NorthWestern (NWE) 10-K 12 Feb 21 2020 FY Annual report Financial data

Cover page Cover page

Cover page Cover page - USD ($)	12 Months Ended
	Dec. 31, 2020	Feb. 05, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Document Transition Report	false
Entity File Number	1-10499
Entity Registrant Name	NORTHWESTERN CORP
Entity Central Index Key	0000073088
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-0172280
Entity Address, Address Line One	3010 W. 69th Street
Entity Address, City or Town	Sioux Falls
Entity Address, State or Province	SD
Entity Address, Postal Zip Code	57108
City Area Code	605
Local Phone Number	978-2900
Title of 12(b) Security	Common stock
Trading Symbol	NWE
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 2,757,293,172
Entity Common Stock, Shares Outstanding		50,616,211
Documents Incorporated by Reference	Documents Incorporated by Reference Certain sections of our Proxy Statement for the 2021 Annual Meeting of Shareholders are incorporated by reference into Part III of this Form 10-K

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues
Electric	$ 940,815	$ 981,178	$ 921,093
Gas	257,855	276,732	270,916
Total Revenues	1,198,670	1,257,910	1,192,009
Operating Expenses
Cost of sales	306,190	318,020	272,883
Operating, general and administrative	297,115	318,229	307,119
Property and other taxes	179,517	171,888	171,259
Depreciation and depletion	179,644	172,923	174,476
Total Operating Expenses	962,466	981,060	925,737
Operating Income	236,204	276,850	266,272
Interest Expense, net	(96,812)	(95,068)	(91,988)
Other Income, net	4,853	413	3,966
Income Before Income Taxes	144,245	182,195	178,250
Income Tax Benefit	10,970	19,925	18,710
Net Income	$ 155,215	$ 202,120	$ 196,960
Average Common Shares Outstanding	50,559,208	50,428,560	49,984,562
Basic Earnings per Average Common Share	$ 3.07	$ 4.01	$ 3.94
Diluted Earnings per Average Common Share	$ 3.06	$ 3.98	$ 3.92

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Net Income	$ 155,215	$ 202,120	$ 196,960
Other comprehensive income (loss), net of tax:
Reclassification of net income (loss) on derivative instruments	452	452	498
Postretirement medical liability adjustment	1,840	(131)	213
Foreign currency translation adjustment	87	(35)	270
Total Other Comprehensive Income (Loss)	2,379	286	981
Comprehensive Income	$ 157,594	$ 202,406	$ 197,941

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current Assets:
Cash and cash equivalents	$ 5,811	$ 5,145
Restricted cash	11,285	6,925
Accounts receivable, net	168,229	167,405
Inventories	61,010	53,925
Regulatory assets	44,973	54,432
Prepaid expenses and other	17,372	13,895
Total current assets	308,680	301,727
Property, plant, and equipment, net	4,952,935	4,700,924
Goodwill	357,586	357,586
Regulatory assets	701,444	656,915
Other noncurrent assets	68,804	66,334
Total Assets	6,389,449	6,083,486
Current Liabilities:
Current maturities of finance leases	2,668	2,476
Short-term borrowings	100,000	0
Accounts payable	100,388	96,690
Accrued expenses	207,514	202,021
Regulatory liabilities	55,853	33,080
Total current liabilities	466,423	334,267
Long-term finance leases	14,771	17,439
Long-term debt	2,315,261	2,233,281
Deferred income taxes	471,777	447,986
Noncurrent regulatory liabilities	631,419	624,267
Other noncurrent liabilities	410,703	387,152
Total Liabilities	4,310,354	4,044,392
Commitments and Contingencies (Note 18)
Common Stock, Value, Issued	$ 541	$ 541
Common stock, par or stated value per share	$ 0.01	$ 0.01
Common stock, shares authorized	200,000,000	200,000,000
Common Stock, shares issued	54,144,775	53,999,189
Common Stock, shares outstanding	50,587,163	50,452,191
Preferred stock, par or stated value per share	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred Stock, shares issued	0	0
Shareholders' Equity:
Treasury stock at cost	$ (98,075)	$ (96,015)
Paid-in capital	1,513,787	1,508,970
Retained earnings	670,111	635,246
Accumulated other comprehensive loss	(7,269)	(9,648)
Total Shareholders' Equity	2,079,095	2,039,094
Total Liabilities and Shareholders' Equity	$ 6,389,449	$ 6,083,486

CONSOLIDATED BALANCE SHEETS PAR

CONSOLIDATED BALANCE SHEETS PARENTHETICAL (Parentheticals) - $ / shares	Dec. 31, 2020	Dec. 31, 2019
Common stock, par or stated value per share	$ 0.01	$ 0.01
Common stock, shares authorized	200,000,000	200,000,000
Common Stock, shares issued	54,144,775	53,999,189
Common Stock, shares outstanding	50,587,163	50,452,191
Preferred stock, par or stated value per share	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred Stock, shares issued	0	0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
OPERATING ACTIVITIES:
Net Income	$ 155,215	$ 202,120	$ 196,960
Items not affecting cash:
Depreciation and depletion	179,644	172,923	174,476
Amortization of debt issuance costs, discount and deferred hedge gain	4,911	4,648	4,645
Stock-based compensation costs	4,149	8,007	7,683
Equity portion of allowance for funds used during construction	(6,895)	(5,768)	(4,165)
Loss (gain) on disposition of assets	37	(188)	87
Deferred income taxes	(7,574)	(13,864)	(13,189)
Changes in current assets and liabilities:
Accounts receivable	(824)	(5,032)	19,909
Inventories	(7,085)	(3,110)	1,617
Other current assets	(3,477)	(3,140)	1,218
Accounts payable	16,043	(1,821)	(3,805)
Accrued expenses	5,909	(16,023)	7,862
Regulatory assets	14,749	(16,028)	(554)
Regulatory liabilities	22,773	(7,796)	25,534
Other noncurrent assets	(5,396)	(22,841)	(2,334)
Other noncurrent liabilities	(20,030)	4,633	(33,959)
Cash Provided by Operating Activities	352,149	296,720	381,985
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(405,762)	(316,016)	(283,966)
Acquisitions	0	0	(18,504)
Proceeds from sale of assets	0	0	71
Investment in equity securities	(42)	(135)	(2,500)
Cash Used in Investing Activities	(405,804)	(316,151)	(304,899)
FINANCING ACTIVITIES:
Dividends on common stock	(120,350)	(115,127)	(109,202)
Proceeds from issuance of common stock, net	0	0	44,796
Issuance of long-term debt	150,000	150,000	0
Line of credit (repayments) borrowings, net	(67,000)	(19,000)	308,000
Issuances (repayments) of short-term borrowings	100,000	0	(319,556)
Treasury stock activity	(1,391)	1,432	2,249
Financing costs	(2,578)	(1,115)	(91)
Cash Provided by (Used In) Financing Activities	58,681	16,190	(73,804)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	5,026	(3,241)	3,282
Cash, Cash Equivalents, and Restricted Cash, beginning of period	12,070	15,311	12,029
Cash, Cash Equivalents, and Restricted Cash, end of period	$ 17,096	$ 12,070	$ 15,311

CONSOLIDATED STATEMENTS OF COMM

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Paid-in Capital	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Loss
Balance at Dec. 31, 2017	$ 1,798,915	$ 530	$ 1,445,181	$ (96,376)	$ 458,352	$ (8,772)
Shares, Balance at Dec. 31, 2017		52,981		3,609
Increase (Decrease) in Shareholders' Equity [Roll Forward]
Net Income	196,960	$ 0	0	$ 0	196,960	0
Foreign currency translation adjustment	270	0	0	0	0	270
Reclassification of net losses (gains) on derivative instruments from OCI to net income, net of tax	498	0	0	0	0	498
Postretirement medical liability adjustment, net of tax	213	0	0	0	0	213
Stock based compensation, value	$ 6,974	$ 0	7,642	$ (668)	0	0
Stock based compensation, shares		72		12
Treasury Stock, Shares, Acquired	(55)
Issuance of shares, value	$ 47,754	$ 9	46,247		0	0
Issuance of shares, shares		836
Issuance of shares, value, treasury stock reissued				$ 1,498
Dividends on common stock	$ (109,202)	$ 0	0	0	(109,202)	0
Dividends per share	$ 2.10
Balance at Dec. 31, 2018	$ 1,942,382	$ 539	1,499,070	$ (95,546)	548,253	(9,934)
Shares, Balance at Dec. 31, 2018		53,889		3,566
Increase (Decrease) in Shareholders' Equity [Roll Forward]
Reclassification from AOCI to Retained Earnings	0	$ 0	0	$ 0	2,143	(2,143)
Net Income	202,120	0	0	0	202,120	0
Foreign currency translation adjustment	(35)	0	0	0	0	(35)
Reclassification of net losses (gains) on derivative instruments from OCI to net income, net of tax	452	0	0	0	0	452
Postretirement medical liability adjustment, net of tax	(131)	0	0	0	0	(131)
Stock based compensation, value	$ 6,309	$ 2	7,964	$ (1,657)	0	0
Stock based compensation, shares		110		25
Treasury Stock, Shares, Acquired	(44)
Issuance of shares, value	$ 3,124	$ 0	1,936		0	0
Issuance of shares, shares		0
Issuance of shares, value, treasury stock reissued				$ 1,188
Dividends on common stock	$ (115,127)	$ 0	0	0	(115,127)	0
Dividends per share	$ 2.20
Balance at Dec. 31, 2019	$ 2,039,094	$ 541	1,508,970	$ (96,015)	635,246	(9,648)
Shares, Balance at Dec. 31, 2019		53,999		3,547
Increase (Decrease) in Shareholders' Equity [Roll Forward]
Net Income	155,215	$ 0	0	$ 0	155,215	0
Foreign currency translation adjustment	87	0	0	0	0	87
Reclassification of net losses (gains) on derivative instruments from OCI to net income, net of tax	452	0	0	0	0	452
Postretirement medical liability adjustment, net of tax	1,840	0	0	0	0	(1,840)
Stock based compensation, value	$ 1,359	$ 0	4,100	$ (2,741)	0	0
Stock based compensation, shares		146		35
Treasury Stock, Shares, Acquired	(24)
Issuance of shares, value	$ 1,398	$ 0	717		0	0
Issuance of shares, shares		0
Issuance of shares, value, treasury stock reissued				$ 681
Dividends on common stock	$ (120,350)	$ 0	0	0	(120,350)	0
Dividends per share	$ 2.30
Balance at Dec. 31, 2020	$ 2,079,095	$ 541	$ 1,513,787	$ (98,075)	$ 670,111	$ (7,269)
Shares, Balance at Dec. 31, 2020		54,145		3,558

Nature of Operations and Basis

Nature of Operations and Basis of Consolidation	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations and Basis of Consolidation	(1) Nature of Operations and Basis of Consolidation NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and / or natural gas to approximately 743,000 customers in Montana, South Dakota, Nebraska and Yellowstone National Park. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have generated and distributed electricity and distributed natural gas in Montana since 2002. The Consolidated Financial Statements for the periods included herein have been prepared by NorthWestern Corporation (NorthWestern, we or us), pursuant to the rules and regulations of the SEC. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The accompanying Consolidated Financial Statements include our accounts together with those of our wholly and majority-owned or controlled subsidiaries. All intercompany balances and transactions have been eliminated from the Consolidated Financial Statements. Events occurring subsequent to December 31, 2020, have been evaluated as to their potential impact to the Consolidated Financial Statements through the date of issuance. Reclassification In 2020, we changed our classification of excess deferred income taxes in the Consolidated Balance Sheets from a regulatory asset to a regulatory liability, such that the excess deferred income tax regulatory liabilities are reflected on a gross basis, rather than net within our income tax regulatory asset based on our right to offset. The impact on the December 31, 2019 Consolidated Balance Sheet is an increase of Noncurrent regulatory assets and Noncurrent regulatory liabilities of $172.8 million. The impact to our Consolidated Statements of Cash Flows for the years ended December 31, 2019 and 2018 is a gross up of non-cash activity within the Other noncurrent assets and Other noncurrent liabilities captions, both within the operating activities section, that offset one another with no impact to cash provided by operating activities. The impact of the reclassification as of December 31, 2019 is also reflected in Note 4 - Regulatory Assets and Liabilities and Note 20 - Segment and Related Information. The impact to the total assets reported in the 2018 segment information table within Note 20 - Segment and Related Information was an increase of $161.6 million. This reclassification had no effect on previously reported Net income in our Consolidated Statements of Income, Consolidated Statements of Comprehensive Income, and Consolidated Statements of Common Shareholders’ Equity. 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.

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Significant Accounting Policies	(2) Significant Accounting Policies Use of Estimates The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Estimates are used for such items as long-lived asset values and impairment charges, long-lived asset useful lives, tax provisions, uncertain tax position reserves, asset retirement obligations, regulatory assets and liabilities, allowances for uncollectible accounts, our QF liability, environmental liabilities, unbilled revenues and actuarially determined benefit costs and liabilities. We revise the recorded estimates when we receive better information or when we can determine actual amounts. Those revisions can affect operating results. Revenue Recognition The Company recognizes revenue as customers obtain control of promised goods and services in an amount that reflects consideration expected in exchange for those goods or services. Generally, the delivery of electricity and natural gas results in the transfer of control to customers at the time the commodity is delivered and the amount of revenue recognized is equal to the amount billed to each customer, including estimated volumes delivered when billings have not yet occurred. Cash Equivalents We consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents. Restricted Cash Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements. Accounts Receivable, Net Accounts receivable are net of allowances for uncollectible accounts of $5.6 million and $2.3 million at December 31, 2020 and December 31, 2019. Receivables include unbilled revenues of $80.5 million and $83.3 million at December 31, 2020 and December 31, 2019, respectively. Inventories Inventories are stated at average cost. Inventory consisted of the following (in thousands): December 31, 2020 2019 Materials and supplies $ 44,311 $ 42,791 Storage gas and fuel 16,699 11,134 Total Inventories $ 61,010 $ 53,925 Regulation of Utility Operations Our regulated operations are subject to the provisions of ASC 980, Regulated Operations. Regulated accounting is appropriate provided that (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise's cost of service, and (iii) in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be charged to and collected from customers. Our Consolidated Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. The economic effects of regulation can result in regulated companies recording costs that have been, or are deemed probable to be, allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities). If we were required to terminate the application of these provisions to our regulated operations, all such deferred amounts would be recognized in the Consolidated Statements of Income at that time. This would result in a charge to earnings and accumulated other comprehensive loss (AOCL), net of applicable income taxes, which could be material. In addition, we would determine any impairment to the carrying costs of deregulated plant and inventory assets. Derivative Financial Instruments We account for derivative instruments in accordance with ASC 815, Derivatives and Hedging. All derivatives are recognized in the Consolidated Balance Sheets at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair-value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash-flow hedge). For fair-value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash-flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in AOCL and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For other derivative contracts that do not qualify or are not designated for hedge accounting, changes in the fair value of the derivatives are recognized in earnings each period. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the underlying nature of the hedged items. Revenues and expenses on contracts that are designated as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but on an accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric and gas operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it were determined that a transaction designated as a normal purchase or a normal sale no longer met the exceptions, the fair value of the related contract would be reflected as an asset or liability and immediately recognized through earnings. See Note 8 - Risk Management and Hedging Activities, for further discussion of our derivative activity. Property, Plant and Equipment Property, plant and equipment are stated at original cost, including contracted services, direct labor and material, AFUDC, and indirect charges for engineering, supervision and similar overhead items. All expenditures for maintenance and repairs of utility property, plant and equipment are charged to the appropriate maintenance expense accounts. A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility plant. At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired and also for the net cost of removal. Also included in plant and equipment are assets under finance lease, which are stated at the present value of minimum lease payments. AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized currently from such allowance, it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. This rate averaged 6.7%, 6.9%, and 7.1% for Montana for 2020, 2019, and 2018, respectively. This rate averaged 6.7%, 6.6%, and 6.7% for South Dakota for 2020, 2019, and 2018, respectively. AFUDC capitalized totaled $9.8 million, $8.2 million, and $5.9 million for the years ended December 31, 2020, 2019, and 2018, respectively, for Montana and South Dakota combined. We record provisions for depreciation at amounts substantially equivalent to calculations made on a straight-line method by applying various rates based on useful lives of the various classes of properties (ranging from 2 to 96 years) determined from engineering studies. As a percentage of the depreciable utility plant at the beginning of the year, our provision for depreciation of utility plant was approximately 2.8%, 2.8%, and 3.0% for 2020, 2019, and 2018, respectively. Depreciation rates include a provision for our share of the estimated costs to decommission our jointly owned plants at the end of the useful life. The annual provision for such costs is included in depreciation expense, while the accumulated provisions are included in noncurrent regulatory liabilities. Pension and Postretirement Benefits We have liabilities under defined benefit retirement plans and a postretirement plan that offers certain health care and life insurance benefits to eligible employees and their dependents. The costs of these plans are dependent upon numerous factors, assumptions and estimates, including determination of discount rate, expected return on plan assets, rate of future compensation increases, age and mortality and employment periods. In determining the projected benefit obligations and costs, assumptions can change from period to period and may result in material changes in the cost and liabilities we recognize. Accrued Expenses Accrued expenses consisted of the following (in thousands): December 31, 2020 2019 Property taxes $ 89,425 $ 85,242 Employee compensation, benefits, and withholdings 40,538 50,142 Interest 18,074 17,538 Other (none of which is individually significant) 59,477 49,099 Total Accrued Expenses $ 207,514 $ 202,021 Other Noncurrent Liabilities Other noncurrent liabilities consisted of the following (in thousands): December 31, 2020 2019 Pension and other employee benefits $ 136,632 $ 128,853 Future QF obligation, net 81,379 92,937 Customer advances 65,186 56,870 Asset retirement obligations 45,355 42,449 Environmental 25,049 27,741 Other (none of which is individually significant) 57,102 38,302 Total Noncurrent Liabilities $ 410,703 $ 387,152 Income Taxes We follow the liability method in accounting for income taxes. Deferred income tax assets and liabilities represent the future effects on income taxes from temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized. Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ from these estimates. The resolution of tax matters in a particular future period could have a material impact on our Consolidated Income Statements and provision for income taxes. Environmental Costs We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset if there is precedent for recovering similar costs from customers in rates. Otherwise, we expense the costs. If an environmental cost is related to facilities we currently use, such as pollution control equipment, then we may capitalize and depreciate the costs over the remaining life of the asset, assuming the costs are recoverable in future rates or future cash flows. Our remediation cost estimates are based on the use of an environmental consultant, our experience, our assessment of the current situation and the technology currently available for use in the remediation. We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated responsible parties, then we estimate and record only our share of the cost. Supplemental Cash Flow Information Year Ended December 31, 2020 2019 2018 (in thousands) Cash paid (received) for: Income taxes $ 115 $ (6,737) $ 55 Interest 84,922 83,776 76,499 Significant non-cash transactions: Capital expenditures included in trade accounts payable 21,430 33,473 21,625 The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts shown in the Consolidated Statements of Cash Flows (in thousands): December 31, 2020 2019 2018 Cash and cash equivalents $ 5,811 $ 5,145 $ 7,860 Restricted cash 11,285 6,925 7,451 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 17,096 $ 12,070 $ 15,311 Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements. Accounting Standards Issued At this time, we are not expecting the adoption of recently issued accounting standards to have a material impact to our financial condition, results of operations, and cash flows.

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2020
Regulated Operations [Abstract]
Regulatory Matters	(3) Regulatory Matters COVID-19 Accounting Order Filings South Dakota - On May 1, 2020, we submitted a joint filing with four other investor owned utilities to the SDPUC seeking approval for an accounting order to defer certain costs related to the COVID-19 pandemic as a regulatory asset, subject to future review for recovery from customers. We limited our specific request to uncollectible accounts expense in excess of amounts included in the latest electric and natural gas test periods. In August, the SDPUC issued an order granting deferral of our excess uncollectible accounts expense. As of December 31, 2020 we have deferred $0.2 million of uncollectible accounts expense into a regulatory asset in the Consolidated Balance Sheet. Montana - On May 29, 2020, we filed a petition for an accounting order with the MPSC seeking approval of an accounting order (i) to defer uncollectible accounts expense in excess of amounts included in the latest electric and natural gas test periods; and (ii) requesting approval of a proposed pension contribution up to $40 million in 2020 to be recognized over a five-year period. The MPSC issued its final order in November 2020 authorizing the amortization of incremental pension contributions and allowing for the tracking of uncollectible accounts expense, although declining to authorize establishment of a regulatory asset for the incremental bad debt expense. Pension costs in Montana are included in expense on a pay as you go (cash funding) basis. We contributed $10.2 million to the Montana pension plan during the twelve months ended December 31, 2020, opting not to make incremental contributions as requested in the accounting order petition. FERC Filing - Montana Transmission Service Rates In May 2019, we submitted a filing with the FERC for our Montana transmission assets. In June 2019, the FERC issued an order accepting our filing, granting interim rates (subject to refund) effective July 1, 2019, establishing settlement procedures and terminating our related Tax Cuts and Jobs Act filing. A settlement judge was appointed and after months of settlement negotiations, the parties reached agreement on all issues. In November 2020, we filed the settlement and implemented settlement rates on December 1, 2020. In January 2021, the FERC approved our settlement. As of December 31, 2020, we had cumulative deferred revenue of approximately $31.3 million. We refunded approximately $20.5 million to our wholesale and choice customers in January 2021. Revenues from FERC regulated wholesale customers associated with our Montana FERC assets are reflected in our Montana MPSC jurisdictional rates as a credit to retail customers. We expect to submit a compliance filing with the MPSC adjusting the proposed credit in our Montana retail rates upon receipt of a final order from FERC. Cost Recovery Mechanisms - Montana Montana Electric and Natural Gas Supply Cost Trackers - Each year we submit an electric and natural gas tracker filing for recovery of supply costs for the 12-month period ended June 30. The MPSC reviews such filings and makes its cost recovery determination based on whether or not our supply procurement activities were prudent. The Power Costs and Credits Adjustment Mechanism (PCCAM) incorporates sharing of power supply costs from an established baseline of power supply costs and tracks the differences between the actual costs and associated base rate revenues. Rates are adjusted annually for variances between actual costs and associated revenues with the variances allocated 90 percent to customers and 10 percent to shareholders. In September 2019, we submitted our annual PCCAM filing for the period July 1, 2018 to June 30, 2019, requesting recovery of approximately $23.8 million in electric supply costs. The MPSC issued its final order on this matter in November 2020, disallowing approximately $9.4 million in prior period purchased power costs, consisting of $5.6 million related to a period in 2018 when Colstrip generation was operating intermittently to ensure it remained in compliance with environmental emission standards and $3.8 million related to the prorated application of the change in state law that eliminated the deadband component of the PCCAM. The disallowed costs are reflected as a reduction to our net supply cost regulatory asset as of December 31, 2020. We issued refunds of these disallowed costs to customers in January 2021, with interest calculated from October 1, 2019 when interim rates went into effect. Montana Community Renewable Energy Projects (CREPs) We were required to acquire, as of December 31, 2020, approximately 65 MW of CREPs. While we have made progress towards meeting this obligation by acquiring approximately 50 MW of CREPs, we have been unable to acquire the remaining MWs required for various reasons, including the fact that proposed projects fail to qualify as CREPs or do not meet the statutory cost cap. The MPSC granted us waivers for 2012 through 2016. The validity of the MPSC’s action as it related to waivers granted for 2015 and 2016 has been challenged legally and we are waiting on a final decision from the Montana Supreme Court. We expect to file waiver requests for 2017, 2018, 2019, and 2020 after resolution of that litigation. If the Montana Supreme Court rules that the 2015 and 2016 waivers were invalid or if the requested waivers for 2017 through 2020 are not granted, we are likely to be liable for penalties. If the MPSC imposes a penalty, the amount of the penalty would depend on how the MPSC calculated the energy that a CREP would have produced. However, we do not believe any such penalty would be material.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2020
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets and Liabilities	(4) Regulatory Assets and Liabilities We prepare our Consolidated Financial Statements in accordance with the provisions of ASC 980, as discussed in Note 2 - Significant Accounting Policies. Pursuant to this guidance, certain expenses and credits, normally reflected in income as incurred, are deferred and recognized when included in rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded based on management's assessment that it is probable that a cost will be recovered or that an obligation has been incurred. Accordingly, we have recorded the following major classifications of regulatory assets and liabilities that will be recognized in expenses and revenues in future periods when the matching revenues are collected or refunded. Of these regulatory assets and liabilities, energy supply costs are the only items earning a rate of return. The remaining regulatory items have corresponding assets and liabilities that will be paid for or refunded in future periods. Note Reference Remaining Amortization Period December 31, 2020 2019 (in thousands) Flow-through income taxes 12 Plant Lives $ 420,925 $ 376,548 Excess deferred income taxes 12 Plant Lives 67,256 73,670 Pension 14 Undetermined 138,567 132,000 Deferred financing costs Various 28,350 31,089 Employee related benefits 14 Undetermined 22,516 18,622 Supply costs 1 Year 8,116 35,454 State & local taxes & fees Various 17,910 7,146 Environmental clean-up 18 Various 11,127 11,179 Other Various 31,650 25,639 Total Regulatory Assets $ 746,417 $ 711,347 Removal cost 6 Various $ 464,669 $ 442,129 Excess deferred income taxes 12 Plant Lives 165,279 172,784 Supply costs 1 Year 13,847 14,226 Gas storage sales 19 years 7,887 8,307 Rates subject to refund 1 Year 32,496 14,177 State & local taxes & fees 1 Year 1,783 1,846 Environmental clean-up Various 656 1,181 Other Various 655 2,697 Total Regulatory Liabilities $ 687,272 $ 657,347 Income Taxes Flow-through income taxes primarily reflect the effects of plant related temporary differences such as flow-through of depreciation, repairs related deductions, and removal costs that we will recover or refund in future rates. We amortize these amounts as temporary differences reverse. Excess deferred income tax assets and liabilities are recorded as a result of the Tax Cuts and Jobs Act and will be recovered or refunded in future rates. See Note 12 - Income Taxes for further discussion. Pension and Employee Related Benefits We recognize the unfunded portion of plan benefit obligations in the Consolidated Balance Sheets, which is remeasured at each year end, with a corresponding adjustment to regulatory assets/liabilities as the costs associated with these plans are recovered in rates. The MPSC allows recovery of pension costs on a cash funding basis. The portion of the regulatory asset related to our Montana pension plan will amortize as cash funding amounts exceed accrual expense under GAAP. The SDPUC allows recovery of pension costs on an accrual basis. The MPSC allows recovery of postretirement benefit costs on an accrual basis. Deferred Financing Costs Consistent with our historical regulatory treatment, a regulatory asset has been established to reflect the remaining deferred financing costs on long-term debt that has been replaced through the issuance of new debt. These amounts are amortized over the life of the new debt. Rates Subject to Refund In June 2019, in response to a filing associated with our Montana transmission assets, FERC granted an interim rate increase, effective July 1, 2019. See Note 3 - Regulatory Matters, for further information on this docket. Also, in our Montana general electric rate case, the MPSC granted an interim rate increase, effective April 2019, with final rates approved in December 2019. The difference between interim and final approved rates is being refunded to customers over a twelve month period through February 2021. Supply Costs The MPSC, SDPUC and NPSC have authorized the use of electric and natural gas supply cost trackers that enable us to track actual supply costs and either recover the under collection or refund the over collection to our customers. Accordingly, we have recorded a regulatory asset and liability to reflect the future recovery of under collections and refunding of over collections through the ratemaking process. We earn interest on natural gas supply costs under collected, or apply interest to an over collection, of 7.0 percent in Montana; 7.2 percent and 7.8 percent for electric and natural gas, respectively, in South Dakota; and 8.5 percent for natural gas in Nebraska. State & Local Taxes & Fees (Montana Property Tax Tracker) Under Montana law, we are allowed to track the changes in the actual level of state and local taxes and fees and recover the increase in rates, less the amount allocated to FERC jurisdictional customers and net of the related income tax benefit. Environmental Clean-up Environmental clean-up costs are the estimated costs of investigating and cleaning up contaminated sites we own. We discuss the specific sites and clean-up requirements further in Note 18 - Commitments and Contingencies. Environmental clean-up costs are typically recoverable in customer rates when they are actually incurred. When cost projections become known and measurable, we coordinate with the appropriate regulatory authority to determine a recovery period. Removal Cost The anticipated costs of removing assets upon retirement are collected from customers in advance of removal activity as a component of depreciation expense. Our depreciation method, including cost of removal, is established by the respective regulatory commissions. Therefore, consistent with this regulated treatment, we reflect this accrual of removal costs for our regulated assets by increasing our regulatory liability. See Note 6 - Asset Retirement Obligations, for further information regarding this item. Gas Storage Sales A regulatory liability was established in 2000 and 2001 based on gains on cushion gas sales in Montana. This gain is being flowed to customers over a period that matches the depreciable life of surface facilities that were added to maintain deliverability from the field after the withdrawal of the gas. This regulatory liability is a reduction of rate base.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	(5) Property, Plant and Equipment The following table presents the major classifications of our property, plant and equipment (in thousands): Estimated Useful Life December 31, 2020 2019 (years) (in thousands) Transmission, distribution, and storage 15 – 95 $ 3,771,023 $ 3,569,141 Generation 23 – 72 1,252,805 1,222,796 Plant acquisition adjustment (1) 25 – 50 686,328 686,328 Building and improvements 23 – 73 303,099 278,164 Land, land rights and easements 53 – 96 157,379 156,069 Other 2 – 45 571,981 545,009 Construction work in process –— 173,492 96,421 Total property, plant and equipment 6,916,107 6,553,928 Less accumulated depreciation (1,703,016) (1,617,817) Less accumulated amortization (260,156) (235,187) Net property, plant and equipment $ 4,952,935 $ 4,700,924 ___________________________ (1) The plant acquisition adjustment balance above includes our Beethoven wind project acquired in 2015, our hydro generating assets acquired in 2014, and the inclusion of our interest in Colstrip Unit 4 in rate base in 2009. The acquisition adjustment is amortized on a straight-line basis over the estimated remaining useful life of each related asset in depreciation expense. Net plant and equipment under finance lease were $11.3 million and $13.3 million as of December 31, 2020 and 2019, respectively, which included $11.1 million and $13.1 million as of December 31, 2020 and 2019, respectively, related to a long-term power supply contract with the owners of a natural gas fired peaking plant, which has been accounted for as a finance lease. Jointly Owned Electric Generating Plant We have an ownership interest in four base-load electric generating plants, all of which are coal fired and operated by other companies. We have an undivided interest in these facilities and are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated. Our interest in each plant is reflected in the Consolidated Balance Sheets on a pro rata basis and our share of operating expenses is reflected in the Consolidated Statements of Income. The participants each finance their own investment. Information relating to our ownership interest in these facilities is as follows (in thousands): Big Stone Neal #4 Coyote Colstrip Unit 4 (MT) December 31, 2020 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 153,632 $ 62,927 $ 51,586 $ 317,438 Accumulated depreciation 40,665 33,942 37,980 105,738 December 31, 2019 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 155,662 $ 62,565 $ 52,448 $ 311,399 Accumulated depreciation 40,988 32,853 38,310 97,563

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	(6) Asset Retirement Obligations We are obligated to dispose of certain long-lived assets upon their abandonment. We recognize a liability for the legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event. We measure the liability at fair value when incurred and capitalize a corresponding amount as part of the book value of the related assets, which increases our property, plant and equipment and other noncurrent liabilities. The increase in the capitalized cost is included in determining depreciation expense over the estimated useful life of these assets. Since the fair value of the asset retirement obligation (ARO) is determined using a present value approach, accretion of the liability due to the passage of time is recognized each period and recorded as a regulatory asset until the settlement of the liability. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a regulatory asset or liability for the difference, which will be surcharged/refunded to customers through the rate making process. We record regulatory assets and liabilities for differences in timing of asset retirement costs recovered in rates and AROs recorded since asset retirement costs are recovered through rates charged to customers. Our AROs relate to the reclamation and removal costs at our jointly-owned coal-fired generation facilities, U.S. Department of Transportation requirements to cut, purge and cap retired natural gas pipeline segments, our obligation to plug and abandon oil and gas wells at the end of their life, and to remove all above-ground wind power facilities and restore the soil surface at the end of their life. The following table presents the change in our ARO (in thousands): December 31, 2020 2019 2018 Liability at January 1, $ 42,449 $ 40,659 $ 39,286 Accretion expense 2,070 2,051 2,031 Liabilities incurred — — 773 Liabilities settled (4,061) (46) (63) Revisions to cash flows 4,897 (215) (1,368) Liability at December 31, $ 45,355 $ 42,449 $ 40,659 During the twelve months ended December 31, 2020 our ARO liability decreased $4.1 million for partial settlement of the legal obligations at our jointly-owned coal-fired generation facilities. Additionally, during the twelve months ended December 31, 2020, our ARO liability increased $4.9 million related to changes in both the timing and amount of retirement cost estimates. In addition, we have identified removal liabilities related to our electric and natural gas transmission and distribution assets that have been installed on easements over property not owned by us. The easements are generally perpetual and only require remediation action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as we intend to utilize these properties indefinitely. In the event we decide to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time. We also identified AROs associated with our hydroelectric generating facilities; however, due to the indeterminate removal date, the fair value of the associated liabilities currently cannot be estimated and no amounts are recognized in the Consolidated Financial Statements. We collect removal costs in rates for certain transmission and distribution assets that do not have associated AROs. Generally, the accrual of future non-ARO removal obligations is not required; however, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. The recorded amounts of costs collected from customers through depreciation rates are classified as a regulatory liability in recognition of the fact that we have collected these amounts that will be used in the future to fund asset retirement costs and do not represent legal retirement obligations. See Note 4 - Regulatory Assets and Liabilities for removal costs recorded as regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2020 and 2019.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	(7) Goodwill We completed our annual goodwill impairment test as of April 1, 2020 and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections. Goodwill by segment is as follows (in thousands): December 31, 2020 2019 Electric $ 243,558 $ 243,558 Natural gas 114,028 114,028 Total Goodwill $ 357,586 $ 357,586

Risk Management and Hedging Act

Risk Management and Hedging Activities	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management and Hedging Activities	(8) Risk Management and Hedging Activities Nature of Our Business and Associated Risks We are exposed to certain risks related to the ongoing operations of our business, including the impact of market fluctuations in the price of electricity and natural gas commodities and changes in interest rates. We rely on market purchases to fulfill a portion of our electric and natural gas supply requirements. Several factors influence price levels and volatility. These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation availability and reliability within and between regions, fuel availability, market liquidity, and the nature and extent of current and potential federal and state regulations. Objectives and Strategies for Using Derivatives To manage our exposure to fluctuations in commodity prices we routinely enter into derivative contracts. These types of contracts are included in our electric and natural gas supply portfolios and are used to manage price volatility risk by taking advantage of fluctuations in market prices. While individual contracts may be above or below market value, the overall portfolio approach is intended to provide greater price stability for consumers. We do not maintain a trading portfolio, and our derivative transactions are only used for risk management purposes consistent with regulatory guidelines. In addition, we may use interest rate swaps to manage our interest rate exposures associated with new debt issuances or to manage our exposure to fluctuations in interest rates on variable rate debt. Accounting for Derivative Instruments We evaluate new and existing transactions and agreements to determine whether they are derivatives. The permitted accounting treatments include: normal purchase normal sale (NPNS); cash flow hedge; fair value hedge; and mark-to-market. Mark-to-market accounting is the default accounting treatment for all derivatives unless they qualify, and we specifically designate them, for one of the other accounting treatments. Derivatives designated for any of the elective accounting treatments must meet specific, restrictive criteria both at the time of designation and on an ongoing basis. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction. Normal Purchases and Normal Sales We have applied the NPNS scope exception to our contracts involving the physical purchase and sale of gas and electricity at fixed prices in future periods. During our normal course of business, we enter into full-requirement energy contracts, power purchase agreements and physical capacity contracts, which qualify for NPNS. All of these contracts are accounted for using the accrual method of accounting; therefore, there were no unrealized amounts recorded in the Consolidated Financial Statements at December 31, 2020 and 2019. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered. Credit Risk Credit risk is the potential loss resulting from counterparty non-performance under an agreement. We manage credit risk with policies and procedures for, among other things, counterparty analysis and exposure measurement, monitoring and mitigation. We limit credit risk in our commodity and interest rate derivatives activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. We are exposed to credit risk through buying and selling electricity and natural gas to serve customers. We may request collateral or other security from our counterparties based on the assessment of creditworthiness and expected credit exposure. It is possible that volatility in commodity prices could cause us to have material credit risk exposures with one or more counterparties. We enter into commodity master enabling agreements with our counterparties to mitigate credit exposure, as these agreements reduce the risk of default by allowing us or our counterparty the ability to make net payments. The agreements generally are: (1) Western Systems Power Pool agreements – standardized power purchase and sales contracts in the electric industry; (2) International Swaps and Derivatives Association agreements – standardized financial gas and electric contracts; (3) North American Energy Standards Board agreements – standardized physical gas contracts; and (4) Edison Electric Institute Master Purchase and Sale Agreements – standardized power sales contracts in the electric industry. Many of our forward purchase contracts contain provisions that require us to maintain an investment grade credit rating from each of the major credit rating agencies. If our credit rating were to fall below investment grade, the counterparties could require immediate payment or demand immediate and ongoing full overnight collateralization on contracts in net liability positions. Interest Rate Swaps Designated as Cash Flow Hedges We have previously used interest rate swaps designated as cash flow hedges to manage our interest rate exposures associated with new debt issuances. We have no interest rate swaps outstanding. These swaps were designated as cash flow hedges with the effective portion of gains and losses, net of associated deferred income tax effects, recorded in AOCL. We reclassify these gains from AOCL into interest expense during the periods in which the hedged interest payments occur. The following table shows the effect of these interest rate swaps previously terminated on the Consolidated Financial Statements (in thousands): Cash Flow Hedges Location of Amount Reclassified from AOCL to Income Amount Reclassified from AOCL into Income during the Year Ended December 31, 2020 Interest rate contracts Interest Expense $ 614 A pre-tax loss of approximately $14.6 million is remaining in AOCL as of December 31, 2020, and we expect to reclassify approximately $0.6 million of pre-tax losses from AOCL into interest expense during the next twelve months. These amounts relate to terminated swaps.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value Measurements	(9) Fair Value Measurements Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs. Applicable accounting guidance establishes a hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The three levels of the fair value hierarchy are as follows: • Level 1 – Unadjusted quoted prices available in active markets at the measurement date for identical assets or liabilities; • Level 2 – Pricing inputs, other than quoted prices included within Level 1, which are either directly or indirectly observable as of the reporting date; and • Level 3 – Significant inputs that are generally not observable from market activity. We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. Due to the short-term nature of cash and cash equivalents, accounts receivable, net, accounts payable, and short-term borrowings, the carrying amount of each such items approximates fair value. The table below sets forth by level within the fair value hierarchy the gross components of our assets and liabilities measured at fair value on a recurring basis. NPNS transactions are not included in the fair values by source table as they are not recorded at fair value. See Note 8 - Risk Management and Hedging Activities for further discussion. We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented. December 31, 2020 Quoted Prices in Active Markets for Identical Assets or Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Margin Cash Collateral Offset Total Net Fair Value (in thousands) Restricted cash equivalents $ 10,055 $ — $ — $ — $ 10,055 Rabbi trust investments 27,027 — — — 27,027 Total $ 37,082 $ — $ — $ — $ 37,082 December 31, 2019 Restricted cash equivalents $ 5,699 $ — $ — $ — $ 5,699 Rabbi trust investments 29,288 — — — 29,288 Total $ 34,987 $ — $ — $ — $ 34,987 Restricted cash equivalents represents amounts held in money market mutual funds. Rabbi trust investments represent assets held for non-qualified deferred compensation plans, which consist of our common stock and actively traded mutual funds with quoted prices in active markets. Financial Instruments The estimated fair value of financial instruments is summarized as follows (in thousands): December 31, 2020 December 31, 2019 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 2,315,261 $ 2,629,755 $ 2,233,281 $ 2,416,814 The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange. We determined fair value for long-term debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted

Short-Term Borrowings and Credi

Short-Term Borrowings and Credit Arrangements	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Short-term Debt	(10) Short-Term Borrowings and Credit Arrangements Short-Term Borrowings In April 2020, we entered into a $100 million Term Loan and borrowed the full amount. The Term Loan bears interest at variable rates tied to the Eurodollar rate plus a credit spread of 1.5 percent. Proceeds were used to repay a portion of our outstanding revolving credit facility borrowings and for general corporate purposes. All principal and unpaid interest under the Term Loan is due and payable on April 2, 2021. The Term Loan provides for prepayment of the principal and interest; however, amounts prepaid may not be reborrowed. The Term Loan requires us to maintain a consolidated indebtedness to total capitalization ratio of 65 percent or less. It also contains covenants which, among other things, limit our ability to engage in any consolidation or merger or otherwise liquidate or dissolve, dispose of property, and enter into transactions with affiliates. A default on the South Dakota or Montana First Mortgage Bonds would trigger a cross default on the Term Loan; however a default on the Term Loan would not trigger a default on the South Dakota or Montana First Mortgage Bonds. Credit Facility On September 2, 2020, we entered into a new $425 million Credit Facility to replace our existing facility. The Credit Facility increased the capacity from that of the prior facility by $25 million to $425 million and extended the maturity date to September 2, 2023 (from December 12, 2021), with uncommitted features that allow us to request up to two one-year extensions to the maturity date and increase the size by an additional $75 million with the consent of the lenders. The facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to the Eurodollar rate, plus a margin of 112.5 to 175.0 basis points, or a base rate, plus a margin of 12.5 to 75.0 basis points. A total of ten banks participate in the facility, with no one bank providing more than 16 percent of the total availability. Commitment fees for the Credit Facility were $0.6 million and $0.3 million for the years ended December 31, 2020 and 2019. The availability under the facilities in place for the years ended December 31 is shown in the following table (in millions): 2020 2019 Unsecured revolving line of credit, expiring September 2023 $ 425.0 $ — Unsecured revolving line of credit, expiring December 2021 — 400.0 Unsecured revolving line of credit, expiring March 2022 25.0 25.0 450.0 425.0 Amounts outstanding at December 31: Eurodollar borrowings 222.0 289.0 Letters of credit — — 222.0 289.0 Net availability as of December 31 $ 228.0 $ 136.0 The Credit Facility includes covenants that require us to meet certain financial tests, including a maximum debt to capitalization ratio not to exceed 65 percent. The facility also contains covenants which, among other things, limit our ability to engage in any consolidation or merger or otherwise liquidate or dissolve, dispose of property, and enter into transactions with affiliates. A default on the South Dakota or Montana First Mortgage Bonds would trigger a cross default on the Credit Facility; however a default on the Credit Facility would not trigger a default on the South Dakota or Montana First Mortgage Bonds.

Long-Term Debt and Capital Leas

Long-Term Debt and Capital Leases	12 Months Ended
	Dec. 31, 2020
Long-term Debt and Lease Obligation [Abstract]
Long-term Debt And Capital Leases	(11) Long-Term Debt and Finance Leases Long-term debt and finance leases consisted of the following (in thousands): December 31, Due 2020 2019 Unsecured Debt: Unsecured Revolving Line of Credit 2023 $ 222,000 $ — Unsecured Revolving Line of Credit 2021 — 289,000 Secured Debt: Mortgage bonds— South Dakota—5.01% 2025 64,000 64,000 South Dakota—4.15% 2042 30,000 30,000 South Dakota—4.30% 2052 20,000 20,000 South Dakota—4.85% 2043 50,000 50,000 South Dakota—4.22% 2044 30,000 30,000 South Dakota—4.26% 2040 70,000 70,000 South Dakota—3.21% 2030 50,000 — South Dakota—2.80% 2026 60,000 60,000 South Dakota—2.66% 2026 45,000 45,000 Montana—5.71% 2039 55,000 55,000 Montana—5.01% 2025 161,000 161,000 Montana—4.15% 2042 60,000 60,000 Montana—4.30% 2052 40,000 40,000 Montana—4.85% 2043 15,000 15,000 Montana—3.99% 2028 35,000 35,000 Montana—4.176% 2044 450,000 450,000 Montana—3.11% 2025 75,000 75,000 Montana—4.11% 2045 125,000 125,000 Montana—4.03% 2047 250,000 250,000 Montana—3.98% 2049 150,000 150,000 Montana—3.21% 2030 100,000 — Pollution control obligations— Montana—2.00% 2023 144,660 144,660 Other Long Term Debt: New Market Tax Credit Financing—1.146% 2046 26,977 26,977 Discount on Notes and Bonds and Debt Issuance Costs, Net — (13,376) (12,356) $ 2,315,261 $ 2,233,281 Less current maturities — — Total Long-Term Debt $ 2,315,261 $ 2,233,281 Finance Leases: Total Finance Leases Various $ 17,439 $ 19,915 Less current maturities (2,668) (2,476) Total Long-Term Finance Leases $ 14,771 $ 17,439 Secured Debt First Mortgage Bonds and Pollution Control Obligations The South Dakota First Mortgage Bonds are a series of general obligation bonds issued under our South Dakota indenture. These bonds are secured by substantially all of our South Dakota and Nebraska electric and natural gas assets. The Montana First Mortgage Bonds and Montana Pollution Control Obligations are secured by substantially all of our Montana electric and natural gas assets. In June 2019, we priced $150 million aggregate principal amount of Montana First Mortgage Bonds, at a fixed interest rate of 3.98 percent maturing in 2049. We issued $50 million of these bonds in June 2019 and the remaining $100 million of these bonds in September 2019 in transactions exempt from the registration requirements of the Securities Act of 1933, as amended. Proceeds were used to repay a portion of our outstanding borrowings under our revolving credit facilities and for other general corporate purposes. The bonds are secured by our electric and natural gas assets in Montana. In May 2020, we issued $100 million principal amount of Montana First Mortgage Bonds and $50 million principal amount of South Dakota First Mortgage Bonds, each at a fixed interest rate of 3.21 percent maturing on May 15, 2030. These bonds were issued in a transaction exempt from the registration requirements of the Securities Act of 1933. Proceeds were used to repay a portion of our outstanding borrowings under our revolving credit facilities and for other general corporate purposes. The bonds are secured by our electric and natural gas assets in Montana and South Dakota. As of December 31, 2020, we were in compliance with our financial debt covenants. Other Long-Term Debt The New Market Tax Credit (NMTC) financing is pursuant to Section 45D of the Internal Revenue Code of 1986 as amended, which was issued in association with a tax credit program related to the development and construction of a new office building in Butte, Montana. This financing agreement is structured with unrelated third party financial institutions (the Investor) and their wholly-owned community development entities (CDEs) in connection with our participation in qualified transactions under the NMTC program. Upon closing of this transaction in 2014, we entered into two loans totaling $27.0 million payable to the CDEs sponsoring the project, and provided an $18.2 million investment. In exchange for substantially all of the benefits derived from the tax credits, the Investor contributed approximately $8.8 million to the project. The NMTC is subject to recapture for a period of seven years. If the expected tax benefits are delivered without risk of recapture to the Investor and our performance obligation is relieved, we expect $7.9 million of the loan to be forgiven in July 2021. If we do not meet the conditions for loan forgiveness, we would be required to repay $27.0 million and would concurrently receive the return of our $18.2 million investment. As we are the primary beneficiary of the entities created in relation to the NMTC transaction, they have been consolidated as variable interest entities. The loans of $27.0 million are recorded in long-term debt and the investment of $18.2 million is recorded in Other noncurrent assets in the Consolidated Balance Sheets. Maturities of Long-Term Debt The aggregate minimum principal maturities of long-term debt and finance leases, during the next five years are $2.7 million in 2021, $2.9 million in 2022, $369.8 million in 2023, $3.3 million in 2024 and $303.6 million in 2025.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income Taxes	(12) Income Taxes Income tax benefit is comprised of the following (in thousands): Year Ended December 31, 2020 2019 2018 Federal Current $ (3,396) $ (6,076) $ (5,526) Deferred (4,006) (15,169) (15,588) Investment tax credits (3) (12) (33) State Current 3 27 38 Deferred (3,568) 1,305 2,399 Income Tax Benefit $ (10,970) $ (19,925) $ (18,710) Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities. The following table reconciles our effective income tax rate to the federal statutory rate: Year Ended December 31, 2020 2019 2018 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax, net of federal provisions (1.1) 0.7 0.9 Flow-through repairs deductions (16.5) (10.8) (10.8) Production tax credits (9.1) (6.3) (6.1) Amortization of excess DIT (0.7) (0.9) (2.1) Recognition of unrecognized tax benefit — (12.5) — Impact of Tax Cuts and Jobs Act — (0.1) (11.1) Plant and depreciation of flow through items 0.1 (2.2) (1.2) Prior year permanent return to accrual adjustments (1.2) 0.3 (1.7) Other, net (0.1) (0.1) 0.6 Effective tax rate (7.6) % (10.9) % (10.5) % The table below summarizes the significant differences in income tax benefit based on the differences between our effective tax rate and the federal statutory rate (in thousands). Year Ended December 31, 2020 2019 2018 Income Before Income Taxes $ 144,245 $ 182,195 $ 178,250 Income tax calculated at federal statutory rate 30,292 38,261 37,433 Permanent or flow through adjustments: State income, net of federal provisions (1,477) 1,251 1,613 Flow-through repairs deductions (23,828) (19,706) (19,323) Production tax credits (13,103) (11,483) (10,890) Amortization of excess DIT (968) (1,688) (3,731) Recognition of unrecognized tax benefit — (22,825) — Impact of Tax Cuts and Jobs Act — (198) (19,840) Plant and depreciation of flow through items 121 (3,952) (2,175) Prior year permanent return to accrual adjustments (1,728) 559 (2,978) Other, net (279) (144) 1,181 (41,262) (58,186) (56,143) Income Tax Benefit $ (10,970) $ (19,925) $ (18,710) The income tax benefit during the twelve months ended December 31, 2019, reflects the release of approximately $22.8 million of unrecognized tax benefits, including approximately $2.7 million of accrued interest and penalties, net of tax, due to the lapse of statutes of limitation in the second quarter of 2019. The income tax benefit during the twelve months ended December 31, 2018, includes finalizing the remeasurement of deferred income taxes associated with the Tax Cuts and Jobs Act following the conclusion of the associated regulatory dockets. The components of the net deferred income tax liability recognized in our Consolidated Balance Sheets are related to the following temporary differences (in thousands): December 31, 2020 2019 Production tax credit $ 63,542 $ 50,440 Pension / postretirement benefits 31,866 30,041 Customer advances 17,165 14,975 Unbilled revenue 14,429 9,820 Compensation accruals 11,748 13,163 Reserves and accruals 6,266 7,069 Environmental liability 6,039 5,938 Interest rate hedges 3,171 3,956 NOL carryforward 393 10,050 AMT credit carryforward — 3,400 Other, net 2,490 1,801 Deferred Tax Asset 157,109 150,653 Excess tax depreciation (412,774) (393,287) Goodwill amortization (83,991) (82,595) Flow through depreciation (83,545) (71,679) Regulatory assets and other (48,576) (51,078) Deferred Tax Liability (628,886) (598,639) Deferred Tax Liability, net $ (471,777) $ (447,986) At December 31, 2020 our total federal NOL carryforward was approximately $78.6 million prior to consideration of unrecognized tax benefits. If unused, our federal NOL carryforwards will expire as follows: $0.4 million in 2036 and $78.2 million in 2037. Our state NOL carryforward as of December 31, 2020 was approximately $38.1 million. If unused, our state NOL carryforwards will expire in 2024. We believe it is more likely than not that sufficient taxable income will be generated to utilize these NOL carryforwards. Uncertain Tax Positions We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The change in unrecognized tax benefits is as follows (in thousands): 2020 2019 2018 Unrecognized Tax Benefits at January 1 $ 35,085 $ 56,150 $ 57,473 Gross increases - tax positions in prior period 120 539 — Gross increases - tax positions in current period — — 338 Gross decreases - tax positions in current period (1,714) (1,489) (1,661) Lapse of statute of limitations — (20,115) — Unrecognized Tax Benefits at December 31 $ 33,491 $ 35,085 $ 56,150 Our unrecognized tax benefits include approximately $28.0 million related to tax positions as of December 31, 2020 and 2019, that if recognized, would impact our annual effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months. Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2020 and December 31, 2019, we did not have any amounts accrued for the payment of interest and penalties. During the year ended December 31, 2019, we released $2.7 million of accrued interest in the Consolidated Statements of Income. Tax years 2017 and forward remain subject to examination by the IRS and state taxing authorities. In addition, the available federal net operating loss carryforward may be reduced by the IRS for losses originating in certain tax years from 2003 forward.

Comprehensive Income (Loss)

Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Comprehensive Income (Loss) Note [Text Block]	(13) Comprehensive Income (Loss) The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands): December 31, 2020 2019 2018 Before-Tax Amount Tax Expense (Benefit) Net-of-Tax Amount Before-Tax Amount Tax Expense Net-of-Tax Amount Before-Tax Amount Tax Expense Net-of-Tax Amount Foreign currency translation adjustment $ 87 $ — $ 87 $ (35) $ — $ (35) $ 270 $ — $ 270 Reclassification of net income (loss) on derivative instruments 614 (162) 452 614 (162) 452 614 (116) 498 Postretirement medical liability adjustment 2,463 (623) 1,840 (175) 44 (131) 346 (133) 213 Other comprehensive income (loss) $ 3,164 $ (785) $ 2,379 $ 404 $ (118) $ 286 $ 1,230 $ (249) $ 981 Balances by classification included within AOCL on the Consolidated Balance Sheets are as follows, net of tax (in thousands): December 31, 2020 2019 Foreign currency translation $ 1,500 $ 1,413 Derivative instruments designated as cash flow hedges (10,729) (11,181) Postretirement medical plans 1,960 120 Accumulated other comprehensive loss $ (7,269) $ (9,648) The following table displays the changes in AOCL by component, net of tax (in thousands): December 31, 2020 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (11,181) $ 120 $ 1,413 $ (9,648) Other comprehensive income before reclassifications — — 87 87 Amounts reclassified from AOCL Interest Expense 452 — — 452 Amounts reclassified from AOCL — 1,840 — 1,840 Net current-period other comprehensive income 452 1,840 87 2,379 Ending Balance $ (10,729) $ 1,960 $ 1,500 $ (7,269) December 31, 2019 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (11,633) $ 251 $ 1,448 $ (9,934) Other comprehensive income before reclassifications — — (35) (35) Amounts reclassified from AOCL Interest Expense 452 — — 452 Amounts reclassified from AOCL — (131) — (131) Net current-period other comprehensive income (loss) 452 (131) (35) 286 Ending Balance $ (11,181) $ 120 $ 1,413 $ (9,648)

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2020
Retirement Benefits [Abstract]
Employee Benefit Plans	(14) Employee Benefit Plans Pension and Other Postretirement Benefit Plans We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for eligible employees. The pension plan for our South Dakota and Nebraska employees is referred to as the NorthWestern Corporation plan, and the pension plan for our Montana employees is referred to as the NorthWestern Energy plan, and collectively they are referred to as the Plans. We utilize a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are recognized into earnings only when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. The Plan’s funded status is recognized as an asset or liability in our Consolidated Financial Statements. See Note 4 - Regulatory Assets and Liabilities, for further discussion on how these costs are recovered through rates charged to our customers. Benefit Obligation and Funded Status Following is a reconciliation of the changes in plan benefit obligations and fair value of plan assets, and a statement of the funded status (in thousands): Pension Benefits Other Postretirement Benefits December 31, December 31, 2020 2019 2020 2019 Change in benefit obligation: Obligation at beginning of period $ 735,564 $ 649,626 $ 20,272 $ 20,611 Service cost 11,116 9,637 370 331 Interest cost 22,840 26,488 492 609 Actuarial loss 84,479 83,364 123 997 Settlements — (4,065) 390 390 Benefits paid (33,020) (29,486) (2,501) (2,666) Benefit Obligation at End of Period $ 820,979 $ 735,564 $ 19,146 $ 20,272 Change in Fair Value of Plan Assets: Fair value of plan assets at beginning of period $ 609,000 $ 525,310 $ 21,479 $ 18,670 Return on plan assets 101,075 107,041 2,723 3,805 Employer contributions 11,401 10,200 1,395 1,670 Settlements — (4,065) — — Benefits paid (33,020) (29,486) (2,501) (2,666) Fair value of plan assets at end of period $ 688,456 $ 609,000 $ 23,096 $ 21,479 Funded Status $ (132,523) $ (126,564) $ 3,950 $ 1,207 Amounts Recognized in the Balance Sheet Consist of: Noncurrent asset 7,001 4,333 8,436 7,783 Total Assets 7,001 4,333 8,436 7,783 Current liability (11,200) (11,401) (1,712) (2,113) Noncurrent liability (128,324) (119,496) (2,774) (4,463) Total Liabilities (139,524) (130,897) (4,486) (6,576) Net amount recognized $ (132,523) $ (126,564) $ 3,950 $ 1,207 Amounts Recognized in Regulatory Assets Consist of: Prior service credit — — 3,857 5,890 Net actuarial loss (115,987) (111,449) (497) 259 Amounts recognized in AOCL consist of: Prior service cost — — (246) (397) Net actuarial gain — — 3,246 934 Total $ (115,987) $ (111,449) $ 6,360 $ 6,686 The actuarial gain/loss is primarily due to the change in discount rate assumption and actual asset returns compared with expected amounts. The total projected benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were as follows (in millions): NorthWestern Energy Pension Plan December 31, 2020 2019 Projected benefit obligation $ 757.4 $ 675.5 Accumulated benefit obligation 757.4 675.5 Fair value of plan assets 619.1 545.8 ____________________ As of December 31, 2020, the fair value of the NorthWestern Corporation pension plan assets exceed the total projected and accumulated benefit obligation and are therefore excluded from this table. Net Periodic Cost (Credit) The components of the net costs (credits) for our pension and other postretirement plans are as follows (in thousands): Pension Benefits Other Postretirement Benefits December 31, December 31, 2020 2019 2018 2020 2019 2018 Components of Net Periodic Benefit Cost Service cost $ 11,116 $ 9,637 $ 11,776 $ 370 $ 331 $ 398 Interest cost 22,840 26,488 24,420 492 609 578 Expected return on plan assets (26,162) (25,443) (28,207) (983) (869) (954) Amortization of prior service cost (credit) — — 4 (1,882) (1,882) (1,882) Recognized actuarial loss (gain) 5,028 6,544 4,360 (61) (96) (79) Settlement loss recognized — 198 — 390 390 390 Net Periodic Benefit Cost (Credit) $ 12,822 $ 17,424 $ 12,353 $ (1,674) $ (1,517) $ (1,549) Regulatory deferral of net periodic benefit cost (1) (2,100) (7,510) (4,057) — — — Previously deferred costs recognized (1) 71 728 243 861 931 913 Amount Recognized in Income $ 10,793 $ 10,642 $ 8,539 $ (813) $ (586) $ (636) Income Statement Presentation Operating, general and administrative expense 9,016 2,125 7,719 370 331 398 Other income (expense), net 1,777 8,517 820 (1,183) (917) (1,034) Amount Recognized in Income $ 10,793 $ 10,642 $ 8,539 $ (813) $ (586) $ (636) ___________________________ (1) Net periodic benefit costs for pension and postretirement benefit plans are recognized for financial reporting based on the authorization of each regulatory jurisdiction in which we operate. A portion of these costs are recorded in regulatory assets and recognized in the Consolidated Statements of Income as those costs are recovered through customer rates. For purposes of calculating the expected return on pension plan assets, the market-related value of assets is used, which is based upon fair value. The difference between actual plan asset returns and estimated plan asset returns are amortized equally over a period not to exceed five years. Actuarial Assumptions The measurement dates used to determine pension and other postretirement benefit measurements for the plans are December 31, 2020 and 2019. The actuarial assumptions used to compute net periodic pension cost and postretirement benefit cost are based upon information available as of the beginning of the year, specifically, market interest rates, past experience and management's best estimate of future economic conditions. Changes in these assumptions may impact future benefit costs and obligations. In computing future costs and obligations, we must make assumptions about such things as employee mortality and turnover, expected salary and wage increases, discount rate, expected return on plan assets, and expected future cost increases. Two of these assumptions have the most impact on the level of cost: (1) discount rate and (2) expected rate of return on plan assets. On an annual basis, we set the discount rate using a yield curve analysis. This analysis includes constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year, projected benefit cash flow from our plans. The decrease in discount rate during 2020 increased our projected benefit obligation by approximately $92.1 million. In determining the expected long-term rate of return on plan assets, we review historical returns, the future expectations for returns for each asset class weighted by the target asset allocation of the pension and postretirement portfolios, and long-term inflation assumptions. Based on the target asset allocation for our pension assets and future expectations for asset returns, we decreased our long term rate of return on assets assumption for NorthWestern Energy Pension Plan to 4.17 percent and decreased our assumption on the NorthWestern Corporation Pension Plan to 3.01 percent for 2021. The weighted-average assumptions used in calculating the preceding information are as follows: Pension Benefits Other Postretirement Benefits December 31, December 31, 2020 2019 2018 2020 2019 2018 Discount rate 2.20-2.30 % 3.10-3.20 % 4.15-4.20 % 1.80 % 2.80 % 3.90-3.95 % Expected rate of return on assets 3.45-4.49 4.23-5.06 4.47-4.97 4.71 4.79 4.82 Long-term rate of increase in compensation levels (non-union) 2.84 2.84 2.84 2.84 2.84 2.84 Long-term rate of increase in compensation levels (union) 2.00 2.00 2.03 2.00 2.00 2.03 Interest crediting rate 3.30-6.00 3.60-6.00 4.00-6.00 N/A N/A N/A The postretirement benefit obligation is calculated assuming that health care costs increase by a 5.00 percent fixed rate. The company contribution toward the premium cost is capped, therefore future health care cost trend rates are expected to have a minimal impact on company costs and the accumulated postretirement benefit obligation. Investment Strategy Our investment goals with respect to managing the pension and other postretirement assets are to meet current and future benefit payment needs while maximizing total investment returns (income and appreciation) after inflation within the constraints of diversification, prudent risk taking, Prudent Man Rule of the Employee Retirement Income Security Act of 1974 and liability-based considerations. Each plan is diversified across asset classes to achieve optimal balance between risk and return and between income and growth through capital appreciation. Our investment philosophy is based on the following: • Each plan should be substantially invested as long-term cash holdings reduce long-term rates of return; • Pension Plan portfolio risk is described by volatility in the funded status of the Plans; • It is prudent to diversify each plan across the major asset classes; • Equity investments provide greater long-term returns than fixed income investments, although with greater short-term volatility; • Fixed income investments of the plans should strongly correlate with the interest rate sensitivity of the plan’s aggregate liabilities in order to hedge the risk of change in interest rates negatively impacting the pension plans overall funded status, (such assets will be described as Liability Hedging Fixed Income assets); • Allocation to foreign equities increases the portfolio diversification and thereby decreases portfolio risk while providing for the potential for enhanced long-term returns; • Active management can reduce portfolio risk and potentially add value through security selection strategies; • A portion of plan assets should be allocated to passive, indexed management funds to provide for greater diversification and lower cost; and • It is appropriate to retain more than one investment manager, provided that such managers offer asset class or style diversification. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies. The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense. In the optimization study, assumptions are formulated about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes, and making adjustments to reflect future conditions expected to prevail over the study period. Based on this, the target asset allocation established, within an allowable range of plus or minus 5 percent, is as follows: NorthWestern Energy Pension NorthWestern Corporation Pension NorthWestern Energy December 31, December 31, December 31, 2020 2019 2020 2019 2020 2019 Fixed income securities 55.0 % 55.0 % 80.0 % 80.0 % 40.0 % 40.0 % Non-U.S. fixed income securities 4.0 4.0 2.0 2.0 — — Global equities 41.0 41.0 18.0 18.0 60.0 60.0 The actual allocation by plan is as follows: NorthWestern Energy Pension NorthWestern Corporation Pension NorthWestern Energy December 31, December 31, December 31, 2020 2019 2020 2019 2020 2019 Cash and cash equivalents — % — % 0.7 % 0.9 % 1.0 % 1.0 % Fixed income securities 52.7 53.8 77.3 77.0 37.9 37.8 Non-U.S. fixed income securities 3.8 4.0 2.6 2.6 — — Global equities 43.5 42.2 19.4 19.5 61.1 61.2 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % Generally, the asset mix will be rebalanced to the target mix as individual portfolios approach their minimum or maximum levels. Debt securities consist of U.S. and international instruments. Core domestic portfolios can be invested in government, corporate, asset-backed and mortgage-backed obligation securities. While the portfolio may invest in high yield securities, the average quality must be rated at least “investment grade" by rating agencies. Performance of fixed income investments is measured by both traditional investment benchmarks as well as relative changes in the present value of the plan's liabilities. Equity investments consist primarily of U.S. stocks including large, mid and small cap stocks, which are diversified across investment styles such as growth and value. We also invest in global equities with exposure to developing and emerging markets. Derivatives, options and futures are permitted for the purpose of reducing risk but may not be used for speculative purposes. Our plan assets are primarily invested in common collective trusts (CCTs), which are invested in equity and fixed income securities. In accordance with our investment policy, these pooled investment funds must have an adequate asset base relative to their asset class and be invested in a diversified manner and have a minimum of three years of verified investment performance experience or verified portfolio manager investment experience in a particular investment strategy and have management and oversight by an investment advisor registered with the SEC. Investments in a collective investment vehicle are valued by multiplying the investee company’s net asset value per share with the number of units or shares owned at the valuation date. Net asset value per share is determined by the trustee. Investments held by the CCT, including collateral invested for securities on loan, are valued on the basis of valuations furnished by a pricing service approved by the CCT’s investment manager, which determines valuations using methods based on quoted closing market prices on national securities exchanges, or at fair value as determined in good faith by the CCT’s investment manager if applicable. The funds do not contain any redemption restrictions. The direct holding of NorthWestern Corporation stock is not permitted; however, any holding in a diversified mutual fund or collective investment fund is permitted. During 2019, due to proposed changes in the John Hancock participating group annuity contract held by the NorthWestern Corporation plan, we elected to discontinue the contract effective January 1, 2020. Cash Flows In accordance with the Pension Protection Act of 2006 (PPA), and the relief provisions of the Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), we are required to meet minimum funding levels in order to avoid required contributions and benefit restrictions. We have elected to use asset smoothing provided by the WRERA, which allows the use of asset averaging, including expected returns (subject to certain limitations), for a 24-month period in the determination of funding requirements. We expect to continue to make contributions to the pension plans in 2021 and future years that reflect the minimum requirements and discretionary amounts consistent with the amounts recovered in rates. Additional legislative or regulatory measures, as well as fluctuations in financial market conditions, may impact our funding requirements. Due to the regulatory treatment of pension costs in Montana, pension expense for 2020, 2019 and 2018 was based on actual contributions to the plan. Annual contributions to each of the pension plans are as follows (in thousands): 2020 2019 2018 NorthWestern Energy Pension Plan (MT) $ 10,201 $ 9,000 $ 8,000 NorthWestern Corporation Pension Plan (SD and NE) 1,200 1,200 1,200 $ 11,401 $ 10,200 $ 9,200 We estimate the plans will make future benefit payments to participants as follows (in thousands): Pension Benefits Other Postretirement Benefits 2021 $ 35,200 $ 2,729 2022 36,533 2,469 2023 37,847 2,331 2024 39,189 1,615 2025 40,210 1,457 2026-2030 209,556 5,699 Defined Contribution Plan

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Stock-Based Compensation	(15) Stock-Based Compensation We grant stock-based awards through our Amended and Restated Equity Compensation Plan (ECP), which includes restricted stock awards and performance share awards. As of December 31, 2020, there were 216,647 shares of common stock remaining available for grants. The remaining vesting period for awards previously granted ranges from one to five years if the service and/or performance requirements are met. Nonvested shares do not receive dividend distributions. The long-term incentive plan provides for accelerated vesting in the event of a change in control. We account for our share-based compensation arrangements by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. The compensation cost is based on the fair value of the grant on the date it was awarded. Performance Unit Awards Performance unit awards are granted annually under the ECP. These awards vest at the end of the three-year performance period if we have achieved certain performance goals and the individual remains employed by us. The exact number of shares issued will vary from 0 percent to 200 percent of the target award, depending on actual company performance relative to the performance goals. These awards contain both market- and performance-based components. The performance goals are independent of each other and equally weighted, and are based on two metrics: (i) EPS growth level and average return on equity; and (ii) total shareholder return (TSR) relative to a peer group. Fair value is determined for each component of the performance unit awards. The fair value of the earnings per share component is estimated based upon the closing market price of our common stock as of the date of grant less the present value of expected dividends, multiplied by an estimated performance multiple determined on the basis of historical experience, which is subsequently trued up at vesting based on actual performance. The fair value of the TSR portion is estimated using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. The following summarizes the significant assumptions used to determine the fair value of performance shares and related compensation expense as well as the resulting estimated fair value of performance shares granted: 2020 2019 Risk-free interest rate 1.42 % 2.47 % Expected life, in years 3 3 Expected volatility 14.9% to 19.7% 16.4% to 20.9% Dividend yield 3.1 % 3.5 % The risk-free interest rate was based on the U.S. Treasury yield of a three-year bond at the time of grant. The expected term of the performance shares is three years based on the performance cycle. Expected volatility was based on the historical volatility for the peer group. Both performance goals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares expected to vest. A summary of nonvested shares as of and changes during the year ended December 31, 2020, are as follows: Performance Unit Awards Shares Weighted-Average Grant-Date Beginning nonvested grants 178,245 $ 53.00 Granted 62,116 73.13 Vested (105,512) 47.99 Forfeited (4,278) 63.57 Remaining nonvested grants 130,571 $ 66.27 We recognized compensation expense of $2.2 million, $6.5 million, and $6.3 million for the years ended December 31, 2020, 2019, and 2018, respectively, and related income tax (benefit) expense of $(0.6) million, $0.2 million, and $0.3 million for the years ended December 31, 2020, 2019, and 2018, respectively. As of December 31, 2020, we had $9.1 million of unrecognized compensation cost related to the nonvested portion of outstanding awards, which is reflected as nonvested stock as a portion of additional paid in capital in our Statements of Common Shareholders' Equity. The cost is expected to be recognized over a weighted-average period of 2 years. The total fair value of shares vested was $5.1 million, $4.2 million, and $4.2 million for the years ended December 31, 2020, 2019 and 2018, respectively. Retirement/Retention Restricted Share Awards In December 2011, an executive retirement / retention program was established that provides for the annual grant of restricted share units. These awards are subject to a five-year performance and vesting period. The performance measure for these awards requires net income for the calendar year of at least three of the five full calendar years during the performance period to exceed net income for the calendar year the awards are granted. Once vested, the awards will be paid out in shares of common stock in five equal annual installments after a recipient has separated from service. The fair value of these awards is measured based upon the closing market price of our common stock as of the date of grant less the present value of expected dividends. A summary of nonvested shares as of and changes during the year ended December 31, 2020, are as follows: Shares Weighted-Average Grant-Date Beginning nonvested grants 72,858 $ 51.35 Granted 20,199 44.57 Vested (15,090) 44.77 Forfeited — — Remaining nonvested grants 77,967 $ 50.86 Director's Deferred Compensation Nonemployee directors may elect to defer up to 100 percent of any qualified compensation that would be otherwise payable to him or her, subject to compliance with our 2005 Deferred Compensation Plan for Nonemployee Directors and Section 409A of the Internal Revenue Code. The deferred compensation may be invested in NorthWestern stock or in designated investment funds. Compensation deferred in a particular month is recorded as a deferred stock unit (DSU) on the first of the following month based on the closing price of NorthWestern stock or the designated investment fund. The DSUs are marked-to-market on a quarterly basis with an adjustment to director’s compensation expense. Based on the election of the nonemployee director, following separation from service on the Board, other than on account of death, he or she shall be paid a distribution either in a lump sum or in approximately equal installments over a designated number of years (not to exceed 10 years). Following is a summary of the components of DSUs issued and compensation expense attributable to the DSUs (in millions, except DSU amounts): December 31, 2020 2019 2018 DSUs Issued 21,434 19,027 29,870 Compensation expense $ 1.5 $ 1.3 $ 1.8 Change in value of shares (2.9) 2.4 0.1 Total compensation (benefit) expense $ (1.4) $ 3.7 $ 1.9 DSUs withdrawn 613 3,708 136,640 Value of DSUs withdrawn $ 0.1 $ 0.3 $ 8.2

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2019
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Common Stock	(16) Common Stock We have 250,000,000 shares authorized consisting of 200,000,000 shares of common stock with a $0.01 par value and 50,000,000 shares of preferred stock with a $0.01 par value. Of these shares, 2,865,957 shares of common stock are reserved for the incentive plan awards. For further detail of grants under this plan see Note 15 - Stock-Based Compensation. Repurchase of Common Stock Shares tendered by employees to us to satisfy the employees' tax withholding obligations in connection with the vesting of restricted stock awards totaled 35,378 and 25,329 during the years ended December 31, 2020 and 2019, respectively, and are reflected in treasury stock. These shares were credited to treasury stock based on their fair market value on the vesting date.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2020
Earnings Per Share [Abstract]
Earnings Per Share	(17) Earnings Per Share Basic earnings per share are computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the potential dilution of common stock equivalent shares that could occur if unvested shares were to vest. Common stock equivalent shares are calculated using the treasury stock method, as applicable. The dilutive effect is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested restricted stock and performance share awards. Average shares used in computing the basic and diluted earnings per share are as follows: December 31, 2020 2019 2018 Basic computation 50,559,208 50,428,560 49,984,562 Dilutive effect of Performance and restricted share awards (1) 145,181 323,298 252,909 Diluted computation 50,704,389 50,751,858 50,237,471 _____________________ (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. As of December 31, 2020, there were 53,716 shares from performance and restricted share awards which were antidilutive and excluded from the earnings per share calculations.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(18) Commitments and Contingencies Qualifying Facilities Liability Our QF liability primarily consists of unrecoverable costs associated with three contracts covered under the PURPA. These contracts require us to purchase minimum amounts of energy at prices ranging from $63 to $136 per MWH through 2029. As of December 31, 2020, our estimated gross contractual obligation related to these contracts was approximately $552.0 million through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $448.5 million through 2029. As contractual obligations are settled, the related purchases and sales are recorded within Cost of sales and Electric revenues in our Consolidated Statements of Income. The present value of the remaining liability is recorded in Other noncurrent liabilities in our Consolidated Balance Sheets. The following summarizes the change in the liability (in thousands): December 31, 2020 2019 Beginning QF liability $ 92,937 $ 102,260 Unrecovered amount (1) (18,665) (17,257) Interest expense 7,107 7,934 Ending QF liability $ 81,379 $ 92,937 ___________________ (1) The change in the unrecovered amount includes (i) a lower periodic adjustment of $1.1 million due to actual price escalation, which was less than previously modeled, and (ii) higher costs of approximately $2.2 million, due to a $0.9 million reduction in costs for the adjustment to actual output and pricing for the current contract year as compared with a $3.1 million reduction in costs in the prior period. The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands): Gross Recoverable Net 2021 $ 77,722 $ 60,136 $ 17,586 2022 79,572 60,639 18,933 2023 81,646 61,280 20,366 2024 79,384 60,706 18,678 2025 65,041 52,950 12,091 Thereafter 168,592 152,837 15,755 Total $ 551,957 $ 448,548 $ 103,409 Long Term Supply and Capacity Purchase Obligations We have entered into various commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 24 years. Costs incurred under these contracts are included in Cost of sales in the Consolidated Statements of Income and were approximately $206.6 million, $222.5 million and $209.3 million for the years ended December 31, 2020, 2019, and 2018, respectively. As of December 31, 2020, our commitments under these contracts were $211.5 million in 2021, $190.9 million in 2022, $195.1 million in 2023, $173.2 million in 2024, $170.1 million in 2025, and $1.3 billion thereafter. These commitments are not reflected in our Consolidated Financial Statements. Hydroelectric License Commitments With the 2014 purchase of hydroelectric generating facilities and associated assets located in Montana, we assumed two Memoranda of Understanding (MOUs) existing with state, federal and private entities. The MOUs are periodically updated and renewed and require us to implement plans to mitigate the impact of the projects on fish, wildlife and their habitats, and to increase recreational opportunities. The MOUs were created to maximize collaboration between the parties and enhance the possibility to receive matching funds from relevant federal agencies. Under these MOUs, we have a remaining commitment to spend approximately $28.4 million between 2021 and 2040. These commitments are not reflected in our Consolidated Financial Statements. ENVIRONMENTAL LIABILITIES AND REGULATION Environmental Matters The operation of electric generating, transmission and distribution facilities, and gas gathering, storage, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance. Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, our environmental reserve, which relates primarily to the remediation of former manufactured gas plant sites owned by us, is estimated to range between $26.6 million to $32.2 million. As of December 31, 2020, we had a reserve of approximately $28.9 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. 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. The following summarizes the change in our environmental liability (in thousands): December 31, 2020 2019 2018 Liability at January 1, $ 30,276 $ 29,741 $ 30,326 Deductions (2,977) (2,232) (2,333) Charged to costs and expense 1,596 2,767 1,748 Liability at December 31, $ 28,895 $ 30,276 $ 29,741 Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as available and 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 $22.7 million of our environmental reserve accrual is related to the following manufactured gas plants. South Dakota - A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies, implementing remedial actions pursuant to work plans approved by the South Dakota Department of Environment and Natural Resources, and conducting ongoing monitoring and operation and maintenance activities. As of December 31, 2020, the reserve for remediation costs at this site was approximately $8.2 million, and we estimate that approximately $3.1 million of this amount will be incurred during the next five years. Nebraska - We 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. Montana - 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 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 October 2019, we submitted a third revised Remedial Investigation Work Plan (RIWP) for the Helena site addressing MDEQ comments. The MDEQ approved the RIWP in March 2020 and soil, groundwater, and vapor intrusion work was conducted in 2020. We expect work at the Helena site will continue in 2021. MDEQ has indicated it expects to proceed in listing the Missoula site as a Montana superfund site. After researching historical ownership we have identified another potentially responsible party with whom we have entered into an agreement allocating third-party costs to be incurred in addressing the site. The other party is assuming the lead role at the site and has expressed its intent to pursue a voluntary remediation at the Missoula site. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, if any, at the Missoula site. Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of GHG including, most significantly, carbon dioxide (CO 2 ). These actions include legislative proposals, Executive and EPA actions at the federal level, actions at the state level, investor activism 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, Congress has not passed any federal climate change legislation and we cannot predict the timing or form of any potential legislation. In 2019, the EPA finalized the Affordable Clean Energy Rule (ACE), which repealed the 2015 Clean Power Plan (CPP) in regulating GHG emissions from coal-fired plants. The U.S. Court of Appeals for the District of Columbia Circuit issued an opinion on January 19, 2021, vacating the ACE and remanding it to EPA for further action. It is widely expected that the Biden Administration will develop an alternative plan for reducing GHG emissions from coal-fired plants. We cannot predict whether or how GHG emission regulations will be applied to our plants, including any actions taken by relevant state authorities. In addition, it is unclear how litigation relating to GHG matters will impact us. As GHG regulations are implemented, it could result in additional compliance costs impacting 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 impact 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. 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 or may be issued or proposed. 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 (CAA) that could require the installation of emission control equipment at the generation plants in which we have joint ownership. Air emissions at our thermal generating plants are managed by the use of emissions and combustion controls and monitoring, and sulfur dioxide allowances. These measures are anticipated to be sufficient to permit the facilities to continue to meet current air emissions compliance requirements. Regional Haze Rules - In January 2017, the EPA published amendments to the requirements under the CAA for state plans for protection of visibility - regional haze rules. 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. By July 31, 2021, Montana must develop and submit to the EPA for approval a revised plan that demonstrates reasonable progress toward eliminating man-made emissions of visibility impairing pollutants, which could impact Colstrip Unit 4. In March 2017, we filed a Petition for Review of these amendments with the D.C. Circuit, which was consolidated with other petitions challenging the final rule. The D.C. Circuit has granted the EPA’s request to hold the case in abeyance while the EPA considers further administrative action to revisit the rule. The North Dakota Department of Environmental Quality (ND DEQ) is expected to decide on statewide reduction strategy in 2021 which could impact the Coyote generating facility. Once the ND DEQ establishes a State Implementation Plan (SIP) for regional haze compliance, the SIP will be submitted for approval to the North Dakota Governor’s office and finally to EPA for approval. Following EPA’s approval, which is not expected to occur until the second half of 2021 or later, the joint owners of the Coyote generating facility will assess the requirements, if any, and determine whether to move forward with the installation of additional emissions controls. Additional controls, if any, to meet new emission restrictions would have to be in place by the end of 2028 under the current schedule. 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 a solar QF developer seeking to construct small solar facilities in Montana. We began negotiating with PNWS in early 2016 to purchase the output from 21 of its proposed facilities pursuant to our standard QF-1 Tariff, which is applicable to projects no larger than 3 MWs. On June 16, 2016, however, the MPSC suspended the availability of the QF-1 Tariff standard rates for that category of solar projects, which included the projects proposed by PNWS. The MPSC exempted from the suspension any projects for which a QF had both submitted a signed power purchase agreement and had executed an interconnection agreement with us by June 16, 2016. Although we had signed four power purchase agreements with PNWS as of that date, we had not entered into interconnection agreements with PNWS for any of those projects. As a result, none of the PNWS projects in Montana qualified for the exemption. In November 2016, PNWS sued us in state court seeking unspecified damages for breach of contract and a judicial declaration that some or all of the 21 proposed power purchase agreements it had proposed to us were in effect despite the MPSC's Order. We removed the state lawsuit to the United States District Court for the District of Montana (Court). PNWS also requested the MPSC to exempt its projects from the tariff suspension and allow those projects to receive the QF-1 tariff rate that had been in effect prior to the suspension. We joined in PNWS’s request for relief with respect to four of the projects, but the MPSC did not grant any of the relief requested by PNWS or us. In August 2017, pursuant to a non-monetary, partial settlement with us, PNWS amended its original complaint to limit its claims for enforcement and/or damages to only four of the 21 power purchase agreements. As a result, the amount of damages sought by the plaintiff was reduced to approximately $8 million for the alleged breach of the four power purchase agreements. We participated in an unsuccessful mediation on January 24, 2019 and subsequent settlement efforts also have been unsuccessful. A jury trial was scheduled to begin on June 2, 2020, but the trial was postponed because of the court closure due to the COVID-19 pandemic and has not yet been rescheduled. We dispute the remaining claims in PNWS’ lawsuit and will continue to vigorously defend against them. We cannot currently predict an outcome in this litigation. If the plaintiff prevails and obtains damages for a breach of contract, we may seek to recover those damages in rates from customers. We cannot predict the outcome of any such effort. 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 Montana, LLC (Talen) as defendants. The State claimed 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 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. In 2012, the United States Supreme Court issued a decision 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. Following briefing and argument, on October 10, 2017, the Federal District Court entered an order denying the State’s motion. Because 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. On August 1, 2018, the Federal District Court granted the motions to dismiss the State’s Complaint as it pertains to approximately 8.2 miles of riverbed from “the head of the Black Eagle Falls to the foot of the Great Falls.” In particular, the dismissal pertained to the Black Eagle Dam, Rainbow Dam and reservoir, Cochrane Dam and reservoir, and Ryan Dam and reservoir. While the dismissal of these four facilities may be subject to appeal, that appeal would not likely occur until after judgment in the case. On February 12, 2019, the Federal District Court granted our motion to join the United States as a defendant to the litigation. As a result, on October 31, 2019, the State filed and served an Amended Complaint including the United States as a defendant and removing claims of ownership for the hydroelectric facilities on the Great Falls Reach, except for the Morony and the Black Eagle Developments. We and Talen filed answers to the Amended Complaint on December 13, 2019, and the United States answered on February 5, 2020. The Federal District Court has scheduled trial for September 27, 2021, on the issue of navigability. By agreement of the parties, if the Federal District Court finds any segments navigable, the court will determine damages in a separate trial. The parties are engaged in discovery and the State has served its expert reports. We, along with the other Defendants, are scheduled to serve our expert reports in February 2021, after depositions of several of Plaintiff’s experts. We dispute the State’s claims and intend to vigorously defend the lawsuit. At this time, we cannot predict an outcome. If the Federal District Court determines the riverbeds are navigable under the remaining six facilities that were not dismissed and if it calculates damages as the State District Court did in 2008, we estimate the annual rents could be approximately $3.8 million commencing when we acquired the facilities in November 2014. 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. 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.

Revenue from Contracts with Cus

Revenue from Contracts with Customers Disaggegation of Revenue	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	(19) 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 do 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 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 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 tables disaggregate our revenue by major source and customer class (in millions): Twelve Months Ended December 31, 2020 December 31, 2019 Electric Natural Gas Total Electric Natural Gas Total Montana $ 320.8 $ 103.5 $ 424.3 $ 308.8 $ 109.4 $ 418.2 South Dakota 66.6 21.5 88.1 62.5 25.8 88.3 Nebraska — 16.9 16.9 — 20.2 20.2 Residential 387.4 141.9 529.3 371.3 155.4 526.7 Montana 338.3 51.3 389.6 348.1 55.7 403.8 South Dakota 101.1 14.3 115.4 97.1 19.3 116.4 Nebraska — 8.1 8.1 — 10.5 10.5 Commercial 439.4 73.7 513.1 445.2 85.5 530.7 Industrial 36.8 0.9 37.7 43.6 1.0 44.6 Lighting, Governmental, Irrigation, and Interdepartmental 31.8 0.9 32.7 30.6 1.0 31.6 Total Customer Revenues 895.4 217.4 1,112.8 890.7 242.9 1,133.6 Other Tariff and Contract Based Revenues 58.5 35.5 94.0 61.7 35.8 97.5 Total Revenue from Contracts with Customers 953.9 252.9 1,206.8 952.4 278.7 1,231.1 Regulatory amortization (13.1) 5.0 (8.1) 28.8 (2.0) 26.8 Total Revenues $ 940.8 $ 257.9 $ 1,198.7 $ 981.2 $ 276.7 $ 1,257.9

Segment and Related Information

Segment and Related Information	12 Months Ended
	Dec. 31, 2020
Segment Reporting [Abstract]
Segment and Related Information	(20) Segment and Related Information Our reportable business segments are primarily engaged in the electric and natural gas business. The remainder of our operations are presented as other, which primarily consists of unallocated corporate costs and unregulated activity. We evaluate the performance of these segments based on gross margin. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions. Financial data for the business segments for the twelve months ended are as follows (in thousands): December 31, 2020 Electric Gas Other Eliminations Total Operating revenues $ 940,815 $ 257,855 $ — $ — $ 1,198,670 Cost of sales 236,581 69,609 — — 306,190 Gross margin 704,234 188,246 — — 892,480 Operating, general and administrative 218,822 80,082 (1,789) — 297,115 Property and other taxes 140,621 38,887 9 — 179,517 Depreciation and depletion 147,968 31,676 — — 179,644 Operating income 196,823 37,601 1,780 — 236,204 Interest expense, net (85,487) (6,341) (4,984) — (96,812) Other income (expense), net 4,867 2,704 (2,718) — 4,853 Income tax benefit (expense) 11,282 (2,426) 2,114 — 10,970 Net income (loss) $ 127,485 $ 31,538 $ (3,808) $ — $ 155,215 Total assets $ 4,638,274 $ 1,739,555 $ 11,620 $ — $ 6,389,449 Capital expenditures $ 324,369 $ 81,393 $ — $ — $ 405,762 December 31, 2019 Electric Gas Other Eliminations Total Operating revenues $ 981,178 $ 276,732 $ — $ — $ 1,257,910 Cost of sales 239,589 78,431 — — 318,020 Gross margin 741,589 198,301 — — 939,890 Operating, general and administrative 232,424 82,732 3,073 — 318,229 Property and other taxes 134,686 37,192 10 — 171,888 Depreciation and depletion 143,262 29,661 — — 172,923 Operating income (loss) 231,217 48,716 (3,083) — 276,850 Interest expense, net (78,809) (6,218) (10,041) — (95,068) Other (expense) income, net (1,365) (814) 2,592 — 413 Income tax (expense) benefit (6,079) 493 25,511 — 19,925 Net income $ 144,964 $ 42,177 $ 14,979 $ — $ 202,120 Total assets $ 4,808,011 $ 1,270,811 $ 4,664 $ — $ 6,083,486 Capital expenditures $ 241,190 $ 74,826 $ — $ — $ 316,016 December 31, 2018 Electric Gas Other Eliminations Total Operating revenues $ 921,093 $ 270,916 $ — $ — $ 1,192,009 Cost of sales 194,608 78,275 — — 272,883 Gross margin 726,485 192,641 — — 919,126 Operating, general and administrative 223,598 82,864 657 — 307,119 Property and other taxes 134,681 36,569 9 — 171,259 Depreciation and depletion 144,636 29,822 18 — 174,476 Operating income (loss) 223,570 43,386 (684) — 266,272 Interest expense, net (79,033) (5,858) (7,097) — (91,988) Other income, net 2,794 962 210 — 3,966 Income tax benefit (expense) 21,686 9,268 (12,244) — 18,710 Net income (loss) $ 169,017 $ 47,758 $ (19,815) $ — $ 196,960 Total assets $ 4,626,530 $ 1,174,737 $ 4,732 $ — $ 5,805,999 Capital expenditures $ 221,968 $ 61,998 $ — $ — $ 283,966

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2020
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data	(21) Fourth Quarter Financial Data (Unaudited) Our fourth quarter financial information has not been audited, but, in management's opinion, includes all adjustments necessary for a fair presentation. Amounts presented are in thousands, except per share data: Three Months Ended December 31, 2020 2019 Operating revenues $ 313,445 $ 328,135 Operating income 66,496 84,651 Net income $ 53,551 $ 59,982 Average common shares outstanding 50,583 50,448 Income per average common share: Basic $ 1.06 $ 1.19 Diluted $ 1.06 $ 1.18

Nature of Operations and Basi_2

Nature of Operations and Basis of Consolidation (Policies)	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable Interest Entities	Variable Interest Entities A reporting company is required to consolidate a variable interest entity (VIE) as its primary beneficiary, which means it has a controlling financial interest, when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity's purpose and design and a company's ability to direct the activities of the entity that most significantly impact the entity's economic performance.
Reclassification, Comparability Adjustment	Reclassification In 2020, we changed our classification of excess deferred income taxes in the Consolidated Balance Sheets from a regulatory asset to a regulatory liability, such that the excess deferred income tax regulatory liabilities are reflected on a gross basis, rather than net within our income tax regulatory asset based on our right to offset. The impact on the December 31, 2019 Consolidated Balance Sheet is an increase of Noncurrent regulatory assets and Noncurrent regulatory liabilities of $172.8 million. The impact to our Consolidated Statements of Cash Flows for the years ended December 31, 2019 and 2018 is a gross up of non-cash activity within the Other noncurrent assets and Other noncurrent liabilities captions, both within the operating activities section, that offset one another with no impact to cash provided by operating activities. The impact of the reclassification as of December 31, 2019 is also reflected in Note 4 - Regulatory Assets and Liabilities and Note 20 - Segment and Related Information. The impact to the total assets reported in the 2018 segment information table within Note 20 - Segment and Related Information was an increase of $161.6 million. This reclassification had no effect on previously reported Net income in our Consolidated Statements of Income, Consolidated Statements of Comprehensive Income, and Consolidated Statements of Common Shareholders’ Equity.

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Estimates are used for such items as long-lived asset values and impairment charges, long-lived asset useful lives, tax provisions, uncertain tax position reserves, asset retirement obligations, regulatory assets and liabilities, allowances for uncollectible accounts, our QF liability, environmental liabilities, unbilled revenues and actuarially determined benefit costs and liabilities. We revise the recorded estimates when we receive better information or when we can determine actual amounts. Those revisions can affect operating results.
Revenue Recognition	Revenue Recognition The Company recognizes revenue as customers obtain control of promised goods and services in an amount that reflects consideration expected in exchange for those goods or services. Generally, the delivery of electricity and natural gas results in the transfer of control to customers at the time the commodity is delivered and the amount of revenue recognized is equal to the amount billed to each customer, including estimated volumes delivered when billings have not yet occurred.
Cash Equivalents	Cash Equivalents We consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents.
Restricted cash	Restricted Cash Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements.
Accounts Receivable, Net	Accounts Receivable, Net Accounts receivable are net of allowances for uncollectible accounts of $5.6 million and $2.3 million at December 31, 2020 and December 31, 2019. Receivables include unbilled revenues of $80.5 million and $83.3 million at December 31, 2020 and December 31, 2019, respectively.
Regulation of Utility Operations	Regulation of Utility Operations Our regulated operations are subject to the provisions of ASC 980, Regulated Operations. Regulated accounting is appropriate provided that (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are designed to recover the specific enterprise's cost of service, and (iii) in view of demand for service, it is reasonable to assume that rates are set at levels that will recover costs and can be charged to and collected from customers. Our Consolidated Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. The economic effects of regulation can result in regulated companies recording costs that have been, or are deemed probable to be, allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities). If we were required to terminate the application of these provisions to our regulated operations, all such deferred amounts would be recognized in the Consolidated Statements of Income at that time. This would result in a charge to earnings and accumulated other comprehensive loss (AOCL), net of applicable income taxes, which could be material. In addition, we would determine any impairment to the carrying costs of deregulated plant and inventory assets.
Derivative Financial Instruments	Derivative Financial Instruments We account for derivative instruments in accordance with ASC 815, Derivatives and Hedging. All derivatives are recognized in the Consolidated Balance Sheets at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair-value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash-flow hedge). For fair-value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash-flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in AOCL and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For other derivative contracts that do not qualify or are not designated for hedge accounting, changes in the fair value of the derivatives are recognized in earnings each period. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the underlying nature of the hedged items. Revenues and expenses on contracts that are designated as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but on an accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric and gas operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it were determined that a transaction designated as a normal purchase or a normal sale no longer met the exceptions, the fair value of the related contract would be reflected as an asset or liability and immediately recognized through earnings. See Note 8 - Risk Management and Hedging Activities, for further discussion of our derivative activity.
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment are stated at original cost, including contracted services, direct labor and material, AFUDC, and indirect charges for engineering, supervision and similar overhead items. All expenditures for maintenance and repairs of utility property, plant and equipment are charged to the appropriate maintenance expense accounts. A betterment or replacement of a unit of property is accounted for as an addition and retirement of utility plant. At the time of such a retirement, the accumulated provision for depreciation is charged with the original cost of the property retired and also for the net cost of removal. Also included in plant and equipment are assets under finance lease, which are stated at the present value of minimum lease payments. AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized currently from such allowance, it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. This rate averaged 6.7%, 6.9%, and 7.1% for Montana for 2020, 2019, and 2018, respectively. This rate averaged 6.7%, 6.6%, and 6.7% for South Dakota for 2020, 2019, and 2018, respectively. AFUDC capitalized totaled $9.8 million, $8.2 million, and $5.9 million for the years ended December 31, 2020, 2019, and 2018, respectively, for Montana and South Dakota combined. We record provisions for depreciation at amounts substantially equivalent to calculations made on a straight-line method by applying various rates based on useful lives of the various classes of properties (ranging from 2 to 96 years) determined from engineering studies. As a percentage of the depreciable utility plant at the beginning of the year, our provision for depreciation of utility plant was approximately 2.8%, 2.8%, and 3.0% for 2020, 2019, and 2018, respectively. Depreciation rates include a provision for our share of the estimated costs to decommission our jointly owned plants at the end of the useful life. The annual provision for such costs is included in depreciation expense, while the accumulated provisions are included in noncurrent regulatory liabilities.
Pension and Postretirement Benefits	Pension and Postretirement Benefits We have liabilities under defined benefit retirement plans and a postretirement plan that offers certain health care and life insurance benefits to eligible employees and their dependents. The costs of these plans are dependent upon numerous factors, assumptions and estimates, including determination of discount rate, expected return on plan assets, rate of future compensation increases, age and mortality and employment periods. In determining the projected benefit obligations and costs, assumptions can change from period to period and may result in material changes in the cost and liabilities we recognize.
Income Taxes	Income Taxes We follow the liability method in accounting for income taxes. Deferred income tax assets and liabilities represent the future effects on income taxes from temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized. Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ
Environmental Costs	Environmental Costs We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset if there is precedent for recovering similar costs from customers in rates. Otherwise, we expense the costs. If an environmental cost is related to facilities we currently use, such as pollution control equipment, then we may capitalize and depreciate the costs over the remaining life of the asset, assuming the costs are recoverable in future rates or future cash flows.

Revenue from Contracts with C_2

Revenue from Contracts with Customers Accounting Policy (Policies)	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Policy Text Block]	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 do 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.

Significant Accounting Polici_3

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Inventories	Inventories Inventories are stated at average cost. Inventory consisted of the following (in thousands): December 31, 2020 2019 Materials and supplies $ 44,311 $ 42,791 Storage gas and fuel 16,699 11,134 Total Inventories $ 61,010 $ 53,925
Schedule of Accrued Liabilities	Accrued Expenses Accrued expenses consisted of the following (in thousands): December 31, 2020 2019 Property taxes $ 89,425 $ 85,242 Employee compensation, benefits, and withholdings 40,538 50,142 Interest 18,074 17,538 Other (none of which is individually significant) 59,477 49,099 Total Accrued Expenses $ 207,514 $ 202,021
Other Noncurrent Liabilities	Other Noncurrent Liabilities Other noncurrent liabilities consisted of the following (in thousands): December 31, 2020 2019 Pension and other employee benefits $ 136,632 $ 128,853 Future QF obligation, net 81,379 92,937 Customer advances 65,186 56,870 Asset retirement obligations 45,355 42,449 Environmental 25,049 27,741 Other (none of which is individually significant) 57,102 38,302 Total Noncurrent Liabilities $ 410,703 $ 387,152
Supplemental Cash Flow Information	Supplemental Cash Flow Information Year Ended December 31, 2020 2019 2018 (in thousands) Cash paid (received) for: Income taxes $ 115 $ (6,737) $ 55 Interest 84,922 83,776 76,499 Significant non-cash transactions: Capital expenditures included in trade accounts payable 21,430 33,473 21,625
Reconciliation of Cash and Restricted Cash [Table Text Block]	The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same such amounts shown in the Consolidated Statements of Cash Flows (in thousands): December 31, 2020 2019 2018 Cash and cash equivalents $ 5,811 $ 5,145 $ 7,860 Restricted cash 11,285 6,925 7,451 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 17,096 $ 12,070 $ 15,311

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2020
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets And Liabilities	Note Reference Remaining Amortization Period December 31, 2020 2019 (in thousands) Flow-through income taxes 12 Plant Lives $ 420,925 $ 376,548 Excess deferred income taxes 12 Plant Lives 67,256 73,670 Pension 14 Undetermined 138,567 132,000 Deferred financing costs Various 28,350 31,089 Employee related benefits 14 Undetermined 22,516 18,622 Supply costs 1 Year 8,116 35,454 State & local taxes & fees Various 17,910 7,146 Environmental clean-up 18 Various 11,127 11,179 Other Various 31,650 25,639 Total Regulatory Assets $ 746,417 $ 711,347 Removal cost 6 Various $ 464,669 $ 442,129 Excess deferred income taxes 12 Plant Lives 165,279 172,784 Supply costs 1 Year 13,847 14,226 Gas storage sales 19 years 7,887 8,307 Rates subject to refund 1 Year 32,496 14,177 State & local taxes & fees 1 Year 1,783 1,846 Environmental clean-up Various 656 1,181 Other Various 655 2,697 Total Regulatory Liabilities $ 687,272 $ 657,347

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Major classifications of property, plant and equipment	The following table presents the major classifications of our property, plant and equipment (in thousands): Estimated Useful Life December 31, 2020 2019 (years) (in thousands) Transmission, distribution, and storage 15 – 95 $ 3,771,023 $ 3,569,141 Generation 23 – 72 1,252,805 1,222,796 Plant acquisition adjustment (1) 25 – 50 686,328 686,328 Building and improvements 23 – 73 303,099 278,164 Land, land rights and easements 53 – 96 157,379 156,069 Other 2 – 45 571,981 545,009 Construction work in process –— 173,492 96,421 Total property, plant and equipment 6,916,107 6,553,928 Less accumulated depreciation (1,703,016) (1,617,817) Less accumulated amortization (260,156) (235,187) Net property, plant and equipment $ 4,952,935 $ 4,700,924
Schedule of jointly owned utility plants	Information relating to our ownership interest in these facilities is as follows (in thousands): Big Stone Neal #4 Coyote Colstrip Unit 4 (MT) December 31, 2020 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 153,632 $ 62,927 $ 51,586 $ 317,438 Accumulated depreciation 40,665 33,942 37,980 105,738 December 31, 2019 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 155,662 $ 62,565 $ 52,448 $ 311,399 Accumulated depreciation 40,988 32,853 38,310 97,563

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation	The following table presents the change in our ARO (in thousands): December 31, 2020 2019 2018 Liability at January 1, $ 42,449 $ 40,659 $ 39,286 Accretion expense 2,070 2,051 2,031 Liabilities incurred — — 773 Liabilities settled (4,061) (46) (63) Revisions to cash flows 4,897 (215) (1,368) Liability at December 31, $ 45,355 $ 42,449 $ 40,659

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	Goodwill by segment is as follows (in thousands): December 31, 2020 2019 Electric $ 243,558 $ 243,558 Natural gas 114,028 114,028 Total Goodwill $ 357,586 $ 357,586

Risk Management and Hedging A_2

Risk Management and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)	The following table shows the effect of these interest rate swaps previously terminated on the Consolidated Financial Statements (in thousands): Cash Flow Hedges Location of Amount Reclassified from AOCL to Income Amount Reclassified from AOCL into Income during the Year Ended December 31, 2020 Interest rate contracts Interest Expense $ 614

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	We record transfers between levels of the fair value hierarchy, if necessary, at the end of the reporting period. There were no transfers between levels for the periods presented. December 31, 2020 Quoted Prices in Active Markets for Identical Assets or Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Margin Cash Collateral Offset Total Net Fair Value (in thousands) Restricted cash equivalents $ 10,055 $ — $ — $ — $ 10,055 Rabbi trust investments 27,027 — — — 27,027 Total $ 37,082 $ — $ — $ — $ 37,082 December 31, 2019 Restricted cash equivalents $ 5,699 $ — $ — $ — $ 5,699 Rabbi trust investments 29,288 — — — 29,288 Total $ 34,987 $ — $ — $ — $ 34,987
Schedule of Estimated Fair Value of Financial Instruments	The estimated fair value of financial instruments is summarized as follows (in thousands): December 31, 2020 December 31, 2019 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 2,315,261 $ 2,629,755 $ 2,233,281 $ 2,416,814

Short-Term Borrowings and Cre_2

Short-Term Borrowings and Credit Arrangements (Tables)	12 Months Ended
	Dec. 31, 2020
Line of Credit Facility [Line Items]
Line of credit facilities availability	The availability under the facilities in place for the years ended December 31 is shown in the following table (in millions): 2020 2019 Unsecured revolving line of credit, expiring September 2023 $ 425.0 $ — Unsecured revolving line of credit, expiring December 2021 — 400.0 Unsecured revolving line of credit, expiring March 2022 25.0 25.0 450.0 425.0 Amounts outstanding at December 31: Eurodollar borrowings 222.0 289.0 Letters of credit — — 222.0 289.0 Net availability as of December 31 $ 228.0 $ 136.0

Long-Term Debt and Capital Le_2

Long-Term Debt and Capital Leases (Tables)	12 Months Ended
	Dec. 31, 2020
Long-term Debt and Lease Obligation [Abstract]
Schedule of Debt and Capital Leases	Long-term debt and finance leases consisted of the following (in thousands): December 31, Due 2020 2019 Unsecured Debt: Unsecured Revolving Line of Credit 2023 $ 222,000 $ — Unsecured Revolving Line of Credit 2021 — 289,000 Secured Debt: Mortgage bonds— South Dakota—5.01% 2025 64,000 64,000 South Dakota—4.15% 2042 30,000 30,000 South Dakota—4.30% 2052 20,000 20,000 South Dakota—4.85% 2043 50,000 50,000 South Dakota—4.22% 2044 30,000 30,000 South Dakota—4.26% 2040 70,000 70,000 South Dakota—3.21% 2030 50,000 — South Dakota—2.80% 2026 60,000 60,000 South Dakota—2.66% 2026 45,000 45,000 Montana—5.71% 2039 55,000 55,000 Montana—5.01% 2025 161,000 161,000 Montana—4.15% 2042 60,000 60,000 Montana—4.30% 2052 40,000 40,000 Montana—4.85% 2043 15,000 15,000 Montana—3.99% 2028 35,000 35,000 Montana—4.176% 2044 450,000 450,000 Montana—3.11% 2025 75,000 75,000 Montana—4.11% 2045 125,000 125,000 Montana—4.03% 2047 250,000 250,000 Montana—3.98% 2049 150,000 150,000 Montana—3.21% 2030 100,000 — Pollution control obligations— Montana—2.00% 2023 144,660 144,660 Other Long Term Debt: New Market Tax Credit Financing—1.146% 2046 26,977 26,977 Discount on Notes and Bonds and Debt Issuance Costs, Net — (13,376) (12,356) $ 2,315,261 $ 2,233,281 Less current maturities — — Total Long-Term Debt $ 2,315,261 $ 2,233,281 Finance Leases: Total Finance Leases Various $ 17,439 $ 19,915 Less current maturities (2,668) (2,476) Total Long-Term Finance Leases $ 14,771 $ 17,439

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Schedule Of Income Tax Expense Domestic	Income tax benefit is comprised of the following (in thousands): Year Ended December 31, 2020 2019 2018 Federal Current $ (3,396) $ (6,076) $ (5,526) Deferred (4,006) (15,169) (15,588) Investment tax credits (3) (12) (33) State Current 3 27 38 Deferred (3,568) 1,305 2,399 Income Tax Benefit $ (10,970) $ (19,925) $ (18,710)
Schedule of Effective Income Tax Rate Reconciliation	The following table reconciles our effective income tax rate to the federal statutory rate: Year Ended December 31, 2020 2019 2018 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax, net of federal provisions (1.1) 0.7 0.9 Flow-through repairs deductions (16.5) (10.8) (10.8) Production tax credits (9.1) (6.3) (6.1) Amortization of excess DIT (0.7) (0.9) (2.1) Recognition of unrecognized tax benefit — (12.5) — Impact of Tax Cuts and Jobs Act — (0.1) (11.1) Plant and depreciation of flow through items 0.1 (2.2) (1.2) Prior year permanent return to accrual adjustments (1.2) 0.3 (1.7) Other, net (0.1) (0.1) 0.6 Effective tax rate (7.6) % (10.9) % (10.5) % The table below summarizes the significant differences in income tax benefit based on the differences between our effective tax rate and the federal statutory rate (in thousands). Year Ended December 31, 2020 2019 2018 Income Before Income Taxes $ 144,245 $ 182,195 $ 178,250 Income tax calculated at federal statutory rate 30,292 38,261 37,433 Permanent or flow through adjustments: State income, net of federal provisions (1,477) 1,251 1,613 Flow-through repairs deductions (23,828) (19,706) (19,323) Production tax credits (13,103) (11,483) (10,890) Amortization of excess DIT (968) (1,688) (3,731) Recognition of unrecognized tax benefit — (22,825) — Impact of Tax Cuts and Jobs Act — (198) (19,840) Plant and depreciation of flow through items 121 (3,952) (2,175) Prior year permanent return to accrual adjustments (1,728) 559 (2,978) Other, net (279) (144) 1,181 (41,262) (58,186) (56,143) Income Tax Benefit $ (10,970) $ (19,925) $ (18,710)
Schedule of Deferred Tax Assets and Liabilities	The components of the net deferred income tax liability recognized in our Consolidated Balance Sheets are related to the following temporary differences (in thousands): December 31, 2020 2019 Production tax credit $ 63,542 $ 50,440 Pension / postretirement benefits 31,866 30,041 Customer advances 17,165 14,975 Unbilled revenue 14,429 9,820 Compensation accruals 11,748 13,163 Reserves and accruals 6,266 7,069 Environmental liability 6,039 5,938 Interest rate hedges 3,171 3,956 NOL carryforward 393 10,050 AMT credit carryforward — 3,400 Other, net 2,490 1,801 Deferred Tax Asset 157,109 150,653 Excess tax depreciation (412,774) (393,287) Goodwill amortization (83,991) (82,595) Flow through depreciation (83,545) (71,679) Regulatory assets and other (48,576) (51,078) Deferred Tax Liability (628,886) (598,639) Deferred Tax Liability, net $ (471,777) $ (447,986)
Summary of Income Tax Contingencies	The change in unrecognized tax benefits is as follows (in thousands): 2020 2019 2018 Unrecognized Tax Benefits at January 1 $ 35,085 $ 56,150 $ 57,473 Gross increases - tax positions in prior period 120 539 — Gross increases - tax positions in current period — — 338 Gross decreases - tax positions in current period (1,714) (1,489) (1,661) Lapse of statute of limitations — (20,115) — Unrecognized Tax Benefits at December 31 $ 33,491 $ 35,085 $ 56,150

Comprehensive Income (Loss) (Ta

Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Schedule of Comprehensive Income (Loss)	The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands): December 31, 2020 2019 2018 Before-Tax Amount Tax Expense (Benefit) Net-of-Tax Amount Before-Tax Amount Tax Expense Net-of-Tax Amount Before-Tax Amount Tax Expense Net-of-Tax Amount Foreign currency translation adjustment $ 87 $ — $ 87 $ (35) $ — $ (35) $ 270 $ — $ 270 Reclassification of net income (loss) on derivative instruments 614 (162) 452 614 (162) 452 614 (116) 498 Postretirement medical liability adjustment 2,463 (623) 1,840 (175) 44 (131) 346 (133) 213 Other comprehensive income (loss) $ 3,164 $ (785) $ 2,379 $ 404 $ (118) $ 286 $ 1,230 $ (249) $ 981
Accumulated Other Comprehensive Income [Table Text Block]	Balances by classification included within AOCL on the Consolidated Balance Sheets are as follows, net of tax (in thousands): December 31, 2020 2019 Foreign currency translation $ 1,500 $ 1,413 Derivative instruments designated as cash flow hedges (10,729) (11,181) Postretirement medical plans 1,960 120 Accumulated other comprehensive loss $ (7,269) $ (9,648)
Schedule of Accumulated Comprehensive Income (Loss)	The following table displays the changes in AOCL by component, net of tax (in thousands): December 31, 2020 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (11,181) $ 120 $ 1,413 $ (9,648) Other comprehensive income before reclassifications — — 87 87 Amounts reclassified from AOCL Interest Expense 452 — — 452 Amounts reclassified from AOCL — 1,840 — 1,840 Net current-period other comprehensive income 452 1,840 87 2,379 Ending Balance $ (10,729) $ 1,960 $ 1,500 $ (7,269) December 31, 2019 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (11,633) $ 251 $ 1,448 $ (9,934) Other comprehensive income before reclassifications — — (35) (35) Amounts reclassified from AOCL Interest Expense 452 — — 452 Amounts reclassified from AOCL — (131) — (131) Net current-period other comprehensive income (loss) 452 (131) (35) 286 Ending Balance $ (11,181) $ 120 $ 1,413 $ (9,648)

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2020
Retirement Benefits [Abstract]
Schedule of Changes in Projected Benefit Obligations	Following is a reconciliation of the changes in plan benefit obligations and fair value of plan assets, and a statement of the funded status (in thousands): Pension Benefits Other Postretirement Benefits December 31, December 31, 2020 2019 2020 2019 Change in benefit obligation: Obligation at beginning of period $ 735,564 $ 649,626 $ 20,272 $ 20,611 Service cost 11,116 9,637 370 331 Interest cost 22,840 26,488 492 609 Actuarial loss 84,479 83,364 123 997 Settlements — (4,065) 390 390 Benefits paid (33,020) (29,486) (2,501) (2,666) Benefit Obligation at End of Period $ 820,979 $ 735,564 $ 19,146 $ 20,272 Change in Fair Value of Plan Assets: Fair value of plan assets at beginning of period $ 609,000 $ 525,310 $ 21,479 $ 18,670 Return on plan assets 101,075 107,041 2,723 3,805 Employer contributions 11,401 10,200 1,395 1,670 Settlements — (4,065) — — Benefits paid (33,020) (29,486) (2,501) (2,666) Fair value of plan assets at end of period $ 688,456 $ 609,000 $ 23,096 $ 21,479 Funded Status $ (132,523) $ (126,564) $ 3,950 $ 1,207 Amounts Recognized in the Balance Sheet Consist of: Noncurrent asset 7,001 4,333 8,436 7,783 Total Assets 7,001 4,333 8,436 7,783 Current liability (11,200) (11,401) (1,712) (2,113) Noncurrent liability (128,324) (119,496) (2,774) (4,463) Total Liabilities (139,524) (130,897) (4,486) (6,576) Net amount recognized $ (132,523) $ (126,564) $ 3,950 $ 1,207 Amounts Recognized in Regulatory Assets Consist of: Prior service credit — — 3,857 5,890 Net actuarial loss (115,987) (111,449) (497) 259 Amounts recognized in AOCL consist of: Prior service cost — — (246) (397) Net actuarial gain — — 3,246 934 Total $ (115,987) $ (111,449) $ 6,360 $ 6,686
Schedule of Benefit Obligations in Excess of Fair Value of Plan Assets	The total projected benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were as follows (in millions): NorthWestern Energy Pension Plan December 31, 2020 2019 Projected benefit obligation $ 757.4 $ 675.5 Accumulated benefit obligation 757.4 675.5 Fair value of plan assets 619.1 545.8 ____________________
Schedule of Defined Benefit Plans Disclosures	The components of the net costs (credits) for our pension and other postretirement plans are as follows (in thousands): Pension Benefits Other Postretirement Benefits December 31, December 31, 2020 2019 2018 2020 2019 2018 Components of Net Periodic Benefit Cost Service cost $ 11,116 $ 9,637 $ 11,776 $ 370 $ 331 $ 398 Interest cost 22,840 26,488 24,420 492 609 578 Expected return on plan assets (26,162) (25,443) (28,207) (983) (869) (954) Amortization of prior service cost (credit) — — 4 (1,882) (1,882) (1,882) Recognized actuarial loss (gain) 5,028 6,544 4,360 (61) (96) (79) Settlement loss recognized — 198 — 390 390 390 Net Periodic Benefit Cost (Credit) $ 12,822 $ 17,424 $ 12,353 $ (1,674) $ (1,517) $ (1,549) Regulatory deferral of net periodic benefit cost (1) (2,100) (7,510) (4,057) — — — Previously deferred costs recognized (1) 71 728 243 861 931 913 Amount Recognized in Income $ 10,793 $ 10,642 $ 8,539 $ (813) $ (586) $ (636) Income Statement Presentation Operating, general and administrative expense 9,016 2,125 7,719 370 331 398 Other income (expense), net 1,777 8,517 820 (1,183) (917) (1,034) Amount Recognized in Income $ 10,793 $ 10,642 $ 8,539 $ (813) $ (586) $ (636) ___________________________ (1) Net periodic benefit costs for pension and postretirement benefit plans are recognized for financial reporting based on the authorization of each regulatory jurisdiction in which we operate. A portion of these costs are recorded in regulatory assets and recognized in the Consolidated Statements of Income as those costs are recovered through customer rates.
Schedule of Assumptions Used	The weighted-average assumptions used in calculating the preceding information are as follows: Pension Benefits Other Postretirement Benefits December 31, December 31, 2020 2019 2018 2020 2019 2018 Discount rate 2.20-2.30 % 3.10-3.20 % 4.15-4.20 % 1.80 % 2.80 % 3.90-3.95 % Expected rate of return on assets 3.45-4.49 4.23-5.06 4.47-4.97 4.71 4.79 4.82 Long-term rate of increase in compensation levels (non-union) 2.84 2.84 2.84 2.84 2.84 2.84 Long-term rate of increase in compensation levels (union) 2.00 2.00 2.03 2.00 2.00 2.03 Interest crediting rate 3.30-6.00 3.60-6.00 4.00-6.00 N/A N/A N/A
Schedule of Pension And Postretirement Benefits Investment Strategy	Based on this, the target asset allocation established, within an allowable range of plus or minus 5 percent, is as follows: NorthWestern Energy Pension NorthWestern Corporation Pension NorthWestern Energy December 31, December 31, December 31, 2020 2019 2020 2019 2020 2019 Fixed income securities 55.0 % 55.0 % 80.0 % 80.0 % 40.0 % 40.0 % Non-U.S. fixed income securities 4.0 4.0 2.0 2.0 — — Global equities 41.0 41.0 18.0 18.0 60.0 60.0
Schedule of Allocation of Plan Assets	The actual allocation by plan is as follows: NorthWestern Energy Pension NorthWestern Corporation Pension NorthWestern Energy December 31, December 31, December 31, 2020 2019 2020 2019 2020 2019 Cash and cash equivalents — % — % 0.7 % 0.9 % 1.0 % 1.0 % Fixed income securities 52.7 53.8 77.3 77.0 37.9 37.8 Non-U.S. fixed income securities 3.8 4.0 2.6 2.6 — — Global equities 43.5 42.2 19.4 19.5 61.1 61.2 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % 100.0 %
Schedule of Pension Contributions	Annual contributions to each of the pension plans are as follows (in thousands): 2020 2019 2018 NorthWestern Energy Pension Plan (MT) $ 10,201 $ 9,000 $ 8,000 NorthWestern Corporation Pension Plan (SD and NE) 1,200 1,200 1,200 $ 11,401 $ 10,200 $ 9,200
Schedule of Expected Benefit Payments	We estimate the plans will make future benefit payments to participants as follows (in thousands): Pension Benefits Other Postretirement Benefits 2021 $ 35,200 $ 2,729 2022 36,533 2,469 2023 37,847 2,331 2024 39,189 1,615 2025 40,210 1,457 2026-2030 209,556 5,699

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions	The following summarizes the significant assumptions used to determine the fair value of performance shares and related compensation expense as well as the resulting estimated fair value of performance shares granted: 2020 2019 Risk-free interest rate 1.42 % 2.47 % Expected life, in years 3 3 Expected volatility 14.9% to 19.7% 16.4% to 20.9% Dividend yield 3.1 % 3.5 %
Schedule of Nonvested Share Activity	A summary of nonvested shares as of and changes during the year ended December 31, 2020, are as follows: Performance Unit Awards Shares Weighted-Average Grant-Date Beginning nonvested grants 178,245 $ 53.00 Granted 62,116 73.13 Vested (105,512) 47.99 Forfeited (4,278) 63.57 Remaining nonvested grants 130,571 $ 66.27
Share-based Compensation Arrangement by Share-based Payment Award
Schedule of Nonvested Restricted Stock Units Activity	A summary of nonvested shares as of and changes during the year ended December 31, 2020, are as follows: Shares Weighted-Average Grant-Date Beginning nonvested grants 72,858 $ 51.35 Granted 20,199 44.57 Vested (15,090) 44.77 Forfeited — — Remaining nonvested grants 77,967 $ 50.86
Schedule of Deferred Compensation Arrangement with Individual, Share-based Payments	Following is a summary of the components of DSUs issued and compensation expense attributable to the DSUs (in millions, except DSU amounts): December 31, 2020 2019 2018 DSUs Issued 21,434 19,027 29,870 Compensation expense $ 1.5 $ 1.3 $ 1.8 Change in value of shares (2.9) 2.4 0.1 Total compensation (benefit) expense $ (1.4) $ 3.7 $ 1.9 DSUs withdrawn 613 3,708 136,640 Value of DSUs withdrawn $ 0.1 $ 0.3 $ 8.2

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2020
Earnings Per Share [Abstract]
Schedule of Weighted Average Number of Shares	Average shares used in computing the basic and diluted earnings per share are as follows: December 31, 2020 2019 2018 Basic computation 50,559,208 50,428,560 49,984,562 Dilutive effect of Performance and restricted share awards (1) 145,181 323,298 252,909 Diluted computation 50,704,389 50,751,858 50,237,471 _____________________ (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. As of December 31, 2020, there were 53,716 shares from performance and restricted share awards which were antidilutive and excluded from the earnings per share calculations.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Schedule of Changes In Qualifying Facility Liability	The following summarizes the change in the liability (in thousands): December 31, 2020 2019 Beginning QF liability $ 92,937 $ 102,260 Unrecovered amount (1) (18,665) (17,257) Interest expense 7,107 7,934 Ending QF liability $ 81,379 $ 92,937 ___________________ (1) The change in the unrecovered amount includes (i) a lower periodic adjustment of $1.1 million due to actual price escalation, which was less than previously modeled, and (ii) higher costs of approximately $2.2 million, due to a $0.9 million reduction in costs for the adjustment to actual output and pricing for the current contract year as compared with a $3.1 million reduction in costs in the prior period.
Schedule of Estimated Gross Contractual Obligation Less Amounts Recoverable Through Rates	The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands): Gross Recoverable Net 2021 $ 77,722 $ 60,136 $ 17,586 2022 79,572 60,639 18,933 2023 81,646 61,280 20,366 2024 79,384 60,706 18,678 2025 65,041 52,950 12,091 Thereafter 168,592 152,837 15,755 Total $ 551,957 $ 448,548 $ 103,409
Schedule of Environmental Loss Contingencies by Site	The following summarizes the change in our environmental liability (in thousands): December 31, 2020 2019 2018 Liability at January 1, $ 30,276 $ 29,741 $ 30,326 Deductions (2,977) (2,232) (2,333) Charged to costs and expense 1,596 2,767 1,748 Liability at December 31, $ 28,895 $ 30,276 $ 29,741

Revenue from Contracts with C_3

Revenue from Contracts with Customers Disaggregation of Revenue (Tables)	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	The following tables disaggregate our revenue by major source and customer class (in millions): Twelve Months Ended December 31, 2020 December 31, 2019 Electric Natural Gas Total Electric Natural Gas Total Montana $ 320.8 $ 103.5 $ 424.3 $ 308.8 $ 109.4 $ 418.2 South Dakota 66.6 21.5 88.1 62.5 25.8 88.3 Nebraska — 16.9 16.9 — 20.2 20.2 Residential 387.4 141.9 529.3 371.3 155.4 526.7 Montana 338.3 51.3 389.6 348.1 55.7 403.8 South Dakota 101.1 14.3 115.4 97.1 19.3 116.4 Nebraska — 8.1 8.1 — 10.5 10.5 Commercial 439.4 73.7 513.1 445.2 85.5 530.7 Industrial 36.8 0.9 37.7 43.6 1.0 44.6 Lighting, Governmental, Irrigation, and Interdepartmental 31.8 0.9 32.7 30.6 1.0 31.6 Total Customer Revenues 895.4 217.4 1,112.8 890.7 242.9 1,133.6 Other Tariff and Contract Based Revenues 58.5 35.5 94.0 61.7 35.8 97.5 Total Revenue from Contracts with Customers 953.9 252.9 1,206.8 952.4 278.7 1,231.1 Regulatory amortization (13.1) 5.0 (8.1) 28.8 (2.0) 26.8 Total Revenues $ 940.8 $ 257.9 $ 1,198.7 $ 981.2 $ 276.7 $ 1,257.9

Segment and Related Informati_2

Segment and Related Information (Tables)	12 Months Ended
	Dec. 31, 2020
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Financial data for the business segments for the twelve months ended are as follows (in thousands): December 31, 2020 Electric Gas Other Eliminations Total Operating revenues $ 940,815 $ 257,855 $ — $ — $ 1,198,670 Cost of sales 236,581 69,609 — — 306,190 Gross margin 704,234 188,246 — — 892,480 Operating, general and administrative 218,822 80,082 (1,789) — 297,115 Property and other taxes 140,621 38,887 9 — 179,517 Depreciation and depletion 147,968 31,676 — — 179,644 Operating income 196,823 37,601 1,780 — 236,204 Interest expense, net (85,487) (6,341) (4,984) — (96,812) Other income (expense), net 4,867 2,704 (2,718) — 4,853 Income tax benefit (expense) 11,282 (2,426) 2,114 — 10,970 Net income (loss) $ 127,485 $ 31,538 $ (3,808) $ — $ 155,215 Total assets $ 4,638,274 $ 1,739,555 $ 11,620 $ — $ 6,389,449 Capital expenditures $ 324,369 $ 81,393 $ — $ — $ 405,762 December 31, 2019 Electric Gas Other Eliminations Total Operating revenues $ 981,178 $ 276,732 $ — $ — $ 1,257,910 Cost of sales 239,589 78,431 — — 318,020 Gross margin 741,589 198,301 — — 939,890 Operating, general and administrative 232,424 82,732 3,073 — 318,229 Property and other taxes 134,686 37,192 10 — 171,888 Depreciation and depletion 143,262 29,661 — — 172,923 Operating income (loss) 231,217 48,716 (3,083) — 276,850 Interest expense, net (78,809) (6,218) (10,041) — (95,068) Other (expense) income, net (1,365) (814) 2,592 — 413 Income tax (expense) benefit (6,079) 493 25,511 — 19,925 Net income $ 144,964 $ 42,177 $ 14,979 $ — $ 202,120 Total assets $ 4,808,011 $ 1,270,811 $ 4,664 $ — $ 6,083,486 Capital expenditures $ 241,190 $ 74,826 $ — $ — $ 316,016 December 31, 2018 Electric Gas Other Eliminations Total Operating revenues $ 921,093 $ 270,916 $ — $ — $ 1,192,009 Cost of sales 194,608 78,275 — — 272,883 Gross margin 726,485 192,641 — — 919,126 Operating, general and administrative 223,598 82,864 657 — 307,119 Property and other taxes 134,681 36,569 9 — 171,259 Depreciation and depletion 144,636 29,822 18 — 174,476 Operating income (loss) 223,570 43,386 (684) — 266,272 Interest expense, net (79,033) (5,858) (7,097) — (91,988) Other income, net 2,794 962 210 — 3,966 Income tax benefit (expense) 21,686 9,268 (12,244) — 18,710 Net income (loss) $ 169,017 $ 47,758 $ (19,815) $ — $ 196,960 Total assets $ 4,626,530 $ 1,174,737 $ 4,732 $ — $ 5,805,999 Capital expenditures $ 221,968 $ 61,998 $ — $ — $ 283,966

Quarterly Financial Data (Una_2

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2020
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Amounts presented are in thousands, except per share data: Three Months Ended December 31, 2020 2019 Operating revenues $ 313,445 $ 328,135 Operating income 66,496 84,651 Net income $ 53,551 $ 59,982 Average common shares outstanding 50,583 50,448 Income per average common share: Basic $ 1.06 $ 1.19 Diluted $ 1.06 $ 1.18

Nature of Operations and Basi_3

Nature of Operations and Basis of Consolidation (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)customerswatts	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Number of customers | customers	743,000
Number of megawatts of qualifying facility | watts	35
Variable interest entity, measure of activity, purchases	$ 22,200	$ 23,400	$ 25,600
Qualifying Facility Contracts [Member]
Estimated aggregate gross contractual payments through 2024	$ 115,300
Flow-through income taxes
Prior Period Reclassification Adjustment		$ 172,800	$ 161,600

Significant Accounting Polici_4

Significant Accounting Policies Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)Months	Dec. 31, 2019USD ($)
Number of months or less of maturity to be considered cash equivalent | Months	3
Allowance for doubtful accounts receivable, current	$ 5.6	$ 2.3
Unbilled receivables,current	$ 80.5	$ 83.3

Significant Accounting Polici_5

Significant Accounting Policies Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Materials and supplies	$ 44,311	$ 42,791
Storage gas and fuel	16,699	11,134
Total Inventories	$ 61,010	$ 53,925

Significant Accounting Polici_6

Significant Accounting Policies Property plant equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Property, plant and equipment, disclosure of composite depreciation rate for plant in service	2.80%	2.80%	3.00%
Allowance for Funds Used During Construction, Capitalized Interest	$ 9.8	$ 8.2	$ 5.9
Montana
Property, Plant and Equipment [Line Items]
Allowance for funds used during construction, rate	6.70%	6.90%	7.10%
South Dakota
Property, Plant and Equipment [Line Items]
Allowance for funds used during construction, rate	6.70%	6.60%	6.70%
Minimum [Member] | Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	2 years
Maximum [Member] | Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	96 years

Significant Accounting Polici_7

Significant Accounting Policies Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Property taxes	$ 89,425	$ 85,242
Employee compensation, benefits, and withholdings	40,538	50,142
Interest	18,074	17,538
Other (none of which is individually significant)	59,477	49,099
Total Accrued Expenses	$ 207,514	$ 202,021

Significant Accounting Polici_8

Significant Accounting Policies Other Noncurrent Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Pension and other employee benefits	$ 136,632	$ 128,853
Future QF obligation, net	81,379	92,937
Customer advances	65,186	56,870
Asset retirement obligations	45,355	42,449
Environmental	25,049	27,741
Other (none of which is individually significant)	57,102	38,302
Total Noncurrent Liabilities	$ 410,703	$ 387,152

Significant Accounting Polici_9

Significant Accounting Policies Supplemental Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Income taxes	$ 115	$ (6,737)	$ 55
Interest	84,922	83,776	76,499
Capital expenditures included in trade accounts payable	$ 21,430	$ 33,473	$ 21,625

Significant Accounting Polic_10

Significant Accounting Policies Reconciliation of Cash and Restricted Cash (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Cash and cash equivalents	$ 5,811	$ 5,145	$ 7,860
Restricted cash	11,285	6,925	7,451
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows	$ 17,096	$ 12,070	$ 15,311	$ 12,029

Regulatory Matters (Details)

Regulatory Matters (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Jan. 31, 2021	Jun. 30, 2020
NorthWestern Energy Pension Plan (MT) [Member]
Public Utilities, General Disclosures [Line Items]
Pension contributions	$ 10,200
Power Cost and Credit Adjustment Mechanism (PCCAM) [Member]
Public Utilities, General Disclosures [Line Items]
Customer sharing percentage of amounts exceeding deadband	90.00%
Company sharing percentage of over/under collection of supply costs	10.00%
Under Collected Supply Costs			$ 23,800
Montana Accounting Order [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Request to Recognize Pension Contribution over 5 years	$ 40,000
South Dakota Accounting Order [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Asset for COVID Uncollectable Accounts	200
Montana FERC Rate Filing Settlement [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	$ 31,300
Montana FERC Rate Filing Settlement [Member] | Subsequent Event [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities		$ 20,500
Power cost and Credit Adjustment Mechanism (PCCAM) Total Disallowed Costs [Member]
Public Utilities, General Disclosures [Line Items]
Under Collected Supply Costs			9,400
Power cost and Credit Adjustment Mechanism (PCCAM) Disallowed Colstrip Costs [Member]
Public Utilities, General Disclosures [Line Items]
Under Collected Supply Costs			5,600
Power cost and Credit Adjustment Mechanism (PCCAM) Disallowed Costs Due to Change in Statute [Member]
Public Utilities, General Disclosures [Line Items]
Under Collected Supply Costs			$ 3,800

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Regulatory Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	$ 746,417	$ 711,347
Regulatory Assets [Member] | Flow-through income taxes
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	420,925	376,548
Regulatory Assets [Member] | Excess deferred income taxes
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	67,256	73,670
Regulatory Assets [Member] | Pension
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	138,567	132,000
Regulatory Assets [Member] | Deferred financing costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	28,350	31,089
Regulatory Assets [Member] | Employee related benefits
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	22,516	18,622
Regulatory Assets [Member] | Supply costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	$ 8,116	35,454
Regulatory assets, remaining amortization period	1 year
Regulatory Assets [Member] | State & local taxes & fees
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	$ 17,910	7,146
Regulatory Assets [Member] | Environmental clean-up
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	11,127	11,179
Regulatory Assets [Member] | Other
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	31,650	25,639
Regulatory Liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	687,272	657,347
Regulatory Liabilities [Member] | Removal cost
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	464,669	442,129
Regulatory Liabilities [Member] | Excess deferred income taxes
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	165,279	172,784
Regulatory Liabilities [Member] | Supply costs
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 13,847	14,226
Regulatory liability, remaining amortization period	1 year
Regulatory Liabilities [Member] | Gas storage sales
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 7,887	8,307
Regulatory liability, remaining amortization period	19 years
Regulatory Liabilities [Member] | Rates subject to refund
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 32,496	14,177
Regulatory liability, remaining amortization period	1 year
Regulatory Liabilities [Member] | State & local taxes & fees
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 1,783	1,846
Regulatory liability, remaining amortization period	1 year
Regulatory Liabilities [Member] | Environmental clean-up
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 656	1,181
Regulatory Liabilities [Member] | Other
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 655	$ 2,697
Minimum [Member] | Regulatory Assets [Member] | Deferred financing costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, remaining amortization period	1 year
Maximum [Member] | Regulatory Assets [Member] | Deferred financing costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets, remaining amortization period	13 years

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities Narrative (Details)	12 Months Ended
	Dec. 31, 2020
Electric Supply Costs | South Dakota
Regulatory Assets And Liabilities [Line Items]
Percentage of interest earned on electric and natural gas supply costs	7.20%
Natural Gas Supply Costs | Montana
Regulatory Assets And Liabilities [Line Items]
Percentage of interest earned on electric and natural gas supply costs	7.00%
Natural Gas Supply Costs | South Dakota
Regulatory Assets And Liabilities [Line Items]
Percentage of interest earned on electric and natural gas supply costs	7.80%
Natural Gas Supply Costs | Nebraska
Regulatory Assets And Liabilities [Line Items]
Percentage of interest earned on electric and natural gas supply costs	8.50%

Property, Plant and Equipment_2

Property, Plant and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Transmission, distribution, and storage	$ 3,771,023	$ 3,569,141
Generation	1,252,805	1,222,796
Plant acquisition adjustment (1)	686,328	686,328
Building and improvements	303,099	278,164
Land, land rights and easements	157,379	156,069
Other	571,981	545,009
Construction work in process	173,492	96,421
Total property, plant and equipment	6,916,107	6,553,928
Less accumulated depreciation	1,703,016	1,617,817
Net property, plant and equipment	4,952,935	4,700,924
Computer Software, Intangible Asset
Property, Plant and Equipment [Line Items]
Less accumulated amortization	(260,156)	(235,187)
Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Finance Lease, Right-of-Use Asset, after Accumulated Amortization	$ 11,300	13,300
Land and improvements [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	53 years
Land and improvements [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	96 years
Building and improvements [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	23 years
Building and improvements [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	73 years
Tranmission, distribution and storage[Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	15 years
Tranmission, distribution and storage[Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	95 years
Generation [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	23 years
Generation [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	72 years
Plant Acquisition adjustment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	25 years
Plant Acquisition adjustment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	50 years
Other [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	2 years
Other [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life	45 years
Basin Capital Lease [Member]
Property, Plant and Equipment [Line Items]
Finance Lease, Right-of-Use Asset, after Accumulated Amortization	$ 11,100	$ 13,100

Property, Plant and Equipment J

Property, Plant and Equipment Joint Ownership (Details) $ in Thousands	Dec. 31, 2020USD ($)plants	Dec. 31, 2019USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Number of joint ownership interests in electric generating plants | plants	4
Big Stone Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentages	23.40%	23.40%
Plant in service	$ 153,632	$ 155,662
Accumulated depreciation	$ 40,665	$ 40,988
Neal 4 Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentages	8.70%	8.70%
Plant in service	$ 62,927	$ 62,565
Accumulated depreciation	$ 33,942	$ 32,853
Coyote Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentages	10.00%	10.00%
Plant in service	$ 51,586	$ 52,448
Accumulated depreciation	$ 37,980	$ 38,310
Colstrip Unit 4 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentages	30.00%	30.00%
Plant in service	$ 317,438	$ 311,399
Accumulated depreciation	$ 105,738	$ 97,563

Asset Retirement Obligations Ro

Asset Retirement Obligations Rollforward (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at January 1,	$ 42,449	$ 40,659	$ 39,286
Accretion expense	2,070	2,051	2,031
Liabilities incurred	0	0	773
Liabilities settled	(4,061)	(46)	(63)
Revision to cash flows	4,897	(215)	(1,368)
Liability at December 31,	$ 45,355	$ 42,449	$ 40,659

Asset Retirement Obligations Na

Asset Retirement Obligations Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation, Liabilities Settled	$ 4,061	$ 46	$ 63
Revision to cash flows	$ 4,897	$ (215)	$ (1,368)

Goodwill (Details)

Goodwill (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Goodwill [Line Items]
No impairment identified	$ 0
Goodwill	357,586,000	$ 357,586,000
Electric
Goodwill [Line Items]
Goodwill	243,558,000	243,558,000
Natural gas
Goodwill [Line Items]
Goodwill	$ 114,028,000	$ 114,028,000

Risk Management and Hedging A_3

Risk Management and Hedging Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Physical purchase and sale of gas and electricity at fixed prices	$ 0	$ 0
Pre-tax gain on cash flow hedge from AOCL to be reclassified during next 12 months	600
No swaps outstanding, interest rate fair value derivatives	0	$ 0
Interest Rate Swap [Member]
Derivative [Line Items]
Pre-tax loss on cash flow hedges remaining in AOCL	14,600
Interest Rate Swap [Member] | Interest Expense [Member]
Derivative [Line Items]
Interest rate contracts, amount of gain reclassified from AOCL into income	$ 614

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Recurring Basis (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Level 1 to level 2 asset transfers, amount	$ 0	$ 0
Level 2 to level 1 assets, transfers, amount	0	0
Level 1 to level 2 liabilities transfers, amount	0	0
Level 2 to level 1 liabilities, transfers, amount	0	0
Transfers into and out of Level 3	0	0
Fair Value, Recurring [Member] | Total Net Fair Value
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	10,055	5,699
Rabbi trust investments	27,027	29,288
Total	37,082	34,987
Fair Value, Recurring [Member] | Quoted Prices In Active Markets for Identical Assets or Liabilities, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	10,055	5,699
Rabbi trust investments	27,027	29,288
Total	37,082	34,987
Fair Value, Recurring [Member] | Significant Other Observable Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	0	0
Rabbi trust investments	0	0
Total	0	0
Fair Value, Recurring [Member] | Significant Unobservable Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	0	0
Rabbi trust investments	0	0
Total	0	0
Margin Cash Collateral Offset | Fair Value, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Restricted cash	0	0
Rabbi trust investments	0	0
Total	$ 0	$ 0

Fair Value Measurements Fair _2

Fair Value Measurements Fair Value Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, carrying value	$ 2,315,261	$ 2,233,281
Long-term debt, fair value	$ 2,629,755	$ 2,416,814

Short-Term Borrowings and Cre_3

Short-Term Borrowings and Credit Arrangements (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Short-term Debt [Line Items]
Maximum Ratio Of Indebtedness To Net Capital Threshold Percentage	65.00%
Short-term borrowings	$ 100,000,000	$ 0
Maximum borrowing capacity	450,000,000	$ 425,000,000
Debt Disclosure [Abstract]
Line of Credit Facility, Increase (Decrease), Net	$ 25,000,000
Term Loan Due 2021 [Member]
Short-term Debt [Line Items]
Maximum Ratio Of Indebtedness To Net Capital Threshold Percentage	65.00%
Short-term borrowings	$ 100,000,000
Term Loan Due 2021 [Member] | Eurodollar [Member]
Short-term Debt [Line Items]
Short Term Debt Basis Spread on Variable Rate	1.50%

Short-Term Borrowings and Cre_4

Short-Term Borrowings and Credit Arrangements (Details)	12 Months Ended
	Dec. 31, 2020USD ($)numberofbanks	Dec. 31, 2019USD ($)
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 450,000,000	$ 425,000,000
Letters of credit outstanding, amount	0	0
LIBOR borrowings and letter of credit, amount outstanding	222,000,000	289,000,000
Net availability as of December 31	$ 228,000,000	136,000,000
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Number of institutions participating in the credit facility | numberofbanks	10
Number of institutions participating in the credit faciltiy pertaining to maximum contributory percentage | numberofbanks	1
Line of credit facility, maximum percentage of total availability provided by a single lender	16.00%
Commitment fees	$ 600,000	300,000
Line of credit facility, expiration date	Sep. 2, 2023
Swingline Credit Facility [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 25,000,000	25,000,000
LIBOR Borrowings [Member]
Line of Credit Facility [Line Items]
LIBOR borrowings	222,000,000	289,000,000
Unsecured Revolving Line Of Credit, Maximun Outstanding Under Accordian Feature [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity	75,000,000
Revolving Credit Facility Due 2023
Line of Credit Facility [Line Items]
Maximum borrowing capacity	425,000,000	0
Revolving Credit Facility Due 2021
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 0	$ 400,000,000
Eurodollar [Member] | Minimum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	12.50%
Eurodollar [Member] | Maximum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	75.00%
Measurement Input, Credit Spread [Member] | Minimum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	112.50%
Measurement Input, Credit Spread [Member] | Maximum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	175.00%

Long-Term Debt and Capital Le_3

Long-Term Debt and Capital Leases Schedule of Debt (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Jun. 30, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019
Debt Instrument [Line Items]
Long-term debt	$ 2,315,261		$ 2,233,281
Less current maturities	0		0
Long-term debt, excluding current maturities	2,315,261		2,233,281
Finance Lease, Liability	17,439		19,915
Current maturities of finance leases	2,668		2,476
Long-term finance leases	$ 14,771		17,439
Secured Debt South Dakota Due 2030
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 50,000
Long-term Debt, Maturity Date	May 15, 2030
Montana 3.98%, Due June 2049
Debt Instrument [Line Items]
Debt Instrument, Face Amount					$ 50,000
Montana 3.98%, Due September 2049
Debt Instrument [Line Items]
Debt Instrument, Face Amount				$ 100,000
Secured Debt Montana Due 2030
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 100,000
Long-term Debt, Maturity Date	May 15, 2030
Secured Debt Montana Due 2049 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount					$ 150,000
Unsecured Debt | Revolving Credit Facility Due 2023
Debt Instrument [Line Items]
Long-term debt	$ 222,000		0
Maturity date	Sep. 2, 2023
Unsecured Debt | Revolving Credit Facility Due 2021
Debt Instrument [Line Items]
Long-term debt	$ 0		289,000
Maturity date	Dec. 12, 2021
Secured Debt | South Dakota, 5.01%, Due 2025
Debt Instrument [Line Items]
Long-term debt	$ 64,000		64,000
Maturity date	May 1, 2025
Interest rate, stated percentage	5.01%
Secured Debt | South Dakota, 4.15%, Due 2042
Debt Instrument [Line Items]
Long-term debt	$ 30,000		30,000
Maturity date	Aug. 10, 2042
Interest rate, stated percentage	4.15%
Secured Debt | South Dakota, 4.30%, Due 2052
Debt Instrument [Line Items]
Long-term debt	$ 20,000		20,000
Maturity date	Aug. 10, 2052
Interest rate, stated percentage	4.30%
Secured Debt | South Dakota, 4.85% Due 2043
Debt Instrument [Line Items]
Long-term debt	$ 50,000		50,000
Maturity date	Dec. 19, 2043
Interest rate, stated percentage	4.85%
Secured Debt | South Dakota, 4.22% Due 2044
Debt Instrument [Line Items]
Long-term debt	$ 30,000		30,000
Maturity date	Dec. 19, 2044
Interest rate, stated percentage	4.22%
Secured Debt | South Dakota, 4.26% Due 2040
Debt Instrument [Line Items]
Long-term debt	$ 70,000		70,000
Maturity date	Sep. 29, 2040
Interest rate, stated percentage	4.26%
Secured Debt | Secured Debt South Dakota Due 2030
Debt Instrument [Line Items]
Long-term debt	$ 50,000		0
Maturity date	May 15, 2030
Interest rate, stated percentage	3.21%
Secured Debt | South Dakota, 2.80%, Due 2026
Debt Instrument [Line Items]
Long-term debt	$ 60,000		60,000
Maturity date	Jun. 15, 2026
Interest rate, stated percentage	2.80%
Secured Debt | South Dakota, 2.66%, Due 2026
Debt Instrument [Line Items]
Long-term debt	$ 45,000		45,000
Maturity date	Sep. 30, 2026
Interest rate, stated percentage	2.66%
Secured Debt | Montana, 5.71%, Due 2039
Debt Instrument [Line Items]
Long-term debt	$ 55,000		55,000
Maturity date	Oct. 15, 2039
Interest rate, stated percentage	5.71%
Secured Debt | Montana, 5.01%, Due 2025
Debt Instrument [Line Items]
Long-term debt	$ 161,000		161,000
Maturity date	May 1, 2025
Interest rate, stated percentage	5.01%
Secured Debt | Montana, 4.15%, Due 2042
Debt Instrument [Line Items]
Long-term debt	$ 60,000		60,000
Maturity date	Aug. 10, 2042
Interest rate, stated percentage	4.15%
Secured Debt | Montana, 4.30%, Due 2052
Debt Instrument [Line Items]
Long-term debt	$ 40,000		40,000
Maturity date	Aug. 10, 2052
Interest rate, stated percentage	4.30%
Secured Debt | Montana 4.85%, Due 2043
Debt Instrument [Line Items]
Long-term debt	$ 15,000		15,000
Maturity date	Dec. 19, 2043
Interest rate, stated percentage	4.85%
Secured Debt | Montana 3.99% Due 2028
Debt Instrument [Line Items]
Long-term debt	$ 35,000		35,000
Maturity date	Dec. 19, 2028
Interest rate, stated percentage	3.99%
Secured Debt | Montana 4.176% Due 2044
Debt Instrument [Line Items]
Long-term debt	$ 450,000		450,000
Maturity date	Nov. 15, 2044
Interest rate, stated percentage	4.18%
Secured Debt | Montana 3.11%, Due 2025
Debt Instrument [Line Items]
Long-term debt	$ 75,000		75,000
Maturity date	Jul. 1, 2025
Interest rate, stated percentage	3.11%
Secured Debt | Montana 4.11%, Due 2045
Debt Instrument [Line Items]
Long-term debt	$ 125,000		125,000
Maturity date	Jul. 1, 2045
Interest rate, stated percentage	4.11%
Secured Debt | Montana 4.03%, Due 2047
Debt Instrument [Line Items]
Long-term debt	$ 250,000		250,000
Maturity date	Nov. 6, 2047
Interest rate, stated percentage	4.03%
Secured Debt | Montana 3.98%, Due June 2049
Debt Instrument [Line Items]
Long-term debt	$ 50,000		50,000
Maturity date	Jun. 26, 2049
Interest rate, stated percentage	3.98%
Secured Debt | Montana 3.98%, Due September 2049
Debt Instrument [Line Items]
Long-term debt	$ 100,000		100,000
Maturity date	Sep. 17, 2049
Interest rate, stated percentage	3.98%
Secured Debt | Secured Debt Montana Due 2030
Debt Instrument [Line Items]
Long-term debt	$ 100,000		0
Maturity date	May 15, 2030
Interest rate, stated percentage	3.21%
Secured Debt | Montana 2.00% Due 2023
Debt Instrument [Line Items]
Long-term debt	$ 144,660		144,660
Maturity date	Aug. 1, 2023
Interest rate, stated percentage	2.00%
Secured Debt | New Market Tax Credit Financing-1.146%, Due 2046
Debt Instrument [Line Items]
Long-term debt	$ 26,977		26,977
Maturity date	Jul. 1, 2046
Interest rate, stated percentage	1.146%
Secured Debt | Secured Debt Montana Due 2049 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 150,000		150,000
Discount on Notes and Bonds and Debt Issuance Costs, Net
Debt Instrument [Line Items]
Discount on notes and bonds and debt issuance costs, net	$ (13,376)		$ (12,356)

Long-Term Debt and Capital Le_4

Long-Term Debt and Capital Leases Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Jun. 30, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019
Debt Instrument [Line Items]
Long-term Debt	$ 2,315,261		$ 2,233,281
Secured Debt Montana Due 2049 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount					$ 150,000
Montana 3.98%, Due June 2049
Debt Instrument [Line Items]
Debt Instrument, Face Amount					$ 50,000
Montana 3.98%, Due September 2049
Debt Instrument [Line Items]
Debt Instrument, Face Amount				$ 100,000
Secured Debt Montana Due 2030
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 100,000
Secured Debt South Dakota Due 2030
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 50,000
Secured Debt | Secured Debt Montana Due 2049 [Member]
Debt Instrument [Line Items]
Long-term Debt	150,000		150,000
Secured Debt | Montana 3.98%, Due June 2049
Debt Instrument [Line Items]
Long-term Debt	$ 50,000		50,000
Interest rate, stated percentage	3.98%
Secured Debt | Montana 3.98%, Due September 2049
Debt Instrument [Line Items]
Long-term Debt	$ 100,000		100,000
Interest rate, stated percentage	3.98%
Secured Debt | Secured Debt Montana Due 2030
Debt Instrument [Line Items]
Long-term Debt	$ 100,000		0
Interest rate, stated percentage	3.21%
Secured Debt | Secured Debt South Dakota Due 2030
Debt Instrument [Line Items]
Long-term Debt	$ 50,000		$ 0
Interest rate, stated percentage	3.21%

Long-Term Debt and Capital Le_5

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

Long-Term Debt and Capital Le_6

Long-Term Debt and Capital Leases (Details) $ in Millions	Dec. 31, 2020USD ($)
Maturities of Long-term Debt [Abstract]
2020	$ 2.7
2021	2.9
2022	369.8
2023	3.3
2024	$ 303.6

Income Taxes Narrative (Details

Income Taxes Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Contingency [Line Items]
Federal statutory rate	21.00%	21.00%	21.00%
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations, Amount Including Interest and Penalties		$ (22.8)
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations, Income Tax Penalties and Interest Portion		$ 2.7
Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Open Tax Year	2003

Income Taxes Domestic Tax Compo

Income Taxes Domestic Tax Components (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Federal
Current	$ (3,396)	$ (6,076)	$ (5,526)
Deferred	(4,006)	(15,169)	(15,588)
Investment tax credits	(3)	(12)	(33)
State
Current	3	27	38
Deferred	(3,568)	1,305	2,399
Income Tax Benefit	$ (10,970)	$ (19,925)	$ (18,710)

Income Taxes Effective Rate Rec

Income Taxes Effective Rate Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Federal statutory rate	21.00%	21.00%	21.00%
State income tax, net of federal provisions	(1.10%)	0.70%	0.90%
Flow-through repairs deductions	(16.50%)	(10.80%)	(10.80%)
Production tax credits	(9.10%)	(6.30%)	(6.10%)
Amortization of excess DIT	(0.70%)	(0.90%)	(2.10%)
Recognition of unrecognized tax benefit	0.00%	(12.50%)	0.00%
Impact of Tax Cuts and Jobs Act	0.00%	0.10%	11.10%
Plant and depreciation of flow through items	0.10%	(2.20%)	(1.20%)
Prior year permanent return to accrual adjustments	(1.20%)	0.30%	(1.70%)
Other, net	(0.10%)	(0.10%)	0.60%
Effective tax rate	(7.60%)	(10.90%)	(10.50%)
Income Before Income Taxes	$ 144,245	$ 182,195	$ 178,250
Income tax calculated at federal statutory rate	30,292	38,261	37,433
State income, net of federal provisions	(1,477)	1,251	1,613
Flow-through repairs deductions	(23,828)	(19,706)	(19,323)
Production tax credits	(13,103)	(11,483)	(10,890)
Amortization of excess DIT	(968)	(1,688)	(3,731)
Recognition of unrecognized tax benefit	0	(22,825)	0
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	0	(198)	(19,840)
Plant and depreciation of flow through items	121	(3,952)	(2,175)
Prior year permanent return to accrual adjustments	(1,728)	559	(2,978)
Other, net	(279)	(144)	1,181
Total reconciling items	(41,262)	(58,186)	(56,143)
Income Tax Benefit	$ (10,970)	$ (19,925)	$ (18,710)

Income Taxes Deferred Tax Liabi

Income Taxes Deferred Tax Liability (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Deferred Tax Assets, [Abstract]
Production tax credit	$ 63,542	$ 50,440
Pension / postretirement benefits	31,866	30,041
Customer advances	17,165	14,975
Unbilled revenue	14,429	9,820
Compensation accruals	11,748	13,163
Reserves and accruals	6,266	7,069
Environmental liability	6,039	5,938
Interest rate hedges	3,171	3,956
NOL carryforward	393	10,050
AMT credit carryforward	0	3,400
Other, net	2,490	1,801
Deferred Tax Asset	157,109	150,653
Deferred Tax Liabilities, [Abstract]
Excess tax depreciation	(412,774)	(393,287)
Goodwill amortization	(83,991)	(82,595)
Flow through depreciation	(83,545)	(71,679)
Regulatory assets and other	(48,576)	(51,078)
Deferred Tax Liability	(628,886)	(598,639)
Deferred Tax Liability, net	$ (471,777)	$ (447,986)

Income Taxes Operating Loss (De

Income Taxes Operating Loss (Details) $ in Millions	Dec. 31, 2020USD ($)
Domestic Tax Authority [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforward	$ 78.6
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforward	38.1
Year 2036 [Member] | Domestic Tax Authority [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforwards, subject to expiration	0.4
Year 2037 [Member] | Domestic Tax Authority [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforwards, subject to expiration	78.2
Year 2024 [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
NOL carryforwards, subject to expiration	$ 38.1

Income Taxes Uncertain Tax Posi

Income Taxes Uncertain Tax Positions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Contingency [Line Items]
Unrecognized tax benefit more likely than not percentage threshold	50.00%
Unrecognized tax benefits that would impact effective tax rate	$ 28,000
Income tax penalties and interest expense		$ (2,700)
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits at January 1	35,085	56,150	$ 57,473
Gross increases - tax positions in prior period	120	539	0
Gross increases - tax positions in current period	0	0	338
Gross decreases - tax positions in current period	(1,714)	(1,489)	(1,661)
Lapse of statute of limitations	0	(20,115)	0
Unrecognized Tax Benefits at December 31	33,491	$ 35,085	$ 56,150
Accrual for interest and penalties	$ 0

Comprehensive Income (Loss) (De

Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Comprehensive Income (Loss), Before Tax [Abstract]
Foreign currency translation adjustment	$ 87	$ (35)	$ 270
Reclassification of net income (loss) on derivative instruments	614	614	614
Postretirement medical liability adjustment	2,463	(175)	346
Other comprehensive income (loss)	3,164	404	1,230
Other Comprehensive Income (Loss), Tax [Abstract]
Foreign currency translation adjustment	0	0	0
Reclassification of net income (loss) on derivative instruments	(162)	(162)	(116)
Postretirement medical liability adjustment	(623)	44	(133)
Other comprehensive income (loss)	(785)	(118)	(249)
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Foreign currency translation adjustment	87	(35)	270
Reclassification of net income (loss) on derivative instruments	452	452	498
Postretirement medical liability adjustment	1,840	(131)	213
Other comprehensive income (loss)	2,379	286	$ 981
Accumulated Other Comprehensive Income, Net of Tax [Abstract]
Foreign currency translation	1,500	1,413
Derivative instruments designated as cash flow hedges	(10,729)	(11,181)
Postretirement medical plans	1,960	120
Accumulated other comprehensive loss	$ (7,269)	$ (9,648)

Comprehensive Income (Loss) Com

Comprehensive Income (Loss) Components of AOCI (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Beginning balance	$ (9,648)
Net current-period other comprehensive income (loss)	2,379	$ 286	$ 981
Ending Balance	(7,269)	(9,648)
Total
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Beginning balance	(9,648)	(9,934)
Other comprehensive income before reclassifications	87	(35)
Amounts reclassified from AOCL	1,840	(131)
Net current-period other comprehensive income (loss)	2,379	286
Ending Balance	(7,269)	(9,648)	(9,934)
Total | Interest Expense [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amounts reclassified from AOCL	452	452
Foreign Currency Translation
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Beginning balance	1,413	1,448
Other comprehensive income before reclassifications	87	(35)
Amounts reclassified from AOCL	0	0
Net current-period other comprehensive income (loss)	87	(35)
Ending Balance	1,500	1,413	1,448
Foreign Currency Translation | Interest Expense [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amounts reclassified from AOCL	0	0
Pension and Postretirement Medical Plans
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Beginning balance	120	251
Other comprehensive income before reclassifications	0	0
Amounts reclassified from AOCL	1,840	(131)
Net current-period other comprehensive income (loss)	1,840	(131)
Ending Balance	1,960	120	251
Pension and Postretirement Medical Plans | Interest Expense [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amounts reclassified from AOCL	0	0
Interest Rate Derivative Instruments Designated as Cash Flow Hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Beginning balance	(11,181)	(11,633)
Other comprehensive income before reclassifications	0	0
Amounts reclassified from AOCL	0	0
Net current-period other comprehensive income (loss)	452	452
Ending Balance	(10,729)	(11,181)	$ (11,633)
Interest Rate Derivative Instruments Designated as Cash Flow Hedges | Interest Expense [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amounts reclassified from AOCL	$ 452	$ 452

Employee Benefit Plans Benefit

Employee Benefit Plans Benefit Obligation And Funded Status (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Plan [Member]
Change in Benefit Obligation:
Obligation at beginning of period	$ 735,564	$ 649,626
Service cost	11,116	9,637	$ 11,776
Interest cost	22,840	26,488	24,420
Actuarial loss	84,479	83,364
Settlements	0	(4,065)
Benefits paid	(33,020)	(29,486)
Benefit Obligation at End of Period	820,979	735,564	649,626
Amounts Recognized in the Balance Sheet Consist of:
Noncurrent asset	7,001	4,333
Total Assets	7,001	4,333
Current liability	(11,200)	(11,401)
Noncurrent liability	(128,324)	(119,496)
Total Liabilities	(139,524)	(130,897)
Net amount recognized	(132,523)	(126,564)
Amounts recognized in AOCL consist of:
Prior service cost	0	0
Net actuarial gain	0	0
Total	(115,987)	(111,449)
Plans with Benefit Obligations in Excess of Plan Assets [Abstract]
Projected benefit obligation	757,400	675,500
Accumulated benefit obligation	757,400	675,500
Fair value of plan assets	619,100	545,800
Pension Plan [Member] | Pension
Amounts Recognized in Regulatory Assets Consist of:
Prior service credit	0	0
Net actuarial loss	(115,987)	(111,449)
Pension Plan [Member] | Changes Measurement [Member]
Change in Fair Value of Plan Assets:
Fair value of plan assets at beginning of period	609,000	525,310
Return on plan assets	101,075	107,041
Employer contributions	11,401	10,200
Settlements	0	(4,065)
Benefits paid	(33,020)	(29,486)
Fair value of plan assets at end of period	688,456	609,000	525,310
Funded Status	(132,523)	(126,564)
Other Postretirement Benefits Plan [Member]
Change in Benefit Obligation:
Obligation at beginning of period	20,272	20,611
Service cost	370	331
Interest cost	492	609
Actuarial loss	123	997
Settlements	390	390
Benefits paid	(2,501)	(2,666)
Benefit Obligation at End of Period	19,146	20,272	20,611
Amounts Recognized in the Balance Sheet Consist of:
Noncurrent asset	8,436	7,783
Total Assets	8,436	7,783
Current liability	(1,712)	(2,113)
Noncurrent liability	(2,774)	(4,463)
Total Liabilities	(4,486)	(6,576)
Net amount recognized	3,950	1,207
Amounts recognized in AOCL consist of:
Prior service cost	(246)	(397)
Net actuarial gain	3,246	(934)
Total	6,360	6,686
Other Postretirement Benefits Plan [Member] | Pension
Amounts Recognized in Regulatory Assets Consist of:
Prior service credit	3,857	5,890
Net actuarial loss	(497)	259
Other Postretirement Benefits Plan [Member] | Changes Measurement [Member]
Change in Fair Value of Plan Assets:
Fair value of plan assets at beginning of period	21,479	18,670
Return on plan assets	2,723	3,805
Employer contributions	1,395	1,670
Settlements	0	0
Benefits paid	(2,501)	(2,666)
Fair value of plan assets at end of period	23,096	21,479	$ 18,670
Funded Status	$ 3,950	$ 1,207

Employee Benefit Plans Net Peri

Employee Benefit Plans Net Periodic Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Plan [Member]
Service cost	$ 11,116	$ 9,637	$ 11,776
Interest cost	22,840	26,488	24,420
Expected return on plan assets	26,162	25,443	28,207
Amortization of prior service cost (credit)	0	0	4
Recognized actuarial loss (gain)	(5,028)	(6,544)	(4,360)
Settlement loss recognized	0	198	0
Net Periodic Benefit Cost (Credit)	12,822	17,424	12,353
Regulatory deferral of net periodic benefit cost (1)	(2,100)	(7,510)	(4,057)
Previously deferred costs recognized (1)	71	728	243
Amount Recognized in Income	10,793	10,642	8,539
Other Pension, Postretirement and Supplemental Plans [Member]
Service cost	370	331	398
Interest cost	492	609	578
Expected return on plan assets	983	869	954
Amortization of prior service cost (credit)	(1,882)	(1,882)	(1,882)
Recognized actuarial loss (gain)	61	96	79
Settlement loss recognized	390	390	390
Net Periodic Benefit Cost (Credit)	(1,674)	(1,517)	(1,549)
Regulatory deferral of net periodic benefit cost (1)	0	0	0
Previously deferred costs recognized (1)	861	931	913
Amount Recognized in Income	(813)	(586)	(636)
Net Periodic Costs [Member] | Pension Plan [Member]
Operating, general and administrative expense	9,016	2,125	7,719
Other income (expense), net	1,777	8,517	820
Amount Recognized in Income	10,793	10,642	8,539
Net Periodic Costs [Member] | Other Pension, Postretirement and Supplemental Plans [Member]
Operating, general and administrative expense	370	331	398
Other income (expense), net	(1,183)	(917)	(1,034)
Amount Recognized in Income	$ (813)	$ (586)	$ (636)

Employee Benefit Plans Actuaria

Employee Benefit Plans Actuarial Assumptions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Increase in projected benefit obligation due to change in discount rate		$ 92.1
Pension Plan [Member] | Nonunion [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Long-term rate of increase in compensation levels		2.84%	2.84%	2.84%
Pension Plan [Member] | Union [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Long-term rate of increase in compensation levels		2.00%	2.00%	2.03%
Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		2.20%	3.10%	4.15%
Expected rate of return on assets		3.45%	4.23%	4.47%
Interest credit rating		3.30%	3.60%	4.00%
Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		2.30%	3.20%	4.20%
Expected rate of return on assets		4.49%	5.06%	4.97%
Interest credit rating		6.00%	6.00%	6.00%
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected rate of return on assets		4.71%	4.79%	4.82%
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Health care cost trend rate assumed for next year		5.00%
Other Postretirement Benefits Plan [Member] | Nonunion [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Long-term rate of increase in compensation levels		2.84%	2.84%	2.84%
Other Postretirement Benefits Plan [Member] | Union [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Long-term rate of increase in compensation levels		2.00%	2.00%	2.03%
Other Postretirement Benefits Plan [Member] | Minimum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		1.80%	2.80%	3.90%
Other Postretirement Benefits Plan [Member] | Maximum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		1.80%	2.80%	3.95%
Forecast [Member] | NorthWestern Corporation Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected rate of return on assets	3.01%
Forecast [Member] | NorthWestern Energy Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected rate of return on assets	4.17%

Employee Benefit Plans Investme

Employee Benefit Plans Investment Strategy (Details)	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan, Plan Assets, Allocations [Abstract]
Target allocation of investments by plan	5.00%
South Dakota | Pension Plan [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	100.00%	100.00%
South Dakota | Cash and cash equivalents | Pension Plan [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	0.70%	0.90%
South Dakota | Fixed income securities | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Allocations [Abstract]
Target allocation of investments by plan	80.00%	80.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	77.30%	77.00%
South Dakota | Non-U.S. fixed income securities | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Allocations [Abstract]
Target allocation of investments by plan	2.00%	2.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	2.60%	2.60%
South Dakota | Global equities | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Allocations [Abstract]
Target allocation of investments by plan	18.00%	18.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	19.40%	19.50%
Montana | Pension Plan [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	100.00%	100.00%
Montana | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	100.00%	100.00%
Montana | Cash and cash equivalents | Pension Plan [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	0.00%	0.00%
Montana | Cash and cash equivalents | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	1.00%	1.00%
Montana | Fixed income securities | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Allocations [Abstract]
Target allocation of investments by plan	55.00%	55.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	52.70%	53.80%
Montana | Fixed income securities | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Plan Assets, Allocations [Abstract]
Target allocation of investments by plan	40.00%	40.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	37.90%	37.80%
Montana | Non-U.S. fixed income securities | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Allocations [Abstract]
Target allocation of investments by plan	4.00%	4.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	3.80%	4.00%
Montana | Non-U.S. fixed income securities | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Plan Assets, Allocations [Abstract]
Target allocation of investments by plan	0.00%	0.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	0.00%	0.00%
Montana | Global equities | Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Allocations [Abstract]
Target allocation of investments by plan	41.00%	41.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	43.50%	42.20%
Montana | Global equities | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Plan Assets, Allocations [Abstract]
Target allocation of investments by plan	60.00%	60.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	61.10%	61.20%

Employee Benefit Plans Cash Flo

Employee Benefit Plans Cash Flows (Details) - Pension Plan [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension contributions	$ 11,401	$ 10,200	$ 9,200
Montana
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension contributions	10,201	9,000	8,000
South Dakota
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension contributions	$ 1,200	$ 1,200	$ 1,200

Employee Benefit Plans Estimate

Employee Benefit Plans Estimated Payments (Details) $ in Thousands	Dec. 31, 2020USD ($)
Pension Plan [Member]
Estimated Future Benefit Payments
2021	$ 35,200
2022	36,533
2023	37,847
2024	39,189
2025	40,210
2026-2030	209,556
Other Pension, Postretirement and Supplemental Plans [Member]
Estimated Future Benefit Payments
2021	2,729
2022	2,469
2023	2,331
2024	1,615
2025	1,457
2026-2030	$ 5,699

Employee Benefit Plans Narrativ

Employee Benefit Plans Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined benefit plan percentage threshold of differences between actuarial assumptions and actual plan results that are greater than projected benefit or market value	10.00%
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Matching employer contributions	$ 11.1	$ 11	$ 10.6

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 2,200	$ 6,500	$ 6,300
Compensation expense tax (expense) benefit	(600)	200	300
Compensation expense not yet recognized for nonvested awards	$ 9,100
Nonvested awards, total compensation cost not yet recognized, period for recognition	2 years
Shares vested in period, total fair value	$ 5,100	$ 4,200	$ 4,200
Share-based Compensation, Significant Assumptions
Risk-free interest rate	1.42%	2.47%
Expected life, in years	3 years	3 years
Expected volatility, minimum	14.90%	16.40%
Expected volatility, maximum	19.70%	20.90%
Dividend yield	3.10%	3.50%
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance and vesting period	3 years
Performance Shares [Member] | Minimum [Member]
Share-based Compensation, Significant Assumptions
Percent of shares issued based on company performance	0.00%
Performance Shares [Member] | Maximum [Member]
Share-based Compensation, Significant Assumptions
Percent of shares issued based on company performance	200.00%
Share-based Payment Arrangement [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance and vesting period	1 year
Share-based Payment Arrangement [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance and vesting period	5 years
Executive retirement/retention program [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance and vesting period	5 years	5 years
Deferred Stock Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum percentage of compensation to be deferred	100.00%
Maximum number of years for distribution payments	10
DSUs Issued	21,434	19,027	29,870
Deferred Compensation Arrangement with Individual, Contributions by Employer	$ 1,500	$ 1,300	$ 1,800
Change in value of shares	(2,900)	2,400	100
Deferred Compensation Arrangement with Individual, Compensation Expense	$ (1,400)	$ 3,700	$ 1,900
DSUs withdrawn	613	3,708	136,640
Value of DSUs withdrawn	$ 100	$ 300	$ 8,200
Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant	216,647

Stock-Based Compensation Nonves

Stock-Based Compensation Nonvested (Details) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Beginning nonvested grants (shares)	178,245
Granted (shares)	62,116
Vested (shares)	(105,512)
Forfeited (shares)	(4,278)
Remaining nonvested grants (shares)	130,571	178,245
Beginning nonvested (weighted-average grant date fair value)	$ 53
Granted (weighted-average grant date fair value)	73.13
Vested (weighted-average grant date fair value)	47.99
Forfeited (weighted-average grant date fair value)	63.57
Remaining nonvested (weighted-average grant date fair value)	$ 66.27	$ 53
Performance and vesting period	3 years
Executive retirement/retention program [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Beginning nonvested grants (shares)	72,858
Granted (shares)	20,199
Vested (shares)	(15,090)
Forfeited (shares)	0
Remaining nonvested grants (shares)	77,967	72,858
Beginning nonvested (weighted-average grant date fair value)	$ 51.35
Granted (weighted-average grant date fair value)	44.57
Vested (weighted-average grant date fair value)	44.77
Forfeited (weighted-average grant date fair value)	0
Remaining nonvested (weighted-average grant date fair value)	$ 50.86	$ 51.35
Performance and vesting period	5 years	5 years

Common Stock Common Stock (Deta

Common Stock Common Stock (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Class of Stock [Line Items]
Combined common and preferred stock, shares authorized	250,000,000
Common stock, shares authorized	200,000,000	200,000,000
Common stock, par or stated value per share	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, par or stated value per share	$ 0.01	$ 0.01
Common stock reserved for incentive plan awards	2,865,957
Net proceeds from sale of stock	$ 1,398	$ 3,124	$ 47,754
Shares paid for tax withholding	35,378	25,329

Earnings Per Share (Details)

Earnings Per Share (Details) - shares	3 Months Ended		12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Basic computation	50,583,000	50,448,000	50,559,208	50,428,560	49,984,562
Performance and restricted share awards (1)			145,181	323,298	252,909
Diluted computation			50,704,389	50,751,858	50,237,471
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount			53,716

Commitments and Contingencies Q

Commitments and Contingencies Qualifying Facilities Liability (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Beginning QF liability	$ 92,937,000
Ending QF liability	81,379,000	$ 92,937,000
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
Periodic adjustment of the liability for price escalation	1,100,000
Annual reset of liability to actual output and pricing	$ 2,200,000
Maximum [Member]
Long term purchase commitments term	24 years
Qualifying Facility Contracts [Member]
Beginning QF liability	$ 92,937,000	102,260,000
Unrecovered amount (1)	(18,665,000)	(17,257,000)
Interest expense	7,107,000	7,934,000
Ending QF liability	81,379,000	$ 92,937,000
Qualifying Facility Contracts [Member] | Minimum [Member]
Price per MWH of energy required to be purchased per QF agreement	63
Qualifying Facility Contracts [Member] | Maximum [Member]
Price per MWH of energy required to be purchased per QF agreement	136
Qualifying Facility Contracts [Member] | Gross Obligation [Member]
Recorded Unconditional Purchase Obligation	551,957,000
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
2021	77,722,000
2022	79,572,000
2023	81,646,000
2024	79,384,000
2025	65,041,000
Thereafter	168,592,000
Recorded Unconditional Purchase Obligation	551,957,000
Qualifying Facility Contracts [Member] | Recoverable Amounts [Member]
Recorded Unconditional Purchase Obligation	448,548,000
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
2021	60,136,000
2022	60,639,000
2023	61,280,000
2024	60,706,000
2025	52,950,000
Thereafter	152,837,000
Recorded Unconditional Purchase Obligation	448,548,000
Qualifying Facility Contracts [Member] | Net Amount [Member]
Recorded Unconditional Purchase Obligation	103,409,000
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
2021	17,586,000
2022	18,933,000
2023	20,366,000
2024	18,678,000
2025	12,091,000
Thereafter	15,755,000
Recorded Unconditional Purchase Obligation	$ 103,409,000

Commitments and Contingencies L

Commitments and Contingencies Long Term Supply and Capacity Purchase Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Long-term Purchase Commitment [Line Items]
Long term purchase committments costs incurred	$ 206.6	$ 222.5	$ 209.3
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
Purchase obligation due in next twelve months	211.5
Purchase obligation due in second year	190.9
Purchase obligation due in third year	195.1
Purchase obligation due in fourth year	173.2
Purchase obligation due in fifth year	170.1
Purchase obligation due thereafter	$ 1,300
Maximum [Member]
Long-term Purchase Commitment [Line Items]
Long term purchase commitments term	24 years
Hydroelectric License Commitments [Member]
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
Hydro MOU commitment	$ 28.4

Commitments and Contingencies E

Commitments and Contingencies Environmental Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Environmental remediation obligations [Member]
Environmental remediation obligation, minimum	$ 26,600
Environmental remediation obligation, maximum	32,200
Accrual for environmental loss contingencies	28,895	$ 30,276	$ 29,741	$ 30,326
Deductions	(2,977)	(2,232)	(2,333)
Charged to costs and expense	1,596	$ 2,767	$ 1,748
Combined Manufacturing Sites [Member] | Manufactured Gas Plants [Member]
Accrual for environmental loss contingencies	22,700
Aberdeen South Dakota Site [Member] | Manufactured Gas Plants [Member]
Accrual for environmental loss contingencies	8,200
Environmental remediation obligation, to be incurred during next 5 years	$ 3,100

Commitments and Contingencies_2

Commitments and Contingencies Legal Proceedings (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)
Pacific Northwest Solar, LLC (PNWS) [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 8
Riverbed Rents [Member]
Loss Contingencies [Line Items]
Annual riverbed rent exposure	$ 3.8

Revenue from Contracts with C_4

Revenue from Contracts with Customers Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			$ 1,206,800	$ 1,231,100
Total revenues	$ 313,445	$ 328,135	1,198,670	1,257,910	$ 1,192,009
Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			529,300	526,700
Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			513,100	530,700
Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			37,700	44,600
Lighting, Governmental, Irrigation, and Interdepartmental
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			32,700	31,600
Total Customer Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			1,112,800	1,133,600
Other Tariff and Contract Based Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			94,000	97,500
Montana | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			424,300	418,200
Montana | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			389,600	403,800
South Dakota | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			88,100	88,300
South Dakota | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			115,400	116,400
Nebraska | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			16,900	20,200
Nebraska | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			8,100	10,500
Regulatory Amortization [Member]
Disaggregation of Revenue [Line Items]
Regulatory amortization			(8,100)	26,800
Total Revenue [Member]
Disaggregation of Revenue [Line Items]
Total revenues			1,198,700	1,257,900
Electric
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			953,900	952,400
Electric | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			387,400	371,300
Electric | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			439,400	445,200
Electric | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			36,800	43,600
Electric | Lighting, Governmental, Irrigation, and Interdepartmental
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			31,800	30,600
Electric | Total Customer Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			895,400	890,700
Electric | Other Tariff and Contract Based Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			58,500	61,700
Electric | Montana | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			320,800	308,800
Electric | Montana | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			338,300	348,100
Electric | South Dakota | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			66,600	62,500
Electric | South Dakota | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			101,100	97,100
Electric | Nebraska | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			0	0
Electric | Nebraska | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			0	0
Electric | Regulatory Amortization [Member]
Disaggregation of Revenue [Line Items]
Regulatory amortization			(13,100)	28,800
Electric | Total Revenue [Member]
Disaggregation of Revenue [Line Items]
Total revenues			940,800	981,200
Natural gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			252,900	278,700
Natural gas | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			141,900	155,400
Natural gas | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			73,700	85,500
Natural gas | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			900	1,000
Natural gas | Lighting, Governmental, Irrigation, and Interdepartmental
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			900	1,000
Natural gas | Total Customer Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			217,400	242,900
Natural gas | Other Tariff and Contract Based Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			35,500	35,800
Natural gas | Montana | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			103,500	109,400
Natural gas | Montana | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			51,300	55,700
Natural gas | South Dakota | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			21,500	25,800
Natural gas | South Dakota | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			14,300	19,300
Natural gas | Nebraska | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			16,900	20,200
Natural gas | Nebraska | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			8,100	10,500
Natural gas | Regulatory Amortization [Member]
Disaggregation of Revenue [Line Items]
Regulatory amortization			5,000	(2,000)
Natural gas | Total Revenue [Member]
Disaggregation of Revenue [Line Items]
Total revenues			$ 257,900	$ 276,700

Segment and Related Informati_3

Segment and Related Information (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Total revenues	$ 313,445	$ 328,135	$ 1,198,670	$ 1,257,910	$ 1,192,009
Cost of sales			306,190	318,020	272,883
Gross margin			892,480	939,890	919,126
Operating, general and administrative			297,115	318,229	307,119
Property and other taxes			179,517	171,888	171,259
Depreciation and depletion			179,644	172,923	174,476
Operating Income	66,496	84,651	236,204	276,850	266,272
Interest expense, net			(96,812)	(95,068)	(91,988)
Other income, net			4,853	413	3,966
Income tax (expense) benefit			10,970	19,925	18,710
Net Income	53,551	59,982	155,215	202,120	196,960
Total assets	6,389,449	6,083,486	6,389,449	6,083,486	5,805,999
Capital expenditures			405,762	316,016	283,966
Eliminations
Segment Reporting Information [Line Items]
Total revenues			0	0	0
Cost of sales			0	0	0
Gross margin			0	0	0
Operating, general and administrative			0	0	0
Property and other taxes			0	0	0
Depreciation and depletion			0	0	0
Operating Income			0	0	0
Interest expense, net			0	0	0
Other income, net			0	0	0
Income tax (expense) benefit			0	0	0
Net Income			0	0	0
Total assets	0	0	0	0	0
Capital expenditures			0	0	0
Operating Segments | Electric
Segment Reporting Information [Line Items]
Total revenues			940,815	981,178	921,093
Cost of sales			236,581	239,589	194,608
Gross margin			704,234	741,589	726,485
Operating, general and administrative			218,822	232,424	223,598
Property and other taxes			140,621	134,686	134,681
Depreciation and depletion			147,968	143,262	144,636
Operating Income			196,823	231,217	223,570
Interest expense, net			(85,487)	(78,809)	(79,033)
Other income, net			4,867	(1,365)	2,794
Income tax (expense) benefit			11,282	(6,079)	21,686
Net Income			127,485	144,964	169,017
Total assets	4,638,274	4,808,011	4,638,274	4,808,011	4,626,530
Capital expenditures			324,369	241,190	221,968
Operating Segments | Gas Domestic Regulated [Member]
Segment Reporting Information [Line Items]
Total revenues			257,855	276,732	270,916
Cost of sales			69,609	78,431	78,275
Gross margin			188,246	198,301	192,641
Operating, general and administrative			80,082	82,732	82,864
Property and other taxes			38,887	37,192	36,569
Depreciation and depletion			31,676	29,661	29,822
Operating Income			37,601	48,716	43,386
Interest expense, net			(6,341)	(6,218)	(5,858)
Other income, net			2,704	(814)	962
Income tax (expense) benefit			(2,426)	493	9,268
Net Income			31,538	42,177	47,758
Total assets	1,739,555	1,270,811	1,739,555	1,270,811	1,174,737
Capital expenditures			81,393	74,826	61,998
Other Segments [Member] | Operating Segments
Segment Reporting Information [Line Items]
Total revenues			0	0	0
Cost of sales			0	0	0
Gross margin			0	0	0
Operating, general and administrative			(1,789)	3,073	657
Property and other taxes			9	10	9
Depreciation and depletion			0	0	18
Operating Income			1,780	(3,083)	(684)
Interest expense, net			(4,984)	(10,041)	(7,097)
Other income, net			(2,718)	2,592	210
Income tax (expense) benefit			2,114	25,511	(12,244)
Net Income			(3,808)	14,979	(19,815)
Total assets	$ 11,620	$ 4,664	11,620	4,664	4,732
Capital expenditures			$ 0	$ 0	$ 0

Quarterly Financial Data (Una_3

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating revenues	$ 313,445	$ 328,135	$ 1,198,670	$ 1,257,910	$ 1,192,009
Operating income	66,496	84,651	236,204	276,850	266,272
Net income	$ 53,551	$ 59,982	$ 155,215	$ 202,120	$ 196,960
Average Common Shares Outstanding	50,583,000	50,448,000	50,559,208	50,428,560	49,984,562
Income per average common share
Income per average common share, basic	$ 1.06	$ 1.19	$ 3.07	$ 4.01	$ 3.94
Income per average common share, diluted	$ 1.06	$ 1.18	$ 3.06	$ 3.98	$ 3.92