Baird Utility Corporate Access Day Chicago, IL | Sept. 10, 2014

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 10-Q which we filed with the SEC on July 24, 2014 and our other public filings with the SEC. Company Information NorthWestern Corp. dba: NorthWestern Energy www.northwesternenergy.com Corporate Support Office 3010 West 69th Street Sioux Falls, SD 57106 (605) 978-2900 Montana Operational Support Office 40 East Broadway Butte, MT 59701 (406) 497-1000 SD/NE Operational Support Office 600 Market Street West Huron, SD 57350 (605) 353-7478 Director of Investor Relations Travis Meyer 605-978-2945 travis.meyer@northwestern.com

About NorthWestern 3 Our Vision: Enriching lives through a safe, sustainable energy future Our Mission: Working together to deliver safe, reliable and innovative energy solutions Our Values: S - safety E - excellence R - respect V - value I - integrity C - community E - environment

NWE: An Investment for the Long Term 4 We’re a fully-regulated and financially solid utility; with – Diversity across states, service type and customer segments – A 100 year history of competitive customer rates, system reliability and customer satisfaction – A strong track record of significant earnings and dividend growth – Strong cash flows aided by net operating loss carryforwards – Solid investment grade credit ratings Attractive future growth prospects; and – Reintegrating energy supply portfolio (electric and natural gas) – Distribution System Infrastructure Project (DSIP) – Transmission opportunities within our service territory Best practices corporate governance – A strong and well rounded board and executive team – Named to the Forbes “Americas Most Trustworthy Companies” for the years 2011, 2012 & 2013

Fortnightly 40 NorthWestern Energy was recently recognized as one of the top 40 best energy companies in the United States by Fortnightly 40. The report compares shareholder value performance by looking at uniform data sets among the leading publicly traded electric and gas companies across a range of metrics. NYSE Ethics NorthWestern Energy earned an "A" from the New York Stock Exchange's Corpedia, for its Code of Conduct and Ethics, putting it in the top 2 percent of all energy and utility companies reviewed. Forbes America's Most Trustworthy Companies for 2011, 2012 & 2013 For the years 2011, 2012 and 2013, NorthWestern Corporation was recognized by Forbes as one of "America's Most Trustworthy Companies," which identifies the most transparent and trustworthy businesses that trade on the American exchanges. In the past, Forbes turned to Audit Integrity who recently merged with Corporate Library and Governance Metrics International to form GMI Ratings (GMI). GMI's quantitative and qualitative data analysis looks beyond the raw data on companies' income statement and balance sheets to assess the true quality of corporate accounting and management practices. Each year Forbes recognizes 100 companies out of over 8,000 for this foremost honor. New York Stock Exchange Century Index Created in 2012 to recognize companies that have thrived for over a century while demonstrating the ability to innovate, transform and grow through the decades of economic and social progress. Glass Lewis NorthWestern was recognized by Glass Lewis, a leading investment research and global proxy advisory firm, as one of the top 42 companies in the US for its 2011 “Say on Pay” proposals, which recognizes companies with clear disclosure and conservative policy with regards to compensation. Corporate Governance Award Finalist In 2013, for the second straight year, Northwestern Corporation was named a finalist in the category of "Best Proxy Statement (small cap)" given by the Corporate Secretary - Governance, Risk & Compliance organization. Strong Corporate Governance 5

Solid Economic Indicators 6 Top Left: Unemployment rate consistently below National Average for our service territory. National Ranking (SD 2nd, NE 3rd & MT 10th) Top: Bad debt / revenue write-off is less than ½ of a percent even during tough economic times – Our customers pay their bills. Left: Projected population growth near or above the National Average for all three states we service provides potential for additional organic growth (average annualized growth of approximately 80 basis points). 3.50% 3.38% 5.12% 3.35% 0% 1% 2% 3% 4% 5% 6% US National Average Montana South Dakota Nebraska Source: Nielsen via SNL Database 7-25-14 Projected Population Growth 2014-2019 (cumulative growth) 0% 2% 4% 6% 8% 10% 12% 2010 2011 2012 2013 2014 US National Average Montana South Dakota Nebraska Source: US Department of Labor via SNL Database 7-25-14 Unemployment Rate (as reported in June each year) 0.25% 0.30% 0.25% 0.21% 0.29% 0.22% 0.26% 0.30% 0.00% 0.20% 0.40% 0.60% 0.80% 1.00% 2007 2008 2009 2010 2011 2012 2013 2014* Write-Off to Revenue Ratio * 2014 data through June 30th

A Diversified Electric and Gas Utility 7 The “80/20” rules of NorthWestern Gross Margin in 2013: Electric: $506M Natural Gas: $167M Other $ 2M Gross Margin in 2013: Montana: $561M South Dakota: $103M Nebraska: $ 11M Average Customers in 2013: Residential: 561k Commercial: 108k Industrial: 6k Above data reflects full year 2013 results. Jurisdiction and service type based upon gross margin contribution. See “Non-GAAP Financial Measures” slide in appendix for Gross Margin reconciliation. 83% Montana 15% South Dakota 2% Nebraska 83% Residential 16% Commercial 1% Industrial 75% Electric 25% Natural Gas

600 700 800 2009 2010 2011 2012 2013 In d ex S co re NorthWestern Energy Score JD Power 26 Combination Electric and Natural Gas Company Average JD Power - Customer Service Index Score 0 25 50 75 100 125 150 M inutes NorthWestern 3-Year Average Customer Average Interruption Duration Index (CAIDI) 0.00 0.25 0.50 0.75 1.00 1.25 1.50 In te rr up ti on s NorthWestern 3-Year Average System Average Interruption Frequency Index (SAIFI) Strong Utility Foundation 8 Strong utility operations: Solid system reliability (EEI 2nd quartile);  A NWE customer anticipates, on average, one outage per year lasting 100 minutes  SAIFI – Reliability Indices with Major Events excluded - Interruptions /customer/year  CAIDI – Reliability Indices with Major Events excluded – Average outage duration Residential electric and natural gas rates below national average; and Customer service satisfaction scores in line with survey average (JD Powers). EEI – 2nd Quartile Performance Electric source: Edison Electric Institute Typical Bills and Average Rates Report, 7/1/13 Natural gas source: US Dept of Energy Monthly residential supply and delivery rates as of 1/1/13 $- $20 $40 $60 $80 $100 $120 $140 MT SD MT SD NE Electric (750 kwh) Natural Gas (100 therms) National Average National Average "Typical Bill" Residential Rate Comparison

$2.02 $2.14 $2.53 $2.66 $2.46 $- $1.50 $1.75 $2.00 $2.25 $2.50 $2.75 $3.00 2009 2010 2011 2012 2013 2014E GAAP Diluted EPS 2014 Earnings Guidance 9 2014 guidance range of $2.60-$2.75 based upon, but not limited to, the following major assumptions and expectations: • Normal weather in our electric and natural gas service territories for 2014; • Excludes any hydro related transaction fees (including legal and bridge financing) and any potential income generated from the operation of the hydro assets post-closing, assuming regulatory approval; • Excludes any potential additional impact as a result of the FERC decision regarding revenue allocation at our Dave Gates Generating Station; • A consolidated income tax rate of approximately 14% to 16% of pre-tax income; and • Diluted average shares outstanding of 39.3 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. Initial Guidance Range Non-GAAP "Adjusted" EPS Diluted Earnings Per Share $2.60-$2.75 See “Non-GAAP Financial Measures” slide in appendix for “Non-GAAP Adjusted EPS”.

Track Record of Delivering Results 10 Notes: - ROE in 2011, 2012 & 2013, on a Non-GAAP Adjusted basis, would be 10.5%, 9.8% & 9.7% respectively. - 2014 ROE and 2014 Dividend payout ratio estimate based on midpoint of guidance range of $2.60- $2.75. - 2011 and 2012 Dividend Payout Ratio based upon Non-GAAP Adjusted EPS would be 60% and 62% respectively. - 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 5 years. Annual dividend increases since emergence in 2004. 5 Year (2009-13) Avg. Return on Equity: 10.1% 5 Year (2009-13) CAGR Dividend: 3.2% Current Dividend Yield Approximately 3.4% $1.34 $1.36 $1.44 $1.48 $1.52 $1.60 40% 50% 60% 70% 80% 90% 100% 110% 120% $1.20 $1.25 $1.30 $1.35 $1.40 $1.45 $1.50 $1.55 $1.60 2009 2010 2011 2012 2013 2014E Annual Dividend Per Share Payout Ratio (based on GAAP EPS) Dividend Per Share and Payout Ratio 9.5% 9.6% 11.0% 11.0% 9.6% 9.8% 0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 2009 2010 2011 2012 2013 2014E Return on Equity

Hard Assets Providing Real Value 11 (Left) We believe continued investment in our system to provide safe, reliable, environmentally responsible and cost-effective service for our customers will produce additional value for our shareholders. (Below) NWE total shareholder return has outperformed our peer group average and the Dow Jones Utility Average over the 1, 3 and 5 year periods ending August 31, 2014, and the S&P 500 index over the 5 year period ending August 31, 2014. $- $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 2009 2010 2011 2012 2013 M ill io ns Gross PP&E Net PP&E Enterprise Value Market Cap Property Plant and Equipment vs Market Value * Peer Group: ALE, AVA, BKH, CNL, EDE, EE, GXP, IDA, MGEE, PNM, POR, UIL, VVC, WR NWE 60.2% 14 Peer Avg. * 56.0% S&P 500 75.4% DJUA 46.2% 0% 10% 20% 30% 40% 50% 60% 70% 80% 3 Year Total Shareholder Return 8/31/2011 to 8/31/2014 NWE 24.5% 14 Peer Avg. * 20.9% S&P 500 25.2% DJUA 22.8% 0% 5% 10% 15% 20% 25% 30% 35% 40% 1 Year Total Shareholder Return 8/31/2013 to 8/31/2014 NWE 150.1% 14 Peer Avg. * 121.3% S&P 500 118.1% DJUA 86.2% 0% 20% 40% 60% 80% 100% 120% 140% 160% 5 Year Total Shareholder Return 8/31/2009 to 8/31/2014

$60 $70 $80 $90 $100 $110 $120 $130 2008 2009 2010 2011 2012 2013 Typical NorthWestern Electric and Natural Gas Bill (average Montana, South Dakota and Nebraska monthly residential customer bill) Electric (750 kW) Natural Gas (10 Dkt) Investment for Our Customers’ Benefit Over the past 5 years we have been reintegrating our Montana energy supply portfolio and invested to enhance system safety, reliability and capacity. We have made these prior enhancements with minimal impact to customers’ bills while delivering solid earnings growth for our investors. 2008-2013 CAGRs Estimated Rate Base: 12.9% GAAP Diluted EPS: 6.7% Typical electric bill: 0.5% Typical natural gas bill: (7.8%) 12 $1.00 $1.25 $1.50 $1.75 $2.00 $2.25 $2.50 $2.75 $3.00 $1,000 $1,250 $1,500 $1,750 $2,000 $2,250 $2,500 $2,750 $3,000 2008 2009 2010 2011 2012 2013 Rate Base and Earnings per Share Estimated Rate Base (Millions) GAAP Diluted EPS Ra te B as e -M ill io ns EPS -D ollars

$(200) $(150) $(100) $(50) $- $50 $100 $150 $200 $250 $300 2009 2010 2011 2012 2013 Dividends Maintenance Capex CFO CFO Less CapEx & Dividends M ill io ns While maintenance capex and total dividend payments have continued to grow since 2009 (4.1% and 4.6% CAGR respectively), Cash Flow from Operations has continued to outpace maintenance capex and averaged approximately $46 million of positive Free Cash Flow per year. We anticipate our Net Operating Loss balance to benefit our cash flow beyond 2016. Strong Cash Flows 13 (3) (1) 2009 Cash Flow from Operation (CFO) is adjusted to add back pension funding in excess of expense and Ammondson settlement paid. (2) CFO was significantly less in 2013 vs 2012 primarily due to the following: A) decrease in collection of receivables from customers of approximately $34.2 million which includes approximately $20 million associated with billing delays as a result of a new customer information system implemented in September 2013, B) $16.9 million from under collection of supply cost in our trackers, and C) higher interest payments of approximately $6.5 million. (3) See “Non-GAAP Financial Measure” slide in appendix for Free Cash Flows reconciliation. Components of Free Cash Flow (2) (1) $476 $434 $457 $255 $326 $596 $358 $429 $201 $244 $0 $100 $200 $300 $400 $500 $600 $700 2009 2010 2011 2012 2013 M ill io ns Net Operating Loss (NOL) Carryforward Balance Federal State (Montana)

Balance Sheet Strength and Liquidity 14 Annual ratio is average of each quarter end debt/cap ratio Excludes Basin Creek capital leases Goal: 50% - 55% Senior Secured Rating Senior Unsecured Rating Commercial Paper Outlook Fitch A- BBB+ F2 Positive Watch Moody's A1 A3 Prime-2 Stable S&P A- BBB A-2 Stable A security rating is not a recommendation to buy, sell or hold securities. Such ratings may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating. Credit Ratings $0 $50 $100 $150 $200 $250 $300 M ill io ns Year Debt Maturity Schedule 54.0% 55.5% 54.8% 54.3% 53.8% 30% 40% 50% 60% 2009 2010 2011 2012 2013 Debt to Capital Ratio $0 $50 $100 $150 $200 $250 $300 $350 Q3 '10 Q4 Q1 Q2 Q3 '11 Q4 Q1 Q2 Q3 '12 Q4 Q1 Q2 Q3 '13 Q4 Q1 Q2 M ill io ns Liquidity Actual >$100M Target

Net Investment in Existing Business 15 Maintenance capital expenditures have cumulatively outpaced depreciation by $190 million over the last five years (2009 to 2013), while maintaining a positive Free Cash Flow during the same period. ($150) ($100) ($50) $0 $50 $100 $150 $200 $250 2009 2010 2011 2012 2013 ($ m ill io ns ) Maintenance Capex vs. Depreciation Distribution System Infrastructure Project (DSIP) Capital Maintenance capex Depreciation Cumulative capex in excess of depreciation

High High High High High MT - Distribution System Infrastructure Project (DSIP) MT - Natural gas reserves MT - Spion Kop - wind (40 MW) SD - Aberdeen peaking generator (60 MW) SD - Neal pollution control equipment SD - Big Stone pollution control equipment MT - pending hydro asset acquisition Investment Project Summary 16 Energy Supply Distribution * As of June 30, 2014 Note: Color / label indicate NorthWestern Energy's current probability of execution and timing of expenditures. Several opportunities exist to further increase and diversify earnings as compared to our approximately $2.1 billion of rate base today. Figures above do not include maintenance capital investment in excess of depreciation. In September 2013, we announced the pending acquisition of 11 hydroelectric facilities from PPL Montana for $900 million. In September of 2014 the Montana Public Service Commission voted to direct commission staff to prepare an order approving the proposed transaction with a few conditions. We expect to close in the fourth quarter of 2014 pending timely regulatory approvals. In commercial operation April 2013 In commercial operation December 2012

Montana Hydro Acquisition - Update 17 • Announced, in September 2013, the $900 million acquisition of eleven baseload hydroelectric generating facilities representing 633 megawatts of capacity and one storage reservoir from PPL Montana. • On September 4, 2014, after a yearlong process, the Montana Public Service Commissioners voted 4-1 to direct commission staff to draft an order approving the inclusion of the assets into regulated rate base with the following summarized conditions: – Purchase price is $900 million; the rate-based amount is $870 million (adjusted for $30 million Kerr proceeds); – The 52% 48% debt to equity capital structure proposed is reasonable and acceptable; – Return on equity shall be 9.8% – Debt: The debt shall be long-term (~30 years) and shall not exceed 4.25% and should be executed with all swiftness possible; – Depreciation of the facilities shall occur over a fifty year period; – First year revenue requirement shall only include known and measureable property taxes currently paid by PPL Montana; – Kerr: The temporary acquisition of the facility shall create zero risk for the rate-payer with any and all financial risk associated with the term of NWE’s Kerr ownership to be born by NWE shareholders (with a compliance filing upon completion of transfer to demonstrate a zero or net benefit to rate payers); – Any future sale, transfer, etc. of NWE’s interest in any of the hydro assets, excluding Kerr, shall require regulatory approval of the Commission. – The proper ratemaking treatment of any future gains on any activity involving the hydro assets shall be determined by the commission recognizing that rate payers have carried certain risks of loss associated with the acquisition of the hydros. Cochrane Dam

Hydro – Next Steps 18 • It is anticipated the Montana Public Service Commission (MPSC) will approve the written order at either the September 18th or 23rd work sessions. Upon approval, we will be seeking authority from FERC to issue securities in connection with the transaction. We anticipate a FERC approval to take 30 to 60 days from the date of a MPSC approval. • Upon receipt of the FERC approval, we plan to close into permanent financing of up to $450 million of debt, up to $400 million of equity and up to $50 million of cash flows. If capital market access is limited we have the option of closing into the $900 million committed Bridge Facility with Credit Suisse and Bank of America Merrill Lynch. • One of the conditions directed by the MPSC in connection with its approval is that the Company issue long-term debt with an effective interest rate not to exceed 4.25%. Accordingly, on September 5, 2014, the Company entered into two separate 30-year treasury swap locks, with notional amounts totaling $450 million at a rate the Company anticipates will satisfy the MPSC's condition. • A fourth quarter 2014 close is anticipated, subject to timely regulatory approvals. • For additional information visit: http://www.northwesternenergy.com/hydroelectric-facilities Mystic Dam

The Hydro Facilities 19 Plant Net Capacity (MW) Ownership% COD River Source FERC License Expiration 5-Yr Avg. Capacity Factor(2) Black Eagle 21 100% 1927 Missouri 2040 73.6% Cochrane 69 100% 1958 Missouri 2040 49.1% Hauser 19 100% 1911 Missouri 2040 79.3% Holter 48 100% 1918 Missouri 2040 72.4% Kerr(3) 194 100% 1938 Flathead 2035 64.5% Madison 8 100% 1906 Madison 2040 89.2% Morony 48 100% 1930 Missouri 2040 63.8% Mystic 12 100% 1925 West Rosebud Creek 2050 48.2% Rainbow 60 100% 1910 / 2013 Missouri 2040 77.5% Ryan 60 100% 1915 Missouri 2040 79.8% Thompson Falls 94 100% 1915 Clark Fork 2025 60.1% Total 633 66.1% (1) Hebgen facility (0 MW net capacity) excluded from figures. All facilities are “run-of-river” dams except for Kerr and Mystic, which are “storage generation” (2) As of June 2013 (3) The Confederated Salish and Kootenai Tribes have an option to purchase Kerr from September 2015 thru 2025 Overview of Hydro Facilities(1) Black Eagle The transaction includes 11 hydroelectric facilities and one storage reservoir. The geographically diversified facilities are located in two different river basins, on five different river systems and on both sides of the continental divide. The units have a long operating history, have been well maintained, and stand ready to offer many more decades of zero-emission energy to our Montana customers.

Hydro - Supporting Our Values 20 Our Vision Statement: Working together to deliver safe, reliable and innovative energy solutions that create value for our customers, communities, employees and investors. The acquisition of these highly valuable assets should allow NorthWestern to further our mission statement for the benefit of all stakeholders for multiple generations to come. • Opportunity to acquire clean, reliable, long-lived generation assets near the bottom of commodity price cycle • Provides multiple generations of customers with long-term energy certainty and locks in rate stability with modest impact of less than 5% to November 2013 rates to total residential bills • Transaction helps match owned generation with load requirements • Increases fuel-type diversity of generation fleet with significant increase in sustainable generation • Consistent with focus on our existing regulated utility business and all of our customers • Reinforces and expands NorthWestern’s commitment to Montana, its people and its environment • Evolving environmental regulation may make Montana hydro assets even more valuable • Allows NorthWestern to increase its commitment to charitable giving throughout Montana • Combination of existing NorthWestern employees with extensive hydroelectric backgrounds and at least 70 PPL employees • Increased opportunity for professional growth for both existing employees and employees who transfer when the sale closes • NorthWestern remains committed to competitive pay and benefits • Inclusion of assets in regulated rate base • Expected to be accretive in first full year of operations • Expected to maintain or enhance credit strength Customers Communities Employees Investors

Coal (Colstrip 4) 29% Hydro (Pending) 42% Hydro (QF/contracted) 1% Wind (Spion Kop) 2% Wind (QF/contracted) 11%Natural Gas 1% Thermal (QF/contracted) 13% 21 Hydro – Owned and Contracted Resources MONTANA Yellowstone River ll t i r Yellowstone River ll t i ll t i Ye lo stone River l t i r Ye lo stone River ll t i Yellowstone ll t Yellowstone ll t ll t Ye lo stone l t Ye lo stone ll t River i r River i i River i r River i Missouri River i ri i r issouri River i i i i i i issouri River i ri i r issouri River i i i Missouri River i ri i r issouri River i i i i i i issouri River i ri i r issouri River i i i Madison River i i r adison River i i i i adison River i i r adison River i i Clark Fork l r r Clark Fork l l Clark Fork l r r Clark Fork l River i r River i i River i r River i Fort Peck Lake rt Fort Peck Lake t t Fort Peck Lake rt Fort Peck Lake t Flathead Lake l t Flathead Lake l t l t Flathead Lake l t Flathead Lake l t Billings illi Billings illi illi Bi lings i li Bi lings illi Colstrip l tri Colstrip l t i l t i Colstrip l tri Colstrip Glendive l i Glendive l i l i lendive l i lendive l i Helena l elena l l ele a l ele a l Great Falls r t ll Great Falls t ll t ll reat Fa ls r t l reat Fa ls t ll Missoula i l issoula i l i l issoula i l issoula i l Mystic i ystic i i ystic i ystic i Hebgen Hauser auser a ser a ser Black Eagle Holter Rainbow i ainbo i i ai i ai i Morony orony r y r y Cochrane ochrane c ra e c ra e Ryan yan ya ya Thompson Tho pson s s Falls ll Falls ll ll a ls l a ls ll Butte tt Butte tt tt Bu te t Bu te tt Kerr err err err Madison i adison i i a is i a is i Colstrip Spion Kop Dave Gates PPL Hydro Facilities NWE Coal Facilities NWE Wind Facilities NWE Gas Facilities Assets are a great fit within our service territory to serve our customers needs. 1.)The confederated Salish and Kootenai Tribes have an option to purchase Kerr Dam beginning September 2015. Owned and contracted hydro and wind will represent over 50% of our generation portfolio, in Montana, after the close of the pending hydro transaction. Montana Annual Production (Excludes Kerr Dam1) NorthWestern Owned Facilities Pro forma for Hydro Transaction

Hydro - Montana Generation Profile 22 99% 31% 44% NWE SD NWE MT NWE Total 99% 63% 69% NWE SD NWE MT NWE Total This transaction will allow us to approximately double owned resources in MT and significantly reduce our reliance on third-party power purchase agreements and spot market purchases. (1) Percentages based on MWh of net generation / MWh of total sales to ultimate customer. Excludes generation from Kerr. Owned and contracted wind and hydro generation currently provides approximately 12% of annual retail MWhs in Montana. Pro forma for the transaction, it is expected this will be in excess of 50%. Source: 2012 FERC Form 1 – Sources and Disposition of Energy Percentage by MWh Owned Resources for Retail Use as 12/31/2012 Owned Resources – NWE 2012 Actual Owned Resources - NWE Pro Forma with Hydro(1) 127% 122% 120% 105% 102% 98% 97% 91% 84% 78% 77% 64% 60% 60% 53% 44% 0% 20% 40% 60% 80% 100% 120% 140% WR GXP EE CNL UNS IDA EDE VVC ALE AVA UIL MGEE PNM BKH POR NWE Peer Average - 93%

Meeting Customer Demands 23 We expect to be able to provide nearly all the power during the light load periods with some flexibility to use market purchases or other resources to meet demand during heavy load periods. The addition of the hydro generation assets into our Montana electric portfolio aligns well with forecasted customer demand. - 100,000 200,000 300,000 400,000 Hydro Owned & Contract Light Load Demand Light Load Hours (MWh's) M W h' s - 100,000 200,000 300,000 400,000 500,000 Hydro Owned & Contract Heavy Load Demand Heavy Load Hours (MWh's) M W h' s Conveyance of Kerr Dam to CSKT Conveyance of Kerr Dam to CSKT

• Existing resources with no development risk. • Location within the service territory eliminates need for additional transmission to serve our customers. • Excellent fit for our portfolio’s needs. Meets our light-load need but we will need additional resources to meet our heavy-load needs. – Upon closing the hydro transaction we will continue to evaluate a variety of alternatives for meeting our heavy-load needs including: developing a natural gas facility, optimizing the hydro assets and market based purchases. • Non-carbon emitting - reduces environmental compliance cost and risk compared to other alternatives. • No fuel costs. Cost of service does not depend on future fuel prices. • Provides needed capacity, necessary for reliability, at the right time. – Strong balance sheet, low interest rates and favorable utility equity valuations to finance the transaction. – Assets valuations at favorable (lower) prices as compared to buying the same assets during higher commodity price periods. Hydro - A Great Fit at the Right Time 24 Thompson Falls Dam

Big Stone and Neal Air Quality Projects 25 Big Stone Power Plant Neal Power Plant Big Stone Neal Location Northeast South Dakota Northwest Iowa Ownership 23.4% of 475 MW coal plant 8.7% of 644 MW coal plant Project Subject to Best Available Retrofit Technology (BART) requirements of the Regional Haze Rule and are installing an Air Quality Control System (AQCS) to reduce SO2, NOx and particulates Subject to comply with national ambient air quality standards and Mercury & Air Toxics Standards (MATS) and are installing a scrubber, a baghouse, activated carbon and a selective non-catalytic reduction system Capital Outlay Capitalized approximately $56M through 6/30/14. Estimated total share of project is expected to be $95M-$105M including AFUDC and overheads Capitalized approximately $23M through 6/30/14, which is our total share of this project including AFUDC and overheads Timeline Project is on time and expected to be completed by April 2016 deadline Project was substantially completed in 2013, ahead of schedule, and is currently in service

Southern Bear Paw Transaction 26 • Finalized acquisition of Bear Paw South – On December 2, 2013, we finalized the purchase of 63 Bcf proven reserves and 82% interest in Havre Pipeline Company for $68.7 million. – Our largest natural gas reserves acquisition to date adding 29 employees to our 14 existing gas production employees. – The Montana PSC approved the structure of the transaction in October 2013 – With this transaction, we now manage an additional 900 wells and 82 miles of transmission in the Bear Paw Basin. – We will utilize our natural gas tracker to recover cost of gas similar to Battle Creek initially and Bear Paw North currently. • 20 Year levelized price of approximately $4.10 per dekatherm – Based upon 2014 estimates, this transaction increased owned supply for our Montana retail customers from approximately 8% to 32%. – At the time of the announced acquisition of the Bear Paw South reserves, we initially communicated the purchase, in the first year, would bring our owned production to 37% of our Montana requirements. A common characteristic of all natural gas production fields is declining annual production over time. We estimate our owned production will supply 32% of our projected 2014 retail natural gas needs in Montana. Blaine County Montana Compressor Station

Natural Gas Reserves Opportunity 27 We continue to pursue opportunities to secure low cost gas reserves for our customers. • Remaining 18% unfilled position to reach our targeted 50% owned supply. • Other potential opportunities to procure reserves to provide up to 50% (or 3-4 Bcf of natural gas annually) for Dave Gates Generating Station and our leased Basin Creek facility to also ensure fuel price stability for our electric customers. As we continue to add to our natural gas reserves portfolio, we anticipate a reduction in supply costs volatility for our customers. Battle Creek Bear Paw North Bear Paw South Announcement 9/22/2010 9/4/2012 5/28/2013 Purchase Price ($M) $12.4 $19.5 $68.7 Assets 8.4 Bcf of proven producing reserves plus gathering system 13.4 Bcf of proven producing reserves plus gathering system 63 Bcf of proven producing reserves plus gathering and 82 mile transmission line Recovery Status Rate Based Tracker Tracker (s tarted Dec. 2013) $- $20 $40 $60 $80 $100 $120 $140 $160 Transmission, Distribution & Storage Costs Natural Gas Supply Costs 10 Year Fluctuation in a 100 Therm Bill (Montana Residential Customers of NorthWestern)

Distribution System Infrastructure Project 28 • Montana Distribution System Infrastructure Project (DSIP) to maintain a safe and reliable electric and natural gas distribution system. – The primary goals: reverse the trend in aging infrastructure, maintain reliability, proactively manage safety, build capacity into the system, and prepare our network for the adoption of new technologies. – Based on our current plans, along with the MPSC's approval of the accounting order, we believe DSIP-related expenses and capital expenditures will be recovered in base rates through future general rate cases. ($millions) CAPEX O&M CAPEX O&M CAPEX O&M CAPEX O&M Electric Utility Total $59 $17 $45 $7 $127 $32 $231 $56 Natural Gas Utility Total 18 2 7 1 27 14 52 17 Other Total 4 6 - 1 0 9 4 16 Project Total $81 $25 $52 $9 $154 $55 $287 $89 Accounting Order ($13) $3 $10 $0 Estimated P&L Impact $12 $12 $65 $89 BudgetActual 2011 - 2013 2014 2015 - 2017 2011-17 Total Estimated Cost w/inflation

$182 $200 $170 $156 $147 $52 $50 $50 $50 $38 $29 $- $50 $100 $150 $200 $250 $300 2014 2015 2016 2017 2018 $M ill io ns Capital Spending Maintenance Capex Distribution System Infrastructure Project (DSIP) Energy Supply (primarily SD environmental projects) Capital Spending 29 DSIP – Distribution System Infrastructure Project - $202 million over the next 4 years. Energy Supply includes the planned environmental spending in South Dakota on Big Stone power plant. *Similar to DSIP, Transmission System Infrastructure Project (TSIP) intends to move us beyond basic compliance by evaluating the overall performance and health of our electric and natural gas transmission system. TSIP would prioritize and address transmission needs for the long-term benefit of our customers. Capital spending projections do not include potential future electric or natural gas energy supply additions, maintenance capital associated with our pending hydro acquisition, or capital related to our electric and gas TSIP*. Source: 2013 10-K.

Dave Gates Generating Station Update (DGGS) 30 • We operate a transmission system and balancing authority within Montana and are responsible for providing safe and reliable electric services to both retail and wholesale customers, or face stiff penalties for non-compliance. • DGGS was designed and constructed to provide NorthWestern with a resource to meet this important obligation. • Montana Public Service Commission provided pre-approval of the project in March 2009 with the groundbreaking in August. • Necessity of the plant has never been in question with the parties, including FERC Staff, agreeing through stipulation to a total revenue requirement. • The facility was completed on time and nearly $20 million under budget in December 2010 and is operating precisely as intended. • On September 21, 2012, a FERC Administrative Law Judge (ALJ) Initial Decision concluded that a significant portion of DGGS costs could not be allocated to wholesale customers, deviating from the previously approved allocation methodology. We have been recognizing revenue consistent with the initial decision and have $27.3 million reserved and subject to refund as of 6/30/14. • On April 17, 2014, nearly three and a half years after plant completion and almost 20 months after the ALJ’s initial decision, FERC issued an order affirming the initial decision. • In May 2014, we filed a request for rehearing, which remains pending. Included in our request we have argued that no refunds are due even if the cost allocation method is modified prospectively. The timing for FERC to act on our rehearing petition is uncertain, but could occur during the second half of 2014. Customer refunds, if any, will not be due until 30 days after a FERC order on rehearing. If unsuccessful on rehearing, we may appeal to a United States Circuit Court of Appeals. The time line for any such appeal could, depending on when the FERC issues a rehearing order extend into 2016 or beyond.

Conclusion 31 Fully- regulated utility Best practices corporate governance Strong track record of earnings and dividend growth Strong cash flows aided by Net Operating Loss (NOL) carryforwards Realistic investment opportunities to invest Free Cash Flow Aberdeen Peaker Plant Ground Breaking October 14, 2011 Aberdeen Peaker Plant Ribbon Cutting July 23, 2013

Appendix 32

2013 and 2014 Adjusted EPS Schedule 33 Q1 Q2 Q3 Q4 2014 2014 Reported GAAP diluted EPS 1.17$ 0.20$ $1.37 Non-GAAP Adjustments: Weather (0.05) 0.01 (0.04)$ Hydro Transaction related legal and professional fees 0.04 0.04 0.08$ 2014 Adjusted diluted EPS 1.16$ 0.25$ -$ -$ $1.41 Q1 Q2 Q3 Q4 2013 2013 Reported GAAP diluted EPS $1.01 $0.37 $0.40 $0.68 $2.46 Non-GAAP Adjustments: Weather (0.02) (0.02) (0.01) (0.05)$ Hydro Transaction related legal and professional fees 0.05 0.06 0.11$ DSM lost revenue recovery - portion related to 2012 (0.04) 0.02 (0.02)$ 2013 Adjusted diluted EPS $1.01 $0.35 $0.39 $0.75 $2.50

Income Statement 34 (in millions, except per share) 2014 2013 2014 2013 Operating Revenues $270.3 $260.2 $640.0 $573.2 Cost of Sales (Other) 112.5 106.9 279.9 239.1 Gross Margin 157.8 153.2 360.1 334.1 Operating Expenses Operating, general & administrative 74.4 67.4 146.4 136.2 Property and other taxes 28.0 25.8 56.5 51.6 Depreciation 30.4 27.4 60.7 56.6 Total Operating Expenses 132.7 120.6 263.7 244.4 Operating Income 25.1 32.7 96.4 89.7 Interest Expense (19.1) (17.1) (39.1) (33.9) Other Income 3.0 0.9 5.2 3.6 Income (Loss) Before Taxes 9.0 16.4 62.5 59.4 Income Tax (Expense) Benefit (1.2) (2.1) (9.2) (7.2) Net Income (Loss) $7.7 $14.3 $53.3 $52.2 Average Common Shares Outstanding 39.1 38.1 39.0 37.7 Basic Earnings per Average Common Share $0.20 $0.37 $1.37 $1.38 Diluted Earnings per Average Common Share $0.20 $0.37 $1.37 $1.38 Dividends Declared per Common Share $0.40 $0.38 $0.80 $0.76 Three Months Ended June 30, Six Months Ended June 30,

35 EPS Reconciliation (Qtr 2 2014 vs 2013) ($millions, except EPS) Th re e M on th s E nd ed , Ju ne 3 0, 2 01 3 N at ur al g as p ro du ct io n M ar gi n D S M lo st re ve nu e re co ve rie s N at ur al g as re ta il vo lu m es N at ur al g as p ro du ct io n ex pe ns e B ad d eb t e xp en se N on em pl oy ee d ire ct or s de fe rr ed co m pe ns at io n H yd ro T ra ns ac tio n co st s P er m an en t a nd fl ow -th ro ug h ad ju st m en ts to in co m e ta x Im pa ct o f h ig he r s ha re c ou nt A ll ot he r Th re e M on th s E nd ed , Ju ne 3 0, 2 01 4 Gross Margin 153.3$ 5.1 1.0 (0.9) (0.6) 157.9 Operating Expenses Op.,Gen., & Administrative 67.4 2.9 2.2 1.5 0.9 (0.5) 74.4 Prop. & other taxes 25.8 2.2 28.0 Depreciation and depletion 27.4 3.0 30.4 Total Operating Expense 120.6 - - - 2.9 2.2 1.5 0.9 - - 4.7 132.8 Operating Income 32.7 5.1 1.0 (0.9) (2.9) (2.2) (1.5) (0.9) - - (5.3) 25.1 Interest Expense (17.1) (1.9) (0.1) (19.1) Other Income (Expense) 0.9 1.5 0.6 3.0 Income Before Inc. Taxes 16.4 5.1 1.0 (0.9) (2.9) (2.2) - (2.8) - - (4.7) 9.0 Income Tax Benefit (Expense)1 (2.1) (2.0) (0.4) 0.3 1.1 0.8 - 1.1 (1.8) 1.7 (1.2) Net Income (Loss) 14.3$ 3.1 0.6 (0.6) (1.8) (1.4) - (1.7) (1.8) - (3.0) 7.8 Fully Diluted Shares 38.22 0.99 - 39.21 Fully Diluted EPS 0.37$ 0.08$ 0.02$ (0.02)$ (0.05)$ (0.04)$ -$ (0.04)$ (0.05)$ (0.00)$ (0.07)$ 0.20$ 1.) Income Tax Benefit (Expense) calculation on reconciling items assumes normal effective tax rate of 38.5%.

36 EPS Reconciliation (YTD through Qtr 2 2014 vs 2013) ($millions, except EPS) S ix M on th s E nd ed , Ju ne 3 0, 2 01 3 N at ur al g as p ro du ct io n N at ur al g as a nd e le ct ric re ta il vo lu m es M on ta na n at ur al g as ra te in cr ea se D S M lo st re ve nu e re co ve rie s N at ur al g as p ro du ct io n B ad d eb t e xp en se H yd ro T ra ns ac tio n co st s N on em pl oy ee d ire ct or s de fe rr ed co m pe ns at io n P er m an en t a nd fl ow -th ro ug h ad ju st m en ts to in co m e ta x Im pa ct o f h ig he r s ha re c ou nt A ll ot he r, ne t S ix M on th s E nd ed , Ju ne 3 0, 2 01 4 Gross Margin 334.1$ 14.6 7.0 4.9 1.5 (2.0) 360.1 Operating Expenses Op.,Gen., & Administrative 136.2 5.0 3.1 1.7 1.3 (0.9) 146.4 Prop. & other taxes 51.6 4.9 56.5 Depreciation and depletion 56.6 4.1 60.7 Total Operating Expense 244.4 - - - - 5.0 3.1 1.7 1.3 - - 8.1 263.6 Operating Income 89.6 14.6 7.0 4.9 1.5 (5.0) (3.1) (1.7) (1.3) - - (10.1) 96.5 Interest Expense (33.9) (3.8) (1.4) (39.1) Other Income (Expense) 3.6 1.3 0.3 5.2 Income Before Inc. Taxes 59.4 14.6 7.0 4.9 1.5 (5.0) (3.1) (5.5) - - - (11.3) 62.5 Income Tax Benefit (Expense)1 (7.2) (5.6) (2.7) (1.9) (0.6) 1.9 1.2 2.1 - (1.0) - 4.5 (9.2) Net Income (Loss) 52.2$ 9.0 4.3 3.0 0.9 (3.1) (1.9) (3.4) - (1.0) - (6.8) 53.3 Fully Diluted Shares 37.87 1.20 - 39.07 Fully Diluted EPS 1.38$ 0.23 0.11 0.08 0.02 (0.08) (0.05) (0.08) - (0.03) (0.04) (0.17) 1.37$ 1.) Income Tax Benefit (Expense) calculation on reconciling items assumes normal effective tax rate of 38.5%.

Cash Flow 37 (in millions) 2014 2013 Operating Activities Net Income 53.3$ 52.2$ Non-Cash adjustments to net income 95.4 87.6 Changes in working capital (6.4) 4.6 Other (17.8) (14.6) Cash provided by operating activities 124.6 129.8 Investing Activities PP&E additions (112.0) (88.5) Asset acquisition 1.5 - Other 0.1 0.7 Cash used in investing activities (110.4) (87.8) Financing Activities Proceeds from issuance of common stock, net 13.3 43.8 Repayments of short-term borrowings, net 4.9 (58.0) Dividends on common stock (30.9) (28.6) Other (1.1) (1.2) Cash used in financing activities (13.8) (44.0) Increase (Decrease) in Cash and Cash Equivale 0.4 (2.0) Beginning Cash 16.5 9.8 Ending Cash 16.9$ 7.8$ Six Months Ending June 30,

Balance Sheet 38 (in millions) As of June 30, As of December 31, 2014 2013 Cash 16.9$ 16.6$ Restricted cash 15.6 6.9 Accounts receivable, net 130.3 174.9 Inventories 52.9 55.6 Other current assets 74.9 67.0 Goodwill 355.1 355.1 PP&E and other non-current assets 3,146.0 3,039.2 Total Assets 3,791.8$ 3,715.3$ Payables 64.0 93.0 Current maturities of long-term debt & capital leases 1.7 1.7 Short-term borrowings 146.0 141.0 Other current liabilities 219.3 228.0 Long-term debt & capital leases 1,211.1 1,185.0 Other non-current liabilities 1,082.6 1,036.0 Shareholders' equity 1,067.2 1,030.7 Total Liabilities and Equity 3,791.8$ 3,715.3$ Capitalization: Current maturities of long-term debt & capital leases 1.7 1.7 Short Term borrowings 146.0 141.0 Long Term Debt & Capital Leases 1,211.1 1,185.0 Less: Basin Creek Capital Lease (30.7) (31.4) Shareholders' Equity 1,067.2 1,030.7 Total Capitalization 2,395.2$ 2,326.8$ Ratio of Debt to Total Capitalization 55.4% 55.7%

Effective Tax Reconciliation 39 (in millions) 2014 2013 2014 2013 Income (Loss) Before Income Taxes $9.0 $16.4 $62.5 $59.4 Income tax calculated at 35% federal statutory rate 3.1 5.8 21.9 20.8 Permanent or flow through adjustments: State income, net of federal provisions - (0.6) 0.4 (1.9) Flow-through repairs deductions (1.8) (2.1) (11.5) (9.8) Production tax credits (0.3) (0.5) (1.8) (1.7) Prior year permanent return to accrual adjustments - 0.5 - 0.5 Plant and depreciaiton of flow through items 0.1 (0.8) 0.5 - Other, net 0.1 (0.2) (0.3) (0.8) (1.9) (3.7) (12.7) (13.7) Income tax expense (benefit) $1.2 $2.1 $9.2 $7.1 Three Months Ended June 30, Six Months Ended June 30,

NorthWestern Energy Profile 40 TICKER: NWE Jurisdiction and Service Implementation Date Rate Base (in millions) (1) Estimated Rate Base (in millions) (2) Authorized Overall Rate of Return Authorized Return on Equity Authorized Equity Level Montana electic delivery (4) Januray 2011 632.5$ 774.5$ 7.80% 10.25% 48.0% Montana - DGGS (4) January 2011 172.7$ 137.5$ 8.16% 10.25% 50.0% Montana - Colstrip Unit 4 January 2009 400.4$ 343.8$ 8.25% 10.00% 50.0% Montana - Spion Kop December 2012 81.7$ 62.0$ 7.00% 10.00% 48.0% Montana natural gas delivery June 2013 309.2$ 362.7$ 7.48% 9.80% 48.0% Montana natural gas production November 2012 12.0$ 85.6$ 7.65% 10.00% 48.0% South Dakota electric (3) September 1981 186.7$ 251.0$ n/a n/a n/a South Dakota natural gas (3) December 2011 65.9$ 64.0$ 7.80% n/a n/a Nebraska natural gas (3) December 2007 24.3$ 25.4$ n/a 10.40% n/a 1,885.4$ 2,106.5$ (1) Rate base reflects amounts on which we are authorized to earn a return. (2) Rate base amounts are estimated as of December 31, 2013 (3) For those items marked as "n/a," the respective settlement and/or order was not specific as to these terms. (4) The FERC regulated portion of Montana electric transmission and DGGS are included as revenue credits to our MPSC jurisdiction customers. Therefore we do not separately reflect FERC authorized rate base or authorized returns. Rate Base as of 12/31/2013 Stock Price $52.19 Outstanding Shares 39.14M Market Capitalization $2.04B Net Debt $1.33B Total Enterprise Value $3.37B EBITDA - 12 months ending 6/30/14 $294M Market Capitalization to Book Equity 1.91 Avg. Common Shares Outstanding 39.00M Debt/Total Capitalization 55.4% Enterprise Value / EBITDA 11.48x Dividend 2014 (annualized) $1.60 Annualized Dividend Yield 3.07% Total Customer Count 678,200 Employees 1,493 Profile Data as of 6/30/2014 See "Non-GAAP Financial Measure" slide in appendix for Net Debt and EBITDA reconciliation Natural Gas $72 M Other ($11 M) Electric $233M EBITDA EBITDA - Earnings before Interest, Tax, Depreciation and Amortization - For the 12 months ending 6/30/14 - Other category includes $11.8 million of costs related to the hydro transaction announced in September 2013

2013 System Statistics 41 Note: Statistics above are as of 12/31/2013 (1) Nebraska is a natural gas only jurisdiction •MT Natural Gas reserves increased in 2013 with the addition 63 Bcf from the Bear Paw South acquisition. (1) Energy Supply Transmission Distribution Electric (MW) MT SD Total 2013 Tx for Others MT SD Total Demand MT SD / NE Total Base load coal 222 254 476 Electric (GWh) 10,300 100 10,400 Daily MWs 750 179 929 Wind 40 40 Natural Gas (Bcf) 22.8 - 22.8 Peak MWs 1,730 326 Other resources 150 106 256 Annual GWhs 6,400 1,560 7,960 Annual Bcf 19 11 30 Natural Gas (Bcf) MT SD Total System (miles) MT SD Total Proven reserves 76.7 - 76.7 Electric 6,900 1,300 8,200 Customers MT SD / NE Total Annual production 6.4 - 6.4 Natural gas 2,000 55 2,055 Electric 344,500 62,100 406,600 Storage 17.8 - 17.8 Natural gas 184,900 86,700 271,600 529,400 148,800 678,200 System (miles) MT SD / NE Total Electric 17,500 2,050 19,550 Natural gas 5,000 2,350 7,350 22,500 4,400 26,900

Well Rounded Board of Directors 42 Members of the Board of Directors tour backstage at The Mansfield Center for the Performing Arts in Great Falls, Montana. From the left: Dana J. Dykhouse – Chief Executive Officer of First PREMIER Bank. Director since 2009 Dorothy M. Bradley – Retired District Court Administrator for the 18th Judicial Court of Montana. Director since 2009 Denton Louis Peoples – Retired CEO and Vice Chairman of the Board of Orange and Rockland Utilities, Inc. Director since 2006 E. Linn Draper Jr. – Chairman of the Board – Retired Chairman, President and Chief Executive Officer of American Electric Power Co., Inc. Director since 2004 Robert C. Rowe – President and CEO of NorthWestern Corporation. Director since 2008 Julia L. Johnson – President and Founder of NetCommunications, LLC. Former Chairwoman of the Florida Public Service Commission. Director since 2004 Stephen P. Adik – Retired Vice Chairman of NiSource, Inc. Director since 2004 Philip L. Maslowe – Formerly Executive Vice President and Chief Financial Officer of The Wackenhut Corp. Director since 2004

Strong Executive Team 43 NorthWestern Energy’s executive officers tour backstage at The Mansfield Center for the Performing Arts in Great Falls, Montana. From the left: Michael R. Cashell – VP of Transmission. 27 years utility industry experience; current position since 2011 Curtis T. Pohl – VP of Distribution. 27 years utility industry experience; current position since 2003 Patrick R. Corcoran – VP of Government and Regulatory Affairs. 34 years utility industry experience; current position since 2001 Heather H. Grahame – VP and General Counsel. 29 years legal experience (21 years representing utilities); current position since 2010 Robert C. Rowe – President and CEO. 21 years of utility and regulatory experience (including 12 years on the Montana Public Service Commission); current position since 2008 John D. Hines – VP of Supply. 24 years utility industry experience; current position since 2011 Bobbi L. Schroeppel – VP of Customer Care, Communications and Human Resources. 20 years utility industry experience; current position since 2002 Brian B. Bird – VP and CFO. 28 years financial management experience with energy and other large industrial companies; current position since 2003 Kendall G. Kliewer – VP and Controller. 16 years finance management experience; current position since 2004

Our Commissioners 44

FERC’s April 17, 2014 Order 45 Relying on the regulatory process to provide an equitable outcome should be as American as…. apple pie.

The Back Story on DGGS 46 Background •NorthWestern Energy operates a transmission system and balancing authority within Montana and is charged with the responsibility of providing safe and reliable electric service to all of its customers. This includes retail and wholesale customers. • Part of NorthWestern’s responsibility is to continually balance all customer loads on the system with all resources on the system. This is a moment to moment requirement and is measured by NERC (North American Reliability Corporation) and WECC (Western Electricity Coordinating Council) criteria. Ultimately the FERC (Federal Energy Regulatory Commission) enforces these NERC and WECC reliability criteria and stiff civil penalties and sanctions can be imposed for non- compliance. • NorthWestern meets this reliability requirement by assuring that it has regulating resources available to constantly balance loads with resources. Regulating resources are sources of energy that can be ramped up or down quickly to balance changing customer load profiles with the energy supply resources available. Variable energy sources, such as wind, require significant balancing services. • For many years, since NorthWestern did not own any resources of its own to provide this service, NorthWestern was forced to rely on the volatile wholesale market to purchase regulating resources from third parties, from systems often very distant from NorthWestern. Support for DGGS • On May 20, 2009, the MPSC issued a Final Order approving DGGS finding that: “The Commission finds NWE provided compelling evidence of the imprudence and risk of continuing to rely exclusively on its longtime practice of contracting with other utilities in the region to meet its need for mandatory regulation service. NWE demonstrated its current need for 91 MW of regulating reserves in order to meet balancing authority requirements, provide safe and reliable service, and avoid the risk of significant financial penalties for violations of reliability standards. NWE’s projection that it will need 115 MW of regulation service by 2015 is reasonable as well”. •FERC stated in its November 2007 Order approving the third party purchase from Powerex: “We also find that NorthWestern has adequately addressed interveners’ arguments. Specifically, we find that NorthWestern has supported the term and level of services contained in the Agreement and explained why it did not elect to provide a back-stop bid based on its ownership interest in Colstrip Unit No. 4. In addition, NorthWestern has provided evidence that its circumstances are temporary because it now may build or otherwise acquire generation that may alleviate its need to purchase ancillary services from third parties. Therefore, we accept the Agreement for filing and grant Powerex’s request for waiver of Section 3 of its Rate Schedule No. 1 for the term of the Agreement (January 1, 2008 through December 31, 2008)”. Project Timeline: -Planning began in 2008 -MT PSC approved project in March ‘09 -Plant online in January ‘11 -MT PSC final approval in March ‘12 -FERC ALJ unfavorable initial ruling in September ’12 (19 months after DGGS started providing service) - FERC affirmed the initial ALJ decision in April ‘14 (40 months after DGGS was placed into service) - In May ‘14, we filed a request for rehearing, which remains pending

The Back Story on DGGS (continued) 47 Support for DGGS (continued) • On April 29, 2010, NorthWestern made a filing with FERC proposing to collect costs associated with DGGS under the same cost allocation methodology and for the same magnitude of Regulating Resource as had been previously approved by FERC when NorthWestern was providing such service under third party contracts. Unfortunately, neither the Initial Order, from the Administrative Law Judge or the Final Order doesn’t support FERC’s previous positions. •The Initial Order, from the FERC Administrative Law Judge, and the Final Order: • Does not challenge the prudency or costs of the DGGS. In fact, the parties agreed, through stipulation, on the total revenue requirement of DGGS. • Instead, FERC’s Order would seek to penalize NorthWestern for its decision to follow FERC precedent on the issue of the magnitude and allocation of costs. Ironically, the rate for DGGS advocated by the Montana Large Customer Group and which appeared to be adopted by the Initial Order would be approximately one-half of the rate that NorthWestern was previously recovering as a pass-through of costs under the third party contracts and approved by FERC! As a result • One side of FERC has ordered NorthWestern to meet reliability criteria and another side of FERC seeks to strip NorthWestern of its tools to meet such criteria (or at least the cost recovery of the tools). • It is important to note that NorthWestern still must meet its reliability criteria obligations or face stiff penalties, ultimately from FERC, the same regulatory agency that has found that NorthWestern only needs a fraction of the regulating service that it has constructed into DGGS and has been required traditionally to meet reliability criteria. In Summary • NorthWestern finds itself in a position where regulatory worlds have collided. No one disagrees that the generating plant is needed. No one argues the costs aren’t prudent. The Montana Public Service Commission issued a thoughtful and fact-based decision concerning the part of the Plant under its jurisdiction. The FERC process and decision seeks to either shift costs to state jurisdictional customers or allow them simply to fall between the cracks.

Non-GAAP Financial Measures 48 The data presented above includes financial information prepared in accordance with GAAP, as well as another financial measure, Gross Margin, Free Cash Flows, Net Debt and EBITDA, but is considered a “Non-GAAP financial measure.” 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), Free Cash Flows (Cash flows from operations less maintenance capex and dividends), Net Debt (Total debt less capital leases) and EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization) are Non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of Gross Margin, Free Cash Flows, Net Debt and EBITDA 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, Net Debt and EBITDA measures may not be comparable to other companies’ Gross Margin, Free Cash Flows, Net Debt and EBITDA measures. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance. (in millions) 2009 2010 2011 2012 2013 Cash flow from operations 116.8$ 218.9$ 233.8$ 251.2$ 193.7$ Adjustments * 88.4 Cash flow from operations - with adjustment 205.2$ 218.9$ 233.8$ 251.2$ 193.7$ * Adjustments: 2009 Cash flow from operations (CFO) is adjusted to add back pension funding in excess of expense and Ammondson settlement paid Property Plant & Equipment additions 189.4$ 228.4$ 188.7$ 219.2$ 230.5$ Less: Investment Growth (82.7) (113.4) (59.1) (86.0) (105.3) Maintenance Capex 106.7$ 115.1$ 129.7$ 133.2$ 125.2$ Free Cash Flow Cash Flow from Operations 205.2$ 218.9$ 233.8$ 251.2$ 193.7$ Less: Maintenance Capex (106.7) (115.1) (129.7) (133.2) (125.2) Less: Dividends (48.2) (49.0) (51.9) (54.2) (57.7) Free Cash Flow 50.4$ 54.9$ 52.2$ 63.7$ 10.9$ Use of Non-GAAP Financial Measures - Free Cash Flow - 2009 to 2013 (in millions) Electric Gas Other Total Operating Revenues 865.2$ 287.6$ 1.6$ 1,154.4$ Cost of Sales 358.7 120.9 - 479.5 Gross Margin 506.6$ 166.7$ 1.6$ 674.9$ (in millions) Montana South Dakota Nebraska Total Operating Revenues 938.6$ 179.9$ 36.0$ 1,154.4$ Cost of Sales 377.6 77.0 25.0 479.5 Gross Margin 561.0$ 102.9$ 11.0$ 674.9$ Use of Non-GAAP Financial Measures - Gross Margin for 2013 Use of Non-GAAP Financial Measures - Gross Margin for 2013 (in thousands) 2009 2010 2011 2012 2013 Reported GAAP diluted EPS 2.02$ 2.14$ 2.53$ 2.66$ 2.46$ Non-GAAP Adjustments Weather - 0.06 (0.05) 0.14 (0.05) Rate adjustments - (0.05) - - - Insurance recoveries - (0.08) - - - Income tax adjustments - - (0.17) (0.06) - Transmission revenue - low hydro - - 0.05 - - Dispute with former employee - - 0.05 - - DGGS FERC ALJ initial decision (2011 portion) - - - 0.12 - Release of MPSC DGGS deferral - - - (0.05) - DSM Lost Revenue recovery - - - (0.05) (0.02) CELP arbitration decision - - - (0.79) - MSTI Impairment - - - 0.40 - Hydro Transaction costs - - - - 0.11 Adjusted Non-GAAP diluted EPS 2.02$ 2.07$ 2.41$ 2.37$ 2.50$ Use of Non-GAAP Financial Measures - Reconcile to Non-GAAP diluted EPS (in thousands) Electric Gas Other Total Operating Revenues 895.2$ 325.2$ 0.9$ 1,221.3$ Cost of Sales 382.1 138.2 - 520.3 Gross Margin 513.1 187.0 0.9 701.0 Less: Operating Expenses Operating, general & administrative 198.1 56.0 12.1 266.2 Property and other taxes 81.3 28.0 0.0 109.3 EBITDA 233.7$ 102.9$ (11.1)$ 325.5$ Use of Non-GAAP Financial Measures - EBITDA for trailing 12 months ending 6/30/14 Use of Non-GAAP Financial Measures - Net Debt as of June 30, 2014 (in millions) Short & Long Term Debt and Capital Leases 1,358.8 Less: Cash and Cash Equivalents (16.9) Less: Capital Leases (30.7) Net Debt 1,311.2

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