NorthWestern (NWE) 8-K Investor Update | October 2014 Thompson Falls

Investor Update | October 2014 Thompson Falls

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 Electric Operations Montana: 344,500 customers - 187 communities 24,400 miles - transmission and distribution lines Owns 262 MW of baseload power generation Owns 105 MW of regulating services generation South Dakota: 62,100 customers - 110 communities 3,350 miles - transmission and distribution lines Owns 360 net MW of power generation Natural Gas Operations Montana: 184,900 customers - 105 communities 7,000 miles - transmission and distribution pipelines Owns 76.7 Bcf of proven gas natural reserves 17.75 Bcf of gas storage capacity South Dakota: 44,900 customers - 60 communities 1,639 miles - transmission and distribution pipelines Nebraska: 41,900 customers - 4 commu ities 775 miles - distribution pipelines All data as of 12/31/2013

NorthWestern Energy Profile 4 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 Natural Gas $73 M Other ($5 M) Electric $229 M EBITDA EBITDA - Earnings before Interest, Tax, Depreciation and Amortization - For the 12 months ending 9/30/14 - Other category includes $3.9 million of costs related to the hydro transaction announced in September 2013 Stock Price (as of 9/30/14) $45.36 Outstanding Shares 39.14M Market Capitalization $1.78B Net Debt $1.33B Total Enterprise Value $3.11B EBITDA - 12 months ending 9/30/14 $297M Market Capitalization to Book Equity 1.64 Avg. Common Shares Outstanding 39.05M Debt/Total Capitalization 55.2% Dividend 2014 (annualized) $1.60 Annualized Dividend Yield 3.53% Total Customer Count 678,200 Employees 1,493 Profile Data as of 9/30/2014 See "Non-GAAP Financial Measure" slide in appendix for Net Debt and EBITDA r conciliation

NWE: An Investment for the Long Term 5 • 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 • Constructive regulatory relationship • Customer service satisfaction scores above the survey average • 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) • Recognized by Cogent Reports as top trusted utility brand in the Northwest 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 • Pending hydro transaction will increase rate base & provide energy supply stability • Disciplined capital investment program • Reintegrating energy supply portfolio (electric and supply) • Distribution System Infrastructure Project (DSIP) • Transmission System Infrastructure Project (TSIP) & other transmission opportunities within our service territory Pure Play Electric & Gas Utility Solid Utility Foundation Strong Earnings & Cash Flows Attractive Future Growth Prospects Best Practices Corporate Governance (NYSE Ethics) (Say on Pay)

A Diversified Electric and Gas Utility 6 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 83% Montana 15% South Dakota 2% Nebraska 83% Residential 16% Commercial 1% Industrial 75% Electric 25% Natural Gas Our 2015 gross margin, inclusive of the hydro assets, is anticipated to be comprised of approximately 80% electric Service Type and 90% Montana Jurisdiction. 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.

$- $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 0 25 50 75 100 125 150 M in u te s 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 In erruption Frequency Index (SAIFI) 600 700 800 2009 2010 2011 2012 2013 Ind ex Sc or e NorthWestern Energy Score JD Power 26 Combination Electric and Natural Gas Company Average JD Power - Customer Service Index Score Strong Utility Foundation 7 EEI – 2nd Quartile Performance Electric source: Edison Electric Institute Typical Bills and Average Rates Report, 1/1/14 Natural gas source: US Dept of Energy Monthly residential supply and delivery rates as of 1/1/14 0 2 4 6 8 10 5.30 6.80 Leaks per 100 Miles f Pipe Excluding Excavation Damages - 2013 NWE - 2013 AGA 1st Quartile Average - 2013 Strong utility operations:  Customer service satisfaction scores in line with survey average (JD Powers)  Residential electric and natural gas rates below national average  Solid electric system reliability (EEI 2nd quartile) and low gas leaks per mile (AGA 1st quartile)

Solid Economic Indicators 8 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 Nati nal Av rage 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 dat through June 30th

$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 We are reaffirming our 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 the remainder of 2014; • Excludes any hydro related transaction fees (including legal and bridge financing) and, assuming FERC approval of our financing, excludes any potential income generated from the operation of the hydro assets post-closing; • 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 12% to 14% (previously 14% to 16%) of pre-tax income after removal of $16.9 million of tax benefits recognized during the third quarter that relate specifically to years prior to 2014; and • Diluted average shares outstanding of 39.3 million, which excludes additional shares we expect to issue in the fourth quarter 2014 in conjunction with the pending hydro transaction. 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”.

$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 2014 Midpoint Annual Dividend Per Share Payout Ratio (based on GAAP EPS) Dividend Per Share and Payout Ratio 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% 9.5% 9.6% 11.0% 11.0% 9.6% 9.8% 0% 2% 4% 6% 8% 10% 12% 2009 2010 2011 2012 2013 2014 Midpoint Return o Equity

Total Shareholder Return 11 * Peer Group: ALE, AVA, BKH, CNL, EDE, EE, GXP, IDA, MGEE, PNM, POR, UIL, VVC, WR NWE 59.3% 14 Peer Avg. * 48.4% S&P 500 86.1% DJUA 43.4% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 3 Year Total Shareholder Return 10/1/2011 to 9/30/2014 NWE 4.5% 14 Peer Avg. * 11.0% S&P 500 19.7% DJUA 18.7% 0% 5% 10% 15% 20% 25% 30% 35% 40% 1 Year Total Shareholder Return 10/1/2013 to 9/30/2014 NWE 129.5% 14 Peer Avg. * 103.5% S&P 500 107.3% DJUA 80.0% 0% 20% 40% 60% 80% 100% 120% 140% 5 Year Total Shareholder Return 10/1/2009 to 9/30/2014 -50% 0% 50% 100% 150% 200% 250% 11/ 2/2 004 5/2 /20 05 11/ 2/2 005 5/2 /20 06 11/ 2/2 006 5/2 /20 07 11/ 2/2 007 5/2 /20 08 11/ 2/2 008 5/2 /20 09 11/ 2/2 009 5/2 /20 10 11/ 2/2 010 5/2 /20 11 11/ 2/2 011 5/2 /20 12 11/ 2/2 012 5/2 /20 13 11/ 2/2 013 5/2 /20 14 NWE Peer Average S&P 500 DJU Babcock & Brown Transaction announced Babcock & Brown Transaction Terminated Start of economic downturn NWE added to S&P Small Cap 600 Index Total Shareholder Return 11/2/04 to 9/30/14 NWE 178.1% Peer Avg. 127.7% DJU 162.3% S&P 500 114.7% NWE annouces DGGS FERC ALJ decision NWE - Total Shareholder Return since Emergence Comparison NWE announces hydro assets acquisition 9/3 0/2 014

$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 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) Non-GAAP Diluted EPS Rate Bas e -M illion s EPS -Dollars See “Non-GAAP Financial Measures” slide in appendix for “Non-GAAP Adjusted EPS” reconciliation.

$(200) $(150) $(100) $(50) $- $50 $100 $150 $200 $250 $300 2009 2010 2011 2012 2013 Dividends Maintenance Capex CFO CFO Less CapEx & Dividends Mil lion s 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. Even with the anticipated additional income generated from hydro assets, we anticipate flow-through tax benefits to continue to keep our book effective tax rate at or below approximately 20% through 2017. Additionally, we expect NOLs to be available into 2017 to reduce cash taxes. 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 $70 2009 2010 2011 2012 2013 Mi llio ns Net Operating Loss (NOL) Carryforward Balance Federal State (Montana)

$0 $50 $100 $150 $200 $250 $300 $350 '10 Q4 Q1 Q2 Q3 '11 Q4 Q1 Q2 Q3 '12 Q4 Q1 Q2 Q3 '13 Q4 Q1 Q2 Q3 M illi on s Liquidity Actual >$100M Target 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 54.0% 55.5% 54.8% 54.3% 53.8% 30% 40% 50% 60% 2009 2010 2011 2012 2013 Debt to Capital Ratio $0 $100 $200 $300 $400 $500 M illi on s Year Debt Maturity Schedule Note: Dotted blue maturity in 2044 is pro forma for assumed $450MM first mortgage bonds to fund hydro transaction

Net Investment in Existing Business 15 ($150) ($100) ($50) $0 $50 $100 $150 $200 $250 2009 2010 2011 2012 2013 ($m illi on s) Maintenance Capex vs. Depreciation Distribution System Infrastructure Project (DSIP) Capital Maintenance capex Depreciation Cumulative capex in excess of depreciation 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. Prior capital spending on South Dakota supply projects (Big Stone $64M, Neal $23M, Aberdeen Peaker $55M)* are not included in the capex above. We plan to seek recovery for these investments through our anticipated SD electric rate filing in the fourth quarter 2014. *South Dakota supply capital spending totals through September 30, 2014

Montana Hydro Acquisition - Update 16 • 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 26, 2014, after a yearlong process, the Montana Public Service Commission issued a final order approving the application, subject to certain conditions, including the following: – Inclusion of $870 million of the $900 million purchase price for the hydro assets in our Montana jurisdictional rate base with a 50-year life; – Return on equity of 9.8%, a cost of debt of 4.25% and a capital structure of 52% debt and 48% equity, resulting in an associated first year annual retail revenue requirement of approximately $117 million; – Authorized issuance in aggregate of $900 million of securities necessary to complete the purchase, with the debt portion of the financing to have a term of 30 years and not to exceed 4.25%; – A final compliance filing in December 2015 to reflect post-closing adjustments, the conveyance of the Kerr project (with no financial risk to customers) and the actual property tax expense for the hydroelectric facilities; and – Tracking of revenue credits on a portfolio basis through our electricity supply costs tracker. Cochrane Dam

Hydro – Next Steps 17 • On September 26th, following receipt of the MPSC Final Order, we requested the final necessary approval from the Federal Energy Regulatory Commission (FERC) to issue securities in connection with the hydro transaction. We anticipate FERC approval to take 30 to 60 days from the date of our filing. • Upon receipt of the FERC approval, we plan to close into permanent financing of up to $450 million of long-term 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 forward starting interest rate swaps to effectively fix the benchmark interest rate associated with the anticipated $450 million debt issuance at a rate the company anticipates will meet the MPSC's condition. • A fourth quarter 2014 close is anticipated, subject to timely FERC approval. • For additional information visit: http://www.northwesternenergy.com/hydroelectric-facilities Mystic Dam

The Hydro Facilities 18 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.

• Existing resources built for our distribution and transmission 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. • 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. • Assets valuations at favorable (lower) prices as compared to buying during high commodity price periods. • Strong balance sheet, low interest rates and favorable utility equity valuations to finance the transaction. Hydro - A Great Fit at the Right Time 19 Thompson Falls Dam

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% 20 Hydro – Owned and Contracted Resources MONTANA Yellowstone River ll t r Yellowstone River ll t r ll t r Ye lowstone River l t r Ye lowstone River ll t r Yellowstone ll t Yellowstone ll t ll t Ye lowstone l t Ye lowstone ll t River r River r r River r River r Missouri River i ri r Missouri River i ri r i ri r issouri River i ri r issouri River i ri r Missouri River i ri r Missouri River i ri r i ri r Missouri River i ri r Missouri River i ri r Madison River i r Madison River i r i r adison River i r adison River i r Clark Fork r r Clark Fork r r r r Clark Fork r r Clark Fork r r River r River r r River r River r Fort Peck Lake rt Fort Peck Lake rt rt Fort Peck Lake rt Fort Peck Lake rt Flathead Lake l t Flathead Lake l t l t Flathead Lake l t Flathead Lake l t Billings Billi Billings li li Billings Billi Billings li Colstrip l tri Colstrip l tri l tri Colstrip l tri Colstrip Glendive l i Glendive l i l i Glendive l i Glendive l i Helena l Helena l l Helena l Helena l Great Falls r t ll Great Falls r t ll r t ll Great Fa ls r t l Great Fa ls r t ll Missoula i l Missoula i l i l issoula i l issoula i l Mystic ti ystic ti ti ystic ti ystic ti Hebgen Hauser Hauser Hauser Hauser Black Eagle Holter Rainbow Rainbo i i i ainbo Rainbo i i Morony orony orony orony Cochrane Cochrane chrane chrane Ryan yan yan yan Thompson Tho pson Tho pson Tho pson Falls ll Falls ll ll Fa ls l Fa ls ll Butte tt Butte tt tt Bu te t Bu te tt Kerr Ker Kerr Kerr er Kerr Madison i adison i i adison i adison 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 Transaction1

Meeting Customer Demands 21 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) MWh 's - 100,000 200,000 300,000 400,000 500,000 Hydro Owned & Contract Heavy Load Demand Heavy Load Hours (MWh's) MWh 'sConveyance of Kerr Dam to CSKT Conveyance of Kerr Dam to CSKT

Big Stone and Neal Air Quality Projects 22 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 $64M through 9/30/14. Estimated total share of project is expected to be $95M-$105M including AFUDC and overheads Capitalized approximately $23M through 9/30/14, 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

Owned Owned Target Total Annual Need Natural Gas Reserves Opportunity 23 As we continue to add to our natural gas reserves portfolio, we anticipate a reduction in supply cost volatility for our customers. $- $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) First ~6 Bcf annual production acquired for ~$100M Remaining 6-7 Bcf annual production needed to meet target. Estimated ~$100M We continue to pursue opportunities to secure low cost gas reserves for our customers. • Three acquisitions totaling approximately $100 million since September 2010: • 84.8 Bcf of natural gas reserves and associated gathering systems along with 82 miles of transmission. • Provides approximately 6 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)

Distribution System Infrastructure Project 24 • 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/improve reliability and safety; – build capacity into the system; and – prepare our network for the adoption of new technologies. – Approximately $314 million* of capital investment into the multiyear project above and beyond the approximately $125 - $150 million of annual maintenance capex in Montana. * DSIP capital investment estimate from project launch in 2011 through 2018.

Transmission System Infrastructure Project 25 • Montana Transmission System Infrastructure Project (TSIP) to maintain a safe and reliable electric and natural gas transmission system. – The primary project goals: – reverse the trend in aging infrastructure; – maintain/improve reliability and safety; – build capacity into the system; and – prepare our network for the adoption of new technologies in our electrical and gas transmission operations as well as our T&D substations. – Three areas of focus: – Electric Transmission System - (TSIP) – Natural Gas Transmission System - (GTIP) – Sub-Stations - (SSIP) – We will continue to work with stakeholders to define project size, scope and timeline.

Dave Gates Generating Station Update (DGGS) 26 • 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.

2014 to 2015 Preliminary Earnings & Dividend Bridge PRELIMINARY 2015 ESTIMATES Basic assumptions include, but are not limited to: • Normal weather in our electric and natural gas service territories; • Assumes successful integration and a full year earnings contribution from the pending hydro transaction; • Excludes any potential additional impact as a result of the FERC decision regarding revenue allocation at our Dave Gates Generating Station; • A consolidated effective income tax rate of approximately 15% - 19% of pre- tax income; and • Diluted average shares outstanding of approximately 49.1 million on the low end of guidance and 47.5 million at the high end of guidance. Shares outstanding for 2015 are dependent upon results of planned $400 million equity issuance to fund hydro transaction and therefore are currently shown as a range with an estimated issuance price of $41 to $49 per share. * Other 2015 Earnings drivers shown above are calculated using a 38.5% effective tax rate. The anticipated “Incremental tax benefits” in 2015 are primarily due to increased repairs tax deductions resulting from higher maintenance capital spending and other flow-through tax impacts. 27 Low Midpoint High $2.60 - $2.75 2014 Adjusted EPS midpoint $2.68 $2.68 $2.68 2015 Earnings drivers (after-tax per share) Gross margin improvements 2.70 - 2.82 OG&A expense increases (0.95) - (0.89) Property & other taxes (0.31) - (0.29) Depreciation & depletion (0.36) - (0.34) Interest expense / other income (0.26) - (0.22) Incremental tax benefits * 0.18 - 0.22 $1.00 - $1.30 $3.68 - $3.98 Dilutive impact of $400 million share issuance (0.73) - (0.68) $2.95 - $3.30 2015 Preliminary EPS midpoint $3.13 2015 Preliminary EPS guidance range $2.95 - $3.30 2015 Preliminary targeted dividend payout ratio 60% 60% $1.77 $1.98 2015 Preliminary targeted dividend midpoint $1.88 2015 Preliminary targeted dividend range 2015 Preliminary EPS guidance range 2015 EPS prior to dilution Subtotal of anticipated improvements 2014 Non-GAAP Adjusted EPS guidance range

$182 $197 $200 $203 $170 $52 $51 $52 $54 $24 $38 $32 $16 $39 $40 $56 $10 $9 $12 $9 $272 $306 $300 $309 $259 $- $50 $100 $150 $200 $250 $300 $350 2014 2015 2016 2017 2018 $M illio ns Estimate as of October 2014 Maintenance Capex DSIP Big Stone TSIP Hydro Capital Spending Forecast 28 Current estimated cumulative capital spending for 2014 through 2018 is $1.45 billion (upper chart), an increase of $330 million over last year’s estimate (bottom chart). We anticipate to be able to fund the updated capital projects with a combination of cash flow (aided by NOLs) and long term debt. If other opportunities arise that are not in the projections (natural gas reserves, peaking generation, acquisitions, etc.), new equity funding may be necessary. Note: The capital forecasts above do not include $900m purchase price for pending hydro acquisition or any potential future natural gas reserve acquisitions. $182 $200 $170 $156 $147 $52 $50 $50 $50 $38 $29 $- $50 $100 $150 $200 $250 3 3 2014 2015 2016 2017 2018 $M illion s As reported in the 2013 10-K 272 $279 $220 $206 $147

Conclusion 29 Pure Play Electric and Gas Utility Solid Utility Foundation Strong Earnings and Cash Flows Attractive Future Growth Prospects Best Practices Corporate Governance Aberdeen Peaker Plant Ground Breaking October 14, 2011 Aberdeen Peaker Plant Ribbon Cutting July 23, 2013

Appendix 30

Non-GAAP Adjusted EPS We anticipate an improvement in the fourth quarter 2014 EPS over the same quarter in 2013 due primarily to customer and load growth, a full quarter of Bear Paw South earnings contribution (asset was placed into service in December 2013), cost controls and a lower effective tax rate. 31 Note: Sum of 2014 quarterly GAAP and Adjusted EPS shown above total $2.14 and $1.79 respectively, or $0.01 greater than when calculated on a year-to-date basis ($2.13 and $1.78). This difference is due to rounding and dilutive share counts used for individual quarters vs the year-to-date calculation. 2014 Q1 Q2 Q3 YTD '14 Low High Low High Reported GAAP diluted EPS $1.17 $0.20 $0.77 $2.13 $0.82 - $0.97 $2.95 - $3.10 Non-GAAP Adjustments: Weather (0.05) 0.01 (0.04) Hydro transaction (Professional fees & bridge financing) 0.04 0.04 0.04 0.12 (0.43) (0.43) Adjusted diluted EPS $1.16 $0.25 $0.38 $1.78 $0.82 - $0.97 $2.60 - $2.75 2013 Q1 Q2 Q3 YTD '13 Reported GAAP diluted EPS $1.01 $0.37 $0.40 $1.78 Non-GAAP Adjustments: Weather (0.02) (0.02) (0.04) Hydro transaction (Professional fees & bridge financing) 0.05 0.05 Prior period DSM lost revenue (Including accrued interest) (0.04) (0.04) Adjusted diluted EPS $1.01 $0.35 $0.39 $1.75 Income Tax Benefits Release of unrecognized tax benefits and safe harbor election (prior years) (0.43) Q4 '13 (0.01) 0.06 ESTIMATED TO MEET GUIDANCE $0.68 Full Year 2013 $2.46 (0.05) $2.50 Full Year 2014 $0.75 ? ? ? Q4 '14 0.02 0.12 (0.04) 0.11 (0.02)

Income Statement 32 (in millions, except per share items) 2014 2013 2014 2013 Operating Revenues 251.9$ 262.3$ 892.0$ 835.5$ Cost of Sales 94.6 104.3 374.5 343.4 Gross Margin 157.3 158.0 517.5 492.1 Operating Expenses Operating, general & administrative 68.1 72.5 214.6 208.7 Property and other taxes 27.8 26.0 84.3 77.5 Depreciation 30.5 28.1 91.1 84.7 Total Operating Expenses 126.4 126.6 390.0 370.9 Operating Income 31.0 31.4 127.4 121.1 Interest Expense (18.8) (17.1) (57.9) (51.0) Other (Expense)/Income (0.4) 3.1 4.7 6.8 Income (Loss) Before Taxes 11.8 17.5 74.3 76.9 Income Tax (Expense)/Benefit 18.4 (1.8) 9.2 (9.0) Net Income (Loss) 30.2$ 15.6$ 83.5$ 67.9$ Average Common Shares Outstanding 39.1 38.5 39.0 38.0 Basic Earnings per Average Common Share $0.77 $0.41 $2.14 $1.79 Diluted Earnings per Average Common Share $0.77 $0.40 $2.13 $1.78 Dividends Declared per Common Share $0.40 $0.38 $1.20 $1.14 Three Months Ended September 30, Nine Months Ended September 30,

33 EPS Reconciliation (Qtr 3 2014 vs 2013) ($millions, except EPS) Thr ee M ont hs End ed, Sep tem ber 30, 201 3 DS M lo st r eve nue rec ove ries Ope ratin g ex pen ses rec ove red in tr ack er Ele ctric ret ail v olum es Ele ctric tra nsm issi on c apa city Nat ura l ga s pr odu ctio n Nat ura l ga s re tail volu me s Non -em ploy ee d irec tors def erre d com pen sati on Hyd ro t ran sac tion cos ts Bad deb t ex pen se Nat ura l ga s pr odu ctio n Per ma nen t an d flo w-th rou gh adju stm ents to i nco me tax Imp act of h ighe r sh are cou nt All o ther Thr ee M ont hs End ed, Sep tem ber 30, 201 4 Gross Margin 158.0$ (4.9) (1.7) (1.3) 3.5 2.8 0.5 0.4 157.3 Operating Expenses Op.,Gen., & Administrative 72.5 (1.7) (3.6) (2.2) (0.6) 2.6 1.1 68.1 Prop. & other taxes 26.0 1.8 27.8 Depreciation and depletion 28.1 2.4 30.5 Total Operating Expense 126.6 - (1.7) - - - - (3.6) (2.2) (0.6) 2.6 - - 5.3 126.4 Operating Income 31.4 (4.9) - (1.3) 3.5 2.8 0.5 3.6 2.2 0.6 (2.6) - - (4.8) 31.0 Interest Expense (17.1) (1.9) 0.2 (18.8) Other Income (Expense) 3.1 (3.6) 0.1 (0.4) Income Before Inc. Taxes 17.5 (4.9) - (1.3) 3.5 2.8 0.5 - 0.3 0.6 (2.6) - - (4.6) 11.8 Income Tax Benefit (Expense)1 (1.8) 1.9 - 0.5 (1.3) (1.1) (0.2) - (0.1) (0.2) 1.0 18.2 - 1.6 18.4 Net Income (Loss) 15.6$ (3.0) - (0.8) 2.2 1.7 0.3 - 0.2 0.4 (1.6) 18.2 - (3.0) 30.2 Fully Diluted Shares 38.65 0.64 - 39.28 Fully Diluted EPS 0.40$ (0.08)$ -$ (0.02)$ 0.06$ 0.04$ 0.01$ -$ 0.01$ 0.01$ (0.04)$ 0.46$ (0.01)$ (0.07)$ 0.77$ 1.) Income Tax Benefit (Expense) calculation on reconciling items assumes normal effective tax rate of 38.5%. NORTHWESTERN CORPORATION Three Months Ended September 30, 2014

34 EPS Reconciliation (YTD through Qtr 3 2014 vs 2013) NORTHWESTERN CORPORATION Nine Months Ended September 30, 2014 ($millions, except EPS) Nin e M on ths En ded , Se pte mb er 30, 20 13 Na tura l ga s p rod uct ion Mo nta na nat ura l ga s ra te i ncr eas e Ele ctri c tr ans mis sio n c apa city Ele ctri c re tail vo lum es Na tura l ga s re tail vo lum es DS M l ost rev enu es Op era ting ex pen ses rec ove red in trac ker s Na tura l ga s p rod uct ion Ba d d ebt ex pen se No n-e mp loy ee dire cto r de ferr ed com pen sat ion Hy dro tra nsa ctio n c ost s Pe rm ane nt a nd flow -thr oug h a dju stm ent s to i nco me tax Imp act of hig her sh are co unt All oth er, net Nin e M on ths En ded , Se pte mb er 30, 20 14 Gross Margin 492.1$ 17.4 4.9 3.5 3.4 2.8 (3.0) (2.1) (1.5) 517.5 Operating Expenses Op.,Gen., & Administrative 208.7 (2.1) 7.6 2.5 (2.2) (1.0) 1.1 214.6 Prop. & other taxes 77.5 6.8 84.3 Depreciation and depletion 84.7 6.4 91.1 Total Operating Expense 370.9 - - - - - - (2.1) 7.6 2.5 (2.2) (1.0) - - 14.3 390.0 Operating Income 121.1 17.4 4.9 3.5 3.4 2.8 (3.0) - (7.6) (2.5) 2.2 1.0 - - (15.8) 127.4 Interest Expense (51.0) (5.7) (1.2) (57.9) Other Income (Expense) 6.8 (2.2) 0.2 4.7 Income Before Inc. Taxes 76.9 17.4 4.9 3.5 3.4 2.8 (3.0) - (7.6) (2.5) - (4.7) - - (16.8) 74.3 Income Tax Benefit (Expense)1 (9.0) (6.7) (1.9) (1.3) (1.3) (1.1) 1.2 - 2.9 1.0 - 1.8 17.3 - 6.4 9.2 Net Income (Loss) 67.9$ 10.7 3.0 2.2 2.1 1.7 (1.8) - (4.7) (1.5) - (2.9) 17.3 - (10.4) 83.5 Fully Diluted Shares 38.16 1.02 - 39.19 Fully Diluted EPS 1.78$ 0.27 0.08 0.06 0.05 0.04 (0.05) - (0.12) (0.04) - (0.07) 0.44 (0.05) (0.26) 2.13$ 1.) Income Tax Benefit (Expense) calculation on reconciling items assumes normal effective tax rate of 38.5%.

Cash Flow 35 (in millions) 2014 2013 Operating Activities Net Income 83.5$ 67.9$ Non-Cash adjustments to net income 123.0 123.6 Changes in working capital 36.5 6.5 Other (38.1) (26.7) Cash provided by operating activities 205.0 171.3 Investing Activities PP&E additions (186.1) (154.0) Other (37.6) 3.9 Cash used in investing activities (223.7) (150.1) Financing Activities Proceeds from issuance of common stock, net 12.4 43.0 Issuance (Repayments) of short-term borrowings, net 54.7 (20.1) Dividends on common stock (46.4) (43.1) Financing costs (0.8) - Cash provided by (used in) financing activities 19.9 (20.2) Increase in Cash and Cash Equivalents 1.2 1.1 Beginning Cash 16.5 9.8 Ending Cash 17.7$ 10.9$ Nine Months Ending September 30, $34 million year-to-date improvement in cash flow from operations as compared to 2013.

Balance Sheet 36 (in millions) As of September 30, As of December 31, 2014 2013 Cash 17.7$ 16.6$ Restricted cash 38.4 6.9 Accounts receivable, net 120.7 174.9 Inventories 63.0 55.6 Other current assets 80.7 67.0 Goodwill 355.1 355.1 PP&E and other non-current assets 3,198.7 3,039.2 Total Assets 3,874.3$ 3,715.3$ Payables 61.9 93.0 Current maturities of long-term debt & capital leases 1.7 1.7 Short-term borrowings 169.9 141.0 Other current liabilities 259.5 228.0 Long-term debt & capital leases 1,210.7 1,185.0 Other non-current liabilities 1,088.8 1,036.0 Shareholders' equity 1,081.7 1,030.7 Total Liabilities and Equity 3,874.3$ 3,715.3$ Capitalization: Current maturities of long-term debt & capital leases 1.7 1.7 Short Term borrowings 169.9 141.0 Long Term Debt & Capital Leases 1,210.7 1,185.0 Less: Basin Cre k Capital Lease (30.3) (31.4) Less: New Market Tax Credit Financing Debt (18.2) - Shareholders' Equity 1,081.7 1,030.7 Total Capitalization 2,415.5$ 2,327.0$ Ratio of Debt to Total Capitalization 55.2% 55.7%

Effective Tax Reconciliation 37 The $12.6 million release of unrecognized tax benefits resulted from the lapse of statute of limitation in the third quarter of 2014. In addition, we submitted a tax accounting method change related to the deductibility of repair costs to bring our existing method into alignment with the safe harbor method, resulting in an income tax benefit of approximately $4.3 million for the cumulative tax accounting method change adjustment for years prior to 2014. (in millions) 2014 2013 Variance 2014 2013 Variance Income Before Income Taxes 11.8$ 17.5$ (5.7)$ 74.3$ 76.9$ (2.6)$ Income tax calculated at 35% federal statutory rate 4.1 6.1 (2.0) 26.0 26.9 (0.9) Permanent or flow through adjustments: State income, net of federal provisions (0.1) (0.7) 0.6 0.3 (2.6) 2.9 Release of unrecognized tax benefits (12.6) - (12.6) (12.6) - (12.6) Safe harbor method election (prior year impact) (4.3) - (4.3) (4.3) - (4.3) Other prior year permanent return to accrual adjustments (0.9) - (0.9) (0.9) 0.5 (1.4) Flow-through repairs deduction (3.4) (3.1) (0.3) (14.9) (12.9) (2.0) Plant and depreciation of flow through items (0.7) - (0.7) (0.2) - (0.2) Produ tio tax credits (0.3) (0.5) 0.2 (2.1) (2.2) 0.1 Other, net (0.2) - (0.2) (0.5) (0.7) 0.2 (22.5) (4.3) (18.2) (35.2) (17.9) (17.3) Income tax (benefit)/expense (18.4)$ 1.8$ (20.2)$ (9.2)$ 9.0$ (18.2)$ Nine Months Ended September 30, Three Months Ended September 30,

(in millions) Income before taxes $53.6 $8.9 $11.8 $74.3 ($2.7) $8.0 $79.6 Statutory tax rate (Federal & State) x 38.5% x 38.5% x 38.5% x 38.5% x 38.5% x 38.5% x 38.5% Tax expense before adjustments ($20.6) ($3.4) ($4.5) ($28.5) $1.0 ($3.1) ($30.6) Permanent or flow through adjustments: Flow-through repairs 9.7 1.8 3.4 14.9 14.9 Production tax credits 1.4 0.3 0.3 2.0 2.0 Release of unrecognized tax benefits 12.6 12.6 (12.6) 0.0 Return to accrual adjustments 5.2 5.2 (4.3) 0.9 Other miscellaneous adjustments 1.5 0.1 1.4 3.0 3.0 Income tax (expense) benefit ($8.0) ($1.2) $18.4 $9.2 $1.0 ($3.1) ($16.9) ($9.8) Net Income $45.6 $7.7 $30.2 $83.5 ($1.7) $4.9 ($16.9) $69.8 Effective Tax Rate 14.9% 13.5% -155.9% -12.4% 38.5% 38.5% N/A 12.3% REMOVE IMPACT OF: GAAP Non-GAAP Updated Effective Tax Rate Guidance 38 Even excluding the significant tax benefits recognized in the third quarter, we are lowering our full year 2014 tax rate guidance from 14% – 16% down to 12% – 14%. This reduction in our 2014 effective tax rate guidance is primarily due to the election and implementation of the safe harbors method for electric transmission and distribution repairs during the third quarter. Even with the anticipated additional income generated from the hydro assets, we anticipate flow-through tax benefits to continue to keep our book effective tax rate at or below approximately 20% through 2017. Additionally, we expect NOLs to be available into 2017 to reduce cash taxes.

(in millions) Three Months Ended September 30, 2014 Fa vo ra bl e we at he r Hy dr o tra ns ac tio n ex pe ns e No n- em p. d ef er re d co m pe ns at io n Re le as e of u nr ec og ni ze d ta x be ne fit s an d sa fe h ar bo r el ec tio n (p rio r y ea rs ) Three Months Ended September 30, 2014 Three Months Ended September 30, 2013 Pr io r y ea r D SM re ve nu e No n- em p. d ef er re d co m pe ns at io n Hy dr o tra ns ac tio n ex pe ns e Fa vo ra bl e we at he r Three Months Ended September 30, 2013 Revenues $251.9 $251.9 ($6.5) -2.5% $258.4 (2.3) (1.5) $262.2 Cost of sales 94.6 94.6 (9.7) -9.3% 104.3 104.3 Gross Margin 157.3 - - - - 157.3 3.2 2.1% 154.2 (2.3) - - (1.5) 158.0 Op. Expenses OG&A 68.1 (0.6) 2.2 69.7 1.3 2.0% 68.3 (1.4) (2.8) 72.5 Prop. & other taxes 27.8 27.8 1.8 7.0% 26.0 26.0 Depreciation 30.5 30.5 2.4 8.6% 28.1 28.1 Total Op. Exp. 126.3 - (0.6) 2.2 - 127.9 5.6 4.5% 122.3 - (1.4) (2.8) - 126.5 Op. Income 31.0 - 0.6 (2.2) - 29.4 (2.4) -7.5% 31.8 (2.3) 1.4 2.8 (1.5) 31.4 Interest expense (18.8) 1.9 (16.9) 0.2 -0.8% (17.1) (17.1) Other income (0.4) 2.2 1.8 0.1 2.6% 1.7 (1.4) 3.1 Pretax Income 11.8 - 2.5 - - 14.3 (2.1) -13.1% 16.4 (2.3) - 2.8 (1.5) 17.5 Income tax 18.4 - (1.0) - (16.9) 0.6 2.0 -140.0% (1.4) 0.9 - (1.1) 0.6 (1.8) Net Income $30.2 - 1.5 - (16.9) $14.8 ($0.2) -1.1% $15.0 (1.4) - 1.7 (0.9) $15.6 ETR -156.9% - 38.5% - - -4.0% 8.7% 38.5% - 38.5% 38.5% 10.4% Diluted Shares 39.3 39.3 39.3 39.3 39.3 39.3 0.6 1.6% 38.6 38.6 38.6 38.6 38.6 38.6 Diluted EPS $0.77 - 0.04 - (0.43) $0.38 (0.01)$ -2.6% $0.39 (0.04) - 0.05 (0.02) $0.40 Incr. / (Decr.) $ % Remove Impact of: GAAP Non-GAAP Non-GAAP Remove Impact of: GAAP Third Quarter Non-GAAP Adjusted P&L 39

Year-to-Date Non-GAAP Adjusted P&L (in millions) Nine Months Ended September 30, 2014 Fa vo ra bl e we at he r Hy dr o tra ns ac tio n ex pe ns e No n- em p. d ef er re d co m pe ns at io n Re le as e of u nr ec og ni ze d ta x be ne fit s an d sa fe h ar bo r el ec tio n (p rio r y ea rs ) Nine Months Ended September 30, 2014 Nine Months Ended September 30, 2013 Pr io r y ea r D SM re ve nu e No n- em p. d ef er re d co m pe ns at io n Hy dr o tra ns ac tio n ex pe ns e Fa vo ra bl e we at he r Nine Months Ended September 30, 2013 Revenues $891.9 (2.7) $889.2 $58.6 7.1% $830.6 (2.3) (2.5) $835.4 Cost of sales 374.5 374.5 31.1 9.1% 343.4 343.4 Gross Margin 517.4 (2.7) - - - 514.7 27.5 5.6% 487.2 (2.3) - - (2.5) 492.0 Op. Expenses OG&A 214.6 (2.3) (0.6) 211.7 9.0 4.4% 202.7 (2.8) (3.3) 208.7 Prop. & other taxes 84.3 84.3 6.8 8.7% 77.5 77.5 Depreciation 91.1 91.1 6.5 7.6% 84.7 84.7 Total Op. Exp. 390.0 - (2.3) (0.6) - 387.1 22.2 6.1% 364.9 - (2.8) (3.3) - 371.0 Op. Income 127.4 (2.7) 2.3 0.6 - 127.6 5.3 4.3% 122.4 (2.3) 2.8 3.3 (2.5) 121.1 Interest expense (57.9) 5.6 (52.3) (1.3) 2.5% (51.0) (51.0) Other income 4.7 (0.6) 4.2 0.2 4.4% 4.0 (2.8) 6.8 Pretax Income 74.3 (2.7) 8.0 - - 79.6 4.2 5.6% 75.4 (2.3) - 3.3 (2.5) 76.9 Income tax 9.2 1.0 (3.1) - (16.9) (9.8) (1.4) 16.7% (8.4) 0.9 - (1.3) 1.0 (9.0) Net Income $83.5 (1.7) 4.9 - (16.9) $69.8 $2.8 4.2% $67.0 (1.4) - 2.0 (1.5) $67.9 ETR -12.4% 38.5% 38.5% - - 12.3% 11.1% 38.5% - 38.5% 38.5% 11.7% Diluted Shares 39.2 39.2 39.2 39.2 39.2 39.2 1.0 2.7% 38.2 38.2 38.2 38.2 38.2 38.2 Diluted EPS $2.13 (0.04) 0.12 - (0.43) $1.78 0.03$ 1.7% $1.75 (0.04) - 0.05 (0.04) $1.78 Incr. / (Decr.) $ % GAAP Remove Impact of: Non-GAAP Non-GAAP Remove Impact of: GAAP 40

Hydro - Montana Generation Profile 41 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%

Forbes America's Most Trustworthy Companies 2013 For the 3rd consecutive time, 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. NWE was one of only three utilities to be distinguished with this honor, by Forbes, in 2013. Cogent Reports NorthWestern Energy was among 53 companies nationwide to earn the honor bestowed by Cogent Reports at Market Strategies International, which surveyed utility customers to develop brand-trust scores. NorthWestern earned the top regional score for combined electric and natural gas utility. 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. Fortnightly 40 For the second year in a row, NorthWestern Energy was 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. 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 2014, for the third 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 42

2013 System Statistics 43 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 44 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 45 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 46 Name Party Began Serving Term Ends Kirk Bushman R Jan-13 Jan-17 Bill Gallagher (Chairman) R Jan-11 Jan-15 Travis Kavulla R Jan-11 Jan-15 Roger Koopman R Jan-13 Jan-17 Bob Lake R Jan-13 Jan-17 Commissioners are elected in statewide elections from each of five districts. Chairperson is elected by fellow Commissioners. Commissioner term is 4 years, Chairperson term is 2 years. Montana Public Service Commission Name Party Began Serving Term Ends Kristie Fiegen R Aug-11 Jan-19 Gary Hanson (Chairman) R Jan-03 Jan-15 Chris Nelson R Jan-11 Jan-17 Commissioners are elected in statewide elections. Chairperson is elected by fellow Commissioners. Commissioner term is 6 years, Chairperson term is 1 year. South Dakota Public Utilities Commission Name Party Began Se ving Term Ends Anne Boyle D Jan-97 Jan-15 Rod Johnson R Jan-93 Jan-17 Frank Landis Jr. (Chairman) R Jan-89 Jan-19 Tim Schram R Jan-07 Jan-19 Gerald Vap R Aug-01 Jan-17 Commissioners are elected in statewide elections. Chairperson is elected by fellow Commissioners. Commissioner term is 6 years, Chairperson term is 1 year. Nebraska Public Service Commission

FERC’s April 17, 2014 Order 47 Relying on the regulatory process to provide an equitable outcome should be as American as…. apple pie.

The Back Story on DGGS 48 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) 49 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 50 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: Maintenanc C p x (106.7) (115.1) (129.7) (133.2) (125.2) Less: Dividen (48.2) (49.0) (51.9) (54.2) (57.7) Free Cash Fl w 50.4$ 54.9$ 52.2$ 63.7$ 10.9$ Use of Non-GAAP Financial Measures - Free Cash Flow - 2009 to 2013 (in mllions) Electric Gas Other Total Op rating 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$ Us 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 Re orted GAAP diluted EPS 2.02$ .1$ 2.53$ 2.66$ 2.46$ Non-GAAP Adjustments Weather - 0.06 (0.05) 0.14 (0.05) Rate adjustments - (0.05) - - - Insurance rec veries - (0.08) - - - Income tax adjustments - - (0.17) (0.06) - Transmission rev u - low hydro - - 0.05 - - Dispute with fo mer e p oy e - - 0.05 - - DGGS FERC ALJ iti l d ision (2011 portion) - - - 0.12 - Release of MPSC DGGS d ferral - - - (0.05) - DSM Lost Reve u recovery - - - (0.05) (0.02) CELP arbitration d cisi n - - - (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 Updated U f N n-GAAP Financial Measur s - Net Debt as of September 30, 2014 (in milli ns) Short & Long Term Debt and Capital Leases 1,382.3 Les : C sh and Cash Equivalents (17.7) Less: Capital Leases (30.3) Less: New Market Tax Credit Financing Debt (18.2) Net Debt 1, 34.3 (in thousands) Electric Gas Other Total Operating Revenues 880.5$ 329.9$ 0.6$ ,211.0$ Co t of Sales 371.6 139.1 - 510.6 Gross Margin 509.0 190.8 0.6 700.4 Less: Operating Expenses Operating, general & administrative 197.4 88.2 5.8 291.4 Property and other taxes 82.3 30.0 0.0 112.3 EBITDA 229.2$ 72.7$ (5.2)$ 296.7$ Use of Non-GAA Fi ncial Measures - EBITDA for trailing 12 months ending 9/30/14

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