Cover page Cover page
Cover page Cover page - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Feb. 09, 2024 | Jun. 30, 2023 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2023 | ||
Document Transition Report | false | ||
Entity File Number | 000-56598 | ||
Entity Registrant Name | NORTHWESTERN ENERGY GROUP, INC. | ||
Entity Central Index Key | 0001993004 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2023 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 93-2020320 | ||
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 | $ 3,404,946,692 | ||
Entity Common Stock, Shares Outstanding | 61,256,549 | ||
Documents Incorporated by Reference | Documents Incorporated by Reference Certain sections of our Proxy Statement for the 2024 Annual Meeting of Shareholders are incorporated by reference into Part III of this Form 10-K | ||
Document Financial Statement Error Correction [Flag] | false |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Revenues | |||
Electric | $ 1,068,833 | $ 1,106,565 | $ 1,052,182 |
Gas | 353,310 | 371,272 | 320,134 |
Total Revenues | 1,422,143 | 1,477,837 | 1,372,316 |
Utilities Operating Expense, Fuel Used | 420,262 | 492,011 | 425,548 |
Operating Expenses | |||
Operating and maintenance | 220,524 | 221,427 | 208,303 |
Administrative and general | 117,360 | 113,776 | 101,873 |
Property and other taxes | 153,068 | 192,524 | 173,444 |
Depreciation and depletion | 210,474 | 195,020 | 187,467 |
Total Operating Expenses | 1,121,688 | 1,214,758 | 1,096,635 |
Operating Income | 300,455 | 263,079 | 275,681 |
Interest Expense, net | (114,617) | (100,110) | (93,674) |
Other Income, net | 15,832 | 19,434 | 8,252 |
Income Before Income Taxes | 201,670 | 182,403 | 190,259 |
Income Tax (Expense) Benefit | (7,539) | 605 | (3,419) |
Net Income | $ 194,131 | $ 183,008 | $ 186,840 |
Average Common Shares Outstanding | 60,321,481 | 55,769,156 | 51,709,229 |
Basic Earnings per Average Common Share | $ 3.22 | $ 3.28 | $ 3.61 |
Diluted Earnings per Average Common Share | $ 3.22 | $ 3.25 | $ 3.60 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Net Income | $ 83,142 | $ 66,743 | $ 194,131 | $ 183,008 | $ 186,840 |
Other comprehensive income (loss), net of tax: | |||||
Reclassification of net income (loss) on derivative instruments | (452) | (452) | (452) | ||
Postretirement medical liability adjustment | (262) | (982) | (436) | ||
Foreign currency translation adjustment | 2 | (8) | (57) | ||
Total Other Comprehensive Income (Loss) | 192 | (538) | (41) | ||
Comprehensive Income | $ 194,323 | $ 182,470 | $ 186,799 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Current Assets: | ||
Cash and cash equivalents | $ 9,164 | $ 8,489 |
Restricted cash | 16,023 | 13,974 |
Accounts receivable, net | 212,257 | 244,952 |
Inventories | 114,539 | 107,359 |
Regulatory assets | 29,626 | 136,009 |
Prepaid expenses and other | 25,397 | 28,041 |
Total current assets | 407,006 | 538,824 |
Property, plant, and equipment, net | 6,039,801 | 5,657,480 |
Goodwill | 357,586 | 357,586 |
Regulatory assets | 743,945 | 716,570 |
Other noncurrent assets | 52,314 | 47,323 |
Total Assets | 7,600,652 | 7,317,783 |
Current Liabilities: | ||
Current maturities of finance leases | 3,338 | 3,098 |
Current portion of long-term debt | 99,950 | 144,525 |
Accounts payable | 124,340 | 201,498 |
Accrued expenses | 246,167 | 250,579 |
Regulatory liabilities | 61,103 | 21,145 |
Total current liabilities | 534,898 | 620,845 |
Commitments and Contingencies (Note 18) | ||
Long-term finance leases | 5,461 | 8,799 |
Long-term debt | 2,684,635 | 2,474,357 |
Deferred income taxes | 600,520 | 538,983 |
Noncurrent regulatory liabilities | 657,452 | 654,213 |
Other noncurrent liabilities | 332,372 | 355,403 |
Total Liabilities | 4,815,338 | 4,652,600 |
Shareholders' Equity: | ||
Common Stock, Value, Issued | 648 | 633 |
Treasury stock at cost | (97,926) | (98,392) |
Paid-in capital | 2,078,753 | 1,999,376 |
Retained earnings | 811,495 | 771,414 |
Accumulated other comprehensive loss | (7,656) | (7,848) |
Total Shareholders' Equity | $ 2,785,314 | $ 2,665,183 |
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 | 64,761,919 | 63,278,307 |
Common Stock, shares outstanding | 61,248,800 | 59,744,130 |
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 |
Total Liabilities and Shareholders' Equity | $ 7,600,652 | $ 7,317,783 |
CONSOLIDATED BALANCE SHEETS PAR
CONSOLIDATED BALANCE SHEETS PARENTHETICAL (Parentheticals) - $ / shares | Dec. 31, 2023 | Dec. 31, 2022 |
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 | 64,761,919 | 63,278,307 |
Common Stock, shares outstanding | 61,248,800 | 59,744,130 |
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, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
OPERATING ACTIVITIES: | |||
Net Income | $ 194,131 | $ 183,008 | $ 186,840 |
Items not affecting cash: | |||
Depreciation and depletion | 210,474 | 195,020 | 187,467 |
Amortization of debt issuance costs, discount and deferred hedge gain | 5,142 | 5,321 | 5,250 |
Stock-based compensation costs | 5,176 | 5,488 | 5,350 |
Equity portion of AFUDC | (17,614) | (14,191) | (11,092) |
Loss (gain) on disposition of assets | 316 | 482 | (47) |
Deferred income taxes | 6,584 | (8,992) | 525 |
Changes in current assets and liabilities: | |||
Accounts receivable | 32,695 | (46,282) | (30,442) |
Inventories | (7,180) | (26,744) | (19,604) |
Other current assets | 2,644 | (3,833) | (6,835) |
Accounts payable | (54,722) | 50,537 | 7,494 |
Accrued expenses | (3,377) | 16,846 | 26,055 |
Regulatory assets | 105,588 | (20,512) | (69,616) |
Regulatory liabilities | 39,957 | (7,034) | (27,674) |
Other noncurrent assets and liabilities | (30,583) | (21,872) | (33,693) |
Cash Provided by Operating Activities | 489,231 | 307,242 | 219,978 |
INVESTING ACTIVITIES: | |||
Property, plant, and equipment additions | (566,889) | (515,140) | (434,328) |
Investment in equity securities | (3,923) | (1,719) | (1,505) |
Cash Used in Investing Activities | (570,812) | (516,859) | (435,833) |
FINANCING ACTIVITIES: | |||
Dividends on common stock | (154,050) | (140,062) | (128,483) |
Proceeds from issuance of common stock, net | 73,613 | 276,971 | 196,246 |
Issuance of long-term debt | 300,000 | 0 | 99,915 |
Payment for Debt Extinguishment or Debt Prepayment Cost | 0 | 0 | (955) |
Line of credit (repayments) borrowings, net | (132,000) | 77,000 | 151,000 |
Repayments of short-term borrowings | 0 | 0 | (100,000) |
Treasury stock activity | 1,069 | 603 | 707 |
Financing costs | (4,327) | (1,194) | (909) |
Cash Provided by Financing Activities | 84,305 | 213,318 | 217,521 |
Net Increase in Cash, Cash Equivalents, and Restricted Cash | 2,724 | 3,701 | 1,666 |
Cash, Cash Equivalents, and Restricted Cash, beginning of period | 22,463 | 18,762 | 17,096 |
Cash, Cash Equivalents, and Restricted Cash, end of period | $ 25,187 | $ 22,463 | $ 18,762 |
CONSOLIDATED STATEMENTS OF COMM
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands | Total | Common Stock | Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Loss | Treasury Stock, Common |
Balance at Dec. 31, 2020 | $ 2,079,095 | $ 541 | $ 1,513,787 | $ 670,111 | $ (7,269) | $ (98,075) |
Shares, Balance at Dec. 31, 2020 | 54,145 | 3,558 | ||||
Increase (Decrease) in Shareholders' Equity [Roll Forward] | ||||||
Net Income | 186,840 | $ 0 | 0 | 186,840 | 0 | $ 0 |
Foreign currency translation adjustment | (57) | 0 | 0 | 0 | (57) | 0 |
Reclassification of net income (loss) on derivative instruments | (452) | 0 | 0 | 0 | (452) | 0 |
Postretirement medical liability adjustment, net of tax | (436) | 0 | 0 | 0 | (436) | 0 |
Stock based compensation, value | $ 4,328 | $ 1 | 5,298 | 0 | 0 | $ (971) |
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 | (128,483) | 0 | 0 |
Balance at Dec. 31, 2021 | $ 2,339,713 | $ 576 | 1,716,227 | 728,468 | (7,310) | $ (98,248) |
Shares, Balance at Dec. 31, 2021 | 57,606 | 3,546 | ||||
Increase (Decrease) in Shareholders' Equity [Roll Forward] | ||||||
Dividends per share | $ 2.48 | |||||
Net Income | $ 183,008 | $ 0 | 0 | 183,008 | 0 | $ 0 |
Foreign currency translation adjustment | (8) | 0 | 0 | 0 | (8) | 0 |
Reclassification of net income (loss) on derivative instruments | (452) | 0 | 0 | 0 | (452) | 0 |
Postretirement medical liability adjustment, net of tax | (982) | 0 | 0 | 0 | (982) | 0 |
Stock based compensation, value | $ 6,480 | $ 0 | 7,391 | 0 | 0 | $ (911) |
Stock based compensation, shares | 87 | 16 | ||||
Treasury Stock, Shares, Acquired | (28) | |||||
Issuance of shares, value | $ 276,582 | $ 57 | 275,758 | 0 | 0 | |
Issuance of shares, shares | 5,585 | |||||
Issuance of shares, value, treasury stock reissued | $ 767 | |||||
Dividends on common stock | (140,062) | $ 0 | 0 | (140,062) | 0 | 0 |
Balance at Dec. 31, 2022 | $ 2,665,183 | $ 633 | 1,999,376 | 771,414 | (7,848) | $ (98,392) |
Shares, Balance at Dec. 31, 2022 | 63,278 | 3,534 | ||||
Increase (Decrease) in Shareholders' Equity [Roll Forward] | ||||||
Dividends per share | $ 2.52 | |||||
Net Income | $ 194,131 | $ 0 | 0 | 194,131 | 0 | $ 0 |
Foreign currency translation adjustment | 2 | 0 | 0 | 0 | 2 | 0 |
Reclassification of net income (loss) on derivative instruments | (452) | 0 | 0 | 0 | (452) | 0 |
Postretirement medical liability adjustment, net of tax | (262) | 0 | 0 | 0 | 262 | 0 |
Stock based compensation, value | $ 4,954 | $ 0 | 4,954 | 0 | 0 | $ 0 |
Stock based compensation, shares | 51 | 0 | ||||
Treasury Stock, Shares, Acquired | (21) | |||||
Issuance of shares, value | $ 74,904 | $ 15 | 74,423 | 0 | 0 | |
Issuance of shares, shares | 1,433 | |||||
Issuance of shares, value, treasury stock reissued | $ 466 | |||||
Dividends on common stock | (154,050) | $ 0 | 0 | (154,050) | 0 | 0 |
Balance at Dec. 31, 2023 | $ 2,785,314 | $ 648 | $ 2,078,753 | $ 811,495 | $ (7,656) | $ (97,926) |
Shares, Balance at Dec. 31, 2023 | 64,762 | 3,513 | ||||
Increase (Decrease) in Shareholders' Equity [Roll Forward] | ||||||
Dividends per share | $ 2.56 |
Nature of Operations and Basis
Nature of Operations and Basis of Consolidation | 12 Months Ended |
Dec. 31, 2023 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Nature of Operations and Basis of Consolidation | (1) Nature of Operations and Basis of Consolidation NorthWestern Energy Group, doing business as NorthWestern Energy, provides electricity and / or natural gas to approximately 775,300 customers in Montana, South Dakota, Nebraska and Yellowstone National Park, through its subsidiaries NW Corp and NWE Public Service. 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 Energy Group (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, 2023, have been evaluated as to their potential impact to the Consolidated Financial Statements through the date of issuance. Holding Company Reorganization On October 2, 2023, NW Corp and NorthWestern Energy Group completed a merger transaction pursuant to which NorthWestern Energy Group became the holding company parent of NW Corp. In this reorganization, shareholders of NW Corp (the predecessor publicly held parent company) became shareholders of NorthWestern Energy Group, maintaining the same number of shares and ownership percentage as held in NW Corp immediately prior to the reorganization. NW Corp became a wholly-owned subsidiary of NorthWestern Energy Group. The transaction was effected pursuant to a merger pursuant to Section 251(g) of the General Corporation Law of the State of Delaware, which provides for the formation of a holding company without a vote of the shareholders of the constituent corporation. Immediately after consummation of the reorganization, NorthWestern Energy Group had, on a consolidated basis, the same assets, businesses and operations as NW Corp had immediately prior to the consummation of the reorganization. As a result of the reorganization, NorthWestern Energy Group became the successor issuer to NW Corp pursuant to Rule 12g-3(a) of the Securities Exchange Act of 1934, and as a result, NorthWestern Energy Group's common stock was deemed registered under Section 12(b) of the Securities Exchange Act of 1934. On January 1, 2024, we completed the second and final phase of the holding company reorganization. NW Corp contributed the assets and liabilities of its South Dakota and Nebraska regulated utilities to NWE Public Service, and then distributed its equity interest in NWE Public Service and certain other subsidiaries to NorthWestern Energy Group, resulting in NW Corp owning and operating the Montana regulated utility and NWE Public Service owning and operating the Nebraska and South Dakota utilities, each as a direct subsidiary of NorthWestern Energy Group. |
Significant Accounting Policies
Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2023 | |
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, AROs, 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 $2.8 million and $2.5 million at December 31, 2023 and December 31, 2022, respectively. Receivables include unbilled revenues of $105.1 million and $117.4 million at December 31, 2023 and December 31, 2022, respectively. Inventories Inventories are stated at average cost. Inventory consisted of the following (in thousands): December 31, 2023 2022 Materials and supplies $ 85,876 $ 71,769 Storage gas and fuel 28,663 35,590 Total Inventories $ 114,539 $ 107,359 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. As of December 31, 2023, the only derivative instruments we have qualify for the normal purchases and normal sales exception. 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 6.4%, 6.4%, and 6.6% for Montana for 2023, 2022, and 2021, respectively. This rate averaged 6.4% for South Dakota in each of 2023, 2022, and 2021. AFUDC capitalized totaled $24.3 million, $20.2 million, and $15.9 million for the years ended December 31, 2023, 2022, and 2021, 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 127 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 2023, 2022, and 2021. 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 and other Accrued expenses and other consisted of the following (in thousands): December 31, 2023 2022 Property taxes $ 79,252 $ 96,093 Employee compensation, benefits, and withholdings 41,773 44,104 Customer advances 27,656 26,137 Interest 24,775 18,350 Other (none of which is individually significant) 72,711 65,895 Total Accrued Expenses $ 246,167 $ 250,579 Other Noncurrent Liabilities Other noncurrent liabilities consisted of the following (in thousands): December 31, 2023 2022 Customer advances $ 107,470 $ 95,393 Pension and other employee benefits 75,302 84,731 AROs 39,255 39,096 Future QF obligation, net 28,670 49,728 Environmental 21,135 22,662 Other (none of which is individually significant) 60,540 63,793 Total Noncurrent Liabilities $ 332,372 $ 355,403 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. Under the Inflation Reduction Act of 2022 our production tax credits may be transferred to an unrelated entity. Our policy is to account for these transferable credits within income tax expense. 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, 2023 2022 2021 (in thousands) Cash paid (received) for: Income taxes $ (827) $ 4,707 $ 4,330 Interest 105,238 95,400 87,221 Significant non-cash transactions: Capital expenditures included in trade accounts payable 42,322 64,758 29,034 New Market Tax Credit (NMTC) debt extinguishment included in other noncurrent assets — — 18,169 NMTC debt extinguishment included in property, plant and equipment, net — — 6,594 NMTC debt extinguishment included in long-term debt — — 1,259 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, 2023 2022 2021 Cash and cash equivalents $ 9,164 $ 8,489 $ 2,820 Restricted cash 16,023 13,974 15,942 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 25,187 $ 22,463 $ 18,762 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 There were no accounting standards adopted in the current year that had a material impact to our financial condition, results of operations, and cash flows. 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, 2023 | |
Regulated Operations [Abstract] | |
Regulatory Matters | (3) Regulatory Matters Montana Rate Review On August 8, 2022, we filed a Montana electric and natural gas rate review with the MPSC under Docket 2022.07.78 requesting an annual increase to electric and natural gas utility rates. On October 27, 2023, the MPSC issued a final order approving the settlement agreement filed April 3, 2023. Final rates, adjusting from interim to settled rates, were effective November 1, 2023. The details of our settlement agreement are set forth below: Returns, Capital Structure & Revenue Increase Resulting From Approved Settlement Agreement ($ in millions) Electric Natural Gas Return on Equity (ROE) 9.65% 9.55% Equity Capital Structure 48.02% 48.02% Base Rates $67.4 $14.1 PCCAM (1) $69.7 n/a Property Tax (tracker base adjustment) (1) $14.5 $4.2 Total Revenue Increase Through Approved Settlement Agreement $151.6 $18.3 (1) These items are flow-through costs. PCCAM reflects our fuel and purchased power costs. The approved settlement includes, among other things, agreement on electric and natural gas base revenue increases, allocated cost of service, rate design, updates to the base amount of revenues associated with property taxes and electric supply costs, and regulatory policy issues related to requested changes in regulatory mechanisms. The approved settlement agreement provides for an update to the PCCAM by adjusting the base costs from $138.7 million to $208.4 million and providing for more timely quarterly recovery of deferred balances instead of annual recovery. It also addresses the potential for future recovery of certain operating costs associated with the Yellowstone County Generating Station and provides for the deferral of incremental operating costs related to our Enhanced Wildfire Mitigation Plan. The settling parties agreed to terminate the pilot decoupling program (Fixed Cost Recovery Mechanism) and that the proposed business technology rider will not be implemented. South Dakota Electric Rate Review On June 15, 2023, we filed a South Dakota electric rate review filing (2022 test year) under Docket EL23-016 for an annual increase to electric rates totaling approximately $30.9 million. Our request was based on a rate of return of 7.54 percent, a capital structure including 50.5 percent equity, and rate base of $787.3 million. On January 10, 2024, the SDPUC issued a final order approving the settlement agreement between NorthWestern and SDPUC Staff for an annual increase in base rates of approximately $21.5 million and an authorized rate of return of 6.81 percent. The approved settlement is based on a capital structure of 50.5 percent equity and a rate base of $791.8 million. Final rates were effective January 10, 2024. In addition, NorthWestern was approved a phase in rate plan rider that allows for the recovery of capital investments not yet included in base rates. |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 2022 (in thousands) Flow-through income taxes 12 Plant Lives $ 553,452 $ 509,038 Pension 14 See Note 14 79,638 87,965 Excess deferred income taxes 12 Plant Lives 51,404 54,364 Employee related benefits 14 See Note 14 21,926 27,920 Deferred financing costs 11 See Note 11 20,028 22,620 Environmental clean-up 18 Undetermined 11,131 10,963 Supply costs 1 Year 7,317 101,096 State & local taxes & fees 1 Year 2,733 15,684 Other Various 25,942 22,929 Total Regulatory Assets $ 773,571 $ 852,579 Removal cost 6 Plant Lives $ 523,744 $ 502,289 Excess deferred income taxes 12 Plant Lives 136,382 148,989 State & local taxes & fees 1 Year 30,576 2,327 Supply costs 1 Year 19,691 11,536 Gas storage sales 16 years 6,625 7,046 Environmental clean-up 1 Year — 592 Other Various 1,537 2,579 Total Regulatory Liabilities $ 718,555 $ 675,358 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 and postretirement benefit 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. 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. 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. For our Montana electric supply tracker, the PCCAM, the interest rate we earn on supply costs under collected, or the interest rate we apply to an over collection, is based on the monthly interest rate for three month commercial paper as published by the Federal Reserve. 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, or refund the decrease, in rates, less the amount allocated to FERC jurisdictional customers and net of the related income tax benefit. 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. Enhanced Wildfire Mitigation Plan We have developed an Enhanced Wildfire Mitigation Plan addressing five key areas: situational awareness, operational practices, system preparedness, vegetation management, and public communications outreach. Because of ever-increasing wildfire risk, our plan includes greater focus on situational awareness to monitor changing environmental conditions, operational practices that are more reactive to changing conditions, increased frequency of patrol and repairs, and more robust system hardening programs that target higher risk segments in our transmission and distribution systems. As discussed within Note 3 - Regulatory Matters |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2023 | |
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): December 31, 2023 2022 (in thousands) Electric Plant $ 5,462,229 $ 5,205,788 Natural Gas Plant 1,506,943 1,371,045 Plant acquisition adjustment (1) 686,328 686,328 Common and Other Plant 267,132 268,970 Construction work in process 377,241 311,652 Total property, plant and equipment 8,299,873 7,843,783 Less accumulated depreciation (1,930,688) (1,880,265) Less accumulated amortization (329,384) (306,038) Net property, plant and equipment $ 6,039,801 $ 5,657,480 (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 $5.2 million and $7.2 million as of December 31, 2023 and 2022, respectively, which included $5.0 million and $7.0 million as of December 31, 2023 and 2022, 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. On January 16, 2023, we entered into a definitive agreement (Agreement) with Avista Corporation (Avista) to acquire Avista's 15 percent interest in each of Units 3 and 4 at the Colstrip Generating Station, a coal-fired, base-load electric generation facility located in Colstrip, Montana. As noted in the table below, we currently have a 30 percent interest in Unit 4. The Agreement provides that the purchase price will be $0 and that we will acquire Avista's interest effective December 31, 2025, subject to the satisfaction of the closing conditions contained within the agreement. Under the terms of this Agreement, we will be responsible for operating costs starting on January 1, 2026; while Avista will retain responsibility for its pre-closing share of environmental and pension liabilities attributed to events or conditions existing prior to the closing of the transaction and for any future decommission and demolition costs associated with the existing facilities that comprise Avista's interest. The Agreement contains customary representations and warranties, covenants, and indemnification obligations, and the Agreement is subject to customary conditions and approvals, including approval from the FERC. Closing also is conditioned on our ability to enter into a new coal supply agreement for Colstrip by December 31, 2024. Such coal supply agreement must provide a sufficient amount of coal to Colstrip to permit the generation of electric power by the maximum permitted capacity of the interest in Colstrip then held by us during the period from January 1, 2026 through, December 31, 2030. Either party may terminate the Agreement if any requested regulatory approval is denied or if the closing has not occurred by December 31, 2025 or if any law or order would delay or impair closing. 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, 2023 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 156,696 $ 64,132 $ 52,630 $ 323,793 Accumulated depreciation 44,525 37,178 39,393 127,381 December 31, 2022 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 155,567 $ 63,032 $ 51,796 $ 326,584 Accumulated depreciation 42,884 35,847 38,955 121,830 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2023 | |
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 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, 2023 2022 2021 Liability at January 1, $ 40,894 $ 40,631 $ 45,355 Accretion expense 1,899 1,853 2,233 Liabilities incurred — — — Liabilities settled (1,244) (4,004) (2,906) Revisions to cash flows (125) 2,414 (4,051) Liability at December 31, $ 41,424 $ 40,894 $ 40,631 During the twelve months ended December 31, 2023 our ARO liability decreased $1.2 million for partial settlement of the legal obligations at our jointly-owned coal-fired generation facilities and natural gas pipeline segments. Additionally, during the twelve months ended December 31, 2023, our ARO liability decreased $0.1 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, 2023 and 2022. |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2023 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill | (7) Goodwill We completed our annual goodwill impairment test as of April 1, 2023. We evaluated qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors, and overall financial performance) to determine whether it was more likely than not that the fair value of our reporting units were less than their carrying amounts. Our evaluation of these factors concluded that it was not more likely than not that the fair value of our reporting units was less than their carrying amounts and therefore no further testing was necessary. Goodwill by segment is as follows (in thousands): December 31, 2023 2022 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, 2023 | |
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, 2023 and 2022. 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, 2023 Interest rate contracts Interest Expense $ 612 A pre-tax loss of approximately $12.8 million is remaining in AOCL as of December 31, 2023, 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, 2023 | |
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 item 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, 2023 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 $ 14,996 $ — $ — $ — $ 14,996 Rabbi trust investments 17,093 — — — 17,093 Total $ 32,089 $ — $ — $ — $ 32,089 December 31, 2022 Restricted cash equivalents $ 12,990 $ — $ — $ — $ 12,990 Rabbi trust investments 20,895 — — — 20,895 Total $ 33,885 $ — $ — $ — $ 33,885 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, 2023 December 31, 2022 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 2,784,585 $ 2,521,030 $ 2,618,882 $ 2,316,700 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, 2023 | |
Line of Credit Facility [Abstract] | |
Short-term Debt | (10) Unsecured Credit Facilities On November 29, 2023, NW Corp amended its existing $425.0 million revolving credit facility (the Amended Facility) to address the holding company reorganization and extended the maturity date of the facility to November 29, 2028. The Amended Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points. After the completion of the holding company reorganization on January 1, 2024, NW Corp owns and operates only the Montana regulated utility, and the base capacity of the Amended Facility automatically reduced to $400.0 million. On October 28, 2022, we entered into a $100.0 million Credit Agreement (the Additional Credit Facility) to supplement our existing $425.0 million revolving credit facility. The Additional Credit Facility has a maturity date of April 28, 2024. The Additional Credit Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points, plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points. As of December 31, 2023, there were no amounts outstanding under this Additional Credit Facility. On March 25, 2023, we amended our existing $25.0 million swingline credit facility (the Swingline Facility) to extend the maturity date of the facility from March 27, 2024 to March 27, 2025. The Swingline Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a margin of 90.0 basis points, or (b) a base rate, plus a margin of 12.5 basis points. As of December 31, 2023, there were no amounts outstanding under this Swingline Facility. On January 2, 2024, NW Corp terminated its $100.0 million Additional Credit Facility. On January 4, 2024, NW Corp terminated its $25.0 million Swingline Facility. On November 29, 2023, NorthWestern Energy Group and its subsidiary, NWE Public Service, entered into a new $200.0 million unsecured revolver credit facility with base sublimits of $50.0 million for NorthWestern Energy Group and $150.0 million for NWE Public Service (the HoldCo and NWE Public Service Credit Facility). The HoldCo and NWE Public Service Credit Facility has a maturity date of November 29, 2028. Upon the completion of the holding company reorganization on January 1, 2024, this credit facility became effective. The HoldCo and NWE Public Service Credit Facility has uncommitted features that allow both NorthWestern Energy Group and NWE Public Service to request one-year extensions to the maturity date and increase the size of the credit facility by an additional $50 million. The credit facility also gives us the flexibility to adjust the sublimits as needed, provided that NorthWestern Energy Group's base sublimit cannot exceed $100.0 million and NWE Public Service's sublimit cannot exceed $200.0 million. Borrowings may be made at interest rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points. Commitment fees for the unsecured revolving lines of credit were $0.6 million and $0.1 million for the years ended December 31, 2023 and 2022. The availability under the facilities in place for the years ended December 31 is shown in the following table (in millions): 2023 2022 Unsecured revolving line of credit, expiring May 2027 $ — $ 425.0 Unsecured revolving line of credit, expiring November 2028 (1) 425.0 — Unsecured revolving line of credit, expiring April 2024 (2) 100.0 100.0 Unsecured revolving line of credit, expiring March 2025 (2) 25.0 25.0 550.0 550.0 Amounts outstanding at December 31: SOFR borrowings 318.0 450.0 Letters of credit — — 318.0 450.0 Net availability as of December 31 (3) $ 232.0 $ 100.0 (1) Upon the completion of the holding company reorganization on January 1, 2024, the base capacity of this facility decreased to $400.0 million. (2) NW Corp terminated the $100.0 million Additional Credit Facility on January 2, 2024, and the $25.0 million Swingline Facility on January 4, 2024. (3) As discussed above, upon the completion of the holding company reorganization on January 1, 2024, our total consolidated base capacity increased to $600.0 million and our net availability increased to $282.0 million. Our credit facilities include covenants that require us to meet certain financial tests, including a maximum debt to capitalization ratio not to exceed 65 percent. The facilities also contain 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 Montana First Mortgage Bonds would trigger a cross default on the Amended Facility; however, a default on the Amended Facility would not trigger a default on the Montana First Mortgage Bonds. A default on the South Dakota First Mortgage Bonds would trigger a cross default on the NWE Public Service sublimit of the HoldCo and NWE Public Service Credit Facility; however, a default on the HoldCo and NWE Public Service Credit Facility would not trigger a default on the South Dakota First Mortgage Bonds. |
Long-Term Debt and Capital Leas
Long-Term Debt and Capital Leases | 12 Months Ended |
Dec. 31, 2023 | |
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 2023 2022 Unsecured Debt: Unsecured Revolving Line of Credit 2027 $ — $ 425,000 Unsecured Revolving Line of Credit 2028 318,000 — Unsecured Revolving Line of Credit 2024 — 25,000 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 South Dakota—5.57% 2033 31,000 — South Dakota—5.42% 2033 30,000 — 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 100,000 100,000 Montana—5.57% 2033 239,000 — Pollution control obligations— Montana—2.00% 2023 — 144,660 Montana—3.88% 2028 144,660 — Other Long Term Debt: Discount on Notes and Bonds and Debt Issuance Costs, Net — (13,075) (10,778) Total Long-Term Debt $ 2,784,585 $ 2,618,882 Less current maturities (including associated debt issuance costs) (99,950) (144,525) Total Long-Term Debt, Net of Current Maturities $ 2,684,635 $ 2,474,357 Finance Leases: Total Finance Leases Various $ 8,799 $ 11,897 Less current maturities (3,338) (3,098) Total Long-Term Finance Leases $ 5,461 $ 8,799 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 South Dakota indenture was transferred from NW Corp to NWE Public Service upon the completion of the holding company reorganization on January 1, 2024. The Montana First Mortgage Bonds are a series of general obligation bonds issued under our Montana indenture. These bonds are secured by substantially all of our Montana electric and natural gas assets. On March 30, 2023, we issued and sold $239.0 million aggregate principal amount of Montana First Mortgage Bonds (the bonds) at a fixed interest rate of 5.57 percent maturing on March 30, 2033. On this same day, we issued and sold $31.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.57 percent maturing on March 30, 2033. On May 1, 2023, we issued and sold an additional $30 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.42 percent maturing on May 1, 2033. These bonds were issued in transactions 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. On June 29, 2023, the City of Forsyth, Rosebud County, Montana issued $144.7 million principal amount of Pollution Control Revenue Refunding Bonds (2023 Pollution Control Bonds) on our behalf. The 2023 Pollution Control Bonds were issued at a fixed interest rate of 3.88 percent maturing on July 1, 2028. The proceeds of the issuance were loaned to us pursuant to a Loan Agreement and were deposited directly with U.S. Bank Trust Company, National Association, as trustee, for the redemption of the 2.00 percent, $144.7 million City of Forsyth Pollution Control Revenue Refunding Bonds due on August 1, 2023 that had previously been issued on our behalf. Pursuant to the Loan Agreement, we are obligated to make payments in such amounts and at such times as will be sufficient to pay, when due, the principal and interest on the 2023 Pollution Control Bonds. Our obligations under the Loan Agreement are secured by delivery of a like amount of our Montana First Mortgage Bonds, which are secured by our Montana electric and natural gas assets. So long as we are making payments under the Loan Agreement, no payments under these mortgage bonds will be due. The 2023 Pollution Control Bonds were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended. As of December 31, 2023, we were in compliance with our financial debt covenants. Maturities of Long-Term Debt The aggregate minimum principal maturities of long-term debt and finance leases, during the next five years are $103.3 million in 2024, $303.6 million in 2025, $106.9 million in 2026, and $497.7 million in 2028. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | (12) Income Taxes Income tax (benefit) expense is comprised of the following (in thousands): Year Ended December 31, 2023 2022 2021 Federal Current $ 2,925 $ 5,024 $ 722 Deferred 2,929 (5,993) 2,626 Investment tax credits (129) (130) (130) State Current (1,971) 3,363 2,172 Deferred 3,785 (2,869) (1,971) Income Tax Expense (Benefit) $ 7,539 $ (605) $ 3,419 Our effective tax rate typically differs from the federal statutory tax rate primarily due to production tax credits and 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, 2023 2022 2021 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax, net of federal provisions 0.3 0.3 0.1 Flow-through repairs deductions (12.9) (12.4) (11.5) Production tax credits (5.1) (7.2) (6.1) Unregulated Tax Cuts and Jobs Act excess deferred income taxes (1.7) — — Release of unrecognized tax benefits (1.6) — — Amortization of excess deferred income taxes (1.1) (0.9) (0.3) Plant and depreciation of flow through items 3.3 (0.1) (0.6) Reduction to previously claimed alternative minimum tax credit 1.6 — — Prior year permanent return to accrual adjustments 0.0 (0.8) 0.0 Other, net (0.1) (0.2) (0.8) Effective tax rate 3.7 % (0.3) % 1.8 % 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, 2023 2022 2021 Income Before Income Taxes $ 201,670 $ 182,403 $ 190,259 Income tax calculated at federal statutory rate 42,350 38,304 39,954 Permanent or flow through adjustments: State income, net of federal provisions 606 562 354 Flow-through repairs deductions (25,922) (22,665) (21,888) Production tax credits (10,274) (13,166) (11,532) Unregulated Tax Cuts and Jobs Act excess deferred income taxes (3,385) — — Release of unrecognized tax benefits (3,241) — — Amortization of excess deferred income taxes (2,184) (1,657) (635) Plant and depreciation of flow through items 6,595 (222) (941) Reduction to previously claimed alternative minimum tax credit 3,186 — — Prior year permanent return to accrual adjustments 45 (1,397) (12) Other, net (237) (364) (1,881) (34,811) (38,909) (36,535) Income Tax Expense (Benefit) $ 7,539 $ (605) $ 3,419 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, 2023 2022 NOL carryforward $ 113,366 — Production tax credit 94,283 $ 80,097 Customer advances 28,300 25,119 Pension / postretirement benefits 15,131 19,291 Compensation accruals 10,716 10,306 Unbilled revenue 10,604 9,440 Environmental liability 5,760 6,009 Interest rate hedges 3,280 3,372 Reserves and accruals 3,098 4,016 Other, net 2,677 2,595 Deferred Tax Asset 287,215 160,245 Excess tax depreciation (660,440) (449,724) Flow through depreciation (120,558) (106,623) Goodwill amortization (88,323) (86,874) Regulatory assets and other (18,414) (56,007) Deferred Tax Liability (887,735) (699,228) Deferred Tax Liability, net $ (600,520) $ (538,983) As of December 31, 2023, our total federal NOL carryforward was approximately $447.8 million. Our federal NOL carryforward does not expire. Our state NOL carryforward as of December 31, 2023 was approximately $362.1 million. If unused, our state NOL carryforwards will expire in 2033. We believe it is more likely than not that sufficient taxable income will be generated to utilize these NOL carryforwards. At December 31, 2023, our total production tax credit carryforward was approximately $94.3 million. If unused, our production tax credit carryforwards will expire as follows: $1.8 million in 2035, $10.9 million in 2036, $11.1 million in 2037, $10.9 million in 2038, $11.5 million in 2039, $13.1 million in 2040, $11.5 million in 2041, $13.2 million in 2042, and $10.4 million in 2043. We believe it is more likely than not that sufficient taxable income will be generated to utilize these production tax credit carryforwards. Uncertain Tax Positions We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The change in unrecognized tax benefits is as follows (in thousands): 2023 2022 2021 Unrecognized Tax Benefits at January 1 $ 30,330 $ 32,049 $ 33,491 Gross increases - tax positions in prior period — — 293 Gross increases - tax positions in current period — — — Gross decreases - tax positions in current period (2,256) (1,719) (1,735) Lapse of statute of limitations — — — Unrecognized Tax Benefits at December 31 $ 28,074 $ 30,330 $ 32,049 Our unrecognized tax benefits include approximately $24.4 million and $27.9 million related to tax positions as of December 31, 2023 and 2022, that if recognized, would impact our annual effective tax rate. On April 14, 2023, the Internal Revenue Service (IRS) issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting for gas repairs expenditures. During the year ended December 31, 2023, we adopted this method and decreased our total unrecognized tax benefits by $0.5 million and recognized an income tax benefit of approximately $3.2 million for previously unrecognized tax benefits. In the next twelve months we expect the statute of limitations to expire for certain uncertain tax benefits, which would result in a decrease to our total unrecognized tax benefits of approximately $16.9 million. Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2023, we have accrued $4.5 million for the payment of interest and penalties in the Consolidated Balance Sheets. As of December 31, 2022, we had $1.4 million accrued for the payment of interest and penalties. Tax years 2020 and forward remain subject to examination by the IRS and state taxing authorities. During the first quarter of 2023 the IRS commenced and concluded a limited scope examination of our 2019 amended federal income tax return. This examination resulted in a reduction to our previously claimed alternative minimum tax credit refund that is reflected in the table above. |
Comprehensive Income (Loss)
Comprehensive Income (Loss) | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 2022 2021 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 $ 2 $ — $ 2 $ (8) $ — $ (8) $ (57) $ — $ (57) Reclassification of net income (loss) on derivative instruments 612 (160) 452 612 (160) 452 614 (162) 452 Postretirement medical liability adjustment (331) 69 (262) (1,359) 377 (982) (585) 149 (436) Other comprehensive (loss) income $ 283 $ (91) $ 192 $ (755) $ 217 $ (538) $ (28) $ (13) $ (41) Balances by classification included within AOCL on the Consolidated Balance Sheets are as follows, net of tax (in thousands): December 31, 2023 2022 Foreign currency translation $ 1,437 $ 1,435 Derivative instruments designated as cash flow hedges (9,373) (9,825) Postretirement medical plans 280 542 Accumulated other comprehensive loss $ (7,656) $ (7,848) The following table displays the changes in AOCL by component, net of tax (in thousands): December 31, 2023 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (9,825) $ 542 $ 1,435 $ (7,848) Other comprehensive income before reclassifications — — 2 2 Amounts reclassified from AOCL Interest Expense 452 — — 452 Amounts reclassified from AOCL — (262) — (262) Net current-period other comprehensive income (loss) 452 (262) 2 192 Ending Balance $ (9,373) $ 280 $ 1,437 $ (7,656) December 31, 2022 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 $ (10,277) $ 1,524 $ 1,443 $ (7,310) Other comprehensive loss before reclassifications — — (8) (8) Amounts reclassified from AOCL Interest Expense 452 — — 452 Amounts reclassified from AOCL — (982) — (982) Net current-period other comprehensive income (loss) 452 (982) (8) (538) Ending Balance $ (9,825) $ 542 $ 1,435 $ (7,848) |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2023 | |
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, 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, 2023 2022 2023 2022 Change in benefit obligation: Obligation at beginning of period $ 521,798 $ 696,802 $ 15,407 $ 17,308 Service cost 5,646 10,223 333 351 Interest cost 25,852 18,787 674 358 Actuarial loss 3,127 (176,389) (1,240) (99) Settlements (1) (51,942) — — — Benefits paid (30,493) (27,625) (1,466) (2,511) Benefit Obligation at End of Period $ 473,988 $ 521,798 $ 13,708 $ 15,407 Change in Fair Value of Plan Assets: Fair value of plan assets at beginning of period $ 441,539 $ 605,499 $ 20,055 $ 25,289 Return on plan assets 34,367 (144,535) 3,334 (4,098) Employer contributions 9,200 8,200 386 1,375 Settlements (1) (51,942) — — — Benefits paid (30,493) (27,625) (1,466) (2,511) Fair value of plan assets at end of period $ 402,671 $ 441,539 $ 22,309 $ 20,055 Funded Status $ (71,317) $ (80,259) $ 8,601 $ 4,648 Amounts Recognized in the Balance Sheet Consist of: Noncurrent asset 7,875 7,195 12,378 8,831 Total Assets 7,875 7,195 12,378 8,831 Current liability (11,200) (11,200) (1,355) (1,585) Noncurrent liability (67,992) (76,254) (2,422) (2,598) Total Liabilities (79,192) (87,454) (3,777) (4,183) Net amount recognized $ (71,317) $ (80,259) $ 8,601 $ 4,648 Amounts Recognized in Regulatory Assets Consist of: Prior service credit — — — (116) Net actuarial (loss) gain (44,453) (54,383) 15 (3,123) Amounts recognized in AOCL consist of: Prior service cost — — — — Net actuarial gain — — 590 1,046 Total $ (44,453) $ (54,383) $ 605 $ (2,193) (1) In October 2023, we entered into a group annuity contract from an insurance company to provide for the payment of pension benefits to 285 NorthWestern Energy Pension Plan participants. We purchased the contract with $51.9 million of plan assets. The insurance company took over the payments of these benefits starting January 1, 2024. This transaction settled $51.9 million of our NorthWestern Energy Pension Plan obligation. As a result of this transaction, during the twelve months ended December 31, 2023, we recorded a non-cash, non-operating settlement charge of $4.4 million. This charge is recorded within other income, net on the Consolidated Statements of Income. As discussed within Note 4 – Regulatory Assets and Liabilities , the MPSC allows recovery of pension costs on a cash funding basis. As such, 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, 2023 2022 Projected benefit obligation $ 427.3 $ 474.9 Accumulated benefit obligation 427.3 474.9 Fair value of plan assets 348.1 388.7 As of December 31, 2023, the fair value of the NorthWestern Corporation pension plan assets exceed the total projected and accumulated benefit obligation and are therefore excluded from this table. Net Periodic Cost (Credit) The components of the net costs (credits) for our pension and other postretirement plans are as follows (in thousands): Pension Benefits Other Postretirement Benefits December 31, December 31, 2023 2022 2021 2023 2022 2021 Components of Net Periodic Benefit Cost Service cost $ 5,646 $ 10,223 $ 12,994 $ 333 $ 351 $ 407 Interest cost 25,852 18,787 18,759 674 359 327 Expected return on plan assets (25,932) (24,173) (27,061) (1,096) (1,047) (919) Amortization of prior service cost (credit) — — — 116 (1,891) (1,835) Recognized actuarial loss (gain) 228 383 6,536 (672) (897) (898) Settlement loss recognized (1) 4,395 — 11,291 — — — Net Periodic Benefit Cost (Credit) $ 10,189 $ 5,220 $ 22,519 $ (645) $ (3,125) $ (2,918) Regulatory deferral of net periodic benefit cost (2) (1,814) 2,307 (13,308) — — — Previously deferred costs recognized (2) 210 — — 550 292 709 Net Periodic Benefit Cost Recognized $ 8,585 $ 7,527 $ 9,211 $ (95) $ (2,833) $ (2,209) (1) Settlement losses are related to partial annuitization of NorthWestern Energy Pension Plan effective October 24, 2023 and December 1, 2021, respectively. (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 the years ended December 31, 2023, 2022, and 2021, Service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income, net on the Consolidated Statements of Income. 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, 2023 and 2022. 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. During 2022, the plan's actuary conducted an experience study to review five years of plan experience and update these assumptions. On an annual basis, we set the discount rate using a yield curve analysis. This analysis includes constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year, projected benefit cash flow from our plans. The decrease in the discount rate during 2023 increased our projected benefit obligation by approximately $10.5 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 6.65 percent and increased our assumption on the NorthWestern Corporation Pension Plan to 5.15 percent for 2024. The weighted-average assumptions used in calculating the preceding information are as follows: Pension Benefits Other Postretirement Benefits December 31, December 31, 2023 2022 2021 2023 2022 2021 Discount rate 4.95-5.00 % 5.20 2.65-2.75 % 4.85-4.90 % 5.15-5.20 % 2.35-2.40 % Expected rate of return on assets 4.83-6.44 2.66-4.26 3.01-4.17 5.62 4.23 4.08 Long-term rate of increase in compensation levels (non-union) 4.00 4.00 2.84 4.00 4.00 2.84 Long-term rate of increase in compensation levels (union) 4.00 4.00 2.00 4.00 4.00 2.00 Interest crediting rate 3.30-6.00 3.30-6.00 3.30-6.00 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; • Private real estate and broad global opportunistic fixed income asset classes can provide diversification to both equity and liability hedging fixed income investments and that a moderate allocation to each can potentially improve the expected risk-adjusted return for the NorthWestern Energy Pension Plan investments over full market cycles; • 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, 2023 2022 2023 2022 2023 2022 Fixed income securities 45.0 % 45.0 % 90.0 % 90.0 % 40.0 % 40.0 % Non-U.S. fixed income securities — — — 1.0 — — Opportunistic fixed income 11.0 5.5 3.0 — — — Global equities 38.5 44.0 7.0 9.0 60.0 60.0 Private real estate 5.5 5.5 — — — — The actual allocation by plan is as follows: NorthWestern Energy Pension NorthWestern Corporation Pension NorthWestern Energy December 31, December 31, December 31, 2023 2022 2023 2022 2023 2022 Cash and cash equivalents — % — % 1.5 % 1.1 % 0.2 % 0.6 % Fixed income securities 45.3 44.5 88.7 88.6 35.1 36.7 Non-U.S. fixed income securities — — — 0.9 — — Opportunistic fixed income 10.6 5.5 2.9 — — — Global equities 37.6 43.4 6.9 9.4 64.7 62.7 Private real estate 6.5 6.6 — — — — 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. The guidelines allow for a transition to targets over time as assets are reallocated to newly-approved asset classes of opportunistic fixed income and private real estate. Debt securities consist of U.S. and international instruments including emerging markets and high yield instruments, as well as government, corporate, asset backed and mortgage backed securities. While the portfolio may invest in high yield securities, the average quality must be rated at least “investment grade" by rating agencies. Equity, real estate and fixed income portfolios may be comprised of both active and passive management strategies. 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. We also invest in global equities with exposure to developing and emerging markets. Equity investments may also be diversified across investment styles such as growth and value. Derivatives, options and futures are permitted for the purpose of reducing risk but may not be used for speculative purposes. Real estate investments will consist of global equity or debt interests in tangible property consisting of land, buildings, and other improvements in commercial and residential sectors. 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 Energy Group stock is not permitted; however, any holding in a diversified mutual fund or collective investment fund is permitted. 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 2024 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 costs for 2023, 2022 and 2021 were based on actual contributions to the plan. Annual contributions to each of the pension plans are as follows (in thousands): 2023 2022 2021 NorthWestern Energy Pension Plan (MT) $ 8,000 $ 7,000 $ 9,000 NorthWestern Corporation Pension Plan (SD and NE) 1,200 1,200 1,200 $ 9,200 $ 8,200 $ 10,200 We estimate the plans will make future benefit payments to participants as follows (in thousands): Pension Benefits Other Postretirement Benefits 2024 27,553 2,149 2025 28,987 1,813 2026 29,920 1,406 2027 30,545 1,251 2028 31,231 1,210 2029-2033 164,362 5,288 Defined Contribution Plan |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023, there were 649,884 shares of common stock remaining available for grants. The remaining vesting period for awards previously granted ranges from one to four 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. Beginning in 2023, these awards contain service-, market-, and performance-based components. The service-based component of these awards, representing 30 percent of the award, vest at the end of the three-year performance period as long as the individual has remained employed with us over that term. The performance goals are independent of each other and equally weighted at 35 percent of the award, and are based on two metrics: (i) EPS growth level and average return on equity; and (ii) total shareholder return relative to a peer group. Performance unit awards issued prior to 2023 included both the market- and performance-based components discussed above. Fair value is determined for each component of the performance unit awards. The fair value of the service-based component is estimated based upon the closing market price of our common stock as of the grant date less the present value of expected dividends. The fair value of the performance-based component is estimated based upon the closing market price of our common stock as of the grant date 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 market-based component 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: 2023 2022 Risk-free interest rate 4.33 % 1.82 % Expected life, in years 3 3 Expected volatility 30.4% to 41.0% 28.2% to 38.8% Dividend yield 4.4 % 4.5 % The risk-free interest rate was based on the U.S. Treasury yield of a three-year bond at the time of grant. The expected term of the performance shares is three years based on the performance cycle. Expected volatility was based on the historical volatility for the peer group. Both performance goals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares expected to vest. A summary of nonvested shares as of and changes during the year ended December 31, 2023, are as follows: Performance Unit Awards Shares Weighted-Average Grant-Date Beginning nonvested grants 194,407 $ 51.04 Granted 95,853 54.41 Vested (87,300) 50.53 Forfeited (49,176) 51.59 Remaining nonvested grants 153,784 $ 53.26 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. Awards granted before 2022 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. Awards granted in 2022 no longer contain this performance measure, instead these awards will vest after five full calendar years if the employee remains employed during that service period. No retirement/retention restricted shares were granted during the year ended December 31, 2023. 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 grant date less the present value of expected dividends. A summary of nonvested shares as of and changes during the year ended December 31, 2023, are as follows: Shares Weighted-Average Grant-Date Beginning nonvested grants 99,285 $ 48.62 Granted — — Vested — — Forfeited (38,506) 49.73 Remaining nonvested grants 60,779 $ 47.91 We recognized total stock-based compensation expense of $3.6 million, $4.2 million, and $3.9 million for the years ended December 31, 2023, 2022, and 2021, respectively, and related income tax benefit of $(1.0) million, $(1.3) million, and $(0.2) million for the years ended December 31, 2023, 2022, and 2021, respectively. As of December 31, 2023, we had $6.5 million of unrecognized compensation cost related to the nonvested portion of our outstanding awards. The cost is expected to be recognized over a weighted-average period of 2 years. The total fair value of shares vested was $4.4 million, $4.3 million, and $4.2 million for the years ended December 31, 2023, 2022 and 2021, respectively. |
Common Stock
Common Stock | 12 Months Ended |
Dec. 31, 2023 | |
Common Stock, Number of Shares, Par Value and Other Disclosure [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 the common stock, 2,865,957 shares 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 4,167 and 16,120 during the years ended December 31, 2023 and 2022, 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, NW Corp entered into an Equity Distribution Agreement pursuant to which we could 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. During the twelve months ended December 31, 2023, NW Corp issued 1,432,738 shares of our common stock under the ATM program at an average price of $52.02, for net proceeds of $73.6 million, which is net of sales commissions and other fees paid of approximately $0.9 million. We have completed the ATM offering program under this Equity Distribution Agreement. Dividend Restrictions Due to our holding company structure, liquidity necessary to pay dividends to holders of our common stock is generally provided by dividend distributions from our utility subsidiaries. Under various state regulatory agreements, debt agreements and the Federal Power Act, our utility subsidiaries have restrictions, including minimum equity ratios, that limit the amount of dividend distributions that can be made. Pursuant to the MPSC regulatory agreement with NW Corp, if NW Corp's secured credit ratings are above BBB- for S&P Global Ratings and Baa3 for Moody's Investor Services, NW Corp may declare or pay dividends as long as NW Corp's common equity ratio is 40 percent or above. If NW Corp's secured credit ratings are BBB- for S&P Global Ratings or Baa3 for Moody's Investor Services, NW Corp may declare or pay dividends as long as NW Corp's common equity ratio is 43 percent or above. If NW Corp's secured credit ratings fall below BBB- with S&P Global Ratings or Baa3 with Moody's Investor Services, NW Corp may not declare or pay dividends to NorthWestern Energy Group. NorthWestern Energy Group, NW Corp, and NWE Public Service's ability to pay dividends is also limited by the terms of various debt agreements, pursuant to which, NorthWestern Energy Group, NW Corp, and NWE Public Service are required to maintain a debt to capitalization ratio of no more than 0.65 to 1.00. As of December 31, 2023, approximately $920.0 million of NW Corp unrestricted net assets were available for the payment of dividends to NorthWestern Energy Group under our most restrictive dividend restriction. |
Dividend Payment Restrictions | Dividend Restrictions Due to our holding company structure, liquidity necessary to pay dividends to holders of our common stock is generally provided by dividend distributions from our utility subsidiaries. Under various state regulatory agreements, debt agreements and the Federal Power Act, our utility subsidiaries have restrictions, including minimum equity ratios, that limit the amount of dividend distributions that can be made. Pursuant to the MPSC regulatory agreement with NW Corp, if NW Corp's secured credit ratings are above BBB- for S&P Global Ratings and Baa3 for Moody's Investor Services, NW Corp may declare or pay dividends as long as NW Corp's common equity ratio is 40 percent or above. If NW Corp's secured credit ratings are BBB- for S&P Global Ratings or Baa3 for Moody's Investor Services, NW Corp may declare or pay dividends as long as NW Corp's common equity ratio is 43 percent or above. If NW Corp's secured credit ratings fall below BBB- with S&P Global Ratings or Baa3 with Moody's Investor Services, NW Corp may not declare or pay dividends to NorthWestern Energy Group. NorthWestern Energy Group, NW Corp, and NWE Public Service's ability to pay dividends is also limited by the terms of various debt agreements, pursuant to which, NorthWestern Energy Group, NW Corp, and NWE Public Service are required to maintain a debt to capitalization ratio of no more than 0.65 to 1.00. As of December 31, 2023, approximately $920.0 million of NW Corp unrestricted net assets were available for the payment of dividends to NorthWestern Energy Group under our most restrictive dividend restriction. |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 2022 2021 Basic computation 60,321,481 55,769,156 51,709,229 Dilutive effect of Performance and restricted share awards (1) 36,312 26,621 111,940 Forward equity sale (2) — 496,333 51,057 Diluted computation 60,357,793 56,292,110 51,872,226 (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. (2) Forward equity shares 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 forward sale agreement. As of December 31, 2023, there were 25,913 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, 2023 | |
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 $67 to $136 per MWH through 2029. As of December 31, 2023, our estimated gross contractual obligation related to these contracts was approximately $303.1 million through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $266.5 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, 2023 2022 Beginning QF liability $ 49,728 $ 64,943 Settlements (1) (24,707) (20,076) Interest expense 3,649 4,861 Ending QF liability $ 28,670 $ 49,728 (1) The primary components of the change in settlement amounts includes (i) a lower periodic adjustment of $4.2 million due to actual price escalation, which was less than previously modeled; and (ii) higher costs of approximately $1.0 million, due to a $0.8 million reduction in costs for the adjustment to actual output and pricing for the current contract year as compared with a $1.8 million reduction in costs in the prior period. The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands): Gross Recoverable Net 2024 $ 74,110 $ 60,706 $ 13,404 2025 60,360 52,950 7,410 2026 55,393 46,274 9,119 2027 56,665 46,668 9,997 2028 42,400 41,664 736 2029 14,134 18,231 (4,097) Total (1) $ 303,062 $ 266,493 $ 36,569 (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 $340.0 million, $328.0 million and $286.7 million for the years ended December 31, 2023, 2022, and 2021, respectively. As of December 31, 2023, our commitments under these contracts were $321.9 million in 2024, $244.1 million in 2025, $263.4 million in 2026, $243.6 million in 2027, $225.9 million in 2028, 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 $22.4 million between 2024 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 $21.0 million to $31.4 million. As of December 31, 2023, we had a reserve of approximately $25.3 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred. The following summarizes the change in our environmental liability (in thousands): December 31, 2023 2022 2021 Liability at January 1, $ 26,367 $ 26,866 $ 28,895 Deductions (2,520) (2,033) (2,799) Charged to costs and expense 1,439 1,534 770 Liability at December 31, $ 25,286 $ 26,367 $ 26,866 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 $19.8 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, 2023, the reserve for remediation costs at this site was approximately $8.0 million, and we estimate that approximately $2.9 million of this amount will be incurred through 2028. Nebraska - We own sites in North Platte, Kearney, and Grand Island, Nebraska on which former manufactured gas facilities were located. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska sites. Our reserve estimate includes assumptions for site assessment and remedial action work. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations. Montana - We own or have responsibility for sites in Butte, Missoula, and Helena, Montana on which former manufactured gas plants were located. The Butte and Helena sites, both listed as high priority sites on Montana’s state superfund list, were placed into the MDEQ voluntary remediation program for cleanup due to soil and groundwater impacts. Soil and coal tar were removed at the sites in accordance with the MDEQ requirements. Groundwater monitoring is conducted semiannually at both sites. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remedial actions and/or investigations, if any, at the Butte site. In August 2016, the MDEQ sent us a Notice of Potential Liability and Request for Remedial Action regarding the Helena site. In October 2019, we submitted a third revised Remedial Investigation Work Plan (RIWP) for the Helena site addressing MDEQ comments. The MDEQ approved the RIWP in March 2020 and field work was completed in 2022. We submitted a Remedial Investigation Report (RI Report) summarizing the work completed to MDEQ in March 2022 and are awaiting its review and comments as to any additional field work. We now expect the MDEQ review of the RI Report to be concluded in 2024, and any additional field work to commence following that. 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 expressed its intention to submit 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 GHG including, most significantly, carbon dioxide (CO 2 ) and methane emissions from natural gas. These actions include legislative proposals, Executive, Congressional and EPA actions at the federal level, state level activity, investor activism and private party litigation relating to emissions. Coal-fired plants have come under particular scrutiny due to their level of 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. Proposed EPA Rules - 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. Section 111(d) of the Clean Air Act (CAA) confers authority on EPA and the states to regulate emissions, including GHGs, from existing stationary sources. In May 2023, EPA proposed new GHG emissions standards for coal and natural gas-fired plants. In particular, the proposed rules would (i) strengthen the current New Source Performance Standards for newly built fossil fuel-fired stationary combustion turbines (generally natural gas-fired); (ii) establish emission guidelines for states to follow in limiting carbon pollution from existing fossil fuel-fired steam generating electric generating units (including coal, oil and natural gas-fired units); and (iii) establish emission guidelines for large, frequently used existing fossil fuel-fired stationary combustion turbines (generally natural gas-fired). In addition, in April 2023, EPA proposed to amend the MATS. Among other things, MATS currently sets stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. We are in compliance with existing MATS requirements. The proposed amendment of the MATS would strengthen the MATS requirements, and if adopted as written, both the GHG and MATS proposed rules could have a material negative impact on our coal-fired plants, including requiring potentially expensive upgrades or the early retirement of Colstrip Unit's 3 and 4 due to the rules making the facility uneconomic. Previous efforts by the EPA were met with extensive litigation and we anticipate a similar response if the proposed rules are adopted. As MATS and GHG regulations are implemented, it could result in additional material compliance costs. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from any MATS or GHG regulations that, in our view, disproportionately impact customers in our region. Future additional environmental requirements - federal or state - 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 or hazardous air pollutants may not be available within a timeframe consistent with the implementation of any such 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 have developed and submitted to the 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, they were all submitted in 2022. The Montana SIP as drafted and submitted to EPA does not call for additional controls for our interest in Colstrip Unit 4. The draft North Dakota SIP does not require any additional controls at the Coyote generating facility. Similarly, the draft South Dakota SIP does not require any additional controls at the Big Stone generating facility. Until these SIPs are finalized 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 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). On August 1, 2018, the Federal District Court granted our and Talen’s motions to dismiss the State’s Complaint as it pertains to the navigability of the riverbeds associated with four of our hydroelectric facilities near Great Falls. A bench trial before the Federal District Court commenced January 4, 2022, and concluded on January 18, 2022, which addressed the issue of navigability concerning our other six facilities. On August 25, 2023, the Federal District Court issued its Findings of Fact, Conclusions of Law and Order (the "Order"), which found all but one of the segments of the riverbeds in dispute not navigable, and thus not owned by the State of Montana. The one segment found navigable, and thus owned by the State, was the segment on which the Black Eagle development was located. The State filed a motion to pursue an interlocutory appeal of the Order, and on January 2, 2024, the Federal District Court certified the Order for appeal to the 9th Circuit Court of Appeals. Damages were bifurcated by agreement and will be tried separately for the Black Eagle segment, and any other segments found navigable should an appeal be granted and other segments found navigable. We dispute the State’s claims and intend to continue to vigorously defend the lawsuit. If the Federal District Court calculates damages as the State District Court did in 2008, we do not anticipate the resulting annual rent for the Black Eagle segment would have a material impact to our financial position or results of operations. 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 The remaining depreciable life of our investment in Colstrip Unit 4 is through 2042. The six owners of Colstrip Units 3 and 4 currently share the operating costs pursuant to the terms of an Ownership and Operation Agreement (O&O Agreement). However, several of the owners are mandated by Washington and Oregon law to eliminate coal-fired resources in 2025 and 2029, respectively. As a result of the mandate, the owners have disagreed on various operational funding decisions, including whether closure requires each owner’s consent under the O&O Agreement. On March 12, 2021, we initiated an arbitration under the O&O Agreement (the “Arbitration”), to resolve the issues of whether closure requires each owner's consent and to clarify each owner's obligations to continue to fund operations until all joint owners agree on closure. The owners previously initiated efforts to identify arbitrators and have agreed to stay the Arbitration through March 31, 2024, while they explore a potential resolution to their disagreements. Colstrip Coal Dust Litigation On December 14, 2020, a claim was filed against Talen in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. Talen is one of the co-owners of Colstrip Unit 3, and the operator of Units 3 and 4. The plaintiffs allege they have suffered adverse effects from coal dust generated during operations associated with Colstrip. On August 26, 2021, the claim was amended to add in excess of 100 plaintiffs. It also added NorthWestern, the other owners of Colstrip, 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 remains in its discovery stages, we are unable to predict outcomes. We continue to evaluate a range of reasonably possible losses. BNSF Demands for Indemnity and Remediation Costs NorthWestern has received a demand for indemnity from BNSF Railway Company (BNSF) for past and future environmental investigation and remediation costs incurred by BNSF at one of the three operable units at the Anaconda Copper Mining (ACM) Smelter and Refinery Superfund Site, located near Great Falls, Montana. Smelter and refining operations at the site commenced in 1893 and continued until 1980. NorthWestern owns property in the Railroad Corridor sub-section of Operable Unit 1. BNSF claims it is entitled to indemnity and contribution from NorthWestern for the costs it has and will incur to investigate and remediate contamination in Operable Unit 1. NorthWestern and BNSF have settled the majority of the dispute for a non-material sum. Any potential remaining claims are not expected to be material. Yellowstone County Generating Station Air Permit On October 21, 2021, the Montana Environmental Information Center and the Sierra Club filed a lawsuit in Montana State District Court, against the MDEQ and NorthWestern, alleging that the environmental analysis conducted by MDEQ prior to issuance of the Yellowstone County Generating Station's air quality construction permit was inadequate. On April 4, 2023, the Montana District Court issued an order finding MDEQ's environmental analysis was deficient in not addressing exterior lighting and greenhouse gases and remanded it back to MDEQ to address the deficiencies and vacated the air quality permit pending that remand. As a result of the vacatur of the permit, we paused construction. On June 8, 2023, the Montana District Court granted our motion to stay the order vacating the air quality permit pending the outcome of our notice of appeal with the Montana Supreme Court. Oral argument is scheduled for April 22, 2024 and a determination of the appeal will follow. We recommenced construction in June 2023 and expect the plant to be operational no later than the end of the third quarter 2024. The ultimate resolution of the lawsuit challenging the Yellowstone County Generating Station air quality permit could delay the project and increase costs. During the litigation of the air permit, Montana House Bill 971 was signed into law, preventing the MDEQ from, except under certain exceptions, evaluating greenhouse gas emissions and corresponding impacts to the climate in environmental reviews of large projects such as coal mines and power plants. On June 1, 2023, the MDEQ issued its supplemental environmental assessment that contained the updated exterior lighting analysis, and the MDEQ indicated that no other analysis was necessary. The comment period concerning the MDEQ’s supplemental air quality permit ended on July 3, 2023. On August 4, 2023, the Montana First Judicial District Court in Held v. State of Montana, a separate case by Montana youths alleging climate damages, issued its order finding House Bill 971 unconstitutional delaying the issuance of the revised Yellowstone County Generating Station's air permit. The Montana Supreme Court granted NorthWestern permission to participate in the Held appeal. The outcome of the Held case could pose additional delays and costs for the Yellowstone County Generating Station. 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 our opinion, 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, 2023 | |
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, 2023 Electric Natural Gas Total Montana 408.3 136.1 544.4 South Dakota 67.9 36.6 104.5 Nebraska — 35.6 35.6 Residential 476.2 208.3 684.5 Montana 431.4 73.7 505.1 South Dakota 103.2 25.9 129.1 Nebraska — 22.1 22.1 Commercial 534.6 121.7 656.3 Industrial 46.0 1.4 47.4 Lighting, governmental, irrigation, and interdepartmental 32.7 1.7 34.4 Total Customer Revenues 1,089.5 333.1 1,422.6 Other tariff and contract based revenues 86.9 45.3 132.2 Total Revenue from Contracts with Customers 1,176.4 378.4 1,554.8 Regulatory amortization and other (107.6) (25.1) (132.7) Total Revenues $ 1,068.8 $ 353.3 $ 1,422.1 December 31, 2022 Electric Natural Gas Total Montana 357.4 152.3 509.7 South Dakota 69.8 39.2 109.0 Nebraska — 35.8 35.8 Residential 427.2 227.3 654.5 Montana 368.6 79.3 447.9 South Dakota 108.2 28.5 136.7 Nebraska — 22.1 22.1 Commercial 476.8 129.9 606.7 Industrial 39.8 1.5 41.3 Lighting, governmental, irrigation, and interdepartmental 31.0 1.9 32.9 Total Customer Revenues 974.8 360.6 1,335.4 Other Tariff and Contract Based Revenues 85.7 38.3 124.0 Total Revenue from Contracts with Customers 1,060.5 398.9 1,459.4 Regulatory amortization and other 46.1 (27.7) 18.4 Total Revenues $ 1,106.6 $ 371.2 $ 1,477.8 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 and other 33.5 12.0 45.5 Total Revenues $ 1,052.2 $ 320.1 $ 1,372.3 |
Segment and Related Information
Segment and Related Information | 12 Months Ended |
Dec. 31, 2023 | |
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 utility businesses. The remainder of our business activities are presented as other, which primarily consists of unallocated corporate costs and some limited unregulated activity within the energy industry. 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, 2023 Electric Gas Other Eliminations Total Operating revenues $ 1,068,833 $ 353,310 $ — $ — $ 1,422,143 Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 262,755 157,507 — — 420,262 Utility Margin 806,078 195,803 — — 1,001,881 Operating and maintenance 166,028 54,496 — — 220,524 Administrative and general 83,521 32,657 1,182 — 117,360 Property and other taxes 120,289 34,323 (1,544) — 153,068 Depreciation and depletion 174,071 36,403 — — 210,474 Operating income 262,169 37,924 362 — 300,455 Interest expense, net (84,089) (15,719) (14,809) — (114,617) Other income, net 11,580 3,344 908 — 15,832 Income tax (expense) benefit (14,196) 4,627 2,030 — (7,539) Net income (loss) $ 175,464 $ 30,176 $ (11,509) $ — $ 194,131 Total assets $ 6,071,021 $ 1,512,135 $ 17,496 $ — $ 7,600,652 Capital expenditures $ 431,547 $ 135,342 $ — $ — $ 566,889 December 31, 2022 Electric Gas Other Eliminations Total Operating revenues $ 1,106,565 $ 371,272 $ — $ — $ 1,477,837 Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 324,434 167,577 — — 492,011 Utility margin 782,131 203,695 — — 985,826 Operating and maintenance 167,798 53,629 — — 221,427 Administrative and general 82,405 31,002 369 — 113,776 Property and other taxes 149,781 42,734 9 — 192,524 Depreciation and depletion 162,404 32,616 — — 195,020 Operating income (loss) 219,743 43,714 (378) — 263,079 Interest expense, net (74,420) (13,030) (12,660) — (100,110) Other income, net 12,491 6,399 544 — 19,434 Income tax benefit (expense) 798 (3,108) 2,915 — 605 Net income (loss) $ 158,612 $ 33,975 $ (9,579) $ — $ 183,008 Total assets $ 5,892,508 $ 1,418,059 $ 7,216 $ — $ 7,317,783 Capital expenditures $ 409,707 $ 105,433 $ — $ — $ 515,140 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 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 |
Quarterly Financial Data (Unaud
Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 2022 Operating revenues $ 356,009 $ 425,283 Operating income 103,163 83,228 Net income $ 83,142 $ 66,743 Average common shares outstanding 61,244 58,345 Income per average common share: Basic $ 1.37 $ 1.16 Diluted $ 1.37 $ 1.16 |
SEC Schedule, Article 12-04, Co
SEC Schedule, Article 12-04, Condensed Financial Information of Registrant | 12 Months Ended |
Dec. 31, 2023 | |
Condensed Financial Information Disclosure [Abstract] | |
Condensed Financial Information of Parent Company Only Disclosure | SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF NORTHWESTERN ENERGY GROUP NORTHWESTERN ENERGY GROUP CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (PARENT COMPANY ONLY) (in thousands) Year Ended December 31, 2023 Operating Expenses: Administrative and general $ 231 Total Operating Expenses 231 Operating Loss 231 Earnings from investments in subsidiaries, net of tax 83,142 Other income, net 230 Income before income taxes 83,141 Income tax (expense) — Net Income 83,141 Other comprehensive income from subsidiaries, net of tax 365 Comprehensive Income $ 83,506 See Notes to Condensed Financial Statements NORTHWESTERN ENERGY GROUP CONDENSED BALANCE SHEET (PARENT COMPANY ONLY) (in thousands) As of December 31, 2023 ASSETS: Current Assets: Cash and cash equivalents $ 59 Accounts receivable 207 Total current assets 266 Investments in subsidiaries 2,784,924 Other noncurrent assets 4,063 Total Assets $ 2,789,253 LIABILITIES AND SHAREHOLDERS EQUITY Other noncurrent liabilities $ 3,939 Total Liabilities 3,939 Total Shareholders' Equity 2,785,314 Total Liabilities and Shareholders' Equity $ 2,789,253 See Notes to Condensed Financial Statements NORTHWESTERN ENERGY GROUP CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY) (in thousands) Year Ended December 31, 2023 OPERATING ACTIVITIES: Net Income $ 83,141 Adjustments to reconcile net income to cash used in operations: Equity in earnings from subsidiaries, net of tax (83,142) Cash dividends received from subsidiaries 39,042 Changes in assets and liabilities Accounts receivable (207) Cash Provided by Operating Activities 38,834 INVESTING ACTIVITIES: Contributions to subsidiaries — Return of capital from subsidiaries — Cash Provided by Investing Activities — FINANCING ACTIVITIES: Treasury stock activity 351 Dividends on common stock (39,002) Financing costs (124) Cash Used in Financing Activities (38,775) Net Increase in Cash and Cash Equivalents 59 Cash, Cash Equivalents and Restricted Cash, beginning of period — Cash and Cash Equivalents end of period $ 59 See Notes to Condensed Financial Statements NOTES TO CONDENSED FINANCIAL STATEMENTS (1) Basis of Presentation NorthWestern Energy Group is an energy services holding company that conducts substantially all of its business operations through its subsidiaries, NW Corp and NWE Public Service. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These financial statements, in which NorthWestern Energy Groups' subsidiary has been included using the equity method of accounting, should be read in conjunction with the consolidated financial statements and notes thereto of NorthWestern Energy Group contained elsewhere within this Form 10-K. There were $39.0 million of cash dividends paid to NorthWestern Energy Group from wholly-owned subsidiaries for the year ended December 31, 2023. |
Pay vs Performance Disclosure
Pay vs Performance Disclosure - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Pay vs Performance Disclosure | |||||
Net Income | $ 83,142 | $ 66,743 | $ 194,131 | $ 183,008 | $ 186,840 |
Insider Trading Arrangements
Insider Trading Arrangements | 12 Months Ended |
Dec. 31, 2023 | |
Trading Arrangements, by Individual | |
Non-Rule 10b5-1 Arrangement Adopted | false |
Significant Accounting Polici_2
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Estimates are used for such items as long-lived asset values and impairment charges, long-lived asset useful lives, tax provisions, uncertain tax position reserves, AROs, regulatory assets and liabilities, allowances for uncollectible accounts, our QF liability, environmental liabilities, unbilled revenues and actuarially determined benefit costs and liabilities. We revise the recorded estimates when we receive better information or when we can determine actual amounts. Those revisions can affect operating results. |
Revenue Recognition | Revenue Recognition The Company recognizes revenue as customers obtain control of promised goods and services in an amount that reflects consideration expected in exchange for those goods or services. Generally, the delivery of electricity and natural gas results in the transfer of control to customers at the time the commodity is delivered and the amount of revenue recognized is equal to the amount billed to each customer, including estimated volumes delivered when billings have not yet occurred. |
Cash Equivalents | Cash Equivalents We consider all highly liquid investments with maturities of three months or less at the time of purchase to be cash equivalents. |
Restricted cash | Restricted Cash Restricted cash consists primarily of funds held in trust accounts to satisfy the requirements of certain stipulation agreements and insurance reserve requirements. |
Accounts Receivable, Net | Accounts Receivable, Net Accounts receivable are net of allowances for uncollectible accounts of $2.8 million and $2.5 million at December 31, 2023 and December 31, 2022, respectively. Receivables include unbilled revenues of $105.1 million and $117.4 million at December 31, 2023 and December 31, 2022, 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. As of December 31, 2023, the only derivative instruments we have qualify for the normal purchases and normal sales exception. 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 6.4%, 6.4%, and 6.6% for Montana for 2023, 2022, and 2021, respectively. This rate averaged 6.4% for South Dakota in each of 2023, 2022, and 2021. AFUDC capitalized totaled $24.3 million, $20.2 million, and $15.9 million for the years ended December 31, 2023, 2022, and 2021, 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 127 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 2023, 2022, and 2021. 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. 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 |
Revenue from Contracts with C_2
Revenue from Contracts with Customers Accounting Policy (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 | |
Accounting Policies [Abstract] | |
Inventories | Inventories Inventories are stated at average cost. Inventory consisted of the following (in thousands): December 31, 2023 2022 Materials and supplies $ 85,876 $ 71,769 Storage gas and fuel 28,663 35,590 Total Inventories $ 114,539 $ 107,359 |
Schedule of Accrued Liabilities | Accrued Expenses and other Accrued expenses and other consisted of the following (in thousands): December 31, 2023 2022 Property taxes $ 79,252 $ 96,093 Employee compensation, benefits, and withholdings 41,773 44,104 Customer advances 27,656 26,137 Interest 24,775 18,350 Other (none of which is individually significant) 72,711 65,895 Total Accrued Expenses $ 246,167 $ 250,579 |
Other Noncurrent Liabilities | Other Noncurrent Liabilities Other noncurrent liabilities consisted of the following (in thousands): December 31, 2023 2022 Customer advances $ 107,470 $ 95,393 Pension and other employee benefits 75,302 84,731 AROs 39,255 39,096 Future QF obligation, net 28,670 49,728 Environmental 21,135 22,662 Other (none of which is individually significant) 60,540 63,793 Total Noncurrent Liabilities $ 332,372 $ 355,403 |
Supplemental Cash Flow Information | Supplemental Cash Flow Information Year Ended December 31, 2023 2022 2021 (in thousands) Cash paid (received) for: Income taxes $ (827) $ 4,707 $ 4,330 Interest 105,238 95,400 87,221 Significant non-cash transactions: Capital expenditures included in trade accounts payable 42,322 64,758 29,034 New Market Tax Credit (NMTC) debt extinguishment included in other noncurrent assets — — 18,169 NMTC debt extinguishment included in property, plant and equipment, net — — 6,594 NMTC debt extinguishment included in long-term debt — — 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, 2023 2022 2021 Cash and cash equivalents $ 9,164 $ 8,489 $ 2,820 Restricted cash 16,023 13,974 15,942 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows $ 25,187 $ 22,463 $ 18,762 |
Regulated Operations (Tables)
Regulated Operations (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Regulated Operations [Abstract] | |
Montana Rate Review | On August 8, 2022, we filed a Montana electric and natural gas rate review with the MPSC under Docket 2022.07.78 requesting an annual increase to electric and natural gas utility rates. On October 27, 2023, the MPSC issued a final order approving the settlement agreement filed April 3, 2023. Final rates, adjusting from interim to settled rates, were effective November 1, 2023. The details of our settlement agreement are set forth below: Returns, Capital Structure & Revenue Increase Resulting From Approved Settlement Agreement ($ in millions) Electric Natural Gas Return on Equity (ROE) 9.65% 9.55% Equity Capital Structure 48.02% 48.02% Base Rates $67.4 $14.1 PCCAM (1) $69.7 n/a Property Tax (tracker base adjustment) (1) $14.5 $4.2 Total Revenue Increase Through Approved Settlement Agreement $151.6 $18.3 (1) These items are flow-through costs. PCCAM reflects our fuel and purchased power costs. |
Regulatory Assets and Liabili_2
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of Regulatory Assets And Liabilities | Note Reference Remaining Amortization Period December 31, 2023 2022 (in thousands) Flow-through income taxes 12 Plant Lives $ 553,452 $ 509,038 Pension 14 See Note 14 79,638 87,965 Excess deferred income taxes 12 Plant Lives 51,404 54,364 Employee related benefits 14 See Note 14 21,926 27,920 Deferred financing costs 11 See Note 11 20,028 22,620 Environmental clean-up 18 Undetermined 11,131 10,963 Supply costs 1 Year 7,317 101,096 State & local taxes & fees 1 Year 2,733 15,684 Other Various 25,942 22,929 Total Regulatory Assets $ 773,571 $ 852,579 Removal cost 6 Plant Lives $ 523,744 $ 502,289 Excess deferred income taxes 12 Plant Lives 136,382 148,989 State & local taxes & fees 1 Year 30,576 2,327 Supply costs 1 Year 19,691 11,536 Gas storage sales 16 years 6,625 7,046 Environmental clean-up 1 Year — 592 Other Various 1,537 2,579 Total Regulatory Liabilities $ 718,555 $ 675,358 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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): December 31, 2023 2022 (in thousands) Electric Plant $ 5,462,229 $ 5,205,788 Natural Gas Plant 1,506,943 1,371,045 Plant acquisition adjustment (1) 686,328 686,328 Common and Other Plant 267,132 268,970 Construction work in process 377,241 311,652 Total property, plant and equipment 8,299,873 7,843,783 Less accumulated depreciation (1,930,688) (1,880,265) Less accumulated amortization (329,384) (306,038) Net property, plant and equipment $ 6,039,801 $ 5,657,480 |
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, 2023 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 156,696 $ 64,132 $ 52,630 $ 323,793 Accumulated depreciation 44,525 37,178 39,393 127,381 December 31, 2022 Ownership percentages 23.4 % 8.7 % 10.0 % 30.0 % Plant in service $ 155,567 $ 63,032 $ 51,796 $ 326,584 Accumulated depreciation 42,884 35,847 38,955 121,830 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 2022 2021 Liability at January 1, $ 40,894 $ 40,631 $ 45,355 Accretion expense 1,899 1,853 2,233 Liabilities incurred — — — Liabilities settled (1,244) (4,004) (2,906) Revisions to cash flows (125) 2,414 (4,051) Liability at December 31, $ 41,424 $ 40,894 $ 40,631 |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of Goodwill | Goodwill by segment is as follows (in thousands): December 31, 2023 2022 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, 2023 | |
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, 2023 Interest rate contracts Interest Expense $ 612 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 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 $ 14,996 $ — $ — $ — $ 14,996 Rabbi trust investments 17,093 — — — 17,093 Total $ 32,089 $ — $ — $ — $ 32,089 December 31, 2022 Restricted cash equivalents $ 12,990 $ — $ — $ — $ 12,990 Rabbi trust investments 20,895 — — — 20,895 Total $ 33,885 $ — $ — $ — $ 33,885 |
Schedule of Estimated Fair Value of Financial Instruments | The estimated fair value of financial instruments is summarized as follows (in thousands): December 31, 2023 December 31, 2022 Carrying Amount Fair Value Carrying Amount Fair Value Liabilities: Long-term debt $ 2,784,585 $ 2,521,030 $ 2,618,882 $ 2,316,700 |
Short-Term Borrowings and Cre_2
Short-Term Borrowings and Credit Arrangements (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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): 2023 2022 Unsecured revolving line of credit, expiring May 2027 $ — $ 425.0 Unsecured revolving line of credit, expiring November 2028 (1) 425.0 — Unsecured revolving line of credit, expiring April 2024 (2) 100.0 100.0 Unsecured revolving line of credit, expiring March 2025 (2) 25.0 25.0 550.0 550.0 Amounts outstanding at December 31: SOFR borrowings 318.0 450.0 Letters of credit — — 318.0 450.0 Net availability as of December 31 (3) $ 232.0 $ 100.0 |
Long-Term Debt and Capital Le_2
Long-Term Debt and Capital Leases (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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 2023 2022 Unsecured Debt: Unsecured Revolving Line of Credit 2027 $ — $ 425,000 Unsecured Revolving Line of Credit 2028 318,000 — Unsecured Revolving Line of Credit 2024 — 25,000 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 South Dakota—5.57% 2033 31,000 — South Dakota—5.42% 2033 30,000 — 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 100,000 100,000 Montana—5.57% 2033 239,000 — Pollution control obligations— Montana—2.00% 2023 — 144,660 Montana—3.88% 2028 144,660 — Other Long Term Debt: Discount on Notes and Bonds and Debt Issuance Costs, Net — (13,075) (10,778) Total Long-Term Debt $ 2,784,585 $ 2,618,882 Less current maturities (including associated debt issuance costs) (99,950) (144,525) Total Long-Term Debt, Net of Current Maturities $ 2,684,635 $ 2,474,357 Finance Leases: Total Finance Leases Various $ 8,799 $ 11,897 Less current maturities (3,338) (3,098) Total Long-Term Finance Leases $ 5,461 $ 8,799 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Schedule Of Income Tax Expense Domestic | Income tax (benefit) expense is comprised of the following (in thousands): Year Ended December 31, 2023 2022 2021 Federal Current $ 2,925 $ 5,024 $ 722 Deferred 2,929 (5,993) 2,626 Investment tax credits (129) (130) (130) State Current (1,971) 3,363 2,172 Deferred 3,785 (2,869) (1,971) Income Tax Expense (Benefit) $ 7,539 $ (605) $ 3,419 |
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, 2023 2022 2021 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax, net of federal provisions 0.3 0.3 0.1 Flow-through repairs deductions (12.9) (12.4) (11.5) Production tax credits (5.1) (7.2) (6.1) Unregulated Tax Cuts and Jobs Act excess deferred income taxes (1.7) — — Release of unrecognized tax benefits (1.6) — — Amortization of excess deferred income taxes (1.1) (0.9) (0.3) Plant and depreciation of flow through items 3.3 (0.1) (0.6) Reduction to previously claimed alternative minimum tax credit 1.6 — — Prior year permanent return to accrual adjustments 0.0 (0.8) 0.0 Other, net (0.1) (0.2) (0.8) Effective tax rate 3.7 % (0.3) % 1.8 % 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, 2023 2022 2021 Income Before Income Taxes $ 201,670 $ 182,403 $ 190,259 Income tax calculated at federal statutory rate 42,350 38,304 39,954 Permanent or flow through adjustments: State income, net of federal provisions 606 562 354 Flow-through repairs deductions (25,922) (22,665) (21,888) Production tax credits (10,274) (13,166) (11,532) Unregulated Tax Cuts and Jobs Act excess deferred income taxes (3,385) — — Release of unrecognized tax benefits (3,241) — — Amortization of excess deferred income taxes (2,184) (1,657) (635) Plant and depreciation of flow through items 6,595 (222) (941) Reduction to previously claimed alternative minimum tax credit 3,186 — — Prior year permanent return to accrual adjustments 45 (1,397) (12) Other, net (237) (364) (1,881) (34,811) (38,909) (36,535) Income Tax Expense (Benefit) $ 7,539 $ (605) $ 3,419 |
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, 2023 2022 NOL carryforward $ 113,366 — Production tax credit 94,283 $ 80,097 Customer advances 28,300 25,119 Pension / postretirement benefits 15,131 19,291 Compensation accruals 10,716 10,306 Unbilled revenue 10,604 9,440 Environmental liability 5,760 6,009 Interest rate hedges 3,280 3,372 Reserves and accruals 3,098 4,016 Other, net 2,677 2,595 Deferred Tax Asset 287,215 160,245 Excess tax depreciation (660,440) (449,724) Flow through depreciation (120,558) (106,623) Goodwill amortization (88,323) (86,874) Regulatory assets and other (18,414) (56,007) Deferred Tax Liability (887,735) (699,228) Deferred Tax Liability, net $ (600,520) $ (538,983) |
Summary of Income Tax Contingencies | The change in unrecognized tax benefits is as follows (in thousands): 2023 2022 2021 Unrecognized Tax Benefits at January 1 $ 30,330 $ 32,049 $ 33,491 Gross increases - tax positions in prior period — — 293 Gross increases - tax positions in current period — — — Gross decreases - tax positions in current period (2,256) (1,719) (1,735) Lapse of statute of limitations — — — Unrecognized Tax Benefits at December 31 $ 28,074 $ 30,330 $ 32,049 |
Comprehensive Income (Loss) (Ta
Comprehensive Income (Loss) (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 2022 2021 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 $ 2 $ — $ 2 $ (8) $ — $ (8) $ (57) $ — $ (57) Reclassification of net income (loss) on derivative instruments 612 (160) 452 612 (160) 452 614 (162) 452 Postretirement medical liability adjustment (331) 69 (262) (1,359) 377 (982) (585) 149 (436) Other comprehensive (loss) income $ 283 $ (91) $ 192 $ (755) $ 217 $ (538) $ (28) $ (13) $ (41) |
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, 2023 2022 Foreign currency translation $ 1,437 $ 1,435 Derivative instruments designated as cash flow hedges (9,373) (9,825) Postretirement medical plans 280 542 Accumulated other comprehensive loss $ (7,656) $ (7,848) |
Schedule of Accumulated Comprehensive Income (Loss) | The following table displays the changes in AOCL by component, net of tax (in thousands): December 31, 2023 Year Ended Affected Line Item in the Consolidated Statements of Income Interest Rate Derivative Instruments Designated as Cash Flow Hedges Postretirement Medical Plans Foreign Currency Translation Total Beginning balance $ (9,825) $ 542 $ 1,435 $ (7,848) Other comprehensive income before reclassifications — — 2 2 Amounts reclassified from AOCL Interest Expense 452 — — 452 Amounts reclassified from AOCL — (262) — (262) Net current-period other comprehensive income (loss) 452 (262) 2 192 Ending Balance $ (9,373) $ 280 $ 1,437 $ (7,656) December 31, 2022 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 $ (10,277) $ 1,524 $ 1,443 $ (7,310) Other comprehensive loss before reclassifications — — (8) (8) Amounts reclassified from AOCL Interest Expense 452 — — 452 Amounts reclassified from AOCL — (982) — (982) Net current-period other comprehensive income (loss) 452 (982) (8) (538) Ending Balance $ (9,825) $ 542 $ 1,435 $ (7,848) |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 2022 2023 2022 Change in benefit obligation: Obligation at beginning of period $ 521,798 $ 696,802 $ 15,407 $ 17,308 Service cost 5,646 10,223 333 351 Interest cost 25,852 18,787 674 358 Actuarial loss 3,127 (176,389) (1,240) (99) Settlements (1) (51,942) — — — Benefits paid (30,493) (27,625) (1,466) (2,511) Benefit Obligation at End of Period $ 473,988 $ 521,798 $ 13,708 $ 15,407 Change in Fair Value of Plan Assets: Fair value of plan assets at beginning of period $ 441,539 $ 605,499 $ 20,055 $ 25,289 Return on plan assets 34,367 (144,535) 3,334 (4,098) Employer contributions 9,200 8,200 386 1,375 Settlements (1) (51,942) — — — Benefits paid (30,493) (27,625) (1,466) (2,511) Fair value of plan assets at end of period $ 402,671 $ 441,539 $ 22,309 $ 20,055 Funded Status $ (71,317) $ (80,259) $ 8,601 $ 4,648 Amounts Recognized in the Balance Sheet Consist of: Noncurrent asset 7,875 7,195 12,378 8,831 Total Assets 7,875 7,195 12,378 8,831 Current liability (11,200) (11,200) (1,355) (1,585) Noncurrent liability (67,992) (76,254) (2,422) (2,598) Total Liabilities (79,192) (87,454) (3,777) (4,183) Net amount recognized $ (71,317) $ (80,259) $ 8,601 $ 4,648 Amounts Recognized in Regulatory Assets Consist of: Prior service credit — — — (116) Net actuarial (loss) gain (44,453) (54,383) 15 (3,123) Amounts recognized in AOCL consist of: Prior service cost — — — — Net actuarial gain — — 590 1,046 Total $ (44,453) $ (54,383) $ 605 $ (2,193) (1) In October 2023, we entered into a group annuity contract from an insurance company to provide for the payment of pension benefits to 285 NorthWestern Energy Pension Plan participants. We purchased the contract with $51.9 million of plan assets. The insurance company took over the payments of these benefits starting January 1, 2024. This transaction settled $51.9 million of our NorthWestern Energy Pension Plan obligation. As a result of this transaction, during the twelve months ended December 31, 2023, we recorded a non-cash, non-operating settlement charge of $4.4 million. This charge is recorded within other income, net on the Consolidated Statements of Income. As discussed within Note 4 – Regulatory Assets and Liabilities , the MPSC allows recovery of pension costs on a cash funding basis. As such, 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, 2023 2022 Projected benefit obligation $ 427.3 $ 474.9 Accumulated benefit obligation 427.3 474.9 Fair value of plan assets 348.1 388.7 As of December 31, 2023, 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, 2023 2022 2021 2023 2022 2021 Components of Net Periodic Benefit Cost Service cost $ 5,646 $ 10,223 $ 12,994 $ 333 $ 351 $ 407 Interest cost 25,852 18,787 18,759 674 359 327 Expected return on plan assets (25,932) (24,173) (27,061) (1,096) (1,047) (919) Amortization of prior service cost (credit) — — — 116 (1,891) (1,835) Recognized actuarial loss (gain) 228 383 6,536 (672) (897) (898) Settlement loss recognized (1) 4,395 — 11,291 — — — Net Periodic Benefit Cost (Credit) $ 10,189 $ 5,220 $ 22,519 $ (645) $ (3,125) $ (2,918) Regulatory deferral of net periodic benefit cost (2) (1,814) 2,307 (13,308) — — — Previously deferred costs recognized (2) 210 — — 550 292 709 Net Periodic Benefit Cost Recognized $ 8,585 $ 7,527 $ 9,211 $ (95) $ (2,833) $ (2,209) (1) Settlement losses are related to partial annuitization of NorthWestern Energy Pension Plan effective October 24, 2023 and December 1, 2021, respectively. (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, 2023 2022 2021 2023 2022 2021 Discount rate 4.95-5.00 % 5.20 2.65-2.75 % 4.85-4.90 % 5.15-5.20 % 2.35-2.40 % Expected rate of return on assets 4.83-6.44 2.66-4.26 3.01-4.17 5.62 4.23 4.08 Long-term rate of increase in compensation levels (non-union) 4.00 4.00 2.84 4.00 4.00 2.84 Long-term rate of increase in compensation levels (union) 4.00 4.00 2.00 4.00 4.00 2.00 Interest crediting rate 3.30-6.00 3.30-6.00 3.30-6.00 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, 2023 2022 2023 2022 2023 2022 Fixed income securities 45.0 % 45.0 % 90.0 % 90.0 % 40.0 % 40.0 % Non-U.S. fixed income securities — — — 1.0 — — Opportunistic fixed income 11.0 5.5 3.0 — — — Global equities 38.5 44.0 7.0 9.0 60.0 60.0 Private real estate 5.5 5.5 — — — — |
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, 2023 2022 2023 2022 2023 2022 Cash and cash equivalents — % — % 1.5 % 1.1 % 0.2 % 0.6 % Fixed income securities 45.3 44.5 88.7 88.6 35.1 36.7 Non-U.S. fixed income securities — — — 0.9 — — Opportunistic fixed income 10.6 5.5 2.9 — — — Global equities 37.6 43.4 6.9 9.4 64.7 62.7 Private real estate 6.5 6.6 — — — — 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): 2023 2022 2021 NorthWestern Energy Pension Plan (MT) $ 8,000 $ 7,000 $ 9,000 NorthWestern Corporation Pension Plan (SD and NE) 1,200 1,200 1,200 $ 9,200 $ 8,200 $ 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 2024 27,553 2,149 2025 28,987 1,813 2026 29,920 1,406 2027 30,545 1,251 2028 31,231 1,210 2029-2033 164,362 5,288 |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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: 2023 2022 Risk-free interest rate 4.33 % 1.82 % Expected life, in years 3 3 Expected volatility 30.4% to 41.0% 28.2% to 38.8% Dividend yield 4.4 % 4.5 % |
Schedule of Nonvested Share Activity | A summary of nonvested shares as of and changes during the year ended December 31, 2023, are as follows: Performance Unit Awards Shares Weighted-Average Grant-Date Beginning nonvested grants 194,407 $ 51.04 Granted 95,853 54.41 Vested (87,300) 50.53 Forfeited (49,176) 51.59 Remaining nonvested grants 153,784 $ 53.26 |
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, 2023, are as follows: Shares Weighted-Average Grant-Date Beginning nonvested grants 99,285 $ 48.62 Granted — — Vested — — Forfeited (38,506) 49.73 Remaining nonvested grants 60,779 $ 47.91 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 2022 2021 Basic computation 60,321,481 55,769,156 51,709,229 Dilutive effect of Performance and restricted share awards (1) 36,312 26,621 111,940 Forward equity sale (2) — 496,333 51,057 Diluted computation 60,357,793 56,292,110 51,872,226 (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. (2) Forward equity shares 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 forward sale agreement. As of December 31, 2023, there were 25,913 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, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Changes In Qualifying Facility Liability | The following summarizes the change in the liability (in thousands): December 31, 2023 2022 Beginning QF liability $ 49,728 $ 64,943 Settlements (1) (24,707) (20,076) Interest expense 3,649 4,861 Ending QF liability $ 28,670 $ 49,728 (1) The primary components of the change in settlement amounts includes (i) a lower periodic adjustment of $4.2 million due to actual price escalation, which was less than previously modeled; and (ii) higher costs of approximately $1.0 million, due to a $0.8 million reduction in costs for the adjustment to actual output and pricing for the current contract year as compared with a $1.8 million reduction in costs in the prior period. |
Schedule of Estimated Gross Contractual Obligation Less Amounts Recoverable Through Rates | The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands): Gross Recoverable Net 2024 $ 74,110 $ 60,706 $ 13,404 2025 60,360 52,950 7,410 2026 55,393 46,274 9,119 2027 56,665 46,668 9,997 2028 42,400 41,664 736 2029 14,134 18,231 (4,097) Total (1) $ 303,062 $ 266,493 $ 36,569 |
Schedule of Environmental Loss Contingencies by Site | The following summarizes the change in our environmental liability (in thousands): December 31, 2023 2022 2021 Liability at January 1, $ 26,367 $ 26,866 $ 28,895 Deductions (2,520) (2,033) (2,799) Charged to costs and expense 1,439 1,534 770 Liability at December 31, $ 25,286 $ 26,367 $ 26,866 |
Revenue from Contracts with C_3
Revenue from Contracts with Customers Disaggregation of Revenue (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 Electric Natural Gas Total Montana 408.3 136.1 544.4 South Dakota 67.9 36.6 104.5 Nebraska — 35.6 35.6 Residential 476.2 208.3 684.5 Montana 431.4 73.7 505.1 South Dakota 103.2 25.9 129.1 Nebraska — 22.1 22.1 Commercial 534.6 121.7 656.3 Industrial 46.0 1.4 47.4 Lighting, governmental, irrigation, and interdepartmental 32.7 1.7 34.4 Total Customer Revenues 1,089.5 333.1 1,422.6 Other tariff and contract based revenues 86.9 45.3 132.2 Total Revenue from Contracts with Customers 1,176.4 378.4 1,554.8 Regulatory amortization and other (107.6) (25.1) (132.7) Total Revenues $ 1,068.8 $ 353.3 $ 1,422.1 December 31, 2022 Electric Natural Gas Total Montana 357.4 152.3 509.7 South Dakota 69.8 39.2 109.0 Nebraska — 35.8 35.8 Residential 427.2 227.3 654.5 Montana 368.6 79.3 447.9 South Dakota 108.2 28.5 136.7 Nebraska — 22.1 22.1 Commercial 476.8 129.9 606.7 Industrial 39.8 1.5 41.3 Lighting, governmental, irrigation, and interdepartmental 31.0 1.9 32.9 Total Customer Revenues 974.8 360.6 1,335.4 Other Tariff and Contract Based Revenues 85.7 38.3 124.0 Total Revenue from Contracts with Customers 1,060.5 398.9 1,459.4 Regulatory amortization and other 46.1 (27.7) 18.4 Total Revenues $ 1,106.6 $ 371.2 $ 1,477.8 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 and other 33.5 12.0 45.5 Total Revenues $ 1,052.2 $ 320.1 $ 1,372.3 |
Segment and Related Informati_2
Segment and Related Information (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 Electric Gas Other Eliminations Total Operating revenues $ 1,068,833 $ 353,310 $ — $ — $ 1,422,143 Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 262,755 157,507 — — 420,262 Utility Margin 806,078 195,803 — — 1,001,881 Operating and maintenance 166,028 54,496 — — 220,524 Administrative and general 83,521 32,657 1,182 — 117,360 Property and other taxes 120,289 34,323 (1,544) — 153,068 Depreciation and depletion 174,071 36,403 — — 210,474 Operating income 262,169 37,924 362 — 300,455 Interest expense, net (84,089) (15,719) (14,809) — (114,617) Other income, net 11,580 3,344 908 — 15,832 Income tax (expense) benefit (14,196) 4,627 2,030 — (7,539) Net income (loss) $ 175,464 $ 30,176 $ (11,509) $ — $ 194,131 Total assets $ 6,071,021 $ 1,512,135 $ 17,496 $ — $ 7,600,652 Capital expenditures $ 431,547 $ 135,342 $ — $ — $ 566,889 December 31, 2022 Electric Gas Other Eliminations Total Operating revenues $ 1,106,565 $ 371,272 $ — $ — $ 1,477,837 Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below) 324,434 167,577 — — 492,011 Utility margin 782,131 203,695 — — 985,826 Operating and maintenance 167,798 53,629 — — 221,427 Administrative and general 82,405 31,002 369 — 113,776 Property and other taxes 149,781 42,734 9 — 192,524 Depreciation and depletion 162,404 32,616 — — 195,020 Operating income (loss) 219,743 43,714 (378) — 263,079 Interest expense, net (74,420) (13,030) (12,660) — (100,110) Other income, net 12,491 6,399 544 — 19,434 Income tax benefit (expense) 798 (3,108) 2,915 — 605 Net income (loss) $ 158,612 $ 33,975 $ (9,579) $ — $ 183,008 Total assets $ 5,892,508 $ 1,418,059 $ 7,216 $ — $ 7,317,783 Capital expenditures $ 409,707 $ 105,433 $ — $ — $ 515,140 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 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 |
Quarterly Financial Data (Una_2
Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information | Amounts presented are in thousands, except per share data: Three Months Ended December 31, 2023 2022 Operating revenues $ 356,009 $ 425,283 Operating income 103,163 83,228 Net income $ 83,142 $ 66,743 Average common shares outstanding 61,244 58,345 Income per average common share: Basic $ 1.37 $ 1.16 Diluted $ 1.37 $ 1.16 |
Condensed Financials Standalone
Condensed Financials Standalone NorthWestern Energy Group (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Condensed Financial Information Disclosure [Abstract] | |
Condensed Income Statement | NORTHWESTERN ENERGY GROUP CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (PARENT COMPANY ONLY) (in thousands) Year Ended December 31, 2023 Operating Expenses: Administrative and general $ 231 Total Operating Expenses 231 Operating Loss 231 Earnings from investments in subsidiaries, net of tax 83,142 Other income, net 230 Income before income taxes 83,141 Income tax (expense) — Net Income 83,141 Other comprehensive income from subsidiaries, net of tax 365 Comprehensive Income $ 83,506 See Notes to Condensed Financial Statements |
Condensed Balance Sheet | NORTHWESTERN ENERGY GROUP CONDENSED BALANCE SHEET (PARENT COMPANY ONLY) (in thousands) As of December 31, 2023 ASSETS: Current Assets: Cash and cash equivalents $ 59 Accounts receivable 207 Total current assets 266 Investments in subsidiaries 2,784,924 Other noncurrent assets 4,063 Total Assets $ 2,789,253 LIABILITIES AND SHAREHOLDERS EQUITY Other noncurrent liabilities $ 3,939 Total Liabilities 3,939 Total Shareholders' Equity 2,785,314 Total Liabilities and Shareholders' Equity $ 2,789,253 See Notes to Condensed Financial Statements |
Condensed Cash Flow Statement | NORTHWESTERN ENERGY GROUP CONDENSED STATEMENTS OF CASH FLOWS (PARENT COMPANY ONLY) (in thousands) Year Ended December 31, 2023 OPERATING ACTIVITIES: Net Income $ 83,141 Adjustments to reconcile net income to cash used in operations: Equity in earnings from subsidiaries, net of tax (83,142) Cash dividends received from subsidiaries 39,042 Changes in assets and liabilities Accounts receivable (207) Cash Provided by Operating Activities 38,834 INVESTING ACTIVITIES: Contributions to subsidiaries — Return of capital from subsidiaries — Cash Provided by Investing Activities — FINANCING ACTIVITIES: Treasury stock activity 351 Dividends on common stock (39,002) Financing costs (124) Cash Used in Financing Activities (38,775) Net Increase in Cash and Cash Equivalents 59 Cash, Cash Equivalents and Restricted Cash, beginning of period — Cash and Cash Equivalents end of period $ 59 See Notes to Condensed Financial Statements |
Nature of Operations and Basi_2
Nature of Operations and Basis of Consolidation (Details) | Dec. 31, 2023 customers |
Number of customers | 775,300 |
Significant Accounting Polici_4
Significant Accounting Policies Narrative (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 USD ($) Months | Dec. 31, 2022 USD ($) | |
Number of months or less of maturity to be considered cash equivalent | Months | 3 | |
Allowance for doubtful accounts receivable, current | $ 2.8 | $ 2.5 |
Unbilled receivables,current | $ 105.1 | $ 117.4 |
Significant Accounting Polici_5
Significant Accounting Policies Inventory (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Accounting Policies [Abstract] | ||
Materials and supplies | $ 85,876 | $ 71,769 |
Storage gas and fuel | 28,663 | 35,590 |
Total Inventories | $ 114,539 | $ 107,359 |
Significant Accounting Polici_6
Significant Accounting Policies Property plant equipment (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
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 | $ 24.3 | $ 20.2 | $ 15.9 |
Montana | |||
Property, Plant and Equipment [Line Items] | |||
Allowance for funds used during construction, rate | 6.40% | 6.40% | 6.60% |
South Dakota | |||
Property, Plant and Equipment [Line Items] | |||
Allowance for funds used during construction, rate | 6.40% | ||
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 | 127 years |
Significant Accounting Polici_7
Significant Accounting Policies Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Accounting Policies [Abstract] | ||
Property taxes | $ 79,252 | $ 96,093 |
Employee compensation, benefits, and withholdings | 41,773 | 44,104 |
Customer advances | 27,656 | 26,137 |
Interest | 24,775 | 18,350 |
Other (none of which is individually significant) | 72,711 | 65,895 |
Total Accrued Expenses | $ 246,167 | $ 250,579 |
Significant Accounting Polici_8
Significant Accounting Policies Other Noncurrent Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Accounting Policies [Abstract] | ||
Pension and other employee benefits | $ 75,302 | $ 84,731 |
Customer advances | 107,470 | 95,393 |
Future QF obligation, net | 28,670 | 49,728 |
AROs | 39,255 | 39,096 |
Environmental | 21,135 | 22,662 |
Other (none of which is individually significant) | 60,540 | 63,793 |
Total Noncurrent Liabilities | $ 332,372 | $ 355,403 |
Significant Accounting Polici_9
Significant Accounting Policies Supplemental Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Income taxes | $ (827) | $ 4,707 | $ 4,330 |
Interest | 105,238 | 95,400 | 87,221 |
Capital expenditures included in trade accounts payable | 42,322 | 64,758 | 29,034 |
New Market Tax Credit [Member] | Debt Extinguishment included in other noncurrent assets | |||
New Market Tax Credit (NMTC) debt extinguishment included in other noncurrent assets | 0 | 0 | 18,169 |
New Market Tax Credit [Member] | Debt Extinguishment included in property, plant, and equipment, net | |||
NMTC debt extinguishment included in property, plant and equipment, net | 0 | 0 | 6,594 |
New Market Tax Credit [Member] | Debt Extinguishment included in long term debt | |||
NMTC debt extinguishment included in property, plant and equipment, net | $ 0 | $ 0 | $ 1,259 |
Significant Accounting Polic_10
Significant Accounting Policies Reconciliation of Cash and Restricted Cash (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Accounting Policies [Abstract] | ||||
Cash and cash equivalents | $ 9,164 | $ 8,489 | $ 2,820 | |
Restricted cash | 16,023 | 13,974 | 15,942 | |
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows | $ 25,187 | $ 22,463 | $ 18,762 | $ 17,096 |
Regulatory Matters (Details)
Regulatory Matters (Details) | 12 Months Ended |
Dec. 31, 2023 USD ($) Rate | |
South Dakota | |
Public Utilities, General Disclosures [Line Items] | |
Requested Rate base | $ 787,300,000 |
Electric | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 151,600,000 |
Electric | Montana | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Approved Return on Equity, Percentage | 9.65% |
Public Utilities, Approved Equity Capital Structure, Percentage | Rate | 48.02% |
PCCAM base costs amount | $ 138,700,000 |
Public Utilities, PCCAM base costs approved through settlement agreement | $ 208,400,000 |
Electric | South Dakota | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Requested Equity Capital Structure, Percentage | Rate | 50.50% |
Public Utilities, Approved Equity Capital Structure, Percentage | Rate | 50.50% |
Public Utilities, Approved Rate of Return | Rate | 6.81% |
Approved Rate base | $ 791,800,000 |
Requested Rate of Return | Rate | 7.54% |
Electric | Base electric rate | Montana | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 67,400,000 |
Electric | Base electric rate | South Dakota | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Requested Rate Increase (Decrease), Amount | 30,900,000 |
Public Utilities, Approved Rate Increase (Decrease), Amount | 21,500,000 |
Electric | PCCAM base amount | Montana | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Approved Rate Increase (Decrease), Amount | 69,700,000 |
Electric | Electric property tax tracker true-up | Montana | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Approved Rate Increase (Decrease), Amount | 14,500,000 |
Gas Domestic Regulated [Member] | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 18,300,000 |
Gas Domestic Regulated [Member] | Montana | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Approved Return on Equity, Percentage | 9.55% |
Public Utilities, Approved Equity Capital Structure, Percentage | Rate | 48.02% |
Gas Domestic Regulated [Member] | Base natural gas rate | Montana | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 14,100,000 |
Gas Domestic Regulated [Member] | Natural gas property tax tracker true-up | Montana | |
Public Utilities, General Disclosures [Line Items] | |
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 4,200,000 |
Regulatory Assets and Liabili_3
Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities | $ 39,957 | $ (7,034) | $ (27,674) |
Regulatory Assets [Member] | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets | 773,571 | 852,579 | |
Regulatory Assets [Member] | Flow-through income taxes | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets | 553,452 | 509,038 | |
Regulatory Assets [Member] | Pension | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets | 79,638 | 87,965 | |
Regulatory Assets [Member] | Excess deferred income taxes | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets | 51,404 | 54,364 | |
Regulatory Assets [Member] | Employee related benefits | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets | 21,926 | 27,920 | |
Regulatory Assets [Member] | Deferred financing costs | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets | 20,028 | 22,620 | |
Regulatory Assets [Member] | Environmental clean-up | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets | 11,131 | 10,963 | |
Regulatory Assets [Member] | Supply costs | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets | $ 7,317 | 101,096 | |
Regulatory assets, remaining amortization period | 1 year | ||
Regulatory Assets [Member] | State & local taxes & fees | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets | $ 2,733 | 15,684 | |
Regulatory Assets [Member] | Other | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets | 25,942 | 22,929 | |
Regulatory Liabilities [Member] | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities | 718,555 | 675,358 | |
Regulatory Liabilities [Member] | Removal cost | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities | 523,744 | 502,289 | |
Regulatory Liabilities [Member] | Excess deferred income taxes | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities | 136,382 | 148,989 | |
Regulatory Liabilities [Member] | State & local taxes & fees | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities | $ 30,576 | 2,327 | |
Regulatory liability, remaining amortization period | 1 year | ||
Regulatory Liabilities [Member] | Supply costs | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities | $ 19,691 | 11,536 | |
Regulatory liability, remaining amortization period | 1 year | ||
Regulatory Liabilities [Member] | Gas storage sales | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities | $ 6,625 | 7,046 | |
Regulatory liability, remaining amortization period | 16 years | ||
Regulatory Liabilities [Member] | Environmental clean-up | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities | $ 0 | 592 | |
Regulatory Liabilities [Member] | Environmental remediation obligations [Member] | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liability, remaining amortization period | 1 year | ||
Regulatory Liabilities [Member] | Other | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities | $ 1,537 | $ 2,579 | |
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 | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory liabilities | $ 39,957 | $ (7,034) | $ (27,674) |
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% | ||
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 Assets [Member] | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets | $ 773,571 | 852,579 | |
Regulatory Assets [Member] | Flow-through income taxes | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets | 553,452 | 509,038 | |
Regulatory Assets [Member] | Wildfire mitigation | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory assets | 1,600 | ||
Regulatory Liabilities [Member] | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory Liabilities | 718,555 | 675,358 | |
Regulatory Liabilities [Member] | State & local taxes & fees | |||
Regulatory Assets And Liabilities [Line Items] | |||
Regulatory Liabilities | $ 30,576 | $ 2,327 |
Property, Plant and Equipment_2
Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Property, Plant and Equipment [Line Items] | ||
Total property, plant and equipment | $ 8,299,873 | $ 7,843,783 |
Less accumulated depreciation | 1,930,688 | 1,880,265 |
Net property, plant and equipment | $ 6,039,801 | 5,657,480 |
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Property, plant, and equipment, net | |
Electric Plant | ||
Property, Plant and Equipment [Line Items] | ||
Public Utilities, Property, Plant and Equipment, Equipment | $ 5,462,229 | 5,205,788 |
Natural Gas Plant | ||
Property, Plant and Equipment [Line Items] | ||
Public Utilities, Property, Plant and Equipment, Equipment | 1,506,943 | 1,371,045 |
Plant Acquisition adjustment [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Plant acquisition adjustment(1) | 686,328 | 686,328 |
Common Plant | ||
Property, Plant and Equipment [Line Items] | ||
Common and Other Plant | 267,132 | 268,970 |
Construction work in progress | ||
Property, Plant and Equipment [Line Items] | ||
Construction work in process | 377,241 | 311,652 |
Computer Software, Intangible Asset | ||
Property, Plant and Equipment [Line Items] | ||
Less accumulated amortization | (329,384) | (306,038) |
Property, Plant and Equipment [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Finance Lease, Right-of-Use Asset, after Accumulated Amortization | 5,200 | 7,200 |
Basin Capital Lease [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Finance Lease, Right-of-Use Asset, after Accumulated Amortization | $ 5,000 | $ 7,000 |
Property, Plant and Equipment J
Property, Plant and Equipment Joint Ownership (Details) | 12 Months Ended | |
Dec. 31, 2023 USD ($) plants | Dec. 31, 2022 USD ($) | |
Jointly Owned Utility Plant Interests [Line Items] | ||
Number of joint ownership interests in electric generating plants | plants | 4 | |
Asset Acquisition, Price of Acquisition, Expected | $ 0 | |
Colstrip Ownership in Unit 3 and 4, effective December 31, 2025 Acquired from Avista Corporation | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Asset Acquisition, Effective Date of Acquisition | Dec. 31, 2025 | |
Big Stone Generating Facility [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership percentages | 23.40% | 23.40% |
Plant in service | $ 156,696,000 | $ 155,567,000 |
Accumulated depreciation | $ 44,525,000 | $ 42,884,000 |
Neal 4 Generating Facility [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership percentages | 8.70% | 8.70% |
Plant in service | $ 64,132,000 | $ 63,032,000 |
Accumulated depreciation | $ 37,178,000 | $ 35,847,000 |
Coyote Generating Facility [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership percentages | 10% | 10% |
Plant in service | $ 52,630,000 | $ 51,796,000 |
Accumulated depreciation | $ 39,393,000 | $ 38,955,000 |
Colstrip Unit 4 [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership percentages | 30% | 30% |
Plant in service | $ 323,793,000 | $ 326,584,000 |
Accumulated depreciation | $ 127,381,000 | $ 121,830,000 |
Colstrip Ownership in Unit 3 and 4, effective December 31, 2025 Acquired from Avista Corporation | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership percentages | 15% |
Asset Retirement Obligations Ro
Asset Retirement Obligations Rollforward (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Liability at January 1, | $ 40,894 | $ 40,631 | $ 45,355 |
Accretion expense | 1,899 | 1,853 | 2,233 |
Liabilities incurred | 0 | 0 | 0 |
Liabilities settled | (1,244) | (4,004) | (2,906) |
Revision to cash flows | (125) | 2,414 | (4,051) |
Liability at December 31, | $ 41,424 | $ 40,894 | $ 40,631 |
Asset Retirement Obligations Na
Asset Retirement Obligations Narrative (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Asset Retirement Obligation Disclosure [Abstract] | |||
Asset Retirement Obligation, Liabilities Settled | $ 1,244 | $ 4,004 | $ 2,906 |
Goodwill (Details)
Goodwill (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Goodwill [Line Items] | ||
Goodwill | $ 357,586 | $ 357,586 |
Electric | ||
Goodwill [Line Items] | ||
Goodwill | 243,558 | 243,558 |
Natural gas | ||
Goodwill [Line Items] | ||
Goodwill | $ 114,028 | $ 114,028 |
Risk Management and Hedging A_3
Risk Management and Hedging Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
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 | 12,800 | |
Interest Rate Swap [Member] | Interest Expense [Member] | ||
Derivative [Line Items] | ||
Interest rate contracts, amount of gain reclassified from AOCL into income | $ 612 |
Fair Value Measurements Fair Va
Fair Value Measurements Fair Value Recurring Basis (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
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 | 14,996 | 12,990 |
Rabbi trust investments | 17,093 | 20,895 |
Total | 32,089 | 33,885 |
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 | 14,996 | 12,990 |
Rabbi trust investments | 17,093 | 20,895 |
Total | 32,089 | 33,885 |
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, 2023 | Dec. 31, 2022 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, carrying value | $ 2,784,585 | $ 2,618,882 |
Long-term debt, fair value | $ 2,521,030 | $ 2,316,700 |
Short-Term Borrowings and Cre_3
Short-Term Borrowings and Credit Arrangements (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | $ 550,000,000 | $ 550,000,000 |
Maximum Ratio Of Indebtedness To Net Capital Threshold Percentage | 65% | |
Revolving Credit Facility [Member] | ||
Line of Credit Facility [Line Items] | ||
Commitment fees | $ 600,000 | 100,000 |
Revolving Credit Facility [Member] | Measurement Input, Credit Spread [Member] | Minimum [Member] | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 1% | |
Revolving Credit Facility [Member] | Measurement Input, Credit Spread [Member] | Maximum [Member] | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 1.75% | |
Revolving Credit Facility [Member] | Base Rate | Minimum [Member] | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0% | |
Revolving Credit Facility [Member] | Base Rate | Maximum [Member] | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0.75% | |
Swingline Credit Facility [Member] | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | $ 25,000,000 | 25,000,000 |
Line of credit facility, expiration date | Mar. 27, 2025 | |
Swingline Credit Facility [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0.90% | |
Swingline Credit Facility [Member] | Base Rate | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0.125% | |
Revolving Credit Facility Due 2024 | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | $ 100,000,000 | 100,000,000 |
Line of credit facility, expiration date | Apr. 28, 2024 | |
Revolving Credit Facility Due 2027 | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | $ 0 | 425,000,000 |
Unsecured Revolving Line of Credit | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0.10% | |
Revolving Credit Facility Due 2028 [Member] | ||
Line of Credit Facility [Line Items] | ||
Line of credit facility, expiration date | Nov. 29, 2028 | |
Revolving Credit Facility Due 2028 [Member] | NWE Public Service | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility, Current Borrowing Capacity | $ 200,000,000 | |
Credit Facility Increase to Maximum Borrowing Capacity | 50,000,000 | |
Line Of Credit Facility Base Sublimit | 150,000,000 | |
Revolving Credit Facility Due 2028 [Member] | NorthWestern Energy Group, Inc. | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility, Current Borrowing Capacity | 200,000,000 | |
Credit Facility Increase to Maximum Borrowing Capacity | 50,000,000 | |
Line Of Credit Facility Base Sublimit | 50,000,000 | |
Revolving Credit Facility Due 2028 [Member] | NW Corp | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | $ 425,000,000 | $ 0 |
Revolving Credit Facility Due 2028 [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0.10% | |
Revolving Credit Facility Due 2028 [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | NWE Public Service | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0.10% | |
Revolving Credit Facility Due 2028 [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | NorthWestern Energy Group, Inc. | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0.10% | |
Revolving Credit Facility Due 2028 [Member] | Measurement Input, Credit Spread [Member] | Minimum [Member] | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 1% | |
Revolving Credit Facility Due 2028 [Member] | Measurement Input, Credit Spread [Member] | Minimum [Member] | NWE Public Service | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 1% | |
Revolving Credit Facility Due 2028 [Member] | Measurement Input, Credit Spread [Member] | Minimum [Member] | NorthWestern Energy Group, Inc. | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 1% | |
Revolving Credit Facility Due 2028 [Member] | Measurement Input, Credit Spread [Member] | Maximum [Member] | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 1.75% | |
Revolving Credit Facility Due 2028 [Member] | Measurement Input, Credit Spread [Member] | Maximum [Member] | NWE Public Service | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 1.75% | |
Revolving Credit Facility Due 2028 [Member] | Measurement Input, Credit Spread [Member] | Maximum [Member] | NorthWestern Energy Group, Inc. | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 1.75% | |
Revolving Credit Facility Due 2028 [Member] | Base Rate | Minimum [Member] | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0% | |
Revolving Credit Facility Due 2028 [Member] | Base Rate | Minimum [Member] | NWE Public Service | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0% | |
Revolving Credit Facility Due 2028 [Member] | Base Rate | Minimum [Member] | NorthWestern Energy Group, Inc. | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0% | |
Revolving Credit Facility Due 2028 [Member] | Base Rate | Maximum [Member] | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0.75% | |
Revolving Credit Facility Due 2028 [Member] | Base Rate | Maximum [Member] | NWE Public Service | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0.75% | |
Revolving Credit Facility Due 2028 [Member] | Base Rate | Maximum [Member] | NorthWestern Energy Group, Inc. | ||
Line of Credit Facility [Line Items] | ||
Basis spread on variable rate | 0.75% | |
Revolving Credit Facility Due 2028 - Effective January 1, 2024 | NWE Public Service | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | $ 200,000,000 | |
Revolving Credit Facility Due 2028 - Effective January 1, 2024 | NorthWestern Energy Group, Inc. | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | 100,000,000 | |
Revolving Credit Facility Due 2028 - Effective January 1, 2024 | NW Corp | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | $ 400,000,000 |
Short-Term Borrowings and Cre_4
Short-Term Borrowings and Credit Arrangements (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | $ 550,000,000 | $ 550,000,000 |
Letters of credit outstanding, amount | 0 | 0 |
Credit Facility Borrowings and Letter of Credit, Amount Outstanding | 318,000,000 | 450,000,000 |
Net availability as of December 31(3) | 232,000,000 | 100,000,000 |
Revolving Credit Facility Due 2028 [Member] | NW Corp | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | 425,000,000 | 0 |
Revolving Credit Facility Due 2027 | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | 0 | 425,000,000 |
Revolving Credit Facility Due 2024 | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | 100,000,000 | 100,000,000 |
Swingline Credit Facility [Member] | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | 25,000,000 | 25,000,000 |
Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | ||
Line of Credit Facility [Line Items] | ||
SOFR borrowings | $ 318,000,000 | $ 450,000,000 |
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, 2023 | Dec. 31, 2022 | Mar. 31, 2022 | |
Debt Instrument [Line Items] | |||
Long-term Debt | $ 2,784,585 | $ 2,618,882 | |
Long-term Debt, Current Maturities | (99,950) | (144,525) | |
Finance Lease, Liability, Total | 8,799 | 11,897 | |
Current maturities of finance leases | (3,338) | (3,098) | |
Long-term finance leases | 5,461 | 8,799 | |
South Dakota First Mortgage Bonds Due 2033 | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Face Amount | $ 31,000 | ||
Interest rate, stated percentage | 5.57% | ||
Long-term Debt, Maturity Date | Mar. 30, 2033 | ||
South Dakota First Mortgage Bonds Due 2033, Issued May 2023 | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Face Amount | $ 30,000 | ||
Montana First Mortgage Bonds Due 2033 | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Face Amount | $ 239,000 | ||
Interest rate, stated percentage | 5.57% | ||
Long-term Debt, Maturity Date | Mar. 30, 2033 | ||
Montana 2.00% Due 2023 | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Face Amount | $ 144,700 | ||
Interest rate, stated percentage | 2% | ||
Secured Debt Montana 3.88% Due 2028 | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Face Amount | $ 144,700 | ||
Interest rate, stated percentage | 3.88% | ||
Long-term Debt, Maturity Date | Jul. 01, 2028 | ||
Unsecured Debt | Revolving Credit Facility Due 2027 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 0 | 425,000 | |
Unsecured Debt | Revolving Credit Facility Due 2028 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | 318,000 | 0 | |
Unsecured Debt | Revolving Credit Facility Due 2024 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 0 | 25,000 | |
Unsecured Debt | Revolving Credit Facility Due 2023 | |||
Debt Instrument [Line Items] | |||
Maturity date | Sep. 02, 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 01, 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 | South Dakota First Mortgage Bonds Due 2033 | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Face Amount | $ 31,000 | 0 | |
Maturity date | Mar. 30, 2033 | ||
Interest rate, stated percentage | 5.57% | ||
Secured Debt | South Dakota First Mortgage Bonds Due 2033, Issued May 2023 | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Face Amount | $ 30,000 | 0 | |
Maturity date | May 01, 2033 | ||
Interest rate, stated percentage | 5.42% | ||
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 01, 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. 01, 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. 01, 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. 06, 2047 | ||
Interest rate, stated percentage | 4.03% | ||
Secured Debt | Secured Debt Montana Due 2049 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 150,000 | 150,000 | |
Secured Debt | Montana 3.98%, Due June 2049 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 50,000 | 50,000 | |
Maturity date | Jun. 26, 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 First Mortgage Bonds Due 2024 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 100,000 | 100,000 | |
Maturity date | Mar. 26, 2024 | ||
Interest rate, stated percentage | 1% | ||
Secured Debt | Montana First Mortgage Bonds Due March 30, 2033 | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Face Amount | $ 239,000 | 0 | |
Secured Debt | Montana First Mortgage Bonds Due 2033 | |||
Debt Instrument [Line Items] | |||
Maturity date | Mar. 30, 2033 | ||
Interest rate, stated percentage | 5.57% | ||
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 | Montana 2.00% Due 2023 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 0 | 144,660 | |
Maturity date | Aug. 01, 2023 | ||
Interest rate, stated percentage | 2% | ||
Secured Debt | Secured Debt Montana 3.88% Due 2028 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 144,660 | $ 0 | |
Maturity date | Jul. 01, 2028 | ||
Interest rate, stated percentage | 2% | ||
Secured Debt | New Market Tax Credit Financing-1.146%, Due 2046 | |||
Debt Instrument [Line Items] | |||
Maturity date | Jul. 01, 2046 | ||
Interest rate, stated percentage | 1.146% | ||
Discount on Notes and Bonds and Debt Issuance Costs, Net | |||
Debt Instrument [Line Items] | |||
Discount on notes and bonds and debt issuance costs, net | $ (13,075) | $ (10,778) |
Long-Term Debt and Capital Le_4
Long-Term Debt and Capital Leases Schedule of Long-Term Debt (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Mar. 31, 2022 |
Secured Debt Montana 3.88% Due 2028 | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 144.7 | |
Interest rate, stated percentage | 3.88% | |
Long-term Debt, Maturity Date | Jul. 01, 2028 | |
Montana 2.00% Due 2023 | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 144.7 | |
Interest rate, stated percentage | 2% | |
South Dakota First Mortgage Bonds Due May 1, 2033 | ||
Debt Instrument [Line Items] | ||
Interest rate, stated percentage | 5.42% | |
Long-term Debt, Maturity Date | May 01, 2033 | |
Montana First Mortgage Bonds Due 2033 | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 239 | |
Interest rate, stated percentage | 5.57% | |
Long-term Debt, Maturity Date | Mar. 30, 2033 | |
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% | |
Secured Debt | Secured Debt Montana 3.88% Due 2028 | ||
Debt Instrument [Line Items] | ||
Interest rate, stated percentage | 2% | |
Secured Debt | Montana 2.00% Due 2023 | ||
Debt Instrument [Line Items] | ||
Interest rate, stated percentage | 2% | |
Secured Debt | Montana First Mortgage Bonds Due 2033 | ||
Debt Instrument [Line Items] | ||
Interest rate, stated percentage | 5.57% |
Long-Term Debt and Capital Le_5
Long-Term Debt and Capital Leases (Details) $ in Millions | Dec. 31, 2023 USD ($) |
Maturities of Long-term Debt [Abstract] | |
2024 | $ 103.3 |
2025 | 303.6 |
2026 | 106.9 |
2028 | $ 497.7 |
Income Taxes Narrative (Details
Income Taxes Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |||
Federal statutory rate | 21% | 21% | 21% |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | $ 4.5 | $ 1.4 |
Income Taxes Domestic Tax Compo
Income Taxes Domestic Tax Components (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Federal | |||
Current | $ 2,925 | $ 5,024 | $ 722 |
Deferred | 2,929 | (5,993) | 2,626 |
Investment tax credits | (129) | (130) | (130) |
State | |||
Current | (1,971) | 3,363 | 2,172 |
Deferred | 3,785 | (2,869) | (1,971) |
Income Tax Expense (Benefit) | $ 7,539 | $ (605) | $ 3,419 |
Income Taxes Effective Rate Rec
Income Taxes Effective Rate Reconciliation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Effective Income Tax Rate Reconciliation, Percent [Abstract] | |||
Federal statutory rate | 21% | 21% | 21% |
State income tax, net of federal provisions | 0.30% | 0.30% | 0.10% |
Flow-through repairs deductions | (12.90%) | (12.40%) | (11.50%) |
Production tax credits | (5.10%) | (7.20%) | (6.10%) |
Effective Income Tax Rate Reconciliation, Unregulated Tax Cuts and Jobs act excess deferred income taxes, Percent | (1.70%) | 0% | 0% |
Release of unrecognized tax benefits | (1.60%) | 0% | |
Amortization of excess deferred income taxes | (1.10%) | (0.90%) | (0.30%) |
Plant and depreciation of flow through items | 3.30% | (0.10%) | (0.60%) |
Reduction to previously claimed alternative minimum tax credit | 1.60% | 0% | |
Prior year permanent return to accrual adjustments | 0% | (0.80%) | 0% |
Other, net | (0.10%) | (0.20%) | (0.80%) |
Effective tax rate | 3.70% | (0.30%) | 1.80% |
Income Before Income Taxes | $ 201,670 | $ 182,403 | $ 190,259 |
Income tax calculated at federal statutory rate | 42,350 | 38,304 | 39,954 |
State income, net of federal provisions | 606 | 562 | 354 |
Flow-through repairs deductions | (25,922) | (22,665) | (21,888) |
Production tax credits | (10,274) | (13,166) | (11,532) |
Effective Income Tax Rate Reconciliation, Unregulated Tax Cuts and Jobs act excess deferred income taxes, Amount | (3,385) | 0 | 0 |
Release of unrecognized tax benefits | (3,241) | 0 | 0 |
Amortization of excess deferred income taxes | (2,184) | (1,657) | (635) |
Plant and depreciation of flow through items | 6,595 | (222) | (941) |
Reduction to previously claimed alternative minimum tax credit | 3,186 | 0 | |
Prior year permanent return to accrual adjustments | 45 | (1,397) | (12) |
Other, net | (237) | (364) | (1,881) |
Total reconciling items | (34,811) | (38,909) | (36,535) |
Income Tax Expense (Benefit) | $ 7,539 | $ (605) | $ 3,419 |
Income Taxes Operating Loss (De
Income Taxes Operating Loss (Details) $ in Millions | Dec. 31, 2023 USD ($) |
State and Local Jurisdiction [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforwards, subject to expiration | $ 362.1 |
Domestic Tax Authority [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforward | 447.8 |
State and Local Jurisdiction [Member] | |
Operating Loss Carryforwards [Line Items] | |
NOL carryforward | $ 362.1 |
Income Taxes Deferred Tax Liabi
Income Taxes Deferred Tax Liability (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Deferred Tax Assets, [Abstract] | ||
Production tax credit | $ 94,283 | $ 80,097 |
Customer advances | 28,300 | 25,119 |
Pension / postretirement benefits | 15,131 | 19,291 |
Compensation accruals | 10,716 | 10,306 |
Unbilled revenue | 10,604 | 9,440 |
Environmental liability | 5,760 | 6,009 |
Reserves and accruals | 3,098 | 4,016 |
Interest rate hedges | 3,280 | 3,372 |
Other, net | 2,677 | 2,595 |
Deferred Tax Asset | 287,215 | 160,245 |
Deferred Tax Liabilities, [Abstract] | ||
Excess tax depreciation | (660,440) | (449,724) |
Flow through depreciation | (120,558) | (106,623) |
Goodwill amortization | (88,323) | (86,874) |
Regulatory assets and other | (18,414) | (56,007) |
Deferred Tax Liability | (887,735) | (699,228) |
Deferred Tax Liability, net | (600,520) | (538,983) |
Deferred Tax Assets, Operating Loss Carryforwards | 113,366 | $ 0 |
2036 | ||
Deferred Tax Assets, [Abstract] | ||
Production tax credit | 10,900 | |
2037 | ||
Deferred Tax Assets, [Abstract] | ||
Production tax credit | 11,100 | |
2038 | ||
Deferred Tax Assets, [Abstract] | ||
Production tax credit | 10,900 | |
Production Tax Credits Expiring in 2039 | ||
Deferred Tax Assets, [Abstract] | ||
Production tax credit | 13,100 | |
Production Tax Credits Expiring in 2041 | ||
Deferred Tax Assets, [Abstract] | ||
Production tax credit | 11,500 | |
Production Tax Credits Expiring in 2042 | ||
Deferred Tax Assets, [Abstract] | ||
Production tax credit | 13,200 | |
Production Tax Credits Expiring in 2039 | ||
Deferred Tax Assets, [Abstract] | ||
Production tax credit | 11,500 | |
Production Tax Credits Expiring in 2035 | ||
Deferred Tax Assets, [Abstract] | ||
Production tax credit | 1,800 | |
Production Tax Credits Expiring in 2043 | ||
Deferred Tax Assets, [Abstract] | ||
Production tax credit | $ 10,400 |
Income Taxes Uncertain Tax Posi
Income Taxes Uncertain Tax Positions (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Income Tax Contingency [Line Items] | |||
Unrecognized tax benefit more likely than not percentage threshold | 50% | ||
Unrecognized tax benefits that would impact effective tax rate | $ 24,400 | $ 27,900 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Unrecognized Tax Benefits at January 1 | 30,330 | 32,049 | $ 33,491 |
Gross increases - tax positions in prior period | 0 | 0 | 293 |
Gross increases - tax positions in current period | 0 | 0 | 0 |
Gross decreases - tax positions in current period | (2,256) | (1,719) | (1,735) |
Lapse of statute of limitations | 0 | 0 | 0 |
Unrecognized Tax Benefits at December 31 | 28,074 | 30,330 | $ 32,049 |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | 4,500 | $ 1,400 | |
IRS Revenue Procedure 2023-15 - safe harbor method of accounting for gas repairs expenditures | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Unrecognized Tax Benefits, Period Increase (Decrease) | 500 | ||
Income Tax Benefit From Decrease in Unrecognized Tax Benefits | 3,200 | ||
Expiration of statute of limitations | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Decrease in Unrecognized Tax Benefits is Reasonably Possible | $ 16,900 |
Comprehensive Income (Loss) (De
Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Other Comprehensive Income (Loss), Before Tax [Abstract] | |||
Foreign currency translation adjustment | $ 2 | $ (8) | $ (57) |
Reclassification of net income (loss) on derivative instruments | (612) | (612) | (614) |
Postretirement medical liability adjustment | (331) | (1,359) | (585) |
Other comprehensive (loss) income | 283 | (755) | (28) |
Other Comprehensive Income (Loss), Tax [Abstract] | |||
Foreign currency translation adjustment | 0 | 0 | 0 |
Reclassification of net income (loss) on derivative instruments | 160 | 160 | 162 |
Postretirement medical liability adjustment | 69 | 377 | 149 |
Other comprehensive (loss) income | (91) | 217 | (13) |
Other Comprehensive Income (Loss), Net of Tax [Abstract] | |||
Foreign currency translation adjustment | 2 | (8) | (57) |
Reclassification of net income (loss) on derivative instruments | (452) | (452) | (452) |
Postretirement medical liability adjustment | (262) | (982) | (436) |
Other comprehensive (loss) income | 192 | (538) | (41) |
Accumulated Other Comprehensive Income, Net of Tax [Abstract] | |||
Foreign currency translation | 1,437 | 1,435 | |
Derivative instruments designated as cash flow hedges | (9,373) | (9,825) | |
Postretirement medical plans | 280 | 542 | |
Accumulated other comprehensive loss | $ (7,656) | $ (7,848) | $ (7,310) |
Comprehensive Income (Loss) Com
Comprehensive Income (Loss) Components of AOCI (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Beginning balance | $ (7,848) | $ (7,310) | |
Other comprehensive loss before reclassifications | 2 | (8) | |
Interest rate contracts, amount of gain reclassified from AOCL into income | (452) | (452) | |
Amounts reclassified from AOCL | (262) | (982) | |
Net current-period other comprehensive income (loss) | 192 | (538) | $ (41) |
Ending Balance | (7,656) | (7,848) | (7,310) |
Foreign Currency Translation | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Beginning balance | 1,435 | 1,443 | |
Other comprehensive loss before reclassifications | 2 | (8) | |
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 (loss) | 2 | (8) | |
Ending Balance | 1,437 | 1,435 | 1,443 |
Pension and Postretirement Medical Plans | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Beginning balance | 542 | (1,524) | |
Other comprehensive loss before reclassifications | 0 | 0 | |
Interest rate contracts, amount of gain reclassified from AOCL into income | 0 | 0 | |
Amounts reclassified from AOCL | (262) | (982) | |
Net current-period other comprehensive income (loss) | (262) | (982) | |
Ending Balance | 280 | 542 | (1,524) |
Interest Rate Derivative Instruments Designated as Cash Flow Hedges | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Beginning balance | (9,825) | (10,277) | |
Other comprehensive loss 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 (loss) | 452 | 452 | |
Ending Balance | $ (9,373) | $ (9,825) | $ (10,277) |
Employee Benefit Plans Benefit
Employee Benefit Plans Benefit Obligation And Funded Status (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 USD ($) numberOfParticipants | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Pension Plan [Member] | |||
Change in Benefit Obligation: | |||
Obligation at beginning of period | $ 521,798 | $ 696,802 | |
Service cost | 5,646 | 10,223 | $ 12,994 |
Interest cost | 25,852 | 18,787 | 18,759 |
Actuarial loss | 3,127 | (176,389) | |
Settlements(1) | (51,942) | 0 | |
Benefits paid | (30,493) | (27,625) | |
Benefit Obligation at End of Period | 473,988 | 521,798 | 696,802 |
Change in Fair Value of Plan Assets: | |||
Settlements(1) | (51,900) | ||
Amounts Recognized in the Balance Sheet Consist of: | |||
Noncurrent asset | 7,875 | 7,195 | |
Total Assets | 7,875 | 7,195 | |
Current liability | (11,200) | (11,200) | |
Noncurrent liability | (67,992) | (76,254) | |
Total Liabilities | (79,192) | (87,454) | |
Net amount recognized | (71,317) | (80,259) | |
Amounts recognized in AOCL consist of: | |||
Prior service cost | 0 | 0 | |
Net actuarial gain | 0 | 0 | |
Total | (44,453) | (54,383) | |
Plans with Benefit Obligations in Excess of Plan Assets [Abstract] | |||
Projected benefit obligation | 427,300 | 474,900 | |
Accumulated benefit obligation | 427,300 | 474,900 | |
Fair value of plan assets | 348,100 | 388,700 | |
Plan Assets used to purchase annuity contract | $ 51,900 | ||
Pension Plan, Participants included in Pension Settlement | numberOfParticipants | 285 | ||
Settlement loss recognized(1) | $ 4,395 | 0 | 11,291 |
Pension Plan [Member] | Pension | |||
Amounts Recognized in Regulatory Assets Consist of: | |||
Prior service credit | 0 | 0 | |
Net actuarial (loss) gain | (44,453) | (54,383) | |
Pension Plan [Member] | Changes Measurement [Member] | |||
Change in Fair Value of Plan Assets: | |||
Fair value of plan assets at beginning of period | 441,539 | 605,499 | |
Return on plan assets | 34,367 | (144,535) | |
Employer contributions | 9,200 | 8,200 | |
Settlements(1) | (51,942) | 0 | |
Benefits paid | (30,493) | (27,625) | |
Fair value of plan assets at end of period | 402,671 | 441,539 | 605,499 |
Funded Status | (71,317) | (80,259) | |
Other Postretirement Benefits Plan [Member] | |||
Change in Benefit Obligation: | |||
Obligation at beginning of period | 15,407 | 17,308 | |
Service cost | 333 | 351 | |
Interest cost | 674 | 358 | |
Actuarial loss | (1,240) | (99) | |
Settlements(1) | 0 | 0 | |
Benefits paid | (1,466) | (2,511) | |
Benefit Obligation at End of Period | 13,708 | 15,407 | 17,308 |
Amounts Recognized in the Balance Sheet Consist of: | |||
Noncurrent asset | 12,378 | 8,831 | |
Total Assets | 12,378 | 8,831 | |
Current liability | (1,355) | (1,585) | |
Noncurrent liability | (2,422) | (2,598) | |
Total Liabilities | (3,777) | (4,183) | |
Net amount recognized | 8,601 | 4,648 | |
Amounts recognized in AOCL consist of: | |||
Prior service cost | 0 | 0 | |
Net actuarial gain | 590 | (1,046) | |
Total | 605 | (2,193) | |
Other Postretirement Benefits Plan [Member] | Pension | |||
Amounts Recognized in Regulatory Assets Consist of: | |||
Prior service credit | 0 | (116) | |
Net actuarial (loss) gain | 15 | (3,123) | |
Other Postretirement Benefits Plan [Member] | Changes Measurement [Member] | |||
Change in Fair Value of Plan Assets: | |||
Fair value of plan assets at beginning of period | 20,055 | 25,289 | |
Return on plan assets | 3,334 | (4,098) | |
Employer contributions | 386 | 1,375 | |
Settlements(1) | 0 | 0 | |
Benefits paid | (1,466) | (2,511) | |
Fair value of plan assets at end of period | 22,309 | 20,055 | $ 25,289 |
Funded Status | $ 8,601 | $ 4,648 |
Employee Benefit Plans Net Peri
Employee Benefit Plans Net Periodic Costs (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Pension Plan [Member] | |||
Service cost | $ 5,646 | $ 10,223 | $ 12,994 |
Interest cost | 25,852 | 18,787 | 18,759 |
Expected return on plan assets | 25,932 | 24,173 | 27,061 |
Amortization of prior service cost (credit) | 0 | 0 | 0 |
Recognized actuarial loss (gain) | (228) | (383) | (6,536) |
Settlement loss recognized(1) | 4,395 | 0 | 11,291 |
Net Periodic Benefit Cost (Credit) | 10,189 | 5,220 | 22,519 |
Regulatory deferral of net periodic benefit cost(2) | (1,814) | 2,307 | (13,308) |
Previously deferred costs recognized(2) | 210 | 0 | 0 |
Net Periodic Benefit Cost Recognized | 8,585 | 7,527 | 9,211 |
Other Pension, Postretirement and Supplemental Plans [Member] | |||
Service cost | 333 | 351 | 407 |
Interest cost | 674 | 359 | 327 |
Expected return on plan assets | 1,096 | 1,047 | 919 |
Amortization of prior service cost (credit) | 116 | (1,891) | (1,835) |
Recognized actuarial loss (gain) | 672 | 897 | 898 |
Settlement loss recognized(1) | 0 | 0 | 0 |
Net Periodic Benefit Cost (Credit) | (645) | (3,125) | (2,918) |
Regulatory deferral of net periodic benefit cost(2) | 0 | 0 | 0 |
Previously deferred costs recognized(2) | 550 | 292 | 709 |
Net Periodic Benefit Cost Recognized | $ (95) | $ (2,833) | $ (2,209) |
Employee Benefit Plans Actuaria
Employee Benefit Plans Actuarial Assumptions (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2024 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Increase in projected benefit obligation due to change in discount rate | $ 10.5 | |||
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 | 4% | 4% | 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 | 4% | 4% | 2% | |
Pension Plan [Member] | Minimum [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Discount rate | 5.20% | 2.65% | 2.20% | |
Expected rate of return on assets | 2.66% | 3.01% | 3.45% | |
Interest credit rating | 3.30% | 3.30% | 3.30% | |
Pension Plan [Member] | Maximum [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Discount rate | 5.20% | 2.75% | 2.30% | |
Expected rate of return on assets | 4.26% | 4.17% | 4.49% | |
Interest credit rating | 6% | 6% | 6% | |
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 | 5.62% | 4.23% | 4.08% | |
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | ||||
Health care cost trend rate assumed for next year | 5% | |||
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 | 4% | 4% | 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 | 4% | 4% | 2% | |
Other Postretirement Benefits Plan [Member] | Minimum [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Discount rate | 5.15% | 2.35% | 1.80% | |
Other Postretirement Benefits Plan [Member] | Maximum [Member] | ||||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||||
Discount rate | 5.20% | 2.40% | 1.80% | |
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 | 5.15% | |||
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 | 6.65% |
Employee Benefit Plans Investme
Employee Benefit Plans Investment Strategy (Details) | Dec. 31, 2023 | Dec. 31, 2022 |
Defined Benefit Plan, Plan Assets, Allocations [Abstract] | ||
Target allocation of investments by plan | 5% | |
Pension Plan [Member] | NorthWestern Energy Pension Plan (MT) [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 100% | 100% |
Pension Plan [Member] | NorthWestern Corporation Pension Plan [Member] | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 100% | 100% |
Pension Plan [Member] | Northwestern Energy Health and Welfare | ||
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 100% | 100% |
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% | 0% |
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 | 1.50% | 1.10% |
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 | 0.20% | 0.60% |
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 | 45% | 45% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 45.30% | 44.50% |
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% | 90% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 88.70% | 88.60% |
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% | 40% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 35.10% | 36.70% |
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 | 0% | 0% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 0% | 0% |
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 | 0% | 1% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 0% | 0.90% |
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% | 0% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 0% | 0% |
Global equities | Pension Plan [Member] | NorthWestern Energy Pension Plan (MT) [Member] | ||
Defined Benefit Plan, Plan Assets, Allocations [Abstract] | ||
Target allocation of investments by plan | 38.50% | 44% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 37.60% | 43.40% |
Global equities | Pension Plan [Member] | NorthWestern Corporation Pension Plan [Member] | ||
Defined Benefit Plan, Plan Assets, Allocations [Abstract] | ||
Target allocation of investments by plan | 7% | 9% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 6.90% | 9.40% |
Global equities | Pension Plan [Member] | Northwestern Energy Health and Welfare | ||
Defined Benefit Plan, Plan Assets, Allocations [Abstract] | ||
Target allocation of investments by plan | 60% | 60% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 64.70% | 62.70% |
Fixed Income Investments | Pension Plan [Member] | NorthWestern Energy Pension Plan (MT) [Member] | ||
Defined Benefit Plan, Plan Assets, Allocations [Abstract] | ||
Target allocation of investments by plan | 11% | 5.50% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 10.60% | 5.50% |
Fixed Income Investments | Pension Plan [Member] | NorthWestern Corporation Pension Plan [Member] | ||
Defined Benefit Plan, Plan Assets, Allocations [Abstract] | ||
Target allocation of investments by plan | 3% | 0% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 2.90% | 0% |
Fixed Income Investments | Pension Plan [Member] | Northwestern Energy Health and Welfare | ||
Defined Benefit Plan, Plan Assets, Allocations [Abstract] | ||
Target allocation of investments by plan | 0% | 0% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 0% | 0% |
Private Real Estate | Pension Plan [Member] | NorthWestern Energy Pension Plan (MT) [Member] | ||
Defined Benefit Plan, Plan Assets, Allocations [Abstract] | ||
Target allocation of investments by plan | 5.50% | 5.50% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 6.50% | 6.60% |
Private Real Estate | Pension Plan [Member] | NorthWestern Corporation Pension Plan [Member] | ||
Defined Benefit Plan, Plan Assets, Allocations [Abstract] | ||
Target allocation of investments by plan | 0% | 0% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 0% | 0% |
Private Real Estate | Pension Plan [Member] | Northwestern Energy Health and Welfare | ||
Defined Benefit Plan, Plan Assets, Allocations [Abstract] | ||
Target allocation of investments by plan | 0% | 0% |
Defined Benefit Plan, Actual Asset Allocations [Abstract] | ||
Actual allocation of investments by plan | 0% | 0% |
Employee Benefit Plans Cash Flo
Employee Benefit Plans Cash Flows (Details) - Pension Plan [Member] - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension contributions | $ 9,200 | $ 8,200 | $ 10,200 |
NorthWestern Energy Pension Plan (MT) [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension contributions | 8,000 | 7,000 | 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) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Pension Plan [Member] | ||
Estimated Future Benefit Payments | ||
2024 | $ 27,553 | |
2025 | 28,987 | |
2026 | 29,920 | |
2027 | 30,545 | |
2028 | 31,231 | |
2029-2033 | 164,362 | |
Other Pension, Postretirement and Supplemental Plans [Member] | ||
Estimated Future Benefit Payments | ||
2024 | 2,149 | |
2025 | 1,813 | |
2026 | 1,406 | |
2027 | $ 1,251 | |
2028 | $ 1,210 | |
2029-2033 | $ 5,288 |
Employee Benefit Plans Narrativ
Employee Benefit Plans Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
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% | ||
Pension Plan [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Matching employer contributions | $ 13.2 | $ 12.3 | $ 11.8 |
Stock-Based Compensation (Detai
Stock-Based Compensation (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation expense | $ 3.6 | $ 4.2 | $ 3.9 |
Compensation expense tax (expense) benefit | (1) | (1.3) | (0.2) |
Compensation expense not yet recognized for nonvested awards | $ 6.5 | ||
Nonvested awards, total compensation cost not yet recognized, period for recognition | 2 years | ||
Shares vested in period, total fair value | $ 4.4 | $ 4.3 | $ 4.2 |
Share-based Compensation, Significant Assumptions | |||
Risk-free interest rate | 4.33% | 1.82% | |
Expected life, in years | 3 years | 3 years | |
Expected volatility, minimum | 30.40% | 28.20% | |
Expected volatility, maximum | 41% | 38.50% | |
Dividend yield | 4.40% | 4.50% | |
Performance Shares [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance and vesting period | 3 years | ||
Performance Shares [Member] | Minimum [Member] | |||
Share-based Compensation, Significant Assumptions | |||
Percent of shares issued based on company performance | 0% | ||
Performance Shares [Member] | Maximum [Member] | |||
Share-based Compensation, Significant Assumptions | |||
Percent of shares issued based on company performance | 200% | ||
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 | 4 years | ||
Executive retirement/retention program [Member] | Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance and vesting period | 4 years | 5 years | |
Common Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares available for grant | 649,884 |
Stock-Based Compensation Nonves
Stock-Based Compensation Nonvested (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Performance Shares [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward] | ||
Beginning nonvested grants (shares) | 194,407 | |
Granted (shares) | 95,853 | |
Vested (shares) | (87,300) | |
Forfeited (shares) | (49,176) | |
Remaining nonvested grants (shares) | 153,784 | 194,407 |
Beginning nonvested (weighted-average grant date fair value) | $ 51.04 | |
Granted (weighted-average grant date fair value) | 54.41 | |
Vested (weighted-average grant date fair value) | 50.53 | |
Forfeited (weighted-average grant date fair value) | 51.59 | |
Remaining nonvested (weighted-average grant date fair value) | $ 53.26 | $ 51.04 |
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) | 99,285 | |
Granted (shares) | 0 | |
Vested (shares) | 0 | |
Forfeited (shares) | (38,506) | |
Remaining nonvested grants (shares) | 60,779 | 99,285 |
Beginning nonvested (weighted-average grant date fair value) | $ 48.62 | |
Granted (weighted-average grant date fair value) | 0 | |
Vested (weighted-average grant date fair value) | 0 | |
Forfeited (weighted-average grant date fair value) | 49.73 | |
Remaining nonvested (weighted-average grant date fair value) | $ 47.91 | $ 48.62 |
Performance and vesting period | 4 years | 5 years |
Common Stock Common Stock (Deta
Common Stock Common Stock (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
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 | $ 74,904,000 | $ 276,582,000 | $ 197,974,000 |
Shares paid for tax withholding | 4,167 | 16,120 | |
Proceeds from issuance of common stock, net | $ 73,613,000 | $ 276,971,000 | $ 196,246,000 |
Amount of Unrestricted Net Assets for Consolidated and Unconsolidated Subsidiaries | $ 920,000,000 | ||
Equity Distribution Agreement | |||
Class of Stock [Line Items] | |||
Issuance of shares, shares | 1,432,738 | ||
Common Stock Average Share Price | $ 52.02 | ||
Investment Banking, Advisory, Brokerage, and Underwriting Fees and Commissions | 900,000 | ||
Proceeds from issuance of common stock, net | 73,600,000 | ||
Common Stock Aggregate Gross Sales Price Maximum | $ 200,000,000 |
Earnings Per Share (Details)
Earnings Per Share (Details) - shares | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Basic computation | 61,244,000 | 58,345,000 | 60,321,481 | 55,769,156 | 51,709,229 |
Performance and restricted share awards(1) | 36,312 | 26,621 | 111,940 | ||
Incremental Common Shares Attributable to Dilutive Effect of Equity Forward Agreements | 0 | 496,333 | 51,057 | ||
Diluted computation | 60,357,793 | 56,292,110 | 51,872,226 | ||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 25,913 |
Commitments and Contingencies Q
Commitments and Contingencies Qualifying Facilities Liability (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Beginning QF liability | $ 49,728,000 | |
Ending QF liability | 28,670,000 | $ 49,728,000 |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
Periodic adjustment of the liability for price escalation | 4,200,000 | |
Annual reset of liability to actual output and pricing | 800,000 | 1,800,000 |
Unrecovered Amount, Annual Reset to Actual Output and Pricing, Change year-over-year | $ 1,000,000 | |
Maximum [Member] | ||
Long term purchase commitments term | 24 years | |
Qualifying Facility Contracts [Member] | ||
Beginning QF liability | $ 49,728,000 | 64,943,000 |
Settlements(1) | (24,707,000) | (20,076,000) |
Interest expense | 3,649,000 | 4,861,000 |
Ending QF liability | 28,670,000 | $ 49,728,000 |
Qualifying Facility Contracts [Member] | Minimum [Member] | ||
Price per MWH of energy required to be purchased per QF agreement | 67 | |
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 | 303,062,000 | |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
2024 | 74,110,000 | |
2025 | 60,360,000 | |
2026 | 55,393,000 | |
2027 | 56,665,000 | |
2028 | 42,400,000 | |
2029 | (14,134,000) | |
Recorded Unconditional Purchase Obligation | 303,062,000 | |
Qualifying Facility Contracts [Member] | Recoverable Amounts [Member] | ||
Recorded Unconditional Purchase Obligation | 266,493,000 | |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
2024 | 60,706,000 | |
2025 | 52,950,000 | |
2026 | 46,274,000 | |
2027 | 46,668,000 | |
2028 | 41,664,000 | |
2029 | (18,231,000) | |
Recorded Unconditional Purchase Obligation | 266,493,000 | |
Qualifying Facility Contracts [Member] | Net Amount [Member] | ||
Recorded Unconditional Purchase Obligation | 36,569,000 | |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
2024 | 13,404,000 | |
2025 | 7,410,000 | |
2026 | 9,119,000 | |
2027 | 9,997,000 | |
2028 | 736,000 | |
2029 | (4,097,000) | |
Recorded Unconditional Purchase Obligation | $ 36,569,000 |
Commitments and Contingencies L
Commitments and Contingencies Long Term Supply and Capacity Purchase Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Long-term Purchase Commitment [Line Items] | |||
Long term purchase committments costs incurred | $ 340 | $ 328 | $ 286.7 |
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | |||
Purchase obligation due in next twelve months | 321.9 | ||
Purchase obligation due in second year | 244.1 | ||
Purchase obligation due in third year | 263.4 | ||
Purchase obligation due in fourth year | 243.6 | ||
Purchase obligation due in fifth year | 225.9 | ||
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 | $ 22.4 |
Commitments and Contingencies E
Commitments and Contingencies Environmental Liabilities (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Environmental Loss Contingency, Statement of Financial Position [Extensible Enumeration] | Other noncurrent liabilities | |||
Environmental remediation obligations [Member] | ||||
Environmental remediation obligation, minimum | $ 21,000 | |||
Environmental remediation obligation, maximum | 31,400 | |||
Accrual for environmental loss contingencies | 25,286 | $ 26,367 | $ 26,866 | $ 28,895 |
Deductions | (2,520) | (2,033) | (2,799) | |
Charged to costs and expense | 1,439 | $ 1,534 | $ 770 | |
Combined Manufacturing Sites [Member] | Manufactured Gas Plants [Member] | ||||
Accrual for environmental loss contingencies | 19,800 | |||
Aberdeen South Dakota Site [Member] | Manufactured Gas Plants [Member] | ||||
Accrual for environmental loss contingencies | 8,000 | |||
Environmental remediation obligation, to be incurred during next 5 years | $ 2,900 |
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, 2023 | Dec. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | $ 1,554,800 | $ 1,459,400 | $ 1,326,800 | ||
Total revenues | $ 356,009 | $ 425,283 | 1,422,143 | 1,477,837 | 1,372,316 |
Residential | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 684,500 | 654,500 | 573,600 | ||
Commercial | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 656,300 | 606,700 | 554,400 | ||
Industrial | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 47,400 | 41,300 | 39,000 | ||
Lighting, Governmental, Irrigation, and Interdepartmental | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 34,400 | 32,900 | 33,500 | ||
Total Customer Revenue | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 1,422,600 | 1,335,400 | 1,200,500 | ||
Other Tariff and Contract Based Revenue | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 132,200 | 124,000 | 126,300 | ||
Montana | Residential | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 544,400 | 509,700 | 460,600 | ||
Montana | Commercial | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 505,100 | 447,900 | 421,400 | ||
South Dakota | Residential | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 104,500 | 109,000 | 92,000 | ||
South Dakota | Commercial | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 129,100 | 136,700 | 121,600 | ||
Nebraska | Residential | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 35,600 | 35,800 | 21,000 | ||
Nebraska | Commercial | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 22,100 | 22,100 | 11,400 | ||
Regulatory Amortization [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Regulatory amortization | (132,700) | 18,400 | 45,500 | ||
Total Revenue [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Total revenues | 1,422,100 | 1,477,800 | 1,372,300 | ||
Electric | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 1,176,400 | 1,060,500 | 1,018,700 | ||
Electric | Residential | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 476,200 | 427,200 | 400,000 | ||
Electric | Commercial | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 534,600 | 476,800 | 459,200 | ||
Electric | Industrial | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 46,000 | 39,800 | 37,900 | ||
Electric | Lighting, Governmental, Irrigation, and Interdepartmental | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 32,700 | 31,000 | 32,100 | ||
Electric | Total Customer Revenue | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 1,089,500 | 974,800 | 929,200 | ||
Electric | Other Tariff and Contract Based Revenue | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 86,900 | 85,700 | 89,500 | ||
Electric | Montana | Residential | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 408,300 | 357,400 | 334,600 | ||
Electric | Montana | Commercial | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 431,400 | 368,600 | 356,700 | ||
Electric | South Dakota | Residential | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 67,900 | 69,800 | 65,400 | ||
Electric | South Dakota | Commercial | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 103,200 | 108,200 | 102,500 | ||
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 | (107,600) | 46,100 | 33,500 | ||
Electric | Total Revenue [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Total revenues | 1,068,800 | 1,106,600 | 1,052,200 | ||
Natural gas | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 378,400 | 398,900 | 308,100 | ||
Natural gas | Residential | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 208,300 | 227,300 | 173,600 | ||
Natural gas | Commercial | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 121,700 | 129,900 | 95,200 | ||
Natural gas | Industrial | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 1,400 | 1,500 | 1,100 | ||
Natural gas | Lighting, Governmental, Irrigation, and Interdepartmental | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 1,700 | 1,900 | 1,400 | ||
Natural gas | Total Customer Revenue | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 333,100 | 360,600 | 271,300 | ||
Natural gas | Other Tariff and Contract Based Revenue | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 45,300 | 38,300 | 36,800 | ||
Natural gas | Montana | Residential | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 136,100 | 152,300 | 126,000 | ||
Natural gas | Montana | Commercial | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 73,700 | 79,300 | 64,700 | ||
Natural gas | South Dakota | Residential | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 36,600 | 39,200 | 26,600 | ||
Natural gas | South Dakota | Commercial | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 25,900 | 28,500 | 19,100 | ||
Natural gas | Nebraska | Residential | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 35,600 | 35,800 | 21,000 | ||
Natural gas | Nebraska | Commercial | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from Contract with Customer | 22,100 | 22,100 | 11,400 | ||
Natural gas | Regulatory Amortization [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Regulatory amortization | (25,100) | (27,700) | 12,000 | ||
Natural gas | Total Revenue [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Total revenues | $ 353,300 | $ 371,200 | $ 320,100 |
Segment and Related Informati_3
Segment and Related Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Segment Reporting Information [Line Items] | |||||
Total revenues | $ 356,009 | $ 425,283 | $ 1,422,143 | $ 1,477,837 | $ 1,372,316 |
Utilities Operating Expense, Fuel Used | 420,262 | 492,011 | 425,548 | ||
Utility Margin | 1,001,881 | 985,826 | 946,768 | ||
Operating and maintenance | 220,524 | 221,427 | 208,303 | ||
Administrative and general | 117,360 | 113,776 | 101,873 | ||
Property and other taxes | 153,068 | 192,524 | 173,444 | ||
Depreciation and depletion | 210,474 | 195,020 | 187,467 | ||
Operating Income | 103,163 | 83,228 | 300,455 | 263,079 | 275,681 |
Interest expense, net | (114,617) | (100,110) | (93,674) | ||
Other income, net | 15,832 | 19,434 | 8,252 | ||
Income tax (expense) benefit | (7,539) | 605 | (3,419) | ||
Net Income | 83,142 | 66,743 | 194,131 | 183,008 | 186,840 |
Total assets | 7,600,652 | 7,317,783 | 7,600,652 | 7,317,783 | 6,780,443 |
Segment, Expenditure, Addition to Long-Lived Assets | 566,889 | 515,140 | 434,328 | ||
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 |
Segment, Expenditure, Addition to Long-Lived Assets | 0 | 0 | 0 | ||
Operating Segments | Electric | |||||
Segment Reporting Information [Line Items] | |||||
Total revenues | 1,068,833 | 1,106,565 | 1,052,182 | ||
Utilities Operating Expense, Fuel Used | 262,755 | 324,434 | 294,820 | ||
Utility Margin | 806,078 | 782,131 | 757,362 | ||
Operating and maintenance | 166,028 | 167,798 | 156,383 | ||
Administrative and general | 83,521 | 82,405 | 72,641 | ||
Property and other taxes | 120,289 | 149,781 | 134,910 | ||
Depreciation and depletion | 174,071 | 162,404 | 154,626 | ||
Operating Income | 262,169 | 219,743 | 238,802 | ||
Interest expense, net | (84,089) | (74,420) | (82,678) | ||
Other income, net | 11,580 | 12,491 | 3,676 | ||
Income tax (expense) benefit | (14,196) | 798 | (2,512) | ||
Net Income | 175,464 | 158,612 | 157,288 | ||
Total assets | 6,071,021 | 5,892,508 | 6,071,021 | 5,892,508 | 5,432,578 |
Segment, Expenditure, Addition to Long-Lived Assets | 431,547 | 409,707 | 354,775 | ||
Operating Segments | Gas Domestic Regulated [Member] | |||||
Segment Reporting Information [Line Items] | |||||
Total revenues | 353,310 | 371,272 | 320,134 | ||
Utilities Operating Expense, Fuel Used | 157,507 | 167,577 | 130,728 | ||
Utility Margin | 195,803 | 203,695 | 189,406 | ||
Operating and maintenance | 54,496 | 53,629 | 51,920 | ||
Administrative and general | 32,657 | 31,002 | 27,550 | ||
Property and other taxes | 34,323 | 42,734 | 38,526 | ||
Depreciation and depletion | 36,403 | 32,616 | 32,841 | ||
Operating Income | 37,924 | 43,714 | 38,569 | ||
Interest expense, net | (15,719) | (13,030) | (6,083) | ||
Other income, net | 3,344 | 6,399 | 3,046 | ||
Income tax (expense) benefit | 4,627 | (3,108) | (2,640) | ||
Net Income | 30,176 | 33,975 | 32,892 | ||
Total assets | 1,512,135 | 1,418,059 | 1,512,135 | 1,418,059 | 1,342,031 |
Segment, Expenditure, Addition to Long-Lived Assets | 135,342 | 105,433 | 79,553 | ||
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 | 1,182 | 369 | 1,682 | ||
Property and other taxes | (1,544) | 9 | 8 | ||
Depreciation and depletion | 0 | 0 | 0 | ||
Operating Income | 362 | (378) | (1,690) | ||
Interest expense, net | (14,809) | (12,660) | (4,913) | ||
Other income, net | 908 | 544 | 1,530 | ||
Income tax (expense) benefit | 2,030 | 2,915 | 1,733 | ||
Net Income | (11,509) | (9,579) | (3,340) | ||
Total assets | $ 17,496 | $ 7,216 | 17,496 | 7,216 | 5,834 |
Segment, Expenditure, Addition to Long-Lived Assets | $ 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, 2023 | Dec. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Operating revenues | $ 356,009 | $ 425,283 | $ 1,422,143 | $ 1,477,837 | $ 1,372,316 |
Operating income | 103,163 | 83,228 | 300,455 | 263,079 | 275,681 |
Net Income | $ 83,142 | $ 66,743 | $ 194,131 | $ 183,008 | $ 186,840 |
Average Common Shares Outstanding | 61,244,000 | 58,345,000 | 60,321,481 | 55,769,156 | 51,709,229 |
Income per average common share | |||||
Income per average common share, basic | $ 1.37 | $ 1.16 | $ 3.22 | $ 3.28 | $ 3.61 |
Income per average common share, diluted | $ 1.37 | $ 1.16 | $ 3.22 | $ 3.25 | $ 3.60 |
Condensed Financial Information
Condensed Financial Information - Parent Company Only (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Condensed Income Statements, Captions [Line Items] | ||||||
Administrative and general | $ 117,360 | $ 113,776 | $ 101,873 | |||
Operating Income | $ (103,163) | $ (83,228) | (300,455) | (263,079) | (275,681) | |
Other Income, net | 15,832 | 19,434 | 8,252 | |||
Income Before Income Taxes | 201,670 | 182,403 | 190,259 | |||
Income tax (expense) benefit | (7,539) | 605 | (3,419) | |||
Net Income | 83,142 | 66,743 | 194,131 | 183,008 | 186,840 | |
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent | 192 | (538) | (41) | |||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 194,323 | 182,470 | 186,799 | |||
Condensed Balance Sheet Statements, Captions [Line Items] | ||||||
Cash and cash equivalents | 9,164 | 8,489 | 9,164 | 8,489 | 2,820 | |
Accounts receivable, net | 212,257 | 244,952 | 212,257 | 244,952 | ||
Assets, Current | 407,006 | 538,824 | 407,006 | 538,824 | ||
Other noncurrent assets | 52,314 | 47,323 | 52,314 | 47,323 | ||
Total assets | 7,600,652 | 7,317,783 | 7,600,652 | 7,317,783 | 6,780,443 | |
Other noncurrent liabilities | 332,372 | 355,403 | 332,372 | 355,403 | ||
Liabilities | 4,815,338 | 4,652,600 | 4,815,338 | 4,652,600 | ||
Stockholders' Equity Attributable to Parent | 2,785,314 | 2,665,183 | 2,785,314 | 2,665,183 | 2,339,713 | $ 2,079,095 |
Liabilities and Equity | 7,600,652 | 7,317,783 | 7,600,652 | 7,317,783 | ||
Condensed Cash Flow Statements, Captions [Line Items] | ||||||
Net Income | 83,142 | 66,743 | 194,131 | 183,008 | 186,840 | |
Increase (Decrease) in Accounts Receivable | 32,695 | (46,282) | (30,442) | |||
Net Cash Provided by (Used in) Operating Activities | 489,231 | 307,242 | 219,978 | |||
Net Cash Provided by (Used in) Investing Activities | (570,812) | (516,859) | (435,833) | |||
Treasury stock activity | 1,069 | 603 | 707 | |||
Payments of Ordinary Dividends, Common Stock | (154,050) | (140,062) | (128,483) | |||
Payments of Financing Costs | (4,327) | (1,194) | (909) | |||
Net Cash Provided by (Used in) Financing Activities | 84,305 | 213,318 | 217,521 | |||
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect | 2,724 | 3,701 | 1,666 | |||
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows | 25,187 | 22,463 | 25,187 | 22,463 | $ 18,762 | $ 17,096 |
Parent Company Condensed Income Statement | ||||||
Condensed Income Statements, Captions [Line Items] | ||||||
Administrative and general | 231 | |||||
Operating Expenses | 231 | |||||
Operating Income | 231 | |||||
Income (Loss) from Subsidiaries, Net of Tax | 83,142 | |||||
Other Income, net | 230 | |||||
Income Before Income Taxes | 83,141 | |||||
Income tax (expense) benefit | 0 | |||||
Net Income | 83,141 | |||||
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent | 365 | |||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 83,506 | |||||
Condensed Balance Sheet Statements, Captions [Line Items] | ||||||
Cash and cash equivalents | 59 | 59 | ||||
Accounts receivable, net | 207 | 207 | ||||
Assets, Current | 266 | 266 | ||||
Equity Method Investments | 2,784,924 | 2,784,924 | ||||
Other noncurrent assets | 4,063 | 4,063 | ||||
Total assets | 2,789,253 | 2,789,253 | ||||
Other noncurrent liabilities | 3,939 | 3,939 | ||||
Liabilities | 3,939 | 3,939 | ||||
Stockholders' Equity Attributable to Parent | 2,785,314 | 2,785,314 | ||||
Liabilities and Equity | 2,789,253 | 2,789,253 | ||||
Condensed Cash Flow Statements, Captions [Line Items] | ||||||
Net Income | 83,141 | |||||
Income (Loss) from Equity Method Investments | (83,142) | |||||
Proceeds from Equity Method Investment, Distribution | 39,042 | |||||
Increase (Decrease) in Accounts Receivable | (207) | |||||
Net Cash Provided by (Used in) Operating Activities | 38,834 | |||||
Payments of Distributions to Affiliates | 0 | |||||
Proceeds from Equity Method Investment, Distribution, Return of Capital | 0 | |||||
Net Cash Provided by (Used in) Investing Activities | 0 | |||||
Treasury stock activity | 351 | |||||
Payments of Ordinary Dividends, Common Stock | (39,002) | |||||
Payments of Financing Costs | (124) | |||||
Net Cash Provided by (Used in) Financing Activities | (38,775) | |||||
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect | 59 | |||||
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows | $ 59 | $ 0 | 59 | $ 0 | ||
Condensed Financial Information - Parent Company Only [Line Items] | ||||||
Proceeds from Contributions from Affiliates | $ (39,000) |