NorthWestern Energy 10-Q 2024 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(mark one)
☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended		September 30, 2024
OR
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from          to          

Commission File Number: 000-56598

NORTHWESTERN ENERGY GROUP, INC.

(Exact name of registrant as specified in its charter)

Delaware			93-2020320
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)
3010 W. 69th Street	Sioux Falls	South Dakota	57108
(Address of principal executive offices)			(Zip Code)

Registrant’s telephone number, including area code: 605-978-2900

N/A

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock	NWE	Nasdaq Stock Market LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non- accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer ☒ Accelerated Filer ☐ Non-accelerated Filer ☐ Smaller Reporting Company ☐ Emerging Growth Company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes☐ No ☒

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Common Stock, Par Value $0.01, 61,314,217 shares outstanding at October 25, 2024

1

NORTHWESTERN ENERGY GROUP

FORM 10-Q

INDEX

		Page
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS		3
PART I. FINANCIAL INFORMATION		5
Item 1.	Financial Statements	5
	Condensed Consolidated Statements of Income — Three and Nine Months Ended September 30, 2024 and 2023	5
	Condensed Consolidated Statements of Comprehensive Income — Three and Nine Months Ended September 30, 2024 and 2023	6
	Condensed Consolidated Balance Sheets — September 30, 2024 and December 31, 2023	7
	Condensed Consolidated Statements of Cash Flows — Three and Nine Months Ended September 30, 2024 and 2023	8
	Condensed Consolidated Statements of Shareholders’ Equity — Three and Nine Months Ended September 30, 2024 and 2023	9
	Notes to Condensed Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 4.	Controls and Procedures	50
PART II. OTHER INFORMATION		51
Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	51
Item 5.	Other Information	51
Item 6.	Exhibits	52
SIGNATURES		53

2

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

On one or more occasions, we may make statements in this Quarterly Report on Form 10-Q regarding our assumptions, projections, expectations, targets, intentions or beliefs about future events. All statements other than statements of historical facts, included or incorporated by reference in this Quarterly Report, relating to our current expectations of future financial performance, continued growth, changes in economic conditions or capital markets and changes in customer usage patterns and preferences are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

Words or phrases such as “anticipates," “may," “will," “should," “believes," “estimates," “expects," “intends," “plans," “predicts," “projects," “targets," “will likely result," “will continue" or similar expressions identify forward-looking statements. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and believe such statements are based on reasonable assumptions, including without limitation, our examination of historical operating trends, data contained in records and other data available from third parties, we cannot assure you that we will achieve our projections. Factors that may cause such differences include, but are not limited to:

•adverse determinations by regulators, as well as potential adverse federal, state, or local legislation or regulation, including costs of compliance with existing and future environmental requirements, and wildfire damages in excess of liability insurance coverage, could have a material effect on our liquidity, results of operations and financial condition;

•the impact of extraordinary external events and natural disasters, such as a wide-spread or global pandemic, geopolitical events, earthquake, flood, drought, lightning, weather, wind, and fire, could have a material effect on our liquidity, results of operations and financial condition;

•acts of terrorism, cybersecurity attacks, data security breaches, or other malicious acts that cause damage to our generation, transmission, or distribution facilities, information technology systems, or result in the release of confidential customer, employee, or Company information;

•supply chain constraints, recent high levels of inflation for product, services and labor costs, and their impact on capital expenditures, operating activities, and/or our ability to safely and reliably serve our customers;

•changes in availability of trade credit, creditworthiness of counterparties, usage, commodity prices, fuel supply costs or availability due to higher demand, shortages, weather conditions, transportation problems or other developments, may reduce revenues or may increase operating costs, each of which could adversely affect our liquidity and results of operations;

•unscheduled generation outages or forced reductions in output, maintenance or repairs, which may reduce revenues and increase operating costs or may require additional capital expenditures or other increased operating costs; and

•adverse changes in general economic and competitive conditions in the U.S. financial markets and in our service territories.

We have attempted to identify, in context, certain of the factors that we believe may cause actual future experience and results to differ materially from our current expectation regarding the relevant matter or subject area. In addition to the items specifically discussed above, our business and results of operations are subject to the uncertainties described under the caption “Risk Factors” which is part of the disclosure included in Part II, Item 1A of this Quarterly Report on Form 10-Q.

From time to time, oral or written forward-looking statements are also included in our reports on Forms 10-K, 10-Q and 8-K, Proxy Statements on Schedule 14A, press releases, analyst and investor conference calls, and other communications released to the public. We believe that at the time made, the expectations reflected in all of these forward-looking statements are and will be reasonable. However, any or all of the forward-looking statements in this Quarterly Report on Form 10-Q, our reports on Forms 10-K and 8-K, our other reports on Form 10-Q, our Proxy Statements on Schedule 14A and any other public statements that are made by us may prove to be incorrect. This may occur as a result of assumptions, which turn out to be inaccurate, or as a consequence of known or unknown risks and uncertainties. Many factors discussed in this Quarterly Report on Form 10-Q, certain of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of any of our forward-looking statements in this Quarterly Report on Form 10-Q or other public communications as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements.

3

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. However, your attention is directed to any further disclosures made on related subjects in our subsequent reports filed with the Securities and Exchange Commission (SEC) on Forms 10-K, 10-Q and 8-K and Proxy Statements on Schedule 14A.

Unless the context requires otherwise, references to “we,” “us,” “our,” “NorthWestern Energy Group,” “NorthWestern Energy,” and “NorthWestern” refer specifically to NorthWestern Energy Group, Inc. and its subsidiaries.

4

PART 1. FINANCIAL INFORMATION

ITEM 1.FINANCIAL STATEMENTS

NORTHWESTERN ENERGY GROUP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per share amounts)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Revenues
Electric	$	306,478	$	280,030	$	909,798	$	804,604
Gas	38,683		41,060		230,634		261,530
Total Revenues	345,161		321,090		1,140,432		1,066,134
Operating expenses
Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	87,888		88,943		339,089		322,013
Operating and maintenance	55,866		53,240		167,415		163,941
Administrative and general	34,924		29,355		106,650		94,058
Property and other taxes	41,596		41,763		125,023		131,043
Depreciation and depletion	56,954		52,159		170,630		157,787
Total Operating Expenses	277,228		265,460		908,807		868,842
Operating income	67,933		55,630		231,625		197,292
Interest expense, net	(33,397)		(28,725)		(96,251)		(85,144)
Other income, net	9,116		4,127		19,595		12,926
Income before income taxes	43,652		31,032		154,969		125,074
Income tax benefit (expense)	3,167		(1,697)		(11,410)		(14,085)
Net Income	$	46,819	$	29,335	$	143,559	$	110,989
Average Common Shares Outstanding	61,302		60,442		61,286		60,011
Basic Earnings per Average Common Share	$	0.76	$	0.48	$	2.34	$	1.85
Diluted Earnings per Average Common Share	$	0.76	$	0.48	$	2.34	$	1.85
Dividends Declared per Common Share	$	0.65	$	0.64	$	1.95	$	1.92

See Notes to Condensed Consolidated Financial Statements

5

NORTHWESTERN ENERGY GROUP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(in thousands)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Net Income	$	46,819	$	29,335	$	143,559	$	110,989
Other comprehensive income, net of tax:
Foreign currency translation adjustment	1		(7)		(1)		(10)
Postretirement medical liability adjustment	—		(168)		—		(502)
Reclassification of net losses on derivative instruments	113		113		339		339
Total Other Comprehensive Income (Loss)	114		(62)		338		(173)
Comprehensive Income	$	46,933	$	29,273	$	143,897	$	110,816

See Notes to Condensed Consolidated Financial Statements

6

NORTHWESTERN ENERGY GROUP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

	September 30, 2024		December 31, 2023
ASSETS
Current Assets:
Cash and cash equivalents	$	2,527	$	9,164
Restricted cash	25,365		16,023
Accounts receivable, net	144,186		212,257
Inventories	121,568		114,539
Regulatory assets	34,334		29,626
Prepaid expenses and other	40,440		25,397
Total current assets	368,420		407,006
Property, plant, and equipment, net	6,304,721		6,039,801
Goodwill	357,586		357,586
Regulatory assets	766,229		743,945
Other noncurrent assets	57,118		52,314
Total Assets	$	7,854,074	$	7,600,652
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of finance leases	$	3,529	$	3,338
Current portion of long-term debt	299,918		99,950
Short-term borrowings	100,000		—
Accounts payable	93,748		124,340
Accrued expenses and other	286,070		246,167
Regulatory liabilities	30,001		61,103
Total current liabilities	813,266		534,898
Long-term finance leases	2,798		5,461
Long-term debt	2,567,940		2,684,635
Deferred income taxes	640,082		600,520
Noncurrent regulatory liabilities	665,360		657,452
Other noncurrent liabilities	348,166		332,372
Total Liabilities	5,037,612		4,815,338
Commitments and Contingencies (Note 10)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 64,803,949 and 61,308,009 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	648		648
Treasury stock at cost	(97,557)		(97,926)
Paid-in capital	2,084,560		2,078,753
Retained earnings	836,129		811,495
Accumulated other comprehensive loss	(7,318)		(7,656)
Total Shareholders' Equity	2,816,462		2,785,314
Total Liabilities and Shareholders' Equity	$	7,854,074	$	7,600,652

See Notes to Condensed Consolidated Financial Statements

7

NORTHWESTERN ENERGY GROUP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Nine Months Ended September 30,
	2024		2023
OPERATING ACTIVITIES:
Net income	$	143,559	$	110,989
Items not affecting cash:
Depreciation and depletion	170,630		157,787
Amortization of debt issuance costs, discount and deferred hedge gain	3,490		3,997
Stock-based compensation costs	5,291		5,119
Equity portion of allowance for funds used during construction	(15,371)		(12,530)
Gain on disposition of assets	(14)		(27)
Impairment of alternative energy storage investment	4,159		—
Deferred income taxes	7,128		(13,281)
Changes in current assets and liabilities:
Accounts receivable	68,071		96,910
Inventories	(7,030)		(11,721)
Other current assets	(15,043)		389
Accounts payable	(14,235)		(60,815)
Accrued expenses and other	39,928		65,058
Regulatory assets	(4,708)		94,069
Regulatory liabilities	(31,102)		10,588
Other noncurrent assets and liabilities	(10,849)		(19,610)
Cash Provided by Operating Activities	343,904		426,922
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(400,511)		(407,170)
Investment in equity securities	(4,599)		(3,804)
Cash Used in Investing Activities	(405,110)		(410,974)
FINANCING ACTIVITIES:
Proceeds from issuance of common stock, net	—		73,613
Dividends on common stock	(118,925)		(115,048)
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 repayments, net	(32,000)		(273,000)
Other financing activities, net	(164)		(2,336)
Cash Provided by (Used in) Financing Activities	63,911		(16,771)
Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	2,705		(823)
Cash, Cash Equivalents, and Restricted Cash, beginning of period	25,187		22,463
Cash, Cash Equivalents, and Restricted Cash, end of period	$	27,892	$	21,640
Supplemental Cash Flow Information:
Cash (received) paid during the period for:
Income taxes	$	(4,469)	$	3,204
Interest	92,562		64,533
Significant non-cash transactions:
Capital expenditures included in accounts payable	25,966		43,389
Refinancing of Pollution Control Revenue Refunding Bonds	—		144,660

See Notes to Condensed Consolidated Financial Statements

8

NORTHWESTERN ENERGY GROUP

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Unaudited)

(in thousands, except per share data)

	Three Months Ended September 30,
	Number of Common Shares	Number of Treasury Shares	Common Stock		Treasury Stock		Paid in Capital		Retained Earnings		Accumulated Other Comprehensive Loss		Total Shareholders' Equity
Balance at June 30, 2023	63,518	3,527	$	635	$	(98,302)	$	2,015,367	$	776,983	$	(7,959)	$	2,686,724
Net income	—	—	—		—		—		29,335		—		29,335
Foreign currency translation adjustment, net of tax	—	—	—		—		—		—		(7)		(7)
Reclassification of net losses on derivative instruments from OCI to net income, net of tax	—	—	—		—		—		—		113		113
Postretirement medical liability adjustment, net of tax	—	—	—		—		—		—		(168)		(168)
Stock-based compensation	—	—	—		—		239		—		—		239
Issuance of shares	1,244	(7)	13		180		62,948		—		—		63,141
Dividends on common stock ($0.640 per share)	—	—	—		—		—		(38,963)		—		(38,963)
Balance at September 30, 2023	64,762	3,520	$	648	$	(98,122)	$	2,078,554	$	767,355	$	(8,021)	$	2,740,414
Balance at June 30, 2024	64,803	3,504	$	648	$	(97,776)	$	2,082,857	$	828,960	$	(7,432)	$	2,807,257
Net income	—	—	—		—		—		46,819		—		46,819
Foreign currency translation adjustment, net of tax	—	—	—		—		—		—		1		1
Reclassification of net losses on derivative instruments from OCI to net income, net of tax	—	—	—		—		—		—		113		113
Stock-based compensation	1	—	—		—		1,481		—		—		1,481
Issuance of shares	—	(8)	—		219		222		—		—		441
Dividends on common stock ( $0.650 per share)	—	—	—		—		—		(39,650)		—		(39,650)
Balance at September 30, 2024	64,804	3,496	648		(97,557)		2,084,560		836,129		(7,318)		2,816,462

9

	Nine Months Ended September 30,
	Number of Common Shares	Number of Treasury Shares	Common Stock		Treasury Stock		Paid in Capital		Retained Earnings		Accumulated Other Comprehensive Loss		Total Shareholders' Equity
Balance at December 31, 2022	63,278	3,534	$	633	$	(98,392)	$	1,999,376	$	771,414	$	(7,848)	$	2,665,183
Net income	—	—	—		—		—		110,989		—		110,989
Foreign currency translation adjustment, net of tax	—	—	—		—		—		—		(10)		(10)
Reclassification of net losses on derivative instruments from OCI to net income, net of tax	—	—	—		—		—		—		339		339
Postretirement medical liability adjustment, net of tax	—	—	—		—		—		—		(502)		(502)
Stock-based compensation	51	—	—		—		4,911		—		—		4,911
Issuance of shares	1,433	(14)	15		270		74,267		—		—		74,552
Dividends on common stock ($1.920 per share)	—	—	—		—		—		(115,048)		—		(115,048)
Balance at September 30, 2023	64,762	3,520	$	648	$	(98,122)	$	2,078,554	$	767,355	$	(8,021)	$	2,740,414
Balance at December 31, 2023	64,762	3,513	$	648	$	(97,926)	$	2,078,753	$	811,495	$	(7,656)	$	2,785,314
Net income	—	—	—		—		—		143,559		—		143,559
Foreign currency translation adjustment, net of tax	—	—	—		—		—		—		(1)		(1)
Reclassification of net losses on derivative instruments from OCI to net income, net of tax	—	—	—		—		—		—		339		339
Postretirement medical liability adjustment, net of tax	—	—	—		—		—		—		—		—
Stock-based compensation	42	—	—		(272)		5,252		—		—		4,980
Issuance of shares	—	(17)	—		641		555		—		—		1,196
Dividends on common stock ($1.950 per share)	—	—	—		—		—		(118,925)		—		(118,925)
Balance at September 30, 2024	64,804	3,496	648		(97,557)		2,084,560		836,129		(7,318)		2,816,462

See Notes to Condensed Consolidated Financial Statements

10

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Reference is made to Notes to Financial Statements included in the NorthWestern Energy Group's Annual Report)

(Unaudited)

(1) Nature of Operations and Basis of Consolidation

NorthWestern Energy Group, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 775,300 customers in Montana, South Dakota, Nebraska and Yellowstone National Park, through its subsidiaries NorthWestern Corporation (NW Corp) and NorthWestern Energy Public Service Corporation (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 preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires us to make estimates and assumptions that may affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. Actual results could differ from those estimates. The unaudited Condensed Consolidated Financial Statements (Financial Statements) reflect all adjustments (which unless otherwise noted are normal and recurring in nature) that are, in our opinion, necessary to fairly present our financial position, results of operations and cash flows. The actual results for the interim periods are not necessarily indicative of the operating results to be expected for a full year or for other interim periods. Events occurring subsequent to September 30, 2024 have been evaluated as to their potential impact to the Financial Statements through the date of issuance.

The Financial Statements included herein have been prepared by NorthWestern, without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, we believe that the condensed disclosures provided are adequate to make the information presented not misleading. We recommend that these Financial Statements be read in conjunction with the audited financial statements and related footnotes included in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023.

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.

Supplemental Cash Flow Information

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the Condensed Consolidated Balance Sheets that sum to the total of the same such amounts shown in the Condensed Consolidated Statements of Cash Flows (in thousands):

	September 30,		December 31,		September 30,		December 31,
	2024		2023		2023		2022
Cash and cash equivalents	$	2,527	$	9,164	$	5,091	$	8,489
Restricted cash	25,365		16,023		16,549		13,974
Total cash, cash equivalents, and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	27,892	$	25,187	$	21,640	$	22,463

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

11

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.

(2) Regulatory Matters

Montana Rate Review

In July 2024, we filed a Montana electric and natural gas rate review with the Montana Public Service Commission (MPSC). The filing requests a base rate annual revenue increase of $156.5 million ($69.4 million net with Property Tax and Power Cost and Credit Adjustment Mechanism (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 ("YCGS"), which was placed in service in October 2024.

Our filing included a request for interim base rates to be effective October 1, 2024. Implementation of interim base rates, if any, has been delayed beyond our requested effective date as the MPSC has not yet made a decision on the interim rate request.

The MPSC has developed its procedural schedule for our rate review request including a hearing 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 South Dakota Public Utilities Commission. The filing requests a base rate annual revenue increase of $6.0 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 $95.6 million. If a final order is not received by December 21, 2024, interim base rates may go into effect.

Nebraska Natural Gas Rate Review

In June 2024, we filed a natural gas rate review (2023 test year) with the Nebraska Public Service Commission (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.

(3) Income Taxes

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

The following table summarizes the differences between our effective tax rate and the federal statutory rate (in thousands):

12

	Three Months Ended September 30,
	2024				2023
Income before income taxes	$	43,652			$	31,032
Income tax calculated at federal statutory rate	9,167		21.0	%	6,516		21.0	%
Permanent or flow-through adjustments:
State income tax, net of federal provisions	61		0.1		121		0.4
Gas repairs safe harbor method change	(6,994)		(16.0)		—		—
Flow-through repairs deductions	(4,581)		(10.5)		(4,189)		(13.5)
Production tax credits	(2,447)		(5.6)		(1,261)		(4.1)
Amortization of excess deferred income tax	(219)		(0.5)		(323)		(1.0)
Income tax return to accrual adjustment	—		—		411		1.3
Plant and depreciation flow-through items	1,816		4.2		358		1.2
Other, net	30		0.0		64		0.2
	(12,334)		(28.3)		(4,819)		(15.5)
Income tax (benefit) expense	$	(3,167)	(7.3)	%	$	1,697	5.5	%

	Nine Months Ended September 30,
	2024				2023
Income before income taxes	$	154,969			$	125,074
Income tax calculated at federal statutory rate	32,544		21.0	%	26,265		21.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	749		0.5		1,353		1.1
Flow-through repairs deductions	(13,824)		(8.9)		(11,742)		(9.4)
Production tax credits	(7,434)		(4.8)		(5,607)		(4.5)
Gas repairs safe harbor method change	(6,994)		(4.5)		—		—
Amortization of excess deferred income tax	(775)		(0.5)		(1,355)		(1.1)
Reduction to previously claimed alternative minimum tax credit	—		—		3,186		2.5
Income tax return to accrual adjustment	—		—		411		0.3
Plant and depreciation flow through items	5,955		3.8		1,247		1.0
Share-based compensation	298		0.2		388		0.3
Other, net	891		0.6		(61)		0.1
	(21,134)		(13.6)		(12,180)		(9.7)
Income tax expense	$	11,410	7.4	%	$	14,085	11.3	%

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. During the three months ended September 30, 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.

13

Uncertain Tax Positions

We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. We had unrecognized tax benefits of approximately $26.9 million as of September 30, 2024, including approximately $24.3 million that, if recognized, would impact our effective tax rate. In the next twelve months we expect the statute of limitations to expire for certain uncertain tax benefits, which would result in a decrease to our total unrecognized tax benefits of approximately $16.9 million.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. As of September 30, 2024, we have accrued $6.8 million for the payment of interest and penalties on the Condensed Consolidated Balance Sheets. As of December 31, 2023, we had accrued $4.5 million for the payment of interest and penalties on the Condensed Consolidated Balance Sheets.

Tax years 2020 and forward remain subject to examination by the Internal Revenue Service and state taxing authorities.

(4) Comprehensive (Loss) Income

The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands):

	Three Months Ended
	September 30, 2024						September 30, 2023
	Before-Tax Amount		Tax Expense		Net-of-Tax Amount		Before-Tax Amount		Tax Expense		Net-of-Tax Amount
Foreign currency translation adjustment	$	1	$	—	$	1	$	(7)	$	—	$	(7)
Reclassification of net income on derivative instruments	153		(40)		113		153		(40)		113
Defined benefit pension plan and postretirement medical liability adjustment	—		—		—		(212)		44		(168)
Other comprehensive income (loss)	$	154	$	(40)	$	114	$	(66)	$	4	$	(62)

	Nine Months Ended
	September 30, 2024						September 30, 2023
	Before-Tax Amount		Tax Expense		Net-of-Tax Amount		Before-Tax Amount		Tax Expense		Net-of-Tax Amount
Foreign currency translation adjustment	$	(1)	$	—	$	(1)	$	(10)	$	—	$	(10)
Reclassification of net income on derivative instruments	459		(120)		339		459		(120)		339
Defined benefit pension plan and postretirement medical liability adjustment	—		—		—		(636)		134		(502)
Other comprehensive income (loss)	$	458	$	(120)	$	338	$	(187)	$	14	$	(173)

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

	September 30, 2024		December 31, 2023
Foreign currency translation	$	1,436	$	1,437
Derivative instruments designated as cash flow hedges	(9,034)		(9,373)
Defined benefit pension plan	280		280
Accumulated other comprehensive loss	$	(7,318)	$	(7,656)

14

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

		Three Months Ended
		September 30, 2024
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges		Defined Benefit Pension Plan		Foreign Currency Translation		Total
Beginning balance		$	(9,147)	$	280	$	1,435	$	(7,432)
Other comprehensive income before reclassifications		—		—		1		1
Amounts reclassified from AOCL	Interest Expense	113		—		—		113
Net current-period other comprehensive income		113		—		1		114
Ending balance		$	(9,034)	$	280	$	1,436	$	(7,318)

		Three Months Ended
		September 30, 2023
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges		Postretirement Medical Plans		Foreign Currency Translation		Total
Beginning balance		$	(9,599)	$	208	$	1,432	$	(7,959)
Other comprehensive loss before reclassifications		—		—		(7)		(7)
Amounts reclassified from AOCL	Interest Expense	113		—		—		113
Amounts reclassified from AOCL		—		(168)		—		(168)
Net current-period other comprehensive income (loss)		113		(168)		(7)		(62)
Ending balance		$	(9,486)	$	40	$	1,425	$	(8,021)

		Nine Months Ended
		September 30, 2024
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges		Defined Benefit Pension Plan and Postretirement Medical Plans		Foreign Currency Translation		Total
Beginning balance		$	(9,373)	$	280	$	1,437	$	(7,656)
Other comprehensive loss before reclassifications		—		—		(1)		(1)
Amounts reclassified from AOCL	Interest Expense	339		—		—		339
Net current-period other comprehensive income (loss)		339		—		(1)		338
Ending balance		$	(9,034)	$	280	$	1,436	$	(7,318)

15

		Nine Months Ended
		September 30, 2023
	Affected Line Item in the Condensed Consolidated Statements of Income	Interest Rate Derivative Instruments Designated as Cash Flow Hedges		Pension and Postretirement Medical Plans		Foreign Currency Translation		Total
Beginning balance		$	(9,825)	$	542	$	1,435	$	(7,848)
Other comprehensive loss before reclassifications		—		—		(10)		(10)
Amounts reclassified from AOCL	Interest Expense	339		—		—		339
Amounts reclassified from AOCL		—		(502)		—		(502)
Net current-period other comprehensive income (loss)		339		(502)		(10)		(173)
Ending balance		$	(9,486)	$	40	$	1,425	$	(8,021)

(5) Financing Activities

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.

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.

(6) Segment Information

Our reportable business segments are primarily engaged in the electric and natural gas business. The remainder of our operations are presented as other, which primarily consists of unallocated corporate costs and unregulated activity.

We evaluate the performance of these segments based on utility margin. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by us for internal reporting purposes and involves estimates and assumptions.

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

16

Three Months Ended
September 30, 2024	Electric		Gas		Other		Eliminations		Total
Operating revenues	$	306,478	$	38,683	$	—	$	—	$	345,161
Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	80,761		7,127		—		—		87,888
Utility margin	225,717		31,556		—		—		257,273
Operating and maintenance	42,491		13,375		—		—		55,866
Administrative and general	24,892		9,887		145		—		34,924
Property and other taxes	32,251		9,345		—		—		41,596
Depreciation and depletion	47,540		9,414		—		—		56,954
Operating income (loss)	78,543		(10,465)		(145)		—		67,933
Interest expense, net	(24,188)		(7,537)		(1,672)		—		(33,397)
Other income, net	6,057		3,017		42		—		9,116
Income tax (expense) benefit	(7,635)		9,734		1,068		—		3,167
Net income (loss)	$	52,777	$	(5,251)	$	(707)	$	—	$	46,819
Total assets	$	6,256,750	$	1,578,075	$	19,249	$	—	$	7,854,074
Capital expenditures	$	109,925	$	43,225	$	—	$	—	$	153,150

Three Months Ended
September 30, 2023	Electric		Gas		Other		Eliminations		Total
Operating revenues	$	280,030	$	41,060	$	—	$	—	$	321,090
Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	77,995		10,948		—		—		88,943
Utility margin	202,035		30,112		—		—		232,147
Operating and maintenance	39,990		13,250		—		—		53,240
Administrative and general	20,682		8,249		424		—		29,355
Property and other taxes	33,740		9,574		(1,551)		—		41,763
Depreciation and depletion	43,230		8,929		—		—		52,159
Operating income (loss)	64,393		(9,890)		1,127		—		55,630
Interest expense, net	(21,300)		(4,426)		(2,999)		—		(28,725)
Other income (expense), net	3,380		1,328		(581)		—		4,127
Income tax (expense) benefit	(3,223)		(41)		1,567		—		(1,697)
Net income (loss)	$	43,250	$	(13,029)	$	(886)	$	—	$	29,335
Total assets	$	5,963,950	$	1,454,445	$	11,104	$	—	$	7,429,499
Capital expenditures	$	110,804	$	46,359	$	—	$	—	$	157,163

17

Nine Months Ended
September 30, 2024	Electric		Gas		Other		Eliminations		Total
Operating revenues	$	909,798	$	230,634	$	—	$	—	$	1,140,432
Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	256,989		82,100		—		—		339,089
Utility margin	652,809		148,534		—		—		801,343
Operating and maintenance	126,257		41,158		—		—		167,415
Administrative and general	76,105		27,754		2,791		—		106,650
Property and other taxes	96,557		28,465		1		—		125,023
Depreciation and depletion	142,390		28,240		—		—		170,630
Operating income (loss)	211,500		22,917		(2,792)		—		231,625
Interest expense, net	(72,143)		(20,933)		(3,175)		—		(96,251)
Other income (expense), net	15,549		4,998		(952)		—		19,595
Income tax (expense) benefit	(18,809)		6,865		534		—		(11,410)
Net income (loss)	$	136,097	$	13,847	$	(6,385)	$	—	$	143,559
Total assets	$	6,256,750	$	1,578,075	$	19,249	$	—	$	7,854,074
Capital expenditures	$	312,773	$	87,738	$	—	$	—	$	400,511

Nine Months Ended
September 30, 2023	Electric		Gas		Other		Eliminations		Total
Operating revenues	$	804,604	$	261,530	$	—	$	—	$	1,066,134
Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	198,492		123,521		—		—		322,013
Utility margin	606,112		138,009		—		—		744,121
Operating and maintenance	123,771		40,170		—		—		163,941
Administrative and general	67,285		26,336		437		—		94,058
Property and other taxes	103,013		29,576		(1,546)		—		131,043
Depreciation and depletion	130,447		27,340		—		—		157,787
Operating income	181,596		14,587		1,109		—		197,292
Interest expense, net	(61,584)		(12,167)		(11,393)		—		(85,144)
Other income (expense), net	9,700		3,887		(661)		—		12,926
Income tax expense	(13,366)		(180)		(539)		—		(14,085)
Net income (loss)	$	116,346	$	6,127	$	(11,484)	$	—	$	110,989
Total assets	$	5,963,950	$	1,454,445	$	11,104	$	—	$	7,429,499
Capital expenditures	$	326,313	$	94,212	$	—	$	—	$	420,525

18

(7)  Revenue from Contracts with Customers

Nature of Goods and Services

We provide retail electric and natural gas services to three primary customer classes. Our largest customer class consists of residential customers, which includes 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 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 0-30 days after the billing date.

Natural Gas Segment - Our regulated natural gas utility business primarily provides production, storage, transmission, and distribution services to 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 0-30 days after the billing date.

Disaggregation of Revenue

The following tables disaggregate our revenue by major source and customer class (in millions):

	Three Months Ended
	September 30, 2024						September 30, 2023
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Montana	$	100.7	$	8.4	$	109.1	$	96.8	$	9.6	$	106.4
South Dakota	19.1		1.7		20.8		18.0		2.0		20.0
Nebraska	—		1.8		1.8		—		2.2		2.2
Residential	119.8		11.9		131.7		114.8		13.8		128.6
Montana	109.6		6.2		115.8		110.1		6.1		116.2
South Dakota	30.1		1.3		31.4		27.5		1.5		29.0
Nebraska	—		0.8		0.8		—		1.3		1.3
Commercial	139.7		8.3		148.0		137.6		8.9		146.5
Industrial	11.8		0.1		11.9		11.4		0.1		11.5
Lighting, governmental, irrigation, and interdepartmental	14.1		0.2		14.3		13.2		0.2		13.4
Total Customer Revenues	285.4		20.5		305.9		277.0		23.0		300.0
Other tariff and contract based revenues	28.0		9.3		37.3		22.1		10.2		32.3
Total Revenue from Contracts with Customers	313.4		29.8		343.2		299.1		33.2		332.3
Regulatory amortization and other	(6.9)		8.9		2.0		(19.1)		7.9		(11.2)
Total Revenues	$	306.5	$	38.7	$	345.2	$	280.0	$	41.1	$	321.1

19

	Nine Months Ended
	September 30, 2024						September 30, 2023
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Montana	$	304.1	$	75.9	$	380.0	$	306.1	$	94.1	$	400.2
South Dakota	53.8		21.2		75.0		53.4		30.3		83.7
Nebraska	—		16.1		16.1		—		30.2		30.2
Residential	357.9		113.2		471.1		359.5		154.6		514.1
Montana	310.8		42.0		352.8		324.6		52.4		377.0
South Dakota	84.2		14.3		98.5		77.8		21.3		99.1
Nebraska	—		9.0		9.0		—		19.1		19.1
Commercial	395.0		65.3		460.3		402.4		92.8		495.2
Industrial	34.8		0.7		35.5		34.0		1.0		35.0
Lighting, governmental, irrigation, and interdepartmental	27.4		1.1		28.5		27.2		1.3		28.5
Total Customer Revenues	815.1		180.3		995.4		823.1		249.7		1,072.8
Other tariff and contract based revenues	77.4		30.9		108.3		63.5		33.1		96.6
Total Revenue from Contracts with Customers	892.5		211.2		1,103.7		886.6		282.8		1,169.4
Regulatory amortization and other	17.3		19.4		36.7		(82.0)		(21.3)		(103.3)
Total Revenues	$	909.8	$	230.6	$	1,140.4	$	804.6	$	261.5	$	1,066.1

(8) 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:

	Three Months Ended
	September 30, 2024	September 30, 2023
Basic computation	61,301,696	60,442,164
Dilutive effect of:
Performance share awards(1)	95,279	35,533
Diluted computation	61,396,975	60,477,697

	Nine Months Ended
	September 30, 2024	September 30, 2023
Basic computation	61,285,570	60,010,609
Dilutive effect of:
Performance share awards(1)	69,136	31,311
Diluted computation	61,354,706	60,041,920

(1) Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.

As of September 30, 2024, there were 16,015 shares from performance and restricted share awards which were antidilutive and excluded from the earnings per share calculations, compared to 32,649 shares as of September 30, 2023.

20

(9) Employee Benefit Plans

We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for eligible employees. Net periodic benefit cost (credit) for our pension and other postretirement plans consists of the following (in thousands):

	Pension Benefits				Other Postretirement Benefits
	Three Months Ended September 30,				Three Months Ended September 30,
	2024		2023		2024		2023
Components of Net Periodic Benefit Cost (Credit)
Service cost	$	1,398	$	1,459	$	77	$	84
Interest cost	5,736		6,524		139		168
Expected return on plan assets	(6,331)		(6,679)		(320)		(274)
Amortization of prior service credit	—		—		—		29
Recognized actuarial loss (gain)	8		68		(18)		18
Net periodic benefit cost (credit)	$	811	$	1,372	$	(122)	$	25

	Pension Benefits				Other Postretirement Benefits
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Components of Net Periodic Benefit Cost (Credit)
Service cost	$	4,194	$	4,375	$	231	$	250
Interest cost	17,208		19,571		418		505
Expected return on plan assets	(18,994)		(20,036)		(960)		(822)
Amortization of prior service credit	—		—		—		87
Recognized actuarial loss (gain)	25		205		(55)		54
Net periodic benefit cost (credit)	$	2,433	$	4,115	$	(366)	$	74

We contributed $8.6 million to our pension plans during the nine months ended September 30, 2024. We expect to contribute an additional $2.6 million to our pension plans during the remainder of 2024.

(10) Commitments and Contingencies

ENVIRONMENTAL LIABILITIES AND REGULATION

Except as set forth below, the circumstances set forth in Note 18 - Commitments and Contingencies to the financial statements included in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023 appropriately represent, in all material respects, the current status of our environmental liabilities and regulation.

Environmental Protection Agency (EPA) Rules

On April 25, 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). 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 the multiple stay requests related to the MATS Rule and the GHG Rule. 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 Rules and GHG Rules are implemented, it would result in

21

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 Rules 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.

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 state and federal court, including before the United States Supreme Court, as detailed in Note 18 - Commitments and Contingencies to the financial statements included in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023. 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. Briefing in the appeal is underway. 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.

Colstrip Arbitration

The remaining depreciable life of our investment in Colstrip Unit 4 is through 2042. The six owners of Colstrip Units 3 and 4 currently share the operating costs pursuant to the terms of an Ownership and Operation Agreement (O&O Agreement). However, several of the owners are mandated by Washington and Oregon law to eliminate coal-fired resources in 2025 and 2029, respectively.

As a result of the mandate, the owners have disagreed on various operational funding decisions, including whether closure requires each owner’s consent under the O&O Agreement. On March 12, 2021, we initiated an arbitration under the O&O Agreement (the “Arbitration”), to resolve the issues of whether closure requires each owner's consent and to clarify each owner's obligations to continue to fund operations until all joint owners agree on closure. On September 17, 2024, the owners agreed to stay the Arbitration for 120 days.

Colstrip Coal Dust Litigation

On December 14, 2020, a claim was filed against Talen in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. Talen is one of the co-owners of Colstrip Unit 3, and the operator of Units 3 and 4. The plaintiffs allege they have suffered adverse effects from coal dust generated during operations associated with Colstrip. On August 26, 2021, the

22

claim was amended to add in excess of 100 plaintiffs; though the number of plaintiffs has since decreased to 57. It also added NorthWestern, the other owners of Colstrip, and Westmoreland Rosebud Mining LLC, as defendants. Plaintiffs are seeking economic damages, costs and disbursements, punitive damages, attorneys’ fees, and an injunction prohibiting defendants from allowing coal dust to blow onto plaintiffs’ properties. We do not anticipate that the amount of ultimate liability, if any, will have a material effect on our financial position, results of operations, or cash flows.

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 Montana Department of Environmental Quality (MDEQ) and NorthWestern, alleging that the environmental analysis conducted by MDEQ prior to issuance of the Yellowstone County Generating Station's air quality construction permit was inadequate. On April 4, 2023, the Montana District Court issued an order finding MDEQ's environmental analysis was deficient in not addressing exterior lighting and greenhouse gases and remanded it back to MDEQ to address the deficiencies and vacated the air quality permit pending that remand. As a result of the vacatur of the permit, we paused construction. On June 8, 2023, the Montana District Court granted our motion to stay the order vacating the air quality permit pending the outcome of our appeal to the Montana Supreme Court. Oral argument was held May 15, 2024. We recommenced construction in June 2023 and placed the plant in service in October 2024. The ultimate resolution of the lawsuit challenging the Yellowstone County Generating Station air quality permit could impact our ability to operate the facility.

During the litigation of the air permit, Montana House Bill 971 was signed into law, preventing the MDEQ from, except under certain exceptions, evaluating greenhouse gas emissions and corresponding impacts to the climate in environmental reviews of large projects such as coal mines and power plants. On August 4, 2023, the Montana First Judicial District Court in Held v. State of Montana, a separate case by Montana youths alleging climate damages, issued its order finding House Bill 971 unconstitutional delaying the issuance of the revised Yellowstone County Generating Station's air permit. The Montana Supreme Court granted NorthWestern permission to participate as amicus in the Held appeal. The Montana Supreme Court heard oral argument on the Held appeal on July 10, 2024.

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.

23

ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Utility Margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. We define Utility Margin as Operating Revenues less fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion) as presented in our Condensed Consolidated Statements of Income. This measure differs from the GAAP definition of Gross Margin due to the exclusion of Operating and maintenance, Property and other taxes, and Depreciation and depletion expenses, which are presented separately in our Condensed Consolidated Statements of Income. The following discussion includes a reconciliation of Utility Margin to Gross Margin, the most directly comparable GAAP measure.

We believe that Utility Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Utility Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow for recovery of operating costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates and other factors impact our results of operations. Our Utility Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report.

OVERVIEW

NorthWestern Energy Group, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 775,300 customers in Montana, South Dakota, Nebraska and Yellowstone National Park. Our operations in Montana and Yellowstone National Park are conducted through our subsidiary, NW Corp, and our operations in South Dakota and Nebraska are conducted through our subsidiary, NWE Public Service. For a discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023.

We work to deliver safe, reliable, and innovative energy solutions that create value for customers, communities, employees, and investors. We do this by providing low-cost and reliable service performed by highly-adaptable and skilled employees. We are focused on delivering long-term shareholder value through:

•Infrastructure investment focused on a stronger and smarter grid to improve the customer experience, while enhancing grid reliability and safety. This includes automation in customer meters, distribution and substations that enables the use of proven new technologies.

•Investing in and integrating supply resources that balance reliability, cost, capacity, and sustainability considerations with more predictable long-term commodity prices.

•Continually improving our operating efficiency. Financial discipline is essential to earning our authorized return on invested capital and maintaining a strong balance sheet, stable cash flows, and quality credit ratings to continue to attract cost-effective capital for future investment.

We expect to pursue these investment opportunities and manage our business in a manner that allows us to be flexible in adjusting to changing economic conditions by adjusting the timing and scale of the projects.

We are committed to providing customers with reliable and affordable electric and natural gas services while also being good stewards of the environment. Towards this end, our efforts towards a carbon-free future are outlined through our goal to achieve net zero carbon emissions by 2050.

As you read this discussion and analysis, refer to our Condensed Consolidated Statements of Income, which present the results of our operations for the three and nine months ended September 30, 2024 and 2023.

24

HOW WE PERFORMED AGAINST OUR THIRD QUARTER 2023 RESULTS

	Three Months Ended September 30, 2024 vs. 2023
		Income Before Income Taxes		Income Tax (Expense) Benefit(3)		Net Income
				(in millions)
Third Quarter, 2023		$	31.0	$	(1.7)	$	29.3
Variance in revenue and fuel, purchased supply, and direct transmission expense(1) items impacting net income:
Base rates		17.2		(4.4)		12.8
Electric transmission revenue		5.9		(1.5)		4.4
Electric retail volumes		3.6		(0.9)		2.7
Montana property tax tracker collections		1.5		(0.4)		1.1
Montana natural gas transportation		0.9		(0.2)		0.7
Non-recoverable Montana electric supply costs		0.6		(0.2)		0.4
Natural gas retail volumes		(0.3)		0.1		(0.2)
Production tax credits, offset within income tax benefit		(0.2)		0.2		—
Other		(1.2)		0.3		(0.9)
Variance in expense items(2) impacting net income:
Operating, maintenance, and administrative		(5.5)		1.4		(4.1)
Depreciation		(4.8)		1.2		(3.6)
Interest expense		(4.7)		1.2		(3.5)
Property and other taxes not recoverable within trackers		(1.9)		0.5		(1.4)
Gas repairs safe harbor method change		—		7.0		7.0
Other		1.5		0.6		2.1
Third Quarter, 2024		$	43.6	$	3.2	$	46.8
Change in Net Income						$	17.5

(1) Exclusive of depreciation and depletion shown separately below

(2) Excluding fuel, purchased supply, and direct transmission expense

(3) Income tax expense calculation on reconciling items assumes a blended federal plus state effective tax rate of 25.3 percent.

Consolidated net income for the three months ended September 30, 2024 was $46.8 million as compared with $29.3 million for the same period in 2023. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, electric retail volumes, Montana property tax tracker collections, lower non-recoverable Montana electric supply costs, and an income tax benefit from a change to the gas repairs safe harbor method. These were offset in part by natural gas retail volumes, depreciation, operating, administrative and general costs, and interest expense.

SIGNIFICANT TRENDS AND REGULATION

Refer to the NorthWestern Energy Group Annual Report on the Form 10-K for the year ended December 31, 2023 for disclosure of the significant trends and regulations that could have a significant impact on our business. These significant trends and regulations have not changed materially since such disclosure, except as follows:

Yellowstone County 175 MW plant

Construction of the new generation facility was substantially completed and the plant placed in service in October 2024. The lawsuit challenging the YCGS air quality permit, which required us to suspend construction activities for a period of time, as well as additional related legal and construction challenges, delayed the project timing and have increased costs. As of September 30, 2024, total costs of approximately $305.6 million have been incurred, with expected total costs of approximately

25

$310.0 million to $320.0 million. See Note 10 - Commitments and Contingencies to the Condensed Consolidated Financial Statements included herein for additional information regarding legal challenges impacting YCGS.

Regulatory Update

Rate reviews are necessary to recover the cost of providing safe, reliable service, while contributing to earnings growth and achieving our financial objectives. We regularly review the need for electric and natural gas rate relief in each state in which we provide service. Our ongoing rate review activity includes the following:

Montana Rate Review - In July 2024, we filed a Montana electric and natural gas rate review 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.

Our filing included a request for interim base rates to be effective October 1, 2024. Implementation of interim base rates, if any, has been delayed beyond our requested effective date as the MPSC has not yet made a decision on the interim rate request.

The MPSC has developed its procedural schedule for our rate review request including a hearing 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 with the South Dakota Public Utilities Commission. The filing requests a base rate annual revenue increase of $6.0 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 $95.6 million. If a final order is not received by December 21, 2024, interim base rates may go into effect.

Nebraska Natural Gas Rate Review - In June 2024, we filed a natural gas rate review 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.

EPA Rules

On April 25, 2024, the EPA released GHG Rules for existing coal-fired facilities and new coal and natural gas-fired facilities as well as MATS Rules. 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. See Note 10 - Commitments and Contingencies to the Condensed Consolidated Financial Statements included herein for additional information regarding these rules.

Acquisition of Energy West Montana Assets

On July 29, 2024, we entered into an Asset Purchase Agreement with Hope Utilities to acquire its Energy West natural gas utility distribution system and operations serving approximately 33,000 customers located near Great Falls, Cut Bank, and West Yellowstone, Montana for approximately $39.0 million in cash, subject to certain working capital and other agreed upon closing adjustments. The transaction is subject to a number of customary closing conditions, including MPSC approval, and we expect the acquisition to be completed by the end of the first quarter of 2025.

Colstrip - Puget Sound Energy Transaction

On July 30, 2024, we entered into a definitive agreement (the Agreement) with Puget Sound Energy (Puget) to acquire Puget's 25 percent interest in each of Units 3 and 4 (collectively representing 370 megawatts) at the Colstrip Generating Station for $0. The acquisition would be effective December 31, 2025, subject to the satisfaction of the closing conditions contained within the Agreement. Under the terms of the Agreement, we will be responsible for operating costs starting on January 1, 2026; while Puget will retain responsibility for its pre-closing share of environmental and pension liabilities attributed to events or conditions existing prior to the closing of the transaction and for any future decommission and demolition costs associated with the existing facilities that comprise Puget's interest. The Agreement is subject to customary conditions and approvals. The

26

ultimate amount of Puget's ownership interest we acquire is contingent on a right-of-first-refusal held by other Colstrip owners which, if exercised prior to expiration in fourth quarter 2024, would reduce our acquired interest proportionately.

Acquisition of Puget’s entire ownership interest, in addition to the previously disclosed acquisition of Avista’s 15 percent interest in each of Colstrip Units 3 and 4 (collectively representing 222 megawatts), would result in our ownership of 55 percent of the facility with the ability to guide operating and maintenance investments. This provides 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.

Regional Transmission Development Activities

In August 2024, the U.S. Department of Energy awarded a $700.0 million grant through the Grid Resilience and Innovation Partnership (GRIP) program to advance the North Plains Connector (NPC) Consortium project. The 415-mile, high-voltage direct-current transmission line is intended to connect Montana's Colstrip substation, of which we are the operator and a joint owner, to central North Dakota, bridging the eastern and western U.S. energy grids. The NPC Consortium includes potential upgrades to our jointly owned Colstrip Transmission System and $70.0 million of the award is earmarked for the Colstrip Transmission System Upgrade. The NPC project, estimated to be a $3.6 billion investment, aims to enhance grid reliability, support renewable energy integration, and provide additional capacity across multiple states. We collaborated with Grid United, the Montana Department of Commerce, and other regional utilities on the successful GRIP grant application. The project is a critical infrastructure investment that aligns with our commitment to providing reliable and affordable energy to our customers while also supporting broader grid resilience efforts in the region. In addition to the Colstrip Transmission System Upgrade, we are considering an investment in NPC and are engaged in regional transmission development activities.

27

RESULTS OF OPERATIONS

Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. The overall consolidated discussion is followed by a detailed discussion of utility margin by segment.

Factors Affecting Results of Operations

Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.

Revenues are also impacted by customer growth and usage, the latter of which is primarily affected by weather and the impact of energy efficiency initiatives and investment. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers. We measure this effect using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.

Fuel, purchased supply and direct transmission expenses are costs directly associated with the generation and procurement of electricity and natural gas. These costs are generally collected in rates from customers and may fluctuate substantially with market prices and customer usage.

Operating and maintenance expenses are costs associated with the ongoing operation of our vertically-integrated utility facilities which provide electric and natural gas utility products and services to our customers. Among the most significant of these costs are those associated with direct labor and supervision, repair and maintenance expenses, and contract services. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in volumes.

OVERALL CONSOLIDATED RESULTS

Three Months Ended September 30, 2024 Compared with the Three Months Ended September 30, 2023

Consolidated net income for the three months ended September 30, 2024 was $46.8 million as compared with $29.3 million for the same period in 2023. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, electric retail volumes, Montana property tax tracker collections, lower non-recoverable Montana electric supply costs, and a income tax benefit from a change to the gas repairs safe harbor method. These were offset in part by natural gas retail volumes, depreciation, operating, administrative and general costs, and interest expense.

Consolidated gross margin for the three months ended September 30, 2024 was $102.8 million as compared with $83.5 million in 2023, an increase of $19.3 million, or 23.1 percent. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, electric retail volumes, Montana property tax tracker collections, and lower non-recoverable Montana electric supply costs. These were offset in part by natural gas retail volumes, depreciation, and operating and maintenance costs.

28

	Electric				Natural Gas				Total
	2024		2023		2024		2023		2024		2023
	(in millions)
Reconciliation of gross margin to utility margin:
Operating Revenues	$	306.5	$	280.0	$	38.7	$	41.1	$	345.2	$	321.1
Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	80.8		78.0		7.1		10.9		87.9		88.9
Less: Operating and maintenance	42.5		40.0		13.4		13.2		55.9		53.2
Less: Property and other taxes	32.3		33.7		9.3		9.6		41.6		43.3
Less: Depreciation and depletion	47.6		43.3		9.4		8.9		57.0		52.2
Gross Margin	103.3		85.0		(0.5)		(1.5)		102.8		83.5
Operating and maintenance	42.5		40.0		13.4		13.2		55.9		53.2
Property and other taxes	32.3		33.7		9.3		9.6		41.6		43.3
Depreciation and depletion	47.6		43.3		9.4		8.9		57.0		52.2
Utility Margin(1)	$	225.7	$	202.0	$	31.6	$	30.2	$	257.3	$	232.2

(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.

	Three Months Ended September 30,
	2024		2023		Change		% Change
	(dollars in millions)
Utility Margin
Electric	$	225.7	$	202.0	$	23.7	11.7	%
Natural Gas	31.6		30.2		1.4		4.6
Total Utility Margin(1)	$	257.3	$	232.2	$	25.1	10.8	%

(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.

Consolidated utility margin for the three months ended September 30, 2024 was $257.3 million as compared with $232.2 million for the same period in 2023, an increase of $25.1 million, or 10.8 percent. Primary components of the change in utility margin include the following (in millions):

	Utility Margin 2024 vs. 2023
Utility Margin Items Impacting Net Income
Base rates	$	17.2
Transmission revenue due to market conditions and rates	5.9
Electric retail volumes	3.6
Montana property tax tracker collections	1.5
Montana natural gas transportation	0.9
Non-recoverable Montana electric supply costs	0.6
Natural gas retail volumes	(0.3)
Other	(1.2)
Change in Utility Margin Items Impacting Net Income	28.2
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property and other taxes	(2.0)
Operating expenses recovered in revenue, offset in operating and maintenance expense	(0.9)
Production tax credits, offset in income tax expense	(0.2)
Change in Utility Margin Items Offset Within Net Income	(3.1)
Increase in Consolidated Utility Margin(1)	$	25.1

29

(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.

Higher electric retail volumes were driven by favorable weather in Montana impacting residential demand, higher commercial and industrial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in South Dakota impacting residential demand. Lower natural gas retail volumes were driven by unfavorable weather in Montana partly offset by customer growth in all jurisdictions.

Under the PCCAM, net supply costs higher or lower than the PCCAM base rate (PCCAM Base) (excluding qualifying facility (QF) costs) are allocated 90 percent to Montana customers and 10 percent to shareholders. For the three months ended September 30, 2024, we over-collected supply costs of $5.9 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $0.7 million (10 percent of the PCCAM Base cost variance). For the three months ended September 30, 2023, we over-collected supply costs of $1.0 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $0.1 million.

	Three Months Ended September 30,
	2024		2023		Change		% Change
	(dollars in millions)
Operating Expenses (excluding fuel, purchased supply and direct transmission expense)
Operating and maintenance	$	55.9	$	53.2	$	2.7	5.1	%
Administrative and general	34.9		29.4		5.5		18.7
Property and other taxes	41.6		41.8		(0.2)		(0.5)
Depreciation and depletion	57.0		52.2		4.8		9.2
Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense)	$	189.4	$	176.6	$	12.8	7.2	%

30

Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $189.4 million for the three months ended September 30, 2024, as compared with $176.6 million for the three months ended September 30, 2023. Primary components of the change include the following (in millions):

	Operating Expenses
	2024 vs. 2023
Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income
Depreciation expense due to plant additions and higher depreciation rates	$	4.8
Insurance expense, primarily due to increased wildfire risk premiums	3.4
Labor and benefits(1)	3.0
Electric generation maintenance	1.9
Property and other taxes not recoverable within trackers	1.9
Technology implementation and maintenance expenses	(0.1)
Partial recovery from previously impaired alternative energy storage investment	(0.5)
Uncollectible accounts	(1.1)
Other	(1.1)
Change in Items Impacting Net Income	12.2
Operating Expenses Offset Within Net Income
Property and other taxes recovered in trackers, offset in revenue	(2.0)
Operating and maintenance expenses recovered in trackers, offset in revenue	(0.9)
Deferred compensation, offset in other income	2.8
Pension and other postretirement benefits, offset in other income(1)	0.7
Change in Items Offset Within Net Income	0.6
Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense)	$	12.8

(1) In order to present the total change in labor and benefits, we have included the change in the non-service cost component of our pension and other postretirement benefits, which is recorded within other income on our Condensed Consolidated Statements of Income. This change is offset within this table as it does not affect our operating expenses.

We estimate property taxes throughout each year, and update those estimates based on valuation reports received from the Montana Department of Revenue. Under Montana law, we are allowed to track the increases and decreases in the actual level of state and local taxes and fees and adjust our rates to recover the increase or decrease between rate cases less the amount allocated to FERC-jurisdictional customers and net of the associated income tax benefit.

Consolidated operating income for the three months ended September 30, 2024 was $67.9 million as compared with $55.6 million in the same period of 2023. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, electric retail volumes, Montana property tax tracker collections, and lower non-recoverable Montana electric supply costs. These were offset in part by natural gas retail volumes, depreciation, operating, and administrative and general expenses.

Consolidated interest expense was $33.4 million for the three months ended September 30, 2024 as compared with $28.7 million for the same period of 2023. This increase was due to higher borrowings and interest rates, partly offset by higher capitalization of Allowance for Funds Used During Construction (AFUDC).

Consolidated other income was $9.1 million for the three months ended September 30, 2024 as compared with $4.1 million for the same period of 2023. This increase was primarily due to higher capitalization of AFUDC, a decrease in the non-service component of pension expense, and an increase in the value of deferred shares held in trust for deferred compensation.

Consolidated income tax benefit was $3.2 million for the three months ended September 30, 2024 as compared to income tax expense of $1.7 million for the same period of 2023. Our effective tax rate for the three months ended September 30, 2024 was (7.3)% as compared with 5.5% for the same period in 2023. As further discussed in Note 3 - Income Taxes, during the third quarter of 2024 we filed a tax accounting method change with the IRS consistent with the guidance for natural gas transmission

31

and distribution property. This resulted in an income tax benefit of $7.0 million during the three months ended September 30, 2024, related to repair costs that were previously capitalized for tax purposes in the 2022 and prior tax years.

The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):

	Three Months Ended September 30,
	2024				2023
Income Before Income Taxes	$	43.7			$	31.0
Income tax calculated at federal statutory rate	9.2		21.0	%	6.5		21.0	%
Permanent or flow-through adjustments:
State income tax, net of federal provisions	0.1		0.1		0.1		0.4
Gas repairs safe harbor method change	(7.0)		(16.0)		—		—
Flow-through repairs deductions	(4.6)		(10.5)		(4.2)		(13.5)
Production tax credits	(2.4)		(5.6)		(1.3)		(4.1)
Amortization of excess deferred income tax	(0.2)		(0.5)		(0.3)		(1.0)
Income tax return to accrual adjustment	—		—		0.4		1.3
Plant and depreciation flow-through items	1.8		4.2		0.4		1.2
Other, net	(0.1)		—		0.1		0.2
	(12.4)		(28.3)		(4.8)		(15.5)
Income tax (benefit) expense	$	(3.2)	(7.3)	%	$	1.7	5.5	%

We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits.

32

Nine Months Ended September 30, 2024 Compared with the Nine Months Ended September 30, 2023

Consolidated net income for the nine months ended September 30, 2024 was $143.6 million as compared with $111.0 million for the same period in 2023. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, Montana property tax tracker collections, electric retail volumes, and an income tax benefit from a change to the gas repairs safe harbor method. These were offset in part by non-recoverable Montana electric supply costs, a less favorable QF liability adjustment in the current year, natural gas retail volumes, depreciation, operating, administrative and general costs, and interest expense.

Consolidated gross margin for the nine months ended September 30, 2024 was $338.3 million as compared with $289.8 million in 2023, an increase of $48.5 million, or 16.7 percent. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, Montana property tax tracker collections, and electric retail volumes. These were offset in part by non-recoverable Montana electric supply costs, a less favorable QF liability adjustment in the current year, natural gas retail volumes, depreciation, and operating and maintenance costs.

	Electric				Natural Gas				Total
	2024		2023		2024		2023		2024		2023
	(in millions)
Reconciliation of gross margin to utility margin:
Operating Revenues	$	909.8	$	804.6	$	230.6	$	261.5	$	1,140.4	$	1,066.1
Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	257.0		198.5		82.1		123.5		339.1		322.0
Less: Operating and maintenance	126.3		123.8		41.1		40.1		167.4		163.9
Less: Property and other taxes	96.6		103.0		28.4		29.6		125.0		132.6
Less: Depreciation and depletion	142.4		130.5		28.2		27.3		170.6		157.8
Gross Margin	287.5		248.8		50.8		41.0		338.3		289.8
Operating and maintenance	126.3		123.8		41.1		40.1		167.4		163.9
Property and other taxes	96.6		103.0		28.4		29.6		125.0		132.6
Depreciation and depletion	142.4		130.5		28.2		27.3		170.6		157.8
Utility Margin(1)	$	652.8	$	606.1	$	148.5	$	138.0	$	801.3	$	744.1

(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.

	Nine Months Ended September 30,
	2024		2023		Change		% Change
	(dollars in millions)
Utility Margin
Electric	$	652.8	$	606.1	$	46.7	7.7	%
Natural Gas	148.5		138.0		10.5		7.6
Total Utility Margin(1)	$	801.3	$	744.1	$	57.2	7.7	%

(1) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.

Consolidated utility margin for the nine months ended September 30, 2024 was $801.3 million as compared with $744.1 million for the same period in 2023, an increase of $57.2 million, or 7.7 percent. Primary components of the change in utility margin include the following (in millions):

33

	Utility Margin 2024 vs. 2023
Utility Margin Items Impacting Net Income
Base rates	$	53.4
Transmission revenue due to market conditions and rates	13.5
Montana property tax tracker collections(1)	4.9
Montana natural gas transportation	1.9
Electric retail volumes	1.0
QF liability adjustment	(4.2)
Non-recoverable Montana electric supply costs	(3.8)
Natural gas retail volumes	(2.7)
Other	2.4
Change in Utility Margin Items Impacting Net Income	66.4
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property and other taxes	(8.2)
Production tax credits, offset in income tax expense	(1.5)
Operating expenses recovered in revenue, offset in operating and maintenance expense	0.5
Change in Utility Margin Items Offset Within Net Income	(9.2)
Increase in Consolidated Utility Margin(2)	$	57.2

(1) In the fourth quarter of 2023, upon receiving the final valuation reports from the Montana Department of Revenue, we recorded a significant reduction in property tax expense. Accordingly, we do not anticipate this year-to-date favorable change to Utility Margin to continue on a full year basis.

(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above.

Under the PCCAM, net supply costs higher or lower than the PCCAM Base (excluding qualifying facility (QF) costs) are allocated 90 percent to Montana customers and 10 percent to shareholders. For the nine months ended September 30, 2024, we under-collected supply costs of $10.1 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $1.2 million (10 percent of the PCCAM Base cost variance). For the nine months ended September 30, 2023, we over-collected supply costs of $23.5 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $2.6 million.

Electric retail volume impact was favorable due to higher residential usage in Montana due to favorable weather, higher industrial volumes, and customer growth, partly offset by lower residential usage due to unfavorable weather in South Dakota, and lower commercial demand. Lower natural gas retail volumes were driven by unfavorable weather in all jurisdictions partly offset by customer growth.

The adjustment to our electric QF liability (unrecoverable costs associated with PURPA contracts as part of a 2002 stipulation with the MPSC and other parties) reflects a $0.8 million gain in 2024, as compared with a $5.0 million gain for the same period in 2023, as further explained above in the consolidated results of operations for the three months ended June 30, 2024.

	Nine Months Ended September 30,
	2024		2023		Change		% Change
	(dollars in millions)
Operating Expenses (excluding fuel, purchased supply and direct transmission expense)
Operating and maintenance	$	167.4	$	163.9	$	3.5	2.1	%
Administrative and general	106.7		94.1		12.6		13.4
Property and other taxes	125.0		131.0		(6.0)		(4.6)
Depreciation and depletion	170.6		157.8		12.8		8.1
Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense)	$	569.7	$	546.8	$	22.9	4.2	%

34

Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $569.7 million for the nine months ended September 30, 2024, as compared with $546.8 million for the nine months ended September 30, 2023. Primary components of the change include the following (in millions):

	Operating Expenses
	2024 vs. 2023
Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income
Depreciation expense due to plant additions and higher depreciation rates	$	12.8
Labor and benefits(1)	6.4
Insurance expense, primarily due to increased wildfire risk premiums	4.4
Litigation outcome (Pacific Northwest Solar)	2.4
Property and other taxes not recoverable within trackers	2.2
Non-cash impairment of alternative energy storage investment	1.7
Electric generation maintenance	1.3
Technology implementation and maintenance expenses	0.5
Uncollectible accounts	(2.1)
Other	(2.4)
Change in Items Impacting Net Income	27.2
Operating Expenses Offset Within Net Income
Property and other taxes recovered in trackers, offset in revenue	(8.2)
Deferred compensation, offset in other income	2.9
Pension and other postretirement benefits, offset in other income(1)	0.5
Operating and maintenance expenses recovered in trackers, offset in revenue	0.5
Change in Items Offset Within Net Income	(4.3)
Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense)	$	22.9

(1) In order to present the total change in labor and benefits, we have included the change in the non-service cost component of our pension and other postretirement benefits, which is recorded within other income on our Condensed Consolidated Statements of Income. This change is offset within this table as it does not affect our operating expenses.

Consolidated operating income for the nine months ended September 30, 2024 was $231.6 million as compared with $197.3 million in the same period of 2023. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, Montana property tax tracker collections, and electric retail volumes. These were offset in part by non-recoverable Montana electric supply costs, a less favorable QF liability adjustment in the current year, natural gas retail volumes, depreciation, operating, and administrative and general costs.

Consolidated interest expense was $96.3 million for the nine months ended September 30, 2024 as compared with $85.1 million for the same period of 2023. This increase was due to higher borrowings and interest rates partly offset by higher capitalization of AFUDC.

Consolidated other income was $19.6 million for the nine months ended September 30, 2024 as compared to $12.9 million during the same period of 2023. This increase was primarily due a $2.3 million reversal of a previously expensed Community Renewable Energy Project penalty due to a favorable legal ruling, higher capitalization of AFUDC, a decrease in the non-service component of pension expense, and an increase in the value of deferred shares held in trust for deferred compensation, partly offset by a $2.5 million non-cash impairment of an alternative energy storage equity investment.

Consolidated income tax expense for the nine months ended September 30, 2024 was $11.4 million as compared to $14.1 million in the same period of 2023. Our effective tax rate for the nine months ended September 30, 2024 was 7.4% as compared with 11.3% for the same period in 2023. As further discussed in Note 3 - Income Taxes, during the third quarter of 2024 we filed a tax accounting method change with the IRS consistent with the guidance for natural gas transmission and distribution property. This resulted in an income tax benefit of $7.0 million during the nine months ended September 30, 2024, related to repair costs that were previously capitalized for tax purposes in the 2022 and prior tax years. Income tax expense for the nine

35

months ended September 30, 2023 includes a one-time $3.2 million charge for the reduction of previously claimed alternative minimum tax credits.

The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):

	Nine Months Ended September 30,
	2024				2023
Income Before Income Taxes	$	155.0			$	125.1
Income tax calculated at federal statutory rate	32.5		21.0	%	26.3		21.0	%
Permanent or flow-through adjustments:
State income tax, net of federal provisions	0.7		0.5		1.4		1.1
Flow-through repairs deductions	(13.8)		(8.9)		(11.7)		(9.4)
Production tax credits	(7.4)		(4.8)		(5.6)		(4.5)
Gas repairs safe harbor method change	(7.0)		(4.5)		—		—
Amortization of excess deferred income tax	(0.8)		(0.5)		(1.4)		(1.1)
Reduction to previously claimed alternative minimum tax credit	—		—		3.2		2.5
Income tax return to accrual adjustment	—		—		0.4		0.3
Plant and depreciation flow-through items	6.0		3.8		1.2		1.0
Share-based compensation	0.3		0.2		0.4		0.3
Other, net	0.9		0.6		(0.1)		0.1
	(21.1)		(13.6)		(12.2)		(9.7)
Income tax expense	$	11.4	7.4	%	$	14.1	11.3	%

We compute income tax expense for each quarter based on the estimated annual effective tax rate for the year, adjusted for certain discrete items. Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits.

36

ELECTRIC SEGMENT

We have various classifications of electric revenues, defined as follows:

•Retail: Sales of electricity to residential, commercial and industrial customers, and the impact of regulatory

mechanisms.

•Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expense and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.

•Transmission: Reflects transmission revenues regulated by the FERC.

•Wholesale and other are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expense.

Three Months Ended September 30, 2024 Compared with the Three Months Ended September 30, 2023

	Revenues				Change				Megawatt Hours (MWH)		Avg. Customer Counts
	2024		2023		$		%		2024	2023	2024	2023
	(in thousands)
Montana	$	100,737	$	96,812	$	3,925	4.1	%	685	664	328,962	322,832
South Dakota	19,062		17,951		1,111		6.2		145	151	51,393	51,236
Residential	119,799		114,763		5,036		4.4		830	815	380,355	374,068
Montana	109,655		110,100		(445)		(0.4)		830	825	75,857	74,385
South Dakota	30,053		27,474		2,579		9.4		288	289	13,115	12,989
Commercial	139,708		137,574		2,134		1.6		1,118	1,114	88,972	87,374
Industrial	11,852		11,423		429		3.8		726	691	80	79
Other	14,071		13,243		828		6.3		82	71	8,274	8,204
Total Retail Electric	$	285,430	$	277,003	$	8,427	3.0	%	2,756	2,691	477,681	469,725
Regulatory amortization	(6,805)		(18,534)		11,729		(63.3)
Transmission	25,750		19,847		5,903		29.7
Wholesale and Other	2,103		1,714		389		22.7
Total Revenues	$	306,478	$	280,030	$	26,448	9.4	%
Fuel, purchased supply and direct transmission expense(1)	80,761		77,995		2,766		3.5
Utility Margin(2)	$	225,717	$	202,035	$	23,682	11.7	%

(1) Exclusive of depreciation and depletion.

(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

	Cooling Degree Days			2024 as compared with:
	2024	2023	Historic Average	2023	Historic Average
Montana	441	396	385	11% warmer	15% warmer
South Dakota	628	744	635	16% cooler	1% cooler
	Heating Degree Days			2024 as compared with:
	2024	2023	Historic Average	2023	Historic Average
Montana(1)	169	190	280	11% warmer	40% warmer
South Dakota	39	25	76	56% colder	49% warmer

(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.

37

The following summarizes the components of the changes in electric utility margin for the three months ended September 30, 2024 and 2023 (in millions):

	Utility Margin 2024 vs. 2023
Utility Margin Items Impacting Net Income
Base rates	$	15.2
Transmission revenue due to market conditions and rates	5.9
Retail volumes	3.6
Montana property tax tracker collections	1.2
Non-recoverable Montana electric supply costs	0.6
Other	0.2
Change in Utility Margin Items Impacting Net Income	26.7
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property and other taxes	(1.9)
Operating expenses recovered in revenue, offset in operating and maintenance expense	(0.9)
Production tax credits, offset in income tax expense	(0.2)
Change in Utility Margin Items Offset Within Net Income	(3.0)
Increase in Utility Margin(1)	$	23.7

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

Higher electric retail volumes were driven by favorable weather in Montana impacting residential demand, higher commercial and industrial demand, and customer growth in all jurisdictions, partly offset by unfavorable weather in South Dakota impacting residential demand.

Under the PCCAM, net supply costs higher or lower than the PCCAM base rate (PCCAM Base) (excluding qualifying facility (QF) costs) are allocated 90 percent to Montana customers and 10 percent to shareholders. For the three months ended September 30, 2024, we over-collected supply costs of $5.9 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $0.7 million (10 percent of the PCCAM Base cost variance). For the three months ended September 30, 2023, we over-collected supply costs of $1.0 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $0.1 million.

The change in regulatory amortization revenue is primarily due to timing differences between when we incur electric supply costs and property taxes and when we recover these costs in rates from our customers, which has a minimal impact on utility margin. Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.

38

Nine Months Ended September 30, 2024 Compared with the Nine Months Ended September 30, 2023

	Revenues				Change				Megawatt Hours (MWH)		Avg. Customer Counts
	2024		2023		$		%		2024	2023	2024	2023
	(in thousands)
Montana	$	304,128	$	306,114	$	(1,986)	(0.6)	%	2,114	2,103	327,644	321,797
South Dakota	53,764		53,408		356		0.7		435	481	51,395	51,224
Residential	357,892		359,522		(1,630)		(0.5)		2,549	2,584	379,039	373,021
Montana	310,813		324,632		(13,819)		(4.3)		2,410	2,435	75,712	74,294
South Dakota	84,182		77,736		6,446		8.3		834	834	13,070	12,972
Commercial	394,995		402,368		(7,373)		(1.8)		3,244	3,269	88,782	87,266
Industrial	34,803		33,986		817		2.4		2,190	1,961	80	79
Other	27,437		27,229		208		0.8		131	119	6,552	6,483
Total Retail Electric	$	815,127	$	823,105	$	(7,978)	(1.0)	%	8,114	7,933	474,453	466,849
Regulatory amortization	18,637		(80,085)		98,722		(123.3)
Transmission	70,573		57,092		13,481		23.6
Wholesale and Other	5,461		4,492		969		21.6
Total Revenues	$	909,798	$	804,604	$	105,194	13.1	%
Fuel, purchased supply and direct transmission expense(1)	256,989		198,492		58,497		29.5
Utility Margin(2)	$	652,809	$	606,112	$	46,697	7.7	%

(1) Exclusive of depreciation and depletion.

(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

	Cooling Degree Days			2024 as compared with:
	2024	2023	Historic Average	2023	Historic Average
Montana(1)	484	440	447	10% warmer	8% warmer
South Dakota	682	945	707	28% cooler	4% cooler

	Heating Degree Days			2024 as compared with:
	2024	2023	Historic Average	2023	Historic Average
Montana(1)	4,661	4,746	4,755	2% warmer	2% warmer
South Dakota	4,847	5,982	5,730	19% warmer	15% warmer

(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.

39

The following summarizes the components of the changes in electric utility margin for the nine months ended September 30, 2024 and 2023 (in millions):

	Utility Margin 2024 vs. 2023
Utility Margin Items Impacting Net Income
Base rates	$	43.2
Transmission revenue due to market conditions and rates	13.5
Montana property tax tracker collections	3.9
Retail volumes	1.0
QF liability adjustment	(4.2)
Non-recoverable Montana electric supply costs	(3.8)
Other	1.6
Change in Utility Margin Items Impacting Net Income	55.2
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property and other taxes	(7.5)
Production tax credits, offset in income tax expense	(1.5)
Operating expenses recovered in revenue, offset in operating and maintenance expense	0.5
Change in Utility Margin Items Offset Within Net Income	(8.5)
Increase in Utility Margin(1)	$	46.7

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

Electric retail volume impact was favorable due to higher residential usage in Montana due to favorable weather, higher industrial volumes, and customer growth, partly offset by lower residential usage in South Dakota due to unfavorable weather, and lower commercial demand.

Under the PCCAM, net supply costs higher or lower than the PCCAM Base (excluding qualifying facility (QF) costs) are allocated 90 percent to Montana customers and 10 percent to shareholders. For the nine months ended September 30, 2024, we under-collected supply costs of $10.1 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $1.2 million (10 percent of the PCCAM Base cost variance). For the nine months ended September 30, 2023, we over-collected supply costs of $23.5 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $2.6 million.

The adjustment to our electric QF liability (unrecoverable costs associated with PURPA contracts as part of a 2002 stipulation with the MPSC and other parties) reflects a $0.8 million gain in 2024, as compared with a $5.0 million gain for the same period in 2023, as further explained above in the consolidated results of operations for the nine months ended September 30, 2024.

The change in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on utility margin. Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.

40

NATURAL GAS SEGMENT

We have various classifications of natural gas revenues, defined as follows:

•Retail: Sales of natural gas to residential, commercial and industrial customers, and the impact of regulatory mechanisms.

•Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expenses and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.

•Wholesale: Primarily represents transportation and storage for others.

Three Months Ended September 30, 2024 Compared with the Three Months Ended September 30, 2023

	Revenues				Change				Dekatherms (Dkt)		Avg. Customer Counts
	2024		2023		$		%		2024	2023	2024	2023
	(in thousands)
Montana	$	8,422	$	9,603	$	(1,181)	(12.3)	%	739	825	185,578	183,586
South Dakota	1,745		1,987		(242)		(12.2)		108	102	42,389	41,821
Nebraska	1,791		2,251		(460)		(20.4)		143	138	37,834	37,580
Residential	11,958		13,841		(1,883)		(13.6)		990	1,065	265,801	262,987
Montana	6,190		6,136		54		0.9		609	622	26,094	25,657
South Dakota	1,262		1,498		(236)		(15.8)		225	208	7,336	7,184
Nebraska	795		1,291		(496)		(38.4)		134	142	5,009	4,970
Commercial	8,247		8,925		(678)		(7.6)		968	972	38,439	37,811
Industrial	115		106		9		8.5		15	13	238	231
Other	169		160		9		5.6		23	19	196	191
Total Retail Gas	$	20,489	$	23,032	$	(2,543)	(11.0)	%	1,996	2,069	304,674	301,220
Regulatory amortization	8,025		7,458		567		(7.6)
Wholesale and other	10,169		10,570		(401)		(3.8)
Total Revenues	$	38,683	$	41,060	$	(2,377)	(5.8)	%
Fuel, purchased supply and direct transmission expense(1)	7,127		10,948		(3,821)		(34.9)
Utility Margin(2)	$	31,556	$	30,112	$	1,444	4.8	%

(1) Exclusive of depreciation and depletion.

(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

	Heating Degree Days			2024 as compared with:
	2024	2023	Historic Average	2023	Historic Average
Montana(1)	203	226	319	10% warmer	36% warmer
South Dakota	39	25	76	56% colder	49% warmer
Nebraska	7	15	33	53% warmer	79% warmer

(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.

41

The following summarizes the components of the changes in natural gas utility margin for the three months ended September 30, 2024 and 2023:

	Utility Margin 2024 vs. 2023
	(in millions)
Utility Margin Items Impacting Net Income
Base rates	$	2.0
Montana natural gas transportation	0.9
Montana property tax tracker collections	0.3
Retail volumes	(0.3)
Other	(1.4)
Change in Utility Margin Items Impacting Net Income	1.5
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property and other taxes	(0.1)
Change in Utility Margin Items Offset Within Net Income	(0.1)
Increase in Utility Margin(1)	$	1.4

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

Lower retail volumes were driven by unfavorable weather in Montana partly offset by customer growth in all jurisdictions.

42

Nine Months Ended September 30, 2024 Compared with the Nine Months Ended September 30, 2023

	Revenues				Change				Dekatherms (Dkt)		Avg. Customer Counts
	2024		2023		$		%		2024	2023	2024	2023
	(in thousands)
Montana	$	75,933	$	94,074	$	(18,141)	(19.3)	%	9,220	9,206	185,412	183,584
South Dakota	21,244		30,297		(9,053)		(29.9)		2,113	2,557	42,477	41,962
Nebraska	16,106		30,221		(14,115)		(46.7)		1,812	2,053	37,924	37,752
Residential	113,283		154,592		(41,309)		(26.7)		13,145	13,816	265,813	263,298
Montana	42,016		52,393		(10,377)		(19.8)		5,307	5,456	26,112	25,679
South Dakota	14,283		21,289		(7,006)		(32.9)		2,139	2,385	7,353	7,218
Nebraska	8,982		19,119		(10,137)		(53.0)		1,328	1,528	5,045	5,017
Commercial	65,281		92,801		(27,520)		(29.7)		8,774	9,369	38,510	37,914
Industrial	703		995		(292)		(29.3)		98	107	237	231
Other	1,036		1,282		(246)		(19.2)		156	155	196	189
Total Retail Gas	$	180,303	$	249,670	$	(69,367)	(27.8)	%	22,173	23,447	304,756	301,632
Regulatory amortization	18,686		(21,312)		39,998		(187.7)
Wholesale and other	31,645		33,172		(1,527)		(4.6)
Total Revenues	$	230,634	$	261,530	$	(30,896)	(11.8)	%
Fuel, purchased supply and direct transmission expense(1)	82,100		123,521		(41,421)		(33.5)
Utility Margin(2)	$	148,534	$	138,009	$	10,525	7.6	%

(1) Exclusive of depreciation and depletion.

(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

	Heating Degree Days			2024 as compared with:
	2024	2023	Historic Average	2023	Historic Average
Montana(1)	4,792	4,855	4,854	1% warmer	1% warmer
South Dakota	4,847	5,982	5,730	19% warmer	15% warmer
Nebraska	3,985	4,521	4,501	12% warmer	11% warmer

(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.

43

The following summarizes the components of the changes in natural gas utility margin for the nine months ended September 30, 2024 and 2023:

	Utility Margin 2024 vs. 2023
	(in millions)
Utility Margin Items Impacting Net Income
Base rates	$	10.2
Montana natural gas transportation	1.9
Montana property tax tracker collections	1.0
Retail volumes	(2.7)
Other	0.8
Change in Utility Margin Items Impacting Net Income	11.2
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property tax expense	(0.7)
Change in Utility Margin Items Offset Within Net Income	(0.7)
Increase in Utility Margin(1)	$	10.5

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

Lower retail volumes were driven by unfavorable weather in all jurisdictions partly offset by customer growth.

44

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

We require liquidity to support and grow our business, and use our liquidity for working capital needs, capital expenditures, investments in or acquisitions of assets, and to repay debt. For NorthWestern Energy Group, liquidity is primarily provided through its revolving credit facility and dividends from its utility operating subsidiaries, NW Corp and NWE Public Service. These subsidiaries are subject to certain restrictions that may limit the amount of their dividend distributions. See Note 16 - Common Stock in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023 for further information regarding these dividend restrictions. As of September 30, 2024, we are in compliance with these provisions.

We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future utility rate increases should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures. We plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases, and expect to continue targeting a long-term dividend payout ratio of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to meet these targets.

As of September 30, 2024, our total net liquidity was approximately $316.5 million, including $2.5 million of cash and $314.0 million of revolving credit facility availability with no letters of credit outstanding.

Cash Flows

The following table summarizes our consolidated cash flows (in millions):

	Nine Months Ended September 30,
	2024		2023
Operating Activities
Net income	$	143.6	$	111.0
Non-cash adjustments to net income	175.3		141.1
Changes in working capital	35.9		194.5
Other noncurrent assets and liabilities	(10.9)		(19.6)
Cash Provided by Operating Activities	343.9		427.0
Investing Activities
Property, plant and equipment additions	(400.5)		(407.2)
Investment in equity securities	(4.6)		(3.8)
Cash Used in Investing Activities	(405.1)		(411.0)
Financing Activities
Proceeds from issuance of common stock, net	—		73.6
Issuance of long-term debt	215.0		300.0
Issuances of short-term borrowings	100.0		—
Line of credit repayments, net	(32.0)		(273.0)
Repayments on long-term debt	(100.0)		—
Dividends on common stock	(118.9)		(115.0)
Other financing activities, net	(0.2)		(2.4)
Cash Provided by (Used in) Financing Activities	63.9		(16.8)
Increase (decrease) in Cash, Cash Equivalents, and Restricted Cash	2.7		(0.8)
Cash, Cash Equivalents, and Restricted Cash, beginning of period	25.2		22.5
Cash, Cash Equivalents, and Restricted Cash, end of period	$	27.9	$	21.7

Operating Activities

45

As of September 30, 2024, cash, cash equivalents, and restricted cash were $27.9 million as compared with $25.2 million as of December 31, 2023 and $21.7 million as of September 30, 2023. Cash provided by operating activities totaled $343.9 million for the nine months ended September 30, 2024 as compared with $427.0 million during the nine months ended September 30, 2023. As shown in the table below, this decrease in operating cash flows is primarily due to significant net cash inflows in the prior period from the recovery of previously under-collected energy supply costs, compared to minimal net cash inflows for energy supply costs in the current period due to the timely recovery of energy supply costs.

Uncollected energy supply costs (in millions)
	Beginning of period		End of period		Net cash inflows (outflows)
2023	$	115.4	$	16.6	$	98.8
2024	$	7.8	$	1.8	$	6.0
Decrease in net cash inflows					$	(92.8)

Investing Activities

Cash used in investing activities totaled $405.1 million during the nine months ended September 30, 2024, as compared with $411.0 million during the nine months ended September 30, 2023. Plant additions during the first nine months of 2024 include maintenance additions of approximately $216.5 million and capacity related capital expenditures of $184.0 million. Plant additions during the first nine months of 2023 included maintenance additions of approximately $235.0 million and capacity related capital expenditures of approximately $172.2 million.

Financing Activities

Cash provided by financing activities totaled $63.9 million during the nine months ended September 30, 2024, as compared with cash used in financing activities of $16.8 million during the nine months ended September 30, 2023. During the nine months ended September 30, 2024, cash provided by financing activities reflects proceeds from the issuance of debt of $215.0 million and short-term borrowings of $100.0 million, partly offset by payment of dividends of $118.9 million, repayment of 1.00 percent, $100.0 million of Montana First Mortgage Bonds, and net repayments under our revolving lines of credit of $32.0 million. During the nine months ended September 30, 2023, cash used in financing activities reflects net repayments under our revolving lines of credit of $273.0 million and payment of dividends of $115.0 million, partly offset by proceeds from the issuance of debt of $300.0 million and proceeds received from the issuance of common stock of $73.6 million.

Cash Requirements and Capital Resources

We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future rate increases should be sufficient to satisfy our material cash requirements over the short-term and the long-term. As a rate-regulated utility our customer rates are generally structured to recover expected operating costs, with an opportunity to earn a return on our invested capital. This structure supports recovery for many of our operating expenses, although there are situations where the timing of our cash outlays results in increased working capital requirements. Due to the seasonality of our utility business, our short-term working capital requirements typically peak during the coldest winter months and warmest summer months when we cover the lag between when purchasing energy supplies and when customers pay for these costs. Our credit facilities may also be utilized for funding cash requirements during seasonally active construction periods, with peak activity during warmer months. Our cash requirements also include a variety of contractual obligations as outlined below in the “Contractual Obligations and Other Commitments” section.

Our material cash requirements are also related to investment in our business through our capital expenditure program. Our estimated capital expenditures are discussed in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023 within the Management’s Discussion and Analysis of Financial Condition and Results of Operations under the "Significant Infrastructure Investments and Initiatives" section. As of September 30, 2024, there have been no material changes in our estimated capital expenditures. The actual amount of capital expenditures is subject to certain factors including the impact that a material change in operations, available financing, supply chain issues, or inflation could impact our current liquidity and ability to fund capital resource requirements. Events such as these could cause us to defer a portion of our planned capital expenditures, as necessary. To fund our strategic growth opportunities, we evaluate the additional capital need in balance with debt capacity and equity issuances that would be intended to allow us to maintain investment grade ratings.

Credit Facilities

46

Liquidity is generally provided by internal operating cash flows and the use of our unsecured revolving credit facilities. We utilize availability under our revolving credit facilities to manage our cash flows due to the seasonality of our business and to fund capital investment. Cash on hand in excess of current operating requirements is generally used to invest in our business and reduce borrowings.

For further information on our credit facilities, see Note 10 - Unsecured Credit Facilities in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023.

As of September 30, 2024 and 2023 the outstanding balances of our credit facilities were $286.0 million and $177.0 million, respectively. As of October 25, 2024, the availability under our credit facilities was approximately $335.0 million, and there were no letters of credit outstanding.

Long-term Debt and Equity

We generally issue long-term debt to refinance other long-term debt maturities and borrowings under our revolving credit facilities, as well as to fund long-term capital investments and strategic opportunities.

For further information on our recent long-term debt activity, see Note 5 - Financing Activities to the Condensed Consolidated Financial Statements included herein.

We generally issue equity securities to fund long-term investment in our business. We evaluate our equity issuance needs to support our plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases.

Credit Ratings

In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and our customers, may impact our trade credit availability, and could result in the need to issue additional equity securities. Fitch Ratings (Fitch), Moody’s Investors Service (Moody’s), and S&P Global Ratings (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of October 25, 2024, our current ratings with these agencies are as follows:

	Issuer Rating	Senior Secured Rating	Senior Unsecured Rating	Outlook
NorthWestern Energy Group
Fitch(1)(2)	BBB	-	BBB	Stable
Moody’s	-	-	-	-
S&P(2)	BBB	-	-	Stable
NW Corp
Fitch(1)(2)	BBB	A-	BBB+	Stable
Moody’s(2)	Baa2	A3	Baa2	Stable
S&P(2)	BBB	A-	-	Stable
NWE Public Service
Fitch(1)(2)	BBB	A-	BBB+	Stable
Moody’s(2)	Baa2	A3	-	Stable
S&P(2)	BBB	A-	-	Stable

(1) This Fitch Issuer Rating represents the Issuer Default Rating.

(2) As part of completing the holding company reorganization, NorthWestern Energy Group and NWE Public Service received their credit ratings from these agencies in December 2023. These agencies also affirmed their ratings for NW Corp.

A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

Contractual Obligations and Other Commitments

47

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. The following table summarizes our contractual cash obligations and commitments as of September 30, 2024.

	Total		2024		2025		2026		2027		2028		Thereafter
	(in thousands)
Long-term debt(1)	$	2,880,660	$	—	$	300,000	$	105,000	$	—	$	465,660	$	2,010,000
Finance leases	6,327		866		3,596		1,865		—		—		—
Short-term borrowings	100,000		—		100,000		—		—		—		—
Estimated pension and other postretirement obligations(2)	47,785		2,937		11,437		11,137		11,137		11,137		N/A
Qualifying facilities liability(3)	247,480		18,528		60,360		55,393		56,665		42,400		14,134
Supply and capacity contracts(4)	3,279,236		92,481		331,100		294,228		275,410		257,802		2,028,215
Contractual interest payments on debt(5)	1,578,806		35,493		125,836		116,651		114,992		112,135		1,073,699
Commitments for significant capital projects(6)	34,800		26,817		7,983		—		—		—		—
Total Commitments(7)	$	8,175,094	$	177,122	$	940,312	$	584,274	$	458,204	$	889,134	$	5,126,048

_________________________

(1)Represents cash payments for long-term debt and excludes $12.8 million of debt discounts and debt issuance costs, net.

(2)We estimate cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter. Pension and postretirement benefit estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements.

(3)Certain QFs require us to purchase minimum amounts of energy at prices ranging from $118 to $130 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $247.5 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $221.0 million.

(4)We have entered into various purchase commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 26 years. The energy supply costs incurred under these contracts are generally recoverable through rate mechanisms approved by the MPSC.

(5)Contractual interest payments include our revolving credit facilities, which have a variable interest rate. We have assumed an average interest rate of 6.19 percent on the outstanding balance through maturity of the facilities.

(6)Represents significant firm purchase commitments for construction of planned capital projects.

(7)The table above excludes potential tax payments related to uncertain tax positions as they are not practicable to estimate. Additionally, the table above excludes reserves for environmental remediation (See Note 10 - Commitments and Contingencies) and asset retirement obligations as the amount and timing of cash payments may be uncertain.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of financial condition and results of operations is based on our Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances.

We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates. We consider an estimate to be critical if it is material to the Financial Statements and it requires assumptions to be made that were uncertain at the time the estimate was made and changes in the estimate are reasonably likely to occur from period to period. This includes the accounting for the following: regulatory assets and liabilities, pension and postretirement benefit plans and income taxes. These policies were disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023. As of September 30, 2024, there have been no material changes in these policies.

48

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risks, including, but not limited to, interest rates, energy commodity price volatility, and counterparty credit exposure. We have established comprehensive risk management policies and procedures to manage these market risks. There have been no material changes in our market risks as disclosed in the NorthWestern Energy Group Annual Report on Form 10-K for the year ended December 31, 2023.

49

ITEM 4.CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and accumulated and reported to management, including the principal executive officer and principal financial officer to allow timely decisions regarding required disclosure.

We conducted an evaluation, under the supervision and with the participation of our principal executive officer and principal financial officer, of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based on this evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

50

PART II. OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

See Note 10 - Commitments and Contingencies, to the Financial Statements for information regarding legal proceedings.

ITEM 1A.  RISK FACTORS

Refer to the NorthWestern Energy Group Annual Report on the Form 10-K for the year ended December 31, 2023 for disclosure of the risk factors that could have a significant impact on our business, financial condition, results of operations or cash flows and could cause actual results or outcomes to differ materially from those discussed in our reports filed with the SEC (including this Quarterly Report on Form 10-Q), and elsewhere. These risk factors have not changed materially since such disclosure.

ITEM 5.  OTHER INFORMATION

Rule 10b5-1 Plans

During the three months ended September 30, 2024, no director or officer of the Company adopted or terminated a "Rule 10b5-1 trading agreement" or "non-Rule 10b5-1 trading agreement," as each term is defined in Item 408(a) of Regulation S-K.

51

ITEM 6.                      EXHIBITS -

(a) Exhibits

Exhibit 2.1 — Colstrip Units 3&4 Interests Abandonment and Acquisition Agreement, dated as of July 30, 2024 by and between Northwestern Corporation and Puget Sound Energy Inc. (incorporated by reference to Exhibit 2.1 of NorthWestern Energy Group, Inc.'s Current Report on Form 8-K, dated July 30, 2024 Commission File No. 000-56598).

Exhibit 31.1 — Certification of chief executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - NorthWestern Energy Group, Inc. 

Exhibit 31.2 — Certification of chief financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - NorthWestern Energy Group, Inc.

Exhibit 32.1 — Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - NorthWestern Energy Group, Inc.

Exhibit 32.2 — Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - NorthWestern Energy Group, Inc.

Exhibit 101.INS—Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

Exhibit 101.SCH—Inline XBRL Taxonomy Extension Schema Document

Exhibit 101.CAL—Inline XBRL Taxonomy Extension Calculation Linkbase Document

Exhibit 101.DEF—Inline XBRL Taxonomy Extension Definition Linkbase Document

Exhibit 101.LAB—Inline XBRL Taxonomy Label Linkbase Document

Exhibit 101.PRE—Inline XBRL Taxonomy Extension Presentation Linkbase Document

Exhibit 104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

52

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

			NorthWestern Energy Group, Inc.
Date:	October 29, 2024	By:	/s/ CRYSTAL LAIL
			Crystal Lail
			Vice President and Chief Financial Officer
			Duly Authorized Officer and Principal Financial Officer

53