2021 First Quarter Earnings Webcast April 22, 2021 CELEBRATING EARTH DAY 2021

Presenting Today 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. Bob Rowe, CEO Crystal Lail, Vice President & CFO Brian Bird, President & COO

• Net income for the first quarter of 2021 increased $12.4 million, as compared to the same period in 2020. – Diluted earnings per share increased $0.24, or 24.0%, as compared to the same period in 2020. – After adjusting for weather differences, Non-GAAP* adjusted earnings per share increased $0.20, or 18.9%, as compared to the same period in 2020. • The Board of Directors declared a quarterly dividend of $0.62 per share payable June 30, 2021 to shareholders of record as of June 15, 2021. Significant Events 3 * See slides 13 & 31 for additional information and Non-GAAP disclosures. • Bid submissions for the January 2020 RFP were evaluated by an independent administrator. After reviewing the independent analyses, the following portfolio of projects was selected for addition: • The construction of Laurel Generating Station (175 MW natural gas-fired generating facility) • A 5-Year agreement with Powerex to purchase capacity (market-based, for 100 MW) • Anticipate finalizing an agreement for an energy storage contract to fill the 5-hour duration tier identified in the January 2020 RFP.

NorthWestern Energy 4 A pure electric and natural gas utility; serving as stewards of critical energy infrastructure; providing essential services - in times of trial and triumph; to our resilient customer base spanning a vast footprint over Montana, South Dakota, Nebraska & Yellowstone Nat’l Park. A Strong Financial Foundation and Investment for the Long Term • Over 100 years of operating history • Customer bills well below national average • Highest ever customer satisfaction scores • Award winning and best practices corporate governance • A history of strong earnings growth • Stable and flexible investment grade balance sheet • Ample liquidity to weather uncertainty (temporarily doubled targeted liquidity $100 to $200 million) • A history of annual dividend increases (from $1.00 per share in 2005 to $2.48 in 2021) • A disciplined capital investment program ($450 million + plan maintained for 2021) • A history of stable and consistent customer growth • A diverse energy supply portfolio already 65% carbon-Free (2020 MWh delivered) • A significant generation capacity deficit with opportunity for investment

Summary Financial Results 5 (1) (First Quarter) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure See appendix for additional disclosure.

Increase in gross margin due to the following factors: $ 4.1 Electric retail volumes 2.8 Natural gas retail volumes 2.1 Electric transmission (0.5) Montana natural gas production rates (1.4) Montana electric supply cost recovery 2.9 Other miscellaneous nonrecurring items $ 10.0 Change in Gross Margin Impacting Net Income $ 2.0 Property taxes recovered in revenue, offset in property tax expense 1.1 Production tax credits reducing revenue, offset in income tax benefit (0.8) Operating expense recovered in revenue, offset in operating expense $ 2.3 Change in Gross Margin Offset Within Net Income $ 12.3 Increase in Gross Margin 6 Gross Margin (First Quarter) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure See appendix for additional disclosure. (dollars in millions) Three Months Ended March 31, 2021 2020 Variance Electric $ 189.9 $ 180.8 $ 9.1 5.0% Natural Gas 66.4 63.2 3.2 5.1% Total Gross Margin $ 256.3 $ 244.0 $ 12.3 5.0%(1)

Weather 7 (First Quarter) Even with the February cold-snap, we experienced a warmer first quarter as compared to normal, which contributed approximately $1.3M pretax gross margin detriment but a $2.7M pretax benefit as compared to first quarter 2020.

Operating Expenses 8 (First Quarter) $3.0 million increase in property and other taxes due primarily to an increase in Montana state and local taxes. $1.7 million increase in depreciation and depletion expense primarily due to plant additions. (dollars in millions) Three Months Ended March 31, 2021 2020 Variance Operating, general & admin. $ 80.9 $ 79.0 $ 1.9 2.4% Property and other taxes 47.5 44.5 3.0 6.7% Depreciation and depletion 47.0 45.3 1.7 3.8% Operating Expenses $ 175.4 $ 168.8 $ 6.6 3.9% Increase in Operating, general & administrative expense due to the following factors: $ (1.6) Uncollectible accounts (0.6) Travel and training (0.4) Labor (0.3) Generation maintenance 0.4 Employee benefits (1.1) Other miscellaneous decreases $ (3.6) Change in OG&A Items Impacting Net Income $ 4.5 Non-employee directors deferred compensation, offset in other income 1.8 Pension and other postretirement benefits, offset in revenue (0.8) Operating expenses recovered in trackers, offset in revenue $ 5.5 Change in OG&A Items Offset Within Net Income $ 1.9 Increase in Operating, General & Administrative Expenses

Operating to Net Income 9 (First Quarter) $0.8 million decrease in interest expenses was primarily due lower interest on our revolving credit facility and higher capitalization of Allowance for Funds used During Construction (AFUDC), slightly offset by higher borrowings. $7.6 million increase in other income includes a $4.5 million increase in the value of deferred shares held in trust for non-employee directors deferred compensation and an $1.8 million decrease in other pension expense (both of which are offset in OG&A expenses with no impact to net income), and higher capitalization of AFUDC $1.8 million decrease in income tax benefit primarily due to higher pretax income partially offset by slightly improved permanent or flow-through adjustments. (dollars in millions) Three Months Ended March 31, 2021 2020 Variance Operating Income $ 80.9 $ 75.2 $ 5.7 7.6% Interest Expense (23.5) (24.3) 0.8 3.3% Other Income / (Expense) 5.6 (2.0) 7.6 380.0% Income Before Taxes 63.1 48.9 14.2 29.0% Income Tax Benefit 0.0 1.8 (1.8) (100.0%) Net Income $ 63.1 $ 50.7 $ 12.4 24.5%

Income Tax Reconciliation 10 (First Quarter) We expect NOLs to be available into 2021 with alternative minimum tax credits and production tax credits to be available into 2023 to reduce cash taxes. Additionally, we anticipate our effective tax rate to reach approximately 10% by 2024.

Balance Sheet 11 Targeted debt to capitalization ratio of 50%-55% 53.6% Debt to Capitalization at March 31, 2021

Cash Flow 12 Cash from operating activities decreased by over $92 million primarily due to an $80.9 million increase in market purchases of supply resulting in an under collection of supply costs from customers in the current period due to colder winter weather in February 2021 and a refund of approximately $20.5 million to our FERC regulated wholesale customers in the first quarter of 2021.

Adjusted Non-GAAP Earnings 13 The adjusted non-GAAP measures presented in the table above are being shown to reflect significant items that were not contemplated in our original guidance, however they should not be considered a substitute for financial results and measures determined or calculated in accordance with GAAP. (First Quarter) (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).

2020 Non-GAAP to 2021 EPS Bridge 14 Assumptions included in the 2021 Guidance includes, but not limited to, the following major assumptions: • Normal weather in our electric and natural gas service territories; • Continued Covid-19 related reduction in our commercial and industrial sales volumes, offset in part by an increase in usage by residential customers through the second quarter of 2021; • A consolidated income tax rate of approximately (2.5%) to +2.5% of pre-tax income; and • Diluted average shares outstanding of approximately 51.5 million to 51.8 million. The 20 cent EPS guidance range slightly wider than normal primarily due to Covid-19 uncertainties. Guidance range may be narrowed in the 2nd or 3rd quarter when we have a better sense of its impact to our margins. Non-GAAP 2020 to 2021 midpoint EPS growth rate of 4.5%. $2.48 annualized dividend is expected to be at the upper end of our 60%-70% targeted payout of EPS.

Earnings Per Share and Dividend History 15 See prior page for Guidance Assumptions and see “Non-GAAP Financial Measures” slide in appendix for reconciliation of “Non-GAAP Adjusted EPS” Non-GAAP Adjusted EPS Growth Averaged 4.3% from 2013 - 2020 Annualized dividend growth rate of 6.7% from 2013 - 2020 Continued investment in our system to serve our customers and communities is expected to provide annualized 4% - 5% growth in rate base and a targeted 3% - 6% annualized EPS growth to our investors over the long-term. Maintaining our 60-70% targeted dividend payout ratio, we anticipate the dividend growth rate to be in line with the EPS growth rate going forward. Earnings Per Share vs Guidance Dividend and Payout Ratio

Looking Forward (Regulatory) 16 • We do not expect to make general rate case filings in any of our regulatory jurisdictions during 2021. We have made or anticipate making several other regulatory filings, primarily in our Montana jurisdiction, including: • An April 15, 2021 filing requesting to delay the implementation of our fixed cost recovery mechanism pilot for another year until July 2022 or beyond, due to the continued uncertainties created by the COVID-19 pandemic; • An April 21, 2021 filing requesting approval to increase the forecasted costs used to develop rates for the recover of electric power costs through our Power Cost and Credit Adjustment Mechanism (PCCAM) by approximately $17 million; and • A May 2021 filing requesting approval to acquire electric capacity resources identified through our January 2020 RFP. • In May 2019, we filed proposed revisions to our FERC transmission rates. In November 2020 we reached a settlement with intervenors establishing formula rates. The settlement, and a motion to implement settlement rates, were filed on November 16th. The motion was granted on November 25th and we began charging settlement rates on December 1st. We refunded approximately $20.5 million to our wholesale customers in the first quarter of 2021. In March 2021, we submitted a compliance filing with the MPSC adjusting the FERC credit in our retail rates. The MPSC approved, on an interim basis, both the updated revenue credit and the refund amount* that will be completed over a one-year period, beginning April 1, 2021. *As of March 31, 2021 we had cumulative deferred revenue for refund of approximately $12.8 million.

February Cold Weather Event 17 • In February 2021, a prolonged cold spell resulted in record winter peak demand for electricity and natural gas. In our SD & NE service territories, natural gas costs for the month of February 2021 exceeded the total cost for all of 2020. • We recorded a regulatory asset of approximately $26 million for natural gas supply we incurred in Nebraska. Considering customer impacts, we proposed recovery of our costs over a two-year period. We expect the Nebraska Public Service Commission to issue a decision during the second quarter of 2021. • We recorded approximate $17.8 million as a regulatory asset for supply costs incurred in our SD jurisdiction for natural gas supply costs in February. The South Dakota Public Utilities Commission (SDPUC) issued an order allowing recovery over a one-year period, effective March 1, 2021. • In Montana, while the impact was still significant, the degree of price excursion was not as significant due to availability of Canadian gas (AECO) from the north. Our combination electric and gas system performed exceptionally well. However, energy imports during this period were critical to maintain services in Montana. • Each year we submit filings for recovery of purchased power, natural gas and property tax costs. The respective state commissions review these tracker filings and make cost recovery determinations based on prudency.

February Cold Weather Event (Montana) 18 (Megawatts) (Megawatt Hours) The chart illustrates the actual contribution of energy, by resource, during February’s multi-day cold weather event, the capacity deficit, and the market price of power. (Thermal includes all thermal resources – 222 MW Colstrip Unit 4, mandatory-purchase Qualifying Facilities, and natural gas.) Hydro (484MW) Coal and Natural Gas (511MW) Solar (17MW) Wind (455MW) Resource Adequacy Requirement Accredited Capacity of current portfolio NWE Load Purchase Price Portfolio Resource Portfolio Resource Production

NorthWestern consistently imports significant volumes of power to serve Montana customers during peak usage periods. Large Electricity Imports Were Critical (Montana) • Regional events helped avoid outages • Colder weather shifted to the east • Outages in Oregon meant more power was available to purchase • Market prices spiked as the event went on • Transmission system for imports significantly constrained Net Electricity Imports into Montana – Feb. 10-15, 2021 (“-” Represents Energy Import) 19

Based on the results of the competitive solicitation process in South Dakota, approximately $100 million of incremental investment for SD generation is included in the projections above (2021-2023). This level of capital investment is anticipated to result in annualized rate base growth of 4%-5%. The projections do not include the results of the Montana RFP. Independent third-party analyses selected a portfolio of projects including our proposed 175 MW natural gas-fired generation plant near Laurel, Montana. If approved by the MPSC, our cost to construct this project is expected to be approximately $250 million (primarily over 2022-2023). Maintaining Capital Investment Forecast 20 • $2.1 billion of total capital investment over the five year period. • We expect to finance this capital with a combination of cash flows from operations, first mortgage bonds and equity issuances. We anticipate initiating a $200 million At-the-Market (ATM) offering during the second quarter of 2021. Any equity issuances will be sized to maintain and protect our current credit ratings. • Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions and other factors.

Generation Portfolio Update 21 60 MW of flexible capacity underway in Huron, SD South Dakota • Construction continues for a 60MW RICE project in Huron, SD to be online in late 2021 with total construction costs of approximately $80 million (~$40 million invested in 2020). • An additional 30-40 MW of flexible generation in Aberdeen, SD is in the planning stages and expected to be online in 2023 with a cost of approximately $60 million. Montana • Initial bids for the January 2020 RFP were received in July 2020. Bid submissions were evaluated by an independent party with the following portfolio of projects selected: • Laurel Generation Station - Construction of 175 MW of flexible reciprocating internal combustion engines (RICE) near Laurel, MT, which we will own. If we receive MPSC approval to build, the cost to construct this plant is expected to be approximately $250 million and be available for commercial operation in late 2023 / early 2024; and • Powerex Transaction – a 5-year power purchase agreement for 100 MW of capacity and energy products originating predominately from hydroelectric resources. We also anticipate finalizing an agreement for an energy storage contract shortly to fill the 5-hour duration tier identified in the January 2020 RFP. We expect to request MPSC approval of the Laurel Generation Station, and possibly an energy storage contract, in May 2021 with a decision anticipated 6 to 9 months after filing.

ESG Advancements 22 www.northwesternenergy.com/our-company/investor-relations THE USE BY NORTHWESTERN CORP OF ANY MSCI ESG RESEARCH LLC OR ITS AFFILIATES (“MSCI”) DATA, AND THE USE OF MSCI LOGOS, TRADEMARKS, SERVICE MARKS OR INDEX NAMES HEREIN, DO NOT CONSTITUTE A SPONSORSHIP, ENDORSEMENT, RECOMMENDATION, OR PROMOTION OF NORTHWESTERN CORP BY MSCI. MSCI SERVICES AND DATA ARE THE PROPERTY OF MSCI OR ITS INFORMATION PROVIDERS, AND ARE PROVIDED ‘AS-IS’ AND WITHOUT WARRANTY. MSCI NAMES AND LOGOS ARE TRADEMARKS OR SERVICE MARKS OF MSCI. • NorthWestern has a new Environmental, Social and Governance landing page. The new page: • Consolidates existing ESG information; • Includes disclosures of 20 new and existing policies and standards necessary for a best-practices ESG program; and • Includes a new, easy reference, Sustainability Statistics Report to disclose 5-year trend of operational and financial ESG data and statistics. • We continue to make progress on several ESG ratings with the most substantial improvement at MSCI (from BB to A in the latest report). www.northwesternenergy.com/our-company/investor-relations/ESG-Sustainability • The first volume of BRIGHT Magazine was published this week. This quarterly publication will showcase our employees, our customers, our communities, and our commitment to sustainability.

Conclusion 23 Pure Electric & Gas Utility Solid Utility Foundation Best Practices Corporate Governance Attractive Future Growth Prospects Strong Earnings & Cash Flows

24 Appendix

25 Segment ResultsAppendix (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. See appendix for additional disclosure. (1) (First Quarter)

26 Electric SegmentAppendix (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. See appendix for additional disclosure. (First Quarter)

27 Natural Gas SegmentAppendix (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. See appendix for additional disclosure. (First Quarter)

Quarterly PCCAM Impacts 28 Appendix In 2017, the Montana legislature revised the statute regarding our recovery of electric supply costs. In response, the MPSC approved a new design for our electric tracker in 2018, effective July 1, 2017. The revised electric tracker, or PCCAM established a baseline of power supply costs and tracks the differences between the actual costs and revenues. Variances in supply costs above or below the baseline are allocated 90% to customers and 10% to shareholders, with an annual adjustment. From July 2017 to May 2019, the PCCAM also included a "deadband" which required us to absorb the variances within +/- $4.1 million from the base, with 90% of the variance above or below the deadband collected from or refunded to customers. In 2019, the Montana legislature revised the statute effective May 7, 2019, prohibiting a deadband, allowing 100% recovery of QF purchases, and maintaining the 90% / 10% sharing ratio for other purchases.

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. Qualified Facility Earnings Adjustment 29 Appendix The gain in 2020 for our QF liability was $3.1 million in total, it was comprised of $2.2 million adjustment to the liability and $0.9 million lower actual costs over last 12 months (QF contract year). This $3.1 million benefit is $3.3 million less than the $6.4 million total benefit we recognized in Q2 last year. Due to our expectations regarding the remeasurement frequency of our QF liability, we no longer reflect this adjustment as a non-GAAP measure.

NWE Rate Base and Earnings Profile 30 Appendix (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. 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 for earnings. The data to the left illustrates that NorthWestern only derives approximately 9-12% of earnings from its jointly owned coal generation rate base. Coal Generation Rate Base as a percentage of Total Rate Base

These materials include financial information prepared in accordance with GAAP, as well as other financial measures, such as Gross Margin and Adjusted 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 exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross Margin (Revenues less Cost of Sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. Gross 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. Adjusted Diluted EPS is another non-GAAP measure. The Company believes the presentation of Adjusted Diluted EPS is more representative of our normal earnings than the GAAP 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. Non-GAAP Financial Measures 31 Appendix

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