6,634 Total cash, cash equivalents, and restricted cash shown in the Condensed Consolidated Statements of Cash Flows $ 10,900 $ 12,029 $ 17,285 $ 9,505 $ 18,614 Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements.

Nature of Operations and Basi19

Nature of Operations and Basis of Consolidation Retirement Benefits (Tables)	3 Months Ended
	Mar. 31, 2018
Income Statement [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	The following table summarizes the adjustments made to conform prior period classifications to the new guidance (in thousands): Three Months Ended March 31, 2017 As Reported Effect of Accounting Change As Adjusted Operating, general and administrative $ 80,962 $ (2,628 ) $ 78,334 Other Income (Expense), net 1,500 (2,628 ) (1,128 ) As Reported Effect of Accounting Change As Adjusted Year Ended December 31, 2017 Operating, general and administrative $ 305,137 $ (10,334 ) $ 294,803 Other Income (Expense), net 6,919 (10,334 ) (3,415 ) Year Ended December 31, 2016 Operating, general and administrative $ 302,893 $ (9,030 ) $ 293,863 Other Income (Expense), net 5,548 (9,030 ) (3,482 ) Year Ended December 31, 2015 Operating, general and administrative $ 297,475 $ (6,757 ) $ 290,718 Other Income (Expense), net 7,583 (6,757 ) 826

Revenue from Contracts with C20

Revenue from Contracts with Customers Disaggregation of Revenue (Tables)	3 Months Ended
	Mar. 31, 2018
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	The following table disaggregates our revenue by major source and customer class (in millions): Three Months Ended March 31, 2018 March 31, 2017 Electric Natural Gas Total Electric Natural Gas Total Montana $ 87.2 $ 40.9 $ 128.1 $ 90.8 $ 43.8 $ 134.6 South Dakota 18.7 11.4 30.1 17.3 10.8 28.1 Nebraska — 11.4 11.4 — 9.0 9.0 Residential 105.9 63.7 169.6 108.1 63.6 171.7 Montana 83.6 20.6 104.2 88.1 21.9 110.0 South Dakota 24.0 7.9 31.9 22.4 7.4 29.8 Nebraska — 6.1 6.1 — 4.9 4.9 Commercial 107.6 34.6 142.2 110.5 34.2 144.7 Industrial 10.8 0.5 11.3 10.9 0.5 11.4 Lighting, Governmental, and Irrigation 5.0 0.5 5.5 5.2 0.5 5.7 Total Customer Revenues 229.3 99.3 328.6 234.7 98.8 333.5 Other Tariff and Contract Based Revenues 17.8 10.3 28.1 37.4 11.1 48.5 Total Revenue from Contracts with Customers 247.1 109.6 356.7 272.1 109.9 382.0 Regulatory amortization (8.8 ) (6.4 ) (15.2 ) (5.9 ) (8.8 ) (14.7 ) Total Revenues $ 238.3 $ 103.2 $ 341.5 $ 266.2 $ 101.1 $ 367.3

Income Taxes (Tables)

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The following table summarizes the significant differences in income tax expense based on the differences between our effective tax rate and the federal statutory rate (in thousands): Three Months Ended March 31, 2018 2017 Income Before Income Taxes $ 60,413 $ 63,244 Income tax calculated at federal statutory rate 12,687 21.0 % 22,135 35.0 % Permanent or flow through adjustments: State income, net of federal provisions 732 1.2 (834 ) (1.3 ) Flow-through repairs deductions (6,586 ) (10.9 ) (8,797 ) (13.9 ) Production tax credits (3,888 ) (6.4 ) (3,831 ) (6.1 ) Plant and depreciation of flow through items (916 ) (1.6 ) (1,440 ) (2.3 ) Share-based compensation 275 0.5 (399 ) (0.6 ) Other, net (390 ) (0.6 ) (157 ) (0.2 ) (10,773 ) (17.8 ) (15,458 ) (24.4 ) Income Tax Expense $ 1,914 3.2 % $ 6,677 10.6 %

Goodwill (Tables)

Goodwill (Tables)	3 Months Ended
	Mar. 31, 2018
Goodwill [Abstract]
Schedule of Goodwill [Table Text Block]	Goodwill by segment is as follows for both March 31, 2018 and December 31, 2017 (in thousands): Electric $ 243,558 Natural gas 114,028 Total $ 357,586

Comprehensive Income Loss (Tabl

Comprehensive Income Loss (Tables)	3 Months Ended
	Mar. 31, 2018
Equity [Abstract]
Comprehensive Income (Loss) [Table Text Block]	The following tables display the components of Other Comprehensive Income, after-tax, and the related tax effects (in thousands): Three Months Ended March 31, 2018 March 31, 2017 Before-Tax Amount Tax Expense Net-of-Tax Amount Before-Tax Amount Tax Expense Net-of-Tax Amount Foreign currency translation adjustment $ 95 $ — $ 95 $ 51 $ — $ 51 Reclassification of net losses on derivative instruments 153 (40 ) 113 153 (60 ) 93 Other comprehensive income $ 248 $ (40 ) $ 208 $ 204 $ (60 ) $ 144

Accumulated Other Comprehensive

Accumulated Other Comprehensive (Income) Loss (Tables)	3 Months Ended
	Mar. 31, 2018
Statement of Financial Position [Abstract]
Accumulated Other Comprehensive Income [Table Text Block]	Balances by classification included within accumulated other comprehensive loss (AOCL) on the Condensed Consolidated Balance Sheets are as follows, net of tax (in thousands): March 31, 2018 December 31, 2017 Foreign currency translation $ 1,273 $ 1,178 Derivative instruments designated as cash flow hedges (9,868 ) (9,981 ) Reclassification of certain tax effects from AOCL (2,143 ) — Postretirement medical plans 31 31 Accumulated other comprehensive loss $ (10,707 ) $ (8,772 )
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	The following tables display the changes in AOCL by component, net of tax (in thousands): Three Months Ended March 31, 2018 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (9,981 ) $ 31 $ 1,178 $ (8,772 ) Other comprehensive income before reclassifications — — 95 95 Amounts reclassified from AOCL Interest Expense 113 — — 113 Net current-period other comprehensive income 113 — 95 208 Reclassification of certain tax effects from AOCL (2,150 ) 7 — (2,143 ) Ending balance $ (12,018 ) $ 38 $ 1,273 $ (10,707 ) Three Months Ended March 31, 2017 Affected Line Item in the Condensed Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Pension and Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (10,352 ) $ (742 ) $ 1,380 (9,714 ) Other comprehensive income before reclassifications — — 51 51 Amounts reclassified from AOCL Interest Expense 93 — — 93 Net current-period other comprehensive income 93 — 51 144 Ending balance $ (10,259 ) $ (742 ) $ 1,431 $ (9,570 )

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2018
Segment Reporting Information [Line Items]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Financial data for the business segments are as follows (in thousands): Three Months Ended March 31, 2018 Electric Gas Other Eliminations Total Operating revenues $ 238,342 $ 103,160 $ — $ — $ 341,502 Cost of sales 57,273 38,804 — — 96,077 Gross margin 181,069 64,356 — — 245,425 Operating, general and administrative 54,648 21,219 (1,522 ) — 74,345 Property and other taxes 33,493 9,318 2 — 42,813 Depreciation and depletion 36,153 7,594 8 — 43,755 Operating income 56,775 26,225 1,512 — 84,512 Interest expense (19,520 ) (1,854 ) (1,596 ) — (22,970 ) Other income (expense) 490 108 (1,727 ) — (1,129 ) Income tax (expense) benefit (498 ) (2,226 ) 810 — (1,914 ) Net income (loss) $ 37,247 $ 22,253 $ (1,001 ) $ — $ 58,499 Total assets $ 4,319,798 $ 1,065,103 $ 15,517 $ — $ 5,400,418 Capital expenditures $ 42,898 $ 9,107 $ — $ — $ 52,005 Three Months Ended March 31, 2017 Electric Gas Other Eliminations Total Operating revenues $ 266,239 $ 101,073 $ — $ — $ 367,312 Cost of sales 85,385 34,432 — — 119,817 Gross margin 180,854 66,641 — — 247,495 Operating, general and administrative (1) 56,720 20,900 714 — 78,334 Property and other taxes 31,161 8,764 3 — 39,928 Depreciation and depletion 34,070 7,383 8 — 41,461 Operating income (loss) 58,903 29,594 (725 ) — 87,772 Interest expense (21,037 ) (1,546 ) (817 ) — (23,400 ) Other (expense) income (1) (1,193 ) (501 ) 566 — (1,128 ) Income tax (expense) benefit (2,887 ) (6,951 ) 3,161 — (6,677 ) Net income $ 33,786 $ 20,596 $ 2,185 $ — $ 56,567 Total assets $ 4,388,267 $ 1,106,062 $ 5,972 $ — $ 5,500,301 Capital expenditures $ 41,041 $ 10,478 $ — $ — $ 51,519 ______________ (1) We adopted ASU 2017-07 on January 1, 2018. As a result, we recorded the non-service cost component of net periodic benefit cost within other expense, net. We adopted this standard retrospectively and $1.9 million and $0.7 million , respectively, were reclassified from electric and gas operating, general and administrative expenses to other expense, net for the three months ended March 31, 2017 , to conform to current period presentation.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Schedule of Weighted Average Number of Shares [Table Text Block]	Average shares used in computing the basic and diluted earnings per share are as follows: Three Months Ended March 31, 2018 March 31, 2017 Basic computation 49,416,230 48,385,738 Dilutive effect of: Performance share awards (1) 67,622 117,658 Diluted computation 49,483,852 48,503,396 _______ (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. The dilutive share calculation for 2018 excludes 34,913 shares under outstanding performance share awards because the inclusion of these awards would have been antidilutive under the treasury stock method.

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	3 Months Ended
	Mar. 31, 2018
Retirement Benefits [Abstract]
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	Net periodic benefit cost (income) for our pension and other postretirement plans consists of the following (in thousands): Pension Benefits Other Postretirement Benefits Three Months Ended March 31, Three Months Ended March 31, 2018 2017 2018 2017 Components of Net Periodic Benefit Cost (Income) Service cost $ 3,204 $ 3,130 $ 112 $ 128 Interest cost 6,108 6,429 147 180 Expected return on plan assets (7,060 ) (6,008 ) (239 ) (213 ) Amortization of prior service cost 1 2 (471 ) (471 ) Recognized actuarial loss 1,072 1,975 (20 ) 78 Net Periodic Benefit Cost (Income) $ 3,325 $ 5,528 $ (471 ) $ (298 )

Nature of Operations and Basi28

Nature of Operations and Basis of Consolidation (Details) $ in Thousands	Mar. 31, 2018USD ($)watts	Dec. 31, 2017USD ($)customers
Reclassification of certain tax effects from AOCL	$ (2,143)	$ 0
Number of customers | customers		718,300
Number of megawatts of qualifying facility | watts	35
Estimated aggregate gross contractual payments for qualifying facilities through 2024	$ 212,700
Restatement Adjustment [Member]
Reclassification of certain tax effects from AOCL	$ 2,100

Nature of Operations and Basi29

Nature of Operations and Basis of Consolidation Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash, Cash Equivalents, and Restricted Cash [Abstract]
Cash and Cash Equivalents	$ 12,433	$ 4,742	$ 8,473	$ 5,079	$ 11,980
Restricted cash	4,852	6,158	3,556	4,426	6,634
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	17,285	$ 10,900	$ 12,029	$ 9,505	$ 18,614
Increase in Restricted Cash	$ 400

Nature of Operations and Basi30

Nature of Operations and Basis of Consolidation Retirement Benefits (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating, general and administrative	$ 74,345	$ 78,334	$ 294,803	$ 293,863	$ 290,718
Other Expense, net	$ (1,129)	(1,128)	(3,415)	(3,482)	826
Scenario, Previously Reported [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating, general and administrative		80,962	305,137	302,893	297,475
Other Expense, net		1,500	6,919	5,548	7,583
Restatement Adjustment [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net periodic benefit cost (credit), effect of accounting change		$ (2,628)	$ (10,334)	$ (9,030)	$ (6,757)

Revenue from Contracts with C31

Revenue from Contracts with Customers (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Disaggregation of Revenue [Line Items]
Revenues	$ 341,502,000	$ 367,312,000
Residential
Disaggregation of Revenue [Line Items]
Revenues	169,600,000	171,700,000
Residential | Montana
Disaggregation of Revenue [Line Items]
Revenues	128,100,000	134,600,000
Residential | South Dakota
Disaggregation of Revenue [Line Items]
Revenues	30,100,000	28,100,000
Residential | Nebraska
Disaggregation of Revenue [Line Items]
Revenues	11,400,000	9,000,000
Commercial
Disaggregation of Revenue [Line Items]
Revenues	142,200,000	144,700,000
Commercial | Montana
Disaggregation of Revenue [Line Items]
Revenues	104,200,000	110,000,000
Commercial | South Dakota
Disaggregation of Revenue [Line Items]
Revenues	31,900,000	29,800,000
Commercial | Nebraska
Disaggregation of Revenue [Line Items]
Revenues	6,100,000	4,900,000
Industrial
Disaggregation of Revenue [Line Items]
Revenues	11,300,000	11,400,000
Other
Disaggregation of Revenue [Line Items]
Revenues	5,500,000	5,700,000
Total Customer Revenue
Disaggregation of Revenue [Line Items]
Revenues	328,600,000	333,500,000
Other Tariff and Contract Based Revenue
Disaggregation of Revenue [Line Items]
Revenues	28,100,000	48,500,000
Revenue from Contract with Customer
Disaggregation of Revenue [Line Items]
Revenues	356,700,000	382,000,000
Regulatory amortization
Disaggregation of Revenue [Line Items]
Revenues	(15,200,000)	(14,700,000)
Total Revenues
Disaggregation of Revenue [Line Items]
Revenues	341,500,000	367,300,000
Electric Domestic Regulated [Member]
Disaggregation of Revenue [Line Items]
Revenues	238,342,000	266,239,000
Electric Domestic Regulated [Member] | Residential
Disaggregation of Revenue [Line Items]
Revenues	105,900,000	108,100,000
Electric Domestic Regulated [Member] | Residential | Montana
Disaggregation of Revenue [Line Items]
Revenues	87,200,000	90,800,000
Electric Domestic Regulated [Member] | Residential | South Dakota
Disaggregation of Revenue [Line Items]
Revenues	18,700,000	17,300,000
Electric Domestic Regulated [Member] | Residential | Nebraska
Disaggregation of Revenue [Line Items]
Revenues	0	0
Electric Domestic Regulated [Member] | Commercial
Disaggregation of Revenue [Line Items]
Revenues	107,600,000	110,500,000
Electric Domestic Regulated [Member] | Commercial | Montana
Disaggregation of Revenue [Line Items]
Revenues	83,600,000	88,100,000
Electric Domestic Regulated [Member] | Commercial | South Dakota
Disaggregation of Revenue [Line Items]
Revenues	24,000,000	22,400,000
Electric Domestic Regulated [Member] | Commercial | Nebraska
Disaggregation of Revenue [Line Items]
Revenues	0	0
Electric Domestic Regulated [Member] | Industrial
Disaggregation of Revenue [Line Items]
Revenues	10,800,000	10,900,000
Electric Domestic Regulated [Member] | Other
Disaggregation of Revenue [Line Items]
Revenues	5,000,000	5,200,000
Electric Domestic Regulated [Member] | Total Customer Revenue
Disaggregation of Revenue [Line Items]
Revenues	229,300,000	234,700,000
Electric Domestic Regulated [Member] | Other Tariff and Contract Based Revenue
Disaggregation of Revenue [Line Items]
Revenues	17,800,000	37,400,000
Electric Domestic Regulated [Member] | Revenue from Contract with Customer
Disaggregation of Revenue [Line Items]
Revenues	247,100,000	272,100,000
Electric Domestic Regulated [Member] | Regulatory amortization
Disaggregation of Revenue [Line Items]
Revenues	(8,800,000)	(5,900,000)
Electric Domestic Regulated [Member] | Total Revenues
Disaggregation of Revenue [Line Items]
Revenues	238,300,000	266,200,000
Gas Domestic Regulated [Member]
Disaggregation of Revenue [Line Items]
Revenues	103,160,000	101,073,000
Gas Domestic Regulated [Member] | Residential
Disaggregation of Revenue [Line Items]
Revenues	63,700,000	63,600,000
Gas Domestic Regulated [Member] | Residential | Montana
Disaggregation of Revenue [Line Items]
Revenues	40,900,000	43,800,000
Gas Domestic Regulated [Member] | Residential | South Dakota
Disaggregation of Revenue [Line Items]
Revenues	11,400,000	10,800,000
Gas Domestic Regulated [Member] | Residential | Nebraska
Disaggregation of Revenue [Line Items]
Revenues	11,400,000	9,000,000
Gas Domestic Regulated [Member] | Commercial
Disaggregation of Revenue [Line Items]
Revenues	34,600,000	34,200,000
Gas Domestic Regulated [Member] | Commercial | Montana
Disaggregation of Revenue [Line Items]
Revenues	20,600,000	21,900,000
Gas Domestic Regulated [Member] | Commercial | South Dakota
Disaggregation of Revenue [Line Items]
Revenues	7,900,000	7,400,000
Gas Domestic Regulated [Member] | Commercial | Nebraska
Disaggregation of Revenue [Line Items]
Revenues	6,100,000	4,900,000
Gas Domestic Regulated [Member] | Industrial
Disaggregation of Revenue [Line Items]
Revenues	500,000	500,000
Gas Domestic Regulated [Member] | Other
Disaggregation of Revenue [Line Items]
Revenues	500,000	500,000
Gas Domestic Regulated [Member] | Total Customer Revenue
Disaggregation of Revenue [Line Items]
Revenues	99,300,000	98,800,000
Gas Domestic Regulated [Member] | Other Tariff and Contract Based Revenue
Disaggregation of Revenue [Line Items]
Revenues	10,300,000	11,100,000
Gas Domestic Regulated [Member] | Revenue from Contract with Customer
Disaggregation of Revenue [Line Items]
Revenues	109,600,000	109,900,000
Gas Domestic Regulated [Member] | Regulatory amortization
Disaggregation of Revenue [Line Items]
Revenues	(6,400,000)	(8,800,000)
Gas Domestic Regulated [Member] | Total Revenues
Disaggregation of Revenue [Line Items]
Revenues	$ 103,200,000	$ 101,100,000

Regulatory Matters (Details)

Regulatory Matters (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016
Public Utilities, General Disclosures [Line Items]
Federal statutory income tax rate	21.00%	35.00%
Deferred Income Tax Revenue [Member]
Public Utilities, General Disclosures [Line Items]
Deferred revenue	$ 7.3
Electric Supply Costs [Member]
Public Utilities, General Disclosures [Line Items]
Disallowed electric tracker costs				$ 12.4
Disallowed modeling costs				0.4
Dave Gates Generating Station [Member]
Public Utilities, General Disclosures [Line Items]
Deferred revenue, refund payments				$ 27.3
Montana Property Tax Tracker [Member]
Public Utilities, General Disclosures [Line Items]
Disallowed property tax costs			$ 1.7
Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Expected annual revenue reduction	15
Potential customer refundable taxes	8
Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Expected annual revenue reduction	20
Potential customer refundable taxes	$ 12

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Income Tax Contingency [Line Items]
Unrecognized tax benefit more likely than not percentage threshold	50.00%
Unrecognized tax benefits	$ 56.5
Unrecognized tax benefits that would impact effective tax rate	47.7
Interest expense or penalties, uncertain tax positions	0.3	$ 0.1
Accrued interest, uncertain tax positions	$ 1.7		$ 1.5
Federal statutory income tax rate	21.00%	35.00%
Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Earliest year subject to examination	2,000

Income Taxes Effective Tax Rate

Income Taxes Effective Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Effective tax rate reconciliation
Income Before Income Taxes	$ 60,413	$ 63,244
Income tax calculated at federal statutory rate	$ 12,687	$ 22,135
Federal statutory income tax rate	21.00%	35.00%
State income, net of federal provisions	$ 732	$ (834)
State income, net of federal provisions	1.20%	(1.30%)
Flow-through repairs deductions	$ (6,586)	$ (8,797)
Flow-through repairs deductions	(10.90%)	(13.90%)
Production tax credits	$ (3,888)	$ (3,831)
Production tax credits	(6.40%)	(6.10%)
Plant and depreciation of flow through items	$ (916)	$ (1,440)
Plant and depreciation of flow through items	(1.60%)	(2.30%)
Share-based compensation	$ 275	$ (399)
Share-based compensation	0.50%	(0.60%)
Other, net	$ (390)	$ (157)
Other, net	(0.60%)	(0.20%)
Total Other Reconciling Items	$ (10,773)	$ (15,458)
Total Other Reconciling Items	(17.80%)	(24.40%)
Income Tax Expense	$ 1,914	$ 6,677
Income Tax Expense	3.20%	10.60%

Goodwill (Details)

Goodwill (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Goodwill [Line Items]
Change in goodwill	$ 0
Goodwill	357,586	$ 357,586
Electric [Member]
Goodwill [Line Items]
Goodwill	243,558	243,558
Natural Gas [Member]
Goodwill [Line Items]
Goodwill	$ 114,028	$ 114,028

Comprehensive Income (Loss) (De

Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Other Comprehensive Income (Loss), before Tax [Abstract]
Foreign currency translation adjustment	$ 95	$ 51
Reclassification of net losses on derivative instruments	153	153
Total Other Comprehensive (Loss) Income	248	204
Other Comprehensive Income (Loss), Tax [Abstract]
Foreign currency translation adjustment	0	0
Reclassification of net losses on derivative instruments	(40)	(60)
Total Other Comprehensive (Loss) Income	(40)	(60)
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustment	95	51
Reclassification of net losses on derivative instruments	113	93
Total Other Comprehensive Income	$ 208	$ 144

Balance Sheet Classification (D

Balance Sheet Classification (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Foreign currency translation	$ 1,273	$ 1,178
Derivative instruments designated as cash flow hedges	(9,868)	(9,981)
Reclassification of certain tax effects from AOCL	(2,143)	0
Postretirement medical plans	31	31
Accumulated other comprehensive loss	$ (10,707)	$ (8,772)

Changes in AOCI by Component (D

Changes in AOCI by Component (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	$ (8,772)
Total Other Comprehensive Income	208	$ 144
Reclassification of certain tax effects from AOCL	(2,143)		$ 0
Ending balance	(10,707)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	(9,981)	(10,352)
Other comprehensive income before reclassifications	0	0
Amounts reclassified from AOCL	113	93
Total Other Comprehensive Income	113	93
Reclassification of certain tax effects from AOCL	(2,150)
Ending balance	(12,018)	(10,259)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	31	(742)
Other comprehensive income before reclassifications	0	0
Amounts reclassified from AOCL	0	0
Total Other Comprehensive Income	0	0
Reclassification of certain tax effects from AOCL	7
Ending balance	38	(742)
Accumulated Foreign Currency Adjustment Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	1,178	1,380
Other comprehensive income before reclassifications	95	51
Amounts reclassified from AOCL	0	0
Total Other Comprehensive Income	95	51
Reclassification of certain tax effects from AOCL	0
Ending balance	1,273	1,431
Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	(8,772)	(9,714)
Other comprehensive income before reclassifications	95	51
Amounts reclassified from AOCL	113	93
Total Other Comprehensive Income	208	144
Reclassification of certain tax effects from AOCL	(2,143)
Ending balance	$ (10,707)	$ (9,570)

Segment Information (Details)

Segment Information (Details) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Operating revenues	$ 341,502,000	$ 367,312,000
Cost of sales	96,077,000	119,817,000
Gross margin	245,425,000	247,495,000
Operating, general and administrative	74,345,000	78,334,000	$ 294,803,000	$ 293,863,000	$ 290,718,000
Property and other taxes	42,813,000	39,928,000
Depreciation and depletion	43,755,000	41,461,000
Operating income	84,512,000	87,772,000
Interest expense	(22,970,000)	(23,400,000)
Other income (expense)	(1,129,000)	(1,128,000)	(3,415,000)	$ (3,482,000)	$ 826,000
Income Tax (Expense) Benefit	(1,914,000)	(6,677,000)
Net Income	58,499,000	56,567,000
Total assets	5,400,418,000	5,500,301,000	$ 5,420,917,000
Capital expenditures	52,005,000	51,519,000
Electric [Member]
Segment Reporting Information [Line Items]
Operating revenues	238,342,000	266,239,000
Cost of sales	57,273,000	85,385,000
Gross margin	181,069,000	180,854,000
Operating, general and administrative	54,648,000	56,720,000
Property and other taxes	33,493,000	31,161,000
Depreciation and depletion	36,153,000	34,070,000
Operating income	56,775,000	58,903,000
Interest expense	(19,520,000)	(21,037,000)
Other income (expense)	490,000	(1,193,000)
Income Tax (Expense) Benefit	(498,000)	(2,887,000)
Net Income	37,247,000	33,786,000
Total assets	4,319,798,000	4,388,267,000
Capital expenditures	42,898,000	41,041,000
Natural Gas [Member]
Segment Reporting Information [Line Items]
Operating revenues	103,160,000	101,073,000
Cost of sales	38,804,000	34,432,000
Gross margin	64,356,000	66,641,000
Operating, general and administrative	21,219,000	20,900,000
Property and other taxes	9,318,000	8,764,000
Depreciation and depletion	7,594,000	7,383,000
Operating income	26,225,000	29,594,000
Interest expense	(1,854,000)	(1,546,000)
Other income (expense)	108,000	(501,000)
Income Tax (Expense) Benefit	(2,226,000)	(6,951,000)
Net Income	22,253,000	20,596,000
Total assets	1,065,103,000	1,106,062,000
Capital expenditures	9,107,000	10,478,000
All Other Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0
Cost of sales	0	0
Gross margin	0	0
Operating, general and administrative	(1,522,000)	714,000
Property and other taxes	2,000	3,000
Depreciation and depletion	8,000	8,000
Operating income	1,512,000	(725,000)
Interest expense	(1,596,000)	(817,000)
Other income (expense)	(1,727,000)	566,000
Income Tax (Expense) Benefit	810,000	3,161,000
Net Income	(1,001,000)	2,185,000
Total assets	15,517,000	5,972,000
Capital expenditures	0	0
Intersegment Elimination [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0
Cost of sales	0	0
Gross margin	0	0
Operating, general and administrative	0	0
Property and other taxes	0	0
Depreciation and depletion	0	0
Operating income	0	0
Interest expense	0	0
Other income (expense)	0	0
Income Tax (Expense) Benefit	0	0
Net Income	0	0
Total assets	0	0
Capital expenditures	$ 0	0
Nonservice cost component of net periodic benefit costs [Member]
Segment Reporting Information [Line Items]
Net periodic benefit cost (credit), effect of accounting change		2,600,000
Nonservice cost component of net periodic benefit costs [Member] | Electric [Member]
Segment Reporting Information [Line Items]
Net periodic benefit cost (credit), effect of accounting change		1,900,000
Nonservice cost component of net periodic benefit costs [Member] | Natural Gas [Member]
Segment Reporting Information [Line Items]
Net periodic benefit cost (credit), effect of accounting change		$ 700,000

Earnings Per Share (Details)

Earnings Per Share (Details) - shares	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Basic computation	49,416,230	48,385,738
Performance share awards (1)	67,622	117,658
Diluted computation	49,483,852	48,503,396
Antidilutive shares	34,913

Employee Benefit Plans Net Peri

Employee Benefit Plans Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Pension Benefits [Member]
Components of Net Periodic Benefit Cost (Income) [Abstract]
Service cost	$ 3,204	$ 3,130
Interest cost	6,108	6,429
Expected return on plan assets	(7,060)	(6,008)
Amortization of prior service cost	1	2
Recognized actuarial loss	1,072	1,975
Net Periodic Benefit Cost (Income)	3,325	5,528
Other Postretirement Benefits [Member]
Components of Net Periodic Benefit Cost (Income) [Abstract]
Service cost	112	128
Interest cost	147	180
Expected return on plan assets	(239)	(213)
Amortization of prior service cost	(471)	(471)
Recognized actuarial loss	(20)	78
Net Periodic Benefit Cost (Income)	$ (471)	(298)
Nonservice cost component of net periodic benefit costs [Member]
Components of Net Periodic Benefit Cost (Income) [Abstract]
Net Periodic Benefit Cost (Income)		$ 2,600

Commitments and Contingencies E

Commitments and Contingencies Environmental (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Environmental remediation obligations [Member]
Environmental remediation obligation, minimum	$ 26.7
Environmental remediation obligation, maximum	31.2
Accrual for environmental loss contingencies	30
Combined Manufacturing Sites [Member] | Manufactured Gas Plants [Member]
Accrual for environmental loss contingencies	23.2
Aberdeen South Dakota Site [Member] | Manufactured Gas Plants [Member]
Accrual for environmental loss contingencies	9.4
Environmental remediation obligation next 5 years	$ 4.4
Number of years for environmental remediation obligation to be incurred	5 years

Commitments and Contingencies L

Commitments and Contingencies Litigation (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Wilde Claim [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Damages sought	$ 4.8