Williams Capital West Coast March 20-21, 2019 Utilities Conference 8-K March 20, 2019

2 Forward Looking Statements Forward Looking Statements O’Dell Creek - Madison River Valley - Montana 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 hereof 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 most recent Form 10-K and 10-Q along with other public filings with the SEC. Company Information NorthWestern Corporation Corporate Office Investor Relations Officer dba: NorthWestern Energy 3010 West 69th Street Travis Meyer Ticker: NWE Sioux Falls, SD 57108 605-978-2967 Trading on the NYSE (605) 978-2900 travis.meyer@northwestern.com www.northwesternenergy.com

3 About NorthWestern South Dakota Operations Electric 63,800 customers 3,572 miles – transmission & distribution lines 440 MW nameplate owned power generation Natural Gas 46,900 customers 1,697 miles of transmission and distribution pipeline Montana Operations Electric 374,000 customers 24,767 miles – transmission & distribution lines 871 MW maximum capacity owned power generation Natural Gas 199,200 customers 6,881 miles of transmission and distribution pipeline Nebraska Operations 17.75 Bcf of gas storage capacity Natural Gas Own 51.7 Bcf of proven natural gas reserves 42,500 customers 795 miles of distribution pipeline Data as of 12/31/2018

4 NWE - An Investment for the Long Term • 100% regulated electric & natural gas utility business Black Eagle dam Pure Electric & with over 100 years of operating history Gas Utility • Solid economic indicators in service territory • Diverse electric supply portfolio ~55% hydro, wind & solar • Residential electric & gas rates below national average Solid Utility • Solid system reliability Foundation • Low leaks per 100 miles of pipe • Solid JD Power Overall Customer Satisfaction scores Strong • Consistent track record of earnings & dividend growth • Strong cash flows aided by net operating loss carry- Earnings & forwards anticipated to be available into 2020 Cash Flow • Strong balance sheet & investment grade credit ratings Attractive • Disciplined maintenance capital investment program to ensure safety and reliability • Significant investment in renewable resources (hydro & wind) will provide long-term Future Growth energy supply pricing stability for the benefit of customers for many years to come Prospects • Further opportunity for energy supply investment to meet significant capacity shortfalls Financial Goals • Debt to total capitalization ratio of 50%-55% with liquidity of $100 million or greater • Targeted 6%-9% long-term total shareholder return (eps growth plus dividend yield) & Metrics • Targeted dividend payout ratio of 60%-70% Best Practices Corporate Governance

5 A Diversified Electric and Gas Utility September 2018 Montana electric rate review, filed with rate base of $2.34 billion, calculated with 13th month average and known and measurable adjustments. NorthWestern’s ‘80/20’ rules: Approximately 80% Electric, 80% Residential and 80% Montana Data as reported in our 2018 10-K Over $3.6 billion of rate base investment to serve our customers

6 Highly Carbon-Free Supply Portfolio Based upon 2018 MWH’s of owned and long-term contracted resources. Approximately 55% of our total company owned and contracted supply is carbon-free. NorthWestern does not own all the renewable energy certificates (RECs) generated by contracted wind, and periodically sells its own RECs with proceeds benefiting retail customers. Accordingly, we cannot represent that 100% of carbon-free energy in the portfolio was delivered to our customers.

7 Strong Utility Foundation . Solid and improving JD Power Overall Customer Satisfaction Scores . Residential electric and natural gas rates below national average . Solid electric system reliability and low gas leaks per mile

8 Solid Economic Indicators Source: NorthWestern customer growth - 2008-2016 Forms 10-K Unemployment Rate: US Department of Labor via SNL Database 2/21/17 Electric: EEI Statistical Yearbook (published December 2015, table 7.2) Natural Gas: EIA.gov (Data table "Number of Natural Gas Consumers") Source: Company 10K’s, 2016/2017 EEI Statistical Yearbook – Table 7.2 and EIA.gov Black Eagle Power House • Customer growth rates historically exceed National Averages. • Projected population growth in our service territories in-line or better than the National Average.

9 A History of Growth $3.30-$3.50 $3.10 - $3.30 $2.60$3.20 - $2.75-$3.40 2009-2018 CAGR’s: GAAP EPS: 7.6% - Non-GAAP EPS: 5.9% - Dividend: 5.7% See appendix for “Non-GAAP Financial Measures”

10 Track Record of Delivering Results * Peer Group: ALE, AVA, BKH, EE, IDA, MGEE, NWN, OGE, OTTR, PNM, POR & SR Return on Equity on GAAP Earnings within 9.5% - 11.0% band over the last 8 years with average of 10.3%. Total Shareholder Return is better than our 12 peer average for the 10 year period but lags in the 1, 3 & 5 year periods, due in part to some unfavorable regulatory decisions in Montana. See appendix for “Non-GAAP Financial Measures”

11 Investment for Our Customers’ Benefit Over the past 8 years we have been reintegrating our Montana energy supply portfolio and making additional investments across our entire service territory to enhance system safety, reliability and capacity. We have made these enhancements with minimal impact to customers’ bills while maintaining bills lower than the US average. As a result we have also been able to deliver solid earnings growth for our investors. 2008-2018 CAGRs Estimated Rate Base: 12.2% GAAP Diluted EPS: 8.3% 2008-2018 CAGRs NWE typical electric bill: 1.9% NWE typical natural gas bill: (5.4%) 2008-2018 CAGRs US average electric bill: 1.9%* US average natural gas bill: (2.7%)**

12 Balance Sheet Strength and Liquidity Investment grade credit ratings, generally liquidity in excess of $100 million target, debt to cap within our targeted 50%-55% range and no long-term debt maturities until 2023.

13 Strong Cash Flows While maintenance capex and total dividend payments have continued to grow since 2011 (11.9% and 11.2% CAGR respectively), Cash Flow from Operations (CFO) has, on average, exceeded maintenance capex and dividend payments by approximately $7 million per year. Note: 2016 CFO is less than 2015 largely due to $30.8M refund to customers related to FERC/DGGS ruling and $7.2M refund to customers for difference in SD Electric interim & final rates. We expect NOLs to be available into 2020 with alternative minimum tax credits and production tax credits to be available into 2022 to reduce cash taxes. Additionally, we anticipate our effective tax rate to reach 10% by 2023. (See appendix for “Non-GAAP Financial Measures” relating to free cash flow and disclaimer on NOLs)

14 Earnings Growth $3.30-$3.45 $3.10 - $3.30 $2.60 - $2.75 Non-GAAP Adjusted EPS Growth averaged 6.3% from 2013-2018 We are not providing 2019 EPS guidance at this time due to the pending Montana rate case. However, continued investment in our system to serve our customers and communities is expected to provide a targeted long term 6-9% total return to our investors through a combination of earnings growth and dividend yield. Negative outcomes in upcoming regulatory proceedings may result in near-term returns below our 6-9% targeted range. Generation investment to reduce or eliminate our capacity shortfall See appendix for additionalcould disclosures allow us regardingto achieve “Non the-GAAP higher Financial-end Measures of our” range over the long term. See “Non-GAAP Financial Measures” slide in appendix.

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

16 Adjusted Non-GAAP Earnings (Full Year) The adjusted non- GAAP measures $3.30-$3.45 presented$3.10 are -being$3.30 $2.60shown - $2.75 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. See “Non-GAAP Financial Measures” slide in appendix. (1) During the first quarter of 2018, we revised our presentation of revenues associated with being a market participant in the Southwest Power Pool to net them with the associated cost of sales. These revenues were previously recorded gross in electric revenues in the Condensed Consolidated Statement of Income. This results in a decrease in electric revenue and a corresponding decrease in cost of sales. There was no impact to operating or net income. We assessed the materiality of this change in presentation, taking into account quantitative and qualitative factors, and determined it to be immaterial. We applied the change in presentation prospectively. (2) Impact of Tax Cuts & Jobs (TCJA) Jurisdictional Settlements includes the addback of $6.1M pretax revenue deferred for customer refunds in excess of the income tax benefits realized in 2018 and $3.3M of pretax expense related to hazard tree removal that was originally proposed to be funded with 50% of TCJA benefits (in lieu of customer refunds). This treatment was ultimately conceded in the settlement in exchange for agreement by the stipulating parties to not oppose a known-and-measurable adjustment equal to the actual 2018 expenditures for hazard tree removal included in our Montana electric rate review 2017 test year. These increases to Non-GAAP earnings were more than offset by the removal of a $19.8M income tax benefit in 2018 related to the final adjustment of excess deferred taxes and $2.4M of increased tax expense related to the two pretax items previously discussed (($6.1M + $3.3M ) x 25.3% = $2.4M). These sum to equal the $22.2M increase to income tax expense ($19.8MSee +appendix $2.4m) and ultimatelyfor additional result in $12.8M disclosures reduction regardingto GAAP Net Income.“Non- GAAP Financial Measures” (3) 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 2017 and 2018 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).

17 Recent Significant Achievements Strong year for safety at NorthWestern • Continue to be a top performer among Edison Electric Institute member companies. Record best customer satisfaction scores with JD Power & Associates • Once again received our best JD Powers overall satisfaction survey score. Best electric reliability scores • Low SAIDI (System Average Interruption Duration Index) and SAIFI (System Average Interruption Frequency Index) in 2018. Especially significant considering our rugged service territories we serve. Corporate Governance Finalist • In 2017 NorthWestern’s proxy statement was again recognized as a finalist for “Best Proxy Statement (Small to Mid Cap)” by Corporate Secretary Magazine. We won the award in 2014. Board Diversity Recognition • Recognized for gender diversity on its board of directors by 2020 Women on Boards. Three of the company’s eight independent directors are female. Best Investor Relations Program • Recognized, in 2018, by Institutional Investor as a top midcap utility and energy company based on access to senior management, well-informed and empowered IR team, appropriate and timely disclosures and constructive earnings calls. Environmental, Social and Governance Reporting • Published EEI’s ESG / Sustainability reporting template in December 2018. This quantitative information supplements our biennial Stewardship Report that highlights our commitment to Echo Lake Nordic Trail the stewardship of natural resources and our sustainable business practices. Acquired Two Dot Wind Farm • June 2018 acquired 9.7 MW wind project, near Geyser, Montana, for $18.5 million.

18 Looking Forward Regulatory • MPSC to review Montana general electric rate review, filed in September 2018. • We expect to file an associated FERC rate case for our Montana transmission assets in the first quarter 2019. Continue to Invest in our T&D infrastructure • Comprehensive infrastructure capital investment program to ensure safety, capacity and reliability. • Natural gas pipeline investment (SAFE PIPES Act, Integrity Verification Process and Pipeline & Hazardous Materials Safety Administration proposed regulations). • Grid modernization, advanced distribution management system and advanced metering infrastructure investment NWE plans to join Western Energy Imbalance Market (EIM) • Real-time energy market could mean lower cost of energy for Montana customers, more efficient use of renewables and greater power grid reliability. Cost Control Efforts • Continue to monitor costs, including labor, benefits and property tax valuations to mitigate increases. Advance Electricity Resource Planning efforts in South Dakota and Montana

19 Montana Electric Tracker Update The MPSC issued a final order in January 2019 approving a Power Cost & Credit Adjustment Mechanism (PCCAM) with the following provisions: • A baseline of power supply costs; • Symmetrical deadband of +/- $4.1 million from the established baseline. Supply cost variances above or below the deadband are shared 90/10 with customers/shareholders, respectively; and • Retroactive implementation to the effective date of the new legislation (July 1, 2017). Our 2018 results include a net reduction in the recovery of supply costs from customers of approximately $1.5 million in the Consolidated Statements of Income, which includes the following: • For the 2017/2018 period, actual costs were below base revenues by approx. $3.4 million, resulting in no refund to customers. • For the 2018/2019 period, actual costs were above base revenues by approx. $11.8 million, resulting in a regulatory asset for collection from customers of approx. $6.9 million and a $4.9 million reduction in recovery of supply costs for the first six months of the period.

20 Estimated Impacts of the Tax Cuts & Jobs Act Montana: In December 2018, the MPSC approved a settlement agreement providing a $20.5 million one-time customer credit to electric and natural gas customers. In addition, the settlement provides: • A $1.3 million annual reduction in natural gas rates beginning 2019 and funds for low-income energy assistance and weatherization. • Agreement of the parties not to oppose our request to include up to $3.5 million of costs to address hazard tree removal in our 2018 Spion Kop wind farm - Montana electric rate review filing. • Issues related to the revaluation of deferred income taxes will also be addressed in rate review. South Dakota: In September 2018, the SDPUC approved a settlement that resulted in a $3.0 million customer credit in the fourth quarter of 2018 and a two-year rate moratorium (until January 1, 2021). Nebraska: In August 2018, the NPSC approved a settlement to evaluate the impact of the TCJA on an annual basis and had no impact on our financial statements. Consolidated Impact: 2018 results include a net benefit related to the impact of the TCJA, which includes: • An income tax benefit of $19.8 million due to final revaluation of deferred income tax liabilities. • A net loss of $6.1 million resulting from $23.5 million in customer credits from approved tax settlements partially offset by a $17.4 million reduction in income tax expense due to the reduction in federal tax rate. • $3.3 million of expense related to our hazard tree program as agreed in our Montana settlement. Our initial filing with the MPSC instead proposed using a portion of the TCJA benefits to fund this expenditure. We expect a reduction in our cash flows from operations ranging from $20 - $22 million in 2019, as a result of one-time customer credits. We expect NOLs to be available into 2020 with alternative minimum tax credits and production tax credits to be available into 2022 to reduce cash taxes. Additionally, we estimate that our effective income tax rate to range from 0% to 5% in 2019 and our effective tax rate to reach 10% by 2023.

21 Montana Electric Rate Case Background • First general electric rate case in Montana since 2009. Black Eagle Power House • While we have efficiently managed operating and administrative costs, The filing also requests: increased Montana property taxes and significant investment in the system • Approval to capitalize Demand have compelled the request for rate relief. Side Management Costs • Establish a new baseline for September 2018 Filing (Docket D2018.2.12) PCCAM costs • Filed based on 2017 test year and $2.34 billion of rate base. • Place Two Dot Wind in rate • Requesting $34.9 million annual increase to electric rates base (~7.4% increase to the typical residential bill) • Approval of new net metering customer class and rate for new • 10.65% return on equity, 4.26% cost of debt, 49.4% equity and 7.42% residential private generation 1 return on rate base customers • Requested $13.8 million interim increase effective November 1, 2018. Update • Feb. 12: Intervenor testimony file with the consumer advocate recommending a $17.3 million rate decrease. • Feb. 26: 5-0 vote at work session granting $10.5 million interim rate increase (order pending, subject to refund). • Feb. 28: 4-0 vote at MPSC work session to request additional testimony on 5 issues ($500k of unexplained generation expense, disposition of excess accumulated deferred income tax liability, hazard tree and wildfire liability mitigation, recently constructed Montana corporate office building, and street lighting tariffs). Next Steps • Apr. 5: NorthWestern Rebuttal testimony and cross-intervenor testimony • Apr. 19: Final day for discovery on NWE rebuttal testimony and cross-intervenor testimony • May 3: Final day for NWE and intervenors to respond to discovery • May 13: Hearing commences and continues day-to-day as necessary 1. Except for Colstrip Unit 4 which has an lifetime ROR of 8.25% per D2008.6.69 (Order No. 6925f)

22 NWE Energy Supply Resource Plans South Dakota Electricity Supply Resource Plan Ryan Dam Upgrade • Published fall of 2018, the plan focuses on modernization of our fleet to improve reliability and flexibility, maintain compliance in Southwest Power Pool, and lowering operating costs. The plan identifies 90MWs of existing generation that should be retired and replaced over the next 10 years (in addition to 8MWs of mobile generation that will be installed by end of 2019). • We expect to issue a all-source request for proposal in the second quarter of 2019 to replace 60 MW of combustion turbine generation by late 2021. Montana Electricity Supply Resource Plan • Draft plan was filed in early March of 2019 and expected to be finalized mid-2019 after a 60 day public comment period. The plan will address our significant generation capacity deficits and negative reserve margin. • Our current peak requirement for energy is about 1,400 MW. We are currently 630 MW short, which is subject to market purchases. We forecast that our generation portfolio will be 725 MW short by 2025. • Planned regional retirements of 3,700 MW of, primarily coal-fired, generation are forecasted through 2032 by the Northwest Power and Conservation Council causing regional energy shortages as early as 2021. • We expect to solicit competitive all-source proposals in 2019 for up to 200 MW of peaking capacity available by 2022. • These supply additions would meet ~25% of our projected need in 2025. • We expect the process will be repeated in subsequent years to provide a resource-adequate energy and capacity portfolio (~200 MWs of capacity per year from 2022 to 2025) . The all-source capacity additions discussed above are subject to a competitive solicitation process administered by independent evaluators. As a result, we have not included the Echo Lake Nordic Trail necessary capital investment in our current five year capital forecast. These additions could increase our capital spending in excess of $200 million over the next five years.

23 Relevant Montana Legislation SENATE BILL 331 (previously SB 278) – Tom Richmond (R) Black Eagle Power House Montana Energy Security Act of 2019 SYNOPSIS: This bill effectively specifies that an electric utility is entitled to recover its investment costs, plant closure costs, and site remediation costs, regardless of when it closes relative to its useful life. Would allow NorthWestern to acquire, under limiting circumstances, an additional share of Colstrip, and recover those costs. This is a bill of possibilities... no mandates. 3/14/19: Referred to Energy and Telecommunications Committee 3/19/19: First Hearing SENATE BILL 244 – Mark Blasdel (R) Public Utilities/Electric Cost Trackers (Provides sideboards for 2017 HB 193) SYNOPSIS: It mandates a tracker, requires all utilities to be treated similarly, and requires full cost recovery unless sharing is instituted, in which case it is limited to a 90/10 split between customers and shareholders, respectively. 2/21/19: Passed out of Senate Energy Committee 7-6 2/27/19: Passed out of full Senate on 31-19 vote 3/20/19: First Hearing in House Energy, Technology and Federal Relations Committee SENATE BILL 199 – Tom Richmond (R) Prohibit PSC from altering certain contract lengths (Anti-symmetry bill) SYNOPSIS: When establishing rates or approving an application by a utility to acquire an electricity supply resource, the commission may not specify a contract length different from a length agreed to by the parties to the contract and may not establish for owned assets an economic life for ratemaking purposes different from the asset life used for depreciation purposes. For the purposes of this section, "electricity supply resource" does not include an agreement or contract with a qualifying small power production facility. 2/19/19: Passed out of Senate Energy & Telecommunications Committee 8-5 2/25/19: Passed out of full Senate on 31-19 vote 3/15/19: First Hearing in House Energy, Technology and Federal Relations Committee

24 Experienced Leadership & Solid Corporate Governance Board of Directors (left to right) Stephan Adik – Chairman of the Board - Independent Director since November 1, 2004 Anthony Clark – Independent Director since December 6, 2016 – Governance & Innovation and Human Resources Committees Dana Dykhouse – Independent Director since January 30, 2009 – Human Resources (Chair) and Audit Committees Jan Horsfall – Independent Director since April 23, 2015 – Audit and Governance & Innovation Committees Britt Ide – Independent Director since April 27, 2017 – Governance & Innovation Committee Julia Johnson – Independent Director since November 1, 2004 – Governance & Innovation (Chair) and Human Resources Committees Robert Rowe - CEO & President – Director since August 13, 2008 Linda Sullivan – Independent Director since April 27, 2017 – Audit (Chair) and Human Resources Committees Executive Management Team (left to right) Robert Rowe - President & CEO – current position since 2008 Brian Bird – CFO – current position since 2003 Michael Cashell – VP Transmission – current position since 2011 Heather Grahame – VP Regulatory & General Counsel – current position since 2010 John Hines – VP Supply – current position since 2011 Crystal Lail – VP & Controller – current position since 2015 Curtis Pohl – VP Distribution – current position since 2003 Bobbi Schroeppel – VP Customer Care, Communications & Human Resources – current position since 2002

25 Capital Investment Forecast $1.6 billion of total capital investment over five years. Increased investment in first three years (relative to last two years) is primarily a result of advanced metering infrastructure (AMI) project. We anticipate funding the expenditures with a combination of cash flows (aided by NOLs available into 2020) and long-term debt issuances. Significant capital investments that are not in the above projections or further negative regulatory actions could necessitate additional equity funding. Capital projections above do not include investment necessary to address capacity issues as identified in the South Dakota and pending* Montana Electricity Supply Resource Procurement Plans. *Draft plan was released March 2019.

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

27

Appendix 28 Gross Margin (Full Year) (dollars in millions) Twelve Months Ended December 31, 2018 2017 Variance(1) Electric $ 726.5 $ 703.1 $ 23.4 3.3% Natural Gas 192.6 192.3 0.3 0.2% Total Gross Margin (1) $ 919.1 $ 895.4 $ 23.7 2.6% Increase in gross margin due to the following factors: $ 25.1 Electric QF liability adjustment 6.2 Electric transmission 3.3 Natural gas retail volumes 0.4 Montana natural gas rates 0.3 Electric retail volumes (6.1) Impacts of Tax Cuts and Jobs Act (jurisdictional settlements) (1.5) PCCAM supply cost recovery 2.3 Other $ 30.0 Change in Gross Margin Impacting Net Income $ (17.4) Impacts of Tax Cuts and Jobs Act (0.5) Natural gas gathering fees (0.4) Natural gas production taxes 11.7 Property taxes recovered in trackers 0.3 Production tax credits flowed-through trackers $ (6.3) Change in Gross Margin Offset Within Net Income $ 23.7 Increase in Gross Margin (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure See appendix for additional disclosure.

Appendix 29 Weather (Full Year) We estimate favorable weather in 2018 has contributed approximately $1.3M pretax benefit as compared to normal and $2.1M pretax detriment as compared to 2017.

Appendix 30 Operating Expenses (Full Year) (dollars in millions) Twelve Months Ended December 31, 2018 2017 Variance Operating, general & admin. $ 307.1 $ 294.8 $ 12.3 4.2% Property and other taxes 171.3 162.6 8.7 5.4% Depreciation and depletion 174.5 166.1 8.4 5.1% Operating Expenses $ 652.9 $ 623.5 $ 29.4 4.7% Increase in Operating, general & admin expense due to the following factors: $ 7.2 Employee benefits 3.3 Hazard trees (3.7) Distribution System Infrastructure Project expenses (3.3) Labor (2.6) Maintenance costs 1.2 Other $ 2.1 Change in OG&A Items Impacting Net Income $ 10.3 Pension and other postretirement benefits 1.1 Operating expense recovered in trackers (0.7) Non-employee directors deferred compensation (0.5) Natural gas gathering fees $ 10.2 Change in OG&A Items Offset Within Net Income $ 12.3 Increase in Operating, General & Administrative Expenses $8.7 million increase in property and other taxes due primarily to plant additions and higher annual estimated property valuations in Montana. $8.4 million increase in depreciation and depletion expense primarily due to plant additions.

Appendix 31 Operating to Net Income (Full Year) (dollars in millions) Twelve Months Ended December 31, 2018 2017 Variance Operating Income $ 266.3 $ 271.8 ($ 5.5) (2.0%) Interest Expense (92.0) (92.3) 0.3 0.3% Other Income / (Expense) 4.0 (3.4) 7.4 217.6% Income Before Taxes 178.3 176.1 2.2 1.2% Income Tax Benefit / (Expense) 18.7 (13.4) 32.1 239.6% Net Income $ 197.0 $ 162.7 $ 34.3 21.1% $0.3 million decrease in interest expenses was primarily due to refinancing of debt in 2017, partly offset by rising interest rates. $7.4 million improvement in other income was due to a $10.3 million decrease in other pension expense (which is offset in OG&A expense) partly offset by lower capitalization of AFUDC. $32.1 million decrease in income tax expense due primarily to a benefit of approximately $19.8 million associated with the final measurement of excess deferred taxes and the impact of the lower federal tax rate of 21.0% compared to 35.0% in 2017.

Appendix 32 Income Tax Reconciliation (Full Year)

Appendix 33 Balance Sheet Improvement in debt to capitalization ratio; which is now closer to bottom end of 50%-55% targeted range.

Appendix 34 Cash Flow Cash from operating activities improved by $59.3 million primarily due to higher net income, improved customer receipts, the receipt of insurance proceeds during the current period.

Appendix 35 Summary Financial Results (Fourth Quarter) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. See appendix for additional disclosure.

Appendix 36 Gross Margin (Fourth Quarter) (dollars in millions) Three Months Ended December 31, 2018 2017 Variance(1) Electric $ 176.6 $ 175.0 $ 1.6 0.9% Natural Gas 59.8 60.5 (0.7) (1.2%) Total Gross Margin $ 236.4 $ 235.5 $ 0.9 0.4% Increase in gross margin due to the following factors: $ (6.1) Impacts of Tax Cuts and Jobs Act (jurisdictional settlements) (1.6) Montana natural gas supply rates 2.1 Electric transmission 1.0 Natural gas retail volumes 0.3 PCCAM supply cost recovery 2.0 Other $ (2.3) Change in Gross Margin Impacting Net Income (1) Gross Margin, $ 4.6 Property taxes recovered in trackers defined as revenues less cost 0.5 Production tax credits flowed-through trackers of sales, is a non- GAAP Measure. (1.0) Impacts of Tax Cuts and Jobs Act See appendix for (0.5) Operating expenses recovered in trackers additional (0.4) Natural gas production taxes disclosure. $ 3.2 Change in Gross Margin Offset Within Net Income $ 0.9 Increase in Gross Margin

Appendix 37 Weather (Fourth Quarter) We estimate unfavorable weather in fourth quarter 2018 resulted in a $1.0M pretax detriment as compared to normal and $2.8M pretax detriment as compared to period in 2017.

Appendix 38 Operating Expenses (Fourth Quarter) (dollars in millions) Three Months Ended December 31, 2018 2017 Variance Operating, general & admin. $ 85.2 $ 76.2 $ 9.0 11.8% Property and other taxes 43.0 44.1 (1.1) (2.5%) Depreciation and depletion 43.6 41.7 1.9 4.6% Operating Expenses $ 171.8 $ 162.0 $ 9.8 6.0% Increase in operating, general & admin expense due to the following factors: $ 5.3 Employee benefits 2.1 Hazard trees 0.7 Maintenance costs (1.1) Distribution System Infrastructure Project expense (0.5) Labor 0.2 Other $ 6.7 Change in OG&A Items Impacting Net Income $ 2.4 Pension and other postretirement benefits 0.6 Operating expenses recovered in trackers (0.7) Non-employee directors deferred compensation $ 2.3 Change in OG&A Items Offset Within Net Income $ 9.0 Increase in Operating, General & Administrative Expenses $1.1 million decrease in property and other taxes due primarily to an accrual true up in 2017 partially offset by plant additions and higher annual estimated property valuations in Montana. $1.9 million increase in depreciation and depletion expense primarily due to plant additions.

Appendix 39 Operating to Net Income (Fourth Quarter) (dollars in millions) Three Months Ended December 31, 2018 2017 Variance Operating Income $ 64.6 $ 73.5 $ (8.9) (12.1%) Interest Expense (23.8) (22.3) (1.5) (6.7%) Other Income / (Expense) 2.2 - 2.2 - Income Before Taxes 43.0 51.2 (8.2) (16.0%) Income Tax Benefit / (Expense) 23.4 (3.3) 26.7 809.1% Net Income $ 66.4 $ 47.9 $ 18.5 38.6% $1.5 million increase in interest expenses was primarily due to rising interest rates in 2018 compared to 2017. $2.2 million improvement in other income was due to a decrease in other pension expense partly offset by a decrease in the value of deferred shares held in trust for non- employee directors deferred compensation (both of which are offset in operating, general, and administrative expenses with no impact to net income). $26.7 million decrease in income tax expense due primarily to a $19.8 million benefit associated with a final measurement of excess deferred taxes and lower federal tax rate (21.0% compared to 35.0% in 2017) as a result of the TCJA.

Appendix 40 Income Tax Reconciliation (Fourth Quarter)

Appendix 41 Adjusted Non-GAAP Earnings (Fourth Quarter) 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. (1) During the first quarter of 2018, we revised our presentation of revenues associated with being a market participant in the Southwest Power Pool to net them with the associated cost of sales. These revenues were previously recorded gross in electric revenues in the Condensed Consolidated Statement of Income. This results in a decrease in electric revenue and a corresponding decrease in cost of sales. There was no impact to operating or net income. We assessed the materiality of this change in presentation, taking into account quantitative and qualitative factors, and determined it to be immaterial. We applied the change in presentation prospectively. (2) Impact of Tax Cuts & Jobs (TCJA) Jurisdictional Settlements includes the addback of $6.1M pretax revenue deferred for customer refunds in excess of the income tax benefits realized in 2018 and $3.3M of pretax expense related to hazard tree removal that was originally proposed to be funded with 50% of TCJA benefits (in lieu of customer refunds). This treatment was ultimately conceded in the settlement in exchange for agreement by the stipulating parties to not oppose a known-and-measurable adjustment equal to the actual 2018 expenditures for hazard tree removal included in our Montana electric rate review 2017 test year. These increases to Non-GAAP earnings were more than offset by the removal of a $19.8M income tax benefit in 2018 related to the final adjustment of excess deferred taxes and $2.4M of increased tax expense related to the two pretax items previously discussed (($6.1M + $3.3M ) x 25.3% = $2.4M). These sum to equal the $22.2M increase to income tax expense ($19.8M + $2.4m) and ultimately result in $12.8M reduction to GAAP Net Income. (3) 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 2017 and 2018 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).

Appendix 42 2018 Non-GAAP Adjustment for TCJA

43 South Dakota Electric Supply Resource Plan NorthWestern and HDR Engineering investigated various retirement & replacement scenarios* to assess Black Eagle Power House potential for modernizing its generation fleet and improve reliability and operational flexibility. A generally distributed generation solution is the best alternative to meet the Southwest Power Pool’s 12% planning reserve margin and benefit the system through: • Improved transmission reliability and lower system losses; • Improved restoration times; • Increased natural gas supply diversity; • Additional localized ancillary services; • Staged approach to incorporate new technologies, adjust to changing load centers and moderate customer rate impacts; and • Broadened tax base and multiple economic development opportunities across several communities. * Capacity solutions will ultimately be subject to a competitive solicitation process to ensure least cost and lowest risk alternatives are procured. Capital investment related to this resource plan is not included in our current 5 year capital estimates.

44 Montana DRAFT Electricity Supply Plan The total planned energy generation reductions in the Pacific Northwest region exceed 3,700 MWs through 2032. The Northwest Power and Conservation Council forecasts regional capacity shortfalls as early as 2021. NorthWestern Energy’s continued reliance on the market to purchase energy to fill the gap during peak customer demand will significantly increase price and reliability risk to NorthWestern Energy’s customers because of the reduced energy supply availability. We expect to solicit competitive all-source proposals in 2019 for up to 200 MW of peaking capacity available by 2022*. These supply additions would meet ~25% of our projected need in 2025. We expect the process will be repeated in subsequent years to provide a resource-adequate energy and capacity portfolio (~200 MWs of capacity per year from 2022 to 2025). Draft of NorthWestern’s Montana Electricity Supply Resource Procurement Plan was filed in early March of 2019 and expected to be finalized mid-2019 after a 60 day public comment period. * Capacity solutions will ultimately be subject to a competitive solicitation process to ensure least cost and lowest risk alternatives are procured. Capital investment related to this resource plan is not included in our current 5 year capital estimates.

Appendix 45 Qualified Facility Earnings Benefit The $25.1 million earnings improvement related to certain Qualified Facilities (QF) contracts in the 2nd quarter 2018 is a result of: • A $17.5 million benefit resulting from the reduction of the estimated future liability of unrecoverable QF costs. The primary driver of the reduction is due to price escalation of a certain variable rate contract that was lower than previously anticipated (when last evaluated in 2015). Due to the periodic nature of this estimated liability adjustment, this benefit has been excluded from non-GAAP earnings. • A $7.6 million benefit due to the annual adjustment to reflect lower actual output and pricing of QF related supply costs driven largely by outages at two QF facilities. Due to the annual nature of this adjustment to actual costs, this benefit was NOT excluded from non-GAAP earnings. 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 accrues to shareholders.

Appendix 46 Montana Natural Gas Rate Filing $430.2M Montana PSC Docket D2016.9.68 9.55% 4.47% 6.96% $5.1M Derivation of Rate Increase ($Millions) Revenue Request in Initial Application ..... $10.9 Property Tax (adjustment to actual) ….….. ($2.0) Income Tax correction and other misc. ..... 0.5 Rebuttal Revenue Request …………….. $9.4 1st Stipulation with MCC ROE Reduction (10.35% to 9.55%) ...... (2.6) Deprec. Reserve and other misc. …...... (0.2) 1st Stipulation Revenue Request …...... $6.6 2nd Stipulation with MCC / LCG A&G Concession ………………………. (0.8) 2nd Stipulation Revenue Request …...… $5.7 July 20, 2017 MPSC Work Session Remove A&G Concession ……………… 0.8 Accumulated depletion adjustment ……. (1.4) MPSC Settlement ………………..……..… $5.1* * Parties did not object to MPSC’s work session final order.

Appendix 47 NorthWestern Energy Profile (1) Rate base reflects amounts on which we are authorized to earn a return. (2) Rate base amounts are estimates as of December 31, 2018 (3) The revenue requirement associated with the FERC regulated portion of Montana electric transmission and DGGS are included as revenue credits to our MPSC jurisdictional customers. Therefore, we do not separately reflect FERC authorized rate base or authorized returns. (4) For those items marked as “n/a” the respective settlement and/or order was not specific as to these terms. Note: Data as reported in our 2018 10-K September 2018 Montana electric rate review, filed with rate base of $2.34 billion, calculated with 13th month average and known and measurable adjustments.

Appendix 48 2018 System Statistics (1) (2) Note: Statistics above are as of 12/31/2018 (1) Nebraska is a natural gas only jurisdiction (2) Dave Gates Generating Station (DGGS) in Montana is a 150 MW nameplate facility but consider it a 105 MW (60 MW FERC & 45MW MPSC jurisdictions) peaker

Appendix 49 Our Commissioners

Appendix 50 Non-GAAP Financial Measures (1 of 3) 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.

Appendix 51 Non-GAAP Financial Measures (2 of 3) Disclaimer on Net Operating Net Operating Losses (NOL’s): The expected tax rate and the expected availability of NOLs are subject to significant business, economic, regulatory and competitive uncertainties and contingencies, many of which are beyond the control of the Company and its management, and are based upon assumptions with respect to future decisions, which are subject to change. Actual results will vary and those variations may be material. For discussion of some of the important factors that could cause these variations, please consult the “Risk Factors” section of our most recent 10-K filed with the SEC.

Appendix 52 Non-GAAP Financial Measures (3 of 3) The data presented in this presentation includes financial information prepared in accordance with GAAP, as well as other Non-GAAP financial measures such as Gross Margin (Revenues less Cost of Sales), Free Cash Flows (Cash flows from operations less maintenance capex and dividends) and Net Debt (Total debt less capital leases), 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. The presentation of Gross Margin, Free Cash Flows and Net Debt is intended to supplement investors’ understanding of our operating performance. 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. Net Debt is used by our company to determine whether we are properly levered to our Total Capitalization (Net Debt plus Equity). Our Gross Margin, Free Cash Flows and Net Debt measures may not be comparable to other companies’ similarly labeled measures. Furthermore, these measures are not intended to replace measures as determined in accordance with GAAP as an indicator of operating performance.

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