8-K May 17, 2017 Investor Update May 17-18, 2017 Spion Kop Wind Farm - near Geyser, MT

2 Forward Looking Statements 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 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 dba: NorthWestern Energy www.northwesternenergy.com Corporate Support Office 3010 West 69th Street Sioux Falls, SD 57106 (605) 978-2900 Montana Operational Support Office 11 East Park Butte, MT 59701 (406) 497-1000 SD/NE Operational Support Office 600 Market Street West Huron, SD 57350 (605) 353-7478 Investor Relations Officer Travis Meyer 605-978-2945 travis.meyer@northwestern.com

NWE - An Investment for the Long Term 3 • 100% Regulated electric & natural gas utility business • 100 year history of competitive customer rates, system reliability and customer satisfaction • Solid economic indicators in service territory • A diverse electric supply portfolio that is approximately 54% hydro and wind (combined MT & SD) • Solid & improving JP Power Overall Customer Satisfaction scores • Residential electric and natural gas rates below the national average • Solid system reliability (EEI 2nd quartile) • Low leaks per 100 miles of pipe (AGA 1st quartile) • Named a “Utility Customer Champion” by Cogent Reports (top trusted utility brand in the West region) • Consistent track record of earnings and dividend growth • Strong cash flows aided by net operating loss carry-forwards • Strong balance sheet and solid investment grade credit ratings • Recent hydro & wind transactions provide additional long-term energy supply pricing stability • Disciplined maintenance capital investment program • Further opportunity to reintegrate energy supply portfolio to meet capacity shortfalls • Significant future investment in a comprehensive transmission, distribution, and substation infrastructure project to address asset lives, safety, capacity and grid modernization Pure Electric & Gas Utility Solid Utility Foundation Strong Earnings & Cash Flows Attractive Future Growth Prospects (NYSE Ethics) Best Practices Corporate Governance

About NorthWestern 4 Montana Operations Electric 363,800 customers 24,450 miles – transmission & distribution lines 809 MW nameplate owned power generation Natural Gas 194,100 customers 7,250 miles of transmission and distribution pipeline 18 Bcf of gas storage capacity Own 61 Bcf of proven natural gas reserves Nebraska Operations Natural Gas 42,300 customers 787 miles of distribution pipeline South Dakota Operations Electric 63,200 customers 3,550 miles – transmission & distribution lines 440 MW nameplate owned power generation Natural Gas 46,200 customers 1,673 miles of transmission and distribution pipeline

A Diversified Electric and Gas Utility 5 Gross Margin in 2016: Electric: $679M Natural Gas: $177M Gross Margin in 2016: Montana: $718M South Dakota: $128M Nebraska: $ 10M Average Customers in 2016: Residential: 586k Commercial: 112k Industrial: 7k NorthWestern‟s „80/20‟ rules: Approximately 80% Electric, 80% Residential and 80% Montana jurisdictional Above data reflects full year 2016 results.

NorthWestern Energy Profile 6 Financial and Company Statistics

7 Based upon 2016 MWH‟s of owned and long-term contracted resources. Approximately 54% of our total company owned and contracted supply is carbon-free. Highly Carbon-Free Supply Portfolio

Strong Utility Foundation 8 Electric source: Edison Electric Institute Typical Bills and Average Rates Report, 1/1/16 Natural gas source: US EIA - Monthly residential supply and delivery rates as of 1/29/16  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 System Average Interruption Duration Index (SAIDI) NWE versus EEI System Reliability Quartiles

Solid Economic Indicators 9 • Unemployment rates in all three of our states are meaningfully below National Average. • Customer growth rates historically exceed National Averages. 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")

2017 Earnings Guidance 10 NorthWestern reaffirms 2017 earnings guidance range of $3.30 - $3.50 per diluted share is based upon, but not limited to, the following major assumptions and expectations: • Normal weather in our electric and natural gas service territories; • A consolidated income tax rate of approximately 7% to 11% of pre-tax income; and • Diluted average shares outstanding of approximately 48.5 million. Continued investment in our system to serve our customers and communities is expected to provide a targeted 7-10% total return to our investors through a combination of earnings growth and dividend yield. However in light of recent regulatory headwinds and reduced & delayed generation spending, we anticipate in the near-term to be at the lower end of the 7-10% range. See “Non-GAAP Financial Measures” slide in appendix for “Non-GAAP “Adjusted EPS”. $2.60 - $2.75 $3.10 - $3.30 $3. 0-$3.40 $3.30-$3.50

Investment for Our Customers‟ Benefit 11 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 and lower than the US average bills, while delivering solid earnings growth for our investors. 2008-2016 CAGRs Estimated Rate Base: 14.8% GAAP Diluted EPS: 8.4% NWE typical electric bill: 2.2% NWE typical natural gas bill: (7.5%) US average electric bill: * 2.0% US avg. natural gas bill ** (4.1%) Note: US avg. natural gas bill CAGR is from 2008-2015

Track Record of Delivering Results 12 Notes: - ROE in 2011, 2012 , 2013, 2014, 2015 & 2016 on a Non-GAAP Adjusted basis, would be 10.5%, 9.8%, 9.6% ,9.4%, 9.9% and 9.8% respectively. - 2017 ROAE and 2017 Dividend payout ratio estimate based on midpoint of our guidance range of $3.30-$3.50. - Details regarding Non-GAAP Adjusted EPS can be found in the “Adjusted EPS Schedule” page of the appendix Return on Equity within 9.5% - 11.0% band over the last 6 years. Annual dividend increases since emergence in 2004. 6 Year (2011-2016) Avg. Return on Equity: 10.4% 5 Year (2011-2016) CAGR Dividend Growth: 6.8% Current Dividend Yield Approximately 3.7% (based on $2.10 annual dividend)

Total Shareholder Return 13 • 13 member peer group: ALE (ALLETE), AVA (Avista), BKH (Black Hills Corp), EE (El Paso Electric), GXP (Great Plains Energy), IDA (IDACORP), MGEE (MGE Energy), OGE (OGE Energy), OTTR (Otter Tail Power), PNM (PNM Resources), POR (Portland General Electric), VVC (Vectren) and WR (Westar)

While maintenance capex and total dividend payments have continued to grow since 2011 (12.9% and 13.0% CAGR respectively), Cash Flow from Operations (CFO) has continued to outpace maintenance capex and averaged approximately $29 million of positive Free Cash Flow per year. 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. With the addition of production tax credits from the Beethoven Wind project and continued flow-through tax benefits, we anticipate our effective tax rate rising into the low-twenties by 2020. Additionally, we expect NOLs to be available into 2021 to reduce cash taxes. Strong Cash Flows 14 See “Non-GAAP Financial Measure” slide in appendix for Free Cash Flows reconciliation. This 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 the preliminary prospectus. Nothing in this presentation should be regarded as a representation by any person that these objectives will be achieved and the Company undertakes no duty to update its objectives. Net Opera ing Loss (NOL) Carryforward Balance (2) (1) (2) (1) Components of Free Cash Flow

Balance Sheet Strength and Liquidity 15

Credit Ratings 16 Moody’s: A2 Fitch: A S&P: A- Moody‟s downgraded our senior secured and unsecured credit rating on March 10, 2017 and has us on a Negative Outlook. However, even after the downgrade, Moody‟s rating is in line with Fitch and above S&P on a secured basis (and between them on an unsecured basis).

Recent Significant Achievements 17 Strong year for safety in 2016 • Fewest OSHA recordable events of any year. • Best year for lost time incidents. Record best customer satisfaction scores • Received our best Overall Customer Satisfaction scores in the JD Power residential utility survey in 2016. Corporate Governance Finalist • NorthWestern‟s 2016 proxy statement was recognized as a finalist in 2016 by Corporate Secretary magazine for Best Proxy Statement (Small to Mid Cap). We won the award in 2014. Echo Lake Nordic Trail Recognized for Strong Dividend • In March 2016, NorthWestern Corporation was added to the NASDAQ US Broad Dividend AchieversTM Index, which aims to represent the country‟s leading stocks by dividend yield in addition to Dow Jones US Dividend Select TM Index in 2015. New Board Members • December 2016: Anthony Clark, senior advisor at Wilkenson Barker Knauer LLP and former FERC commissioner and ND Public Service Commissioner. • April 2017: Britt Ide, president of Ide Energy & Strategy • April 2017: Linda Sullivan, executive vice president and chief financial officer of American Water.

What we are working on in 2017 18 Natural Gas Rate Case in Montana • A Hearing was held May 9-11 with a decision expected in mid 2017. Cost control efforts • Continue to monitor costs, especially labor and benefits • Monitor property tax valuations in Montana Continue to invest in our existing transmission and distribution infrastructure. • Transition from DSIP/TSIP to overall infrastructure capital plan • Natural gas pipeline investment (Integrity Verification Process and PHMSA Requirements) • Advanced Metering Infrastructure (AMI) investment Refining our Supply Plan in Montana • Capacity generation additions • Continue to work with MPSC and other stakeholder groups to refine energy supply plans Continue to search for natural gas reserve acquisition opportunities • Acquisitions at a price that benefits both customers and shareholders

19 Regulatory Update Regulatory Item Current / Anticipated Action FERC / DGGS: April 2014 order regarding cost allocation at DGGS between retail and wholesale customers. • FERC denied our request for rehearing and required us to make refunds in June 2016. • We filed a petition for review with the US Circuit Court of Appeals for the District of Columbia Circuit in June 2016. • We do not expect a decision until the fourth quarter of 2017, at the earliest. Colstrip: In May 2016, the MPSC issued a final order disallowing recovery of certain costs included in the electric supply tracker related to a 2013 outage at Colstrip Unit 4. • Appeals have been filed in two Montana district courts regarding disallowance. • We believe we are likely to receive orders from the courts in these matters by the end of 2017 or in early 2018. Hydro Compliance Filing: In December 2016, the MPSC issued a final order reducing the annual amount we are allowed to recover in hydro generation rates by approximately $1.2 million and required us to indicate our intentions to file a Montana electric rate case with a 2016 test year. On April 26, 2017, we filed our required annual report with the MPSC regarding 2016 results, which indicates we earned less than our authorized rate of return. At the same time, we also submitted a filing to the MPSC responsive to the hydro compliance order, indicating we do not expect to file an electric rate case in 2017 based on a 2016 test year. However, we expect to file a general electric rate case in 2018 based on a 2017 test year. The MPSC may require an additional filing that would facilitate their assessment of just and reasonable rates. • 2016 Schedule 27 ROE: 9.76% Actual, 9.38% Normalized vs 10.05% wt. avg. authorized.

20 Montana Natural Gas Rate Filing: • On May 5th a proposed Stipulation and Settlement Agreement was reached with the MCC. If approved, the settlement would result in a $6.6 million revenue increase and 9.55% ROE. • Hearing was held May 9-11 with a decision expected in mid 2017. Montana House Bill 193: Passed by Montana legislature in April 2017. • This bill revises the current tracker related legislation, which mandated that the MPSC use an electric cost recovery mechanism that provides for full cost recovery of prudently incurred electric supply costs. HB193 increases the discretion the MPSC may exercise with regard to costs included in tracker filings. While the text of HB193 does not address the specifics of changes in cost recovery, testimony provided by the MPSC in support of HB193 indicates our tracker filings would be handled similarly to Montana- Dakota Utilities (MDU) mechanism. The MDU mechanism allows for recovery of 90 percent of the increases or decreases in fuel and purchased power costs from an established baseline. However, due to the discretion allowed in HB193, we can not guarantee how the MPSC may apply the stature to our electric tracker filings. HB193 is expected to go into effect on July 1, 2017. Property Tax Tracker Rules: In March 2017, the MPSC proposed new rules to establish minimum filing requirements for property tax trackers. • Current MT Property tax tracker rules allows recovery of 60 percent of the change in state and local taxes and fees. Some of the proposed rules would enable MPSC to challenge amounts and allocation to customers • A work session was held on May 4th in which the Commission instructed staff to move forward finalizing the rules. It is unclear if the rules will remain exactly as proposed or modified before they are finalized in mid 2017. Regulatory Update (continued)

Montana Natural Gas Rate Filing 21 Montana PSC Docket D2016.9.68 On May 5th a proposed Stipulation and Settlement Agreement was reached with the MCC. If approved, the settlement would result in a $6.6 million* revenue increase, 9.55% ROE and the 46.79% equity capital structure as originally filed. The Large Customer Group did not join in the settlement but indicated that it supports the agreement other than provisions relating to the allocation of common plant and administrative & general expenses. A Hearing was held May 9-11 with the decision expected mid-2017. * The Initial Application requested a $10.9 million increase. This amount was updated in Rebuttal to $9.4 million primarily as a result of $2.0 million lower actual property tax expense a $0.5 million offsetting increase for an income tax adjustment. $6.6M 6.96% $430.2M $76.06 9.55% 4.47%

Capital Spending Forecast 22 The current estimated 5 year capital spending is $1.58 billion. We anticipate managing capital expenditures to provide a more levelized annual spend (including spending on generation assets) and anticipate funding the expenditures with a combination of cash flows, aided by NOLs now anticipated to be available into 2021, and long-term debt. If other opportunities arise that are not in the above projections (natural gas reserves, acquisitions, etc.), new equity funding may be necessary. *

Montana 2015 Electric Supply Resource Plan 23 The resource initiatives and actions developed in 2015 Electricity Supply Resource Procurement Plan identify the critical future needs of our portfolio, including solutions to resolve our current negative planning reserve margin. The plan identifies how to co- optimize hydro, wind and thermal resources to best meet the anticipated large capacity needs with the least-cost, lowest-risk resources. On February 2, 2017 the Montana Public Service Commission issued a press release acknowledging the need for additional capacity but identified specific concerns with the plan. A constructive workshop, to clarify the technical underpinnings of the plan, was held on February 27 with the MPSC and staff. Spending on the generation assets will be subject to the development of a plan for clear regulatory recovery. Source: Company’s IRP or other publications

Montana 2015 Electric Supply Resource Plan 24 On February 13, 2017 we issued a Request for Proposal (RFP) to partially address NorthWestern‟s negative reserve margin. Pacific Northwest planning bodies (PNUCC & NWPPC*) have reaffirmed the expected growing capacity need. NorthWestern is addressing this risk through a deliberate and incremental approach that will include subsequent RFP‟s to lessen the risk of a large reliance on markets that are vulnerable to price spikes during capacity shortages. * Pacific Northwest Utilities Conference Committee & Northwest Power and Conservation Council Current Capacity Economically Optimal Portfolio (Current capacity plus identified generation additions)

Owned Owned Target Total Annual Need Natural Gas Reserves Opportunity 25 Current gas prices are very attractive for buyers but it is difficult to find sellers willing to transact at these low rates. First ~6 Bcf annual production acquired for ~$100M Remaining 6-7 Bcf annual production needed to meet target. Estimated cost of $50M to $100M We continue to pursue opportunities to secure low cost gas reserves for our customers. • Three acquisitions totaling approximately $100 million since September 2010: • 84.6 Bcf of natural gas reserves and associated gathering systems along with 82 miles of transmission. • Provides approximately 5.3 Bcf of annual production. • Target to own 50% of our 25 Bcf total annual need • Retail customers (20 Bcf) • DGGS & Basin Creek generation facilities (5 Bcf) • As we continue to add to our natural gas reserves portfolio, we anticipate a reduction in supply cost volatility for our customers.

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

27

Summary Financial Results (First Quarter) 28 Note: During the fourth quarter of 2016, we early adopted the provisions of Accounting Standards Update No. 2016-09 (ASU 2016-09), Improvements to Employee Share-Based Payment Accounting, revising certain elements of the accounting for share-based payments. As a result of this adoption, during the fourth quarter of 2016, excess tax benefits of $1.8 million related to vested share-based compensation awards were recorded as a decrease in income tax expense in the Consolidated Statement of Income. In accordance with the guidance, the $1.8 million impact of this adoption is reflected as of January 1, 2016. The guidance also requires that in future filings that include the previously issued interim financial information, the interim financial information is presented on a recast basis to reflect the adoption of ASU 2016-09 as of January 1, 2016. The Condensed Consolidated Statement of Income and Condensed Consolidated Statement of Cash Flow for the period ended March 31, 2016, have been recast to reflect this adoption, resulting in an increase in net income and earnings per share.

29 Gross Margin (First Quarter) (dollars in millions) Three Months Ended March 31, 2017 2016 Variance Electric $ 180.8 $ 157.7 $ 23.1 14.6% Natural Gas 66.7 59.4 7.3 12.3% Gross Margin $ 247.5 $ 217.1 $ 30.4 14.0% Increase in gross margin due to the following factors: $ 10.3 MPSC disallowance (2016) 8.6 Electric retail volumes 6.0 Natural gas retail volumes 1.2 South Dakota electric rate increase (0.6) Natural gas production 1.8 Other $ 27.3 Change in Gross Margin Impacting Net Income $ 3.1_ Property taxes recovered in trackers $ 3.1 Change in Gross Margin Offset Within Net Income $ 30.4 Increase in Consolidated Gross Margin

Weather (First Quarter) 30 Mean Temperature from Normal Our Montana service territory benefited from a colder than normal January offset partially by warmer than normal February and March in all three states we serve. Our service territory also experienced colder winter weather than the prior year.

Operating Expenses (First Quarter) 31 Increase in operating expenses due mainly to the following factors: $1.1 million increase in OG&A $ 1.5 Maintenance costs $ 1.3 Bad debt expense $ 0.5 Labor $ (1.7) Non-employee directors deferred compensation $ (1.0) Insurance reserves $ 0.5 Other $4.5 million increase in property and other taxes due primarily to plant additions and higher estimated property valuations in Montana. $1.6 million increase in depreciation and depletion expense primarily due to plant additions. (dollars in millions) Three Months Ended March 31, 2017 2016 Variance Operating, general & admin. $ 81.0 $ 79.9 $ 1.1 1.4% Property and other taxes 39.9 35.4 4.5 12.7% Depreciation and depletion 41.5 39.9 1.6 4.0% Operating Expenses $ 162.4 $ 155.2 $ 7.2 4.6%

Operating to Net Income (First Quarter) 32 $1.1 million decrease in interest expenses was primarily due to debt refinancing at a lower interest rate of the Pollution Control Revenue Refunding Bonds during the third quarter of 2016. $1.6 million decrease in other income due primarily to a $1.7 million decrease in the value of deferred shares held in trust for non-employee directors deferred compensation (which had a corresponding increase to operating, general and administrative expenses). $5.9 million increase in income tax expense due primarily to higher pre-tax income, offset by lower flow-through repairs deductions. (dollars in millions) Three Months Ended March 31, 2017 2016 Variance Operating Income $ 85.1 $ 61.9 $ 23.2 37.5% Interest Expense (23.4) (24.5) 1.1 (4.5%) Other Income 1.5 3.1 (1.6) (51.6%) Income Before Taxes 63.2 40.6 22.6 55.7% Income Tax Expense (6.6) (0.7) (5.9) (842.9%) Net Income $ 56.6 $ 39.9 $ 16.7 41.9%

Balance Sheet 33

Cash Flow 34

Income Tax Reconciliation 35

Adjusted Earnings (First Quarter „17 vs ‟16) 36 The 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) Note: First quarter net income and EPS last year (2016) was originally reported as $38.1M and $0.79, respectively. As a result of adopting Accounting Standards Update No. 2016-09 during the fourth quarter of 2016, excess tax benefits of $1.8 million related to vested share-based compensation awards were recorded as a decrease in income tax expense in the Consolidated Statement of Income. In accordance with the guidance, the $1.8 million impact of this adoption is reflected as of January 1, 2016.

Non-GAAP Adjusted EPS 37 The 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. (in millions, except EPS)

2016 to 2017 EPS & Dividend Bridge 2016 Non-GAAP EPS to 2017 Midpoint $3.30 → $3.40 = 3.0% increase 2016 to 2017 Dividend Growth $2.00 → $2.10 = 5.0% increase Slower near-term EPS growth along with slightly lower capital investment projections than previously provided, led us to a 5% (or 10 cents annualized) dividend increase rather than the 4% (or 8 cents annualized) targeted dividend increase we had last indicated in December 2016. NWE’s 2017 earnings guidance range of $3.30-$3.50 per diluted share is based upon, but not limited to, the following major assumptions and expectations: • Normal weather in our electric and natural gas service territories • A consolidated income tax rate of approximately 7% to 11% of pre-tax income; and • Diluted average shares outstanding of approximately $48.5 million. 38 * 2017 earnings drivers shown above are calculated using a 38.5% effective tax rate. The anticipated "Incremental tax detriment" shown above is primarily due to lower anticipated tax-repairs eligible capital spending in 2017.

2016 System Statistics 39 Note: Statistics above are as of 12/31/2016 (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 (1) (2)

Experienced & Engaged Board of Directors 40 Dr. E. Linn Draper Jr. • Chairman of the Board • Independent • Director since November 1, 2004 Stephan P. Adik • Committees: Audit (chair), Human Resources • Independent • Director since November 1, 2004 Anthony T. Clark • Committees: Governance and Innovation • Independent • Director since December 6, 2016 Julia L. Johnson • Committees: Governance and Innovation, Human Resources • Independent • Director since November 1, 2004 Robert C. Rowe • Committees: None • CEO and President • Director since August 13, 2008 Linda G. Sullivan • Committees: Audit • Independent • Director since April 27, 2017 Dana J. Dykhouse • Committees: Human Resources (chair), Audit • Independent • Director since January 30, 2009 Jan R. Horsfall • Committees: Audit, Governance and Innovation • Independent • Director since April 23, 2015 Britt E. Ide • Committees: Governance and Innovation • Independent • Director since April 27, 2017

Strong Executive Team 41 Robert C. Rowe • President and Chief Executive Officer • Current position since 2008 Brian B. Bird • Vice President and Chief Financial Officer • Current position since 2003 Michael R. Cashell • Vice President - Transmission • Current Position since 2011 Patrick R. Corcoran • Vice President – Government and Regulatory Affairs • Current position since 2001 Heather H. Grahame • Vice President and General Counsel • Current position since 2010 John D. Hines • Vice President - Supply • Current Position since 2011 Crystal D. Lail • Vice President and Controller • Current position since 2015 Curtis T. Pohl • Vice President - Distribution • Current position since 2003 Bobbi L. Schroeppel • Vice President – Customer Care, Communications and Human Resources • Current Position since 2002

Our Commissioners 42

The Hydro Facilities 43 Overview of Hydro Facilities Black Eagle Hydro Asset Integration • Montana Asset Optimization Study: As part of reintegrating the hydro facilities into our generation portfolio, we initiated an asset optimization study to maximize the value of our diverse generation portfolio. The study was recently completed and we are in the process of implementing new operating procedures that we anticipate will reduce both operating cost and market risk. Kerr Dam Conveyance / Hydro Compliance Filing • In accordance with the 1985 FERC relicensing, the facility was conveyed to the Confederated Salish and Kootenai Tribes (CSKT) on September 5, 2015. • As required by the MPSC order approving the hydro transaction, we filed a compliance filing in December 2015 to remove the Kerr project from the hydros cost of service and to adjust for actual revenue credits and property taxes. In January „16, the MPSC approved an interim adjustment and opened a separate contested docket requesting additional detail. A hearing was held in September 2016. The only contested issue at the hearing was the level of administrative & general expenses that should be deducted due to the transfer of the Kerr Project. We expect a final order during the fourth quarter of 2016. (1) As of June 2013. Despite the 2015 drought conditions in western Montana, the hydro assets generated at targeted capacity (5 year historical average). Talen Energy‟s recently announced sale of 292 MW of hydro generation for $860 million (or $2,945 per KW) to Brookfield Renewables is significantly higher cost (49%) than the 439 MW of hydro generation we purchased for $870 million (or $1,982 per KW).

44 Colstrip Unit 4 / Sierra Club Litigation Background • On March 6, 2013, the Sierra Club and the Montana Environmental Information Center (MEIC) (both are plaintiffs) filed suit in the United States District Court for the District of Montana (court) against the six individual Owners of the Colstrip Generating Station (Colstrip) • Colstrip consists of four coal fired generating units – units 1 & 2 are older than units 3 & 4. • NWE has a 30% joint interest in unit 4 and a risk sharing agreement with Talen Montana regarding the operation of units 3 & 4, which each party receives 15% of the combined output and respective operating and construction costs. • Original suit was for alleged violations of the Clean Air Act and the Montana State Implementation Plan. Current Results • On July 12, 2016 the parties lodged a consent decree with the Court. • The Court entered the consent decree on September 6, 2016. • Decree provides the following • Dismisses all of the claims against all Colstrip units • Provides no shut down date for Units 3 & 4 • Provides that Units 1 & 2 must be shut down by July 1, 2022 (NWE has no ownership or role in Units 1 & 2 shut down) • Permits parties to petition the Court for costs and attorneys‟ fees • The consent decree gave the Plaintiffs and Defendants the right to seek recovery of attorneys‟ fees and costs from the other party by filing a motion with the Court by October 6, 2016. Each party filed such a motion on a timely basis. On January 30, 2017 the United States Magistrate Judge (Magistrate) issued his Findings and Recommendation on the competing fee applications. The Magistrate recommended the Defendants‟ fee request be denied and the Plaintiffs‟ fee request should be granted, but only to the extent of fifty percent of their request. The 50% reduction was due to the Plaintiffs‟ limited success in the case, citing failure of Plaintiffs to obtain civil penalties and failure to achieve any relief as to Units 3 and 4. As a result, while the Plaintiffs had requested approximately $3.1 million in fees and costs, the Magistrate recommended that they recover approximately $1.6 million. Our share of this amount would be approximately $0.2 million. The parties had 14 days following issuance of the Magistrate‟s Findings and Recommendation in which to object. Neither Plaintiffs or Defendants filed an objection. On February 15, 2017, the District Court adopted the Magistrate‟s Findings and Recommendation, and dismissed the case.

DGGS Update – Denied Rehearing Request 45 Note: Please see Regulatory Matters footnote and Risk Factors section of our recent Form 10-K and Form 10-Q for additional disclosures.

Non-GAAP Financial Measures 46 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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