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, 2023
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: 1-10499

NORTHWESTERN CORP

(Exact name of registrant as specified in its charter)

Delaware			46-0172280
(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, 60,041,809 shares outstanding at July 21, 2023

1

NORTHWESTERN CORPORATION

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, 2023 and 2022	5
	Condensed Consolidated Statements of Comprehensive Income — Three and Six Months Ended June 30, 2023 and 2022	6
	Condensed Consolidated Balance Sheets — June 30, 2023 and December 31, 2022	7
	Condensed Consolidated Statements of Cash Flows — Six Months Ended June 30, 2023 and 2022	8
	Condensed Consolidated Statements of Shareholders’ Equity — Three and Six Months Ended June 30, 2023 and 2022	9
	Notes to Condensed Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 4.	Controls and Procedures	53
PART II. OTHER INFORMATION		54
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 6.	Exhibits	55
SIGNATURES		57

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, 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 Corporation,” “NorthWestern Energy,” and “NorthWestern” refer specifically to NorthWestern Corporation and its subsidiaries.

4

PART 1. FINANCIAL INFORMATION

ITEM 1.FINANCIAL STATEMENTS

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

(in thousands, except per share amounts)

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Revenues
Electric	$	229,266	$	243,418	$	524,574	$	515,145
Gas	61,236		79,586		220,470		202,341
Total Revenues	290,502		323,004		745,044		717,486
Operating expenses
Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	67,578		95,001		233,070		230,074
Operating and maintenance	54,840		53,337		110,701		106,131
Administrative and general	29,955		27,220		64,703		58,864
Property and other taxes	40,129		46,893		89,280		93,743
Depreciation and depletion	52,380		48,212		105,628		97,117
Total Operating Expenses	244,882		270,663		603,382		585,929
Operating income	45,620		52,341		141,662		131,557
Interest expense, net	(28,411)		(24,033)		(56,419)		(47,749)
Other income, net	4,062		2,913		8,799		7,634
Income before income taxes	21,271		31,221		94,042		91,442
Income tax expense	(2,147)		(1,435)		(12,388)		(2,546)
Net Income	$	19,124	$	29,786	$	81,654	$	88,896
Average Common Shares Outstanding	59,804		54,272		59,790		54,185
Basic Earnings per Average Common Share	$	0.32	$	0.55	$	1.37	$	1.64
Diluted Earnings per Average Common Share	$	0.32	$	0.54	$	1.37	$	1.62
Dividends Declared per Common Share	$	0.64	$	0.63	$	1.28	$	1.26

See Notes to Condensed Consolidated Financial Statements

5

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(in thousands)

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Net Income	$	19,124	$	29,786	$	81,654	$	88,896
Other comprehensive income, net of tax:
Foreign currency translation adjustment	(1)		1		(3)		(1)
Postretirement medical liability adjustment	(167)		(158)		(334)		(316)
Reclassification of net losses on derivative instruments	113		113		226		226
Total Other Comprehensive Loss	(55)		(44)		(111)		(91)
Comprehensive Income	$	19,069	$	29,742	$	81,543	$	88,805

See Notes to Condensed Consolidated Financial Statements

6

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(in thousands, except share data)

	June 30, 2023		December 31, 2022
ASSETS
Current Assets:
Cash and cash equivalents	$	7,757	$	8,489
Restricted cash	16,263		13,974
Accounts receivable, net	147,173		244,952
Inventories	107,577		107,359
Regulatory assets	52,869		136,009
Prepaid expenses and other	25,567		28,041
Total current assets	357,206		538,824
Property, plant, and equipment, net	5,802,526		5,657,480
Goodwill	357,586		357,586
Regulatory assets	726,129		716,570
Other noncurrent assets	50,795		47,323
Total Assets	$	7,294,242	$	7,317,783
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of finance leases	$	3,213	$	3,098
Current portion of long-term debt	99,850		144,525
Accounts payable	94,552		201,498
Accrued expenses and other	247,287		250,579
Regulatory liabilities	28,444		21,145
Total current liabilities	473,346		620,845
Long-term finance leases	7,192		8,799
Long-term debt	2,558,192		2,474,357
Deferred income taxes	546,066		538,983
Noncurrent regulatory liabilities	666,060		654,213
Other noncurrent liabilities	356,662		355,403
Total Liabilities	4,607,518		4,652,600
Commitments and Contingencies (Note 10)
Shareholders' Equity:
Common stock, par value $0.01; authorized 200,000,000 shares; issued and outstanding 63,517,861 and 59,991,283 shares, respectively; Preferred stock, par value $0.01; authorized 50,000,000 shares; none issued	635		633
Treasury stock at cost	(98,302)		(98,392)
Paid-in capital	2,015,367		1,999,376
Retained earnings	776,983		771,414
Accumulated other comprehensive loss	(7,959)		(7,848)
Total Shareholders' Equity	2,686,724		2,665,183
Total Liabilities and Shareholders' Equity	$	7,294,242	$	7,317,783

See Notes to Condensed Consolidated Financial Statements

7

NORTHWESTERN CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Six Months Ended June 30,
	2023		2022
OPERATING ACTIVITIES:
Net income	$	81,654	$	88,896
Items not affecting cash:
Depreciation and depletion	105,628		97,117
Amortization of debt issuance costs, discount and deferred hedge gain	2,636		2,546
Stock-based compensation costs	4,868		4,002
Equity portion of allowance for funds used during construction	(7,812)		(6,653)
Loss on disposition of assets	(20)		(1)
Deferred income taxes	(10,005)		(3,394)
Changes in current assets and liabilities:
Accounts receivable	97,779		52,629
Inventories	(218)		(18,405)
Other current assets	2,474		(1,474)
Accounts payable	(63,127)		10,877
Accrued expenses and other	(3,029)		10,072
Regulatory assets	83,139		9,035
Regulatory liabilities	7,299		(9,904)
Other noncurrent assets	1,454		7,517
Other noncurrent liabilities	(8,655)		(9,967)
Cash Provided by Operating Activities	294,065		232,893
INVESTING ACTIVITIES:
Property, plant, and equipment additions	(263,362)		(234,438)
Investment in equity securities	(2,426)		(914)
Cash Used in Investing Activities	(265,788)		(235,352)
FINANCING ACTIVITIES:
Proceeds from issuance of common stock, net	10,802		99,903
Dividends on common stock	(76,085)		(67,806)
Issuance of long-term debt	300,000		—
Line of credit repayments, net	(259,000)		(21,000)
Other financing activities, net	(2,437)		(1,320)
Cash (Used in) Provided by Financing Activities	(26,720)		9,777
Increase in Cash, Cash Equivalents, and Restricted Cash	1,557		7,318
Cash, Cash Equivalents, and Restricted Cash, beginning of period	22,463		18,762
Cash, Cash Equivalents, and Restricted Cash, end of period	$	24,020	$	26,080
Supplemental Cash Flow Information:
Cash paid during the period for:
Income taxes	$	3,204	$	1,634
Interest	51,047		44,537
Significant non-cash transactions:
Capital expenditures included in accounts payable	20,938		24,116
Refinancing of Pollution Control Revenue Refunding Bonds	144,660		—

See Notes to Condensed Consolidated Financial Statements

8

NORTHWESTERN CORPORATION

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, 2022	57,693	3,556	$	577	$	(98,986)	$	1,719,070	$	753,677	$	(7,357)	$	2,366,981
Net income	—	—	—		—		—		29,786		—		29,786
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	—	—	—		—		—		—		(158)		(158)
Stock-based compensation	—	—	—		—		1,230		—		—		1,230
Issuance of shares	2,004	(8)	20		221		100,231		—		—		100,472
Dividends on common stock ($0.630 per share)	—	—	—		—		—		(33,905)		—		(33,905)
Balance at June 30, 2022	59,697	3,548	$	597	$	(98,765)	$	1,820,531	$	749,558	$	(7,401)	$	2,464,520
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

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, 2021	57,606	3,546	$	576	$	(98,248)	$	1,716,227	$	728,468	$	(7,310)	$	2,339,713
Net income	—	—	—		—		—		88,896		—		88,896
Foreign currency translation adjustment, net of tax	—	—	—		—		—		—		(1)		(1)
Reclassification of net losses on derivative instruments from OCI to net income, net of tax	—	—	—		—		—		—		226		226
Postretirement medical liability adjustment, net of tax	—	—	—		—		—		—		(316)		(316)
Stock-based compensation	87	16	1		(911)		3,976		—		—		3,066
Issuance of shares	2,004	(14)	20		394		100,328		—		—		100,742
Dividends on common stock ($1.260 per share)	—	—	—		—		—		(67,806)		—		(67,806)
Balance at June 30, 2022	59,697	3,548	$	597	$	(98,765)	$	1,820,531	$	749,558	$	(7,401)	$	2,464,520
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

See Notes to Condensed Consolidated Financial Statements

10

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Reference is made to Notes to Financial Statements included in NorthWestern Corporation’s Annual Report)

(Unaudited)

(1) Nature of Operations and Basis of Consolidation

NorthWestern Corporation, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 764,200 customers in Montana, South Dakota, Nebraska and Yellowstone National Park. We have generated and distributed electricity in South Dakota and distributed natural gas in South Dakota and Nebraska since 1923 and have generated and distributed electricity and distributed natural gas in Montana since 2002.

The 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, 2023 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 our Annual Report on Form 10-K for the year ended December 31, 2022.

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,
	2023		2022		2022		2021
Cash and cash equivalents	$	7,757	$	8,489	$	8,117	$	2,820
Restricted cash	16,263		13,974		17,963		15,942
Total cash, cash equivalents, and restricted cash shown in the Condensed Consolidated Statements of Cash Flows	$	24,020	$	22,463	$	26,080	$	18,762

Goodwill

We completed our annual goodwill impairment test as of April 1, 2023. We evaluated qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors, and overall financial performance) to determine whether it was more likely than not that the fair value of our reporting units was less than its carrying amount. Our evaluation of these factors concluded that it was not more likely than not that the fair value of our reporting units was less than its carrying amount and therefore no further testing was necessary.

11

(2) Regulatory Matters

Except as set forth below, the circumstances set forth in Note 3 - Regulatory Matters to the financial statements included in our Annual Report on the Form 10-K for the year ended December 31, 2022 appropriately represent, in all material respects, the current status of our regulatory matters.

Montana Rate Review

On August 8, 2022, we filed a Montana electric and natural gas rate review with the Montana Public Service Commission (MPSC) requesting an annual increase to electric and natural gas utility rates. On September 28, 2022, the MPSC approved interim rates effective October 1, 2022, subject to refund. Subsequently, we modified our request through rebuttal testimony. On April 3, 2023, we filed a settlement with certain parties, which is subject to approval by the MPSC. The details of our rebuttal request, interim rates granted, and settlement agreement are set forth below:

Requested Revenue Increase Through Rebuttal Testimony (in millions)
	Electric	Natural Gas
Base Rates	$90.6	$22.4
Power Cost & Credit Mechanism (PCCAM)(1)	$69.7	n/a
Property Tax (tracker base adjustment)(1)	$14.5	$4.2
Total Revenue Increase Requested through Rebuttal Testimony	$174.8	$26.6
Interim Revenue Increase Granted (in millions)
	Electric	Natural Gas
Base Rates	$29.4	$1.7
PCCAM(1)	$61.1	n/a
Property Tax (tracker base adjustment)(1)(2)	$10.8	$2.9
Total Interim Revenue Granted	$101.3	$4.6
Requested Revenue Increase Through Settlement Agreement (in millions)
	Electric	Natural Gas
Base Rates	$67.4	$14.1
PCCAM(1)	$69.7	n/a
Property Tax (tracker base adjustment)(1)	$14.5	$4.2
Total Revenue Increase Requested Through Settlement Agreement	$151.6	$18.3

(1) These items are flow-through costs. PCCAM reflects our fuel and purchased power costs.

(2) Our requested interim property tax base increases went into effect on January 1, 2023, as part of our 2023 property tax tracker filing.

The settlement includes, among other things, agreement on electric and natural gas base revenue increases, allocated cost of service, rate design, updates to the base amount of revenues associated with property taxes and electric supply costs, and regulatory policy issues related to requested changes in regulatory mechanisms. The settlement is based on a 48.02 percent equity component of our capital structure and an authorized return on equity (ROE) of 9.65 percent for electric operations and 9.55 percent for natural gas operations, which are consistent with current authorized ROE.

The settlement agreement provides for an update to the PCCAM by adjusting the base costs from $138.7 million to $208.4 million and providing for more timely quarterly recovery of deferred balances instead of annual recovery. It also addresses the potential for future recovery of certain operating costs associated with the Yellowstone County Generating Station and provides for the deferral of incremental operating costs related to our Enhanced Wildfire Mitigation Plan. The settling parties agreed to terminate the pilot decoupling program (Fixed Cost Recovery Mechanism) and that the proposed business technology rider will not be implemented.

A hearing on the settlement agreement was held in April 2023, post-hearing briefing concluded in June 2023, and we expect a decision from the MPSC during the third quarter of 2023. Interim rates remain in effect on a refundable basis until the MPSC issues a final order.

South Dakota Electric Rate Review

12

On June 15, 2023, we filed a South Dakota electric rate review filing (2022 test year) under Docket EL23-016 for an annual increase to electric rates totaling approximately $30.9 million. Our request was based on a ROE of 10.7 percent, a capital structure including 50.5 percent equity, and rate base of $787.3 million.

Holding Company Filings

On June 1, 2022, we filed a legal corporate restructuring application (Restructuring Plan) with the state commissions in Montana, South Dakota and Nebraska and the Federal Energy Regulatory Commission (FERC). Currently, our utility businesses are held in the same legal entity. Under the Restructuring Plan, we proposed to legally separate our Montana public utility business from our South Dakota and Nebraska public utility business and establish a holding company to hold the ownership interests of all of the subsidiaries. The purpose of the reorganization is to segregate our organizational structure to be more transparent and in line with the public utility industry. The Restructuring Plan does not include substantive changes in how the state public utility commissions regulate those services. We have received all necessary regulatory approvals and we expect to effectuate the Restructuring Plan by early 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,
	2023				2022
Income before income taxes	$	21,271			$	31,221
Income tax calculated at federal statutory rate	4,467		21.0	%	6,554		21.0	%
Permanent or flow-through adjustments:
State income tax, net of federal provisions	273		1.3		431		1.4
Flow-through repairs deductions	(1,708)		(8.0)		(3,313)		(10.6)
Production tax credits	(1,147)		(5.4)		(2,558)		(8.2)
Amortization of excess deferred income tax	(233)		(1.1)		(162)		(0.5)
Plant and depreciation flow-through items	201		0.9		398		1.3
Other, net	294		1.4		85		0.2
	(2,320)		(10.9)		(5,119)		(16.4)
Income tax expense	$	2,147	10.1	%	$	1,435	4.6	%

13

	Six Months Ended June 30,
	2023				2022
Income before income taxes	$	94,042			$	91,442
Income tax calculated at federal statutory rate	19,749		21.0	%	19,200		21.0	%
Permanent or flow through adjustments:
State income, net of federal provisions	1,232		1.3		831		0.9
Flow-through repairs deductions	(7,553)		(8.0)		(10,114)		(11.1)
Production tax credits	(4,346)		(4.6)		(6,382)		(7.0)
Reduction to previously claimed alternative minimum tax credit	3,186		3.4		—		—
Amortization of excess deferred income tax	(1,032)		(1.1)		(573)		(0.6)
Share-based compensation	388		0.4		(253)		(0.3)
Plant and depreciation flow through items	889		0.9		143		0.2
Other, net	(125)		(0.1)		(306)		(0.3)
	(7,361)		(7.8)		(16,654)		(18.2)
Income tax expense	$	12,388	13.2	%	$	2,546	2.8	%

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 $29.5 million as of June 30, 2023, including approximately $27.8 million that, if recognized, would impact our effective tax rate. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. As of June 30, 2023, we have accrued $2.1 million for the payment of interest and penalties on the Condensed Consolidated Balance Sheets. As of December 31, 2022, we had accrued $1.4 million for the payment of interest and penalties on the Condensed Consolidated Balance Sheets.

Tax years 2019 and forward remain subject to examination by the Internal Revenue Service (IRS) and state taxing authorities. During the first quarter of 2023 the IRS commenced and concluded a limited scope examination of our 2019 amended federal income tax return. This examination resulted in a reduction to our previously claimed alternative minimum tax credit refund that is reflected in the table above.

(4) Comprehensive (Loss) Income

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

	Three Months Ended
	June 30, 2023						June 30, 2022
	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
Postretirement medical liability adjustment	(212)		45		(167)		(212)		54		(158)
Other comprehensive (loss) income	$	(60)	$	5	$	(55)	$	(58)	$	14	$	(44)

14

	Six Months Ended
	June 30, 2023						June 30, 2022
	Before-Tax Amount		Tax Expense		Net-of-Tax Amount		Before-Tax Amount		Tax Expense		Net-of-Tax Amount
Foreign currency translation adjustment	$	(3)	$	—	$	(3)	$	(1)	$	—	$	(1)
Reclassification of net income on derivative instruments	306		(80)		226		306		(80)		226
Postretirement medical liability adjustment	(424)		90		(334)		(424)		108		(316)
Other comprehensive (loss) income	$	(121)	$	10	$	(111)	$	(119)	$	28	$	(91)

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, 2023		December 31, 2022
Foreign currency translation	$	1,432	$	1,435
Derivative instruments designated as cash flow hedges	(9,599)		(9,825)
Postretirement medical plans	208		542
Accumulated other comprehensive loss	$	(7,959)	$	(7,848)

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

		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)

15

		Three Months Ended
		June 30, 2022
	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		$	(10,164)	$	1,366	$	1,441	$	(7,357)
Other comprehensive loss before reclassifications		—		—		1		1
Amounts reclassified from AOCL	Interest Expense	113		—		—		113
Amounts reclassified from AOCL		—		(158)		—		(158)
Net current-period other comprehensive income (loss)		113		(158)		1		(44)
Ending balance		$	(10,051)	$	1,208	$	1,442	$	(7,401)

		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)

		Six Months Ended
		June 30, 2022
	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		$	(10,277)	$	1,524	$	1,443	$	(7,310)
Other comprehensive loss before reclassifications		—		—		(1)		(1)
Amounts reclassified from AOCL	Interest Expense	226		—		—		226
Amounts reclassified from AOCL		—		(316)		—		(316)
Net current-period other comprehensive income (loss)		226		(316)		(1)		(91)
Ending balance		$	(10,051)	$	1,208	$	1,442	$	(7,401)

16

(5) Financing Activities

On March 30, 2023, we issued and sold $239.0 million aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 5.57 percent maturing on March 30, 2033. On this same day, we issued and sold $31.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.57 percent maturing on March 30, 2033. On May 1, 2023, we issued and sold an additional $30.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.42 percent maturing on May 1, 2033. These bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933. Proceeds were used to repay a portion of our outstanding borrowings under our revolving credit facilities and for other general corporate purposes. The bonds are secured by our electric and natural gas assets in Montana and South Dakota.

In June 2023, we amended our Equity Distribution Agreement to replace one of the sales agents. Pursuant to the Equity Distribution Agreement we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $200.0 million, through an At-the-Market (ATM) offering program, including an equity forward sales component. This is a three-year agreement, expiring on February 11, 2024. During the three months ended June 30, 2023, we issued 188,682 shares of common stock under the ATM program at an average price of $57.83 per share, for net proceeds of $10.8 million which is net of sales commissions and other fees paid of approximately $0.1 million.

On June 29, 2023, the City of Forsyth, Rosebud County, Montana issued $144.7 million principal amount of Pollution Control Revenue Refunding Bonds (2023 Pollution Control Bonds) on our behalf. The 2023 Pollution Control Bonds were issued at a fixed interest rate of 3.88 percent maturing on July 1, 2028. The proceeds of the issuance were loaned to us pursuant to a Loan Agreement and were deposited directly with U.S. Bank Trust Company, National Association, as trustee, for the redemption of the 2.00 percent, $144.7 million City of Forsyth Pollution Control Revenue Refunding Bonds due on August 1, 2023 that had previously been issued on our behalf. Pursuant to the Loan Agreement, we are obligated to make payments in such amounts and at such times as will be sufficient to pay, when due, the principal and interest on the 2023 Pollution Control Bonds. Our obligations under the Loan Agreement are secured by delivery of a like amount of our Montana First Mortgage Bonds, which are secured by our Montana electric and natural gas assets. So long as we are making payments under the Loan Agreement, no payments under these mortgage bonds will be due. The 2023 Pollution Control Bonds were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended.

(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):

17

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

Three Months Ended
June 30, 2022	Electric		Gas		Other		Eliminations		Total
Operating revenues	$	243,418	$	79,586	$	—	$	—	$	323,004
Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	57,696		37,305		—		—		95,001
Utility margin	185,722		42,281		—		—		228,003
Operating and maintenance	40,822		12,515		—		—		53,337
Administrative and general	20,115		7,171		(66)		—		27,220
Property and other taxes	36,426		10,465		2		—		46,893
Depreciation and depletion	40,185		8,027		—		—		48,212
Operating income	48,174		4,103		64		—		52,341
Interest expense, net	(18,837)		(3,323)		(1,873)		—		(24,033)
Other income, net	1,319		1,412		182		—		2,913
Income tax (expense) benefit	(790)		(1,000)		355		—		(1,435)
Net income (loss)	$	29,866	$	1,192	$	(1,272)	$	—	$	29,786
Total assets	$	5,593,989	$	1,319,829	$	6,479	$	—	$	6,920,297
Capital expenditures	$	91,673	$	27,263	$	—	$	—	$	118,936

18

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	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

Six Months Ended
June 30, 2022	Electric		Gas		Other		Eliminations		Total
Operating revenues	$	515,145	$	202,341	$	—	$	—	$	717,486
Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	135,319		94,755		—		—		230,074
Utility margin	379,826		107,586		—		—		487,412
Operating and maintenance	80,323		25,808		—		—		106,131
Administrative and general	42,852		15,823		189		—		58,864
Property and other taxes	72,851		20,888		4		—		93,743
Depreciation and depletion	80,609		16,508		—		—		97,117
Operating income (loss)	103,191		28,559		(193)		—		131,557
Interest expense, net	(37,806)		(6,713)		(3,230)		—		(47,749)
Other income, net	4,301		2,942		391		—		7,634
Income tax (expense) benefit	(1,784)		(2,382)		1,620		—		(2,546)
Net income (loss)	$	67,902	$	22,406	$	(1,412)	$	—	$	88,896
Total assets	$	5,593,989	$	1,319,829	$	6,479	$	—	$	6,920,297
Capital expenditures	$	190,282	$	44,156	$	—	$	—	$	234,438

19

(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 20-30 days after the billing date.

Natural Gas Segment - Our regulated natural gas utility business primarily provides production, storage, transmission, and distribution services to 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 20-30 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, 2023						June 30, 2022
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Montana	$	83.8	$	17.6	$	101.4	$	70.7	$	28.6	$	99.3
South Dakota	15.7		8.4		24.1		15.6		9.4		25.0
Nebraska	—		7.4		7.4		—		7.4		7.4
Residential	99.5		33.4		132.9		86.3		45.4		131.7
Montana	101.9		9.9		111.8		84.3		14.7		99.0
South Dakota	25.1		5.5		30.6		26.5		6.4		32.9
Nebraska	—		4.7		4.7		—		4.5		4.5
Commercial	127.0		20.1		147.1		110.8		25.6		136.4
Industrial	10.8		0.2		11.0		9.0		0.2		9.2
Lighting, governmental, irrigation, and interdepartmental	8.7		0.3		9.0		8.3		0.5		8.8
Total Customer Revenues	246.0		54.0		300.0		214.4		71.7		286.1
Other tariff and contract based revenues	20.0		10.6		30.6		21.6		9.2		30.8
Total Revenue from Contracts with Customers	266.0		64.6		330.6		236.0		80.9		316.9
Regulatory amortization and other	(36.7)		(3.4)		(40.1)		7.4		(1.3)		6.1
Total Revenues	$	229.3	$	61.2	$	290.5	$	243.4	$	79.6	$	323.0

20

	Six Months Ended
	June 30, 2023						June 30, 2022
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Montana	$	209.3	$	84.5	$	293.8	$	167.7	$	80.9	$	248.6
South Dakota	35.5		28.3		63.8		36.0		29.3		65.3
Nebraska	—		28.0		28.0		—		22.8		22.8
Residential	244.8		140.8		385.6		203.7		133.0		336.7
Montana	214.5		46.3		260.8		170.8		41.8		212.6
South Dakota	50.3		19.8		70.1		54.1		20.9		75.0
Nebraska	—		17.8		17.8		—		13.7		13.7
Commercial	264.8		83.9		348.7		224.9		76.4		301.3
Industrial	22.6		0.9		23.5		18.7		0.8		19.5
Lighting, governmental, irrigation, and interdepartmental	13.9		1.0		14.9		12.8		1.2		14.0
Total Customer Revenues	546.1		226.6		772.7		460.1		211.4		671.5
Other tariff and contract based revenues	41.3		22.9		64.2		41.7		19.2		60.9
Total Revenue from Contracts with Customers	587.4		249.5		836.9		501.8		230.6		732.4
Regulatory amortization and other	(62.8)		(29.1)		(91.9)		13.3		(28.2)		(14.9)
Total Revenues	$	524.6	$	220.4	$	745.0	$	515.1	$	202.4	$	717.5

(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 and forward equity sale. Average shares used in computing the basic and diluted earnings per share are as follows:

	Three Months Ended
	June 30, 2023	June 30, 2022
Basic computation	59,804,283	54,271,862
Dilutive effect of:
Performance share awards(1)	45,391	34,900
Forward equity sale(2)	—	834,126
Diluted computation	59,849,674	55,140,888

	Six Months Ended
	June 30, 2023	June 30, 2022
Basic computation	59,790,316	54,184,798
Dilutive effect of:
Performance share awards(1)	29,200	23,072
Forward equity sale(2)	—	772,755
Diluted computation	59,819,516	54,980,625

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

(2) Forward equity shares are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the forward sale agreement.

21

As of June 30, 2023, there were 21,890 shares from performance and restricted share awards which were antidilutive and excluded from the earnings per share calculations, compared to 36,296 shares as of June 30, 2022.

(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,
	2023		2022		2023		2022
Components of Net Periodic Benefit Cost (Credit)
Service cost	$	1,422	$	2,228	$	79	$	84
Interest cost	6,482		4,725		161		88
Expected return on plan assets	(6,671)		(6,034)		(273)		(261)
Amortization of prior service credit	—		—		29		(473)
Recognized actuarial (gain) loss	(3)		191		5		(10)
Net periodic benefit cost (credit)	$	1,230	$	1,110	$	1	$	(572)

	Pension Benefits				Other Postretirement Benefits
	Six Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Components of Net Periodic Benefit Cost (Credit)
Service cost	$	2,916	$	5,112	$	166	$	175
Interest cost	13,047		9,393		337		179
Expected return on plan assets	(13,357)		(12,086)		(548)		(523)
Amortization of prior service credit	—		—		58		(946)
Recognized actuarial loss (gain)	137		191		36		(24)
Net periodic benefit cost (credit)	$	2,743	$	2,610	$	49	$	(1,139)

We contributed $0.6 million to our pension plans during the three and six months ended June 30, 2023. We expect to contribute an additional $10.6 million to our pension plans during the remainder of 2023.

(10) Commitments and Contingencies

Except as set forth below and in Note 2 - Regulatory Matters above, the circumstances set forth in Note 18 - Commitments and Contingencies to the financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2022 appropriately represent, in all material respects, the current status of our material commitments and contingent liabilities.

22

ENVIRONMENTAL LIABILITIES AND REGULATION

Environmental Matters

The operation of electric generating, transmission and distribution facilities, and gas gathering, storage, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance.

Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, our environmental reserve, which relates primarily to the remediation of former manufactured gas plant sites owned by us or for which we are responsible, is estimated to range between $20.9 million to $32.0 million. As of June 30, 2023, we had a reserve of approximately $25.7 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred.

Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as available and applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our consolidated financial position or results of operations.

Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of greenhouse gas (GHG) including, most significantly, carbon dioxide (CO2) and methane emissions from natural gas. These actions include legislative proposals, Executive, Congressional and Environmental Protection Agency (EPA) actions at the federal level, state level activity, investor activism and private party litigation relating to emissions. Coal-fired plants have come under particular scrutiny due to their level of emissions. We have joint ownership interests in four coal-fired electric generating plants, all of which are operated by other companies. We are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated.

Proposed EPA Rules - Congress has not passed any federal climate change legislation regarding GHG emissions from coal fired plants, and we cannot predict the timing or form of any potential legislation. Section 111(d) of the Clean Air Act (CAA) confers authority on EPA and the states to regulate emissions, including GHGs, from existing stationary sources. In May 2023, EPA proposed new GHG emissions standards for coal and natural gas-fired plants. In particular, the proposed rules would (i) strengthen the current New Source Performance Standards for newly built fossil fuel-fired stationary combustion turbines (generally natural gas-fired); (ii) establish emission guidelines for states to follow in limiting carbon pollution from existing fossil fuel-fired steam generating electric generating units (including coal, oil and natural gas-fired units); and (iii) establish emission guidelines for large, frequently used existing fossil fuel-fired stationary combustion turbines (generally natural gas-fired). In addition, in April 2023, EPA proposed to amend the Mercury Air Toxics Standard (MATS). Among other things, MATS currently sets stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. We are in compliance with existing MATS requirements. The proposed amendment of the MATS would strengthen the MATS requirements, and if adopted as written, both the GHG and MATS proposed rules could have a material negative impact on our coal-fired plants, including requiring potentially expensive upgrades or the early retirement of Colstrip Unit's 3 and 4 due to the rules making the facility uneconomic.

Previous efforts by the EPA were met with extensive litigation and we anticipate a similar response if the proposed rules are adopted. As MATS and GHG regulations are implemented, it could result in additional material compliance costs. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from any MATS or GHG regulations that, in our view, disproportionately impact customers in our region.

Future additional environmental requirements - federal or state - could cause us to incur material costs of compliance, increase our costs of procuring electricity, decrease transmission revenue and impact cost recovery. Technology to efficiently

23

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. Physical impacts of climate change also may present potential risks for severe weather, such as droughts, fires, floods, wind, ice storms and tornadoes, in the locations where we operate or have interests. These potential risks may impact costs for electric and natural gas supply and maintenance of generation, distribution, and transmission facilities.

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 our Annual Report on Form 10-K for the year ended December 31, 2022. 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. Damages were bifurcated by agreement and will be tried separately should the Federal District Court find any segments navigable. While we await the Federal District Court decision on navigability, the damages phase of the case remains stayed.

We dispute the State’s claims and intend to continue to vigorously defend the lawsuit. At this time, we cannot predict an outcome. If the Federal District Court determines the riverbeds are navigable under the remaining six facilities that were not dismissed and if it calculates damages as the State District Court did in 2008, we estimate the annual rents could be approximately $3.8 million commencing when we acquired the facilities in November 2014. We anticipate that any obligation to pay the State rent for use and occupancy of the riverbeds would be recoverable in rates from customers, although there can be no assurances that the MPSC would approve any such recovery.

Colstrip Arbitration

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

As a result of the mandate, the owners have disagreed on various operational funding decisions, including whether closure requires each owner’s consent under the O&O Agreement. On March 12, 2021, we initiated an arbitration under the O&O Agreement (the “Arbitration”), to resolve the issues of whether closure requires each owner's consent and to clarify each owner's obligations to continue to fund operations until all joint owners agree on closure. The owners previously initiated efforts to identify arbitrators and have agreed to stay the Arbitration through September 29, 2023, while they explore a potential resolution to their disagreements.

Colstrip Coal Dust Litigation

On December 14, 2020, a claim was filed against Talen in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. Talen is one of the co-owners of Colstrip Unit 3, and the operator of Units 3 and 4. The plaintiffs allege they have suffered adverse effects from coal dust generated during operations associated with Colstrip. On August 26, 2021, the claim was amended to add in excess of 100 plaintiffs. It also added NorthWestern, the other owners of Colstrip, and Westmoreland Rosebud Mining LLC, as defendants. Plaintiffs are seeking economic damages, costs and disbursements, punitive damages, attorneys’ fees, and an injunction prohibiting defendants from allowing coal dust to blow onto plaintiffs’ properties.

Since this lawsuit remains in its early discovery stages, we are unable to predict outcomes or estimate a range of reasonably possible losses.

24

BNSF Demands for Indemnity and Remediation Costs

NorthWestern has received a demand for indemnity from BNSF Railway Company (BNSF) for past and future environmental investigation and remediation costs incurred by BNSF at one of the three operable units at the Anaconda Copper Mining (ACM) Smelter and Refinery Superfund Site, located near Great Falls, Montana. Smelter and refining operations at the site commenced in 1893 and continued until 1980.

According to EPA, the smelter and refining operations have contaminated soil, groundwater and surface water resources around the site with lead, arsenic and other metal wastes. ARCO (Atlantic Richfield Company) initiated reclamation and maintenance activities in the 1980s and 1990s. Between 2002 and 2008, the EPA conducted several site investigations. In March 2011, the EPA placed the ACM Smelter and Refinery Site on the Superfund program’s National Priority List. The Superfund Site is 427 acres and contains three operable units: Operable Unit 1 (consisting of five subsections including the Railroad Corridor and four other “areas of interest”), Operable Unit 2 (the former smelter and refinery site), and Operable Unit 3 (the Missouri River that flows along the south sides of Operable Units 1 and 2).

NorthWestern owns property in the Railroad Corridor sub-section of Operable Unit 1. BNSF claims it is entitled to indemnity and contribution from NorthWestern for the costs it has and will incur to investigate and remediate contamination in Operable Unit 1. BNSF reports it has incurred in excess of $4.4 million, pending final resolution, of response and oversight costs incurred by government agencies (EPA and Montana DEQ), in investigative and other response costs associated with Operable Unit 1, and that in the future it will incur additional costs to implement the final remedy for Operable Unit 1. In the Record of Decision (ROD) for Operable Unit 1 issued on August 21, 2021, the EPA estimated the costs to implement the selected remedies for the Railroad Corridor will be approximately $4.1 million. In the ROD, the EPA also estimated the costs to implement the selected remedy (including institutional controls) for the four “areas of interest” in Operable Unit 1 would be approximately $1.8 million, with annual operating costs of ten thousand dollars. We are evaluating BNSF’s claim and are unable at this time to predict outcomes or estimate a range of reasonably possible losses.

Yellowstone County Generating Station Air Permit

On October 21, 2021, the Montana Environmental Information Center (MEIC) and the Sierra Club filed a lawsuit in Montana State 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 notice of appeal with the Montana Supreme Court. We recommenced construction in June 2023 and expect the plant to be operational by the end of the third quarter 2024.

On May 10, 2023, Montana House Bill 971 was signed into law, preventing the MDEQ from considering climate impacts in its analysis of large projects such as coal mines and power plants, and on June 1, 2023, the MDEQ issued its supplemental air quality permit that contained the updated exterior lighting analysis, and the MDEQ indicated that no other analysis was necessary. The comment period concerning the MDEQ’s supplemental air quality permit ended on July 3, 2023. We expect to receive a final revised permit from the MDEQ during the third quarter of 2023. This current lawsuit, as well as additional potential legal challenges related to the Yellowstone County Generating Station, could delay the project timing and increase costs.

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.

25

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 Corporation, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 764,200 customers in Montana, South Dakota, Nebraska and Yellowstone National Park. For a discussion of NorthWestern’s business strategy, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2022.

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, in 2022 we expanded and outlined our efforts towards a carbon-free future 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, 2023 and 2022.

26

HOW WE PERFORMED AGAINST OUR SECOND QUARTER 2022 RESULTS

	Three Months Ended June 30, 2023 vs. 2022
		Income Before Income Taxes		Income Tax (Expense) Benefit		Net Income
				(in millions)
Second Quarter, 2022		$	31.2	$	(1.4)	$	29.8
Variance in revenue and fuel, purchased supply, and direct transmission expense(1) items impacting net income:
Lower natural gas retail volumes		(5.3)		1.3		(4.0)
Lower electric retail volumes		(3.5)		0.9		(2.6)
Lower electric transmission revenue		(1.7)		0.4		(1.3)
Montana interim rates (subject to refund)		7.1		(1.8)		5.3
Montana property tax tracker collections		3.3		(0.8)		2.5
Lower non-recoverable Montana electric supply costs due to higher electric supply revenues and lower electric supply costs		3.0		(0.8)		2.2
Natural gas transportation		0.4		(0.1)		0.3
Other		(0.4)		0.1		(0.3)
Variance in expense items(2) impacting net income:
Higher operating, maintenance, and administrative expenses		(7.2)		1.8		(5.4)
Higher interest expense		(4.4)		1.1		(3.3)
Higher depreciation expense		(4.2)		1.1		(3.1)
Higher other state and local tax expense		(0.9)		0.2		(0.7)
Prior year Montana Community Renewable Energy Projects (CREP) Penalty		2.5		—		2.5
Other		1.4		(4.2)		(2.8)
Second Quarter, 2023		$	21.3	$	(2.2)	$	19.1
Change in Net Income						$	(10.7)

(1) Exclusive of depreciation and depletion shown separately below

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

Consolidated net income for the three months ended June 30, 2023 was $19.1 million as compared with $29.8 million for the same period in 2022. This decrease was primarily due to lower electric and natural gas retail volumes, lower transmission revenues, higher operating and maintenance expense, higher administrative and general expense, higher depreciation and depletion expense, higher interest expense, and higher income tax expense, partly offset by higher Montana interim rates associated with our ongoing rate review, which are subject to refund, higher Montana property tax tracker collections, and lower non-recoverable Montana electric supply costs.

SIGNIFICANT TRENDS AND REGULATION

Refer to our Annual Report on the Form 10-K for the year ended December 31, 2022 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:

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.

Montana Rate Review Filing – On August 8, 2022, we filed a Montana electric and natural gas rate review with the MPSC requesting an annual increase to electric and natural gas utility rates. On September 28, 2022, the MPSC approved interim rates

27

effective October 1, 2022, subject to refund. Subsequently, we modified our request through rebuttal testimony. On April 3, 2023, we filed a settlement agreement with certain parties, which is subject to approval by the MPSC. The details of our rebuttal request, interim rates granted, and the settlement agreement are set forth below:

Montana Rate Review ($ in millions)
	Electric	Natural Gas
Current ROE	9.65%	9.55%
Current Equity Ratio	49.38%	46.79%
Proposed Settlement ROE	9.65%	9.55%
Proposed Settlement Equity Ratio	48.02%	48.02%
Rebuttal Filing Forecasted 2022 Rate Base	$2,842	$582
Requested Revenue Increase Through Rebuttal Testimony (in millions)
	Electric	Natural Gas
Base Rates	$90.6	$22.4
PCCAM(1)	$69.7	n/a
Property Tax (tracker base adjustment)(1)	$14.5	$4.2
Total Revenue Increase Requested through Rebuttal Testimony	$174.8	$26.6
Interim Revenue Increase Granted (in millions)
	Electric	Natural Gas
Base Rates	$29.4	$1.7
PCCAM(1)	$61.1	n/a
Property Tax (tracker base adjustment)(1)(2)	$10.8	$2.9
Total Interim Revenue Granted	$101.3	$4.6
Requested Revenue Increase Through Settlement Agreement (in millions)
	Electric	Natural Gas
Base Rates	$67.4	$14.1
PCCAM(1)	$69.7	n/a
Property Tax (tracker base adjustment)(1)	$14.5	$4.2
Total Revenue Increase Requested Through Settlement Agreement	$151.6	$18.3

(1) These items are flow-through costs. PCCAM reflects our fuel and purchased power costs.

(2) Our requested interim property tax base increases went into effect on January 1, 2023, as part of our 2023 property tax tracker filing.

The settlement includes, among other things, agreement on electric and natural gas base revenue increases, allocated cost of service, rate design, updates to the base amount of revenues associated with property taxes and electric supply costs, and regulatory policy issues related to requested changes in regulatory mechanisms.

The settlement agreement provides for an update to the PCCAM by adjusting the base costs from $138.7 million to $208.4 million and providing for more timely quarterly recovery of deferred balances instead of annual recovery. It also addresses the potential for future recovery of certain operating costs associated with the Yellowstone County Generating Station and provides for the deferral of incremental operating costs related to our Enhanced Wildfire Mitigation Plan. The settling parties agreed to terminate the pilot decoupling program (Fixed Cost Recovery Mechanism) and that the proposed business technology rider will not be implemented.

A hearing on the settlement agreement was held in April 2023, post-hearing briefing concluded in June 2023, and we expect a decision from the MPSC during the third quarter of 2023. Interim rates remain in effect on a refundable basis until the MPSC issues a final order.

28

South Dakota Electric Rate Review Filing – On June 15, 2023, we filed a South Dakota electric rate review filing (2022 test year) under Docket EL23-016 for an annual increase to electric rates totaling approximately $30.9 million. Our request was based on a ROE of 10.7%, a capital structure including 50.5% equity, and rate base of $787.3 million.

Holding Company Filings – We filed a Restructuring Plan with the state commissions in Montana, South Dakota and Nebraska and the FERC. Currently, our utility businesses are held in the same legal entity. Under the Restructuring Plan, we proposed to legally separate our Montana public utility business from our South Dakota and Nebraska public utility business and establish a holding company to hold the ownership interests of all of the subsidiaries. The purpose of the reorganization is to segregate our organizational structure to be more transparent and in line with the public utility industry. The Restructuring Plan does not include substantive changes in how the state public utility commissions regulate those services. We have received all necessary regulatory approvals and we expect to effectuate the Restructuring Plan by early 2024.

Power Costs and Credits Adjustment Mechanism - The MPSC's September 2022 decision approving interim rates, which are subject to refund, included an increase to the PCCAM Base of $61.1 million, effective October 1, 2022. As of June 30, 2023, we have under-collected our total Montana electric supply costs for the July 2022 through June 2023 PCCAM year by approximately $18.5 million. Absent the interim rate PCCAM Base increase, as of June 30, 2023, our under-collected position would have been approximately $58.7 million. In the current PCCAM design, under-collections are not recovered from customers until the subsequent power cost adjustment year with a change in customer rates effective annually on October 1, which has adversely affected our cash flows and liquidity.

Under the PCCAM, net costs higher or lower than the PCCAM Base (excluding qualifying facility costs) are allocated 90% to Montana customers and 10% to shareholders. For the three and six months ended June 30, 2023, we over collected supply costs for the 2022 - 2023 PCCAM year of $18.9 million and $23.4 million, respectively, resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $2.1 million and $2.6 million, respectively (10% of the PCCAM Base cost variance). For the three and six months ended June 30, 2022, we under collected costs of $7.5 million and $14.6 million, respectively, resulting in an increase to the under collection of costs, and recorded a reduction in pre-tax earnings of $0.8 million and $1.6 million, respectively.

Our electric supply from owned and long-term contracted resources is not adequate to meet our peak-demand needs. Because of this, the volatility of market prices for energy on peak-demand days, even if only for a few days in duration, exposes us to potentially significant market purchases that could negatively impact our results of operations and cash flows. See the Electric Resource Planning - Montana section below for how we are working to address this market exposure.

Electric Resource Planning - Montana

Yellowstone County 175 MW plant - As previously reported, in October 2021, the Montana Environmental Information Center and the Sierra Club filed a lawsuit in Montana State Court, against the MDEQ and us, alleging that the environmental analysis conducted prior to issuance of the Yellowstone County Generating Station's air quality permit was inadequate. On April 4, 2023, the Montana District Court issued an order finding the MDEQ's environmental analysis was deficient in not addressing exterior lighting and greenhouse gases and remanded it back to MDEQ to address the deficiencies and vacated the air quality permit pending that remand. As a result of the vacatur of the permit, we paused construction. On June 8, 2023, the Montana District Court granted our motion to stay the order vacating the air quality permit pending the outcome of our notice of appeal with the Montana Supreme Court. We recommenced construction in June 2023 and expect the plant to be operational by the end of the third quarter 2024.

On May 10, 2023, Montana House Bill 971 was signed into law, preventing the MDEQ from considering climate impacts in its analysis of large projects such as coal mines and power plants, and on June 1, 2023, the MDEQ issued its supplemental air quality permit that contained the updated exterior lighting analysis, and the MDEQ indicated that no other analysis was necessary. The comment period concerning the MDEQ’s supplemental air quality permit ended on July 3, 2023. The current lawsuit, as well as additional potential legal challenges related to the Yellowstone County Generating Station, could delay the project timing and increase costs. Total costs of approximately $203.6 million have been incurred, with expected total costs of approximately $275.0 million.

Future Integrated Resource Planning - Resource adequacy in the Western third of the U.S. has been declining with the retirement of thermal power plants. Our owned and long-term contracted resources are inadequate to supply the necessary capacity we require to meet our peak-demand loads, which exposes us to large quantities of market purchases at typically high and volatile energy prices. To comply with regulatory resource planning requirements, we submitted an integrated resource plan to the MPSC on April 28, 2023.

We remain concerned regarding an overall lack of capacity in the West and our owned and long-term contracted capacity deficit to meet peak-demand loads. The construction of the Yellowstone County Generating Station and acquisition of Avista's Colstrip Units 3 and 4 interests are expected to reduce our exposure to market purchases.

29

Proposed EPA Rules

In May 2023, the EPA proposed new GHG emissions standards for coal and natural gas-fired plants. In particular, the proposed rules would (i) strengthen the current New Source Performance Standards for newly built fossil fuel-fired stationary combustion turbines (generally natural gas-fired); (ii) establish emission guidelines for states to follow in limiting carbon pollution from existing fossil fuel-fired steam generating electric generating units (including coal, oil and natural gas-fired units); and (iii) establish emission guidelines for large, frequently used existing fossil fuel-fired stationary combustion turbines (generally natural gas-fired). In addition, in April 2023, EPA proposed to amend the MATS. Among other things, MATS currently sets stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. We are in compliance with existing MATS requirements. The proposed amendment of the MATS would strengthen the MATS requirements, and if adopted as written, both the GHG and MATS proposed rules could have a material negative impact on our coal-fired plants, including requiring potentially expensive upgrades or the early retirement of Colstrip Unit's 3 and 4 due to the rules making the facility uneconomic.

Previous efforts by the EPA were met with extensive litigation and we anticipate a similar response if the proposed rules are adopted. As MATS and GHG regulations are implemented, it could result in additional material compliance costs. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from any MATS or GHG regulations that, in our view, disproportionately impact customers in our region.

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.

30

OVERALL CONSOLIDATED RESULTS

Three Months Ended June 30, 2023 Compared with the Three Months Ended June 30, 2022

Consolidated net income for the three months ended June 30, 2023 was $19.1 million as compared with $29.8 million for the same period in 2022. This decrease was primarily due to lower electric and natural gas retail volumes, lower transmission revenues, higher operating and maintenance expense, higher administrative and general expense, higher depreciation and depletion expense, higher interest expense, and higher income tax expense, partly offset by higher Montana interim rates associated with our ongoing rate review, which are subject to refund, higher Montana property tax tracker collections, and lower non-recoverable Montana electric supply costs.

Consolidated gross margin for the three months ended June 30, 2023 was $75.5 million as compared with $79.6 million in 2022, a decrease of $4.1 million, or 5.2 percent. This decrease was primarily due to lower electric and natural gas retail volumes and lower transmission revenues, higher operating and maintenance expense, and higher depreciation and depletion expense, partly offset by higher Montana interim rates associated with our ongoing rate review, which are subject to refund, higher Montana property tax tracker collections, and lower non-recoverable Montana electric supply costs.

	Electric				Natural Gas				Total
	2023		2022		2023		2022		2023		2022
	(in millions)
Reconciliation of gross margin to utility margin:
Operating Revenues	$	229.3	$	243.4	$	61.2	$	79.6	$	290.5	$	323.0
Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	42.4		57.7		25.2		37.3		67.6		95.0
Less: Operating and maintenance	41.4		40.8		13.5		12.5		54.9		53.3
Less: Property and other taxes	31.0		36.4		9.1		10.5		40.1		46.9
Less: Depreciation and depletion	43.3		40.2		9.1		8.0		52.4		48.2
Gross Margin	71.2		68.3		4.3		11.3		75.5		79.6
Operating and maintenance	41.4		40.8		13.5		12.5		54.9		53.3
Property and other taxes	31.0		36.4		9.1		10.5		40.1		46.9
Depreciation and depletion	43.3		40.2		9.1		8.0		52.4		48.2
Utility Margin(1)	$	186.9	$	185.7	$	36.0	$	42.3	$	222.9	$	228.0

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

	Three Months Ended June 30,
	2023		2022		Change		% Change
	(dollars in millions)
Utility Margin
Electric	$	186.9	$	185.7	$	1.2	0.6	%
Natural Gas	36.0		42.3		(6.3)		(14.9)
Total Utility Margin(1)	$	222.9	$	228.0	$	(5.1)	(2.2)	%

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

Consolidated utility margin for the three months ended June 30, 2023 was $222.9 million as compared with $228.0 million for the same period in 2022, a decrease of $5.1 million, or 2.2 percent.

Primary components of the change in utility margin include the following (in millions):

31

	Utility Margin 2023 vs. 2022
Utility Margin Items Impacting Net Income
Montana interim rates (subject to refund)	$	7.1
Montana property tax tracker collections	3.3
Lower non-recoverable Montana electric supply costs due to higher electric supply revenues and lower electric supply costs	3.0
Higher Montana natural gas transportation	0.4
Lower natural gas retail volumes	(5.3)
Lower electric retail volumes	(3.5)
Lower transmission revenue due to market conditions and lower rates	(1.7)
Other	(0.4)
Change in Utility Margin Items Impacting Net Income	$	2.9
Utility Margin Items Offset Within Net Income
Lower property taxes recovered in revenue, offset in property and other taxes	(7.2)
Lower operating expenses recovered in revenue, offset in operating and maintenance expense	(1.4)
Lower natural gas production taxes recovered in revenue, offset in property and other taxes	(0.4)
Higher revenue from lower production tax credits, offset in income tax expense	1.0
Change in Utility Margin Items Offset Within Net Income	(8.0)
Decrease in Consolidated Utility Margin(1)	$	(5.1)

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

Lower electric retail volumes were driven by unfavorable weather in Montana impacting residential demand and lower commercial demand, partly offset by customer growth and favorable weather in South Dakota. Lower natural gas retail volumes were driven by unfavorable weather in Montana, partly offset by customer growth. Interim rates in our Montana rate review were effective October 1, 2022, and are subject to refund, pending an outcome in the proceeding.

	Three Months Ended June 30,
	2023		2022		Change		% Change
	(dollars in millions)
Operating Expenses (excluding fuel, purchased supply and direct transmission expense)
Operating and maintenance	$	54.8	$	53.3	$	1.5	2.8	%
Administrative and general	30.0		27.2		2.8		10.3
Property and other taxes	40.1		46.9		(6.8)		(14.5)
Depreciation and depletion	52.4		48.2		4.2		8.7
Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense)	$	177.3	$	175.6	$	1.7	1.0	%

32

Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $177.3 million for the three months ended June 30, 2023, as compared with $175.6 million for the three months ended June 30, 2022. Primary components of the change include the following (in millions):

	Operating Expenses
	2023 vs. 2022
Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income
Higher labor and benefits(1)	$	4.4
Higher depreciation expense due to plant additions	4.2
Higher other state and local tax expense	0.9
Increase in uncollectible accounts	0.8
Higher insurance expense	0.4
Lower expenses at our electric generation facilities	(0.2)
Other	1.8
Change in Items Impacting Net Income	12.3
Operating Expenses Offset Within Net Income
Lower property taxes recovered in trackers, offset in revenue	(7.2)
Lower pension and other postretirement benefits, offset in other income(1)	(1.7)
Lower operating and maintenance expenses recovered in trackers, offset in revenue	(1.4)
Lower natural gas production taxes recovered in trackers, offset in revenue	(0.4)
Higher non-employee directors deferred compensation recorded within administrative and general expense, offset in other income	0.1
Change in Items Offset Within Net Income	(10.6)
Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense)	$	1.7

(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, 2023 was $45.6 million as compared with $52.3 million in the same period of 2022. This decrease was primarily driven by lower electric and natural gas retail volumes, lower transmission revenues, higher operating and maintenance expense, higher administrative and general expense, and higher depreciation and depletion expense, partly offset by higher Montana interim rates associated with our ongoing rate review, which are subject to refund, higher Montana property tax tracker collections, and lower non-recoverable Montana electric supply costs.

Consolidated interest expense was $28.4 million for the three months ended June 30, 2023 as compared with $24.0 million for the same period of 2022. This increase was due to higher borrowings and interest rates, partly offset by higher capitalization of Allowance for Funds Used During Construction (AFUDC).

Consolidated other income was $4.1 million for the three months ended June 30, 2023 as compared with $2.9 million for the same period of 2022. This increase was primarily due to the prior year CREP penalty, partly offset by an increase in the non-service component of pension expense.

Consolidated income tax expense was $2.1 million for the three months ended June 30, 2023 as compared to $1.4 million for the same period of 2022. Our effective tax rate for the three months ended June 30, 2023 was 10.1% as compared with 4.6% for the same period in 2022.

33

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

	Three Months Ended June 30,
	2023				2022
Income Before Income Taxes	$	21.3			$	31.2
Income tax calculated at federal statutory rate	4.5		21.0	%	6.6		21.0	%
Permanent or flow-through adjustments:
State income tax, net of federal provisions	0.3		1.3		0.4		1.4
Flow-through repairs deductions	(1.7)		(8.0)		(3.3)		(10.6)
Production tax credits	(1.1)		(5.4)		(2.6)		(8.2)
Amortization of excess deferred income tax	(0.2)		(1.1)		(0.2)		(0.5)
Plant and depreciation flow-through items	0.2		0.9		0.4		1.3
Other, net	0.1		1.4		0.1		0.2
	(2.4)		(10.9)		(5.2)		(16.4)
Income tax expense	$	2.1	10.1	%	$	1.4	4.6	%

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.

34

Six Months Ended June 30, 2023 Compared with the Six Months Ended June 30, 2022

Consolidated net income for the six months ended June 30, 2023 was $81.7 million as compared with $88.9 million for the same period in 2022. This decrease was primarily due to lower natural gas retail volumes, higher depreciation and depletion, higher operating and maintenance expense, higher administrative and general expense, higher interest expense, and higher income tax expense, including a one-time charge for the reduction of previously claimed alternative minimum tax credits, partly offset by Montana interim rates associated with our ongoing rate review, which are subject to refund, higher electric retail volumes, lower non-recoverable Montana electric supply costs, and higher Montana property tax tracker collections.

Consolidated gross margin for the six months ended June 30, 2023 was $206.4 million as compared with $190.3 million in 2022, an increase of $16.1 million, or 8.5 percent. This increase was primarily due to Montana interim rates associated with our ongoing rate review, which are subject to refund, higher electric retail volumes, lower non-recoverable Montana electric supply costs, and higher Montana property tax tracker collections, partly offset by lower natural gas retail volumes, higher depreciation and depletion, and higher operating and maintenance expense.

	Electric				Natural Gas				Total
	2023		2022		2023		2022		2023		2022
	(in millions)
Reconciliation of gross margin to utility margin:
Operating Revenues	$	524.6	$	515.1	$	220.5	$	202.3	$	745.1	$	717.4
Less: Fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion shown separately below)	120.5		135.3		112.6		94.8		233.1		230.1
Less: Operating and maintenance	83.8		80.3		26.9		25.8		110.7		106.1
Less: Property and other taxes	69.3		72.9		20.0		20.9		89.3		93.8
Less: Depreciation and depletion	87.2		80.6		18.4		16.5		105.6		97.1
Gross Margin	163.8		146.0		42.6		44.3		206.4		190.3
Operating and maintenance	83.8		80.3		26.9		25.8		110.7		106.1
Property and other taxes	69.3		72.9		20.0		20.9		89.3		93.8
Depreciation and depletion	87.2		80.6		18.4		16.5		105.6		97.1
Utility Margin(1)	$	404.1	$	379.8	$	107.9	$	107.5	$	512.0	$	487.3

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

	Six Months Ended June 30,
	2023		2022		Change		% Change
	(dollars in millions)
Utility Margin
Electric	$	404.1	$	379.8	$	24.3	6.4	%
Natural Gas	107.9		107.5		0.4		0.4
Total Utility Margin(1)	$	512.0	$	487.3	$	24.7	5.1	%

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

Consolidated utility margin for the six months ended June 30, 2023 was $512.0 million as compared with $487.3 million for the same period in 2022, an increase of $24.7 million, or 5.1 percent.

Primary components of the change in utility margin include the following (in millions):

35

	Utility Margin 2023 vs. 2022
Utility Margin Items Impacting Net Income
Montana interim rates (subject to refund)	$	15.6
Higher electric retail volumes	6.3
Lower non-recoverable Montana electric supply costs due to higher electric supply revenues and lower electric supply costs	4.3
Montana property tax tracker collections	3.5
Higher Montana natural gas transportation	1.5
Lower natural gas retail volumes	(1.6)
Lower transmission revenue due to market conditions and lower rates	(0.5)
Other	(0.3)
Change in Utility Margin Items Impacting Net Income	28.8
Utility Margin Items Offset Within Net Income
Lower property taxes recovered in revenue, offset in property and other taxes	(4.6)
Lower operating expenses recovered in revenue, offset in operating and maintenance expense	(1.7)
Lower natural gas production taxes recovered in revenue, offset in property and other taxes	(0.5)
Higher revenue from lower production tax credits, offset in income tax expense	2.7
Change in Utility Margin Items Offset Within Net Income	(4.1)
Increase in Consolidated Utility Margin(1)	$	24.7

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

Higher electric retail volumes were driven by customer growth and increased residential demand as compared to the prior year. Lower natural gas retail volumes were driven by overall unfavorable weather in Montana, partly offset by favorable weather in South Dakota and Nebraska and customer growth. Interim rates in our Montana rate review were effective October 1, 2022, and are subject to refund pending an outcome in the proceeding.

	Six Months Ended June 30,
	2023		2022		Change		% Change
	(dollars in millions)
Operating Expenses (excluding fuel, purchased supply and direct transmission expense)
Operating and maintenance	$	110.7	$	106.1	$	4.6	4.3	%
Administrative and general	64.7		58.9		5.8		9.8
Property and other taxes	89.3		93.7		(4.4)		(4.7)
Depreciation and depletion	105.6		97.1		8.5		8.8
Total Operating Expenses (excluding fuel, purchased supply and direct transmission expense)	$	370.3	$	355.8	$	14.5	4.1	%

36

Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $370.3 million for the six months ended June 30, 2023, as compared with $355.8 million for the six months ended June 30, 2022. Primary components of the change include the following (in millions):

	Operating Expenses
	2023 vs. 2022
Operating Expenses (excluding fuel, purchased supply and direct transmission expense) Impacting Net Income
Higher depreciation expense due to plant additions	$	8.5
Higher labor and benefits(1)	7.5
Higher expenses at our electric generation facilities	3.2
Increase in uncollectible accounts	1.1
Higher insurance expense	1.0
Higher other state and local tax expense	0.7
Lower technology implementation and maintenance expenses	(0.4)
Other	1.4
Change in Items Impacting Net Income	23.0
Operating Expenses Offset Within Net Income
Lower property taxes recovered in trackers, offset in revenue	(4.6)
Lower operating and maintenance expenses recovered in trackers, offset in revenue	(1.7)
Lower pension and other postretirement benefits, offset in other income(1)	(1.5)
Lower natural gas production taxes recovered in trackers, offset in revenue	(0.5)
Lower non-employee directors deferred compensation recorded within administrative and general expense, offset in other income	(0.2)
Change in Items Offset Within Net Income	(8.5)
Increase in Operating Expenses (excluding fuel, purchased supply and direct transmission expense)	$	14.5

(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, 2023 was $141.7 million as compared with $131.6 million in the same period of 2022. This increase was primarily driven by Montana interim rates associated with our ongoing rate review, which are subject to refund, higher electric retail volumes, lower non-recoverable Montana electric supply costs, and higher Montana property tax tracker collections, partly offset by lower natural gas retail volumes, higher depreciation and depletion expense, higher operating and maintenance expense, and higher administrative and general expenses.

Consolidated interest expense was $56.4 million for the six months ended June 30, 2023 as compared with $47.7 million for the same period of 2022. This increase was due to higher borrowings and interest rates, partly offset by higher capitalization of AFUDC.

Consolidated other income was $8.8 million for the six months ended June 30, 2023 as compared to $7.6 million during the same period of 2022. This increase was primarily due to the prior year CREP penalty, partly offset by an increase in the non-service component of pension expense.

Consolidated income tax expense for the six months ended June 30, 2023 was $12.4 million as compared to $2.5 million in the same period of 2022. Our effective tax rate for the six months ended June 30, 2023 was 13.2% as compared with 2.8% for the same period in 2022. 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):

37

	Six Months Ended June 30,
	2023				2022
Income Before Income Taxes	$	94.0			$	91.4
Income tax calculated at federal statutory rate	19.7		21.0	%	19.2		21.0	%
Permanent or flow-through adjustments:
State income tax, net of federal provisions	1.2		1.3		0.8		0.9
Flow-through repairs deductions	(7.6)		(8.0)		(10.1)		(11.1)
Production tax credits	(4.3)		(4.6)		(6.4)		(7.0)
Amortization of excess deferred income tax	(1.0)		(1.1)		(0.6)		(0.6)
Reduction to previously claimed alternative minimum tax credit	3.2		3.4		—		—
Plant and depreciation flow-through items	0.9		0.9		0.1		0.2
Share-based compensation	0.4		0.4		(0.3)		(0.3)
Other, net	(0.1)		(0.1)		(0.2)		(0.3)
	(7.3)		(7.8)		(16.7)		(18.2)
Income tax expense	$	12.4	13.2	%	$	2.5	2.8	%

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.

38

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, 2023 Compared with the Three Months Ended June 30, 2022

	Revenues				Change				Megawatt Hours (MWH)		Avg. Customer Counts
	2023		2022		$		%		2023	2022	2023	2022
	(in thousands)
Montana	$	83,840	$	70,715	$	13,125	18.6	%	568	590	321,820	316,180
South Dakota	15,686		15,593		93		0.6		135	123	51,162	50,925
Residential	99,526		86,308		13,218		15.3		703	713	372,982	367,105
Montana	101,919		84,327		17,592		20.9		759	772	74,234	72,826
South Dakota	25,134		26,445		(1,311)		(5.0)		266	261	12,985	12,882
Commercial	127,053		110,772		16,281		14.7		1,025	1,033	87,219	85,708
Industrial	10,722		8,988		1,734		19.3		644	608	78	76
Other	8,732		8,311		421		5.1		33	42	6,388	6,415
Total Retail Electric	$	246,033	$	214,379	$	31,654	14.8	%	2,405	2,396	466,667	459,304
Regulatory amortization	(36,254)		7,741		(43,995)		(568.3)
Transmission	18,352		20,005		(1,653)		(8.3)
Wholesale and Other	1,135		1,293		(158)		(12.2)
Total Revenues	$	229,266	$	243,418	$	(14,152)	(5.8)	%
Fuel, purchased supply and direct transmission expense(1)	42,363		57,695		(15,332)		(26.6)
Utility Margin(2)	$	186,903	$	185,723	$	1,180	0.6	%

(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			2023 as compared with:
	2023	2022	Historic Average	2022	Historic Average
Montana	44	40	64	10% warmer	31% cooler
South Dakota	201	66	72	205% warmer	179% warmer

	Heating Degree Days			2023 as compared with:
	2023	2022	Historic Average	2022	Historic Average
Montana(1)	1,017	1,402	1,156	27% warmer	12% warmer
South Dakota	1,613	1,593	1,484	1% colder	9% colder

(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 three months ended June 30, 2023 and 2022 (in millions):

	Utility Margin 2023 vs. 2022
Utility Margin Items Impacting Net Income
Montana interim rates (subject to refund)	$	6.7
Lower non-recoverable Montana electric supply costs due to higher electric supply revenues and lower electric supply costs	3.0
Montana property tax tracker collections	2.3
Lower retail volumes	(3.5)
Lower transmission revenue due to market conditions and lower rates	(1.7)
Qualifying facility (QF) liability adjustment	(0.1)
Other	(0.1)
Change in Utility Margin Items Impacting Net Income	6.6
Utility Margin Items Offset Within Net Income
Lower property taxes recovered in revenue, offset in property and other taxes	(5.0)
Lower operating expenses recovered in revenue, offset in operating and maintenance expense	(1.4)
Higher revenue from lower production tax credits, offset in income tax expense	1.0
Change in Utility Margin Items Offset Within Net Income	(5.4)
Increase in Utility Margin(1)	$	1.2

(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.

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

The 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 $5.0 million gain in 2023, as compared with a $5.1 million gain for the same period in 2022, due to the combination of:

•A $0.8 million favorable reduction in costs for the current contract year to record the annual adjustment for actual output and pricing as compared with a $1.8 million favorable reduction in costs in the prior period; and

•A favorable adjustment, 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 is the last year of the contract that contains variable pricing terms. This is compared to a favorable adjustment of $3.3 million in the prior year due to less than previously estimated actual price escalation.

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

Six Months Ended June 30, 2023 Compared with the Six Months Ended June 30, 2022

	Revenues				Change				Megawatt Hours (MWH)		Avg. Customer Counts
	2023		2022		$		%		2023	2022	2023	2022
	(in thousands)
Montana	$	209,302	$	167,668	$	41,634	24.8	%	1,439	1,415	321,278	315,811
South Dakota	35,457		36,023		(566)		(1.6)		330	312	51,218	50,964
Residential	244,759		203,691		41,068		20.2		1,769	1,727	372,496	366,775
Montana	214,532		170,861		43,671		25.6		1,610	1,581	74,249	72,722
South Dakota	50,262		54,079		(3,817)		(7.1)		545	552	12,964	12,848
Commercial	264,794		224,940		39,854		17.7		2,155	2,133	87,213	85,570
Industrial	22,563		18,642		3,921		21.0		1,270	1,236	79	76
Other	13,986		12,784		1,202		9.4		48	57	5,623	5,599
Total Retail Electric	$	546,102	$	460,057	$	86,045	18.7	%	5,242	5,153	465,411	458,020
Regulatory amortization	(61,551)		14,281		(75,832)		(531.0)
Transmission	37,245		37,695		(450)		(1.2)
Wholesale and Other	2,778		3,112		(334)		(10.7)
Total Revenues	$	524,574	$	515,145	$	9,429	1.8	%
Fuel, purchased supply and direct transmission expense(1)	120,497		135,318		(14,821)		(11.0)
Utility Margin(2)	$	404,077	$	379,827	$	24,250	6.4	%

(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.

	Cooling Degree Days			2023 as compared with:
	2023	2022	Historic Average	2022	Historic Average
Montana(1)	44	40	64	10% warmer	31% cooler
South Dakota	201	66	74	205% warmer	172% warmer

	Heating Degree Days			2023 as compared with:
	2023	2022	Historic Average	2022	Historic Average
Montana(1)	4,556	4,638	4,454	2% warmer	2% colder
South Dakota	5,957	5,688	5,603	5% colder	6% colder

(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 electric utility margin for the six months ended June 30, 2023 and 2022 (in millions):

	Utility Margin 2023 vs. 2022
Utility Margin Items Impacting Net Income
Montana interim rates (subject to refund)	$	15.1
Higher retail volumes	6.3
Lower non-recoverable Montana electric supply costs due to higher electric supply revenues and lower electric supply costs	4.3
Montana property tax tracker collections	2.5
Lower transmission revenue due to market conditions and lower rates	(0.5)
QF liability adjustment	(0.1)
Other	(0.3)
Change in Utility Margin Items Impacting Net Income	27.3
Utility Margin Items Offset Within Net Income
Lower property taxes recovered in revenue, offset in property and other taxes	(4.0)
Lower operating expenses recovered in revenue, offset in operating and maintenance expense	(1.7)
Higher revenue from lower production tax credits, offset in income tax expense	2.7
Change in Utility Margin Items Offset Within Net Income	(3.0)
Increase in Utility Margin(1)	$	24.3

(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 customer growth and increased residential demand as compared to the prior year.

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 $5.0 million gain in 2023, as compared with a $5.1 million gain for the same period in 2022, as further explained above in electric utility results for the three months ended June 30, 2023.

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.

42

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, 2023 Compared with the Three Months Ended June 30, 2022

	Revenues				Change				Dekatherms (Dkt)		Avg. Customer Counts
	2023		2022		$		%		2023	2022	2023	2022
	(in thousands)
Montana	$	17,589	$	28,596	$	(11,007)	(38.5)	%	1,864	2,701	183,669	181,694
South Dakota	8,375		9,408		(1,033)		(11.0)		703	715	41,914	41,355
Nebraska	7,457		7,357		100		1.4		508	524	37,711	37,569
Residential	33,421		45,361		(11,940)		(26.3)		3,075	3,940	263,294	260,618
Montana	9,918		14,697		(4,779)		(32.5)		1,147	1,464	25,714	25,309
South Dakota	5,505		6,425		(920)		(14.3)		675	663	7,217	7,021
Nebraska	4,665		4,456		209		4.7		387	386	5,004	4,977
Commercial	20,088		25,578		(5,490)		(21.5)		2,209	2,513	37,935	37,307
Industrial	160		222		(62)		(27.9)		19	21	232	233
Other	326		469		(143)		(30.5)		43	57	188	177
Total Retail Gas	$	53,995	$	71,630	$	(17,635)	(24.6)	%	5,346	6,531	301,649	298,335
Regulatory amortization	(3,369)		(1,204)		(2,165)		(179.8)
Wholesale and other	10,610		9,160		1,450		15.8
Total Revenues	$	61,236	$	79,586	$	(18,350)	(23.1)	%
Fuel, purchased supply and direct transmission expense(1)	25,215		37,305		(12,090)		(32.4)
Utility Margin(2)	$	36,021	$	42,281	$	(6,260)	(14.8)	%

(1) Exclusive of depreciation and depletion.

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

	Heating Degree Days			2023 as compared with:
	2023	2022	Historic Average	2022	Historic Average
Montana(1)	1,037	1,463	1,176	29% warmer	12% warmer
South Dakota	1,613	1,593	1,484	1% colder	9% colder
Nebraska	1,142	1,152	1,133	1% warmer	1% colder

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

43

The following summarizes the components of the changes in natural gas utility margin for the three months ended June 30, 2023 and 2022:

	Utility Margin 2023 vs. 2022
	(in millions)
Utility Margin Items Impacting Net Income
Lower retail volumes	$	(5.3)
Montana property tax tracker collections	1.0
Higher Montana natural gas transportation	0.4
Montana interim rates (subject to refund)	0.4
Other	(0.2)
Change in Utility Margin Items Impacting Net Income	(3.7)
Utility Margin Items Offset Within Net Income
Lower property taxes recovered in revenue, offset in property and other taxes	(2.2)
Lower gas production taxes recovered in revenue, offset in property and other taxes	(0.4)
Change in Utility Margin Items Offset Within Net Income	(2.6)
Decrease in Utility Margin(1)	$	(6.3)

(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.

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

44

Six Months Ended June 30, 2023 Compared with the Six Months Ended June 30, 2022

	Revenues				Change				Dekatherms (Dkt)		Avg. Customer Counts
	2023		2022		$		%		2023	2022	2023	2022
	(in thousands)
Montana	$	84,471	$	80,895	$	3,576	4.4	%	8,381	8,740	183,583	181,579
South Dakota	28,310		29,325		(1,015)		(3.5)		2,455	2,464	42,032	41,463
Nebraska	27,970		22,799		5,171		22.7		1,915	1,822	37,838	37,690
Residential	140,751		133,019		7,732		5.8		12,751	13,026	263,453	260,732
Montana	46,257		41,747		4,510		10.8		4,834	4,723	25,690	25,286
South Dakota	19,791		20,950		(1,159)		(5.5)		2,177	2,153	7,235	7,035
Nebraska	17,828		13,683		4,145		30.3		1,386	1,266	5,040	5,008
Commercial	83,876		76,380		7,496		9.8		8,397	8,142	37,965	37,329
Industrial	889		773		116		15.0		94	88	232	232
Other	1,122		1,160		(38)		(3.3)		136	151	188	176
Total Retail Gas	$	226,638	$	211,332	$	15,306	7.2	%	21,378	21,407	301,838	298,469
Regulatory amortization	(28,770)		(27,774)		(996)		3.6
Wholesale and other	22,602		18,783		3,819		20.3
Total Revenues	$	220,470	$	202,341	$	18,129	9.0	%
Fuel, purchased supply and direct transmission expense(1)	112,573		94,756		17,817		18.8
Utility Margin(2)	$	107,897	$	107,585	$	312	0.3	%

(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			2023 as compared with:
	2023	2022	Historic Average	2022	Historic Average
Montana(1)	4,629	4,746	4,484	2% warmer	3% colder
South Dakota	5,957	5,688	5,603	5% colder	6% colder
Nebraska	4,506	4,230	4,427	7% colder	2% colder

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

45

The following summarizes the components of the changes in natural gas utility margin for the six months ended June 30, 2023 and 2022:

	Utility Margin 2023 vs. 2022
	(in millions)
Utility Margin Items Impacting Net Income
Higher Montana natural gas transportation	$	1.5
Montana property tax tracker collections	1.0
Montana interim rates (subject to refund)	0.5
Lower retail volumes	(1.6)
Change in Utility Margin Items Impacting Net Income	1.4
Utility Margin Items Offset Within Net Income
Lower gas production taxes recovered in revenue, offset in property and other taxes	(0.5)
Higher property taxes recovered in revenue, offset in property tax expense	(0.6)
Change in Utility Margin Items Offset Within Net Income	(1.1)
Increase in Utility Margin(1)	$	0.3

(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.

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

46

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. 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, 2023, our total net liquidity was approximately $366.8 million, including $7.8 million of cash and $359.0 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,
	2023		2022
Operating Activities
Net income	$	81.7	$	88.9
Non-cash adjustments to net income	95.3		93.6
Changes in working capital	124.3		52.8
Other noncurrent assets and liabilities	(7.2)		(2.5)
Cash Provided by Operating Activities	294.1		232.8
Investing Activities
Property, plant and equipment additions	(263.4)		(234.4)
Investment in equity securities	(2.4)		(0.9)
Cash Used in Investing Activities	(265.8)		(235.3)
Financing Activities
Proceeds from issuance of common stock, net of issuance costs	10.8		99.9
Issuance of long-term debt	300.0		—
Line of credit repayments, net	(259.0)		(21.0)
Dividends on common stock	(76.1)		(67.8)
Other financing activities, net	(2.5)		(1.3)
Cash (Used in) Provided by Financing Activities	(26.8)		9.8
Increase in Cash, Cash Equivalents, and Restricted Cash	1.5		7.3
Cash, Cash Equivalents, and Restricted Cash, beginning of period	22.5		18.8
Cash, Cash Equivalents, and Restricted Cash, end of period	$	24.0	$	26.1

Operating Activities

As of June 30, 2023, cash, cash equivalents, and restricted cash were $24.0 million as compared with $22.5 million as of December 31, 2022 and $26.1 million as of June 30, 2022. Cash provided by operating activities totaled $294.1 million for the six months ended June 30, 2023 as compared with $232.8 million during the six months ended June 30, 2022. As shown in the table below, this increase in operating cash flows is primarily due to a $62.1 million improvement in collections of energy supply costs and interim rates in our Montana rate review, partly offset by lower net income.

47

Uncollected energy supply costs (in millions)
	Beginning of period		End of period		Net cash inflows
2022	$	99.1	$	75.8	$	23.3
2023	$	115.4	$	30.0	$	85.4
Improvement in net cash inflows					$	62.1

As of June 30, 2023, our remaining uncollected energy supply cost balance related to the July 2021 - June 2022 PCCAM period is approximately $13.5 million. In addition, we have approximately $18.5 million of uncollected energy supply costs related to the July 2022 - June 2023 PCCAM period that we expect to begin to collect in October 2023. On September 28, 2022, the MPSC approved our request for interim rates, which are subject to refund, including a $61.1 million increase to the PCCAM Base, which became effective in customer rates on October 1, 2022. Our under-collected position for the July 2022 - June 2023 PCCAM period improved $40.2 million due to the interim rate approved PCCAM Base increase.

If the settlement agreement is approved as submitted, we anticipate continued improvements in our cash flows from operations. However, unfavorable results in our Montana rate review, and continued higher overall market prices, which could be further exacerbated by extreme weather events, could create additional costs with deferred recovery that would offset these anticipated cash flow improvements.

Investing Activities

Cash used in investing activities totaled $265.8 million during the six months ended June 30, 2023, as compared with $235.3 million during the six months ended June 30, 2022. Plant additions during the first six months of 2023 include maintenance additions of approximately $142.2 million and capacity related capital expenditures of $121.2 million. Plant additions during the first six months of 2022 included maintenance additions of approximately $135.4 million and capacity related capital expenditures of approximately $99.0 million.

Financing Activities

Cash used in financing activities totaled $26.8 million during the six months ended June 30, 2023 as compared with cash provided by financing activities of $9.8 million during the six months ended June 30, 2022. 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, offset in part by net proceeds from the issuance of debt of $300.0 million and proceeds received from the issuance of common stock of $10.8 million. During the six months ended June 30, 2022, cash provided by financing activities reflects proceeds received from the issuance of common stock of $99.9 million, offset in part by payment of dividends of $67.8 million and net repayments under our revolving lines of credit of $21.0 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 our Annual Report on Form 10-K for the year ended December 31, 2022 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, 2023, 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.

48

Credit Facilities

Liquidity is generally provided by internal 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.

Our $425 million Credit Facility has a maturity date of May 18, 2027. The Credit Facility includes uncommitted features that allow us to request up to two one-year extensions to the maturity date and increase the size by an additional $75 million with the consent of the lenders. The Credit Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) secured overnight financing rate as administered by the Federal Reserve Bank of New York (SOFR), plus a credit spread adjustment of 10.0 basis points, plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points. A total of nine banks participate in the facility, with no one bank providing more than 15 percent of the total availability.

Our $25 million Swingline Facility has a maturity date of March 27, 2025. The Swingline Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a margin of 90.0 basis points, or (b) a base rate plus a margin of 12.5 basis points.

As of June 30, 2023 and 2022 the outstanding balances on the above credit facilities were $191.0 million and $352.0 million, respectively. As of July 21, 2023, our availability under our revolving credit facilities was approximately $368.0 million, and there were no letters of credit outstanding.

Our $100 million Additional Credit Facility has a maturity date of April 28, 2024. The Additional Credit Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points, plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points. There is currently no amount outstanding associated with this Additional Credit Facility.

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. We have $100.0 million of debt maturing in March 2024, which we intend to refinance.

On March 30, 2023, we issued and sold $239.0 million aggregate principal amount of Montana First Mortgage Bonds at a fixed interest rate of 5.57 percent maturing on March 30, 2033. On this same day, we issued and sold $31.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.57 percent maturing on March 30, 2033. On May 1, 2023, we issued and sold an additional $30.0 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.42 percent maturing on May 1, 2033. These bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933. Proceeds were used to repay a portion of our outstanding borrowings under our revolving credit facilities and for other general corporate purposes. The bonds are secured by our electric and natural gas assets in Montana and South Dakota.

In June 2023, we amended our Equity Distribution Agreement to replace one of the sales agents. Pursuant to the Equity Distribution Agreement we may offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $200.0 million, through an At-the-Market (ATM) offering program, including an equity forward sales component. This is a three-year agreement, expiring on February 11, 2024. During the three months ended June 30, 2023, we issued 188,682 shares of common stock under the ATM program at an average price of $57.83 per share, for net proceeds of $10.8 million which is net of sales commissions and other fees paid of approximately $0.1 million.

On June 29, 2023, the City of Forsyth, Rosebud County, Montana issued $144.7 million principal amount of Pollution Control Revenue Refunding Bonds (2023 Pollution Control Bonds) on our behalf. The 2023 Pollution Control Bonds were issued at a fixed interest rate of 3.88 percent maturing on July 1, 2028. The proceeds of the issuance were loaned to us pursuant to a Loan Agreement and were deposited directly with U.S. Bank Trust Company, National Association, as trustee, for the redemption of the 2.00 percent, $144.7 million City of Forsyth Pollution Control Revenue Refunding Bonds due on August 1, 2023 that had previously been issued on our behalf. Pursuant to the Loan Agreement, we are obligated to make payments in such amounts and at such times as will be sufficient to pay, when due, the principal and interest on the 2023 Pollution Control Bonds. Our obligations under the Loan Agreement are secured by delivery of a like amount of our Montana First Mortgage

49

Bonds, which are secured by our Montana electric and natural gas assets. So long as we are making payments under the Loan Agreement, no payments under these mortgage bonds will be due. The 2023 Pollution Control Bonds were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended.

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. We anticipate issuing $63.6 million of common stock through our ATM program through the remainder of 2023.

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 21, 2023, our current ratings with these agencies are as follows:

	Senior Secured Rating	Senior Unsecured Rating	Outlook
Fitch	A-	BBB+	Stable
Moody’s	A3	Baa2	Stable
S&P	A-	BBB	Stable

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

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, 2023.

	Total		2023		2024		2025		2026		2027		Thereafter
	(in thousands)
Long-term debt(1)	$	2,670,660	$	—	$	100,000	$	325,000	$	105,000	$	166,000	$	1,974,660
Finance leases	10,405		1,606		3,338		3,596		1,865		—		—
Estimated pension and other postretirement obligations(2)	57,160		11,392		11,667		11,367		11,367		11,367		N/A
Qualifying facilities liability(3)	342,296		39,234		74,110		60,360		55,393		56,665		56,534
Supply and capacity contracts(4)	2,748,013		219,539		289,237		237,647		248,875		232,176		1,520,539
Contractual interest payments on debt(5)	1,581,732		54,698		113,075		103,748		97,658		89,133		1,123,420
Commitments for significant capital projects(6)	118,908		45,399		63,434		10,075		—		—		—
Total Commitments(7)	$	7,529,174	$	371,868	$	654,861	$	751,793	$	520,158	$	555,341	$	4,675,153

_________________________

(1)Represents cash payments for long-term debt and excludes $12.6 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 $64 to $136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $342.3 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $297.1 million.

50

(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 6.44 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.

Other Obligations - As a co-owner of Colstrip, we provided surety bonds of approximately $15.7 million and $17.3 million as of June 30, 2023 and December 31, 2022, respectively, to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Stations, Colstrip Montana (the AOC) as required by the MDEQ. As costs are incurred under the AOC, the surety bonds will be reduced.

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, income taxes and qualifying facilities liability. These policies were disclosed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2022. As of June 30, 2023, there have been no material changes in these policies.

51

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 our Annual Report on Form 10-K for the year ended December 31, 2022.

52

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.

53

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 our Annual Report on the Form 10-K for the year ended December 31, 2022 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.

54

ITEM 6.                      EXHIBITS -

(a) Exhibits

Exhibit 4.1 — Eighteenth Supplemental Indenture, dated as of May 1, 2023, between the Company and The Bank of New York Mellon, as trustee. (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated May 1, 2023, Commission File No. 1-10499).

Exhibit 4.2 — Nineteenth Supplemental Indenture, dated as of June 1, 2023, between the Company and The Bank of New York Mellon, as trustee. (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 5, 2023, Commission File No. 1-10499).

Exhibit 4.3 — Forty-third Supplemental Indenture, dated as of May 1, 2023, between the Company and The Bank of New York Mellon and Mary Miselis, as trustees. (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation's Current Report on Form 8-K, dated June 5, 2023, Commission File No. 1-10499).

Exhibit 4.4 - Indenture, dated as of June 1, 2023 between City of Forsyth, Rosebud County, Montana and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 29, 2023, Commission File No. 1-10499).

Exhibit 4.5 - Loan Agreement, dated as of June 1, 2023, by and between the City of Forsyth, Rosebud County, Montana, and NorthWestern Corporation (incorporated by reference to Exhibit 4.2 of NorthWestern Corporation's Current Report on Form 8-K, dated June 29, 2023, Commission File No. 1-10499).

Exhibit 4.6 - Bond Delivery Agreement, dated as of June 1, 2023, between NorthWestern Corporation and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 of NorthWestern Corporation's Current Report on Form 8-K, dated June 29, 2023, Commission File No. 1-10499).

Exhibit 4.7 - Forty-fourth Supplemental Indenture, dated as of June 1, 2023, between NorthWestern Corporation and The Bank of New York Mellon and Mary Miselis, as trustees (incorporated by reference to Exhibit 4.4 of NorthWestern Corporation's Current Report on Form 8-K, dated June 29, 2023, Commission File No. 1-10499).

Exhibit 10.1 — Amendment No. 1 to Equity Distribution Agreement by and among the Company, on the one hand, and JPMorgan Chase Bank, National Association, Bank of America N.A., Canadian Imperial Bank of Commerce and Bank of Montreal as forward purchasers and J.P. Morgan Securities LLC, BofA Securities, Inc., CIBC World Markets Corp. and BMO Capital Markets Corp., as sales agents and forward sellers (incorporated by reference to Exhibit 1.1 of NorthWestern Corporation's Current Report on Form 8-K, dated June 15, 2023, Commission File No. 1-10499).

Exhibit 31.1—Certification of chief executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 

Exhibit 31.2—Certification of chief financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.1—Certification of chief executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.2—Certification of chief financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

55

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

56

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 Corporation
Date:	July 25, 2023	By:	/s/ CRYSTAL LAIL
			Crystal Lail
			Vice President and Chief Financial Officer
			Duly Authorized Officer and Principal Financial Officer

57