Second Quarter Earnings Webcast July 31, 2025 8-K Date: July 31, 2025
NorthWestern Energy 2 Forward Looking Statements During the course of this presentation, there will be forward-looking statements within the meaning of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address our expected future business and financial performance, and often contain words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” or “will.” The information in this presentation is based upon our current expectations as of the date of this document unless otherwise noted. Our actual future business and financial performance may differ materially and adversely from our expectations expressed in any forward-looking statements. We undertake no obligation to revise or publicly update our forward-looking statements or this presentation for any reason. Although our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. The factors that may affect our results are listed in certain of our press releases and disclosed in the Company’s 10-K and 10-Q along with other public filings with the SEC.
Recent Highlights ✓ Reported GAAP diluted EPS of $0.35 o Non-GAAP diluted EPS of $0.401 ✓ Initiating 2025 earnings guidance range of $3.53 - $3.652 ✓ Affirming long-term rate base and earnings per share growth rate targets of 4% - 6%3 ✓ Completed acquisition of Energy West and Cut Bank Gas •~33,000 customers and 43 valued employees ✓ Third Letter of Intent signed with 500+ megawatt data center developer4 ✓ Dividend Declared: $0.66 per share payable September 30, 2025 to shareholders of record as of September 15, 2025 1.) See “Second Quarter 2025 Non-GAAP Earnings” below and “Non-GAAP Financial Measures” in appendix. 2.) See “2025 Earnings Bridge” below for additional details and major assumptions included in guidance. 3.) Based on 2024 Adjusted Diluted Non-GAAP EPS of $3.40 and estimated rate base of $5.38 billion. 4.) See “Large Load Customers” below for additional details. 3 In June 2025, NorthWestern’s operations team at Hauser Dam was honored with the Occupational Safety and Health Administration’s Voluntary Protection Program (VPP) Star Worksite designation, the highest safety recognition from OSHA. Powerhouse at Hauser Dam on the Missouri River (near Helena, Montana)
9%-11% Total Return >11% Total Return Incremental Opportunities: > 6% EPS Growth ~5% Dividend Yield Base Capital Plan: 4%-6% EPS Growth ✓ Data centers & new large- load opportunities ✓ FERC Regional Transmission ✓ Incremental generating capacity (subject to successful resource procurement bids) $2.74 billion of highly executable and low-risk capital investment forecasted over the next five years. This investment is expected to drive annualized earnings and rate base growth of approximately 4% - 6%. See slide titled “Strong Growth Outlook” for additional information. + The NorthWestern Value Proposition + 4 = = 2025-2029 Capital Investment ($ Millions)
Thank youSecond Quarter Financial Review 5
Second Quarter 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.
Second Quarter 2025 Financial Results 7 1.) See “Second Quarter 2025 Non-GAAP Earnings” below and “Non-GAAP Financial Measures” in appendix. Second Quarter Net Income vs Prior Period • GAAP: $10.5 million or -33.1% • Non-GAAP1: $8.1 million or -25.2% Second Quarter EPS vs Prior Period • GAAP: $0.17 or -32.7% • Non-GAAP1: $0.13 or -24.5%
Year-to-Date 2025 Financial Results 8 1.) See “Year-to-Date 2025 Non-GAAP Earnings” below and “Non-GAAP Financial Measures” in appendix. Year-to-Date Net Income vs Prior Period • GAAP: $1.5 million or 1.6% • Non-GAAP1: $0.2 million or 0.2% Year-to-Date EPS vs Prior Period • GAAP: $0.02 or 1.3% • Non-GAAP1: No Change
Second Quarter Earnings Drivers 9 The decrease in diluted EPS during the quarter is primarily due to higher operating and other expenses partially offset by an improvement in Utility Margin. After-Tax EPS vs Prior Year 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 2025 Non-GAAP Earnings” below and “Non-GAAP Financial Measures” in appendix.
Second Quarter Utility Margin Bridge Pre-tax Millions vs. Prior Year $13.3 million or 5.5% increase in Utility Margin items that impact Net Income Note: Utility Margin is a non-GAAP measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure. 10
We estimate weather to be a $2.5 million pre-tax detriment as compared to normal and a $1.8 million detriment as compared to second quarter 2024. (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) Utility Margin is a non-GAAP Measure. See the slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosures. Second Quarter 2025 Non-GAAP Earnings 11 Note: Subtotal variances may exist due to rounding.
Credit, Cash Flow, and Financing Plans 12 Stable Outlook at Moody’s, S&P, and Fitch. No equity expected to fund the current $2.74 billion 5-year capital plan. Financing plans (targeting a FFO to Debt ratio > 14%) are expected to maintain our current credit ratings. We expect to pay minimal cash taxes into 2028 due to utilization of our NOL’s and tax credits. Financing plans are subject to change. FFO: Cash from Operations less Working Capital Adjustments. Debt: Long- & Short-term Debt (including unamortized debt issuance costs and pension liability).
13 Montana Electric Rate Review MPSC approval of the partial Joint Party Settlement, along with NorthWestern’s proposals for YCGS and PCCAM, would allow for recovery of increased operating costs and an opportunity to earn a fair return on the investment that funds the critical energy infrastructure in Montana. Key Dates • 6/9/25 - 6/18/25: MPSC Public Hearings • 7/2/25: Implementation of revised interim rates ($110.3 million subject to refund) • 7/21/25: NWE opening brief submitted • 8/11/25: Intervenor response briefs due • 8/26/25: NWE optional response due
Key Dates • 6/9/25 - 6/18/25: MPSC Public Hearings • 7/2/25: Interim rates remain in place as implemented Dec. 1, 2024 ($17.4 million subject to refund) • 7/21/25: NWE opening brief submitted • 8/11/25: Intervenor response briefs due • 8/26/25: NWE optional response due MPSC approval of the Joint Party Settlement would allow for recovery of increased operating costs and an opportunity to earn a fair return on the investment that funds the critical energy infrastructure in Montana. 14 Montana Natural Gas Rate Review
15 Initiating 2025 Non-GAAP EPS Guidance1 of $3.53 - $3.65 per diluted share ✓ Affirming long-term growth rates from 2024 base2 • EPS growth of 4% to 6% • Rate base growth of 4% to 6% • Continued focus on closing the gap between earned & authorized returns ✓ No equity expected to fund the current 5-year | $2.74 billion capital plan • Capital plan sized to be funded by cash from operations, aided by income tax net operating losses, and secured debt • Incremental capital opportunities may result in equity financing ✓ Expect to maintain FFO / Debt > 14% in 2025 and beyond ✓ Earnings growth is expected to exceed dividend growth until we return to our targeted 60% to 70% payout ratio 1.) See “2025 Earnings Bridge” below for additional details and major assumptions included in guidance. 2.) Based on 2024 Adjusted Diluted Non-GAAP EPS of $3.40 and estimated rate base of $5.38 billion. See “Non-GAAP Financial Measures” in appendix. Strong Growth Outlook
16 2025 Earnings Bridge This guidance range is based upon, but not limited to, the following major assumptions: • Final approval of all material aspects of NorthWestern's settlement position in the currently pending Montana general rate review; • Normal weather in our service territories; • An effective income tax rate of approximately 12%-15%; and • Diluted average shares outstanding of approximately 61.5 million. 2025 guidance represents 4% to 7% EPS growth from 2024 Non-GAAP Base Year1 1.) Based on 2024 Adjusted Diluted Non-GAAP EPS of $3.40. See “Non-GAAP Financial Measures” in appendix.
$2.74 billion of highly-executable and low-risk critical capital investment Regulated Utility Five-Year Capital Forecast (millions) 17
Thank youOther Updates 18
19 Montana Wildfire Bill No Strict Liability: • Confirms strict liability cannot be applied to utility operations related to wildfire Legal Protections for Providers: • Negligence standard based on Montana specific circumstances • Rebuttable presumption utility acted reasonably if it substantially followed a MPSC approved wildfire mitigation plan (burden of proof rests on plaintiffs) • 3-year statute of limitations from date of damage Damages: • Economic: Property damage (market value or restoration) and fire control costs • Noneconomic: Only if bodily injury or death occurs • Punitive: Only with clear & convincing evidence of gross negligence or intent NorthWestern’s Wildfire Mitigation Plan is expected to be filed during the third quarter of 2025 and updated every three years thereafter. HB 490 was passed by the Montana Legislature with broad bipartisan support in both the House (90-0) and Senate (40-8) and has been signed into law. The new law clarifies and limits wildfire-related risks, protecting our customers, communities and investors.
20 Transmission Bill Allows Certificate of Public Convenience & Necessity (CPCN) for electric transmission to be issued by the Montana Public Service Commission (MPSC) • Greater confidence of fair and equitable return Bill allows greater confidence for investors providing the critical capital necessary for the continued modernization of the energy grid. • Approvals MPSC shall determine within 300 days of application if transmission projects (greater than 69 kV) are in public interest and may grant or deny a CPCN • Cost clarity post CPCN Within 90 days of application, the MPSC shall issue an order responding to a utilities request for advanced approval of prudent cost recovery. SB 301 was also passed by the Montana Legislature with unanimous bipartisan support and signed into law.
✓ Montana ▪ Expected to be served by overall utility portfolio, which is projected to be long capacity beginning in 2026 ▪ Current generating portfolio over 60% carbon free ▪ If data center demand interest develops beyond existing capacity, we will work with the Montana Public Service Commission to structure appropriate tariffs ✓ 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 21 Large Load Customers ✓ Confidentially Announced: December 17, 2024 ▪ Company: Sabey Data Centers ▪ Load: 50 MW expected to grow to 250 MW ▪ Start Date: Mid-2027 ▪ Agreement Status: Letter of Intent ✓ Announced: December 19, 2024 ▪ Company: Atlas Power ▪ Load: 75 MW expected to grow to 150 MW ▪ Start Date: January 2026 ▪ Agreement Status: Letter of Intent (Existing transmission customer) ✓ Announced: July 30, 2025 ▪ Company: Quantica Infrastructure ▪ Load: 175MW growing to 500MW by 2030 ▪ Start Date: 2028 ▪ Agreement Status: Letter of Intent
22 Data Center Process (Montana & South Dakota) Data Center Request • Load & Location • Supply Potential • Customer/Developer Required Timing High-Level Assessment • Viability Assessment • SPP Screening • High Level $ Estimate • Development Costs Letter of Intent (LOI) • Supply Development Estimates • SIS/FS Studies • SD SPP DPNS • Contract Negotiations Energy Service Agreement (ESA) • Regulatory Approvals (as needed) • Contract Signing • Business Development Handoff Construction • PM Assignment • Construction Kick-Off • Supply Development • Generation Build Process SPP: Southwest Power Pool SIS: System Impact Study FS: Facilities Study SD: South Dakota DPNS: Delivery Point Network Study PM: Project Management Queue Count: 9 Queue Count: 4 Queue Count: 3 Queue Count: 0 Queue Count: 0
23 Regional Transmission Opportunities Colstrip Transmission System North Plains Connector (NPC) Consortium Project • $3.6 billion, 415-mile, high-voltage direct-current transmission line connecting to Montana's Colstrip substation, bridging the eastern and western U.S. energy grids • Project awarded $700M Grid Resilience & Innovation Partnership grant by U.S. Department of Energy1 • $70.0 million of the award is earmarked for upgrades to the Colstrip Transmission System (of which we are ~30% owner) North Plains Connector In December 2024, NorthWestern announced a memorandum of understanding to own 10% of the North Plains Connector. The project, targeting a 2032 in-service date, strengthens grid reliability and efficiency. A separate partnership will explore expanding Montana's southwest transmission corridor to bolster reliability, allow for critical import capability, and enhance Western market access. 1.) President Trump issued an Executive Order on January 20, 2025, "Unleashing American Energy," directing all federal executive agency heads to review all agency actions implicating energy reliability and affordability or potentially burdening the development of domestic energy resources. This Executive Order has delayed the disbursement of the funds granted by the U.S. Department of Energy for the NPC Consortium project.
24 Incremental Colstrip Capacity NorthWestern’s planned no cost acquisition of 592 MW of additional Colstrip capacity supports the integration of large-load customers, delivering substantial benefits to our customers, communities, and investors. ✓ No cost acquisition of incremental Colstrip ownership allows us to reliably and affordably serve existing customers ▪ Provides energy independence & improves system reliability / integrity ▪ Moves portfolio from short capacity position to long capacity ▪ Maintains affordability while insulating customers from volatile capacity and energy market pricing ✓ Increased ownership (from 15% to 55%) is expected to protect existing interest and provide Montana control to keep the plant open beyond Washington and Oregon mandated closure deadlines ✓ Significant capacity surplus provides opportunity for new large- load customers, spreading fixed costs over more kilowatt- hours, lowering and stabilizing the cost per unit for all our customers 760 MW Existing Ownership Montana Average Load 222 MW 222 MW 370 MW Avista & Puget Sound Energy 1400 MW Montana Peak Load + Planning Reserve During the second half of 2025 we intend to make filings with the MPSC and FERC to request regulatory approvals and cost recovery mechanisms that provide reasonable opportunities to recover these additional operating costs while providing valuable electric generation capacity and energy to customers.
Conclusion Pure Electric & Gas Utility Solid Utility Foundation Best Practices Corporate Governance Attractive Future Growth Prospects Strong Earnings & Cash Flows 25 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 Investor Relations Officer Travis Meyer 605-978-2967 travis.meyer@northwestern.com
Thank youAppendix: 26
(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) For those items marked as "n/a," the respective settlement and/or order was not specific as to these terms. (4) In June 2024, we filed a South Dakota natural gas rate review filing (2023 test year) with the SDPUC and a Nebraska natural gas rate review filing (2023 test year) with the NEPSC. 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 8-10% of earnings from its jointly owned coal generation rate base. Rate Base & Authorized Return Summary Appendix 27
Thank youSecond Quarter Appendix 28
Second Quarter Financial Results 29 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
Utility Margin (Q2) ($ in millions) Three Months Ended June 30, 2025 2024 Variance Electric $ 219.8 $ 199.2 $ 20.6 10.3% Natural Gas 47.6 44.2 3.4 7.7% Total Utility Margin1 $ 267.4 $ 243.4 $ 24.0 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: $ 17.9 Interim rates (subject to refund) 5.7 Transmission revenue due to market conditions and rates 1.6 Montana natural gas transportation 1.5 Base rates (4.3) Montana property tax tracker collections (4.0) Natural gas retail volumes (2.9) Electric retail volumes (2.0) Non-recoverable Montana electric supply costs (0.2) Other $ 13.3 Change in Utility Margin Impacting Net Income $ 10.4 Property & other taxes recovered in revenue, offset in property & other taxes 1.2 Production tax credits, offset in income tax expense (0.9) Operating expenses recovered in revenue, offset in operating & maintenance expense $ 10.7 Change in Utility Margin Offset Within Net Income $ 24.0 Increase in Utility Margin 30 Appendix
Operating Expenses (Q2) Increase in operating expenses due to the following factors: $ 5.5 Depreciation expense due to plant additions and higher depreciation rates 3.7 Electric generation maintenance 3.0 Insurance expense, primarily due to increased wildfire risk premiums 1.5 Property and other taxes not recoverable within trackers 1.4 Wildfire mitigation expense, partly offset by higher base revenues 1.3 Labor and benefits(1) 0.9 Technology implementation and maintenance expenses (0.1) Uncollectible accounts (0.2) Other $ 17.0 Change in Operating Expense Items Impacting Net Income ($ in millions) Three Months Ended June 30, 2025 2024 Variance Operating & maintenance $ 62.3 $ 57.4 $ 4.9 8.5% Administrative & general 33.8 31.3 2.5 8.0% Property & other taxes 48.2 36.3 11.9 32.8% Depreciation & depletion 62.4 56.9 5.5 9.7% Operating Expenses $ 206.7 $ 181.9 $ 24.8 13.6% $ 10.4 Property and other taxes recovered in trackers, offset in revenue (1.2) Deferred compensation, offset in other income (0.9) Operating and maintenance expenses recovered in trackers, offset in revenue (0.5) Pension and other postretirement benefits, offset in other income(1) $ 7.8 Change in Operating Expense Items Offset Within Net Income $ 24.8 Increase in Operating Expenses (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. 31 Appendix
Operating to Net Income (Q2) ($ in millions) Three Months Ended June 30, 2025 2024 Variance Operating Income $ 60.8 $ 61.6 $ (0.8) (1.3%) Interest expense, net (36.3) (31.9) 4.4 13.8% Other income, net 0.1 6.2 (6.1) (98.4%) Income Before Taxes 24.6 35.9 (11.3) (31.5%) Income tax expense (3.4) (4.2) (0.8) (19.0%) Net Income $ 21.2 $ 31.7 $ (10.5) (33.1%) $4.4 million increase in interest expense, net was primarily due to higher borrowings and interest rates and lower capitalization of Allowance for Funds Used During Construction (AFUDC). $6.1 million decrease in other income, net was primarily due to lower capitalization of AFUDC, a decrease in the value of deferred shares held in trust for deferred compensation, higher non-service component pension expense, and a $1.0 million expense accrual related to an estimated penalty for the previously disclosed Community Renewable Energy Project informed by a recent MPSC ruling. $0.8 million decrease in income tax expense was primarily due to a decrease in pre-tax income. 32 Appendix
Tax Reconciliation (Q2) 33 Appendix
Segment Results (Q2) 34 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 and some limited unregulated activity within the energy industry.
Electric Segment (Q2) (1) Included within this line is our lighting customer class, for which we have historically counted each lighting district as one customer. We have retroactively modified our customer counts to now reflect each lighting service as a customer as that better aligns with the MWH usage of this customer class. (2) Utility Margin is a non-GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure. 35 Appendix
Natural Gas Segment (Q2) 36 Appendix (1) Utility Margin is a non-GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure.
Thank you2025 Year-to-Date Appendix 37
We estimate weather to be a $0.3 million pre-tax detriment as compared to normal and a $1.6 million benefit as compared to the six months ending second quarter 2024. (1) As a result of the adoption of Accounting Standard Update 2017-07 in March 2018, pension and other employee benefit expense is now disaggregated on the GAAP income statement with portions now recorded in both OG&A expense and Other (Expense) Income lines. To facilitate better understanding of trends in year-over-year comparisons, the non-GAAP adjustment above re-aggregates the expense in OG&A - as it was historically presented prior to the ASU 2017-07 (with no impact to net income or earnings per share). (2) Utility Margin is a non-GAAP Measure. See the slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosures. Year-to-Date 2025 Non-GAAP Earnings 38 Note: Subtotal variances may exist due to rounding. Appendix
Year-to-Date Financial Results 39 1.) Utility Margin is a non- GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure. Note: Subtotal variances may exist due to rounding. Appendix
Utility Margin (YTD) ($ in millions) Six Months Ended June 30, 2025 2024 Variance Electric $ 462.6 $ 427.1 $ 35.5 8.3% Natural Gas 133.3 117.0 16.3 13.9% Total Utility Margin1 $ 595.9 $ 544.1 $ 51.8 9.5% (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: $ 30.1 Interim rates (subject to refund) 9.9 Transmission revenue due to market conditions and rates 5.8 Base rates 4.1 Electric retail volumes 2.9 Montana natural gas transportation 0.3 Natural gas retail volumes (6.8) Montana property tax tracker collections (1.7) Non-recoverable Montana electric supply costs (0.6) Other $ 44.0 Change in Utility Margin Impacting Net Income $ 6.6 Property & other taxes recovered in revenue, offset in property & other taxes 2.0 Production tax credits, offset in income tax expense (0.8) Operating expenses recovered in revenue, offset in operating & maintenance expense $ 7.8 Change in Utility Margin Offset Within Net Income $ 51.8 Increase in Utility Margin 40 Appendix
Operating Expenses (YTD) Increase in operating expenses due to the following factors: $ 11.1 Depreciation expense due to plant additions and higher depreciation rates 7.2 Electric generation maintenance 6.3 Insurance expense, primarily due to increased wildfire risk premiums 2.4 Labor and benefits(1) 1.4 Wildfire mitigation expense, partly offset by higher base revenues 1.4 Property and other taxes not recoverable within trackers 1.4 Technology implementation and maintenance expenses 0.3 Uncollectible accounts (2.4) Litigation outcome (Pacific Northwest Solar) (2.2) Non-cash impairment of alternative energy storage investment (2.7) Other $ 24.2 Change in Operating Expense Items Impacting Net Income ($ in millions) Six Months Ended June 30, 2025 2024 Variance Operating & maintenance $ 119.0 $ 111.5 $ 7.5 6.7% Administrative & general 75.1 71.7 3.4 4.7% Property & other taxes 91.4 83.4 8.0 9.6% Depreciation & depletion 124.8 113.7 11.1 9.8% Operating Expenses $ 410.3 $ 380.3 $ 30.0 7.9% $ 6.6 Property and other taxes recovered in trackers, offset in revenue (0.8) Operating and maintenance expenses recovered in trackers, offset in revenue $ 5.8 Change in Operating Expense Items Offset Within Net Income $ 30.0 Increase in Operating Expenses41 Appendix (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.
Operating to Net Income (YTD) ($ in millions) Six Months Ended June 30, 2025 2024 Variance Operating Income $ 185.5 $ 163.7 $ 21.8 13.3% Interest expense, net (72.8) (62.9) 9.9 15.7% Other income, net 4.0 10.5 (6.5) (61.9%) Income Before Taxes 116.8 111.3 25.3 22.7% Income tax expense (18.6) (14.6) 4.0 27.4% Net Income $ 98.2 $ 96.7 $ 1.5 1.6% $9.9 million increase in interest expense, net was primarily due to higher borrowings and interest rates and lower capitalization of Allowance for Funds Used During Construction (AFUDC). $6.5 million decrease in other income, net was primarily due to lower capitalization of AFUDC, a prior year reversal of $2.3 million from a previously disclosed CREP penalty due to a favorable legal ruling, and a $1.0 million expense accrual related to an estimated penalty for the CREP informed by a recent MPSC ruling, partly offset by an increase of $2.5 million driven by a prior year non-cash impairment of an alternative energy storage equity investment. $4.0 million increase in income tax expense was primarily due to an increase in pre-tax income. 42 Appendix
Tax Reconciliation (YTD) 43 Appendix
Segment Results (YTD) 44 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 and some limited unregulated activity within the energy industry.
Electric Segment (YTD) (1) Included within this line is our lighting customer class, for which we have historically counted each lighting district as one customer. We have retroactively modified our customer counts to now reflect each lighting service as a customer as that better aligns with the MWH usage of this customer class. (2) Utility Margin is a non-GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure. 45 Appendix
Natural Gas Segment (YTD) 46 Appendix (1) Utility Margin is a non-GAAP Measure. See appendix slide titled “Reconciling Gross Margin to Utility Margin” for additional disclosure.
Cash from Operating Activities decreased by $12.3 million primarily due to lower collections of accounts receivable balances due to timing of colder weather and an increase in our net cash outflows for energy supply costs, as shown in the table below. Funds from Operations increased by $10.8 million over prior period. Net Under-Collected Supply Costs (in millions) Beginning (Jan. 1) Ending (June 30) (Outflow) / Inflow 2024 $7.8 $14.9 ($7.1) 2025 $5.9 $28.6 ($22.7) 2025 Increase in Net Cash Outflows ($15.6) Year-to-Date Cash Flow 47 No Planned Equity Issuances in 2025 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 2025 • Issued $400 million, 5.07% coupon, 5-year Montana FMBs in Q1 • Issued $100 million, 5.49% coupon, 10-year South Dakota FMBs in Q2 • Amended our existing NorthWestern Energy Group $100 million term loan to extend the maturity date from April 11, 2025 to April 10, 2026 in Q2. Appendix
Balance Sheet 48 Appendix Debt to Total Capitalization up from last quarter and inside our targeted 50% - 55% range.
Reconciling Gross Margin to Utility Margin Management believes that Utility Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Utility Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow recovery of operating costs, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates and other factors impact our results of operations. Our Utility Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report. 1) Utility Margin is a non-GAAP Measure. 49 Appendix
PCCAM Impact by Quarter Qualified Facility Earnings Adjustment Our electric QF liability consists of unrecoverable costs associated with contracts covered under PURPA that are part of a 2002 stipulation with the MPSC and other parties. Risks / losses associated with these contracts are born by shareholders, not customers. Therefore, any mitigation of prior losses and / or benefits of liability reduction also accrue to shareholders.50 Appendix Pretax millions – shareholder (detriment) benefit
Non-GAAP Financial Measures 51 Appendix Pre-Tax Adjustments ($ Millions) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Reported GAAP Pre-Tax Income 181.2$ 156.5$ 176.1$ 178.3$ 182.2$ 144.2$ 190.2$ 182.4$ 201.6$ 214.7$ Non-GAAP Adjustments to Pre-Tax Income: Weather 13.2 15.2 (3.4) (1.3) (7.3) 9.8 1.1 (8.9) 4.3 10.6 Lost revenue recovery related to prior periods - (14.2) - - - - - - - - Remove benefit of insurance settlement (20.8) - - - - - - - - - QF liability adjustment 6.1 - - (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) Impairment of Alternative Energy Storage Investment - - - - - - - - - 4.2 Adjusted Non-GAAP Pre-Tax Income 179.7$ 169.7$ 172.7$ 168.9$ 174.9$ 163.9$ 184.4$ 176.0$ 205.9$ 227.2$ Tax Adjustments to Non-GAAP Items ($ Millions) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 GAAP Net Income 151.2$ 164.2$ 162.7$ 197.0$ 202.1$ 155.2$ 186.8$ 183.0$ 194.1$ 224.1$ Non-GAAP Adjustments Taxed at 38.5% (12'-17') and 25.3% (18'-current): Weather 8.1 9.3 (2.1) (1.0) (5.5) 7.3 0.8 (6.6) 3.2 7.9 Lost revenue recovery related to prior periods - (8.7) - - - - - - - - Remove benefit of insurance settlement (12.8) - - - - - - - - - QF liability adjustment 3.8 - - (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) Previously claimed AMT credit - - - - - - - - 3.2 - Release of Unrecognized Tax Benefit - - - - - - - - (3.2) (16.9) Impairment of Alternative Energy Storage Investment - - - - - - - - - 3.1 Natural Gas Safe Harbor Method Change - - - - - - - - - (7.0) Non-GAAP Net Income 150.3$ 159.8$ 160.6$ 170.1$ 173.8$ 169.9$ 182.4$ 178.9$ 197.3$ 208.9$ Non-GAAP Diluted Earnings per Share 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Diluted Average Shares (Millions) 47.6 48.5 48.7 50.2 50.8 50.7 51.9 56.3 60.4 61.4 Reported GAAP Diluted Earnings per Share 3.17$ 3.39$ 3.34$ 3.92$ 3.98$ 3.06$ 3.60$ 3.25$ 3.22$ 3.65$ Non-GAAP Adjustments: Weather 0.17 0.19 (0.04) (0.02) (0.11) 0.14 0.01 (0.11) 0.05 0.13 Lost revenue recovery related to prior periods - (0.18) - - - - - - - - Remove benefit of insurance settlementments & recoveries (0.27) - - - - - - - - - QF liability adjustment 0.08 - - (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) Previously claimed AMT credit - - - - - - - - 0.05 - Release of Unrecognized Tax Benefit - - - - - - - - (0.05) (0.28) Impairment of Alternative Energy Storage Investment - - - - - - - - - 0.05 Natural Gas Safe Harbor Method Change - - - - - - - - - (0.11) Non-GAAP Diluted Earnings per Share 3.15$ 3.30$ 3.30$ 3.39$ 3.42$ 3.35$ 3.51$ 3.18$ 3.27$ 3.40$
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, 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 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. 52 Appendix
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