Slides
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Second Quarter Earnings Webinar July 30, 2026 8-K Date: July 30, 2026
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Forward-Looking Statements 2 Information in this communication, other than statements of historical facts, may constitute forward-looking statements, within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements include, but are not limited to, statements about the benefits of the proposed transaction between NorthWestern and Black Hills, including future financial and operating results (including the anticipated impact of the transaction on NorthWestern’s and Black Hills’ respective earnings), statements related to the expected timing of the completion of the transaction, the plans, objectives, expectations and intentions of either company or of the combined company following the merger, anticipated future results of either company or of the combined company following the merger, the anticipated benefits and strategic and financial rationale of the merger, including estimated rate bases, investment opportunities, cash flows and capital expenditure rates and other statements that are not historical facts. Forward-looking statements may be identified by terminology such as “may,” “will,” “should,” “targets,” “scheduled,” “plans,” “intends,” “goal,” “anticipates,” “expects,” “believes,” “forecasts,” “outlook,” “estimates,” “potential,” or “continue” or negatives of such terms or other comparable terminology. The forward-looking statements are based on NorthWestern and Black Hills’ current expectations, plans and estimates. NorthWestern and Black Hills believe these assumptions to be reasonable, but there is no assurance that they will prove to be accurate. All forward-looking statements are subject to risks, uncertainties and other factors that may cause the actual results, performance or achievements of NorthWestern or Black Hills to differ materially from any results expressed or implied by such forward-looking statements. Such factors include, among others, (1) the risk of delays in consummating the potential transaction, including as a result of required regulatory and shareholder approvals, which may not be obtained on the expected timeline, or at all, (2) the risk of any event, change or other circumstance that could give rise to the termination of the merger agreement, (3) the risk that required regulatory approvals are subject to conditions not anticipated by NorthWestern and Black Hills, (4) the possibility that any of the anticipated benefits and projected synergies of the potential transaction will not be realized or will not be realized within the expected time period, (5) disruption to the parties’ businesses as a result of the announcement and pendency of the transaction, including potential distraction of management from current plans and operations of NorthWestern or Black Hills and the ability of NorthWestern or Black Hills to retain and hire key personnel, (6) reputational risk and the reaction of each company’s customers, suppliers, employees or other business partners to the transaction, (7) the possibility that the transaction may be more expensive to complete than anticipated, including as a result of unexpected factors or events, (8) the outcome of any legal or regulatory proceedings that may be instituted against NorthWestern or Black Hills related to the merger agreement or the transaction, (9) the risks associated with third party contracts containing consent and/or other provisions that may be triggered by the proposed transaction, (10)legislative, regulatory, political, market, economic and other conditions, developments and uncertainties affecting NorthWestern’s and Black Hills’ businesses; (11) the evolving legal, regulatory and tax regimes under which NorthWestern and Black Hills operate; (12) restrictions during the pendency of the proposed transaction that may impact NorthWestern’s or Black Hills’ ability to pursue certain business opportunities or strategic transactions; and (13) unpredictability and severity of catastrophic events, including, but not limited to, extreme weather, natural disasters, acts of terrorism or outbreak of war or hostilities, as well as NorthWestern’s and Black Hills’ response to any of the aforementioned factors. Additional factors which could affect future results of NorthWestern and Black Hills can be found in NorthWestern Energy’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K, and Black Hills’ Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K, in each case filed with the SEC and available on the SEC’s website at http://www.sec.gov. NorthWestern and Black Hills disclaim any obligation and do not intend to update or revise any forward-looking statements contained in this communication, which speak only as of the date hereof, whether as a result of new information, future events or otherwise, except as required by federal securities laws. See Appendix for Additional Merger Related Disclosures.
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NorthWestern Energy 3 NorthWestern Energy Group, Inc. dba: NorthWestern Energy Ticker: NWE (Nasdaq) www.northwesternenergy.com Corporate Support Office 3010 West 69th Street Sioux Falls, SD 57108 (605) 978-2900 Director - Corporate Development & Investor Relations Officer Travis Meyer 605-978-2967 travis.meyer@northwestern.com
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Recent Highlights ✓ Reported GAAP diluted EPS of $0.40 o Non-GAAP diluted EPS of $0.501 o Affirming 2026 earnings guidance range of $3.68 - $3.832 o Affirming long-term rate base and EPS growth rates targets of 4% - 6%3 ✓ Merger Progress o Received approvals from the Nebraska PSC, South Dakota PUC, and FERC o Montana hearing and final briefing completed, awaiting final order ✓ Dividend Declared: $0.67 per share payable September 1, 2026 o This change in payment date, and August 17 record date, align with Black Hills Corp. dividend dates and is intended to simplify the closing mechanics in the merger. (1) See slides “Second Quarter 2026 Non-GAAP Earnings” and “Non-GAAP Financial Measures” that follow. (2) See “Strong Growth Outlook” slide that follows for major assumptions included in guidance. (3) Based on 2024 Adjusted Diluted Non-GAAP EPS of $3.40 and 2024 estimated rate base of $5.38 billion. See “Non-GAAP Financial Measures” slide in appendix for additional information. 4 In June 2026, NorthWestern’s operations teams at the Black Eagle, Cochrane, Morony, Rainbow, and Ryan Dams were honored with the Occupational Safety and Health Administrations Voluntary Protection Program (VPP) Star Worksite designation, the highest safety recognition from OSHA. Ryan Dam near Great Falls, Montana
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Thank youSecond Quarter Financial Review 5
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Second Quarter 2026 Financial Results 6 (1) Utility Margin is a non- GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure. Note: Subtotal variances may exist due to rounding.
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Second Quarter EPS vs Prior Period • GAAP: $0.05 or 14.3% • Non-GAAP1: $0.10 or 25.0% Second Quarter Net Income vs Prior Period • GAAP: $3.8 or 17.9% • Non-GAAP1: $7.0 or 29.0% Second Quarter 2026 Financial Results 7 (1) See “Second Quarter 2026 Non-GAAP Earnings” and “Non-GAAP Financial Measures” slides that follow.
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Year-to-Date EPS vs Prior Period • GAAP: $0.17 or (10.6)% • Non-GAAP1: $0.19 or 11.7% Year-to-Date Net Income vs Prior Period • GAAP: $9.7 or (9.9)% • Non-GAAP1: $12.2 or 12.3% Year-to-Date 2026 Financial Results 8 (1) See “Year-to-Date 2026 Non-GAAP Earnings” and “Non-GAAP Financial Measures” slides that follow.
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Second Quarter 2026 Earnings Drivers 9 (1) Utility Margin is a non-GAAP measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure. (2) See “Second Quarter 2026 Non-GAAP Earnings” and “Non-GAAP Financial Measures” slides that follow. After - Tax EPS vs Prior Year The increase in GAAP diluted EPS for the quarter vs prior year was primarily due to new rates and retail volumes, partly offset by OA&G expense, including merger- related costs and costs associated with our additional ownership interests in Colstrip, depreciation expense, and interest expense.
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Second Quarter 2026 Utility Margin Bridge 10 Pre - Tax Millions vs Prior Year Note: Utility Margin is a non-GAAP measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure. (1) Including a $2.0 million increase due to acquisition of Energy West Operations. $31.6 million or 11.8% increase in Utility Margin items that impact Net Income
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We estimate weather to be a $0.9 million pre-tax detriment as compared to normal, and a $1.6 million benefit as compared to second quarter 2025. (1) As a result of the adoption of Accounting Standard Update 2017-07 in March 2018, pension and other employee benefit expense is now disaggregated on the GAAP income statement with portions now recorded in both OG&A expense and Other (Expense) Income lines. To facilitate better understanding of trends in year-over-year comparisons, the non-GAAP adjustment above re-aggregates the expense in OG&A - as it was historically presented prior to the ASU 2017-07 (with no impact to net income or earnings per share). (2) Certain merger-related costs are not tax- deductible. (3) Power prices in the Pacific Northwest associated with the designated power sales contracts included within our temporary PCCAM tariff waiver were insufficient to recover the operating expenses associated with the Avista Interests. (4) Utility Margin is a non-GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure. Second Quarter 2026 Non-GAAP Earnings 11 Note: Subtotal variances may exist due to rounding.
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12 Affirming 2026 Non-GAAP EPS Guidance of $3.68 - $3.83 per diluted share ✓ Affirming long-term growth rate from 2024 base1 • EPS growth of 4% to 6% • Rate base growth of 4% to 6% • Continued focus on closing the gap between earned & authorized returns ✓ $3.2 billion 5-year capital plan including approximately $300 million of investment for generation development in South Dakota ✓ Cash from operations and debt to fund base capital plan. Equity issuances expected beginning in 2027 to fund South Dakota generation investment ✓ Targeting FFO / Debt > 14% (1) Based on 2024 Adjusted Diluted Non-GAAP EPS of $3.40 and 2024 estimated rate base of $5.38 billion. See “Non-GAAP Financial Measures” slide in appendix for additional information. Strong Growth Outlook The 2026 Non-GAAP EPS guidance range is based upon, but not limited to, the following major assumptions: • Normal weather in our service territories; • Excludes costs related to the pending merger with Black Hills Corp.; • Approval of PCCAM waiver and power prices sufficient to recover operating expense from incremental Avista and Puget Colstrip interests; • An effective income tax rate of approximately 14%-18%; and • Diluted average shares outstanding of approximately 61.8 million.
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Highly diversified, executable, and low-risk critical capital investment plan. Regulated Utility Five-Year Capital Plan (millions) 13
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Thank youBusiness Updates 14
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15 Merger with Black Hills Benefits Stakeholders Strategic combination represents a highly attractive value creation opportunity for both companies. Increases Scale Position and Growth Increases the combined company target EPS growth rate to 5-7%, supported by the doubling of each company’s rate base to total of ~$11 bn with significant growth opportunities Expands Investment Opportunity Leverages enhanced resources to make strategic investments that foster economic development, including addressing the growing demand for energy, including from data centers Substantial Long-Term Value for Customers Enhances Business Diversity Delivering energy to more than 2.2 mm customers across multiple contiguous jurisdictions, served by a highly skilled workforce focused on safety and reliability Strengthens Balance Sheet Strong and predictable cash flows support a customer-focused capital investment program while producing high-quality, investment- grade credit metrics Bringing together two complementary teams focused on reliability and exceptional customer service to deliver even greater value. For more information, see www.blackhillsnorthwesternbettertogether.com
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Merger with Black Hills Timeline 16 ✓ Filed joint applications for approval in Montana, Nebraska, and South Dakota in Q4 2025 ✓ Nebraska hearing held April 7, 2026; unanimous approval of settlements received May 19, 2026 ✓ South Dakota hearing held and unanimous approval of settlements received June 24, 2026 ✓ Settlements reached with certain key intervenors in Montana o Montana hearing concluded May 15, 2026; final briefs submitted July 13, 2026; awaiting final order ✓ Filed joint application with FERC on December 22, 2025 ✓ FERC approval received May 29, 2026 ✓ Filed S-4/Joint Proxy Statement on January 30, 2026 ✓ Shareholder approvals received by both companies on April 2, 2026 ✓ Filed Hart-Scott-Rodino on March 20, 2026 ✓ 30-day waiting period expired April 20, 2026, satisfying a U.S. antitrust condition to closing
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17 Data Center Process (Montana & South Dakota) Data Center Request • Load & Location • Supply Potential • Customer/Developer Required Timing Queue Count: 6 (8 in Q1 2026) High-Level Assessment • Viability Assessment • Southwest Power Pool Screening • High Level Cost Estimate Energy Service Agreement (ESA) • Regulatory Approvals (as needed) • Contract Signing • Business Development Handoff Construction • Project Management Assignment • Construction Kick-Off • Supply Development • Generation Build Process Development Agreement • Deposit Funds Studies (Montana: System Impact Study & Facility Study, South Dakota: Southwest Power Pool Delivery Point Network Study) Queue Count: 8 (4 in Q1 2026) Queue Count: 3 (3 in Q1 2026) Queue Count: 0 (0 in Q1 2026) Queue Count: 0 (0 in Q1 2026)
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✓ Montana ▪ Expected to be served by overall utility portfolio, which is long capacity beginning in 2026 ▪ Diversified and highly carbon-free generating portfolio ▪ Submitted a Large New Load tariff rule proposal with the MPSC in March 2026 ✓ South Dakota ▪ Significant indications of interest ▪ Any new large-load customers would require incremental capacity with infrastructure rider to provide generation cost recovery ▪ South Dakota PUC has an established process for large-load customers with a deviated rate tariff 18 Large-Load Customers Montana Large-Load Opportunities ✓ Announced: December 17, 2024 ▪ Company: Sabey Data Centers ▪ Study Load: 50 MW ramping to 200 MW ▪ Targeted Start Date: Mid-2028 ▪ Agreement Status: Development Agreement ✓ Announced: December 19, 2024 ▪ Company: Atlas Power ▪ Study Load: 75 MW ramping to 150 MW ▪ Targeted Start Date: Late 2027 ▪ Agreement Status: Development Agreement ✓ Announced: July 30, 2025 ▪ Company: Quantica Infrastructure ▪ Study Load: 25 MW ramping to 1,100 MW ▪ Targeted Start Date: Early 2029 ▪ Agreement Status: Development Agreement
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8% to 10% Total Return >10% Total Return Incremental Opportunities: > 6% EPS Growth Approximately 4% Dividend Yield Base Capital Plan: 4% to 6% EPS Growth ✓ Data centers & new large- load opportunities ✓ FERC Regional Transmission ✓ Incremental generating capacity (subject to successful resource procurement bids) $3.21 billion of highly diversified, executable and low-risk critical capital investment forecasted over the next five years. This investment is expected to drive annualized earnings and rate base growth of approximately 4% - 6%. + The NorthWestern Value Proposition + 19 = = 2026-2030 Capital Investment ($ Millions)
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Conclusion Pure Electric & Gas Utility Solid Utility Foundation Best Practices Corporate Governance Attractive Future Growth Prospects Strong Earnings & Cash Flows 20 The pending merger with Black Hills Corporation will combine the strengths of both companies, resulting in an organization with greater scale, financial stability, and operational expertise and is designed to create a stronger, more resilient energy company focused on delivering safe, reliable, and affordable energy solutions to customers.
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Thank youAppendix: 21
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Colstrip Transaction Overview 22 Announcement: Effective Date: Capacity: Acquisition Price: Status Update: Puget July 2024 December 31, 2025 370 MW (185 MW each of units 3 & 4) $0.0 Signed contract in October 2025 to sell the dispatchable capacity and associated energy through late 2027. Revenue from the contract is expected to largely offset the ~$30 million of incremental annual operating costs resulting from the transfer. Filed with FERC for cost- based rates in October 2025, with approval received in February 2026 retroactive to January 1, 2026. Avista January 2023 December 31, 2025 222 MW (111 MW each of units 3 & 4) $0.0 Filed a temporary PCCAM tariff waiver request with the MPSC in August 2025 that would provide a near-term cost-recovery mechanism to offset a portion of the ~$18.0 million of incremental annual operating costs resulting from the transfer. The waiver was temporarily granted in January 2026. NorthWestern’s acquisition of Avista and Puget’s 592 MW of additional Colstrip capacity: • Avista interests advance our regulated portfolio to resource adequacy and increase facility ownership from 15% to 30% • Puget interests move ownership from 30% to 55% which provides the ability to determine strategic direction and investment decisions at the facility • Combined interests support the integration of large-load customers, delivering substantial benefits to our customers, communities, and investors Avista and Puget Sound will remain responsible for their respective pre-closing share of environmental, asset retirement obligations, and pension liabilities attributed to events or conditions existing prior to the closing of the transaction and for any future decommissioning and demolition costs associated with the existing facilities that comprise their interests Appendix
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(1) The revenue requirement associated with the FERC regulated portion of Montana electric transmission and ancillary services are included as revenue credits to our MPSC jurisdictional customers. Therefore, we do not separately reflect FERC authorized rate base or authorized returns. (2) The Montana gas revenue requirement includes a step-down which approximates annual depletion of our natural gas production assets included in rate base. (3) This jurisdiction was acquired in 2025 as part of the acquisition of Energy West Operations. (4) This table excludes insignificant jurisdictions for Montana propane delivery, Havre Pipeline Company, and Cut Bank Gas natural gas delivery. (5) For those items marked as "n/a," the respective settlement and/or order was not specific as to these terms. Coal Generation Rate Base as a percentage of Total Rate Base Revenue from coal generation is not easily identifiable due to the use of bundled rates in South Dakota and other rate design and accounting considerations. However, NorthWestern is a fully regulated utility company for which rate base is the primary driver of earnings. The data to the left illustrates that NorthWestern only derives approximately 7-8% of earnings from its jointly owned coal generation rate base. Rate Base & Authorized Return Summary Appendix 23
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Thank youSecond Quarter Appendix 24
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Second Quarter 2026 Financial Results 25 (1) Utility Margin is a non- GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure. Note: Subtotal variances may exist due to rounding. Appendix
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Utility Margin (Q2) ($ in millions) Three Months Ended June 30, 2026 2025 Variance Electric $ 251.4 $ 219.8 $ 31.6 14.4% Natural Gas 51.4 47.6 3.8 8.0% Total Utility Margin1 $ 302.8 $ 267.4 $ 35.4 13.2% Increase in utility margin due to the following factors: $ 13.8 Base rates 7.3 Electric retail volumes 4.7 Electric margin from the acquisition of the Puget Interests 3.5 Natural gas retail volumes (including a $2.0 million increase due to acquisition of Energy West Operations) 1.0 Electric transmission revenue 0.8 Non-recoverable Montana electric supply costs (0.4) Natural gas production step down (0.2) Montana property tax tracker collections 1.1 Other $ 31.6 Change in Utility Margin Impacting Net Income $ 2.4 Operating expenses recovered in revenue, offset in operating and maintenance expense 1.4 Production tax credits, offset in income tax expense $ 3.8 Change in Utility Margin Offset Within Net Income $ 35.4 Increase in Consolidated Utility Margin 26 Appendix Note: Subtotal variances may exist due to rounding.(1) Utility Margin is a non-GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure.
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Operating Expenses (Q2) Increase in operating expenses due to the following factors: $ 9.0 Electric generation maintenance (Including $6.4 million and $3.7 million due to the acquisition of the Colstrip Puget Interests and Avista Interests, respectively) 4.6 Depreciation expense due to plant additions and higher depreciation rates 3.3 Merger-related costs, including consulting and legal fees 2.6 Wildfire mitigation expense, partly offset by higher base revenues 2.0 Property and other taxes not recoverable within trackers 1.7 Labor and benefits 0.8 Technology implementation and maintenance expenses 0.3 Insurance expense 0.2 Uncollectible accounts 2.1 Other $ 26.6 Change in Operating Expense Items Impacting Net Income ($ in millions) Three Months Ended June 30, 2026 2025 Variance Operating & maintenance $ 79.1 $ 62.3 $ 16.8 27.0% Administrative & general 42.4 33.8 8.6 25.4% Property & other taxes 50.1 48.2 1.9 3.9% Depreciation & depletion 67.0 62.4 4.6 7.4% Total Operating Expenses* $ 238.6 $ 206.7 $ 31.9 15.4% $ 3.0 Deferred compensation, offset in other income 2.4 Operating and maintenance expenses recovered in trackers, offset in revenue (0.1) Property and other taxes recovered in trackers, offset in revenue $ 5.3 Change in Operating Expense Items Offset Within Net Income $ 31.9 Increase in Operating Expenses* *Excluding fuel, purchased supply, and direct transmission expense. 27 Appendix
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Operating to Net Income (Q2) ($ in millions) Three Months Ended June 30, 2026 2025 Variance Operating Income $ 64.2 $ 60.8 $3.4 5.6% Interest Expense, net (40.3) (36.3) 4.0 11.0% Other Income, net 4.5 0.1 4.4 4400.0% Income Before Income Taxes 28.5 24.6 3.9 15.9% Income Tax Expense (3.5) (3.4) 0.1 2.9% Net Income $ 25.0 $ 21.2 $3.8 17.9% 28 Appendix Note: Subtotal variances may exist due to rounding.
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Tax Reconciliation (Q2) 29 Appendix
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Segment Results (Q2) 30 Appendix *Direct transmission expense excludes depreciation and depletion. (1) Utility Margin is a non-GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure. (2) Consists of unallocated corporate costs, including merger-related costs, and certain limited unregulated activity within the energy industry.
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Electric Segment (Q2) (1) Utility Margin is a non-GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure. 31 Appendix
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Natural Gas Segment (Q2) 32 Appendix (1) Utility Margin is a non-GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure.
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Thank you2026 Year-to-Date Appendix 33
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We estimate weather to be a $15.3 million pre-tax detriment as compared to normal, and a $15.0 million detriment as compared to second quarter 2025. Year-to-Date 2026 Non-GAAP Earnings 34 Note: Subtotal variances may exist due to rounding. Appendix (1) As a result of the adoption of Accounting Standard Update 2017-07 in March 2018, pension and other employee benefit expense is now disaggregated on the GAAP income statement with portions now recorded in both OG&A expense and Other (Expense) Income lines. To facilitate better understanding of trends in year-over-year comparisons, the non-GAAP adjustment above re-aggregates the expense in OG&A - as it was historically presented prior to the ASU 2017-07 (with no impact to net income or earnings per share). (2) Certain merger-related costs are not tax- deductible. (3) Power prices in the Pacific Northwest associated with the designated power sales contracts included within our temporary PCCAM tariff waiver were insufficient to recover the operating expenses associated with the Avista Interests. (4) Utility Margin is a non-GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure.
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Year-to-Date 2026 Financial Results 35 (1) Utility Margin is a non- GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure. Note: Subtotal variances may exist due to rounding. Appendix
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Utility Margin (YTD) ($ in millions) Six Months Ended June 30, 2026 2025 Variance Electric $ 523.2 $ 462.6 $ 60.6 13.1% Natural Gas 131.6 133.3 (1.7) (1.3%) Total Utility Margin1 $ 654.8 $ 595.9 $ 58.9 9.9% (1) Utility Margin is a non-GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure. Increase in utility margin due to the following factors: $ 37.5 Base rates 10.2 Electric margin from the acquisition of the Puget Interests 5.4 Electric transmission revenue 2.8 Non-recoverable Montana electric supply costs (4.9) Electric retail volumes (3.5) Montana property tax tracker collections (2.7) Natural gas retail volumes (including a $5.2 million increase due to acquisition of Energy West Operations) (1.1) Natural gas production step down 2.9 Other $ 46.6 Change in Utility Margin Impacting Net Income $ 5.1 Property & other taxes recovered in revenue, offset in property & other taxes 4.0 Production tax credits, offset in income tax expense 3.2 Operating expenses recovered in revenue, offset in operating & maintenance expense $ 12.3 Change in Utility Margin Offset Within Net Income $ 58.9 Increase in Consolidated Utility Margin 36 Appendix Note: Subtotal variances may exist due to rounding.
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Operating Expenses (YTD) Increase in operating expenses due to the following factors: $ 19.1 Electric generation maintenance (Including $12.7 million and $7.6 million due to the acquisition of the Colstrip Puget Interests and Avista Interests, respectively) 9.0 Depreciation expense due to plant additions and higher depreciation rates 6.7 Merger-related costs, including consulting and legal fees 5.2 Labor and benefits(1) 4.5 Wildfire mitigation expense, partly offset by higher base revenues 4.0 Property and other taxes not recoverable within trackers 1.0 Insurance expense 1.0 Technology implementation and maintenance expenses 0.7 Uncollectible accounts 5.3 Other $ 56.5 Change in Operating Expense Items Impacting Net Income ($ in millions) Six Months Ended June 30, 2026 2025 Variance Operating & maintenance $ 153.6 $ 119.0 $ 34.6 29.1% Administrative & general 88.5 75.1 13.4 17.8% Property & other taxes 100.5 91.4 9.1 10.0% Depreciation & depletion 133.8 124.8 9.0 7.2% Total Operating Expenses* $ 476.4 $ 410.3 $ 66.1 16.1% $ 5.1 Property and other taxes recovered in trackers, offset in revenue 3.2 Operating and maintenance expenses recovered in trackers, offset in revenue 2.0 Deferred compensation, offset in other income (0.7) Pension and other postretirement benefits, offset in other income (1) $ 9.6 Change in Operating Expense Items Offset Within Net Income $ 66.1 Increase in Operating Expenses* *Excluding fuel, purchased supply, and direct transmission expense. (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. 37 Appendix
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Operating to Net Income (YTD) ($ in millions) Six Months Ended June 30, 2026 2025 Variance Operating Income $ 178.4 $ 185.5 ($7.1) (3.8%) Interest Expense, net (80.2) (72.8) 7.4 10.2% Other Income, net 7.6 4.0 3.6 90.0% Income Before Income Taxes 105.7 116.8 (11.1) (9.5%) Income Tax Expense (17.3) (18.6) (1.3) (7.0%) Net Income $ 88.5 $ 98.2 ($9.7) (9.9%) 38 Appendix Note: Subtotal variances may exist due to rounding.
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Tax Reconciliation (YTD) 39 Appendix
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Segment Results (YTD) 40 Appendix *Direct transmission expense excludes depreciation and depletion. (1) Utility Margin is a non-GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure. (2) Consists of unallocated corporate costs, including merger-related costs, and certain limited unregulated activity within the energy industry.
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Electric Segment (YTD) (1) Utility Margin is a non-GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure. 41 Appendix
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Natural Gas Segment (YTD) 42 Appendix (1) Utility Margin is a non-GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure.
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Cash from Operating Activities increased by $21.6 million. The increase in cash provided by working capital is primarily due to a decrease in our net cash outflows for energy supply costs, as shown in the table below. Funds from Operations decreased by $12.9 million over prior period. Net Under-Collected Supply Costs ($ in millions) Beginning (Jan. 1) Ending (June 30) Inflow / (Outflow) 2025 $5.9 $28.6 ($22.7) 2026 $44.8 $51.9 ($7.1) 2026 Decrease in Net Cash Outflows $15.6 Year-to-Date 2026 Cash Flow 43 No Planned Equity Issuances in 2026 Financing plans (targeting a FFO to Debt ratio > 14%) are expected to maintain our current credit ratings and are subject to change Debt financing in 2026 • Amended our existing NorthWestern Energy Group $150 million term loan to extend the maturity date from April 10, 2026 to December 31, 2026 in Q2. • Issued $150 million, 5.51% coupon, 10-year South Dakota FMBs in Q2. • Entered $225 million NorthWestern Corp. Term Loan Credit Agreement with a maturity date of November 26, 2027 in Q2. Appendix
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Balance Sheet 44 Appendix Debt to Total Capitalization slightly up from last quarter and just above our targeted 50% - 55% range.
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Reconciling Gross Margin to Utility Margin Management believes 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, 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 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. Note: Subtotal variances may exist due to rounding. (1) Utility Margin is a non-GAAP Measure. 45 Appendix
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PCCAM Impact by Quarter 46 Appendix Pre-Tax $ Millions – Shareholder (Detriment) Benefit Note: • Effective February 1, 2026 the cost sharing mechanism of the PCCAM was suspended on an interim basis pending further review by the MPSC. • Subtotal variances may exist due to rounding.
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Qualified Facility Earnings Adjustment Our electric QF liability consists of unrecoverable costs associated with contracts covered under PURPA that are part of a 2002 stipulation with the MPSC and other parties. Risks / losses associated with these contracts are born by shareholders, not customers. Therefore, any mitigation of prior losses and / or benefits of liability reduction also accrue to shareholders. 47 Appendix
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Non-GAAP Financial Measures 48 Appendix Pre-Tax Adjustments ($ Millions) 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Reported GAAP Pre-Tax Income 156.5$ 176.1$ 178.3$ 182.2$ 144.2$ 190.2$ 182.4$ 201.6$ 214.7$ 187.6$ Non-GAAP Adjustments to Pre-Tax Income: Weather 15.2 (3.4) (1.3) (7.3) 9.8 1.1 (8.9) 4.3 10.6 14.4 Lost revenue recovery related to prior periods (14.2) - - - - - - - - - QF liability adjustment - - (17.5) - - (6.9) - - - - Electric tracker disallowance of prior period costs 12.2 - - - 9.9 - - - - - Income tax adjustment - - 9.4 - - - - - - - Community Renewable Energy Project Penalty - - - - - - 2.5 - (2.3) 1.3 Impairment of Alternative Energy Storage Investment - - - - - - - - 4.2 - NWE-BKH Merger Transaction Costs (not tax deductible) - - - - - - - - - 9.3 Regulatory Disallowance of Certain YCGS Capital Costs - - - - - - - - - 31.2 Remove Q4 2025 PCCAM Expense Following Suspension of 90/10 Sharing - - - - - - - - - 2.3 Adjusted Non-GAAP Pre-Tax Income 169.7$ 172.7$ 168.9$ 174.9$ 163.9$ 184.4$ 176.0$ 205.9$ 227.2$ 246.1$ Tax Adjustments to Non-GAAP Items ($ Millions) 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 GAAP Net Income 164.2$ 162.7$ 197.0$ 202.1$ 155.2$ 186.8$ 183.0$ 194.1$ 224.1$ 181.1$ Non-GAAP Adjustments Taxed at 38.5% (12'-17') and 25.3% (18'-current): Weather 9.3 (2.1) (1.0) (5.5) 7.3 0.8 (6.6) 3.2 7.9 10.8 Lost revenue recovery related to prior periods (8.7) - - - - - - - - - QF liability adjustment - - (13.1) - - (5.2) - - - - Electric tracker disallowance of prior period costs 7.5 - - - 7.4 - - - - - Income tax adjustment (12.5) - (12.8) (22.8) - - - - - - Community Renewable Energy Project Penalty - - - - - - 2.5 - (2.3) 1.3 Previously claimed AMT credit - - - - - - - 3.2 - - Release of Unrecognized Tax Benefit - - - - - - - (3.2) (16.9) (7.4) Impairment of Alternative Energy Storage Investment - - - - - - - - 3.1 - Natural Gas Safe Harbor Method Change - - - - - - - - (7.0) - NWE-BKH Merger Transaction Costs (not tax deductible) - - - - - - - - - 9.3 Regulatory Disallowance of Certain YCGS Capital Costs - - - - - - - - - 23.3 Remove Q4 2025 PCCAM Expense Following Suspension of 90/10 Sharing - - - - - - - - - 1.7 Non-GAAP Net Income 159.8$ 160.6$ 170.1$ 173.8$ 169.9$ 182.4$ 178.9$ 197.3$ 208.9$ 220.1$ Non-GAAP Diluted Earnings per Share 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Diluted Average Shares (Millions) 48.5 48.7 50.2 50.8 50.7 51.9 56.3 60.4 61.4 61.5 Reported GAAP Diluted Earnings per Share 3.39$ 3.34$ 3.92$ 3.98$ 3.06$ 3.60$ 3.25$ 3.22$ 3.65$ 2.94$ Non-GAAP Adjustments: Weather 0.19 (0.04) (0.02) (0.11) 0.14 0.01 (0.11) 0.05 0.13 0.18 Lost revenue recovery related to prior periods (0.18) - - - - - - - - - QF liability adjustment - - (0.26) - - (0.10) - - - - Electric tracker disallowance of prior period costs 0.16 - - - 0.15 - - - - - Income tax adjustment (0.26) - (0.25) (0.45) - - - - - - Community Renewable Energy Project Penalty - - - - - - 0.04 - (0.04) 0.02 Previously claimed AMT credit - - - - - - - 0.05 - - Release of Unrecognized Tax Benefit - - - - - - - (0.05) (0.28) (0.12) Impairment of Alternative Energy Storage Investment - - - - - - - - 0.05 - Natural Gas Safe Harbor Method Change - - - - - - - - (0.11) - NWE-BKH Merger Transaction Costs (not tax deductible) - - - - - - - - - 0.15 Regulatory Disallowance of Certain YCGS Capital Costs - - - - - - - - - 0.38 Remove Q4 2025 PCCAM Expense Following Suspension of 90/10 Sharing - - - - - - - - - 0.03 Non-GAAP Diluted Earnings per Share 3.30$ 3.30$ 3.39$ 3.42$ 3.35$ 3.51$ 3.18$ 3.27$ 3.40$ 3.58$
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Non-GAAP Financial Measures This presentation includes financial information prepared in accordance with GAAP, as well as other financial measures, such as Utility Margin, Adjusted Non-GAAP pretax income, Adjusted Non-GAAP net income and Adjusted Non-GAAP Diluted EPS that are considered “non-GAAP financial measures.” 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 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 Consolidated Statements of Income. A reconciliation of Utility Margin to Gross Margin, the most directly comparable GAAP measure, is included in this presentation. Management believes 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, 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 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. Management also believes the presentation of Adjusted Non-GAAP pre-tax income, Adjusted Non-GAAP net income and Adjusted Non-GAAP Diluted EPS is more representative of normal earnings than GAAP pre-tax income, net income and EPS due to the exclusion (or inclusion) of certain impacts that are not reflective of ongoing earnings. The presentation of these non-GAAP measures is intended to supplement investors' understanding of our financial performance and not to replace other GAAP measures as an indicator of actual operating performance. Our measures may not be comparable to other companies' similarly titled measures. 49 Appendix
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