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		June 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, 61,300,497 shares outstanding at July 26, 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 Six Months Ended June 30, 2024 and 2023	5
	Condensed Consolidated Statements of Comprehensive Income — Three and Six Months Ended June 30, 2024 and 2023	6
	Condensed Consolidated Balance Sheets — June 30, 2024 and December 31, 2023	7
	Condensed Consolidated Statements of Cash Flows — Three and Six Months Ended June 30, 2024 and 2023	8
	Condensed Consolidated Statements of Shareholders’ Equity — Three and Six Months Ended June 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 June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Revenues
Electric	$	260,134	$	229,266	$	603,320	$	524,574
Gas	59,795		61,236		191,951		220,470
Total Revenues	319,929		290,502		795,271		745,044
Operating expenses
Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	76,480		67,578		251,201		233,070
Operating and maintenance	57,367		54,840		111,549		110,701
Administrative and general	31,281		29,955		71,726		64,703
Property and other taxes	36,256		40,129		83,427		89,280
Depreciation and depletion	56,933		52,380		113,676		105,628
Total Operating Expenses	258,317		244,882		631,579		603,382
Operating income	61,612		45,620		163,692		141,662
Interest expense, net	(31,875)		(28,411)		(62,854)		(56,419)
Other income, net	6,160		4,062		10,479		8,799
Income before income taxes	35,897		21,271		111,317		94,042
Income tax expense	(4,243)		(2,147)		(14,577)		(12,388)
Net Income	$	31,654	$	19,124	$	96,740	$	81,654
Average Common Shares Outstanding	61,289		59,804		61,277		59,790
Basic Earnings per Average Common Share	$	0.52	$	0.32	$	1.58	$	1.37
Diluted Earnings per Average Common Share	$	0.52	$	0.32	$	1.58	$	1.37
Dividends Declared per Common Share	$	0.65	$	0.64	$	1.30	$	1.28

See Notes to Condensed Consolidated Financial Statements

5

NORTHWESTERN ENERGY GROUP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(in thousands)

	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Net Income	$	31,654	$	19,124	$	96,740	$	81,654
Other comprehensive income, net of tax:
Foreign currency translation adjustment	(1)		(1)		(2)		(3)
Postretirement medical liability adjustment	—		(167)		—		(334)
Reclassification of net losses on derivative instruments	113		113		226		226
Total Other Comprehensive Income (Loss)	112		(55)		224		(111)
Comprehensive Income	$	31,766	$	19,069	$	96,964	$	81,543

See Notes to Condensed Consolidated Financial Statements

6

NORTHWESTERN ENERGY GROUP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

	June 30, 2024		December 31, 2023
ASSETS
Current Assets:
Cash and cash equivalents	$	6,398	$	9,164
Restricted cash	24,640		16,023
Accounts receivable, net	149,500		212,257
Inventories	114,956		114,539
Regulatory assets	42,024		29,626
Prepaid expenses and other	26,527		25,397
Total current assets	364,045		407,006
Property, plant, and equipment, net	6,193,234		6,039,801
Goodwill	357,586		357,586
Regulatory assets	748,857		743,945
Other noncurrent assets	50,097		52,314
Total Assets	$	7,713,819	$	7,600,652
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of finance leases	$	3,462	$	3,338
Current portion of long-term debt	224,926		99,950
Short-term borrowings	100,000		—
Accounts payable	91,258		124,340
Accrued expenses and other	244,000		246,167
Regulatory liabilities	36,164		61,103
Total current liabilities	699,810		534,898
Long-term finance leases	3,730		5,461
Long-term debt	2,569,553		2,684,635
Deferred income taxes	629,311		600,520
Noncurrent regulatory liabilities	658,857		657,452
Other noncurrent liabilities	345,301		332,372
Total Liabilities	4,906,562		4,815,338
Commitments and Contingencies (Note 10)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 64,803,261 and 61,299,477 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	648		648
Treasury stock at cost	(97,776)		(97,926)
Paid-in capital	2,082,857		2,078,753
Retained earnings	828,960		811,495
Accumulated other comprehensive loss	(7,432)		(7,656)
Total Shareholders' Equity	2,807,257		2,785,314
Total Liabilities and Shareholders' Equity	$	7,713,819	$	7,600,652

See Notes to Condensed Consolidated Financial Statements

7

NORTHWESTERN ENERGY GROUP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Six Months Ended June 30,
	2024		2023
OPERATING ACTIVITIES:
Net income	$	96,740	$	81,654
Items not affecting cash:
Depreciation and depletion	113,676		105,628
Amortization of debt issuance costs, discount and deferred hedge gain	2,337		2,636
Stock-based compensation costs	3,797		4,868
Equity portion of allowance for funds used during construction	(9,397)		(7,812)
Loss (gain) on disposition of assets	21		(20)
Impairment of alternative energy storage investment	4,659		—
Deferred income taxes	12,953		(10,005)
Changes in current assets and liabilities:
Accounts receivable	62,757		97,779
Inventories	(417)		(218)
Other current assets	(1,130)		2,474
Accounts payable	(20,693)		(63,127)
Accrued expenses and other	(2,157)		(3,029)
Regulatory assets	(12,398)		83,139
Regulatory liabilities	(24,939)		7,299
Other noncurrent assets and liabilities	(1,866)		(7,201)
Cash Provided by Operating Activities	223,943		294,065
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(247,361)		(263,362)
Investment in equity securities	(917)		(2,426)
Cash Used in Investing Activities	(248,278)		(265,788)
FINANCING ACTIVITIES:
Proceeds from issuance of common stock, net	—		10,802
Dividends on common stock	(79,275)		(76,085)
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	(105,000)		(259,000)
Other financing activities, net	(539)		(2,437)
Cash Provided by (Used in) Financing Activities	30,186		(26,720)
Increase in Cash, Cash Equivalents, and Restricted Cash	5,851		1,557
Cash, Cash Equivalents, and Restricted Cash, beginning of period	25,187		22,463
Cash, Cash Equivalents, and Restricted Cash, end of period	$	31,038	$	24,020
Supplemental Cash Flow Information:
Cash (received) paid during the period for:
Income taxes	$	(4,669)	$	3,204
Interest	59,995		51,047
Significant non-cash transactions:
Capital expenditures included in accounts payable	27,144		20,938
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 June 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 March 31, 2023	63,326	3,533	$	633	$	(98,471)	$	2,002,839	$	795,903	$	(7,904)	$	2,693,000
Net income	—	—	—		—		—		19,124		—		19,124
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
Postretirement medical liability adjustment, net of tax	—	—	—		—		—		—		(167)		(167)
Stock-based compensation	3	—	—		—		1,378		—		—		1,378
Issuance of shares	189	(6)	2		169		11,150		—		—		11,321
Dividends on common stock ($0.640 per share)	—	—	—		—		—		(38,044)		—		(38,044)
Balance at June 30, 2023	63,518	3,527	$	635	$	(98,302)	$	2,015,367	$	776,983	$	(7,959)	$	2,686,724
Balance at March 31, 2024	64,798	3,515	$	648	$	(97,990)	$	2,080,953	$	836,951	$	(7,544)	$	2,813,018
Net income	—	—	—		—		—		31,654		—		31,654
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	5	—	—		—		1,732		—		—		1,732
Issuance of shares	—	(11)	—		214		172		—		—		386
Dividends on common stock ( $0.650 per share)	—	—	—		—		—		(39,645)		—		(39,645)
Balance at June 30, 2024	64,803	3,504	$	648	$	(97,776)	$	2,082,857	$	828,960	$	(7,432)	$	2,807,257

9

	Six Months Ended June 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	—	—	—		—		—		81,654		—		81,654
Foreign currency translation adjustment, net of tax	—	—	—		—		—		—		(3)		(3)
Reclassification of net losses on derivative instruments from OCI to net income, net of tax	—	—	—		—		—		—		226		226
Postretirement medical liability adjustment, net of tax	—	—	—		—		—		—		(334)		(334)
Stock-based compensation	51	—	—		—		4,672		—		—		4,672
Issuance of shares	189	(7)	2		90		11,319		—		—		11,411
Dividends on common stock ($1.280 per share)	—	—	—		—		—		(76,085)		—		(76,085)
Balance at June 30, 2023	63,518	3,527	$	635	$	(98,302)	$	2,015,367	$	776,983	$	(7,959)	$	2,686,724
Balance at December 31, 2023	64,762	3,513	$	648	$	(97,926)	$	2,078,753	$	811,495	$	(7,656)	$	2,785,314
Net income	—	—	—		—		—		96,740		—		96,740
Foreign currency translation adjustment, net of tax	—	—	—		—		—		—		(2)		(2)
Reclassification of net losses on derivative instruments from OCI to net income, net of tax	—	—	—		—		—		—		226		226
Postretirement medical liability adjustment, net of tax	—	—	—		—		—		—		—		—
Stock-based compensation	41	—	—		(272)		3,771		—		—		3,499
Issuance of shares	—	(9)	—		422		333		—		—		755
Dividends on common stock ($1.300 per share)	—	—	—		—		—		(79,275)		—		(79,275)
Balance at June 30, 2024	64,803	3,504	$	648	$	(97,776)	$	2,082,857	$	828,960	$	(7,432)	$	2,807,257

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 June 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):

	June 30,		December 31,		June 30,		December 31,
	2024		2023		2023		2022
Cash and cash equivalents	$	6,398	$	9,164	$	7,757	$	8,489
Restricted cash	24,640		16,023		16,263		13,974
Total cash, cash equivalents, and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	31,038	$	25,187	$	24,020	$	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

On July 10, 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 is expected to be in service during the third quarter of 2024. We requested interim base rates to be effective October 1, 2024.

South Dakota Natural Gas Rate Review

On June 21, 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

On June 6, 2024, we filed a natural gas rate review (2023 test year) with the Nebraska Public Service Commission. 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 base rates are not anticipated to be implemented prior to October 1, 2024.

(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):

	Three Months Ended June 30,
	2024				2023
Income before income taxes	$	35,897			$	21,271
Income tax calculated at federal statutory rate	7,539		21.0	%	4,467		21.0	%
Permanent or flow-through adjustments:
State income tax, net of federal provisions	49		0.1		273		1.3
Flow-through repairs deductions	(3,069)		(8.5)		(1,708)		(8.0)
Production tax credits	(2,004)		(5.6)		(1,147)		(5.4)
Amortization of excess deferred income tax	(196)		(0.5)		(233)		(1.1)
Plant and depreciation flow-through items	1,060		3.0		201		0.9
Other, net	864		2.3		294		1.4
	(3,296)		(9.2)		(2,320)		(10.9)
Income tax expense	$	4,243	11.8	%	$	2,147	10.1	%

12

	Six Months Ended June 30,
	2024				2023
Income before income taxes	$	111,317			$	94,042
Income tax calculated at federal statutory rate	23,377		21.0	%	19,749		21.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	688		0.6		1,232		1.3
Flow-through repairs deductions	(9,243)		(8.3)		(7,553)		(8.0)
Production tax credits	(4,987)		(4.5)		(4,346)		(4.6)
Amortization of excess deferred income tax	(556)		(0.5)		(1,032)		(1.1)
Reduction to previously claimed alternative minimum tax credit	—		—		3,186		3.4
Plant and depreciation flow through items	4,139		3.7		889		0.9
Share-based compensation	298		0.3		388		0.4
Other, net	861		0.8		(125)		(0.1)
	(8,800)		(7.9)		(7,361)		(7.8)
Income tax expense	$	14,577	13.1	%	$	12,388	13.2	%

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 $27.3 million as of June 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 June 30, 2024, we have accrued $6.0 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
	June 30, 2024						June 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)	$	(1)	$	—	$	(1)
Reclassification of net income on derivative instruments	153		(40)		113		153		(40)		113
Defined benefit pension plan and postretirement medical liability adjustment	—		—		—		(212)		45		(167)
Other comprehensive income (loss)	$	152	$	(40)	$	112	$	(60)	$	5	$	(55)

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	Six Months Ended
	June 30, 2024						June 30, 2023
	Before-Tax Amount		Tax Expense		Net-of-Tax Amount		Before-Tax Amount		Tax Expense		Net-of-Tax Amount
Foreign currency translation adjustment	$	(2)	$	—	$	(2)	$	(3)	$	—	$	(3)
Reclassification of net income on derivative instruments	306		(80)		226		306		(80)		226
Defined benefit pension plan and postretirement medical liability adjustment	—		—		—		(424)		90		(334)
Other comprehensive income (loss)	$	304	$	(80)	$	224	$	(121)	$	10	$	(111)

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

	June 30, 2024		December 31, 2023
Foreign currency translation	$	1,435	$	1,437
Derivative instruments designated as cash flow hedges	(9,147)		(9,373)
Defined benefit pension plan	280		280
Accumulated other comprehensive loss	$	(7,432)	$	(7,656)

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

		Three Months Ended
		June 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		$	(9,260)	$	280	$	1,436	$	(7,544)
Other comprehensive loss before reclassifications		—		—		(1)		(1)
Amounts reclassified from AOCL	Interest Expense	113		—		—		113
Net current-period other comprehensive income (loss)		113		—		(1)		112
Ending balance		$	(9,147)	$	280	$	1,435	$	(7,432)

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		Three Months Ended
		June 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		$	(9,712)	$	375	$	1,433	$	(7,904)
Other comprehensive loss before reclassifications		—		—		(1)		(1)
Amounts reclassified from AOCL	Interest Expense	113		—		—		113
Amounts reclassified from AOCL		—		(167)		—		(167)
Net current-period other comprehensive income (loss)		113		(167)		(1)		(55)
Ending balance		$	(9,599)	$	208	$	1,432	$	(7,959)

		Six Months Ended
		June 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		—		—		(2)		(2)
Amounts reclassified from AOCL	Interest Expense	226		—		—		226
Net current-period other comprehensive income (loss)		226		—		(2)		224
Ending balance		$	(9,147)	$	280	$	1,435	$	(7,432)

		Six Months Ended
		June 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		—		—		(3)		(3)
Amounts reclassified from AOCL	Interest Expense	226		—		—		226
Amounts reclassified from AOCL		—		(334)		—		(334)
Net current-period other comprehensive income (loss)		226		(334)		(3)		(111)
Ending balance		$	(9,599)	$	208	$	1,432	$	(7,959)

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(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):

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Three Months Ended
June 30, 2024	Electric		Gas		Other		Eliminations		Total
Operating revenues	$	260,134	$	59,795	$	—	$	—	$	319,929
Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	60,887		15,593		—		—		76,480
Utility margin	199,247		44,202		—		—		243,449
Operating and maintenance	43,467		13,900		—		—		57,367
Administrative and general	23,294		7,821		166		—		31,281
Property and other taxes	28,006		8,251		(1)		—		36,256
Depreciation and depletion	47,546		9,387		—		—		56,933
Operating income (loss)	56,934		4,843		(165)		—		61,612
Interest expense, net	(23,298)		(7,147)		(1,430)		—		(31,875)
Other income, net	4,031		927		1,202		—		6,160
Income tax (expense) benefit	(3,891)		304		(656)		—		(4,243)
Net income (loss)	$	33,776	$	(1,073)	$	(1,049)	$	—	$	31,654
Total assets	$	6,172,704	$	1,525,851	$	15,264	$	—	$	7,713,819
Capital expenditures	$	112,258	$	26,349	$	—	$	—	$	138,607

Three Months Ended
June 30, 2023	Electric		Gas		Other		Eliminations		Total
Operating revenues	$	229,266	$	61,236	$	—	$	—	$	290,502
Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	42,363		25,215		—		—		67,578
Utility margin	186,903		36,021		—		—		222,924
Operating and maintenance	41,368		13,472		—		—		54,840
Administrative and general	21,635		8,321		(1)		—		29,955
Property and other taxes	31,022		9,104		3		—		40,129
Depreciation and depletion	43,319		9,061		—		—		52,380
Operating income (loss)	49,559		(3,937)		(2)		—		45,620
Interest expense, net	(21,724)		(4,490)		(2,197)		—		(28,411)
Other income (expense), net	2,954		1,144		(36)		—		4,062
Income tax (expense) benefit	(3,515)		(373)		1,741		—		(2,147)
Net income (loss)	$	27,274	$	(7,656)	$	(494)	$	—	$	19,124
Total assets	$	5,878,433	$	1,406,068	$	9,741	$	—	$	7,294,242
Capital expenditures	$	94,690	$	32,068	$	—	$	—	$	126,758

17

Six Months Ended
June 30, 2024	Electric		Gas		Other		Eliminations		Total
Operating revenues	$	603,320	$	191,951	$	—	$	—	$	795,271
Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	176,228		74,973		—		—		251,201
Utility margin	427,092		116,978		—		—		544,070
Operating and maintenance	83,766		27,783		—		—		111,549
Administrative and general	51,213		17,867		2,646		—		71,726
Property and other taxes	64,306		19,120		1		—		83,427
Depreciation and depletion	94,850		18,826		—		—		113,676
Operating income (loss)	132,957		33,382		(2,647)		—		163,692
Interest expense, net	(47,955)		(13,396)		(1,503)		—		(62,854)
Other income (expense), net	9,492		1,981		(994)		—		10,479
Income tax expense	(11,174)		(2,869)		(534)		—		(14,577)
Net income (loss)	$	83,320	$	19,098	$	(5,678)	$	—	$	96,740
Total assets	$	6,172,704	$	1,525,851	$	15,264	$	—	$	7,713,819
Capital expenditures	$	202,848	$	44,513	$	—	$	—	$	247,361

Six Months Ended
June 30, 2023	Electric		Gas		Other		Eliminations		Total
Operating revenues	$	524,574	$	220,470	$	—	$	—	$	745,044
Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	120,497		112,573		—		—		233,070
Utility margin	404,077		107,897		—		—		511,974
Operating and maintenance	83,781		26,920		—		—		110,701
Administrative and general	46,603		18,087		13		—		64,703
Property and other taxes	69,273		20,002		5		—		89,280
Depreciation and depletion	87,217		18,411		—		—		105,628
Operating income (loss)	117,203		24,477		(18)		—		141,662
Interest expense, net	(40,284)		(7,741)		(8,394)		—		(56,419)
Other income (expense), net	6,320		2,559		(80)		—		8,799
Income tax expense	(10,143)		(139)		(2,106)		—		(12,388)
Net income (loss)	$	73,096	$	19,156	$	(10,598)	$	—	$	81,654
Total assets	$	5,878,433	$	1,406,068	$	9,741	$	—	$	7,294,242
Capital expenditures	$	215,509	$	47,853	$	—	$	—	$	263,362

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(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
	June 30, 2024						June 30, 2023
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Montana	$	86.0	$	18.9	$	104.9	$	83.8	$	17.6	$	101.4
South Dakota	15.4		5.9		21.3		15.7		8.4		24.1
Nebraska	—		3.8		3.8		—		7.4		7.4
Residential	101.4		28.6		130.0		99.5		33.4		132.9
Montana	99.7		10.7		110.4		101.9		9.9		111.8
South Dakota	26.3		3.7		30.0		25.1		5.5		30.6
Nebraska	—		2.0		2.0		—		4.7		4.7
Commercial	126.0		16.4		142.4		127.0		20.1		147.1
Industrial	11.3		0.2		11.5		10.8		0.2		11.0
Lighting, governmental, irrigation, and interdepartmental	8.6		0.3		8.9		8.7		0.3		9.0
Total Customer Revenues	247.3		45.5		292.8		246.0		54.0		300.0
Other tariff and contract based revenues	24.2		10.6		34.8		20.0		10.6		30.6
Total Revenue from Contracts with Customers	271.5		56.1		327.6		266.0		64.6		330.6
Regulatory amortization and other	(11.4)		3.7		(7.7)		(36.7)		(3.4)		(40.1)
Total Revenues	$	260.1	$	59.8	$	319.9	$	229.3	$	61.2	$	290.5

19

	Six Months Ended
	June 30, 2024						June 30, 2023
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Montana	$	203.4	$	67.5	$	270.9	$	209.3	$	84.5	$	293.8
South Dakota	34.7		19.5		54.2		35.5		28.3		63.8
Nebraska	—		14.3		14.3		—		28.0		28.0
Residential	238.1		101.3		339.4		244.8		140.8		385.6
Montana	201.2		35.8		237.0		214.5		46.3		260.8
South Dakota	54.1		13.0		67.1		50.3		19.8		70.1
Nebraska	—		8.2		8.2		—		17.8		17.8
Commercial	255.3		57.0		312.3		264.8		83.9		348.7
Industrial	23.0		0.6		23.6		22.6		0.9		23.5
Lighting, governmental, irrigation, and interdepartmental	13.3		0.9		14.2		13.9		1.0		14.9
Total Customer Revenues	529.7		159.8		689.5		546.1		226.6		772.7
Other tariff and contract based revenues	49.3		21.6		70.9		41.3		22.9		64.2
Total Revenue from Contracts with Customers	579.0		181.4		760.4		587.4		249.5		836.9
Regulatory amortization and other	24.3		10.6		34.9		(62.8)		(29.1)		(91.9)
Total Revenues	$	603.3	$	192.0	$	795.3	$	524.6	$	220.4	$	745.0

(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
	June 30, 2024	June 30, 2023
Basic computation	61,288,870	59,804,283
Dilutive effect of:
Performance share awards(1)	68,478	45,391
Diluted computation	61,357,348	59,849,674

	Six Months Ended
	June 30, 2024	June 30, 2023
Basic computation	61,277,418	59,790,316
Dilutive effect of:
Performance share awards(1)	56,065	29,200
Diluted computation	61,333,483	59,819,516

(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 June 30, 2024, there were 35,933 shares from performance and restricted share awards which were antidilutive and excluded from the earnings per share calculations, compared to 21,890 shares as of June 30, 2023.

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(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 June 30,				Three Months Ended June 30,
	2024		2023		2024		2023
Components of Net Periodic Benefit Cost (Credit)
Service cost	$	1,378	$	1,422	$	74	$	79
Interest cost	5,739		6,482		132		161
Expected return on plan assets	(6,335)		(6,671)		(321)		(273)
Amortization of prior service credit	—		—		—		29
Recognized actuarial loss (gain)	6		(3)		(25)		5
Net periodic benefit cost (credit)	$	788	$	1,230	$	(140)	$	1

	Pension Benefits				Other Postretirement Benefits
	Six Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
Components of Net Periodic Benefit Cost (Credit)
Service cost	$	2,796	$	2,916	$	154	$	166
Interest cost	11,472		13,047		279		337
Expected return on plan assets	(12,663)		(13,357)		(640)		(548)
Amortization of prior service credit	—		—		—		58
Recognized actuarial loss (gain)	17		137		(37)		36
Net periodic benefit cost (credit)	$	1,622	$	2,743	$	(244)	$	49

We contributed $3.2 million to our pension plans during the six months ended June 30, 2024. We expect to contribute an additional $8.0 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 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. We have further requested the court stay the implementation of the Rules pending review on the merits, but that judicial relief is discretionary. Briefing is underway for the requests to stay the MATS Rules. On July 19, 2024, the D.C. Circuit denied all consolidated motions to stay the GHG Rules, concluding the petitioners

21

had not shown likelihood of success on the merits and irreparable harm from the GHG Rules' imposition. However, the court ordered the litigation parties to submit a proposed briefing schedule to ensure the case is argued and the GHG Rule is reviewed on the merits as soon as possible. If the MATS Rules and GHG Rules are implemented, it would result in additional material compliance costs. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from the MATS or 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 Montana Public Service Commission (MPSC) would approve any such recovery.

Colstrip Arbitration

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

As a result of the mandate, the owners have disagreed on various operational funding decisions, including whether closure requires each owner’s consent under the O&O Agreement. On March 12, 2021, we initiated an arbitration under the O&O Agreement (the “Arbitration”), to resolve the issues of whether closure requires each owner's consent and to clarify each owner's obligations to continue to fund operations until all joint owners agree on closure. The owners previously agreed to stay the Arbitration in an effort to work out a global resolution to the dispute, but that stay has now expired. The parties were not able to agree to continue the stay, and are presently in the process of retaining an arbitrator and are proceeding with the Arbitration.

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Colstrip Coal Dust Litigation

On December 14, 2020, a claim was filed against Talen in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. Talen is one of the co-owners of Colstrip Unit 3, and the operator of Units 3 and 4. The plaintiffs allege they have suffered adverse effects from coal dust generated during operations associated with Colstrip. On August 26, 2021, the claim was amended to add in excess of 100 plaintiffs; 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. Since this lawsuit remains in its discovery stages, we are unable to predict outcomes. We continue to evaluate a range of reasonably possible losses.

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 expect the plant to be in service during the third quarter of 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.

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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 six months ended June 30, 2024 and 2023.

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HOW WE PERFORMED AGAINST OUR SECOND QUARTER 2023 RESULTS

	Three Months Ended June 30, 2024 vs. 2023
		Income Before Income Taxes		Income Tax Expense(3)		Net Income
				(in millions)
Second Quarter, 2023		$	21.3	$	(2.2)	$	19.1
Variance in revenue and fuel, purchased supply, and direct transmission expense(1) items impacting net income:
Base rates		16.4		(4.2)		12.2
Electric transmission revenue		4.1		(1.0)		3.1
Montana property tax tracker collections		2.5		(0.6)		1.9
Natural gas retail volumes		1.1		(0.3)		0.8
Montana natural gas transportation		0.8		(0.2)		0.6
Electric retail volumes		0.6		(0.2)		0.4
QF liability adjustment		(4.2)		1.1		(3.1)
Non-recoverable Montana electric supply costs		(0.9)		0.2		(0.7)
Production tax credits, offset within income tax benefit		(0.8)		0.8		—
Other		3.7		(0.9)		2.8
Variance in expense items(2) impacting net income:
Depreciation		(4.5)		1.1		(3.4)
Interest expense		(3.5)		0.9		(2.6)
Operating, maintenance, and administrative		(2.3)		0.6		(1.7)
Other		1.6		0.7		2.3
Second Quarter, 2024		$	35.9	$	(4.2)	$	31.7
Change in Net Income						$	12.6

(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 June 30, 2024 was $31.7 million as compared with $19.1 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, and electric and natural gas retail volumes. These were offset in part by a less favorable QF liability adjustment in the current year, non-recoverable Montana electric supply costs, 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 continues to progress and we expect the plant to be in service during the third quarter of 2024. The lawsuit challenging the Yellowstone County Generating Station (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 June 30, 2024, total costs of approximately $288.9 million have been incurred, with expected total costs of approximately $310.0 million to $320.0 million. See Note 10 - Commitments and

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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 - On July 10, 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 is expected to be in service during the third quarter of 2024. We requested interim base rates to be effective October 1, 2024.

South Dakota Natural Gas Rate Review - On June 21, 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 - On June 6, 2024, we filed a natural gas rate review with the Nebraska Public Service Commission. 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 base rates are not anticipated to be implemented prior to October 1, 2024.

EPA Rules

On April 25, 2024, the EPA released final rules related to 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. 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, including approval from the FERC.

Acquisition of Puget’s 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), will 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

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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.

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

Consolidated net income for the three months ended June 30, 2024 was $31.7 million as compared with $19.1 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, and electric and natural gas retail volumes. These were offset in part by a less favorable QF liability adjustment in the current year, non-recoverable Montana electric supply costs, depreciation, operating, administrative and general costs, and interest expense.

Consolidated gross margin for the three months ended June 30, 2024 was $92.8 million as compared with $75.5 million in 2023, an increase of $17.3 million, or 22.9 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 and natural gas retail volumes. These were offset in part by a less favorable QF liability adjustment in the current year, non-recoverable Montana electric supply costs, depreciation, and operating and maintenance costs.

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	Electric				Natural Gas				Total
	2024		2023		2024		2023		2024		2023
	(in millions)
Reconciliation of gross margin to utility margin:
Operating Revenues	$	260.1	$	229.3	$	59.8	$	61.2	$	319.9	$	290.5
Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	60.9		42.4		15.6		25.2		76.5		67.6
Less: Operating and maintenance	43.5		41.4		13.9		13.5		57.4		54.9
Less: Property and other taxes	28.0		31.0		8.2		9.1		36.2		40.1
Less: Depreciation and depletion	47.6		43.3		9.4		9.1		57.0		52.4
Gross Margin	80.1		71.2		12.7		4.3		92.8		75.5
Operating and maintenance	43.5		41.4		13.9		13.5		57.4		54.9
Property and other taxes	28.0		31.0		8.2		9.1		36.2		40.1
Depreciation and depletion	47.6		43.3		9.4		9.1		57.0		52.4
Utility Margin(1)	$	199.2	$	186.9	$	44.2	$	36.0	$	243.4	$	222.9

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

	Three Months Ended June 30,
	2024		2023		Change		% Change
	(dollars in millions)
Utility Margin
Electric	$	199.2	$	186.9	$	12.3	6.6	%
Natural Gas	44.2		36.0		8.2		22.8
Total Utility Margin(1)	$	243.4	$	222.9	$	20.5	9.2	%

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

Consolidated utility margin for the three months ended June 30, 2024 was $243.4 million as compared with $222.9 million for the same period in 2023, an increase of $20.5 million, or 9.2 percent. Primary components of the change in utility margin include the following (in millions):

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	Utility Margin 2024 vs. 2023
Utility Margin Items Impacting Net Income
Base rates	$	16.4
Transmission revenue due to market conditions	4.1
Montana property tax tracker collections	2.5
Natural gas retail volumes	1.1
Montana natural gas transportation	0.8
Electric retail volumes	0.6
QF liability adjustment	(4.2)
Non-recoverable Montana electric supply costs	(0.9)
Other	3.7
Change in Utility Margin Items Impacting Net Income	24.1
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property and other taxes	(3.8)
Production tax credits, offset in income tax expense	(0.8)
Operating expenses recovered in revenue, offset in operating and maintenance expense	1.0
Change in Utility Margin Items Offset Within Net Income	(3.6)
Increase in Consolidated Utility Margin(1)	$	20.5

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

The less favorable adjustment to our electric QF liability (unrecoverable costs associated with contracts covered by the Public Utility Regulatory Policies Act of 1978 (PURPA) 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, due to a favorable adjustment in the prior year, decreasing the QF liability by $4.2 million, reflecting annual actual contract price escalation for the 2023-2024 contract year, which was less than previously estimated. The 2023-2024 contract year was the last year of the contract that contains variable pricing terms.

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 June 30, 2024, we over-collected supply costs of $11.0 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $1.2 million (10 percent of the PCCAM Base cost variance). For the three months ended June 30, 2023, we over-collected supply costs of $18.9 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $2.1 million.

	Three Months Ended June 30,
	2024		2023		Change		% Change
	(dollars in millions)
Operating Expenses (excluding fuel, purchased supply and direct transmission expense)
Operating and maintenance	$	57.4	$	54.8	$	2.6	4.7	%
Administrative and general	31.3		30.0		1.3		4.3
Property and other taxes	36.3		40.1		(3.8)		(9.5)
Depreciation and depletion	56.9		52.4		4.5		8.6
Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense)	$	181.9	$	177.3	$	4.6	2.6	%

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Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $181.9 million for the three months ended June 30, 2024, as compared with $177.3 million for the three months ended June 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	$	4.5
Electric generation maintenance	2.0
Labor and benefits(1)	1.8
Insurance expense	0.5
Technology implementation and maintenance expenses	0.4
Uncollectible accounts	(0.5)
Other	(1.9)
Change in Items Impacting Net Income	6.8
Operating Expenses Offset Within Net Income
Property and other taxes recovered in trackers, offset in revenue	(3.8)
Pension and other postretirement benefits, offset in other income(1)	0.7
Operating and maintenance expenses recovered in trackers, offset in revenue	1.0
Deferred compensation, offset in other income	(0.1)
Change in Items Offset Within Net Income	(2.2)
Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense)	$	4.6

(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 June 30, 2024 was $61.6 million as compared with $45.6 million in the same period of 2023. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, Montana property tax tracker collections, and electric and natural gas retail volumes. These were offset in part by a less favorable QF liability adjustment in the current year, non-recoverable Montana electric supply costs, depreciation, and operating, administrative and general costs.

Consolidated interest expense was $31.9 million for the three months ended June 30, 2024 as compared with $28.4 million for the same period of 2023. This increase was due to higher borrowings and interest rates, partly offset by lower interest on our revolving credit facilities and higher capitalization of Allowance for Funds Used During Construction (AFUDC).

Consolidated other income was $6.2 million for the three months ended June 30, 2024 as compared with $4.1 million for the same period of 2023. This increase was primarily due to higher capitalization of AFUDC and a decrease in the non-service component of pension expense.

Consolidated income tax expense was $4.2 million for the three months ended June 30, 2024 as compared to $2.1 million for the same period of 2023. Our effective tax rate for the three months ended June 30, 2024 was 11.8% as compared with 10.1% for the same period in 2023.

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

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	Three Months Ended June 30,
	2024				2023
Income Before Income Taxes	$	35.9			$	21.3
Income tax calculated at federal statutory rate	7.5		21.0	%	4.5		21.0	%
Permanent or flow-through adjustments:
State income tax, net of federal provisions	0.0		0.1		0.3		1.3
Flow-through repairs deductions	(3.0)		(8.5)		(1.7)		(8.0)
Production tax credits	(2.0)		(5.6)		(1.1)		(5.4)
Amortization of excess deferred income tax	(0.2)		(0.5)		(0.2)		(1.1)
Plant and depreciation flow-through items	1.1		3.0		0.2		0.9
Other, net	0.8		2.3		0.1		1.4
	(3.3)		(9.2)		(2.4)		(10.9)
Income tax expense	$	4.2	11.8	%	$	2.1	10.1	%

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.

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Six Months Ended June 30, 2024 Compared with the Six Months Ended June 30, 2023

Consolidated net income for the six months ended June 30, 2024 was $96.7 million as compared with $81.7 million for the same period in 2023. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, and Montana property tax tracker collections. These were offset in part by non-recoverable Montana electric supply costs, a less favorable QF liability adjustment in the current year, electric and natural gas retail volumes, depreciation, operating, administrative and general costs, and interest expense.

Consolidated gross margin for the six months ended June 30, 2024 was $235.4 million as compared with $206.4 million in 2023, an increase of $29.0 million, or 14.1 percent. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, and Montana property tax tracker collections. These were offset in part by non-recoverable Montana electric supply costs, a less favorable QF liability adjustment in the current year, electric and 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	$	603.3	$	524.6	$	192.0	$	220.5	$	795.3	$	745.1
Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	176.2		120.5		75.0		112.6		251.2		233.1
Less: Operating and maintenance	83.8		83.8		27.8		26.9		111.6		110.7
Less: Property and other taxes	64.3		69.3		19.1		20.0		83.4		89.3
Less: Depreciation and depletion	94.9		87.2		18.8		18.4		113.7		105.6
Gross Margin	184.1		163.8		51.3		42.6		235.4		206.4
Operating and maintenance	83.8		83.8		27.8		26.9		111.6		110.7
Property and other taxes	64.3		69.3		19.1		20.0		83.4		89.3
Depreciation and depletion	94.9		87.2		18.8		18.4		113.7		105.6
Utility Margin(1)	$	427.1	$	404.1	$	117.0	$	107.9	$	544.1	$	512.0

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

	Six Months Ended June 30,
	2024		2023		Change		% Change
	(dollars in millions)
Utility Margin
Electric	$	427.1	$	404.1	$	23.0	5.7	%
Natural Gas	117.0		107.9		9.1		8.4
Total Utility Margin(1)	$	544.1	$	512.0	$	32.1	6.3	%

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

Consolidated utility margin for the six months ended June 30, 2024 was $544.1 million as compared with $512.0 million for the same period in 2023, an increase of $32.1 million, or 6.3 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	$	36.2
Transmission revenue due to market conditions	7.6
Montana property tax tracker collections	3.4
Montana natural gas transportation	1.0
Non-recoverable Montana electric supply costs	(4.4)
QF liability adjustment	(4.2)
Electric retail volumes	(2.6)
Natural gas retail volumes	(2.4)
Other	3.6
Change in Utility Margin Items Impacting Net Income	38.2
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property and other taxes	(6.2)
Production tax credits, offset in income tax expense	(1.3)
Operating expenses recovered in revenue, offset in operating and maintenance expense	1.4
Change in Utility Margin Items Offset Within Net Income	(6.1)
Increase in Consolidated Utility Margin(1)	$	32.1

(1) 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 six months ended June 30, 2024, we under-collected supply costs of $16.1 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $1.8 million (10 percent of the PCCAM Base cost variance). For the six months ended June 30, 2023, we over-collected supply costs of $23.4 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 unfavorable as lower residential usage, due to unfavorable weather, and lower commercial demand, was partly offset by higher industrial demand and customer growth. 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.

	Six Months Ended June 30,
	2024		2023		Change		% Change
	(dollars in millions)
Operating Expenses (excluding fuel, purchased supply and direct transmission expense)
Operating and maintenance	$	111.5	$	110.7	$	0.8	0.7	%
Administrative and general	71.7		64.7		7.0		10.8
Property and other taxes	83.4		89.3		(5.9)		(6.6)
Depreciation and depletion	113.7		105.6		8.1		7.7
Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense)	$	380.3	$	370.3	$	10.0	2.7	%

34

Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $380.3 million for the six months ended June 30, 2024, as compared with $370.3 million for the six months ended June 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	$	8.1
Labor and benefits(1)	3.4
Litigation outcome (Pacific Northwest Solar)	2.4
Non-cash impairment of alternative energy storage investment	2.2
Insurance expense	1.0
Technology implementation and maintenance expenses	0.6
Property and other taxes not recoverable within trackers	0.3
Uncollectible accounts	(1.0)
Electric generation maintenance	(0.6)
Other	(1.5)
Change in Items Impacting Net Income	14.9
Operating Expenses Offset Within Net Income
Property and other taxes recovered in trackers, offset in revenue	(6.2)
Pension and other postretirement benefits, offset in other income(1)	(0.2)
Operating and maintenance expenses recovered in trackers, offset in revenue	1.4
Deferred compensation, offset in other income	0.1
Change in Items Offset Within Net Income	(4.9)
Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense)	$	10.0

(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 six months ended June 30, 2024 was $163.7 million as compared with $141.7 million in the same period of 2023. This increase was primarily due to new base rates in Montana and South Dakota, electric transmission revenues, and Montana property tax tracker collections. These were offset in part by non-recoverable Montana electric supply costs, a less favorable QF liability adjustment in the current year, electric and natural gas retail volumes, depreciation, and operating, administrative and general costs.

Consolidated interest expense was $62.9 million for the six months ended June 30, 2024 as compared with $56.4 million for the same period of 2023. This increase was due to higher borrowings and interest rates partly offset by lower interest on our revolving credit facilities and higher capitalization of AFUDC.

Consolidated other income was $10.5 million for the six months ended June 30, 2024 as compared to $8.8 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 and higher capitalization of AFUDC, partly offset by a $2.5 million non-cash impairment of an alternative energy storage equity investment and an increase in the non-service component of pension expense.

Consolidated income tax expense for the six months ended June 30, 2024 was $14.6 million as compared to $12.4 million in the same period of 2023. Our effective tax rate for the six months ended June 30, 2024 was 13.1% as compared with 13.2% for the same period in 2023. Income tax expense for the six months ended June 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):

35

	Six Months Ended June 30,
	2024				2023
Income Before Income Taxes	$	111.3			$	94.0
Income tax calculated at federal statutory rate	23.4		21.0	%	19.7		21.0	%
Permanent or flow-through adjustments:
State income tax, net of federal provisions	0.7		0.6		1.2		1.3
Flow-through repairs deductions	(9.2)		(8.3)		(7.6)		(8.0)
Production tax credits	(5.0)		(4.5)		(4.3)		(4.6)
Amortization of excess deferred income tax	(0.6)		(0.5)		(1.0)		(1.1)
Reduction to previously claimed alternative minimum tax credit	—		—		3.2		3.4
Plant and depreciation flow-through items	4.1		3.7		0.9		0.9
Share-based compensation	0.3		0.3		0.4		0.4
Other, net	0.9		0.8		(0.1)		(0.1)
	(8.8)		(7.9)		(7.3)		(7.8)
Income tax expense	$	14.6	13.1	%	$	12.4	13.2	%

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

	Revenues				Change				Megawatt Hours (MWH)		Avg. Customer Counts
	2024		2023		$		%		2024	2023	2024	2023
	(in thousands)
Montana	$	86,028	$	83,840	$	2,188	2.6	%	582	568	327,655	321,820
South Dakota	15,392		15,686		(294)		(1.9)		117	135	51,340	51,162
Residential	101,420		99,526		1,894		1.9		699	703	378,995	372,982
Montana	99,655		101,919		(2,264)		(2.2)		756	759	75,602	74,234
South Dakota	26,356		25,134		1,222		4.9		259	266	13,083	12,985
Commercial	126,011		127,053		(1,042)		(0.8)		1,015	1,025	88,685	87,219
Industrial	11,282		10,722		560		5.2		739	644	80	78
Other	8,550		8,732		(182)		(2.1)		36	33	6,460	6,388
Total Retail Electric	$	247,263	$	246,033	$	1,230	0.5	%	2,489	2,405	474,220	466,667
Regulatory amortization	(10,904)		(36,254)		25,350		(69.9)
Transmission	22,436		18,352		4,084		22.3
Wholesale and Other	1,339		1,135		204		18.0
Total Revenues	$	260,134	$	229,266	$	30,868	13.5	%
Fuel, purchased supply and direct transmission expense(1)	60,887		42,363		18,524		43.7
Utility Margin(2)	$	199,247	$	186,903	$	12,344	6.6	%

(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.

	Cooling Degree Days			2024 as compared with:
	2024	2023	Historic Average	2023	Historic Average
Montana	43	44	63	2% cooler	32% cooler
South Dakota	54	201	72	73% cooler	25% cooler
	Heating Degree Days			2024 as compared with:
	2024	2023	Historic Average	2023	Historic Average
Montana(1)	1,154	1,017	1,139	13% colder	1% colder
South Dakota	1,333	1,613	1,466	17% warmer	9% 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 June 30, 2024 and 2023 (in millions):

	Utility Margin 2024 vs. 2023
Utility Margin Items Impacting Net Income
Base rates	$	13.1
Transmission revenue due to market conditions	4.1
Montana property tax tracker collections	0.7
Retail volumes	0.6
QF liability adjustment	(4.2)
Non-recoverable Montana electric supply costs	(0.9)
Other	1.7
Change in Utility Margin Items Impacting Net Income	15.1
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property and other taxes	(3.1)
Production tax credits, offset in income tax expense	(0.8)
Operating expenses recovered in revenue, offset in operating and maintenance expense	1.1
Change in Utility Margin Items Offset Within Net Income	(2.8)
Increase in Utility Margin(1)	$	12.3

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

The less favorable adjustment to our electric QF liability (unrecoverable costs associated with PURPA 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.

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 three months ended June 30, 2024, we over-collected supply costs of $11.0 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $1.2 million (10 percent of the PCCAM Base cost variance). For the three months ended June 30, 2023, we over-collected supply costs of $18.9 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $2.1 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

Six Months Ended June 30, 2024 Compared with the Six Months Ended June 30, 2023

	Revenues				Change				Megawatt Hours (MWH)		Avg. Customer Counts
	2024		2023		$		%		2024	2023	2024	2023
	(in thousands)
Montana	$	203,391	$	209,302	$	(5,911)	(2.8)	%	1,429	1,439	326,986	321,278
South Dakota	34,702		35,457		(755)		(2.1)		290	330	51,396	51,218
Residential	238,093		244,759		(6,666)		(2.7)		1,719	1,769	378,382	372,496
Montana	201,158		214,532		(13,374)		(6.2)		1,580	1,610	75,639	74,249
South Dakota	54,128		50,262		3,866		7.7		546	545	13,047	12,964
Commercial	255,286		264,794		(9,508)		(3.6)		2,126	2,155	88,686	87,213
Industrial	22,951		22,563		388		1.7		1,464	1,270	80	79
Other	13,366		13,986		(620)		(4.4)		49	48	5,689	5,623
Total Retail Electric	$	529,696	$	546,102	$	(16,406)	(3.0)	%	5,358	5,242	472,837	465,411
Regulatory amortization	25,442		(61,551)		86,993		(141.3)
Transmission	44,824		37,245		7,579		20.3
Wholesale and Other	3,358		2,778		580		20.9
Total Revenues	$	603,320	$	524,574	$	78,746	15.0	%
Fuel, purchased supply and direct transmission expense(1)	176,228		120,497		55,731		46.3
Utility Margin(2)	$	427,092	$	404,077	$	23,015	5.7	%

(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)	43	44	63	2% cooler	32% cooler
South Dakota	54	201	72	73% cooler	25% cooler

	Heating Degree Days			2024 as compared with:
	2024	2023	Historic Average	2023	Historic Average
Montana(1)	4,492	4,556	4,437	1% warmer	1% colder
South Dakota	4,808	5,957	5,654	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 six months ended June 30, 2024 and 2023 (in millions):

	Utility Margin 2024 vs. 2023
Utility Margin Items Impacting Net Income
Base rates	$	28.0
Transmission revenue due to market conditions	7.6
Montana property tax tracker collections	2.7
Non-recoverable Montana electric supply costs	(4.4)
QF liability adjustment	(4.2)
Retail volumes	(2.6)
Other	1.4
Change in Utility Margin Items Impacting Net Income	28.5
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property and other taxes	(5.6)
Production tax credits, offset in income tax expense	(1.3)
Operating expenses recovered in revenue, offset in operating and maintenance expense	1.4
Change in Utility Margin Items Offset Within Net Income	(5.5)
Increase in Utility Margin(1)	$	23.0

(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.

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 six months ended June 30, 2024, we under-collected supply costs of $16.1 million resulting in an increase to our under collection of costs, and recorded a decrease in pre-tax earnings of $1.8 million (10 percent of the PCCAM Base cost variance). For the six months ended June 30, 2023, we over-collected supply costs of $23.4 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $2.6 million.

Retail volume impact was unfavorable as lower residential usage, due to unfavorable weather, and lower commercial demand, was partly offset by higher industrial demand and 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.

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

	Revenues				Change				Dekatherms (Dkt)		Avg. Customer Counts
	2024		2023		$		%		2024	2023	2024	2023
	(in thousands)
Montana	$	18,921	$	17,589	$	1,332	7.6	%	2,224	1,864	185,449	183,669
South Dakota	5,894		8,375		(2,481)		(29.6)		568	703	42,440	41,914
Nebraska	3,798		7,457		(3,659)		(49.1)		438	508	37,889	37,711
Residential	28,613		33,421		(4,808)		(14.4)		3,230	3,075	265,778	263,294
Montana	10,743		9,918		825		8.3		1,301	1,147	26,160	25,714
South Dakota	3,754		5,505		(1,751)		(31.8)		600	675	7,354	7,217
Nebraska	1,969		4,665		(2,696)		(57.8)		333	387	5,044	5,004
Commercial	16,466		20,088		(3,622)		(18.0)		2,234	2,209	38,558	37,935
Industrial	169		160		9		5.6		23	19	237	232
Other	292		326		(34)		(10.4)		44	43	196	188
Total Retail Gas	$	45,540	$	53,995	$	(8,455)	(15.7)	%	5,531	5,346	304,769	301,649
Regulatory amortization	3,735		(3,369)		7,104		210.9
Wholesale and other	10,520		10,610		(90)		(0.8)
Total Revenues	$	59,795	$	61,236	$	(1,441)	(2.4)	%
Fuel, purchased supply and direct transmission expense(1)	15,593		25,215		(9,622)		(38.2)
Utility Margin(2)	$	44,202	$	36,021	$	8,181	22.7	%

(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.

	Heating Degree Days			2024 as compared with:
	2024	2023	Historic Average	2023	Historic Average
Montana(1)	1,209	1,037	1,202	17% colder	1% colder
South Dakota	1,333	1,613	1,466	17% warmer	9% warmer
Nebraska	985	1,142	1,119	14% warmer	12% 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 June 30, 2024 and 2023:

	Utility Margin 2024 vs. 2023
	(in millions)
Utility Margin Items Impacting Net Income
Base rates	$	3.3
Montana property tax tracker collections	1.8
Retail volumes	1.1
Montana natural gas transportation	0.8
Other	2.0
Change in Utility Margin Items Impacting Net Income	9.0
Utility Margin Items Offset Within Net Income
Property and other taxes recovered in revenue, offset in property and other taxes	(0.7)
Operating expenses recovered in revenue, offset in operating and maintenance expense	(0.1)
Change in Utility Margin Items Offset Within Net Income	(0.8)
Increase in Utility Margin(1)	$	8.2

(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 retail volumes were driven by favorable weather in Montana and customer growth, partly offset by unfavorable weather in South Dakota and Nebraska.

42

Six Months Ended June 30, 2024 Compared with the Six Months Ended June 30, 2023

	Revenues				Change				Dekatherms (Dkt)		Avg. Customer Counts
	2024		2023		$		%		2024	2023	2024	2023
	(in thousands)
Montana	$	67,511	$	84,471	$	(16,960)	(20.1)	%	8,482	8,381	185,332	183,583
South Dakota	19,499		28,310		(8,811)		(31.1)		2,005	2,455	42,521	42,032
Nebraska	14,315		27,970		(13,655)		(48.8)		1,669	1,915	37,970	37,838
Residential	101,325		140,751		(39,426)		(28.0)		12,156	12,751	265,823	263,453
Montana	35,826		46,257		(10,431)		(22.6)		4,698	4,834	26,121	25,690
South Dakota	13,021		19,791		(6,770)		(34.2)		1,914	2,177	7,362	7,235
Nebraska	8,188		17,828		(9,640)		(54.1)		1,192	1,386	5,063	5,040
Commercial	57,035		83,876		(26,841)		(32.0)		7,804	8,397	38,546	37,965
Industrial	588		889		(301)		(33.9)		83	94	237	232
Other	868		1,122		(254)		(22.6)		133	136	196	188
Total Retail Gas	$	159,816	$	226,638	$	(66,822)	(29.5)	%	20,176	21,378	304,802	301,838
Regulatory amortization	10,661		(28,770)		39,431		(137.1)
Wholesale and other	21,474		22,602		(1,128)		(5.0)
Total Revenues	$	191,951	$	220,470	$	(28,519)	(12.9)	%
Fuel, purchased supply and direct transmission expense(1)	74,973		112,573		(37,600)		(33.4)
Utility Margin(2)	$	116,978	$	107,897	$	9,081	8.4	%

(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)	4,589	4,629	4,535	1% warmer	1% colder
South Dakota	4,808	5,957	5,654	19% warmer	15% warmer
Nebraska	3,978	4,506	4,468	12% warmer	11% warmer

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

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

	Utility Margin 2024 vs. 2023
	(in millions)
Utility Margin Items Impacting Net Income
Base rates	$	8.2
Montana natural gas transportation	1.0
Montana property tax tracker collections	0.7
Retail volumes	(2.4)
Other	2.2
Change in Utility Margin Items Impacting Net Income	9.7
Utility Margin Items Offset Within Net Income
Property taxes recovered in revenue, offset in property tax expense	(0.6)
Change in Utility Margin Items Offset Within Net Income	(0.6)
Increase in Utility Margin(1)	$	9.1

(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.

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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 June 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 June 30, 2024, our total net liquidity was approximately $393.4 million, including $6.4 million of cash and $387.0 million of revolving credit facility availability with no letters of credit outstanding.

Cash Flows

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

	Six Months Ended June 30,
	2024		2023
Operating Activities
Net income	$	96.7	$	81.7
Non-cash adjustments to net income	128.1		95.3
Changes in working capital	1.0		124.3
Other noncurrent assets and liabilities	(1.9)		(7.2)
Cash Provided by Operating Activities	223.9		294.1
Investing Activities
Property, plant and equipment additions	(247.4)		(263.4)
Investment in equity securities	(0.9)		(2.4)
Cash Used in Investing Activities	(248.3)		(265.8)
Financing Activities
Proceeds from issuance of common stock, net	—		10.8
Issuance of long-term debt	215.0		300.0
Issuances of short-term borrowings	100.0		—
Line of credit repayments, net	(105.0)		(259.0)
Repayments on long-term debt	(100.0)		—
Dividends on common stock	(79.3)		(76.1)
Other financing activities, net	(0.5)		(2.5)
Cash Provided by (Used in) Financing Activities	30.2		(26.8)
Increase in Cash, Cash Equivalents, and Restricted Cash	5.8		1.5
Cash, Cash Equivalents, and Restricted Cash, beginning of period	25.2		22.5
Cash, Cash Equivalents, and Restricted Cash, end of period	$	31.0	$	24.0

Operating Activities

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As of June 30, 2024, cash, cash equivalents, and restricted cash were $31.0 million as compared with $25.2 million as of December 31, 2023 and $24.0 million as of June 30, 2023. Cash provided by operating activities totaled $223.9 million for the six months ended June 30, 2024 as compared with $294.1 million during the six months ended June 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 net cash outflows for energy supply costs in the current period, primarily related to a January 2024 cold weather event.

Uncollected energy supply costs (in millions)
	Beginning of period		End of period		Net cash inflows (outflows)
2023	$	115.4	$	30.0	$	85.4
2024	$	7.8	$	14.9	$	(7.1)
Decrease in net cash inflows					$	(92.5)

Investing Activities

Cash used in investing activities totaled $248.3 million during the six months ended June 30, 2024, as compared with $265.8 million during the six months ended June 30, 2023. Plant additions during the first six months of 2024 include maintenance additions of approximately $130.5 million and capacity related capital expenditures of $116.9 million. Plant additions during the first six months of 2023 included maintenance additions of approximately $142.2 million and capacity related capital expenditures of approximately $121.2 million.

Financing Activities

Cash provided by financing activities totaled $30.2 million during the six months ended June 30, 2024, as compared with cash used in financing activities of $26.8 million during the six months ended June 30, 2023. During the six months ended June 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 net repayments under our revolving lines of credit of $105.0 million, repayment of 1.00 percent, $100.0 million of Montana First Mortgage Bonds, and payment of dividends of $79.3 million. During the six months ended June 30, 2023, cash used in financing activities reflects net repayments under our revolving lines of credit of $259.0 million and payment of dividends of $76.1 million, partly offset by proceeds from the issuance of debt of $300.0 million and proceeds received from the issuance of common stock of $10.8 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 June 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

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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 June 30, 2024 and 2023 the outstanding balances of our credit facilities were $213.0 million and $191.0 million, respectively. As of July 26, 2024, the availability under our credit facilities was approximately $371.0 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 July 26, 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

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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 June 30, 2024.

	Total		2024		2025		2026		2027		2028		Thereafter
	(in thousands)
Long-term debt(1)	$	2,807,660	$	—	$	300,000	$	105,000	$	—	$	392,660	$	2,010,000
Finance leases	7,192		1,731		3,596		1,865		—		—		—
Short-term borrowings	100,000		—		100,000		—		—		—		—
Estimated pension and other postretirement obligations(2)	53,527		8,679		11,437		11,137		11,137		11,137		N/A
Qualifying facilities liability(3)	266,007		37,055		60,360		55,393		56,665		42,400		14,134
Supply and capacity contracts(4)	3,336,438		168,445		295,128		297,587		277,367		259,067		2,038,844
Contractual interest payments on debt(5)	1,588,526		64,127		119,521		113,431		111,771		108,915		1,070,761
Commitments for significant capital projects(6)	45,296		39,513		5,783		—		—		—		—
Total Commitments(7)	$	8,204,646	$	319,550	$	895,825	$	584,413	$	456,940	$	814,179	$	5,133,739

_________________________

(1)Represents cash payments for long-term debt and excludes $13.2 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 $67 to $136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $266.0 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $236.1 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 6.81 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 June 30, 2024, there have been no material changes in these policies.

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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.

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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.

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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 June 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.

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ITEM 6.                      EXHIBITS -

(a) Exhibits

Exhibit 10.1 — Term Loan Credit Agreement, dated April 12, 2024 (incorporated by reference to Exhibit 10.1 of NorthWestern Energy Group's Current Report on Form 8-K, dated April 12, 2024, Commission File No. 000-56598).

Exhibit 10.2 — NorthWestern Corporation Amended and Restated Key Employee Severance Plan, as amended and restated effective April 25, 2024 (incorporated by reference to Exhibit 10.7 of NorthWestern Energy Group's Quarterly Report on Form 10-Q for the quarter ended March 31, 2024, Commission File No. 000-56598).

Exhibit 10.3 — NorthWestern Energy Group, Inc. Amended and Restated Equity Compensation Plan, as amended and restated effective April 25, 2024 (incorporated by reference to Exhibit 10.7 of NorthWestern Energy Group's Quarterly Report on Form 10-Q for the quarter ended March 31, 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)

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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:	July 31, 2024	By:	/s/ CRYSTAL LAIL
			Crystal Lail
			Vice President and Chief Financial Officer
			Duly Authorized Officer and Principal Financial Officer

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