EX-99.1


NORTHWESTERN ENERGY GROUP
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per share amounts)
			Year Ended December 31,
			2024		2023		2022
Revenues
Electric	$		1,200,701	$	1,068,833	$	1,106,565
Gas			313,197		353,310		371,272
Total Revenues			1,513,898		1,422,143		1,477,837
Operating Expenses
Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)			433,816		420,262		492,011
Operating and maintenance			227,836		220,524		221,427
Administrative and general			137,437		117,360		113,776
Property and other taxes			163,853		153,068		192,524
Depreciation and depletion			227,635		210,474		195,020
Total Operating Expenses			1,190,577		1,121,688		1,214,758
Operating Income			323,321		300,455		263,079
Interest Expense, net			(131,673)		(114,617)		(100,110)
Other Income, net			23,024		15,832		19,434
Income Before Income Taxes			214,672		201,670		182,403
Income Tax Benefit (Expense)			9,439		(7,539)		605
Net Income		$	224,111	$	194,131	$	183,008


Average Common Shares Outstanding			61,293		60,321		55,769
Basic Earnings per Average Common Share		$	3.66	$	3.22	$	3.28
Diluted Earnings per Average Common Share		$	3.65	$	3.22	$	3.25

See Notes to Consolidated Financial Statements


NORTHWESTERN ENERGY GROUP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	(in thousands)
			Year Ended December 31,
			2024		2023		2022
Net Income		$	224,111	$	194,131	$	183,008
Other comprehensive income (loss), net of tax:
Reclassification of net losses on derivative instruments			452		452		452
Postretirement medical liability adjustment			504		(262)		(982)
Foreign currency translation			(4)		2		(8)
Total Other Comprehensive Income (Loss)			952		192		(538)
Comprehensive Income		$	225,063	$	194,323	$	182,470

See Notes to Consolidated Financial Statements


NORTHWESTERN ENERGY GROUP
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share amounts)
		As of December 31,
		2024		2023
ASSETS
Current Assets:
Cash and cash equivalents	$	4,283	$	9,164
Restricted cash		24,734		16,023
Accounts receivable, net		187,764		212,257
Inventories		122,940		114,539
Regulatory assets		39,851		29,626
Prepaid expenses and other		38,614		25,397
Total current assets		418,186		407,006
Property, plant, and equipment, net		6,398,275		6,039,801
Goodwill		357,586		357,586
Regulatory assets		764,414		743,945
Other noncurrent assets		59,063		52,314
Total Assets	$	7,997,524	$	7,600,652

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of finance leases	$	3,596	$	3,338
Current portion of long-term debt		299,950		99,950
Short-term borrowings		100,000		—
Accounts payable		111,794		124,340
Accrued expenses and other		254,599		246,167
Regulatory liabilities		32,261		61,103
Total current liabilities		802,200		534,898
Long-term finance leases		1,865		5,461
Long-term debt		2,695,343		2,684,635
Deferred income taxes		663,430		600,520
Noncurrent regulatory liabilities		660,942		657,452
Other noncurrent liabilities		316,044		332,372
Total Liabilities		5,139,824		4,815,338
Commitments and Contingencies (Note 18)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 64,810,932 and
61,320,812, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued		648		648
Treasury stock at cost		(97,394)		(97,926)
Paid-in capital		2,084,133		2,078,753
Retained earnings		877,017		811,495
Accumulated other comprehensive loss		(6,704)		(7,656)
Total Shareholders' Equity		2,857,700		2,785,314
Total Liabilities and Shareholders' Equity	$	7,997,524	$	7,600,652

See Notes to Consolidated Financial Statements


NORTHWESTERN ENERGY GROUP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
		Year Ended December 31,
		2024		2023		2022
OPERATING ACTIVITIES:
Net Income	$	224,111	$	194,131	$	183,008
Adjustments to reconcile net income to cash provided by operations:
Depreciation and depletion		227,635		210,474		195,020
Amortization of debt issuance costs, discount and deferred hedge gain		4,647		5,142		5,321
Stock-based compensation costs		4,721		5,176		5,488
Equity portion of AFUDC		(18,628)		(17,614)		(14,191)
(Gain) loss on disposition of assets		(61)		316		482
Impairment of alternative energy storage investment		4,159		—		—
Deferred income taxes		(8,969)		6,584		(8,992)
Changes in current assets and liabilities:
Accounts receivable		24,493		32,695		(46,282)
Inventories		(8,402)		(7,180)		(26,744)
Other current assets		(13,216)		2,644		(3,833)
Accounts payable		7,399		(54,722)		50,537
Accrued expenses		9,748		(3,377)		16,846
Regulatory assets		(10,109)		105,588		(20,512)
Regulatory liabilities		(28,842)		39,957		(7,034)
Other noncurrent assets and liabilities		(11,945)		(30,583)		(21,872)
Cash Provided by Operating Activities		406,741		489,231		307,242
INVESTING ACTIVITIES:
Property, plant, and equipment additions		(549,244)		(566,889)		(515,140)
Investment in equity securities		(4,719)		(3,923)		(1,719)
Other investing activity		(500)		—		—
Cash Used in Investing Activities		(554,463)		(570,812)		(516,859)
FINANCING ACTIVITIES:
Dividends on common stock		(158,589)		(154,050)		(140,062)
Proceeds from issuance of common stock, net		—		73,613		276,971
Issuance of long-term debt		215,000		300,000		—
Issuances of short-term borrowings		100,000		—		—
Repayments on long-term debt		(100,000)		—		—
Line of credit borrowings (repayments), net		95,000		(132,000)		77,000
Treasury stock activity		1,192		1,069		603
Financing costs		(1,051)		(4,327)		(1,194)
Cash Provided by Financing Activities		151,552		84,305		213,318
Net Increase in Cash, Cash Equivalents, and
Restricted Cash		3,830		2,724		3,701
Cash, Cash Equivalents, and Restricted Cash, beginning of period		25,187		22,463		18,762
Cash, Cash Equivalents, and Restricted Cash, end of period	$	29,017	$	25,187	$	22,463

See Notes to Consolidated Financial Statements

NORTHWESTERN ENERGY GROUP

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY

(in thousands, except per share data)


	Number of	Number of		Common		Paid in			Treasury			Retained		Accumulated			Total
	Common	Treasury		Common					Treasury										Other	Shareholders'
	Shares	Shares		Stock		Paid in	Capital			Stock		Retained	Earnings		Comprehensive Loss			Equity
Balance at December 31, 2021	57,606	3,546	$	576	$	1,716,227		$	(98,248)		$	728,468	$	(7,310)		$	2,339,713


Net income	—	—		—		—			—			183,008		—			183,008
Foreign currency translation	—	—		—		—			—			—		(8)			(8)
adjustment, net of tax	—	—							—			—		(8)			(8)
Reclassification of net gains on				—		—
derivative instruments from OCI to	—	—		—		—			—			—		452			452
net income, net of tax	—	—		—		—			—			—		452			452
Postretirement medical liability	—	—		—		—			—			—		(982)			(982)
adjustment, net of tax	—	—		—		—			—			—		(982)			(982)
Stock based compensation	87	16		—		7,391			(911)			—		—			6,480
Issuance of shares	5,585	(28)		57		275,758			767			—		—			276,582
Dividends on common stock ($2.52	—	—		—		—			—			(140,062)		—			(140,062)
per share)	—	—		—		—			—			(140,062)		—			(140,062)
Balance at December 31, 2022	63,278	3,534	$	633	$	1,999,376		$	(98,392)		$	771,414	$	(7,848)		$	2,665,183


Net income	—	—		—		—			—			194,131		—			194,131
Foreign currency translation	—	—		—		—			—			—		2			2
adjustment, net of tax	—	—		—		—			—			—		2			2
Reclassification of net losses on
derivative instruments from OCI to	—	—		—		—			—			—		452			452
net income, net of tax	—	—		—		—			—			—		452			452
Postretirement medical liability	—	—		—		—			—			—		(262)			(262)
adjustment, net of tax	—	—		—		—			—			—		(262)			(262)
Stock based compensation	51	—		—		4,954			—			—		—			4,954
Issuance of shares	1,433	(21)		15		74,423			466			—		—			74,904
Dividends on common stock ($2.56	—	—		—		—			—			(154,050)		—			(154,050)
per share)	—	—		—		—			—			(154,050)		—			(154,050)
Balance at December 31, 2023	64,762	3,513	$	648	$	2,078,753		$	(97,926)		$	811,495	$	(7,656)		$	2,785,314


Net income	—	—		—		—			—			224,111		—			224,111
Foreign currency translation	—	—		—		—			—			—		(4)			(4)
adjustment, net of tax	—	—		—		—			—			—		(4)			(4)
Reclassification of net losses on
derivative instruments from OCI to	—	—		—		—			—			—		452			452
net income, net of tax	—	—		—		—			—			—		452			452
Postretirement medical liability	—	—		—		—			—			—		504			504
adjustment, net of tax	—	—		—		—			—			—		504			504
Stock based compensation	49	—		—		4,672			(272)			—		—			4,400
Issuance of shares	—	(23)		—		708			804			—		—			1,512
Dividends on common stock ($2.60	—	—		—		—			—			(158,589)		—			(158,589)
per share)	—	—		—		—			—			(158,589)		—			(158,589)
Balance at December 31, 2024	64,811	3,490	$	648	$	2,084,133		$	(97,394)		$	877,017	$	(6,704)		$	2,857,700

See Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Nature of Operations and Basis of Consolidation

NorthWestern Energy Group, doing business as NorthWestern Energy, provides electricity and / or natural gas to approximately 787,000 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, 2024, have been evaluated as to their potential impact to the Consolidated Financial Statements through the date of issuance.

Holding Company Reorganization

On January 1, 2024, we completed the second and final phase of our 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.

(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, unrecognized tax benefits, 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

We recognize 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 $2.5 million and $2.8 million at December 31, 2024 and December 31, 2023, respectively. Receivables include unbilled revenues of $95.2 million and $105.1 million at December 31, 2024 and December 31, 2023, respectively.


	Inventories

	Inventories are stated at average cost. Inventory consisted of the following (in thousands):
			December 31,
			2024		2023
Materials and supplies		$	103,671	$	85,876
Storage gas and fuel			19,269		28,663
Total Inventories		$	122,940	$	114,539

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, 2024, 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 7.0%, 6.4%, and 6.4% for Montana for 2024, 2023, and 2022, respectively. This rate averaged 6.9%, 6.4%, and 6.4% for South Dakota and Nebraska for 2024, 2023, and 2022, respectively. AFUDC capitalized totaled $27.1 million, $24.3 million, and $20.2 million for the years ended December 31, 2024, 2023, and 2022, respectively, for Montana, South Dakota, and Nebraska 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 5 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 2.9% for 2024, and 2.8% for each of 2023 and 2022.

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,
		2024		2023
Property taxes	$	81,716	$	79,252
Employee compensation, benefits, and withholdings		49,786		41,773
Interest		28,702		24,775
Customer advances		16,535		27,656
Other (none of which is individually significant)		77,860		72,711
Total Accrued Expenses	$	254,599	$	246,167

Other Noncurrent Liabilities


Other noncurrent liabilities consisted of the following (in thousands):
		December 31,
		2024		2023
Customer advances	$	123,249	$	107,470
Pension and other employee benefits		56,603		75,302
AROs		37,725		39,255
Future QF obligation, net		23,498		28,670
Environmental		20,350		21,135
Other (none of which is individually significant)		54,619		60,540
Total Noncurrent Liabilities	$	316,044	$	332,372

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,
		2024		2023		2022
				(in thousands)
Cash (received) paid for:
Income taxes	$	(4,284)	$	(827)	$	4,707
Production tax credits(1)		(6,867)		—		—
Interest		128,333		105,238		95,400
Significant non-cash transactions:
Capital expenditures included in trade accounts payable		22,377		42,322		64,758

(1) Proceeds from production tax credits transferred are included in cash provided by operating activities within the Consolidated Statement of Cash Flows.

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,
		2024		2023		2022
Cash and cash equivalents	$	4,283	$	9,164	$	8,489
Restricted cash		24,734		16,023		13,974
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of	$	29,017	$	25,187	$	22,463
Cash Flows	$	29,017	$	25,187	$	22,463

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

In November 2023, the Financial Accounting Standards Board issued Accounting Standards Update 2023-07, Improvements to Reportable Segment Disclosures, which expands public entities' segment disclosures by requiring disclosure of significant segment expenses that are regularly reviewed by the Chief Operating Decision Maker (CODM) and included within each reported measure of segment profit or loss. We adopted this standard for annual periods beginning after December 15, 2023, and interim periods beginning after December 15, 2024, as required, and used the retrospective method of adoption, with no material impact on our Consolidated Financial Statements or internal controls.

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.

(3) Regulatory Matters

Montana Rate Review

In July 2024, we filed a Montana electric and natural gas rate review (2023 test year) with the MPSC. The filing requests a base rate annual revenue increase of $156.5 million ($69.4 million net with Property Tax and PCCAM tracker adjustments) for electric and $28.6 million for natural gas. Our request is based on a return on equity of 10.80 percent with a capital structure including 46.81 percent equity, and forecasted 2024 electric and natural gas rate base of $3.45 billion and $731.9 million, respectively. The electric rate base investment includes the 175-megawatt natural gas-fired Yellowstone County Generating Station, which was placed in service in October 2024.

In November 2024, the MPSC partially approved our requested interim rates, which are subject to refund, increasing electric and natural gas base rates by $18.4 million and $17.4 million, respectively, and decreasing our PCCAM base costs by $88.0 million, effective December 1, 2024.

In January 2025, intervenor testimony was filed and we anticipate filing our rebuttal testimony in March 2025. Based on the procedural schedule developed by the MPSC, a hearing on our rate review request is scheduled to commence on April 22, 2025. If a final order is not received by May 23, 2025, which is 270 days from acceptance of our filing, we intend to implement, as permitted by the MPSC regulations, our requested rates, which will be subject to refund, until a final order is received.

South Dakota Natural Gas Rate Review

In June 2024, we filed a natural gas rate review (2023 test year) with the SDPUC for an annual increase to natural gas rates totaling approximately $6.0 million. Our request was based on a rate of return of 7.75 percent and rate base of $95.6 million. In December 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 $4.6 million and an authorized rate of return of 6.91 percent. The approved settlement is based on a rate base of $96.2 million. Final rates were effective December 19, 2024.

Nebraska Natural Gas Rate Review

In June 2024, we filed a natural gas rate review (2023 test year) with the NPSC. The filing requests a base rate annual revenue increase of $3.6 million. Our request is based on a return on equity of 10.70 percent, a capital structure including 53.13 percent equity, and rate base of $47.4 million. Interim rates, which increased base natural gas rates $2.3 million, were implemented on October 1, 2024. Interim rates will remain in effect on a refundable basis until the NPSC issues a final order.

(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 our 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.


				December 31,
		Remaining		2024		2023
	Note Reference	Amortization Period		(in thousands)
Flow-through income taxes	12	Plant Lives	$	596,265	$	553,452
Pension	14	See Note 14		62,096		79,638
Excess deferred income taxes	12	Plant Lives		45,620		51,404
Employee related benefits	14	See Note 14		17,877		21,926
Deferred financing costs	11	See Note 11		17,754		20,028
Wildfire mitigation		Undetermined		17,368		1,623
Supply costs		1 Year		11,441		7,317
Environmental clean-up	18	Undetermined		11,257		11,131
State & local taxes & fees		1 Year		8,924		2,733
Other		Various		15,663		24,319
Total Regulatory Assets			$	804,265	$	773,571
Removal cost	6	Plant Lives
Removal cost	6	Plant Lives				$	537,210	$	523,744
Excess deferred income taxes	12	Plant Lives		125,878		136,382
Supply costs		1 Year		20,933		19,691
Gas storage sales		15 years		6,205		6,625
State & local taxes & fees		1 Year		251		30,576
Other		Various		2,726		1,537
Total Regulatory Liabilities			$	693,203	$	718,555

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.

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. The MPSC has approved the deferral of incremental operating costs related to this Enhanced Wildfire Mitigation Plan.

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 6.7 percent in Montana; 6.8 percent and 6.9 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.

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.

State & Local Taxes & Fees

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.

(5) Property, Plant and Equipment

The following table presents the major classifications of our property, plant and equipment (in thousands):


		December 31,
		2024		2023
		(in thousands)
Electric Plant	$	6,034,159	$	5,462,229
Natural Gas Plant		1,615,228		1,506,943
Plant acquisition adjustment(1)		686,328		686,328
Common and Other Plant		277,623		267,132
Construction work in process		164,767		377,241
Total property, plant and equipment		8,778,105		8,299,873
Less accumulated depreciation		(2,019,142)		(1,930,688)
Less accumulated amortization		(360,688)		(329,384)
Net property, plant and equipment	$	6,398,275	$	6,039,801

(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 $3.0 million and $5.2 million as of December 31, 2024 and 2023, respectively, which is primarily comprised of 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.

In January 2023 and July 2024, we entered into definitive agreements, the first with Avista and the second with Puget, to acquire their respective interests in Colstrip Units 3 & 4. In particular, we agreed to acquire a 15% (222 megawatts) interest from Avista and a 25% (370 megawatts) interest from Puget. Both agreements provide that the purchase price will be $0. These agreements are substantially similar and are both scheduled to close December 31, 2025, subject to the satisfaction of customary closing conditions and approvals contained within the agreements. Under the terms of the agreements, we will be responsible for operating costs starting on January 1, 2026; while Puget and Avista will remain responsible for their respective 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 their interests.

Acquisition of Avista and Puget's interests would result in our ownership of 55 percent of the facility with the ability to guide operating and maintenance investments. This would provide capacity to help us meet our obligation to provide reliable and cost effective power to our customers in Montana, while allowing opportunity for us to identify and plan for newer lower or no-carbon technologies in the future.

Either party may terminate the respective separate 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
		(SD)		(IA)		(ND)		(MT)
December 31, 2024

Ownership percentages		23.4 %		8.7 %		10.0 %		30.0 %
Plant in service	$	157,572	$	65,426	$	52,430	$	330,888
Accumulated depreciation		49,573		39,025		39,887		137,153
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

(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,
	2024			2023		2022
Liability at January 1,	$	41,424	$	40,894	$	40,631
Accretion expense		1,937		1,899		1,853
Liabilities incurred		—		—		—
Liabilities settled		(2,044)		(1,244)		(4,004)
Revisions to cash flows		(265)		(125)		2,414
Liability at December 31,	$	41,052	$	41,424	$	40,894

During the twelve months ended December 31, 2024, our ARO liability decreased $2.0 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, 2024, our ARO liability decreased $0.3 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, 2024 and 2023.

(7) Goodwill

We completed our annual goodwill impairment test as of April 1, 2024, and no impairment was identified. We calculate the fair value of our reporting units by considering various factors, including valuation studies based primarily on a discounted cash flow analysis, with published industry valuations and market data as supporting information. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in our service territory, regulatory stability, and commodity prices (where appropriate), as well as other factors that affect our revenue, expense and capital expenditure projections.


Goodwill by segment is as follows (in thousands):
		December 31,
		2024		2023
Electric	$	243,558	$	243,558
Natural gas		114,028		114,028
Total Goodwill	$	357,586	$	357,586

(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, 2024 and 2023. 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):


	Location of Amount Reclassified		Amount Reclassified from
Cash Flow Hedges	Location of Amount Reclassified				AOCL into Income during the
Cash Flow Hedges		from AOCL to Income		Year Ended December 31, 2023
Interest rate contracts	Interest Expense	$	612

A pre-tax loss of approximately $12.2 million is remaining in AOCL as of December 31, 2024, 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.

(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.


		Quoted Prices in Active		Significant Other
		Markets for Identical		Significant Other			Significant Unobservable			Margin Cash Collateral
December 31, 2024		Assets or	Observable Inputs (Level							Margin Cash Collateral		Total Net Fair Value
December 31, 2024			Liabilities (Level 1)		2)		Significant Unobservable		Inputs (Level 3)		Offset	Total Net Fair Value
						(in thousands)
Restricted cash equivalents	$	1,076	$	—	$	—		$	—	$	1,076
Rabbi trust investments		18,749		—		—			—		18,749
Total	$	19,825	$	—	$	—		$	—	$	19,825


December 31, 2023
Restricted cash equivalents	$	14,996	$	—	$	—		$	—	$	14,996
Rabbi trust investments		17,093		—		—			—		17,093
Total	$	32,089	$	—	$	—		$	—	$	32,089

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, 2024				December 31, 2023
	Carrying Amount			Fair Value	Carrying Amount			Fair Value
Liabilities:
Long-term debt	$	2,995,293	$	2,645,779	$	2,784,585	$	2,521,030

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.

(10) Short-Term Borrowings and Credit Arrangements

Short-Term Borrowings

On April 12, 2024, NorthWestern Energy Group entered into a $100.0 million Term Loan Credit Agreement (Term Loan) with a maturity date of April 11, 2025. Borrowings may be made at a variable interest rate equal to the Secured Overnight Financing Rate plus an applicable margin as provided in the Term Loan. These proceeds were used to repay a portion of our outstanding revolving credit facility borrowings and for general corporate purposes. The Term Loan provides for prepayment of the principal and interest; however, amounts prepaid may not be reborrowed. The Term Loan requires us to maintain a consolidated indebtedness to total capitalization ratio of 65 percent or less. It also contains covenants which, among other things, limit our ability to engage in any consolidation or merger or otherwise liquidate or dissolve, dispose of property, and restricts certain affiliate transactions. A default on the South Dakota or Montana First Mortgage Bonds would trigger a cross default on the Term Loan; however a default on the Term Loan would not trigger a default on the South Dakota or Montana First Mortgage Bonds.

Credit Facility

On 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. The Amended Facility has uncommitted features that allow NW Corp to request one-year extensions to the maturity date and increase the size of the Amended Facility by an additional $100.0 million.

On January 24, 2025, NW Corp amended its existing $400.0 million Amended Facility to increase the capacity to $425.0 million. This amendment did not affect the maturity date or borrowing rates.

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 $0.7 million and $0.6 million for the years ended December 31, 2024 and 2023.

The availability under the facilities in place for the years ended December 31 is shown in the following table (in millions):


		2024		2023
Unsecured revolving line of credit, expiring November 2028		600.0		425.0
Unsecured revolving line of credit, expiring April 2024		—		100.0
Unsecured revolving line of credit, expiring March 2025		—		25.0
		600.0		550.0

Amounts outstanding at December 31:
SOFR borrowings		413.0		318.0
Letters of credit		—		—
		413.0		318.0

Net availability as of December 31	$	187.0	$	232.0

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.

(11) Long-Term Debt and Finance Leases


Long-term debt and finance leases consisted of the following (in thousands):
				December 31,
	Due			2024		2023
Unsecured Debt:
Unsecured Revolving Line of Credit		2028		413,000		318,000
Secured Debt:
Mortgage bonds—
South Dakota—5.01%		2025		64,000		64,000
South Dakota—2.80%		2026		60,000		60,000
South Dakota—2.66%		2026		45,000		45,000
South Dakota—5.55%		2029		33,000		—
South Dakota—3.21%		2030		50,000		50,000
South Dakota—5.57%		2033		31,000		31,000
South Dakota—5.42%		2033		30,000		30,000
South Dakota—5.75%		2034		7,000		—
South Dakota—4.26%		2040		70,000		70,000
South Dakota—4.15%		2042		30,000		30,000
South Dakota—4.85%		2043		50,000		50,000
South Dakota—4.22%		2044		30,000		30,000
South Dakota—4.30%		2052		20,000		20,000
Montana—1.00%		2024		—		100,000
Montana—5.01%		2025		161,000		161,000
Montana—3.11%		2025		75,000		75,000
Montana—3.99%		2028		35,000		35,000
Montana—3.21%		2030		100,000		100,000
Montana—5.56%		2031		175,000		—
Montana—5.57%		2033		239,000		239,000
Montana—5.71%		2039		55,000		55,000
Montana—4.15%		2042		60,000		60,000
Montana—4.85%		2043		15,000		15,000
Montana—4.176%		2044		450,000		450,000
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—4.30%		2052		40,000		40,000
Pollution control obligations—
Montana—3.88%		2028		144,660		144,660
Other Long Term Debt:

Discount on Notes and Bonds and Debt Issuance Costs, Net		—		(12,367)		(13,075)
Total Long-Term Debt			$	2,995,293	$	2,784,585
Less current maturities (including associated debt issuance costs)
							(299,950)	(99,950)
Total Long-Term Debt, Net of Current Maturities			$	2,695,343	$	2,684,635


Finance Leases:
Total Finance Leases		2026	$	5,461	$	8,799
Less current maturities				(3,596)		(3,338)
Total Long-Term Finance Leases			$	1,865	$	5,461

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.

On March 28, 2024, NW Corp issued and sold $175.0 million aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 5.56 percent maturing on March 28, 2031. These bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933. Proceeds were used to redeem NW Corp's $100.0 million of Montana First Mortgage Bonds due this year and for other general utility purposes. The bonds are secured by NW Corp's electric and natural gas assets associated with its Montana utility operations.

On March 28, 2024, NWE Public Service issued and sold $33.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.55 percent maturing on March 28, 2029, and $7.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.75 percent maturing on March 28, 2034. These bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933. Proceeds were used for general utility purposes. The bonds are secured by NWE Public Service's electric and natural gas assets associated with its South Dakota and Nebraska utility operations.

As of December 31, 2024, 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 $303.6 million in 2025, $106.9 million in 2026, $592.7 million in 2028, and $33.0 million in 2029.

(12) Income Taxes

Income tax (benefit) expense is comprised of the following (in thousands):


		Year Ended December 31,
		2024		2023		2022
Federal
Current	$	(8,121)	$	2,925	$	5,024
Deferred		(3,807)		2,929		(5,993)
Investment tax credits		1,970		(129)		(130)
State
Current		(41)		(1,971)		3,363
Deferred		560		3,785		(2,869)
Income Tax (Benefit) Expense	$	(9,439)	$	7,539	$	(605)
Deferred income tax expense is comprised of the following (in thousands):

		Year Ended December 31,
		2024		2023		2022
Deferred tax expense excluding items below	$	54,950	$	61,537	$	39,349
Adjustments to other noncurrent liabilities, regulatory assets, and liabilities		(65,596)		(54,732)		(48,428)
Tax (benefit) expense allocated to other comprehensive income		(293)		(91)		217
Adjustments to deferred income taxes for production tax credit cash transfer		7,692		—		—
Investment tax credits		1,970		(129)		(130)
Deferred tax (benefit) expense	$	(1,277)	$	6,585	$	(8,992)

Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable), and production tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.

The following table reconciles our effective income tax rate to the federal statutory rate:

Year Ended December 31,


	2024	2023		2022
Federal statutory rate		21.0 %	21.0 %	21.0 %
State income tax, net of federal provisions		0.2	0.3	0.3
Flow-through repairs deductions		(10.8)	(12.9)	(12.4)
Release of unrecognized tax benefits (inclusive of related interest previously
accrued)		(9.8)	(1.6)	—
Production tax credits		(5.2)	(5.1)	(7.2)
Gas repairs safe harbor method change		(3.3)	—	—
Amortization of excess deferred income taxes		(1.4)	(1.1)	(0.9)
Prior year permanent return to accrual adjustments		(0.2)	—	(0.8)
Plant and depreciation of flow through items		4.4	3.3	(0.1)
Unregulated Tax Cuts and Jobs Act excess deferred income taxes		—	(1.7)	—
Reduction to previously claimed alternative minimum tax credit		—	1.6	—
Other, net		0.7	(0.1)	(0.2)
Effective tax rate		(4.4)%	3.7 %	(0.3)%

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). All of our income from continuing operations is primarily from domestic operations.


		Year Ended December 31,
		2024		2023		2022
Income Before Income Taxes	$	214,672	$	201,670	$	182,403

Income tax calculated at federal statutory rate		45,081		42,350		38,304

Permanent or flow through adjustments:
State income, net of federal provisions		374		606		562
Flow-through repairs deductions		(23,132)		(25,922)		(22,665)
Release of unrecognized tax benefits (2024 is inclusive of $4.1 million of related
interest previously accrued)		(20,993)		(3,241)		—
Production tax credits		(11,069)		(10,274)		(13,166)
Gas repairs safe harbor method change		(6,994)		—		—
Amortization of excess deferred income taxes		(2,930)		(2,184)		(1,657)
Prior year permanent return to accrual adjustments		(433)		45		(1,397)
Plant and depreciation of flow through items		9,360		6,595		(222)
Unregulated Tax Cuts and Jobs Act excess deferred income taxes		—		(3,385)		—
Reduction to previously claimed alternative minimum tax credit		—		3,186		—
Other, net		1,297		(237)		(364)
		(54,520)		(34,811)		(38,909)

Income Tax (Benefit) Expense	$	(9,439)	$	7,539	$	(605)

In 2023, the Internal Revenue Service (IRS) issued a safe harbor method of accounting for the repair and maintenance of natural gas transmission and distribution property. For the year ending December 31, 2024, after completion of our impact analysis of the gas repairs safe harbor method change, we recorded an income tax benefit of approximately $7.0 million related to tax deductions for repair costs that were previously capitalized in the 2022 and prior tax years.

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,
		2024		2023
NOL carryforward	$	123,043	$	113,366
Production tax credit		97,695		94,283
Customer advances		32,455		28,300
Compensation accruals		12,717		10,716
Pension / postretirement benefits		9,078		15,131
Unbilled revenue		6,477		10,604
Environmental liability		5,415		5,760
Interest rate hedges		2,985		3,280
Reserves and accruals		2,252		3,098
Other, net		3,369		2,677
Deferred Tax Asset		295,486		287,215
Excess tax depreciation		(713,416)		(660,440)
Flow through depreciation		(132,944)		(120,558)
Goodwill amortization		(89,827)		(88,323)
Regulatory assets and other		(22,729)		(18,414)
Deferred Tax Liability		(958,916)		(887,735)
Deferred Tax Liability, net	$	(663,430)	$	(600,520)

As of December 31, 2024, our total federal NOL carryforward was approximately $486.6 million. Our federal NOL carryforward does not expire. Our state NOL carryforward as of December 31, 2024 was approximately $391.2 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, 2024, our total production tax credit carryforward was approximately $97.7 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, $2.6 million in 2043, and $11.1 million in 2044. We believe it is more likely than not that sufficient taxable income will be generated to utilize these production tax credit carryforwards.

Unrecognized Tax Benefits

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):


		2024		2023		2022
Unrecognized Tax Benefits at January 1	$	28,074	$	30,330	$	32,049
Gross increases - tax positions in prior period		—		—		—
Gross increases - tax positions in current period		—		—		—
Gross decreases - tax positions in current period		(1,574)		(2,256)		(1,719)
Lapse of statute of limitations		(16,888)		—		—
Unrecognized Tax Benefits at December 31	$	9,612	$	28,074	$	30,330

Our unrecognized tax benefits include approximately $7.4 million and $24.4 million related to tax positions as of December 31, 2024 and 2023, that if recognized, would impact our annual effective tax rate. During the year ending December 31, 2024, due to the expiration of the statute of limitations we decreased our unrecognized tax benefits by $16.9 million. 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 unrecognized tax benefits, which would result in a decrease to our total unrecognized tax benefits of approximately $9.4 million.

Our policy is to recognize interest and penalties related to unrecognized tax benefits in income tax expense. As of December 31, 2024, we have accrued $3.0 million for the payment of interest and penalties in the Consolidated Balance Sheets. As of December 31, 2023, we had $4.5 million accrued for the payment of interest and penalties.

Tax years 2021 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.

(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,
				2024						2023						2022
	Before-Tax			Tax	Net-of-Tax		Before-Tax		Tax Expense		Net-of-Tax		Before-Tax		Tax Expense		Net-of-Tax
	Before-Tax			Expense	Net-of-Tax		Before-Tax				Net-of-Tax		Before-Tax				Net-of-Tax
	Amount			Expense	Amount		Amount				Amount		Amount					Amount
	Amount		(Benefit)		Amount		Amount			(Benefit)	Amount		Amount			(Benefit)		Amount
			(Benefit)							(Benefit)						(Benefit)
Foreign currency
translation adjustment	$	(4)	$	—	$	(4)	$	2	$	—	$	2	$	(8)	$	—	$	(8)
Reclassification of net
income (loss) on
derivative instruments		612		(160)		452		612		(160)		452		612		(160)		452
Postretirement medical
liability adjustment		637		(133)		504		(331)		69		(262)		(1,359)		377		(982)
Other comprehensive	$	1,245	$	(293)	$	952	$	283	$	(91)	$	192	$	(755)	$	217	$	(538)
income (loss)	$	1,245	$	(293)	$	952	$	283	$	(91)	$	192	$	(755)	$	217	$	(538)

Balances by classification included within AOCL on the Consolidated Balance Sheets are as follows, net of tax (in thousands):


		December 31,
Foreign currency translation	2024				2023
Foreign currency translation		$	1,433		$	1,437
Derivative instruments designated as cash flow hedges		(8,921)			(9,373)
Postretirement medical plans		784			280
Accumulated other comprehensive loss	$	(6,704)		$	(7,656)

The following table displays the changes in AOCL by component, net of tax (in thousands):


		31-Dec-24
		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		$	(9,373	)	$	280	$	1,437		$	(7,656	)
Other comprehensive loss before reclassifications			—			—		(4	)		(4	)
Amounts reclassified from AOCL	Interest Expense		452			—		—			452
Amounts reclassified from AOCL			—			504		—			504
Net current-period other comprehensive income (loss)			452			504		(4	)		952
Ending Balance		$	(8,921	)	$	784	$	1,433		$	(6,704	)


		31-Dec-23
		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 loss 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	)

(14) Employee Benefit Plans

Pension and Other Postretirement Benefit Plans

We sponsor and/or contribute to pension, 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 Energy SD/NE Plan (formerly known as the NorthWestern Corporation Plan), the pension plan for our Montana employees is referred to as the NorthWestern Energy MT Plan (formerly known 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 Obligations 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,
		2024		2023		2024		2023
Change in benefit obligation:
Obligation at beginning of period	$	473,988	$	521,798	$	13,708	$	15,407
Service cost		5,592		5,646		308		333
Interest cost		22,944		25,852		557		674
Actuarial (gain) loss		(28,499)		3,127		(2,514)		(1,240)
Settlements(1)		(848)		(51,942)		—		—
Benefits paid		(25,230)		(30,493)		(1,333)		(1,466)
Benefit Obligation at End of Period	$	447,947	$	473,988	$	10,726	$	13,708

Change in fair value of plan assets:
Fair value of plan assets at beginning of period	$	402,671	$	441,539	$	22,309	$	20,055
Return on plan assets		9,411		34,367		3,177		3,334
Employer contributions		9,322		9,200		619		386
Settlements(1)		(848)		(51,942)		—		—
Benefits paid		(25,230)		(30,493)		(1,333)		(1,466)
Fair value of plan assets at end of period	$	395,326	$	402,671	$	24,772	$	22,309
Funded Status	$	(52,621)	$	(71,317)	$	14,046	$	8,601

Amounts Recognized in the Balance Sheet Consist of:


	Noncurrent asset			9,467		7,875		16,943		12,378
Total Assets				9,467		7,875		16,943		12,378
	Current liability			(10,000)		(11,200)		(1,310)		(1,355)
	Noncurrent liability			(52,088)		(67,992)		(1,587)		(2,422)
Total Liabilities				(62,088)		(79,192)		(2,897)		(3,777)
Net amount recognized			$	(52,621)	$	(71,317)	$	14,046	$	8,601


Amounts Recognized in Regulatory Assets Consist of:

	Prior service credit			—		—		—		—
	Net actuarial (loss) gain			(31,835)		(44,453)		3,716		15
Amounts recognized in AOCL consist of:
		Prior service cost		—		—		—		—
	Net actuarial gain			—		—		1,228		590
Total			$	(31,835)	$	(44,453)	$	4,944	$	605

(1)

In October 2023, we entered into a group annuity contract from an insurance company to provide for the payment of pension benefits to select NorthWestern Energy MT Pension Plan participants. We purchased the contract with $51.9 million of plan assets in 2023. A trailing premium of $0.8 million related to final data reconciliation was paid from plan assets in 2024, reflecting a final, annuitized participant count of 276. The insurance company took over the payments of these benefits starting January 1, 2024. This transaction settled $52.7 million of our NorthWestern Energy MT 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 NorthWestern Energy MT Pension Plan with accumulated benefit obligations in excess of plan assets were as follows (in millions):


	NorthWestern Energy MT Pension Plan
	December 31,
	2024			2023
Projected benefit obligation	$	404.8	$	427.3
Accumulated benefit obligation		404.8		427.3
Fair value of plan assets		342.7		348.1

As of December 31, 2024, the fair value of the NorthWestern Energy SD/NE Pension Plan assets exceeds 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,
		2024		2023		2022		2024		2023		2022
Components of net periodic benefit
cost
Service cost	$	5,592	$	5,646	$	10,223	$	308	$	333	$	351
Interest cost		22,944		25,852		18,787		557		674		359
Expected return on plan assets		(25,325)		(25,932)		(24,173)		(1,280)		(1,096)		(1,047)
Amortization of prior service cost
(credit)		—		—		—		—		116		(1,891)
Recognized actuarial loss (gain)		33		228		383		(73)		(672)		(897)
Settlement loss recognized(1)		—		4,395		—		—		—		—
Net Periodic Benefit Cost (Credit)	$	3,244	$	10,189	$	5,220	$	(488)	$	(645)	$	(3,125)

Regulatory deferral of net periodic
benefit cost(2)		4,850		(1,814)		2,307		—		—		—
Previously deferred costs recognized(2)		75		210		—		181		550		292
Net Periodic Benefit Cost (Credit)	$	8,169	$	8,585	$	7,527	$	(307)	$	(95)	$	(2,833)
Recognized	$	8,169	$	8,585	$	7,527	$	(307)	$	(95)	$	(2,833)

(1)

Settlement loss is related to partial annuitization of NorthWestern Energy MT Pension Plan effective October 24, 2023.

(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, 2024, 2023, and 2022, 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, 2024 and 2023. 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 increase in the discount rate during 2024 decreased our projected benefit obligation by approximately $29.6 million.

In determining the expected long-term rate of return on plan assets, we review historical returns, the future expectations for returns for each asset class weighted by the target asset allocation of the pension and postretirement portfolios, and long-term inflation assumptions. Based on the target asset allocation for our pension assets and future expectations for asset returns, we decreased our long term rates of return on asset assumptions for the NorthWestern Energy MT Pension Plan and the NorthWestern Energy SD/NE Pension Plan to 6.17 percent and 4.58 percent, respectively, for 2025.

The weighted-average assumptions used in calculating the preceding information are as follows:


			Pension Benefits				Other Postretirement Benefits
			December 31,						December 31,
	2024		2023		2022		2024		2023			2022
Discount rate	5.50-5.60	%		4.95-5.00	5.20	%	5.30-5.45	%		4.85-4.90	%	5.15-5.20	%
Expected rate of return on assets	5.15-6.65		4.83-6.44		2.66-4.26		5.84		5.62			4.23
Long-term rate of increase in compensation levels (non-union)	4.00			4.00	4.00		4.00			4.00		4.00
Long-term rate of increase in compensation levels (union)	4.00			4.00	4.00		4.00			4.00		4.00
Interest crediting rate	3.3-6.0		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 MT 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 MT		NorthWestern Energy SD/NE		NorthWestern Energy
	Pension		Pension		Health and Welfare
	December 31,		December 31,		December 31,
	2024	2023	2024	2023	2024	2023
Fixed income securities	45.0 %	45.0 %	90.0 %	90.0 %	40.0 %	40.0 %
Non-U.S. fixed income securities	—	—	—	—	—	—
Opportunistic fixed income	11.0	11.0	3.0	3.0	—	—
Global equities	38.5	38.5	7.0	7.0	60.0	60.0
Private real estate	5.5	5.5	—	—	—	—

The actual allocation by plan is as follows:


	NorthWestern Energy MT		NorthWestern Energy SD/NE		NorthWestern Energy
	Pension		Pension		Health and Welfare
	December 31,		December 31,		December 31,
	2024	2023	2024	2023	2024	2023
Cash and cash equivalents	— %	— %	0.8 %	1.5 %	0.3 %	0.2 %
Fixed income securities(1)	43.7	45.3	89.4	88.7	32.2	35.1
Non-U.S. fixed income securities	—	—	—	—	—	—
Opportunistic fixed income	11.1	10.6	2.9	2.9	—	—
Global equities(1)	39.0	37.6	6.9	6.9	67.5	64.7
Private real estate	6.2	6.5	—	—	—	—
	100.0 %	100.0 %	100.0 %	100.0 %	100.0 %	100.0 %

(1)

While the NorthWestern Energy Health and Welfare plan allocation of assets as of December 31, 2024, between Fixed income securities and Global equities is greater than 5 percent different from the target allocation, the plan Investment Manager has 60 days to correct this deviation from the plan.

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 2024, 2023 and 2022 were based on actual contributions to the NorthWestern Energy MT Pension Plan. Annual contributions to each of the pension plans are as follows (in thousands):


	2024			2023		2022
NorthWestern Energy MT Pension Plan	$	8,122	$	8,000	$	7,000
NorthWestern Energy SD/NE Pension Plan		1,200		1,200		1,200
	$	9,322	$	9,200	$	8,200

We estimate the plans will make future benefit payments to participants as follows (in thousands):
				Pension Benefits		Other Postretirement
				Pension Benefits			Benefits
2025				28,549		1,919
2026				29,467		1,216
2027				30,393		1,064
2028				31,155		1,015
2029				32,218		935
2030-2034				166,566		4,329

Defined Contribution Plan

Our defined contribution plan permits employees to defer receipt of compensation as provided in Section 401(k) of the Internal Revenue Code. Under the plan, employees may elect to direct a percentage of their gross compensation to the plan. We also contribute various percentages of employees' gross compensation to the plan. Company contributions for the years ended December 31, 2024, 2023 and 2022 totaled $14.7 million, $13.2 million, and $12.3 million, respectively.

(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, 2024, there were 558,300 shares of common stock remaining available for grants. The remaining vesting period for awards previously granted ranges from one to three 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:


	2024	2023
Risk-free interest rate	4.38 %	4.33 %
Expected life, in years	3	3
Expected volatility	12.5% to 29.0%	30.4% to 41.0%
Dividend yield	5.6 %	4.4 %

The risk-free interest rate was based on the U.S. Treasury yield of a three-year bond at the time of grant. The expected term of the performance shares is three years based on the performance cycle. Expected volatility was based on the historical volatility for the peer group. Both performance goals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares expected to vest.

A summary of nonvested shares as of and changes during the year ended December 31, 2024, are as follows:


	Performance Unit Awards
			Weighted-Average Grant-
	Shares		Date
	Shares			Fair Value
Beginning nonvested grants		153,784	$	53.26
Granted		150,704		41.13
Vested		(60,830)		51.61
Forfeited		(11,732)		48.12
Remaining nonvested grants		231,926	$	46.07

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, 2024. 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, 2024, are as follows:
			Weighted-Average Grant-
	Shares			Date
	Shares				Fair Value
Beginning nonvested grants		60,779	$	47.91
Granted		—		—
Vested		—		—
Forfeited		(9,983)		60.73
Remaining nonvested grants		50,796	$	45.40

We recognized total stock-based compensation expense of $3.4 million, $3.6 million, and $4.2 million for the years ended December 31, 2024, 2023, and 2022, respectively, and related income tax benefit of $(0.7) million, $(1.0) million, and $(1.3) million for the years ended December 31, 2024, 2023, and 2022, respectively. As of December 31, 2024, we had $6.6 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 $3.1 million, $4.4 million, and $4.3 million for the years ended December 31, 2024, 2023 and 2022, respectively.

(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, 2,856,957 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 5,809 and 4,167 during the years ended December 31, 2024 and 2023, respectively, and are reflected in treasury stock. These shares were credited to treasury stock based on their fair market value on the vesting date.

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. Further, the declaration of dividends is at the discretion of our Board of Directors and is not guaranteed.

As of December 31, 2024, approximately $784.6 million and $294.6 million of NW Corp and NWE Public Service unrestricted net assets, respectively, were available for the payment of dividends to NorthWestern Energy Group under our most restrictive dividend restriction.

(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,
	2024	2023	2022
Basic computation	61,293,052	60,321,481	55,769,156
Dilutive effect of
Performance and restricted share awards(1)	81,153	36,312	26,621
Forward equity sale(2)	—	—	496,333
Diluted computation	61,374,205	60,357,793	56,292,110

(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, 2024, there were 22,470 shares from performance and restricted share awards which were antidilutive and excluded from the earnings per share calculations.

(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 $118 to $130 per MWH through 2029. As of December 31, 2024, our estimated gross contractual obligation related to these contracts was approximately $229.0 million through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $205.8 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,
	2024		2023
Beginning QF liability	$	28,670	$	49,728
Settlements		(7,606)		(24,707)
Interest expense		2,434		3,649
Ending QF liability	$	23,498	$	28,670

The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands):


		Gross		Recoverable		Net
		Obligation		Amounts		Net
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)	$	228,952	$	205,787	$	23,165

(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 $290.1 million, $340.0 million and $328.0 million for the years ended December 31, 2024, 2023, and 2022, respectively. As of December 31, 2024, our commitments under these contracts were $345.8 million in 2025, $365.2 million in 2026, $350.4 million in 2027, $349.3 million in 2028, $350.2 million in 2029, and $2.5 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 $19.1 million between 2025 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 $19.0 million to $29.9 million. As of December 31, 2024, we had a reserve of approximately $23.7 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,
	2024			2023		2022
Liability at January 1,	$	25,286	$	26,367	$	26,866
Deductions		(2,262)		(2,520)		(2,033)
Charged to costs and expense		705		1,439		1,534
Liability at December 31,	$	23,729	$	25,286	$	26,367

We are permitted to recover the remediation costs related to certain environmental liabilities within rates. Over time, as costs become determinable, we may seek authorization to recover additional costs in rates or seek insurance reimbursement as available and applicable; therefore, although we cannot guarantee regulatory recovery for all remediation costs, we do not expect these costs to have a material effect on our consolidated financial position or results of operations.

Manufactured Gas Plants - Approximately $18.2 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, 2024, the reserve for remediation costs at this site was approximately $7.2 million, and we estimate that approximately $2.1 million of this amount will be incurred through 2029. The SDPUC permits the recovery of these costs within rates.

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 2025, 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 (CO2) 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.

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 April 2024, the EPA released final rules related to greenhouse gas (GHG) emission standards (GHG Rules) for existing coal-fired facilities and new coal and natural gas-fired facilities as well as final rules strengthening the MATS requirements (MATS Rules). In particular, the GHG Rules will (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). The MATS Rules will strengthen emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. Compliance with the rules will require expensive upgrades at Colstrip Units 3 and 4 with proposed compliance dates that may not be achievable and / or require technology that is unproven, resulting in significant impacts to costs of the facilities. The final MATS and GHG Rules require compliance as early as 2027 and 2032, respectively.

Previous efforts by the EPA were met with extensive litigation, and this time is no different. We, along with many other utilities, electric cooperatives, organizations, and states, have petitioned for judicial review of the GHG and MATS Rules with the U.S. Court of Appeals for the D.C. Circuit. The United States Supreme Court denied multiple stay requests related to the MATS and GHG Rules. The litigation on the merits continues for both the MATS and GHG Rules in the D.C. Circuit Court of Appeals, and decisions are expected in 2025. If the MATS Rule and GHG Rule are ultimately enforced, it would result in additional material compliance costs. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from the MATS and GHG regulations that, in our view, disproportionately impact customers in our region.

These GHG and MATS Rules as well as 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. The appeal was argued on January 15, 2025, and we await the court's disposition. Damages were bifurcated by agreement and will be tried separately for the Black Eagle segment, and any other segments found navigable, should the State prevail on appeal.

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.

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 YCGS 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 YCGS 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 appeal to the Montana Supreme Court. We recommenced YCGS construction in June 2023 and placed the plant in service in October 2024. On January 3, 2025, the Montana Supreme Court ordered that the YCGS air quality permit be reinstated. The Court remanded the matter back to MDEQ for supplemental analysis regarding lighting and greenhouse gas emissions in Montana. YCGS is commercially operable with the reinstated air quality permit.

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.

(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, 2024		Electric		Natural Gas		Total
Montana		398.8		110.2		509.0
South Dakota		70.0		26.9		96.9
Nebraska		—		21.2		21.2
Residential		468.8		158.3		627.1
Montana		409.0		59.9		468.9
South Dakota		111.8		18.1		129.9
Nebraska		—		11.4		11.4
Commercial		520.8		89.4		610.2
Industrial		46.6		1.0		47.6
Lighting, governmental, irrigation, and interdepartmental		32.8		1.4		34.2
Total Retail Revenues		1,069.0		250.1		1,319.1
Regulatory Amortization		24.9		19.0		43.9
Transmission		97.1		—		97.1
Wholesale and other		9.7		44.1		53.8
Total Revenues	$	1,200.7	$	313.2	$	1,513.9


December 31, 2023		Electric		Natural Gas		Total
Montana		408.3		136.1		544.4
South Dakota		67.9		36.6		104.5
Nebraska		—		35.5		35.5
Residential		476.2		208.2		684.4
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 Retail Revenues		1,089.5		333.0		1,422.5
Regulatory Amortization		(105.6)		(25.0)		(130.6)
Transmission		78.4		—		78.4
Wholesale and other		6.5		45.3		51.8
Total Revenues(1)	$	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 Retail Revenues		974.8		360.6		1,335.4
Regulatory Amortization		46.4		(28.1)		18.3
Transmission		77.8		—		77.8
Wholesale and other		7.6		38.7		46.3
Total Revenues(1)	$	1,106.6	$	371.2	$	1,477.8

(1)

Certain amounts in the prior period have been reclassified to conform with current period presentation. These reclassifications have no effect on the reported financial results.

(20)

Segment and Related Information

Our reportable segments are engaged in the electric and gas utility businesses. Our Electric segment includes the aggregated operating segment results of the regulated electric utility operations of Montana and South Dakota. Our Gas segment includes the aggregated operating segment results of the regulated gas utility operations of Montana, South Dakota, and Nebraska.

Our CODM, who is our Chief Executive Officer, uses segment net income to evaluate if our operating segments are earning their authorized rate of return and in the annual budget and forecasting process. Our CODM uses segment net income to determine how to allocate capital resources between our operating segments and when to allocate the resources necessary to file for rate reviews. The accounting policies of the operating segments are the same as those described within Note 2 – Significant Accounting Policies. Segment asset and capital expenditure information is not provided for our reportable segments. As an integrated electric and gas utility, we operate significant assets that are not dedicated to a specific reportable segment.

Financial data for the business segments for the twelve months ended are as follows (in thousands):


December 31, 2024		Electric		Gas		Total
Operating revenues	$	1,200,701	$	313,197	$	1,513,898
Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion
shown separately below)		329,578		104,238		433,816
Operating, general, and administrative		270,145		92,211		362,356
Property and other taxes		126,470		37,386		163,856
Depreciation and depletion		189,987		37,648		227,635
Interest expense, net		(99,250)		(27,740)		(126,990)
Other income, net		18,082		5,803		23,885
Income tax (expense) benefit		(20,892)		7,963		(12,929)
Segment net income	$	182,461	$	27,740	$	210,201
Reconciliation to consolidated net income
Other, net(1)						13,910
Consolidated net income					$	224,111


December 31, 2023		Electric		Gas		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
Operating, general, and administrative		249,549		87,153		336,702
Property and other taxes		120,289		34,323		154,612
Depreciation and depletion		174,071		36,403		210,474
Interest expense, net		(84,089)		(15,719)		(99,808)
Other income, net		11,580		3,344		14,924
Income tax (expense) benefit		(14,196)		4,627		(9,569)
Segment net income	$	175,464	$	30,176	$	205,640
Reconciliation to consolidated net income
Other, net(1)						(11,509)
Consolidated net income					$	194,131


December 31, 2022		Electric		Gas		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
Operating, general, and administrative		250,203		84,631		334,834
Property and other taxes		149,781		42,734		192,515
Depreciation and depletion		162,404		32,616		195,020
Interest expense, net		(74,420)		(13,030)		(87,450)
Other income, net		12,491		6,399		18,890
Income tax benefit (expense)		798		(3,108)		(2,310)
Segment net income	$	158,612	$	33,975	$	192,587
Reconciliation to consolidated net income
Other, net(1)						(9,579)
Consolidated net income					$	183,008
(1) Consists of unallocated corporate costs and some limited unregulated activity within the energy industry.


	Three Months Ended December 31,
	2024		2023
Operating revenues	$	373,466	$	356,009
Operating income		91,696		103,163
Net income	$	80,552	$	83,142
Average common shares outstanding		61,315		61,244
Income per average common share:
Basic	$	1.32	$	1.37
Diluted	$	1.31	$	1.37