NorthWestern (NWE) 10-K 11 Feb 22 2021 FY Annual report Financial data

Cover page Cover page

Cover page Cover page - USD ($)	12 Months Ended
	Dec. 31, 2021	Feb. 04, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
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	2021
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			$ 3,104,943,983
Entity Common Stock, Shares Outstanding		54,082,096
Documents Incorporated by Reference	Documents Incorporated by Reference Certain sections of our Proxy Statement for the 2022 Annual Meeting of Shareholders are incorporated by reference into Part III of this Form 10-K

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
Audit Information [Abstract]
Auditor Name	Deloitte & Touche LLP
Auditor Firm ID	34
Auditor Location	Minneapolis, Minnesota

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenues
Electric	$ 1,052,182	$ 940,815	$ 981,178
Gas	320,134	257,855	276,732
Total Revenues	1,372,316	1,198,670	1,257,910
Utilities Operating Expense, Fuel Used	425,548	306,190	318,020
Operating Expenses
Operating and maintenance	208,303	202,991	209,052
Administrative and general	101,873	94,124	109,177
Property and other taxes	173,444	179,517	171,888
Depreciation and depletion	187,467	179,644	172,923
Total Operating Expenses	1,096,635	962,466	981,060
Operating Income	275,681	236,204	276,850
Interest Expense, net	(93,674)	(96,812)	(95,068)
Other Income, net	8,252	4,853	413
Income Before Income Taxes	190,259	144,245	182,195
Income Tax (Expense) Benefit	(3,419)	10,970	19,925
Net Income	$ 186,840	$ 155,215	$ 202,120
Average Common Shares Outstanding	51,709,229	50,559,208	50,428,560
Basic Earnings per Average Common Share	$ 3.61	$ 3.07	$ 4.01
Diluted Earnings per Average Common Share	$ 3.60	$ 3.06	$ 3.98

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Net Income	$ 186,840	$ 155,215	$ 202,120
Other comprehensive income (loss), net of tax:
Postretirement medical liability adjustment	(436)	1,840	(131)
Foreign currency translation adjustment	(57)	87	(35)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, after Tax	(452)	(452)	(452)
Total Other Comprehensive Income (Loss)	(41)	2,379	286
Comprehensive Income	$ 186,799	$ 157,594	$ 202,406

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Current Assets:
Cash and cash equivalents	$ 2,820	$ 5,811
Restricted cash	15,942	11,285
Accounts receivable, net	198,671	168,229
Inventories	80,614	61,010
Regulatory assets	115,541	44,973
Prepaid expenses and other	24,207	17,372
Total current assets	437,795	308,680
Property, plant, and equipment, net	5,247,232	4,952,935
Goodwill	357,586	357,586
Regulatory assets	690,686	701,444
Other noncurrent assets	47,144	68,804
Total Assets	6,780,443	6,389,449
Current Liabilities:
Current maturities of finance leases	2,875	2,668
Short-term borrowings	0	100,000
Accounts payable	115,237	100,388
Accrued expenses	233,351	207,514
Regulatory liabilities	28,179	55,853
Total current liabilities	379,642	466,423
Long-term finance leases	11,897	14,771
Long-term debt	2,541,478	2,315,261
Deferred income taxes	499,634	471,777
Noncurrent regulatory liabilities	638,760	631,419
Other noncurrent liabilities	369,319	410,703
Total Liabilities	4,440,730	4,310,354
Commitments and Contingencies (Note 18)
Common Stock, Value, Issued	$ 576	$ 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	57,606,252	54,144,775
Common Stock, shares outstanding	54,060,608	50,587,163
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	$ (98,248)	$ (98,075)
Paid-in capital	1,716,227	1,513,787
Retained earnings	728,468	670,111
Accumulated other comprehensive loss	(7,310)	(7,269)
Total Shareholders' Equity	2,339,713	2,079,095
Total Liabilities and Shareholders' Equity	$ 6,780,443	$ 6,389,449

CONSOLIDATED BALANCE SHEETS PAR

CONSOLIDATED BALANCE SHEETS PARENTHETICAL (Parentheticals) - $ / shares	Dec. 31, 2021	Dec. 31, 2020
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	57,606,252	54,144,775
Common Stock, shares outstanding	54,060,608	50,587,163
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, 2021	Dec. 31, 2020	Dec. 31, 2019
OPERATING ACTIVITIES:
Net Income	$ 186,840	$ 155,215	$ 202,120
Items not affecting cash:
Depreciation and depletion	187,467	179,644	172,923
Amortization of debt issuance costs, discount and deferred hedge gain	5,250	4,911	4,648
Stock-based compensation costs	5,350	4,149	8,007
Equity portion of allowance for funds used during construction	(11,092)	(6,895)	(5,768)
(Gain) loss on disposition of assets	(47)	37	(188)
Deferred income taxes	525	(7,574)	(13,864)
Changes in current assets and liabilities:
Accounts receivable	(30,442)	(824)	(5,032)
Inventories	(19,604)	(7,085)	(3,110)
Other current assets	(6,835)	(3,477)	(3,140)
Accounts payable	7,494	16,043	(1,821)
Accrued expenses	26,055	5,909	(16,023)
Regulatory assets	(69,616)	14,749	(16,028)
Regulatory liabilities	(27,674)	22,773	(7,796)
Other noncurrent assets	2,313	(5,396)	(22,841)
Other noncurrent liabilities	(36,006)	(20,030)	4,633
Cash Provided by Operating Activities	219,978	352,149	296,720
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(434,328)	(405,762)	(316,016)
Investment in equity securities	(1,505)	(42)	(135)
Cash Used in Investing Activities	(435,833)	(405,804)	(316,151)
FINANCING ACTIVITIES:
Dividends on common stock	(128,483)	(120,350)	(115,127)
Proceeds from issuance of common stock, net	196,246	0	0
Issuance of long-term debt	99,915	150,000	150,000
Payment for Debt Extinguishment or Debt Prepayment Cost	(955)	0	0
Line of credit borrowings (repayments), net	151,000	(67,000)	(19,000)
(Repayments) issuances of short-term borrowings	(100,000)	100,000	0
Treasury stock activity	707	(1,391)	1,432
Financing costs	(909)	(2,578)	(1,115)
Cash Provided by Financing Activities	217,521	58,681	16,190
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	1,666	5,026	(3,241)
Cash, Cash Equivalents, and Restricted Cash, beginning of period	17,096	12,070	15,311
Cash, Cash Equivalents, and Restricted Cash, end of period	$ 18,762	$ 17,096	$ 12,070

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, 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]
Net Income	202,120	$ 0	0	$ 0	202,120	0
Foreign currency translation adjustment	(35)	0	0	0	0	(35)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, after 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	$ 2.30
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
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, after 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	$ 2.40
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
Increase (Decrease) in Shareholders' Equity [Roll Forward]
Net Income	186,840	$ 0	0	$ 0	186,840	0
Foreign currency translation adjustment	(57)	0	0	0	0	(57)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, after Tax	(452)	0	0	0	0	(452)
Postretirement medical liability adjustment, net of tax	(436)	0	0	0	0	436
Stock based compensation, value	$ 4,328	$ 1	5,298	$ (971)	0	0
Stock based compensation, shares		93		17
Treasury Stock, Shares, Acquired	(29)
Issuance of shares, value	$ 197,974	$ 34	197,142		0	0
Issuance of shares, shares		3,368
Issuance of shares, value, treasury stock reissued				$ 798
Dividends on common stock	$ (128,483)	$ 0	0	0	(128,483)	0
Dividends per share	$ 2.48
Balance at Dec. 31, 2021	$ 2,339,713	$ 576	$ 1,716,227	$ (98,248)	$ 728,468	$ (7,310)
Shares, Balance at Dec. 31, 2021		57,606		3,546

Nature of Operations and Basis

Nature of Operations and Basis of Consolidation	12 Months Ended
	Dec. 31, 2021
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 753,600 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, 2021, have been evaluated as to their potential impact to the Consolidated Financial Statements through the date of issuance. Reclassification In 2021, we renamed the line item "Cost of sales" as previously shown on the Consolidated Statements of Income, and used elsewhere within our filing, to "Fuel, purchased supply and direct transmission expense." Additionally, we disaggregated the line item "Operating, general and administrative" as previously shown on the Consolidated Statements of Income, and used elsewhere within our filing, to two line items, "Operating and maintenance" and "Administrative and general." These reclassifications were done in an effort to better convey the nature of these costs. 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, 2021
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 $2.3 million and $5.6 million at December 31, 2021 and December 31, 2020. Receivables include unbilled revenues of $98.1 million and $80.5 million at December 31, 2021 and December 31, 2020, respectively. Inventories Inventories are stated at average cost. Inventory consisted of the following (in thousands): December 31, 2021 2020 Materials and supplies $ 54,137 $ 44,311 Storage gas and fuel 26,477 16,699 Total Inventories $ 80,614 $ 61,010 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 6.6%, 6.7%, and 6.9% for Montana for 2021, 2020, and 2019, respectively. This rate averaged 6.4%, 6.7%, and 6.6% for South Dakota for 2021, 2020, and 2019, respectively. AFUDC capitalized totaled $15.9 million, $9.8 million, and $8.2 million for the years ended December 31, 2021, 2020, and 2019, 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% for 2021, 2020, and 2019. 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, 2021 2020 Property taxes $ 86,168 $ 89,425 Employee compensation, benefits, and withholdings 44,743 40,538 Customer advances 29,013 16,015 Interest 18,568 18,074 Other (none of which is individually significant) 54,859 43,462 Total Accrued Expenses $ 233,351 $ 207,514 Other Noncurrent Liabilities Other noncurrent liabilities consisted of the following (in thousands): December 31, 2021 2020 Pension and other employee benefits $ 96,151 $ 136,632 Customer advances 80,780 65,186 Future QF obligation, net 64,943 81,379 Asset retirement obligations 38,350 45,355 Environmental 23,395 25,049 Other (none of which is individually significant) 65,700 57,102 Total Noncurrent Liabilities $ 369,319 $ 410,703 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, 2021 2020 2019 (in thousands) Cash paid (received) for: Income taxes $ 4,330 $ 115 $ (6,737) Interest 87,221 84,922 83,776 Significant non-cash transactions: Capital expenditures included in trade accounts payable 29,034 21,430 33,473 NMTC debt extinguishment included in other noncurrent assets (1) 18,169 — — NMTC debt extinguishment included in property, plant and equipment, net (1) 6,594 — — NMTC debt extinguishment included in long-term debt (1) 1,259 — — (1) See Note 11 - Long-Term Debt and Finance Leases for further information regarding these non-cash transactions. 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, 2021 2020 2019 Cash and cash equivalents $ 2,820 $ 5,811 $ 5,145 Restricted cash 15,942 11,285 6,925 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 18,762 $ 17,096 $ 12,070 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, 2021
Regulated Operations [Abstract]
Regulatory Matters	(3) Regulatory Matters Power Costs and Credits Adjustment Mechanism (PCCAM) - Montana We track electric supply costs for our Montana electric utility, such as purchased power and fuel, against a forecast of costs approved by the MPSC. This forecast is referred to as the power costs and credits adjustment mechanism base (PCCAM Base). If our actual costs exceed the approved PCCAM Base revenues on an annual basis, we can recover 90% of the excess costs, with the non-recoverable 10% impacting net income. Our QF power purchase costs are recoverable through rates separate from the PCCAM Base. The MPSC reviews these costs annually, with NorthWestern receiving an automatic adjustment through interim rates, subject to refund, effective on October 1 of each year. During the twelve months ended December 31, 2021 we recognized $5.4 million of non-recoverable excess PCCAM supply costs, compared to $0.8 million of non-recoverable excess PCCAM supply costs for the twelve months ended December 31, 2020. The current PCCAM Base, approved in 2019, no longer reflects an accurate current forecast of our fuel and power costs. In April 2021, we filed an application with the MPSC for approval to increase the PCCAM Base by approximately $17.0 million. On June 29, 2021, the MPSC approved interim rates reflecting our request, subject to refund. On August 2, 2021, the MCC filed a motion asking the MPSC to dismiss the application arguing that the MPSC issued a Final Order in 2018 prohibiting NorthWestern from requesting an update to the PCCAM Base, except in a general rate case. NorthWestern argued that the tariff, which the MPSC approved as implementing the Final Order, allows us to file an application outside of a general rate case. On October 5, 2021, the MPSC voted to grant the MCC’s motion to dismiss. The MPSC issued the final written order on December 2, 2021, dismissing our application. As of December 31, 2021, we had deferred revenue of approximately $8.2 million, which we expect to refund in 2022, associated with these interim rates, including interest. Montana Community Renewable Energy Projects (CREPs) We were required to acquire, as of December 31, 2020, approximately 65 MW of CREPs. While we made progress towards meeting this obligation by acquiring approximately 50 MW of CREPs, we were 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 was fully briefed before the Montana Supreme Court. On May 14, 2021, the Montana Governor signed a bill that eliminated the state's Renewable Portfolio Standard, including repeal of the CREP requirement. We notified the Montana Supreme Court of the repeal. We also dismissed our pending application filed with the MPSC for a waiver from full compliance for years 2017 through 2020. On September 7, 2021, the Montana Supreme Court remanded the case challenging the 2015 and 2016 waivers to the District Court to determine whether the repeal of the CREP requirement made the petition moot. The matter has been fully briefed before the District Court. In that briefing, the Montana Environmental Information Center requested the District Court to amend its previous judgment and penalize us $2.5 million for failure to comply with the CREP requirement in 2015 and 2016. We responded to this request arguing that it was unlawful for the District Court to penalize us. We expect a decision from the District Court in the first half of 2022. If the Montana Courts and/or MPSC determine that the repeal should not be applied retroactively and find that waivers should not be granted, we could be liable for penalties. However, we do not believe any such penalties would be material. FERC Financial Audit We are subject to FERC’s jurisdiction and regulations with respect to rates for electric transmission service in interstate commerce and electricity sold at wholesale rates, the issuance of certain securities, and incurrence of certain long-term debt, among other things. The Division of Audits and Accounting in the Office of Enforcement of FERC has initiated a routine audit of NorthWestern Corporation for the period of January 1, 2018 to the present to evaluate our compliance with FERC accounting and financial reporting requirements. We have responded to several sets of data requests as part of the audit process. An audit report has not yet been received from FERC, but is expected during the first quarter of 2022. Management is unable to predict the outcome or timing of the final resolution of the audit.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 (in thousands) Flow-through income taxes 12 Plant Lives $ 464,663 $ 420,925 Excess deferred income taxes 12 Plant Lives 60,813 67,256 Pension 14 See Note 14 98,336 138,567 Deferred financing costs Various 25,636 28,350 Employee related benefits 14 Various 21,648 22,516 Supply costs 18 months 88,329 8,116 State & local taxes & fees Various 6,520 17,910 Environmental clean-up 18 Various 11,262 11,127 Other Various 29,020 31,650 Total Regulatory Assets $ 806,227 $ 746,417 Removal cost 6 Various $ 479,294 $ 464,669 Excess deferred income taxes 12 Plant Lives 158,047 165,279 Supply costs 1 Year 16,430 13,847 Gas storage sales 18 years 7,466 7,887 Rates subject to refund 1 Year 1,971 32,496 State & local taxes & fees 1 Year 3,021 1,783 Environmental clean-up Various 508 656 Other Various 202 655 Total Regulatory Liabilities $ 666,939 $ 687,272 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 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, and granting interim rates (subject to refund) effective July 1, 2019. In November 2020, we filed a settlement and implemented settlement rates on December 1, 2020. In January 2021, the FERC approved our settlement and during the first quarter of 2021 we refunded approximately $20.5 million to our FERC regulated customers. Revenues from FERC regulated customers associated with our Montana FERC assets are reflected in our MPSC jurisdictional rates as a credit to retail customers. In March 2021, we submitted a compliance filing with the MPSC adjusting the revenue credit in our Montana retail rates to reflect the FERC approved settlement rates and a refund to retail customers of the difference between the FERC interim rates and the FERC approved settlement rates that were collected during the period from July 1, 2019 through March 31, 2021. On May 19, 2021, the MPSC approved the proposed tariffs and rates on a final basis. During the second quarter of 2021, we recognized a $4.7 million favorable adjustment related to excess deferred revenues based on the final MPSC approval. As of December 31, 2021, we had cumulative deferred revenue remaining of approximately $2.0 million recorded as a regulatory liability on the Consolidated Balance Sheets. 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. We do not earn interest on our electric supply tracker, the PCCAM, in Montana. 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, 2021
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, 2021 2020 (years) (in thousands) Transmission, distribution, and storage 15 – 95 $ 4,004,819 $ 3,771,023 Generation 23 – 72 1,287,517 1,252,805 Plant acquisition adjustment (1) 25 – 50 686,328 686,328 Building and improvements 23 – 73 296,955 303,099 Land, land rights and easements 53 – 96 161,585 157,379 Other 2 – 45 585,448 571,981 Construction work in process –— 294,617 173,492 Total property, plant and equipment 7,317,269 6,916,107 Less accumulated depreciation (1,787,550) (1,703,016) Less accumulated amortization (282,487) (260,156) Net property, plant and equipment $ 5,247,232 $ 4,952,935 ___________________________ (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 $9.2 million and $11.3 million as of December 31, 2021 and 2020, respectively, which included $9.0 million and $11.1 million as of December 31, 2021 and 2020, 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, 2021 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 154,375 $ 62,865 $ 51,652 $ 324,433 Accumulated depreciation 42,102 34,629 38,453 113,805 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

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 2019 Liability at January 1, $ 45,355 $ 42,449 $ 40,659 Accretion expense 2,233 2,070 2,051 Liabilities incurred — — — Liabilities settled (2,906) (4,061) (46) Revisions to cash flows (4,051) 4,897 (215) Liability at December 31, $ 40,631 $ 45,355 $ 42,449 During the twelve months ended December 31, 2021 our ARO liability decreased $2.9 million for partial settlement of the legal obligations at our jointly-owned coal-fired generation facilities. Additionally, during the twelve months ended December 31, 2021, our ARO liability decreased $4.1 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, 2021 and 2020.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	(7) Goodwill We completed our annual goodwill impairment test as of April 1, 2021 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, 2021 2020 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, 2021
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, 2021 and 2020. 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, 2021 Interest rate contracts Interest Expense $ 614 A pre-tax loss of approximately $14.0 million is remaining in AOCL as of December 31, 2021, 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, 2021
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, 2021 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 $ 14,967 $ — $ — $ — $ 14,967 Rabbi trust investments 18,234 — — — 18,234 Total $ 33,201 $ — $ — $ — $ 33,201 December 31, 2020 Restricted cash equivalents $ 10,055 $ — $ — $ — $ 10,055 Rabbi trust investments 27,027 — — — 27,027 Total $ 37,082 $ — $ — $ — $ 37,082 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, 2021 December 31, 2020 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 2,541,478 $ 2,827,336 $ 2,315,261 $ 2,629,755 The estimated fair value amounts have been determined using available market information and appropriate valuation methodologies; however, considerable judgment is required in interpreting market data to develop estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we would realize in a current market exchange. We determined fair value for long-term debt based on interest rates that are currently available to us for issuance of debt with similar terms and remaining maturities, except for publicly traded debt, for which fair value is based on market prices for the same or similar issues or upon the quoted market prices of U.S. treasury issues having a similar term to maturity, adjusted for our bond issuance rating and the present value of future cash flows. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy.

Short-Term Borrowings and Credi

Short-Term Borrowings and Credit Arrangements	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Short-term Debt	(10) Unsecured Credit Facilities Credit Facility We have a $425 million Credit Facility which matures September 2, 2023. The Credit Facility includes 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 $0.4 million and $0.6 million for the years ended December 31, 2021 and 2020. The availability under the facilities in place for the years ended December 31 is shown in the following table (in millions): 2021 2020 Unsecured revolving line of credit, expiring September 2023 $ 425.0 $ 425.0 Unsecured revolving line of credit, expiring March 2023 25.0 25.0 450.0 450.0 Amounts outstanding at December 31: Eurodollar borrowings 373.0 222.0 Letters of credit — — 373.0 222.0 Net availability as of December 31 $ 77.0 $ 228.0 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, 2021
Long-term Debt and Lease Obligation [Abstract]
Long-term Debt	(11) Long-Term Debt and Finance Leases Long-term debt and finance leases consisted of the following (in thousands): December 31, Due 2021 2020 Unsecured Debt: Unsecured Revolving Line of Credit 2023 $ 373,000 $ 222,000 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 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 100,000 100,000 Montana—1.00% 2024 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 Discount on Notes and Bonds and Debt Issuance Costs, Net — (11,182) (13,376) Total Long-Term Debt $ 2,541,478 $ 2,315,261 Finance Leases: Total Finance Leases Various $ 14,772 $ 17,439 Less current maturities (2,875) (2,668) Total Long-Term Finance Leases $ 11,897 $ 14,771 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 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. In March 2021, we issued and sold $100.0 million aggregate principal amount of Montana First Mortgage Bonds (the bonds) at a fixed interest rate of 1.00 percent maturing on March 26, 2024. The net proceeds were used to repay in full our outstanding $100.0 million term loan that was due April 2, 2021. We may redeem some or all of the bonds at any time in whole, or from time to time in part, at our option, on or after March 26, 2022, at a redemption price equal to 100% of the principal amount of the bonds to be redeemed, plus accrued and unpaid interest on the principal amount of the bonds being redeemed to, but excluding, the redemption date. The bonds are secured by our electric and natural gas assets in Montana and Wyoming. As of December 31, 2021, we were in compliance with our financial debt covenants. Other Long-Term Debt In July 2021, our two loans totaling $27.0 million associated with the New Market Tax Credit (NMTC) financing agreement were extinguished. These loans were satisfied with our $18.2 million investment in the entities created in relation to the NMTC transaction, investor forgiveness of $7.9 million for substantially all of the benefits derived from the tax credits, and cash payment of $0.9 million. In accordance with our last rate case filing in the state of Montana, the portion of the loan forgiven, less unamortized debt issuance costs of $1.3 million, was recorded as a reduction to the cost of the office building associated with the NMTC financing agreement. This cash payment is reflected within the financing activities section of our Consolidated Statement of Cash Flows for the year ended December 31, 2021; however, the remaining reduction to Long-term debt, Other noncurrent assets, and Property, plant and equipment are non-cash financing activities that are not reflected within our Consolidated Statement of Cash Flows for the year ended December 31, 2021. Maturities of Long-Term Debt The aggregate minimum principal maturities of long-term debt and finance leases, during the next five years are $2.9 million in 2022, $520.8 million in 2023, $103.3 million in 2024, $303.6 million in 2025 and $106.9 million in 2026.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income Taxes	(12) Income Taxes Income tax expense (benefit) is comprised of the following (in thousands): Year Ended December 31, 2021 2020 2019 Federal Current $ 722 $ (3,396) $ (6,076) Deferred 2,626 (4,006) (15,169) Investment tax credits (130) (3) (12) State Current 2,172 3 27 Deferred (1,971) (3,568) 1,305 Income Tax Expense (Benefit) $ 3,419 $ (10,970) $ (19,925) 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, 2021 2020 2019 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax, net of federal provisions 0.1 (1.1) 0.7 Flow-through repairs deductions (11.5) (16.5) (10.8) Production tax credits (6.1) (9.1) (6.3) Plant and depreciation of flow through items (0.6) 0.1 (2.2) Amortization of excess DIT (0.3) (0.7) (0.9) Recognition of unrecognized tax benefit — — (12.5) Impact of Tax Cuts and Jobs Act — — (0.1) Prior year permanent return to accrual adjustments 0.0 (1.2) 0.3 Other, net (0.8) (0.1) (0.1) Effective tax rate 1.8 % (7.6) % (10.9) % The table below summarizes the significant differences in income tax expense (benefit) based on the differences between our effective tax rate and the federal statutory rate (in thousands). Year Ended December 31, 2021 2020 2019 Income Before Income Taxes $ 190,259 $ 144,245 $ 182,195 Income tax calculated at federal statutory rate 39,954 30,292 38,261 Permanent or flow through adjustments: State income, net of federal provisions 354 (1,477) 1,251 Flow-through repairs deductions (21,888) (23,828) (19,706) Production tax credits (11,532) (13,103) (11,483) Plant and depreciation of flow through items (941) 121 (3,952) Amortization of excess DIT (635) (968) (1,688) Prior year permanent return to accrual adjustments (12) (1,728) 559 Recognition of unrecognized tax benefit — — (22,825) Impact of Tax Cuts and Jobs Act — — (198) Other, net (1,881) (279) (144) (36,535) (41,262) (58,186) Income Tax Expense (Benefit) $ 3,419 $ (10,970) $ (19,925) 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 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, 2021 2020 Production tax credit $ 75,092 $ 63,542 Pension / postretirement benefits 21,435 31,866 Customer advances 21,271 17,165 Unbilled revenue 10,704 14,429 Compensation accruals 10,612 11,748 Reserves and accruals 5,106 6,266 Environmental liability 5,704 6,039 Interest rate hedges 3,158 3,171 NOL carryforward — 393 Other, net 1,738 2,490 Deferred Tax Asset 154,820 157,109 Excess tax depreciation (425,202) (412,774) Goodwill amortization (85,425) (83,991) Flow through depreciation (94,616) (83,545) Regulatory assets and other (49,211) (48,576) Deferred Tax Liability (654,454) (628,886) Deferred Tax Liability, net $ (499,634) $ (471,777) 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): 2021 2020 2019 Unrecognized Tax Benefits at January 1 $ 33,491 $ 35,085 $ 56,150 Gross increases - tax positions in prior period 293 120 539 Gross increases - tax positions in current period — — — Gross decreases - tax positions in current period (1,735) (1,714) (1,489) Lapse of statute of limitations — — (20,115) Unrecognized Tax Benefits at December 31 $ 32,049 $ 33,491 $ 35,085 Our unrecognized tax benefits include approximately $28.1 million and $28.0 million related to tax positions as of December 31, 2021 and 2020, 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, 2021, we have accrued $0.5 million for the payment of interest and penalties in the Consolidated Balance Sheets. As of December 31, 2020, we did not have any amounts accrued for the payment of interest and penalties.

Comprehensive Income (Loss)

Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 2019 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 $ (57) $ — $ (57) $ 87 $ — $ 87 $ (35) $ — $ (35) Reclassification of net income (loss) on derivative instruments 614 (162) 452 614 (162) 452 614 (162) 452 Postretirement medical liability adjustment (585) 149 (436) 2,463 (623) 1,840 (175) 44 (131) Other comprehensive (loss) income $ (28) $ (13) $ (41) $ 3,164 $ (785) $ 2,379 $ 404 $ (118) $ 286 Balances by classification included within AOCL on the Consolidated Balance Sheets are as follows, net of tax (in thousands): December 31, 2021 2020 Foreign currency translation $ 1,443 $ 1,500 Derivative instruments designated as cash flow hedges (10,277) (10,729) Postretirement medical plans 1,524 1,960 Accumulated other comprehensive loss $ (7,310) $ (7,269) The following table displays the changes in AOCL by component, net of tax (in thousands): December 31, 2021 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (10,729) $ 1,960 $ 1,500 $ (7,269) Other comprehensive loss before reclassifications — — (57) (57) Amounts reclassified from AOCL Interest Expense 452 — — 452 Amounts reclassified from AOCL — (436) — (436) Net current-period other comprehensive income (loss) 452 (436) (57) (41) Ending Balance $ (10,277) $ 1,524 $ 1,443 $ (7,310) 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)

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2021
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 Plans' 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, 2021 2020 2021 2020 Change in benefit obligation: Obligation at beginning of period $ 820,979 $ 735,564 $ 19,146 $ 20,272 Service cost 12,994 11,116 407 370 Interest cost 18,759 22,840 317 492 Actuarial loss (28,905) 84,479 415 123 Settlements (1) (93,488) — — 390 Benefits paid (33,537) (33,020) (2,977) (2,501) Benefit Obligation at End of Period $ 696,802 $ 820,979 $ 17,308 $ 19,146 Change in Fair Value of Plan Assets: Fair value of plan assets at beginning of period $ 688,456 $ 609,000 $ 23,096 $ 21,479 Return on plan assets 33,868 101,075 3,349 2,723 Employer contributions 10,200 11,401 1,821 1,395 Settlements (1) (93,488) — — — Benefits paid (33,537) (33,020) (2,977) (2,501) Fair value of plan assets at end of period $ 605,499 $ 688,456 $ 25,289 $ 23,096 Funded Status $ (91,303) $ (132,523) $ 7,981 $ 3,950 Amounts Recognized in the Balance Sheet Consist of: Noncurrent asset 8,297 7,001 11,914 8,436 Total Assets 8,297 7,001 11,914 8,436 Current liability (11,200) (11,200) (1,575) (1,712) Noncurrent liability (88,400) (128,324) (2,358) (2,774) Total Liabilities (99,600) (139,524) (3,933) (4,486) Net amount recognized $ (91,303) $ (132,523) $ 7,981 $ 3,950 Amounts Recognized in Regulatory Assets Consist of: Prior service credit — — 1,870 3,857 Net actuarial loss (62,448) (115,987) 1,366 (497) Amounts recognized in AOCL consist of: Prior service cost — — (95) (246) Net actuarial gain — — 2,500 3,246 Total $ (62,448) $ (115,987) $ 5,641 $ 6,360 (1) In December 2021, we entered into a group annuity contract from an insurance company to provide for the payment of pension benefits to 1,062 NorthWestern Energy Pension Plan participants. We purchased the contract with $93.5 million of plan assets. The insurance company took over the payments of these benefits starting January 1, 2022. This transaction settled $93.5 million of our NorthWestern Energy Pension Plan obligation. As a result of this transaction, during the twelve months ended December 31, 2021, we recorded a non-cash, non-operating settlement charge of $11.3 million. This charge is recorded within other income, net on the Consolidated Statements of Income. As discussed within Note 4 – Regulatory Assets and Liabilities, this charge was deferred as a regulatory asset on the Consolidated Balance Sheets, with a corresponding decrease to operating and maintenance expense on the Consolidated Statements of Income. 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, 2021 2020 Projected benefit obligation $ 636.3 $ 757.4 Accumulated benefit obligation 636.3 757.4 Fair value of plan assets (1) 537.9 619.1 ____________________ As of December 31, 2021, 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. (1) Fair value of plan assets was impacted by the group annuity contract discussed above. 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, 2021 2020 2019 2021 2020 2019 Components of Net Periodic Benefit Cost Service cost $ 12,994 $ 11,116 $ 9,637 $ 407 $ 370 $ 331 Interest cost 18,759 22,840 26,488 327 492 609 Expected return on plan assets (27,061) (26,162) (25,443) (919) (983) (869) Amortization of prior service cost (credit) — — — (1,835) (1,882) (1,882) Recognized actuarial loss (gain) 6,536 5,028 6,544 (898) (61) (96) Settlement loss recognized (1) 11,291 — 198 — 390 390 Net Periodic Benefit Cost (Credit) $ 22,519 $ 12,822 $ 17,424 $ (2,918) $ (1,674) $ (1,517) Regulatory deferral of net periodic benefit cost (2) (13,308) (2,100) (7,510) — — — Previously deferred costs recognized (2) — 71 728 709 861 931 Amount Recognized in Income $ 9,211 $ 10,793 $ 10,642 $ (2,209) $ (813) $ (586) Income Statement Presentation Operating and maintenance (313) 9,016 2,125 407 370 331 Other income (expense), net 9,524 1,777 8,517 (2,616) (1,183) (917) Amount Recognized in Income $ 9,211 $ 10,793 $ 10,642 $ (2,209) $ (813) $ (586) ___________________________ (1) Settlement loss is related to partial annuitization of NorthWestern Energy Pension Plan effective December 1, 2021. (2) 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, 2021 and 2020. 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 increase in the discount rate during 2021 decreased our projected benefit obligation by approximately $45.1 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 increased our long term rate of return on assets assumption for NorthWestern Energy Pension Plan to 4.26 percent and decreased our assumption on the NorthWestern Corporation Pension Plan to 2.66 percent for 2022. The weighted-average assumptions used in calculating the preceding information are as follows: Pension Benefits Other Postretirement Benefits December 31, December 31, 2021 2020 2019 2021 2020 2019 Discount rate 2.65-2.75 % 2.20-2.30 % 3.10-3.20 % 2.35-2.40 % 1.80 % 2.80 % Expected rate of return on assets 3.01-4.17 3.45-4.49 4.23-5.06 4.08 4.71 4.79 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 2.00 2.00 2.00 2.00 Interest crediting rate 3.30-6.00 3.30-6.00 3.60-6.00 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, 2021 2020 2021 2020 2021 2020 Fixed income securities 55.0 % 55.0 % 90.0 % 80.0 % 40.0 % 40.0 % Non-U.S. fixed income securities 4.0 4.0 1.0 2.0 — — Global equities 41.0 41.0 9.0 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, 2021 2020 2021 2020 2021 2020 Cash and cash equivalents 0.1 % — % 0.4 % 0.7 % 0.1 % 1.0 % Fixed income securities 53.8 52.7 89.5 77.3 33.7 37.9 Non-U.S. fixed income securities 3.9 3.8 0.9 2.6 — — Global equities 42.2 43.5 9.2 19.4 66.2 61.1 100.0 % 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. Additional funding relief was passed in the American Rescue Plan Act of 2021, providing for longer amortization and interest rate smoothing, which we elected to use. We expect to continue to make contributions to the pension plans in 2022 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 2021, 2020 and 2019 was based on actual contributions to the plan. Annual contributions to each of the pension plans are as follows (in thousands): 2021 2020 2019 NorthWestern Energy Pension Plan (MT) $ 9,000 $ 10,201 $ 9,000 NorthWestern Corporation Pension Plan (SD and NE) 1,200 1,200 1,200 $ 10,200 $ 11,401 $ 10,200 We estimate the plans will make future benefit payments to participants as follows (in thousands): Pension Benefits Other Postretirement Benefits 2022 $ 28,842 $ 2,579 2023 30,368 2,296 2024 31,933 1,952 2025 33,410 1,435 2026 34,692 1,381 2027-2031 183,671 5,352 Defined Contribution Plan

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2021
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, 2021, there were 828,486 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: 2021 2020 Risk-free interest rate 0.19 % 1.42 % Expected life, in years 3 3 Expected volatility 28.2% to 38.5% 14.9% to 19.7% Dividend yield 4.3 % 3.1 % The risk-free interest rate was based on the U.S. Treasury yield of a three-year bond at the time of grant. The expected term of the performance shares is three years based on the performance cycle. Expected volatility was based on the historical volatility for the peer group. Both performance goals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares expected to vest. A summary of nonvested shares as of and changes during the year ended December 31, 2021, are as follows: Performance Unit Awards Shares Weighted-Average Grant-Date Beginning nonvested grants 130,571 $ 66.27 Granted 104,927 50.53 Vested (69,867) 60.41 Forfeited (3,108) 59.14 Remaining nonvested grants 162,523 $ 58.76 We recognized compensation expense of $3.9 million, $2.2 million, and $6.5 million for the years ended December 31, 2021, 2020, and 2019, respectively, and related income tax (benefit) expense of $(0.2) million, $(0.6) million, and $0.2 million for the years ended December 31, 2021, 2020, and 2019, respectively. As of December 31, 2021, we had $5.7 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 $4.2 million, $5.1 million, and $4.2 million for the years ended December 31, 2021, 2020 and 2019, 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, 2021, are as follows: Shares Weighted-Average Grant-Date Beginning nonvested grants 77,967 $ 50.86 Granted 24,385 43.29 Vested (15,033) 45.78 Forfeited — — Remaining nonvested grants 87,319 $ 49.63 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, 2021 2020 2019 DSUs Issued 18,741 21,434 19,027 Compensation expense $ 1.1 $ 1.5 $ 1.3 Change in value of shares 1.3 (2.9) 2.4 Total compensation (benefit) expense $ 2.4 $ (1.4) $ 3.7 DSUs withdrawn 186,137 613 3,708 Value of DSUs withdrawn $ 12.1 $ 0.1 $ 0.3

Common Stock

Common Stock	12 Months Ended
	Dec. 31, 2021
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 16,880 and 35,378 during the years ended December 31, 2021 and 2020, respectively, and are reflected in treasury stock. These shares were credited to treasury stock based on their fair market value on the vesting date. Issuance of Common Stock In April 2021, we entered into an Equity Distribution Agreement with BofA Securities, Inc., CIBC World Markets Corp, Credit Suisse Securities (USA) LLC, and J.P. Morgan Securities LLC, collectively the sales agents, pursuant to which we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $200.0 million, through an At-the-Market (ATM) offering program, including an equity forward sales component. This is a three-year agreement, expiring on February 11, 2024. During the twelve months ended December 31, 2021, we issued 1,966,117 shares of our common stock under the ATM program at an average price of $63.81, for net proceeds of $124.2 million, which is net of sales commissions and other fees paid of approximately $1.3 million. We do not anticipate needing to issue equity through the ATM program during 2022. On November 17, 2021, we announced a registered public offering of 6,074,767 shares of our common stock at a public offering price of $53.50 per share, for an issuance amount of $325.0 million. In conjunction with this offering, we granted the underwriters an option to purchase up to 911,215 additional shares, which was subsequently exercised in full, for an additional issuance amount of $48.8 million. Of the total 6,985,982 shares of common stock offered, we initially sold 1,401,869 shares, $75.0 million in gross proceeds, directly to the underwriters in the offering, with cash proceeds received at closing. The remaining 5,584,113 shares were sold under forward sales agreements which provide for settlement on a settlement date or dates to be specified at our discretion, but which is expected to occur on or prior to February 28, 2023. The cumulative shares issued under the forward sales agreement is limited to one and one-half times the base number of shares within the agreement, or 8,376,170 shares. The forward sales agreements will be physically settled with common shares issued by us, unless we elect to settle the agreements in cash or to net share settle the agreements, subject to certain conditions. On a settlement date or dates, if we decide to physically settle the forward sales agreement, we will issue shares of common stock to the forward purchaser at the then-applicable forward sale price and receive issuance proceeds at that time. The forward sale price will initially be $51.8950 per share, which is subject to adjustment based on a floating interest rate factor equal to the overnight bank funding rate less a spread of 75 basis points, and will be subject to decrease on certain dates specified in the forward sale agreement by amounts related to expected dividends on shares of common stock during the term of the forward sale agreement. At December 31, 2021, we could have settled the forward sale agreement with physical delivery of 5,584,113 shares of common stock to the counterparty in exchange for cash of $286.1 million. The forward sale could have also been settled at December 31, 2021, with delivery of approximately $24.2 million of cash or approximately 435,522 shares of common stock to the counterparty, if we had elected to net cash or net share settle, respectfully. The forward sale agreement has been classified as an equity transaction because it is indexed to our common stock, physical settlement is within our control, and the other requirements necessary for equity classification are met. As a result of the equity classification, no gain or loss will be recognized within earnings due to subsequent changes in the fair value of the forward sales agreement. If the average price of our common stock exceeds the adjusted forward sales price during a quarterly period, the forward sales agreement could have a dilutive effect on earnings per share.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 2019 Basic computation 51,709,229 50,559,208 50,428,560 Dilutive effect of Performance and restricted share awards (1) 111,940 145,181 323,298 Forward equity sale 51,057 — — Diluted computation 51,872,226 50,704,389 50,751,858 _____________________ (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, 2021, there were 77,856 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, 2021
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 $64 to $136 per MWH through 2029. As of December 31, 2021, our estimated gross contractual obligation related to these contracts was approximately $466.9 million through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $388.4 million through 2029. As contractual obligations are settled, the related purchases and sales are recorded within Fuel, purchased power and direct transmission expense 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, 2021 2020 Beginning QF liability $ 81,379 $ 92,937 Settlements (1) (22,497) (18,665) Interest expense 6,061 7,107 Ending QF liability $ 64,943 $ 81,379 ___________________ (1) The settlements amount includes (i) a higher periodic adjustment of $4.3 million due to actual price escalation, which was more than previously modeled; (ii) lower costs of approximately $1.7 million, due to a $2.6 million reduction in costs for the adjustment to actual output and pricing for the current contract year as compared with a $0.9 million reduction in costs in the prior period; and (iii) a favorable adjustment of approximately $7.0 million decreasing the QF liability associated with a one-time clarification in contract term. The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands): Gross Recoverable Net 2022 $ 80,355 $ 60,639 $ 19,716 2023 82,452 61,280 21,172 2024 75,113 60,706 14,407 2025 60,360 52,950 7,410 2026 55,393 46,274 9,119 Thereafter 113,199 106,563 6,636 Total (1) $ 466,872 $ 388,412 $ 78,460 _____________________ (1) This net unrecoverable amount represents the undiscounted difference between the total gross obligations and recoverable amounts. The ending QF liability in the table above represents the present value of this net unrecoverable amount. 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 Fuel, purchased power and direct transmission expense in the Consolidated Statements of Income and were approximately $286.7 million, $206.6 million and $222.5 million for the years ended December 31, 2021, 2020, and 2019, respectively. As of December 31, 2021, our commitments under these contracts were $283.2 million in 2022, $269.7 million in 2023, $221.8 million in 2024, $219.4 million in 2025, $172.2 million in 2026, and $1.5 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 $26.7 million between 2022 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 or for which we are responsible, is estimated to range between $24.1 million to $30.7 million. As of December 31, 2021, we had a reserve of approximately $26.9 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. 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. The following summarizes the change in our environmental liability (in thousands): December 31, 2021 2020 2019 Liability at January 1, $ 28,895 $ 30,276 $ 29,741 Deductions (2,799) (2,977) (2,232) Charged to costs and expense 770 1,596 2,767 Liability at December 31, $ 26,866 $ 28,895 $ 30,276 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 $22.1 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 Agriculture and Natural Resources, and conducting ongoing monitoring and operation and maintenance activities. As of December 31, 2021, the reserve for remediation costs at this site was approximately $8.1 million, and we estimate that approximately $3.0 million of this amount will be incurred through 2025. 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 Montana Department of Environmental Quality (MDEQ) voluntary remediation program for cleanup due to soil and groundwater impacts. Soil and coal tar were removed at the sites in accordance with the MDEQ requirements. Groundwater monitoring is conducted semiannually at both sites. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remedial actions and/or investigations, if any, at the Butte site. In August 2016, the MDEQ sent us a Notice of Potential Liability and Request for Remedial Action regarding the Helena site. In 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 we expect work at the Helena site to continue into 2022. 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 has assumed the lead role at the site and has submitted a voluntary remediation plan for the Missoula site to MDEQ. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, if any, at the Missoula site. Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of greenhouse gas (GHG) including, most significantly, carbon dioxide (CO2). These actions include legislative proposals, Executive and Environmental Protection Agency (EPA) actions at the federal level, state level activity, 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 regarding GHG emissions from coal fired plants, 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. The United States Supreme Court agreed to review the case in October 2021 and oral argument regarding the scope of EPA’s authority to regulate GHG emissions is scheduled to take place February 28, 2022, with a decision expected the following summer. It also is widely expected that the Biden Administration will develop an alternative plan for reducing GHG emissions from coal-fired plants, and in a memorandum dated February 12, 2021, EPA stated its belief that the January 19, 2021 opinion left neither the ACE nor the CPP rules in place. We cannot predict whether or how GHG emission regulations will be applied to our plants, including any actions taken by the relevant state authorities. In addition, it is unclear how pending or future 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. 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. The states of Montana, North Dakota and South Dakota are expected to develop and submit to EPA, for its approval, their respective State Implementation Plans (SIP) for Regional Haze compliance. While these states, among others, did not meet the EPA’s July 31, 2021 submission deadline, we still expect each state to submit its SIP in 2022. The draft Montana SIP does not require any additional controls at Colstrip Units 3 and 4. The draft North Dakota SIP does not require any additional controls at the Coyote generating facility, however the EPA, following a preliminary review, has asked North Dakota to reassess its determination regarding Coyote. The draft South Dakota SIP does not require any additional controls at the Big Stone generating facility. Until these SIPs are submitted and approved by EPA, the potential remains that installation of additional emissions controls might be required at these 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. 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, we entered into a non-monetary, partial settlement with PNWS in which 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 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. On August 31, 2021, the Court ruled that the four agreements are valid and enforceable contracts and that NorthWestern breached the agreements on June 16, 2016 by refusing to go forward with the projects in spite of the MPSC's Orders. On December 15, 2021, after a three-day trial, the jury determined that PNWS had sustained $0.4 million in damages and the judge subsequently entered judgment against us in that amount. We filed a post-trial motion on January 13, 2022 seeking to have the judgement set aside. On February 9, 2022, the judge denied our post-trial motion. We have 30 days from February 9, 2022 to appeal the judgement to the Ninth Circuit Court of Appeals if we decide to do so. The plaintiff did not seek any post-trial relief and the deadline for doing so has passed. 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, and formerly Talen’s, 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. A bench trial before the Federal District Court commenced January 4, 2022 and concluded on January 18, 2022. This bench trial addressed the issue of navigability of the segments at issue. The parties must submit amended findings of fact and conclusions of law, along with post-trial briefing, by April 29, 2022. A decision on navigability is expected following such submissions. Damages were bifurcated by agreement and will be tried separately, should the Federal District Court find any segments navigable. 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. Colstrip Arbitration and Litigation As part of the settlement of litigation brought by the Sierra Club and the Montana Environmental Information Center against the owners and operator of Colstrip, the owners of Units 1 and 2 agreed to shut down those units no later than July 2022. In January 2020, the owners of Units 1 and 2 closed those two units. We do not have ownership in Units 1 and 2, and decisions regarding those units, including their shut down, were made by their respective owners. The six owners of Units 3 and 4 currently share the operating costs pursuant to the terms of an operating agreement among them, the Ownership and Operation Agreement (O&O Agreement). Costs of common facilities were historically shared among the owners of all four units. With the closure of Units 1 and 2, we have incurred additional operating costs with respect to our interest in Unit 4 and expect to experience a negative impact on our transmission revenue due to reduced amounts of energy transmitted across our transmission lines. We expect to incorporate any reduction in revenue in our next general electric rate filing, resulting in lower revenue credits to certain customers. The remaining depreciable life of our investment in Colstrip Unit 4 is through 2042. Recovery of costs associated with the closure of the facility is subject to MPSC approval. Three of the joint owners of Units 3 and 4 are subject to regulation in Washington and in May 2019, the Washington state legislature enacted a statute mandating Washington electric utilities to “eliminate coal-fired resources from [their] allocation of electricity” on or before December 31, 2025, after which date they may no longer include their share of coal-fired resources in their regulated electric supply portfolio. As a result of the Washington legislation, four of the six joint owners of Units 3 and 4 requested the operator prepare a 2021 budget reflecting closure of Units 3 and 4 by 2025, and alternately a closure of Unit 3 by 2025 and a closure of Unit 4 by 2027. Differing viewpoints on closure dates delayed approval of the 2021 budget, until it was approved on March 22, 2021. Budgeting for 2022 was also delayed, with the same four joint owners demanding substantial budget reductions, but was ultimately approved on January 21, 2022. Such budgeting pressures may result in future budgets that may not be sufficient to maintain the reliability of Units 3 and 4. While we believe closure requires each owner’s consent, there are differences among the owners as to this issue under the O&O Agreement. On March 12, 2021, we initiated an arbitration under the O&O Agreement (the “Arbitration”), which seeks to resolve the primary issue of whether closure of Units 3 and 4 can be accomplished without each joint owner's consent and to clarify the obligations of the joint owners to continue to fund operations until all joint owners agree on closure. The Arbitration has given rise to three lawsuits concerning the number of arbitrators, the venue and the applicable arbitration laws. The four joint owners from the Pacific Northwest assert the Arbitration must be conducted under the O&O Agreement, with one arbitrator, in Spokane County, Washington, and pursuant to the Washington Arbitration Act. The fifth joint owner asserts the Arbitration must be conducted per the terms of Montana Senate Bill 265 (SB 265), which requires the Arbitration be conducted, with three arbitrators, in Montana and pursuant to the Montana Uniform Arbitration Act. The three initiated lawsuits do not make direct financial demands, and instead, are intended to address issues related to process for the Arbitration. Since the Arbitration was initiated, and despite the litigation, we have worked and continue to work with the other joint owners to arrive at an agreed upon process for the Arbitration. Colstrip Coal Dust Litigation On December 14, 2020, a claim was filed against Talen Montana, LLC, the operator of the Colstrip Steam Plant, in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. The plaintiffs allege they have suffered adverse effects from coal dust generated during operations associated with the Colstrip Steam Plant. On August 26, 2021, the claim was amended to add in excess of 100 plaintiffs. It also added NorthWestern, as well as the other owners of the Colstrip Steam Plant, and Westmoreland Rosebud Mining LLC, as defendants. Plaintiffs are seeking economic damages, costs and disbursements, punitive damages, attorneys’ fees, and an injunction prohibiting defendants from allowing coal dust to blow onto plaintiffs’ properties. Since this lawsuit is in its early stages, we are unable to predict outcomes or estimate a range of reasonably possible losses. 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, 2021
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 for the twelve months ended by major source and customer class (in millions): December 31, 2021 Electric Natural Gas Total Montana 334.6 126.0 460.6 South Dakota 65.4 26.6 92.0 Nebraska — 21.0 21.0 Residential 400.0 173.6 573.6 Montana 356.7 64.7 421.4 South Dakota 102.5 19.1 121.6 Nebraska — 11.4 11.4 Commercial 459.2 95.2 554.4 Industrial 37.9 1.1 39.0 Lighting, Governmental, Irrigation, and Interdepartmental 32.1 1.4 33.5 Total Customer Revenues 929.2 271.3 1,200.5 Other Tariff and Contract Based Revenues 89.5 36.8 126.3 Total Revenue from Contracts with Customers 1,018.7 308.1 1,326.8 Regulatory amortization 33.5 12.0 45.5 Total Revenues $ 1,052.2 $ 320.1 $ 1,372.3 December 31, 2020 Electric Natural Gas Total Montana 320.8 103.5 424.3 South Dakota 66.6 21.5 88.1 Nebraska — 16.9 16.9 Residential 387.4 141.9 529.3 Montana 338.3 51.3 389.6 South Dakota 101.1 14.3 115.4 Nebraska — 8.1 8.1 Commercial 439.4 73.7 513.1 Industrial 36.8 0.9 37.7 Lighting, Governmental, Irrigation, and Interdepartmental 31.8 0.9 32.7 Total Customer Revenues 895.4 217.4 1,112.8 Other Tariff and Contract Based Revenues 58.5 35.5 94.0 Total Revenue from Contracts with Customers 953.9 252.9 1,206.8 Regulatory amortization (13.1) 5.0 (8.1) Total Revenues $ 940.8 $ 257.9 $ 1,198.7 December 31, 2019 Electric Natural Gas Total Montana 308.8 109.4 418.2 South Dakota 62.5 25.8 88.3 Nebraska — 20.2 20.2 Residential 371.3 155.4 526.7 Montana 348.1 55.7 403.8 South Dakota 97.1 19.3 116.4 Nebraska — 10.5 10.5 Commercial 445.2 85.5 530.7 Industrial 43.6 1.0 44.6 Lighting, Governmental, Irrigation, and Interdepartmental 30.6 1.0 31.6 Total Customer Revenues 890.7 242.9 1,133.6 Other Tariff and Contract Based Revenues 61.7 35.8 97.5 Total Revenue from Contracts with Customers 952.4 278.7 1,231.1 Regulatory amortization 28.8 (2.0) 26.8 Total Revenues $ 981.2 $ 276.7 $ 1,257.9

Segment and Related Information

Segment and Related Information	12 Months Ended
	Dec. 31, 2021
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 utility 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, 2021 Electric Gas Other Eliminations Total Operating revenues $ 1,052,182 $ 320,134 $ — $ — $ 1,372,316 Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 294,820 130,728 — — 425,548 Utility Margin 757,362 189,406 — — 946,768 Operating and maintenance 156,383 51,920 — — 208,303 Administrative and general 72,641 27,550 1,682 — 101,873 Property and other taxes 134,910 38,526 8 — 173,444 Depreciation and depletion 154,626 32,841 — — 187,467 Operating income (loss) 238,802 38,569 (1,690) — 275,681 Interest expense, net (82,678) (6,083) (4,913) — (93,674) Other income, net 3,676 3,046 1,530 — 8,252 Income tax (expense) benefit (2,512) (2,640) 1,733 — (3,419) Net income (loss) $ 157,288 $ 32,892 $ (3,340) $ — $ 186,840 Total assets $ 5,432,578 $ 1,342,031 $ 5,834 $ — $ 6,780,443 Capital expenditures $ 354,775 $ 79,553 $ — $ — $ 434,328 December 31, 2020 Electric Gas Other Eliminations Total Operating revenues $ 940,815 $ 257,855 $ — $ — $ 1,198,670 Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 236,581 69,609 — — 306,190 Utility margin 704,234 188,246 — — 892,480 Operating and maintenance 149,220 53,771 — — 202,991 Administrative and general 69,602 26,311 (1,789) — 94,124 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 (1) $ 5,126,589 $ 1,251,240 $ 11,620 $ — $ 6,389,449 Capital expenditures $ 324,369 $ 81,393 $ — $ — $ 405,762 ___________________________ (1) Subsequent to the issuance of our Annual Report on Form 10-K for the year ended December 31, 2020, we determined that Total Assets - Electric and Total Assets - Gas had been incorrectly reported due to an error in the allocation methodology utilized to calculate assets by segment. As a result, the December 31, 2020 Total Assets - Electric and Total Assets - Gas amounts have been corrected from the amounts previously reported to reflect an increase of Total Assets - Electric and a decrease of Total Assets - Gas of $488.3 million. The correction had no impact on net income or the presentation of total assets on the consolidated balance sheets and was determined not to be material. December 31, 2019 Electric Gas Other Eliminations Total Operating revenues $ 981,178 $ 276,732 $ — $ — $ 1,257,910 Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 239,589 78,431 — — 318,020 Utility margin 741,589 198,301 — — 939,890 Operating and maintenance 155,285 53,767 — — 209,052 Administrative and general 77,139 28,965 3,073 — 109,177 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

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 Operating revenues $ 347,341 $ 313,445 Operating income 79,990 66,496 Net income $ 51,336 $ 53,551 Average common shares outstanding 53,293 50,583 Income per average common share: Basic $ 0.96 $ 1.06 Diluted $ 0.96 $ 1.06

Nature of Operations and Basi_2

Nature of Operations and Basis of Consolidation (Policies)	12 Months Ended
	Dec. 31, 2021
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 2021, we renamed the line item "Cost of sales" as previously shown on the Consolidated Statements of Income, and used elsewhere within our filing, to "Fuel, purchased supply and direct transmission expense." Additionally, we disaggregated the line item "Operating, general and administrative" as previously shown on the Consolidated Statements of Income, and used elsewhere within our filing, to two line items, "Operating and maintenance" and "Administrative and general." These reclassifications were done in an effort to better convey the nature of these costs.

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
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,
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 $2.3 million and $5.6 million at December 31, 2021 and December 31, 2020. Receivables include unbilled revenues of $98.1 million and $80.5 million at December 31, 2021 and December 31, 2020, 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 6.6%, 6.7%, and 6.9% for Montana for 2021, 2020, and 2019, respectively. This rate averaged 6.4%, 6.7%, and 6.6% for South Dakota for 2021, 2020, and 2019, respectively. AFUDC capitalized totaled $15.9 million, $9.8 million, and $8.2 million for the years ended December 31, 2021, 2020, and 2019, 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% for 2021, 2020, and 2019. 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 from these estimates. The resolution of tax matters in a particular future period could have a material impact on our Consolidated Income Statements and provision for income taxes.
Environmental Costs	Environmental Costs We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset if there is precedent for recovering similar costs from customers in rates. Otherwise, we expense the costs. If an environmental cost is related to facilities we currently use, such as pollution control equipment, then we may capitalize and depreciate the costs over the remaining life of the asset, assuming the costs are recoverable in future rates or future cash flows.

Revenue from Contracts with C_2

Revenue from Contracts with Customers Accounting Policy (Policies)	12 Months Ended
	Dec. 31, 2021
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, 2021
Accounting Policies [Abstract]
Inventories	Inventories Inventories are stated at average cost. Inventory consisted of the following (in thousands): December 31, 2021 2020 Materials and supplies $ 54,137 $ 44,311 Storage gas and fuel 26,477 16,699 Total Inventories $ 80,614 $ 61,010
Schedule of Accrued Liabilities	Accrued Expenses Accrued expenses consisted of the following (in thousands): December 31, 2021 2020 Property taxes $ 86,168 $ 89,425 Employee compensation, benefits, and withholdings 44,743 40,538 Customer advances 29,013 16,015 Interest 18,568 18,074 Other (none of which is individually significant) 54,859 43,462 Total Accrued Expenses $ 233,351 $ 207,514
Other Noncurrent Liabilities	Other Noncurrent Liabilities Other noncurrent liabilities consisted of the following (in thousands): December 31, 2021 2020 Pension and other employee benefits $ 96,151 $ 136,632 Customer advances 80,780 65,186 Future QF obligation, net 64,943 81,379 Asset retirement obligations 38,350 45,355 Environmental 23,395 25,049 Other (none of which is individually significant) 65,700 57,102 Total Noncurrent Liabilities $ 369,319 $ 410,703
Supplemental Cash Flow Information	Supplemental Cash Flow Information Year Ended December 31, 2021 2020 2019 (in thousands) Cash paid (received) for: Income taxes $ 4,330 $ 115 $ (6,737) Interest 87,221 84,922 83,776 Significant non-cash transactions: Capital expenditures included in trade accounts payable 29,034 21,430 33,473 NMTC debt extinguishment included in other noncurrent assets (1) 18,169 — — NMTC debt extinguishment included in property, plant and equipment, net (1) 6,594 — — NMTC debt extinguishment included in long-term debt (1) 1,259 — —
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, 2021 2020 2019 Cash and cash equivalents $ 2,820 $ 5,811 $ 5,145 Restricted cash 15,942 11,285 6,925 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 18,762 $ 17,096 $ 12,070

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2021
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets And Liabilities	Note Reference Remaining Amortization Period December 31, 2021 2020 (in thousands) Flow-through income taxes 12 Plant Lives $ 464,663 $ 420,925 Excess deferred income taxes 12 Plant Lives 60,813 67,256 Pension 14 See Note 14 98,336 138,567 Deferred financing costs Various 25,636 28,350 Employee related benefits 14 Various 21,648 22,516 Supply costs 18 months 88,329 8,116 State & local taxes & fees Various 6,520 17,910 Environmental clean-up 18 Various 11,262 11,127 Other Various 29,020 31,650 Total Regulatory Assets $ 806,227 $ 746,417 Removal cost 6 Various $ 479,294 $ 464,669 Excess deferred income taxes 12 Plant Lives 158,047 165,279 Supply costs 1 Year 16,430 13,847 Gas storage sales 18 years 7,466 7,887 Rates subject to refund 1 Year 1,971 32,496 State & local taxes & fees 1 Year 3,021 1,783 Environmental clean-up Various 508 656 Other Various 202 655 Total Regulatory Liabilities $ 666,939 $ 687,272

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 (years) (in thousands) Transmission, distribution, and storage 15 – 95 $ 4,004,819 $ 3,771,023 Generation 23 – 72 1,287,517 1,252,805 Plant acquisition adjustment (1) 25 – 50 686,328 686,328 Building and improvements 23 – 73 296,955 303,099 Land, land rights and easements 53 – 96 161,585 157,379 Other 2 – 45 585,448 571,981 Construction work in process –— 294,617 173,492 Total property, plant and equipment 7,317,269 6,916,107 Less accumulated depreciation (1,787,550) (1,703,016) Less accumulated amortization (282,487) (260,156) Net property, plant and equipment $ 5,247,232 $ 4,952,935
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, 2021 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 154,375 $ 62,865 $ 51,652 $ 324,433 Accumulated depreciation 42,102 34,629 38,453 113,805 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

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 2019 Liability at January 1, $ 45,355 $ 42,449 $ 40,659 Accretion expense 2,233 2,070 2,051 Liabilities incurred — — — Liabilities settled (2,906) (4,061) (46) Revisions to cash flows (4,051) 4,897 (215) Liability at December 31, $ 40,631 $ 45,355 $ 42,449

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	Goodwill by segment is as follows (in thousands): December 31, 2021 2020 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, 2021
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, 2021 Interest rate contracts Interest Expense $ 614

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 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 $ 14,967 $ — $ — $ — $ 14,967 Rabbi trust investments 18,234 — — — 18,234 Total $ 33,201 $ — $ — $ — $ 33,201 December 31, 2020 Restricted cash equivalents $ 10,055 $ — $ — $ — $ 10,055 Rabbi trust investments 27,027 — — — 27,027 Total $ 37,082 $ — $ — $ — $ 37,082
Schedule of Estimated Fair Value of Financial Instruments	The estimated fair value of financial instruments is summarized as follows (in thousands): December 31, 2021 December 31, 2020 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 2,541,478 $ 2,827,336 $ 2,315,261 $ 2,629,755

Short-Term Borrowings and Cre_2

Short-Term Borrowings and Credit Arrangements (Tables)	12 Months Ended
	Dec. 31, 2021
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): 2021 2020 Unsecured revolving line of credit, expiring September 2023 $ 425.0 $ 425.0 Unsecured revolving line of credit, expiring March 2023 25.0 25.0 450.0 450.0 Amounts outstanding at December 31: Eurodollar borrowings 373.0 222.0 Letters of credit — — 373.0 222.0 Net availability as of December 31 $ 77.0 $ 228.0

Long-Term Debt and Capital Le_2

Long-Term Debt and Capital Leases (Tables)	12 Months Ended
	Dec. 31, 2021
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 2021 2020 Unsecured Debt: Unsecured Revolving Line of Credit 2023 $ 373,000 $ 222,000 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 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 100,000 100,000 Montana—1.00% 2024 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 Discount on Notes and Bonds and Debt Issuance Costs, Net — (11,182) (13,376) Total Long-Term Debt $ 2,541,478 $ 2,315,261 Finance Leases: Total Finance Leases Various $ 14,772 $ 17,439 Less current maturities (2,875) (2,668) Total Long-Term Finance Leases $ 11,897 $ 14,771

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Schedule Of Income Tax Expense Domestic	Income tax expense (benefit) is comprised of the following (in thousands): Year Ended December 31, 2021 2020 2019 Federal Current $ 722 $ (3,396) $ (6,076) Deferred 2,626 (4,006) (15,169) Investment tax credits (130) (3) (12) State Current 2,172 3 27 Deferred (1,971) (3,568) 1,305 Income Tax Expense (Benefit) $ 3,419 $ (10,970) $ (19,925)
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, 2021 2020 2019 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax, net of federal provisions 0.1 (1.1) 0.7 Flow-through repairs deductions (11.5) (16.5) (10.8) Production tax credits (6.1) (9.1) (6.3) Plant and depreciation of flow through items (0.6) 0.1 (2.2) Amortization of excess DIT (0.3) (0.7) (0.9) Recognition of unrecognized tax benefit — — (12.5) Impact of Tax Cuts and Jobs Act — — (0.1) Prior year permanent return to accrual adjustments 0.0 (1.2) 0.3 Other, net (0.8) (0.1) (0.1) Effective tax rate 1.8 % (7.6) % (10.9) % The table below summarizes the significant differences in income tax expense (benefit) based on the differences between our effective tax rate and the federal statutory rate (in thousands). Year Ended December 31, 2021 2020 2019 Income Before Income Taxes $ 190,259 $ 144,245 $ 182,195 Income tax calculated at federal statutory rate 39,954 30,292 38,261 Permanent or flow through adjustments: State income, net of federal provisions 354 (1,477) 1,251 Flow-through repairs deductions (21,888) (23,828) (19,706) Production tax credits (11,532) (13,103) (11,483) Plant and depreciation of flow through items (941) 121 (3,952) Amortization of excess DIT (635) (968) (1,688) Prior year permanent return to accrual adjustments (12) (1,728) 559 Recognition of unrecognized tax benefit — — (22,825) Impact of Tax Cuts and Jobs Act — — (198) Other, net (1,881) (279) (144) (36,535) (41,262) (58,186) Income Tax Expense (Benefit) $ 3,419 $ (10,970) $ (19,925)
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, 2021 2020 Production tax credit $ 75,092 $ 63,542 Pension / postretirement benefits 21,435 31,866 Customer advances 21,271 17,165 Unbilled revenue 10,704 14,429 Compensation accruals 10,612 11,748 Reserves and accruals 5,106 6,266 Environmental liability 5,704 6,039 Interest rate hedges 3,158 3,171 NOL carryforward — 393 Other, net 1,738 2,490 Deferred Tax Asset 154,820 157,109 Excess tax depreciation (425,202) (412,774) Goodwill amortization (85,425) (83,991) Flow through depreciation (94,616) (83,545) Regulatory assets and other (49,211) (48,576) Deferred Tax Liability (654,454) (628,886) Deferred Tax Liability, net $ (499,634) $ (471,777)
Summary of Income Tax Contingencies	The change in unrecognized tax benefits is as follows (in thousands): 2021 2020 2019 Unrecognized Tax Benefits at January 1 $ 33,491 $ 35,085 $ 56,150 Gross increases - tax positions in prior period 293 120 539 Gross increases - tax positions in current period — — — Gross decreases - tax positions in current period (1,735) (1,714) (1,489) Lapse of statute of limitations — — (20,115) Unrecognized Tax Benefits at December 31 $ 32,049 $ 33,491 $ 35,085

Comprehensive Income (Loss) (Ta

Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 2019 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 $ (57) $ — $ (57) $ 87 $ — $ 87 $ (35) $ — $ (35) Reclassification of net income (loss) on derivative instruments 614 (162) 452 614 (162) 452 614 (162) 452 Postretirement medical liability adjustment (585) 149 (436) 2,463 (623) 1,840 (175) 44 (131) Other comprehensive (loss) income $ (28) $ (13) $ (41) $ 3,164 $ (785) $ 2,379 $ 404 $ (118) $ 286
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, 2021 2020 Foreign currency translation $ 1,443 $ 1,500 Derivative instruments designated as cash flow hedges (10,277) (10,729) Postretirement medical plans 1,524 1,960 Accumulated other comprehensive loss $ (7,310) $ (7,269)
Schedule of Accumulated Comprehensive Income (Loss)	The following table displays the changes in AOCL by component, net of tax (in thousands): December 31, 2021 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (10,729) $ 1,960 $ 1,500 $ (7,269) Other comprehensive loss before reclassifications — — (57) (57) Amounts reclassified from AOCL Interest Expense 452 — — 452 Amounts reclassified from AOCL — (436) — (436) Net current-period other comprehensive income (loss) 452 (436) (57) (41) Ending Balance $ (10,277) $ 1,524 $ 1,443 $ (7,310) 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)

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 2021 2020 Change in benefit obligation: Obligation at beginning of period $ 820,979 $ 735,564 $ 19,146 $ 20,272 Service cost 12,994 11,116 407 370 Interest cost 18,759 22,840 317 492 Actuarial loss (28,905) 84,479 415 123 Settlements (1) (93,488) — — 390 Benefits paid (33,537) (33,020) (2,977) (2,501) Benefit Obligation at End of Period $ 696,802 $ 820,979 $ 17,308 $ 19,146 Change in Fair Value of Plan Assets: Fair value of plan assets at beginning of period $ 688,456 $ 609,000 $ 23,096 $ 21,479 Return on plan assets 33,868 101,075 3,349 2,723 Employer contributions 10,200 11,401 1,821 1,395 Settlements (1) (93,488) — — — Benefits paid (33,537) (33,020) (2,977) (2,501) Fair value of plan assets at end of period $ 605,499 $ 688,456 $ 25,289 $ 23,096 Funded Status $ (91,303) $ (132,523) $ 7,981 $ 3,950 Amounts Recognized in the Balance Sheet Consist of: Noncurrent asset 8,297 7,001 11,914 8,436 Total Assets 8,297 7,001 11,914 8,436 Current liability (11,200) (11,200) (1,575) (1,712) Noncurrent liability (88,400) (128,324) (2,358) (2,774) Total Liabilities (99,600) (139,524) (3,933) (4,486) Net amount recognized $ (91,303) $ (132,523) $ 7,981 $ 3,950 Amounts Recognized in Regulatory Assets Consist of: Prior service credit — — 1,870 3,857 Net actuarial loss (62,448) (115,987) 1,366 (497) Amounts recognized in AOCL consist of: Prior service cost — — (95) (246) Net actuarial gain — — 2,500 3,246 Total $ (62,448) $ (115,987) $ 5,641 $ 6,360 (1) In December 2021, we entered into a group annuity contract from an insurance company to provide for the payment of pension benefits to 1,062 NorthWestern Energy Pension Plan participants. We purchased the contract with $93.5 million of plan assets. The insurance company took over the payments of these benefits starting January 1, 2022. This transaction settled $93.5 million of our NorthWestern Energy Pension Plan obligation. As a result of this transaction, during the twelve months ended December 31, 2021, we recorded a non-cash, non-operating settlement charge of $11.3 million. This charge is recorded within other income, net on the Consolidated Statements of Income. As discussed within Note 4 – Regulatory Assets and Liabilities, this charge was deferred as a regulatory asset on the Consolidated Balance Sheets, with a corresponding decrease to operating and maintenance expense on the Consolidated Statements of Income.
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, 2021 2020 Projected benefit obligation $ 636.3 $ 757.4 Accumulated benefit obligation 636.3 757.4 Fair value of plan assets (1) 537.9 619.1 ____________________ As of December 31, 2021, 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.
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, 2021 2020 2019 2021 2020 2019 Components of Net Periodic Benefit Cost Service cost $ 12,994 $ 11,116 $ 9,637 $ 407 $ 370 $ 331 Interest cost 18,759 22,840 26,488 327 492 609 Expected return on plan assets (27,061) (26,162) (25,443) (919) (983) (869) Amortization of prior service cost (credit) — — — (1,835) (1,882) (1,882) Recognized actuarial loss (gain) 6,536 5,028 6,544 (898) (61) (96) Settlement loss recognized (1) 11,291 — 198 — 390 390 Net Periodic Benefit Cost (Credit) $ 22,519 $ 12,822 $ 17,424 $ (2,918) $ (1,674) $ (1,517) Regulatory deferral of net periodic benefit cost (2) (13,308) (2,100) (7,510) — — — Previously deferred costs recognized (2) — 71 728 709 861 931 Amount Recognized in Income $ 9,211 $ 10,793 $ 10,642 $ (2,209) $ (813) $ (586) Income Statement Presentation Operating and maintenance (313) 9,016 2,125 407 370 331 Other income (expense), net 9,524 1,777 8,517 (2,616) (1,183) (917) Amount Recognized in Income $ 9,211 $ 10,793 $ 10,642 $ (2,209) $ (813) $ (586) ___________________________ (1) Settlement loss is related to partial annuitization of NorthWestern Energy Pension Plan effective December 1, 2021. (2) 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, 2021 2020 2019 2021 2020 2019 Discount rate 2.65-2.75 % 2.20-2.30 % 3.10-3.20 % 2.35-2.40 % 1.80 % 2.80 % Expected rate of return on assets 3.01-4.17 3.45-4.49 4.23-5.06 4.08 4.71 4.79 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 2.00 2.00 2.00 2.00 Interest crediting rate 3.30-6.00 3.30-6.00 3.60-6.00 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, 2021 2020 2021 2020 2021 2020 Fixed income securities 55.0 % 55.0 % 90.0 % 80.0 % 40.0 % 40.0 % Non-U.S. fixed income securities 4.0 4.0 1.0 2.0 — — Global equities 41.0 41.0 9.0 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, 2021 2020 2021 2020 2021 2020 Cash and cash equivalents 0.1 % — % 0.4 % 0.7 % 0.1 % 1.0 % Fixed income securities 53.8 52.7 89.5 77.3 33.7 37.9 Non-U.S. fixed income securities 3.9 3.8 0.9 2.6 — — Global equities 42.2 43.5 9.2 19.4 66.2 61.1 100.0 % 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): 2021 2020 2019 NorthWestern Energy Pension Plan (MT) $ 9,000 $ 10,201 $ 9,000 NorthWestern Corporation Pension Plan (SD and NE) 1,200 1,200 1,200 $ 10,200 $ 11,401 $ 10,200
Schedule of Expected Benefit Payments	We estimate the plans will make future benefit payments to participants as follows (in thousands): Pension Benefits Other Postretirement Benefits 2022 $ 28,842 $ 2,579 2023 30,368 2,296 2024 31,933 1,952 2025 33,410 1,435 2026 34,692 1,381 2027-2031 183,671 5,352

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2021
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: 2021 2020 Risk-free interest rate 0.19 % 1.42 % Expected life, in years 3 3 Expected volatility 28.2% to 38.5% 14.9% to 19.7% Dividend yield 4.3 % 3.1 %
Schedule of Nonvested Share Activity	A summary of nonvested shares as of and changes during the year ended December 31, 2021, are as follows: Performance Unit Awards Shares Weighted-Average Grant-Date Beginning nonvested grants 130,571 $ 66.27 Granted 104,927 50.53 Vested (69,867) 60.41 Forfeited (3,108) 59.14 Remaining nonvested grants 162,523 $ 58.76
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, 2021, are as follows: Shares Weighted-Average Grant-Date Beginning nonvested grants 77,967 $ 50.86 Granted 24,385 43.29 Vested (15,033) 45.78 Forfeited — — Remaining nonvested grants 87,319 $ 49.63
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, 2021 2020 2019 DSUs Issued 18,741 21,434 19,027 Compensation expense $ 1.1 $ 1.5 $ 1.3 Change in value of shares 1.3 (2.9) 2.4 Total compensation (benefit) expense $ 2.4 $ (1.4) $ 3.7 DSUs withdrawn 186,137 613 3,708 Value of DSUs withdrawn $ 12.1 $ 0.1 $ 0.3

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 2019 Basic computation 51,709,229 50,559,208 50,428,560 Dilutive effect of Performance and restricted share awards (1) 111,940 145,181 323,298 Forward equity sale 51,057 — — Diluted computation 51,872,226 50,704,389 50,751,858 _____________________ (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, 2021, there were 77,856 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, 2021
Commitments and Contingencies Disclosure [Abstract]
Schedule of Changes In Qualifying Facility Liability	The following summarizes the change in the liability (in thousands): December 31, 2021 2020 Beginning QF liability $ 81,379 $ 92,937 Settlements (1) (22,497) (18,665) Interest expense 6,061 7,107 Ending QF liability $ 64,943 $ 81,379 ___________________ (1) The settlements amount includes (i) a higher periodic adjustment of $4.3 million due to actual price escalation, which was more than previously modeled; (ii) lower costs of approximately $1.7 million, due to a $2.6 million reduction in costs for the adjustment to actual output and pricing for the current contract year as compared with a $0.9 million reduction in costs in the prior period; and (iii) a favorable adjustment of approximately $7.0 million decreasing the QF liability associated with a one-time clarification in contract term.
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 2022 $ 80,355 $ 60,639 $ 19,716 2023 82,452 61,280 21,172 2024 75,113 60,706 14,407 2025 60,360 52,950 7,410 2026 55,393 46,274 9,119 Thereafter 113,199 106,563 6,636 Total (1) $ 466,872 $ 388,412 $ 78,460
Schedule of Environmental Loss Contingencies by Site	The following summarizes the change in our environmental liability (in thousands): December 31, 2021 2020 2019 Liability at January 1, $ 28,895 $ 30,276 $ 29,741 Deductions (2,799) (2,977) (2,232) Charged to costs and expense 770 1,596 2,767 Liability at December 31, $ 26,866 $ 28,895 $ 30,276

Revenue from Contracts with C_3

Revenue from Contracts with Customers Disaggregation of Revenue (Tables)	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	The following tables disaggregate our revenue for the twelve months ended by major source and customer class (in millions): December 31, 2021 Electric Natural Gas Total Montana 334.6 126.0 460.6 South Dakota 65.4 26.6 92.0 Nebraska — 21.0 21.0 Residential 400.0 173.6 573.6 Montana 356.7 64.7 421.4 South Dakota 102.5 19.1 121.6 Nebraska — 11.4 11.4 Commercial 459.2 95.2 554.4 Industrial 37.9 1.1 39.0 Lighting, Governmental, Irrigation, and Interdepartmental 32.1 1.4 33.5 Total Customer Revenues 929.2 271.3 1,200.5 Other Tariff and Contract Based Revenues 89.5 36.8 126.3 Total Revenue from Contracts with Customers 1,018.7 308.1 1,326.8 Regulatory amortization 33.5 12.0 45.5 Total Revenues $ 1,052.2 $ 320.1 $ 1,372.3 December 31, 2020 Electric Natural Gas Total Montana 320.8 103.5 424.3 South Dakota 66.6 21.5 88.1 Nebraska — 16.9 16.9 Residential 387.4 141.9 529.3 Montana 338.3 51.3 389.6 South Dakota 101.1 14.3 115.4 Nebraska — 8.1 8.1 Commercial 439.4 73.7 513.1 Industrial 36.8 0.9 37.7 Lighting, Governmental, Irrigation, and Interdepartmental 31.8 0.9 32.7 Total Customer Revenues 895.4 217.4 1,112.8 Other Tariff and Contract Based Revenues 58.5 35.5 94.0 Total Revenue from Contracts with Customers 953.9 252.9 1,206.8 Regulatory amortization (13.1) 5.0 (8.1) Total Revenues $ 940.8 $ 257.9 $ 1,198.7 December 31, 2019 Electric Natural Gas Total Montana 308.8 109.4 418.2 South Dakota 62.5 25.8 88.3 Nebraska — 20.2 20.2 Residential 371.3 155.4 526.7 Montana 348.1 55.7 403.8 South Dakota 97.1 19.3 116.4 Nebraska — 10.5 10.5 Commercial 445.2 85.5 530.7 Industrial 43.6 1.0 44.6 Lighting, Governmental, Irrigation, and Interdepartmental 30.6 1.0 31.6 Total Customer Revenues 890.7 242.9 1,133.6 Other Tariff and Contract Based Revenues 61.7 35.8 97.5 Total Revenue from Contracts with Customers 952.4 278.7 1,231.1 Regulatory amortization 28.8 (2.0) 26.8 Total Revenues $ 981.2 $ 276.7 $ 1,257.9

Segment and Related Informati_2

Segment and Related Information (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 Electric Gas Other Eliminations Total Operating revenues $ 1,052,182 $ 320,134 $ — $ — $ 1,372,316 Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 294,820 130,728 — — 425,548 Utility Margin 757,362 189,406 — — 946,768 Operating and maintenance 156,383 51,920 — — 208,303 Administrative and general 72,641 27,550 1,682 — 101,873 Property and other taxes 134,910 38,526 8 — 173,444 Depreciation and depletion 154,626 32,841 — — 187,467 Operating income (loss) 238,802 38,569 (1,690) — 275,681 Interest expense, net (82,678) (6,083) (4,913) — (93,674) Other income, net 3,676 3,046 1,530 — 8,252 Income tax (expense) benefit (2,512) (2,640) 1,733 — (3,419) Net income (loss) $ 157,288 $ 32,892 $ (3,340) $ — $ 186,840 Total assets $ 5,432,578 $ 1,342,031 $ 5,834 $ — $ 6,780,443 Capital expenditures $ 354,775 $ 79,553 $ — $ — $ 434,328 December 31, 2020 Electric Gas Other Eliminations Total Operating revenues $ 940,815 $ 257,855 $ — $ — $ 1,198,670 Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 236,581 69,609 — — 306,190 Utility margin 704,234 188,246 — — 892,480 Operating and maintenance 149,220 53,771 — — 202,991 Administrative and general 69,602 26,311 (1,789) — 94,124 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 (1) $ 5,126,589 $ 1,251,240 $ 11,620 $ — $ 6,389,449 Capital expenditures $ 324,369 $ 81,393 $ — $ — $ 405,762 ___________________________ (1) Subsequent to the issuance of our Annual Report on Form 10-K for the year ended December 31, 2020, we determined that Total Assets - Electric and Total Assets - Gas had been incorrectly reported due to an error in the allocation methodology utilized to calculate assets by segment. As a result, the December 31, 2020 Total Assets - Electric and Total Assets - Gas amounts have been corrected from the amounts previously reported to reflect an increase of Total Assets - Electric and a decrease of Total Assets - Gas of $488.3 million. The correction had no impact on net income or the presentation of total assets on the consolidated balance sheets and was determined not to be material. December 31, 2019 Electric Gas Other Eliminations Total Operating revenues $ 981,178 $ 276,732 $ — $ — $ 1,257,910 Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 239,589 78,431 — — 318,020 Utility margin 741,589 198,301 — — 939,890 Operating and maintenance 155,285 53,767 — — 209,052 Administrative and general 77,139 28,965 3,073 — 109,177 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

Quarterly Financial Data (Una_2

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2021
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Amounts presented are in thousands, except per share data: Three Months Ended December 31, 2021 2020 Operating revenues $ 347,341 $ 313,445 Operating income 79,990 66,496 Net income $ 51,336 $ 53,551 Average common shares outstanding 53,293 50,583 Income per average common share: Basic $ 0.96 $ 1.06 Diluted $ 0.96 $ 1.06

Nature of Operations and Basi_3

Nature of Operations and Basis of Consolidation (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)wattscustomers	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Number of customers | customers	753,600
Number of megawatts of qualifying facility | watts	35
Qualifying Facility Contracts [Member]
Estimated aggregate gross contractual payments through 2024	$ 67.6
Variable interest entity, measure of activity, purchases	$ 26.1	$ 22.2	$ 23.4

Significant Accounting Polici_4

Significant Accounting Policies Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)Months	Dec. 31, 2020USD ($)
Number of months or less of maturity to be considered cash equivalent | Months	3
Allowance for doubtful accounts receivable, current	$ 2.3	$ 5.6
Unbilled receivables,current	$ 98.1	$ 80.5

Significant Accounting Polici_5

Significant Accounting Policies Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Accounting Policies [Abstract]
Materials and supplies	$ 54,137	$ 44,311
Storage gas and fuel	26,477	16,699
Total Inventories	$ 80,614	$ 61,010

Significant Accounting Polici_6

Significant Accounting Policies Property plant equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Property, plant and equipment, disclosure of composite depreciation rate for plant in service	2.80%	2.80%	2.80%
Allowance for Funds Used During Construction, Capitalized Interest	$ 15.9	$ 9.8	$ 8.2
Montana
Property, Plant and Equipment [Line Items]
Allowance for funds used during construction, rate	6.60%	6.70%	6.90%
South Dakota
Property, Plant and Equipment [Line Items]
Allowance for funds used during construction, rate	6.40%	6.70%	6.60%
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, 2021	Dec. 31, 2020
Accounting Policies [Abstract]
Property taxes	$ 86,168	$ 89,425
Employee compensation, benefits, and withholdings	44,743	40,538
Customer advances	29,013	16,015
Interest	18,568	18,074
Other (none of which is individually significant)	54,859	43,462
Total Accrued Expenses	$ 233,351	$ 207,514

Significant Accounting Polici_8

Significant Accounting Policies Other Noncurrent Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Accounting Policies [Abstract]
Pension and other employee benefits	$ 96,151	$ 136,632
Customer advances	80,780	65,186
Future QF obligation, net	64,943	81,379
Asset retirement obligations	38,350	45,355
Environmental	23,395	25,049
Other (none of which is individually significant)	65,700	57,102
Total Noncurrent Liabilities	$ 369,319	$ 410,703

Significant Accounting Polici_9

Significant Accounting Policies Supplemental Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income taxes	$ 4,330	$ 115	$ (6,737)
Interest	87,221	84,922	83,776
Capital expenditures included in trade accounts payable	29,034	21,430	33,473
New Market Tax Credit [Member] | Secured Debt
NMTC debt extinguishment included in other noncurrent assets(1)	18,200
NMTC debt extinguishment included in property, plant and equipment, net(1)	7,900
New Market Tax Credit [Member] | Debt Extinguishment included in other noncurrent assets
NMTC debt extinguishment included in other noncurrent assets(1)	18,169	0	0
New Market Tax Credit [Member] | Debt Extinguishment included in property, plant, and equipment, net
NMTC debt extinguishment included in property, plant and equipment, net(1)	6,594	0	0
New Market Tax Credit [Member] | Debt Extinguishment included in long term debt
NMTC debt extinguishment included in property, plant and equipment, net(1)	$ 1,259	$ 0	$ 0

Significant Accounting Polic_10

Significant Accounting Policies Reconciliation of Cash and Restricted Cash (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Cash and cash equivalents	$ 2,820	$ 5,811	$ 5,145
Restricted cash	15,942	11,285	6,925
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows	$ 18,762	$ 17,096	$ 12,070	$ 15,311

Regulatory Matters (Details)

Regulatory Matters (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Failure to Comply with CREP requirements in 2015 and 2016
Public Utilities, General Disclosures [Line Items]
Loss Contingency, Damages Sought, Value	$ 2.5
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%
Regulatory Liabilities	$ 8.2
Company Sharing Amount Exceeding PCCAM Base	5.4	$ 0.8
Requested increase in PCCAM Base amount	17
Montana FERC Rate Filing Settlement [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	$ 2

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ (27,674)	$ 22,773	$ (7,796)
Regulatory Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	806,227	746,417
Regulatory Assets [Member] | Flow-through income taxes
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	464,663	420,925
Regulatory Assets [Member] | Excess deferred income taxes
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	60,813	67,256
Regulatory Assets [Member] | Pension
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	98,336	138,567
Regulatory Assets [Member] | Deferred financing costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	25,636	28,350
Regulatory Assets [Member] | Employee related benefits
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	21,648	22,516
Regulatory Assets [Member] | Supply costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	$ 88,329	8,116
Regulatory assets, remaining amortization period	18 months
Regulatory Assets [Member] | State & local taxes & fees
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	$ 6,520	17,910
Regulatory Assets [Member] | Environmental clean-up
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	11,262	11,127
Regulatory Assets [Member] | Other
Regulatory Assets And Liabilities [Line Items]
Regulatory assets	29,020	31,650
Regulatory Liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	666,939	687,272
Regulatory Liabilities [Member] | Removal cost
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	479,294	464,669
Regulatory Liabilities [Member] | Excess deferred income taxes
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	158,047	165,279
Regulatory Liabilities [Member] | Supply costs
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 16,430	13,847
Regulatory liability, remaining amortization period	1 year
Regulatory Liabilities [Member] | Gas storage sales
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 7,466	7,887
Regulatory liability, remaining amortization period	18 years
Regulatory Liabilities [Member] | Rates subject to refund
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 1,971	32,496
Regulatory liability, remaining amortization period	1 year
Regulatory Liabilities [Member] | State & local taxes & fees
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 3,021	1,783
Regulatory liability, remaining amortization period	1 year
Regulatory Liabilities [Member] | Environmental clean-up
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 508	656
Regulatory Liabilities [Member] | Other
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 202	$ 655
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) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities			$ (27,674)	$ 22,773	$ (7,796)
Montana FERC Rate Filing Settlement [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory liabilities	$ 4,700	$ 20,500
Regulatory Liabilities			$ 2,000
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%
Regulatory Liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory Liabilities			$ 666,939	687,272
Regulatory Liabilities [Member] | State & local taxes & fees
Regulatory Assets And Liabilities [Line Items]
Regulatory Liabilities			$ 3,021	$ 1,783

Property, Plant and Equipment_2

Property, Plant and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Transmission, distribution, and storage	$ 4,004,819	$ 3,771,023
Generation	1,287,517	1,252,805
Plant acquisition adjustment(1)	686,328	686,328
Building and improvements	296,955	303,099
Land, land rights and easements	161,585	157,379
Other	585,448	571,981
Construction work in process	294,617	173,492
Total property, plant and equipment	7,317,269	6,916,107
Less accumulated depreciation	1,787,550	1,703,016
Net property, plant and equipment	5,247,232	4,952,935
Computer Software, Intangible Asset
Property, Plant and Equipment [Line Items]
Less accumulated amortization	(282,487)	(260,156)
Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Finance Lease, Right-of-Use Asset, after Accumulated Amortization	$ 9,200	11,300
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	$ 9,000	$ 11,100

Property, Plant and Equipment J

Property, Plant and Equipment Joint Ownership (Details) $ in Thousands	Dec. 31, 2021USD ($)plants	Dec. 31, 2020USD ($)
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	$ 154,375	$ 153,632
Accumulated depreciation	$ 42,102	$ 40,665
Neal 4 Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentages	8.70%	8.70%
Plant in service	$ 62,865	$ 62,927
Accumulated depreciation	$ 34,629	$ 33,942
Coyote Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentages	10.00%	10.00%
Plant in service	$ 51,652	$ 51,586
Accumulated depreciation	$ 38,453	$ 37,980
Colstrip Unit 4 [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership percentages	30.00%	30.00%
Plant in service	$ 324,433	$ 317,438
Accumulated depreciation	$ 113,805	$ 105,738

Asset Retirement Obligations Ro

Asset Retirement Obligations Rollforward (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at January 1,	$ 45,355	$ 42,449	$ 40,659
Accretion expense	2,233	2,070	2,051
Liabilities incurred	0	0	0
Liabilities settled	(2,906)	(4,061)	(46)
Revision to cash flows	(4,051)	4,897	(215)
Liability at December 31,	$ 40,631	$ 45,355	$ 42,449

Asset Retirement Obligations Na

Asset Retirement Obligations Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation, Liabilities Settled	$ 2,906	$ 4,061	$ 46

Goodwill (Details)

Goodwill (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
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, 2021	Dec. 31, 2020
Derivative [Line Items]
Physical purchase and sale of gas and electricity at fixed prices	$ 0	$ 0
Interest rate contracts, amount of gain reclassified from AOCL into income	(452)	(452)
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	14,000
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, 2021	Dec. 31, 2020
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	14,967	10,055
Rabbi trust investments	18,234	27,027
Total	33,201	37,082
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	14,967	10,055
Rabbi trust investments	18,234	27,027
Total	33,201	37,082
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, 2021	Dec. 31, 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, carrying value	$ 2,541,478	$ 2,315,261
Long-term debt, fair value	$ 2,827,336	$ 2,629,755

Short-Term Borrowings and Cre_3

Short-Term Borrowings and Credit Arrangements (Details)	12 Months Ended
	Dec. 31, 2021USD ($)numberofbanks	Dec. 31, 2020USD ($)
Short-term Debt [Line Items]
Maximum borrowing capacity	$ 450,000,000	$ 450,000,000
Maximum Ratio Of Indebtedness To Net Capital Threshold Percentage	65.00%
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of credit facility, expiration date	Sep. 2, 2023
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	$ 400,000	600,000
Swingline Credit Facility [Member]
Short-term Debt [Line Items]
Maximum borrowing capacity	25,000,000	25,000,000
Unsecured Revolving Line Of Credit, Maximun Outstanding Under Accordian Feature [Member]
Short-term Debt [Line Items]
Maximum borrowing capacity	75,000,000
Revolving Credit Facility Due 2023
Short-term Debt [Line Items]
Maximum borrowing capacity	$ 425,000,000	$ 425,000,000
Eurodollar [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Short-term Debt [Line Items]
Basis spread on variable rate	12.50%
Eurodollar [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Short-term Debt [Line Items]
Basis spread on variable rate	75.00%
Measurement Input, Credit Spread [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Short-term Debt [Line Items]
Basis spread on variable rate	112.50%
Measurement Input, Credit Spread [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Short-term Debt [Line Items]
Basis spread on variable rate	175.00%

Short-Term Borrowings and Cre_4

Short-Term Borrowings and Credit Arrangements (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 450,000,000	$ 450,000,000
Letters of credit outstanding, amount	0	0
LIBOR borrowings and letter of credit, amount outstanding	373,000,000	222,000,000
Net availability as of December 31	77,000,000	228,000,000
LIBOR Borrowings [Member]
Line of Credit Facility [Line Items]
LIBOR borrowings	$ 373,000,000	$ 222,000,000

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, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Long-term Debt	$ 2,541,478	$ 2,315,261
Finance Lease, Liability, Total	14,772	17,439
Current maturities of finance leases	(2,875)	(2,668)
Long-term finance leases	11,897	14,771
Secured Debt South Dakota Due 2030
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 50,000
Long-term Debt, Maturity Date	May 15, 2030
Secured Debt Montana Due 2030
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 100,000
Long-term Debt, Maturity Date	May 15, 2030
Montana First Mortgage Bonds Due 2024
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 100,000
Interest rate, stated percentage	1.00%
Long-term Debt, Maturity Date	Mar. 26, 2024
Unsecured Debt | Revolving Credit Facility Due 2023
Debt Instrument [Line Items]
Long-term Debt	$ 373,000	222,000
Maturity date	Sep. 2, 2023
Unsecured Debt | Revolving Credit Facility Due 2021
Debt Instrument [Line Items]
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	50,000
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	100,000
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	$ 0	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
Secured Debt | Montana First Mortgage Bonds Due 2024
Debt Instrument [Line Items]
Long-term Debt	$ 100,000	0
Maturity date	Mar. 26, 2024
Interest rate, stated percentage	1.00%
Discount on Notes and Bonds and Debt Issuance Costs, Net
Debt Instrument [Line Items]
Discount on notes and bonds and debt issuance costs, net	$ (11,182)	$ (13,376)

Long-Term Debt and Capital Le_4

Long-Term Debt and Capital Leases Schedule of Long-Term Debt (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)
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 South Dakota Due 2030
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 50,000
Long-term Debt, Maturity Date	May 15, 2030
Montana First Mortgage Bonds Due 2024
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 100,000
Interest rate, stated percentage	1.00%
Long-term Debt, Maturity Date	Mar. 26, 2024
New Market Tax Credit [Member] | Secured Debt
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 27,000
Revolving Credit Facility Due 2021 | Secured Debt
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 100,000
Secured Debt | Secured Debt Montana Due 2030
Debt Instrument [Line Items]
Interest rate, stated percentage	3.21%
Secured Debt | Secured Debt South Dakota Due 2030
Debt Instrument [Line Items]
Interest rate, stated percentage	3.21%
Secured Debt | Montana First Mortgage Bonds Due 2024
Debt Instrument [Line Items]
Interest rate, stated percentage	1.00%

Long-Term Debt and Capital Le_5

Long-Term Debt and Capital Leases Other Long-term Debt (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Payment for Debt Extinguishment or Debt Prepayment Cost	$ 955	$ 0	$ 0
New Market Tax Credit [Member] | Secured Debt
Debt Instrument [Line Items]
NMTC debt extinguishment included in property, plant and equipment, net(1)	7,900
Extinguishment of Debt, Amount	27,000
NMTC debt extinguishment included in other noncurrent assets(1)	18,200
Payment for Debt Extinguishment or Debt Prepayment Cost	900
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net	1,300
Revolving Credit Facility Due 2021 | Secured Debt
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 100,000
Montana First Mortgage Bonds Due 2024
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%

Long-Term Debt and Capital Le_6

Long-Term Debt and Capital Leases (Details) $ in Millions	Dec. 31, 2021USD ($)
Maturities of Long-term Debt [Abstract]
2022	$ 2.9
2023	520.8
2024	103.3
2025	303.6
2026	$ 106.9

Income Taxes Narrative (Details

Income Taxes Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
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	$ (22,800)
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations, Income Tax Penalties and Interest Portion	2,700
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	$ 500

Income Taxes Domestic Tax Compo

Income Taxes Domestic Tax Components (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Federal
Current	$ 722	$ (3,396)	$ (6,076)
Deferred	2,626	(4,006)	(15,169)
Investment tax credits	(130)	(3)	(12)
State
Current	2,172	3	27
Deferred	(1,971)	(3,568)	1,305
Income Tax Expense (Benefit)	$ 3,419	$ (10,970)	$ (19,925)

Income Taxes Effective Rate Rec

Income Taxes Effective Rate Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Federal statutory rate	21.00%	21.00%	21.00%
State income tax, net of federal provisions	0.10%	(1.10%)	0.70%
Flow-through repairs deductions	(11.50%)	(16.50%)	(10.80%)
Production tax credits	(6.10%)	(9.10%)	(6.30%)
Amortization of excess DIT	(0.30%)	(0.70%)	(0.90%)
Recognition of unrecognized tax benefit	0.00%	0.00%	(12.50%)
Impact of Tax Cuts and Jobs Act	0.00%	0.00%	0.10%
Plant and depreciation of flow through items	(0.60%)	0.10%	(2.20%)
Prior year permanent return to accrual adjustments	0.00%	(1.20%)	0.30%
Other, net	(0.80%)	(0.10%)	(0.10%)
Effective tax rate	1.80%	(7.60%)	(10.90%)
Income Before Income Taxes	$ 190,259	$ 144,245	$ 182,195
Income tax calculated at federal statutory rate	39,954	30,292	38,261
State income, net of federal provisions	354	(1,477)	1,251
Flow-through repairs deductions	(21,888)	(23,828)	(19,706)
Production tax credits	(11,532)	(13,103)	(11,483)
Amortization of excess DIT	(635)	(968)	(1,688)
Recognition of unrecognized tax benefit	0	0	(22,825)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	0	0	(198)
Plant and depreciation of flow through items	(941)	121	(3,952)
Prior year permanent return to accrual adjustments	(12)	(1,728)	559
Other, net	(1,881)	(279)	(144)
Total reconciling items	(36,535)	(41,262)	(58,186)
Income Tax Expense (Benefit)	$ 3,419	$ (10,970)	$ (19,925)

Income Taxes Deferred Tax Liabi

Income Taxes Deferred Tax Liability (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Deferred Tax Assets, [Abstract]
Production tax credit	$ 75,092	$ 63,542
Pension / postretirement benefits	21,435	31,866
Customer advances	21,271	17,165
Unbilled revenue	10,704	14,429
Compensation accruals	10,612	11,748
Reserves and accruals	5,106	6,266
Environmental liability	5,704	6,039
Interest rate hedges	3,158	3,171
NOL carryforward	0	393
Other, net	1,738	2,490
Deferred Tax Asset	154,820	157,109
Deferred Tax Liabilities, [Abstract]
Excess tax depreciation	(425,202)	(412,774)
Goodwill amortization	(85,425)	(83,991)
Flow through depreciation	(94,616)	(83,545)
Regulatory assets and other	(49,211)	(48,576)
Deferred Tax Liability	(654,454)	(628,886)
Deferred Tax Liability, net	$ (499,634)	$ (471,777)

Income Taxes Uncertain Tax Posi

Income Taxes Uncertain Tax Positions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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	$ 28,100	$ 28,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits at January 1	33,491	35,085	$ 56,150
Gross increases - tax positions in prior period	293	120	539
Gross increases - tax positions in current period	0	0	0
Gross decreases - tax positions in current period	(1,735)	(1,714)	(1,489)
Lapse of statute of limitations	0	0	(20,115)
Unrecognized Tax Benefits at December 31	32,049	$ 33,491	$ 35,085
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	$ 500

Comprehensive Income (Loss) (De

Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Other Comprehensive Income (Loss), Before Tax [Abstract]
Foreign currency translation adjustment	$ (57)	$ 87	$ (35)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, after Tax	(452)	(452)	(452)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax	162	162	162
Reclassification of net income (loss) on derivative instruments	(614)	(614)	(614)
Postretirement medical liability adjustment	(585)	2,463	(175)
Other comprehensive (loss) income	(28)	3,164	404
Other Comprehensive Income (Loss), Tax [Abstract]
Foreign currency translation adjustment	0	0	0
Postretirement medical liability adjustment	149	(623)	44
Other comprehensive (loss) income	(13)	(785)	(118)
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Foreign currency translation adjustment	(57)	87	(35)
Postretirement medical liability adjustment	(436)	1,840	(131)
Other comprehensive (loss) income	(41)	2,379	286
Accumulated Other Comprehensive Income, Net of Tax [Abstract]
Foreign currency translation	1,443	1,500
Derivative instruments designated as cash flow hedges	(10,277)	(10,729)
Postretirement medical plans	1,524	1,960
Accumulated other comprehensive loss	$ (7,310)	$ (7,269)	$ (9,648)

Comprehensive Income (Loss) Com

Comprehensive Income (Loss) Components of AOCI (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Beginning balance	$ (7,269)	$ (9,648)
Other comprehensive income before reclassifications	(57)	87
Interest rate contracts, amount of gain reclassified from AOCL into income	(452)	(452)
Amounts reclassified from AOCL	(436)	1,840
Net current-period other comprehensive income	(41)	2,379	$ 286
Ending Balance	(7,310)	(7,269)	(9,648)
Total
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net current-period other comprehensive income		2,379
Foreign Currency Translation
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Beginning balance	1,500	1,413
Other comprehensive income before reclassifications	(57)	87
Interest rate contracts, amount of gain reclassified from AOCL into income	0	0
Amounts reclassified from AOCL	0	0
Net current-period other comprehensive income	(57)	87
Ending Balance	1,443	1,500	1,413
Pension and Postretirement Medical Plans
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Beginning balance	1,960	120
Other comprehensive income before reclassifications	0	0
Interest rate contracts, amount of gain reclassified from AOCL into income	0	0
Amounts reclassified from AOCL	(436)	1,840
Net current-period other comprehensive income	(436)	1,840
Ending Balance	1,524	1,960	120
Interest Rate Derivative Instruments Designated as Cash Flow Hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Beginning balance	(10,729)	(11,181)
Other comprehensive income before reclassifications	0	0
Interest rate contracts, amount of gain reclassified from AOCL into income	(452)	(452)
Amounts reclassified from AOCL	0	0
Net current-period other comprehensive income	452	452
Ending Balance	$ (10,277)	$ (10,729)	$ (11,181)

Employee Benefit Plans Benefit

Employee Benefit Plans Benefit Obligation And Funded Status (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)numberOfParticipants	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Pension Plan [Member]
Change in Benefit Obligation:
Obligation at beginning of period	$ 820,979	$ 735,564
Service cost	12,994	11,116	$ 9,637
Interest cost	18,759	22,840	26,488
Actuarial loss	(28,905)	84,479
Settlements(1)	(93,488)	0
Benefits paid	(33,537)	(33,020)
Benefit Obligation at End of Period	696,802	820,979	735,564
Change in Fair Value of Plan Assets:
Settlements(1)	(93,500)
Amounts Recognized in the Balance Sheet Consist of:
Noncurrent asset	8,297	7,001
Total Assets	8,297	7,001
Current liability	(11,200)	(11,200)
Noncurrent liability	(88,400)	(128,324)
Total Liabilities	(99,600)	(139,524)
Net amount recognized	(91,303)	(132,523)
Amounts recognized in AOCL consist of:
Prior service cost	0	0
Net actuarial gain	0	0
Total	(62,448)	(115,987)
Plans with Benefit Obligations in Excess of Plan Assets [Abstract]
Projected benefit obligation	636,300	757,400
Accumulated benefit obligation	636,300	757,400
Fair value of plan assets(1)	537,900	619,100
Plan Assets used to purchase annuity contract	93,500
Settlement loss recognized(1)	$ 11,291	0	198
Pension Plan, Participants included in Pension Settlement | numberOfParticipants	1,062
Pension Plan [Member] | Pension
Amounts Recognized in Regulatory Assets Consist of:
Prior service credit	$ 0	0
Net actuarial loss	(62,448)	(115,987)
Pension Plan [Member] | Changes Measurement [Member]
Change in Fair Value of Plan Assets:
Fair value of plan assets at beginning of period	688,456	609,000
Return on plan assets	33,868	101,075
Employer contributions	10,200	11,401
Settlements(1)	(93,488)	0
Benefits paid	(33,537)	(33,020)
Fair value of plan assets at end of period	605,499	688,456	609,000
Funded Status	(91,303)	(132,523)
Other Postretirement Benefits Plan [Member]
Change in Benefit Obligation:
Obligation at beginning of period	19,146	20,272
Service cost	407	370
Interest cost	317	492
Actuarial loss	415	123
Settlements(1)	0	(390)
Benefits paid	(2,977)	(2,501)
Benefit Obligation at End of Period	17,308	19,146	20,272
Amounts Recognized in the Balance Sheet Consist of:
Noncurrent asset	11,914	8,436
Total Assets	11,914	8,436
Current liability	(1,575)	(1,712)
Noncurrent liability	(2,358)	(2,774)
Total Liabilities	(3,933)	(4,486)
Net amount recognized	7,981	3,950
Amounts recognized in AOCL consist of:
Prior service cost	(95)	(246)
Net actuarial gain	2,500	(3,246)
Total	5,641	6,360
Other Postretirement Benefits Plan [Member] | Pension
Amounts Recognized in Regulatory Assets Consist of:
Prior service credit	1,870	3,857
Net actuarial loss	1,366	(497)
Other Postretirement Benefits Plan [Member] | Changes Measurement [Member]
Change in Fair Value of Plan Assets:
Fair value of plan assets at beginning of period	23,096	21,479
Return on plan assets	3,349	2,723
Employer contributions	1,821	1,395
Settlements(1)	0	0
Benefits paid	(2,977)	(2,501)
Fair value of plan assets at end of period	25,289	23,096	$ 21,479
Funded Status	$ 7,981	$ 3,950

Employee Benefit Plans Net Peri

Employee Benefit Plans Net Periodic Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Plan [Member]
Service cost	$ 12,994	$ 11,116	$ 9,637
Interest cost	18,759	22,840	26,488
Expected return on plan assets	27,061	26,162	25,443
Amortization of prior service cost (credit)	0	0	0
Recognized actuarial loss (gain)	(6,536)	(5,028)	(6,544)
Settlement loss recognized(1)	11,291	0	198
Net Periodic Benefit Cost (Credit)	22,519	12,822	17,424
Regulatory deferral of net periodic benefit cost(2)	(13,308)	(2,100)	(7,510)
Previously deferred costs recognized(2)	0	71	728
Amount Recognized in Income	9,211	10,793	10,642
Other Pension, Postretirement and Supplemental Plans [Member]
Service cost	407	370	331
Interest cost	327	492	609
Expected return on plan assets	919	983	869
Amortization of prior service cost (credit)	(1,835)	(1,882)	(1,882)
Recognized actuarial loss (gain)	898	61	96
Settlement loss recognized(1)	0	390	390
Net Periodic Benefit Cost (Credit)	(2,918)	(1,674)	(1,517)
Regulatory deferral of net periodic benefit cost(2)	0	0	0
Previously deferred costs recognized(2)	709	861	931
Amount Recognized in Income	(2,209)	(813)	(586)
Net Periodic Costs [Member] | Pension Plan [Member]
Operating and maintenance	(313)	9,016	2,125
Other income (expense), net	9,524	1,777	8,517
Amount Recognized in Income	9,211	10,793	10,642
Net Periodic Costs [Member] | Other Pension, Postretirement and Supplemental Plans [Member]
Operating and maintenance	407	370	331
Other income (expense), net	(2,616)	(1,183)	(917)
Amount Recognized in Income	$ (2,209)	$ (813)	$ (586)

Employee Benefit Plans Actuaria

Employee Benefit Plans Actuarial Assumptions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Increase in projected benefit obligation due to change in discount rate		$ (45.1)
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%	2.00%
Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		2.65%	2.20%	3.10%
Expected rate of return on assets		3.01%	3.45%	4.23%
Interest credit rating		3.30%	3.30%	3.60%
Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		2.75%	2.30%	3.20%
Expected rate of return on assets		4.14%	4.49%	5.06%
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		4.08%	4.71%	4.79%
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%	2.00%
Other Postretirement Benefits Plan [Member] | Minimum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		2.35%	1.80%	2.80%
Other Postretirement Benefits Plan [Member] | Maximum [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		2.40%	1.80%	2.80%
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	2.66%
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	4.26%

Employee Benefit Plans Investme

Employee Benefit Plans Investment Strategy (Details)	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan, Plan Assets, Allocations [Abstract]
Target allocation of investments by plan	5.00%
Pension Plan [Member] | NorthWestern Energy Pension Plan (MT) [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	100.00%	100.00%
Pension Plan [Member] | NorthWestern Corporation Pension Plan [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	100.00%	100.00%
Pension Plan [Member] | Northwestern Energy Health and Welfare
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	100.00%	100.00%
Cash and cash equivalents | Pension Plan [Member] | NorthWestern Energy Pension Plan (MT) [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	0.10%	0.00%
Cash and cash equivalents | Pension Plan [Member] | NorthWestern Corporation Pension Plan [Member]
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	0.40%	0.70%
Cash and cash equivalents | Pension Plan [Member] | Northwestern Energy Health and Welfare
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	0.10%	1.00%
Fixed income securities | Pension Plan [Member] | NorthWestern Energy Pension Plan (MT) [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	53.80%	52.70%
Fixed income securities | Pension Plan [Member] | NorthWestern Corporation Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Allocations [Abstract]
Target allocation of investments by plan	90.00%	80.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	89.50%	77.30%
Fixed income securities | Pension Plan [Member] | Northwestern Energy Health and Welfare
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	33.70%	37.90%
Non-U.S. fixed income securities | Pension Plan [Member] | NorthWestern Energy Pension Plan (MT) [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	3.90%	3.80%
Non-U.S. fixed income securities | Pension Plan [Member] | NorthWestern Corporation Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Allocations [Abstract]
Target allocation of investments by plan	1.00%	2.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	0.90%	2.60%
Non-U.S. fixed income securities | Pension Plan [Member] | Northwestern Energy Health and Welfare
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%
Global equities | Pension Plan [Member] | NorthWestern Energy Pension Plan (MT) [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	42.20%	43.50%
Global equities | Pension Plan [Member] | NorthWestern Corporation Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Allocations [Abstract]
Target allocation of investments by plan	9.00%	18.00%
Defined Benefit Plan, Actual Asset Allocations [Abstract]
Actual allocation of investments by plan	9.20%	19.40%
Global equities | Pension Plan [Member] | Northwestern Energy Health and Welfare
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	66.20%	61.10%

Employee Benefit Plans Cash Flo

Employee Benefit Plans Cash Flows (Details) - Pension Plan [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension contributions	$ 10,200	$ 11,401	$ 10,200
NorthWestern Energy Pension Plan (MT) [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension contributions	9,000	10,201	9,000
NorthWestern Corporation Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension contributions	$ 1,200	$ 1,200	$ 1,200

Employee Benefit Plans Estimate

Employee Benefit Plans Estimated Payments (Details) $ in Thousands	Dec. 31, 2021USD ($)
Pension Plan [Member]
Estimated Future Benefit Payments
2022	$ 28,842
2023	30,368
2024	31,933
2025	33,410
2026	34,692
2027-2031	183,671
Other Pension, Postretirement and Supplemental Plans [Member]
Estimated Future Benefit Payments
2022	2,579
2023	2,296
2024	1,952
2025	1,435
2026	1,381
2027-2031	$ 5,352

Employee Benefit Plans Narrativ

Employee Benefit Plans Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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	$ 11.8	$ 11.1	$ 11

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 3,900	$ 2,200	$ 6,500
Compensation expense tax (expense) benefit	(200)	(600)	200
Compensation expense not yet recognized for nonvested awards	$ 5,700
Nonvested awards, total compensation cost not yet recognized, period for recognition	2 years
Shares vested in period, total fair value	$ 4,200	$ 5,100	$ 4,200
Share-based Compensation, Significant Assumptions
Risk-free interest rate	0.19%	1.42%
Expected life, in years	3 years	3 years
Expected volatility, minimum	28.20%	14.90%
Expected volatility, maximum	38.50%	19.70%
Dividend yield	4.30%	3.10%
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	18,741	21,434	19,027
Deferred Compensation Arrangement with Individual, Contributions by Employer	$ 1,100	$ 1,500	$ 1,300
Change in value of shares	1,300	(2,900)	2,400
Deferred Compensation Arrangement with Individual, Compensation Expense	$ 2,400	$ (1,400)	$ 3,700
DSUs withdrawn	186,137	613	3,708
Value of DSUs withdrawn	$ 12,100	$ 100	$ 300
Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant	828,486

Stock-Based Compensation Nonves

Stock-Based Compensation Nonvested (Details) - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Beginning nonvested grants (shares)	130,571
Granted (shares)	104,927
Vested (shares)	(69,867)
Forfeited (shares)	(3,108)
Remaining nonvested grants (shares)	162,523	130,571
Beginning nonvested (weighted-average grant date fair value)	$ 66.27
Granted (weighted-average grant date fair value)	50.53
Vested (weighted-average grant date fair value)	60.41
Forfeited (weighted-average grant date fair value)	59.14
Remaining nonvested (weighted-average grant date fair value)	$ 58.76	$ 66.27
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)	77,967
Granted (shares)	24,385
Vested (shares)	(15,033)
Forfeited (shares)	0
Remaining nonvested grants (shares)	87,319	77,967
Beginning nonvested (weighted-average grant date fair value)	$ 50.86
Granted (weighted-average grant date fair value)	43.29
Vested (weighted-average grant date fair value)	45.78
Forfeited (weighted-average grant date fair value)	0
Remaining nonvested (weighted-average grant date fair value)	$ 49.63	$ 50.86
Performance and vesting period	5 years	5 years

Common Stock Common Stock (Deta

Common Stock Common Stock (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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	$ 197,974,000	$ 1,398,000	$ 3,124,000
Shares paid for tax withholding	16,880	35,378
Proceeds from issuance of common stock, net	$ 196,246,000	$ 0	$ 0
Cash received on settlement of forward sale agreement	286,100,000
Cash needed to settle forward sales agreement, net	$ 24,200,000
Shares needed to deliver to settle forward sales agreement, net.	435,522
Equity Distribution Agreement
Class of Stock [Line Items]
Common Stock Aggregate Gross Sales Price Maximum	$ 200,000,000
Issuance of shares, shares	1,966,117
Common Stock Average Share Price	$ 63.81
Stock Issued, Value, Net of Fees	124,200,000
Investment Banking, Advisory, Brokerage, and Underwriting Fees and Commissions	$ 1,300,000
Registered Public Offering
Class of Stock [Line Items]
Issuance of shares, shares	1,401,869
Registered Public Offering, Shares Registered	6,074,767
Registered Public Offering, Issuance Amount	$ 325,000,000
Registered public offering, price per share	$ 53.50
Option to Purchase Additional Common Shares	911,215
Option to Purchase Additional Common Shares, Value	$ 48,800,000
Registered Public Offering, Total Common Shares Offered	6,985,982
Proceeds from issuance of common stock, net	$ 75,000,000
Forward Sales Agreement
Class of Stock [Line Items]
Registered Public Offering, Common Shares Remaining	5,584,113
Maximum Total Shares Issued Under Forward Sales Agreement	8,376,170
Equity Instrument, Basis Spread on Forward Sale Price, Per Share	0.75%
Forward Sale Price, Per Share	$ 51.8950
Common shares to deliver to settle forward sales agreement, gross	5,584,113

Earnings Per Share (Details)

Earnings Per Share (Details) - shares	3 Months Ended		12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Basic computation	53,293,000	50,583,000	51,709,229	50,559,208	50,428,560
Performance and restricted share awards(1)			111,940	145,181	323,298
Incremental Common Shares Attributable to Dilutive Effect of Equity Forward Agreements			51,057	0	0
Diluted computation			51,872,226	50,704,389	50,751,858
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount			77,856

Commitments and Contingencies Q

Commitments and Contingencies Qualifying Facilities Liability (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Beginning QF liability	$ 81,379,000
Ending QF liability	64,943,000	$ 81,379,000
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
Periodic adjustment of the liability for price escalation	(4,300,000)
Annual reset of liability to actual output and pricing	2,600,000	900,000
Unrecovered Amount, One Time Adjustment Of The Liability based on Contract Terms	7,000,000
Unrecovered Amount, Annual Reset to Actual Output and Pricing, Change year-over-year	$ 1,700,000
Maximum [Member]
Long term purchase commitments term	24 years
Qualifying Facility Contracts [Member]
Beginning QF liability	$ 81,379,000	92,937,000
Settlements(1)	(22,497,000)	(18,665,000)
Interest expense	6,061,000	7,107,000
Ending QF liability	64,943,000	$ 81,379,000
Qualifying Facility Contracts [Member] | Minimum [Member]
Price per MWH of energy required to be purchased per QF agreement	64
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	466,872,000
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
2022	80,355,000
2023	82,452,000
2024	75,113,000
2025	60,360,000
2026	55,393,000
Thereafter	113,199,000
Recorded Unconditional Purchase Obligation	466,872,000
Qualifying Facility Contracts [Member] | Recoverable Amounts [Member]
Recorded Unconditional Purchase Obligation	388,412,000
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
2022	60,639,000
2023	61,280,000
2024	60,706,000
2025	52,950,000
2026	46,274,000
Thereafter	106,563,000
Recorded Unconditional Purchase Obligation	388,412,000
Qualifying Facility Contracts [Member] | Net Amount [Member]
Recorded Unconditional Purchase Obligation	78,460,000
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
2022	19,716,000
2023	21,172,000
2024	14,407,000
2025	7,410,000
2026	9,119,000
Thereafter	6,636,000
Recorded Unconditional Purchase Obligation	$ 78,460,000

Commitments and Contingencies L

Commitments and Contingencies Long Term Supply and Capacity Purchase Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Long-term Purchase Commitment [Line Items]
Long term purchase committments costs incurred	$ 286.7	$ 206.6	$ 222.5
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]
Purchase obligation due in next twelve months	283.2
Purchase obligation due in second year	269.7
Purchase obligation due in third year	221.8
Purchase obligation due in fourth year	219.4
Purchase obligation due in fifth year	172.2
Purchase obligation due thereafter	$ 1,500
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	$ 26.7

Commitments and Contingencies E

Commitments and Contingencies Environmental Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Environmental remediation obligations [Member]
Environmental remediation obligation, minimum	$ 24,100
Environmental remediation obligation, maximum	30,700
Accrual for environmental loss contingencies	26,866	$ 28,895	$ 30,276	$ 29,741
Deductions	(2,799)	(2,977)	(2,232)
Charged to costs and expense	770	$ 1,596	$ 2,767
Combined Manufacturing Sites [Member] | Manufactured Gas Plants [Member]
Accrual for environmental loss contingencies	22,100
Aberdeen South Dakota Site [Member] | Manufactured Gas Plants [Member]
Accrual for environmental loss contingencies	8,100
Environmental remediation obligation, to be incurred during next 5 years	$ 3,000

Commitments and Contingencies_2

Commitments and Contingencies Legal Proceedings (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)
Pacific Northwest Solar, LLC (PNWS) [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 8
Loss Contingency, Damages Awarded, Value	0.4
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, 2021	Dec. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			$ 1,326,800	$ 1,206,800	$ 1,231,100
Total revenues	$ 347,341	$ 313,445	1,372,316	1,198,670	1,257,910
Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			573,600	529,300	526,700
Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			554,400	513,100	530,700
Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			39,000	37,700	44,600
Lighting, Governmental, Irrigation, and Interdepartmental
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			33,500	32,700	31,600
Total Customer Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			1,200,500	1,112,800	1,133,600
Other Tariff and Contract Based Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			126,300	94,000	97,500
Montana | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			460,600	424,300	418,200
Montana | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			421,400	389,600	403,800
South Dakota | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			92,000	88,100	88,300
South Dakota | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			121,600	115,400	116,400
Nebraska | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			21,000	16,900	20,200
Nebraska | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			11,400	8,100	10,500
Regulatory Amortization [Member]
Disaggregation of Revenue [Line Items]
Regulatory amortization			45,500	(8,100)	26,800
Total Revenue [Member]
Disaggregation of Revenue [Line Items]
Total revenues			1,372,300	1,198,700	1,257,900
Electric
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			1,018,700	953,900	952,400
Electric | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			400,000	387,400	371,300
Electric | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			459,200	439,400	445,200
Electric | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			37,900	36,800	43,600
Electric | Lighting, Governmental, Irrigation, and Interdepartmental
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			32,100	31,800	30,600
Electric | Total Customer Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			929,200	895,400	890,700
Electric | Other Tariff and Contract Based Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			89,500	58,500	61,700
Electric | Montana | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			334,600	320,800	308,800
Electric | Montana | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			356,700	338,300	348,100
Electric | South Dakota | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			65,400	66,600	62,500
Electric | South Dakota | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			102,500	101,100	97,100
Electric | Nebraska | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			0	0	0
Electric | Nebraska | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			0	0	0
Electric | Regulatory Amortization [Member]
Disaggregation of Revenue [Line Items]
Regulatory amortization			33,500	(13,100)	28,800
Electric | Total Revenue [Member]
Disaggregation of Revenue [Line Items]
Total revenues			1,052,200	940,800	981,200
Natural gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			308,100	252,900	278,700
Natural gas | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			173,600	141,900	155,400
Natural gas | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			95,200	73,700	85,500
Natural gas | Industrial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			1,100	900	1,000
Natural gas | Lighting, Governmental, Irrigation, and Interdepartmental
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			1,400	900	1,000
Natural gas | Total Customer Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			271,300	217,400	242,900
Natural gas | Other Tariff and Contract Based Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			36,800	35,500	35,800
Natural gas | Montana | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			126,000	103,500	109,400
Natural gas | Montana | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			64,700	51,300	55,700
Natural gas | South Dakota | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			26,600	21,500	25,800
Natural gas | South Dakota | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			19,100	14,300	19,300
Natural gas | Nebraska | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			21,000	16,900	20,200
Natural gas | Nebraska | Commercial
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer			11,400	8,100	10,500
Natural gas | Regulatory Amortization [Member]
Disaggregation of Revenue [Line Items]
Regulatory amortization			12,000	5,000	(2,000)
Natural gas | Total Revenue [Member]
Disaggregation of Revenue [Line Items]
Total revenues			$ 320,100	$ 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, 2021	Dec. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Total revenues	$ 347,341	$ 313,445	$ 1,372,316	$ 1,198,670	$ 1,257,910
Utilities Operating Expense, Fuel Used			425,548	306,190	318,020
Utility Margin			946,768	892,480	939,890
Operating and maintenance			208,303	202,991	209,052
Administrative and general			101,873	94,124	109,177
Property and other taxes			173,444	179,517	171,888
Depreciation and depletion			187,467	179,644	172,923
Operating Income	79,990	66,496	275,681	236,204	276,850
Interest expense, net			(93,674)	(96,812)	(95,068)
Other income, net			8,252	4,853	413
Income tax (expense) benefit			(3,419)	10,970	19,925
Net Income	51,336	53,551	186,840	155,215	202,120
Total assets	(6,780,443)	(6,389,449)	(6,780,443)	(6,389,449)	(6,083,486)
Capital expenditures			434,328	405,762	316,016
Eliminations
Segment Reporting Information [Line Items]
Total revenues			0	0	0
Utilities Operating Expense, Fuel Used			0	0	0
Utility Margin			0	0	0
Operating and maintenance			0	0	0
Administrative and general			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			1,052,182	940,815	981,178
Utilities Operating Expense, Fuel Used			294,820	236,581	239,589
Utility Margin			757,362	704,234	741,589
Operating and maintenance			156,383	149,220	155,285
Administrative and general			72,641	69,602	77,139
Property and other taxes			134,910	140,621	134,686
Depreciation and depletion			154,626	147,968	143,262
Operating Income			238,802	196,823	231,217
Interest expense, net			(82,678)	(85,487)	(78,809)
Other income, net			3,676	4,867	(1,365)
Income tax (expense) benefit			(2,512)	11,282	(6,079)
Net Income			157,288	127,485	144,964
Total assets	(5,432,578)	(5,126,589)	(5,432,578)	(5,126,589)	(4,808,011)
Capital expenditures			354,775	324,369	241,190
Operating Segments | Electric | Revision of Prior Period, Error Correction, Adjustment
Segment Reporting Information [Line Items]
Total assets	(488,300)		(488,300)
Operating Segments | Gas Domestic Regulated [Member]
Segment Reporting Information [Line Items]
Total revenues			320,134	257,855	276,732
Utilities Operating Expense, Fuel Used			130,728	69,609	78,431
Utility Margin			189,406	188,246	198,301
Operating and maintenance			51,920	53,771	53,767
Administrative and general			27,550	26,311	28,965
Property and other taxes			38,526	38,887	37,192
Depreciation and depletion			32,841	31,676	29,661
Operating Income			38,569	37,601	48,716
Interest expense, net			(6,083)	(6,341)	(6,218)
Other income, net			3,046	2,704	(814)
Income tax (expense) benefit			(2,640)	(2,426)	493
Net Income			32,892	31,538	42,177
Total assets	(1,342,031)	(1,251,240)	(1,342,031)	(1,251,240)	(1,270,811)
Capital expenditures			79,553	81,393	74,826
Operating Segments | Gas Domestic Regulated [Member] | Revision of Prior Period, Error Correction, Adjustment
Segment Reporting Information [Line Items]
Total assets	488,300		488,300
Other Segments [Member] | Operating Segments
Segment Reporting Information [Line Items]
Total revenues			0	0	0
Utilities Operating Expense, Fuel Used			0	0	0
Utility Margin			0	0	0
Operating and maintenance			0	0	0
Administrative and general			1,682	(1,789)	3,073
Property and other taxes			8	9	10
Depreciation and depletion			0	0	0
Operating Income			(1,690)	1,780	(3,083)
Interest expense, net			(4,913)	(4,984)	(10,041)
Other income, net			1,530	(2,718)	2,592
Income tax (expense) benefit			1,733	2,114	25,511
Net Income			(3,340)	(3,808)	14,979
Total assets	$ (5,834)	$ (11,620)	(5,834)	(11,620)	(4,664)
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, 2021	Dec. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating revenues	$ 347,341	$ 313,445	$ 1,372,316	$ 1,198,670	$ 1,257,910
Operating income	79,990	66,496	275,681	236,204	276,850
Net income	$ 51,336	$ 53,551	$ 186,840	$ 155,215	$ 202,120
Average Common Shares Outstanding	53,293,000	50,583,000	51,709,229	50,559,208	50,428,560
Income per average common share
Income per average common share, basic	$ 0.96	$ 1.06	$ 3.61	$ 3.07	$ 4.01
Income per average common share, diluted	$ 0.96	$ 1.06	$ 3.60	$ 3.06	$ 3.98