1 48th Annual EEI Financial Conference | Nov. 10-13, 2013

2 FORWARD LOOKING STATEMENTS During the course of this presentation, there will be forward-looking statements within the meaning of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address our expected future business and financial performance, and often contain words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” or “will.” The information in this presentation is based upon our current expectations as of the date 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 public filings with the SEC.

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 Best practices corporate governance; and – A strong and well rounded board and executive team – Named to the Forbes “Americas Most Trustworthy Companies” for the 3rd consecutive year Attractive future growth prospects – Reintegrating energy supply portfolio (electric and natural gas) – Distribution System Infrastructure Program (DSIP) – Transmission opportunities within our service territory

Natural Gas $45 M Other ($5 M) Electric $243 M EBITDA NORTHWESTERN ENERGY PROFILE 5 TICKER: NWE Jurisdiction and Service Implementation Date Rate Base (in millions) (1) Estimated Rate Base (in millions) (2) Authorized Overall Rate of Return Authorized Return on Equity Authorized Equity Level South Dakota natural gas (3) December 2011 65.9$ 62.0$ 7.80% n/a n/a Montana electic delivery (4) January 2011 632.5$ 724.6$ 7.80% 10.25% 48.0% Montana natural gas delivery (5) April 2013 309.5$ 353.8$ n/a 9.80% n/a Montana natural gas production November 2012 12.0$ 10.9$ 7.65% 10.00% 48.0% DGGS (4) January 2011 172.7$ 155.6$ 8.16% 10.25% 50.0% Montana - Colstrip Unit 4 January 2009 400.4$ 356.8$ 8.25% 10.00% 50.0% Montana - Spion Kop December 2012 83.6$ 82.1$ 7.00% 10.00% 48.0% Nebraska natural gas (3) December 2007 24.3$ 23.1$ n/a 10.40% n/a South Dakota electric (3) September 1981 186.7$ 200.2$ n/a n/a n/a 1,887.6$ 1,969.1$ (1) Rate base reflects amounts on which we are authorized to earn a return. (2) Rate base amounts are estimated as of December 31, 2012 (3) For those items marked as "n/a," the respecitve 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. (5) Updated to reflect Final Order received in April 2013 (based on 2011 test year) Rate Base as of 12/31/2012 EBITDA - Earnings before Interest, Tax, Depreciation and Amortization for the 12 months ending 12/31/12 . Stock Price * $47.01 Outstanding Shares 38.65M Market Capitalization * $1.81B Net Debt $1.15B Total Enterprise Value * $2.96B EBITDA - 12 months ending 12/31/12 $283M Market Capitalization to Book Equity * 1.81 Avg. Common Shares Outstanding 37.98M Debt/Total Capitalization 53.6% Enterprise Value / EBITDA * 10.47x Dividend 2013 - 3 Qtrs annualized $1.52 Annualized Dividend Yield * 3.23% Total Customer Count as of 12/31/12 673,200 Employees as of 12/31/12 1,430 Profile Data All data as of 9/30/13, unless noted * Market Data as of 10/29/13 See "Non-GAAP Financial Measure" slide in appendix for Net Debt and EBITDA reconciliation

STRONG & WELL ROUNDED MANAGEMENT 6 E. Linn Draper Jr. Chairman of the Board Retired Chairman, President and Chief Executive Officer of American Electric Power Co., Inc. Director since 2004 Stephen P. Adik Retired Vice Chairman of NiSource, Inc. Director since 2004 Dorothy M. Bradley Retired District Court Administrator for the 18th Judicial Court of Montana. Director since 2009 Dana J. Dykhouse President and CEO of First PREMIER Bank. Director since 2009 Julia L. Johnson President and Founder of NetCommunications, LLC. Former Chairperson of the Florida Public Service Commission. Director since 2004 Phillip L. Maslowe Formerly Executive VP and CFO of The Wackenhut Corp. Director since 2004 Denton Louis Peoples Retired CEO and Vice Chairman of the Board of Orange and Rockland Utilities, Inc. Director since 2006 Robert C. Rowe President and CEO of NorthWestern Corporation. Director since 2008 BOARD OF DIRECTORS Robert C. Rowe President and CEO. 20-plus years of energy, utility and regulatory experience; current position since 2008 Brian B. Bird VP - CFO. 27 years financial management experience with energy and other large industrial companies; current position since 2003 Patrick R. Corcoran VP of Government and Regulatory Affairs. 33 years utility industry experience; current position since 2001 Michael R. Cashell VP of Transmission. 26 years utility industry experience; current position since 2011 Heather H. Grahame VP and General Counsel. 28 years legal experience; current position since 2010 John D. Hines VP of Supply. 23 years utility industry experience; current position since 2011 Kendall G. Kliewer VP and Controller. 15 years finance management experience; current position since 2004 Curtis T. Pohl VP of Distribution. 26 years utility industry experience; current position since 2003 Bobbi L. Schroeppel VP of Customer Care, Communications and Human Resources. 19 years utility industry experience; current position since 2002 EXECUTIVE TEAM

STRONG CORPORATE GOVERNANCE 7 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 2013 For the 3rd year in a row, 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. 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 CITIZENSHIP 8 Montana Business of the Year NorthWestern Energy was recently selected as the 2012 Business of the Year by the Montana Ambassadors. The Ambassadors are a group of 120 business leaders from across Montana, the Pacific Northwest and the Bay Area of California who work to increase the economic vitality of Montana. Community Works Community Works encompasses NorthWestern Energy's tradition of funding community activities, charitable efforts and economic development within its service territory. NorthWestern Energy's Community Works programs currently provide more than $1.5 million annually in funds for community sponsorships, charitable contributions and economic development organizations in Montana, South Dakota and Nebraska. Worksite Health In May 2012 NorthWestern Corporation was recognized, by the Montana Worksite Health Promotion Coalition, for excellence in promoting worksite health and earned the Gold Award, for our wellness program "Energize Your Life." NorthWestern Energy works to help build strong communities everywhere we serve.

3.47% 4.46% 5.60% 3.67% 0% 1% 2% 3% 4% 5% 6% US National Average Montana South Dakota Nebraska Source: Economic & Social Research Institute (ESRI) via SNL Database 10-30-13 Projected Population Growth 2012-2017 (cumulative growth) SOLID ECONOMIC INDICATORS 9 Top Left: Unemployment rate consistently below National Average for our service territory. National Ranking (SD 2nd, NE 3rd & MT 8th) 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 above National Average for all three states we service provides potential for additional organic growth (average annualized growth of approximately 90 basis points). 0% 2% 4% 6% 8% 10% 12% 2009 2010 2011 2012 2013 US National Average Montana South Dakota Nebraska Source: US Department of Labor via SNL Database 10-30-13 Unemployment Rate (as reported in August each year) 0.25% 0.30% 0.25% 0.21% 0.29% 0.21% .00% 0.20% 0.40% 0.60% 0.80% 1.00% 2007 2008 2009 2010 2011 2012 Write-Off to Revenue Ratio

A DIVERSIFIED ELECTRIC AND GAS UTILITY 10 The “80/20” rules of NorthWestern Gross Margin in 2012: Electric: $528M Natural Gas: $146M Other $ 1M Gross Margin in 2012 Montana: $570M South Dakota: $ 95M Nebraska: $ 10M Average Customers in 2012: Residential: 557k Commercial: 107k Industrial: 6k Above data reflects full year 2012 results. Jurisdiction and service type based upon gross margin contribution. See “Non-GAAP Financial Measures” slide in appendix for Gross Margin reconciliation.

600 700 800 2009 2010 2011 2012 In de x 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 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) STRONG UTILITY FOUNDATION 11 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, 1/1/13 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

$1.78 $2.02 $2.14 $2.53 $2.66 $- $1.25 $1.50 $1.75 $2.00 $2.25 $2.50 $2.75 $3.00 2008 2009 2010 2011 2012 2013E GAAP Diluted EPS 2013 EARNINGS GUIDANCE 12 Updated and increased 2013 guidance range of $2.45-$2.60 based upon, but not limited to, the following major assumptions and expectations: • A consolidated income tax rate of approximately 12% of pre-tax income; • Normal weather in our electric and natural gas service territories for the remainder of 2013; • Excludes any potential additional impact as a result of the FERC decision regarding revenue allocation at our Dave Gates Generating Station; and • Diluted average shares outstanding of 38.3 million. Continued investment in our system to serve our customers and communities is expected to provide average earnings per share growth and dividend growth of 4-6% annually. That, coupled with an anticipated dividend yield of 3-4%, should provide good results for investors over the foreseeable future. In July we updated our 2013 Non-GAAP Adjusted EPS Range from $2.40 - $2.55 per diluted share to $2.45 - $2.60 per diluted share with a midpoint of $2.53. Initial Guidance Range Non-GAAP "Adjusted" EPS Diluted Earnings Per Share

2014 EARNINGS ASSUMPTIONS 13 Transaction fees, including legal and bridge financing, related to the hydro acquisition are excluded from the 2014 EPS assumptions. Post closing income and operating expenses related to the hydro assets are also excluded from the assumptions as the transaction is subject to regulatory approval. If approved, the transaction is anticipated to close the second half of 2014. 2014 Expectations/Assumptions - Bear Paw South (Devon) natural gas reserves transaction expected to add approximately $.06 to $.10 per share - Full year benefit of Montana Natural Gas rate case expected to add approximately $.08 to $.12 per share - Additional gross margin adding between $.25 to $.35 per share from 2013 - OA&G expenses to increase from 2013 by approximately $.05 to $.10 per share - Property tax and other expenses are expected to increase from $.08 to $.10 compared to 2013 - Depreciation expense to increase about $.02 to $.04 per share from 2013 - Combination of increased interest expense and decreased AFUDC expected to decrease earnings by approximately $.04 to $.08 per share - Dilution from dribble program to reduce earnings by approximately $.07 to $.08 per share Full year revenues from 2013 Montana natural gas rate case (Rate case finalized in Q2 2013) Full year revenues from 2013 South Dakota Electric rate case Environmental riders on Big Stone and Neal compliance projects (The need for a rate filing and rider has been mitigated by reduced depreciation rates, as a result of a recent depreciation study, and continuted AFUDC accrual on Big Stone and Neal power plants.) AFUDC on DSIP capital additions Possible additional natural gas reserves 2013 expectations as communicated at 2012 EEI

TRACK RECORD OF DELIVERING RESULTS 14 Notes: - ROE in 2011 & 2012, on a Non-GAAP Adjusted basis, would be 10.5% and 9.8% respectively. - 2013 ROE and 2013 Dividend payout ratio estimate based on midpoint of updated guidance range of $2.45 - $2.60. - 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 steadily improved each year from 2008 – 2012 and Dividend per Share increased each of the last 5 years. 5 Year (2008-12) Avg. Return on Equity: 9.8% 5 Year (2008-12) CAGR Dividend: 2.9% Current Dividend Yield Approximately 3.2% 8.5% 9.5% 9.6% 11.0% 11.0% 10.1% 0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 2008 2009 2010 2011 2012 2013E $M illio ns Return on Equity $1.32 $1.34 $1.36 $1.44 $1.48 1.52 40% 50% 60% 70% 80% 90% 100% 1 0% 120% $1.20 $1.25 $1.30 $1.35 $1.40 $1.45 $1.50 $1.55 $1.60 2008 2009 2010 2011 2012 2013E Annual Dividend Per Share Payout Ratio (based on GAAP EPS) Dividend Per Share and Payout Ratio

HARD ASSETS PROVIDING REAL VALUE 15 (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) With the exception of the 1 year return versus S&P 600 (on which we are listed), NWE total shareholder return has outperformed our peer group average, the S&P 600 index and the Dow Jones Utility Average over the 1, 3 and 5 year periods ending October 31, 2013. * Peer Group: ALE, AVA, BKH, CNL, EDE, EE, GXP, IDA, MGEE, PNM, POR, UIL, UNS, VVC, WR $- $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 2008 2009 2010 2011 2012 M illi on s Gross PP&E Net PP&E Enterprise Value Market Cap Property Plant and Equipment vs Market Value NWE 78.3% 15 Peer Avg. * 57.1% S&P 600 75.8% DJUA 40.9% 0% 10% 20% 30% 40% 50% 60% 70% 80% 3 Year Total Shareholder Return 11/1/2010 to 10/31/2013 NWE 198.2% 15 Peer Avg. * 101.5% S&P 600 132.6% DJUA 63.9% 0% 50% 100% 15 % 200% 250% 5 Y ar Total Shareholder Return 11/1/2008 to 10/31/2013 NWE 33.4% 16 Peer Avg. * 15.7% S&P 600 37.4% DJUA 10.1% 0% 5% 10% 15% 20% 25% 30% 35% 40% 1 Year Total Shareh lder Return 11/1/2012 to 10/3 2013

INVESTMENT FOR OUR CUSTOMER’S BENEFIT $69.57 $68.78 $70.03 $73.26 $74.95 $60 7 8 $90 2008 2009 2010 2011 2012 Retail Electric Revenue per Megawatt hour (MWh) $11.20 $9.8 $9.1 $8.92 $8.66 $- 3 6 9 $12 5 2008 2009 20 0 2011 2012 Retail Natural Gas Revenue p r Dekatherm (Dkt) 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. 2008-2012 CAGRs Estimated Rate Base: 14.5% GAAP Diluted EPS: 10.6% Elec. retail rev./ MWh : 1.9% Nat. Gas retail rev./Dkt: (6.2%) 16 $1.00 $1.25 $1.50 $1.75 $2.00 $2.25 $2.50 $2.75 $3.00 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 $2,000 $2,200 2008 2009 2010 2011 2012 Rate Base and Earnings per Share Estimated Rate Base GAAP Diluted EPS Rate Bas e -M illion s EPS -Dollars

While maintenance capex and total dividend payments have continued to grow over the past 5 years (6.1% and 2.1% CAGR respectively), Cash Flow from Operations has continued to outpace maintenance capex and provided approximately $40-60 million of positive Free Cash Flow per year. We anticipate our Net Operating Loss balance to benefit our cash flow beyond 2016. (1) 2009 Cash Flow from Operations (CFO) is adjusted to add back pension funding in excess of expense and Ammondson settlement paid (2) See "Non-GAAP Financial Measure" slide in appendix for Free Cash Flows reconciliation. STRONG CASH FLOWS 17 (2) (1) - ($200) ($150) ($100) ($50) $0 $50 $100 $150 $200 $250 $300 2008 2009 2010 2011 2012 Mi llion s CFO Maintenance Capex Dividends Free Cash Flow Components of Free Cash Flow $350 $476 $434 $457 $255 $495 $596 $358 $429 $201 $0 $100 $200 $300 $4 0 $500 $600 $700 2008 2009 2010 2011 2012 Mi llio ns Net Operating Loss (NOL) Carryforward Balance Federal State (Montana)

$0 $50 $100 $150 $200 $250 $300 $350 '09 Q4 Q1 Q2 Q3 '10 Q4 Q1 Q2 Q3 '11 Q4 Q1 Q2 Q3 '12 Q4 Q1 Q2 Q3 M illi on s Liquidity Actual >$100M Target BALANCE SHEET STRENGTH AND LIQUIDITY 18 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 A2 Baa1 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 illi on s Year Debt Maturity Schedule 50.4% 54.0% 55.5% 54.8% 54.3% 30% 40% 50% 60% 2008 009 2010 2011 2012 Debt to Capital Ratio

NET INVESTMENT IN EXISTING BUSINESS 19 Maintenance capital expenditures have cumulatively outpaced depreciation by $150 million over the last five years (2008 to 2012), while maintaining a positive Free Cash Flow during the same period. ($150) ($100) ($50) $0 $50 $100 $150 $200 $250 $300 2008 2009 2010 2011 2012 2013E ($m illi on s) Maintenance Capex vs. Depreciation Distribution System Infrastructure Project (DSIP) Capital Maintenance capex Depreciation Cumulative capex in excess of depreciation

INVESTMENT OPPORTUNITY OUTLOOK 20  Energy Supply – Pending hydro transaction – Big Stone/Neal pollution control – Other vertical integration opportunities for Montana natural gas reserves  Transmission – Network upgrades – Jack Rabbit - Big Sky 161kV line – Carbon - Stillwater 100kV  Distribution – Distribution System Infrastructure Project (DSIP)

High High High High High High 2013 2014 2015 2016 2017 2018 Distribution System Infrastructure Project (DSIP) Natural gas reserves Spion Kop - Montana wind (40 MW) South Dakota peaking generator (60 MW) Neal pollution control equipment Big Stone pollution control equipment Pending Montana hydro asset acquisition INVESTMENT PROJECT SUMMARY 21 Energy Supply Distribution * As of September 30, 2013 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 $1.9 billion of rate base today. Figures above do not include maintenance capital investment in excess of depreciation. In May 2013, we announced the acquisition of the Bear Paw Natural Gas Reserves and Havre Pipeline from Devon Energy for $70 million, which we expect to close year end 2013. In September 2013, we announced the acquisition of 11 hydroelectric facilities from PPL Montana for $900 million. We expect to close last half of 2014 pending regulatory approval. In commercial operation April 2013 In commercial operation December 2012

MONTANA BASELOAD ELECTRIC OPPORTUNITY 22 - 100 200 300 400 500 600 700 Giga wat t ho urs Owned Spion Kop All Other PPL Contracts Supply opportunity Demand Load Forecast Post PPL supply opportunity approximately 200GWh per month or about 280MWs of capacity Forecasted demand NWE's Future Energy Supply vs Demand (Montana only - Heavy Load) The total load served over our Montana system is approximately 11 million MWh. The load we currently have responsibility for providing supply is just over 6 million MWh. Our owned generation in Montana, including the addition of Spion Kop in 2013, would serve approximately 17% of the system load and 31% of the load for which we provide supply. 2011 Resource Procurement Plan filed with the MPSC explored several options, most of which involved a new build generation resource online in 2018. 96% 44% 31% 0.0% 20.0% 40.0% 60.0% 80.0% 100.0% 120.0% 140.0% WR GXP EE CNL UNS IDA EDE NWE SD VVC ALE AVA UIL MGEE PNM BKH POR NWE NWE MT Peer Average Source: 2012 FERC Form 1 - Sources and Disposition of Energy Electricity - Percentage of Owned Resources for Retail Use

MONTANA HYDRO ACQUISITION 23 • Announced, in September 2013, the acquisition of eleven baseload hydroelectric generating facilities representing 633 megawatts of capacity and one storage reservoir from PPL Montana • These assets are consistent with our vision of providing safe and reliable energy for our customers for generations to come • Asset purchase price of $900 million, subject to customary closing adjustments • Acquisition subject to Montana Public Service Commission (MPSC) approval to include the assets in rate base to earn a regulated return consistent with our other resource acquisitions 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% My tic 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% Overview of Hydro Facilities(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 Cochrane Dam

HYDRO - SUPPORTING OUR VALUES 24 Our Vision Statement: Working together to deliver safe, reliable and innovative energy solutions that create value for our customers, communities, employees and investors. • 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 m dest impact of ~5% increase f rom current rates to total r sidential bills • Transaction helps match owned generation with load requirements • Increases fuel-type diversity of generation f leet with signif icant increase in sustainable generation • Consistent with focus on our existing regulated utility business and all of our customers Customers • Reinforces and expands NorthWestern’s commitment to Montana, its people and its environment Evolving environmental regulation may make Monta a hydro assets ev n more valuable • All ws NorthWester to incre se its commitment to charitable giving throughout Montana Communities • Combination of existing NorthWestern employees with extensive hydroelectric backgrounds and at least 70 PPL employees • Increas d opportunity for professional growth for both existing employees and employees who transfer when the s le cl ses • NorthWestern remains committed to competitive pay and benef its Employees • Inclusion of assets in regulated rate base Expected to be accretive in f irst full year of operations • t t maintain or enhance credit strength 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.

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% 25 Montana Annual Production (Excludes Kerr Dam1) HYDRO – OWNED & CONTRACTED RESOURCES MONTANA Yellowstone River ll t r Yellowstone River ll t ll t Ye lo stone River l t r Ye lo stone River ll t Yellowstone ll t Yellowstone ll t ll t Ye lo stone l t Ye lo stone ll t River r River River r River Missouri River i ri r issouri River i i i i issouri River i ri r issouri River i i Missouri River i ri r issouri River i i i i issouri River i ri r issouri River i i Madison River i r adison River i i adison River i r adison River i Clark Fork r r Clark Fork Clark Fork r r Clark Fork River r River River r River 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 li Billings li li Billings li Billings li 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 lena l l le a l le 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 sti y tic i ystic sti y tic Hebgen Hauser user ser ser Black Eagle Holter Rainbow Rainbo inbo i i i ai i i Morony orony oro y oro y Cochrane chrane chra e chra 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 Kerr Kerr Kerr 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. NorthWestern Owned Facilities Pro forma for Hydro Transaction Owned and contracted hydro and wind will represent over 50% of our generation portfolio, in Montana, after the close of the pending hydro transaction.

HYDRO - A GREAT FIT AT THE RIGHT TIME 26 – 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 during high commodity price periods. Thompson Falls Dam • 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 off-peak need but we will need additional resource 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.

MEETING CUSTOMER DEMANDS 27 The addition of the hydro generation assets into our Montana electric portfolio aligns well with forecasted customer demand. 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. Heavy Load Hours Light Load hours - 100,000 200,000 300,000 400,000 500,000 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22 Jan-23 Jan-24 Jan-25 Jan-26 Jan-27 Jan-28 Jan-29 Jan-30 Jan-31 Jan-32 Jan-33 New Hydro Assets Existing Resources Heavy Load - Demand Conveyance of Kerr Dam to CSKT MWhs - 100,000 200,000 300,000 400,000 500,000 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22 Jan-23 Jan-24 Jan-25 Jan-26 Jan-27 Jan-28 Jan-29 Jan-30 Jan-31 Jan-32 Jan-33 New Hydro Assets Existing Resources Light Load - Demand Conveyance of Kerr Dam to CSKTMWhs

HYDRO - MONTANA GENERATION PROFILE 28 127% 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 93% Peer Average Owned Resources for Retail Use as 12/31/2012 (Percentage by MWh) Owned Resources - NWE 2012 Actual (Percentage by MWh) 99% 31% 44% NWE SD NWE MT NWE Total Owned Resources - NWE Pro Forma with Hydro(1) 99% 63% 69% NWE SD NWE MT NWE Total (Percentage by MWh) 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. Source: 2012 FERC Form 1 Note: Percentages based on MWh of net generation / MWh of total sales to ultimate customer (1) 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%.

HYDRO - FINANCING STRATEGY 29 • Financing Plans – Plan to close into permanent financing with approximately $450 – 500 million of debt, up to $400 million of equity, and up to $50 million of free 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. Black Eagle Dam

Pre-signing • NorthWestern has been actively interested in these assets for several years – Provided proposal in June 2013 for hydro assets • Valuation of the assets took into consideration various factors including: – Considered fit within the supply portfolio – Forward market curve; adjusted for carbon per MPSC direction and consistent with the approach taken in planning and other acquisitions – DCF (discounted cash flow) analysis – Due diligence which provided support for key modeling assumptions and identification/evaluation of potential risks – Considered the cost of alternatives such as a combined cycle plant – Market comparisons and other analyses to derive price range, including what others would pay for the assets – Effect of purchase price on customers’ bills Post-signing • After agreeing to an acceptable price: – Negotiated the purchase and sale agreement – Conducted additional due diligence on assets – Arranged financing • Interim period before MPSC decision – Complete filings seeking approval of MPSC, FERC,FTC and DOJ – Work on smooth transition to NorthWestern Post Approval • Execute permanent financing and transition HYDRO – PROCESS AND TIMELINE 30 If approved, we expect to close the 2nd half of 2014 Ryan Dam

BIG STONE – AIR QUALITY CONTROL SYSTEM 31 • Big Stone Power Plant – Ownership: 23.4% of 475 MW coal plant – Project: Big Stone is subject to the Best Available Retrofit Technology (BART) requirements of the Regional Haze Rule. In order to comply, we are required to install Air Quality Control System (AQCS) to reduce SO2, NOx and particulates. Based on the finalized Mercury & Air Toxics Standards (MATS), it appears Big Stone would meet the requirements by installing the AQCS system and using mercury control technology such as activated carbon injection. – Capital Outlay: Through September 30th, 2013 we have capitalized approximately $28 million related to this project. NorthWestern has estimated its share of the $405 million project to be between $95-$110 million including AFUDC and overheads. – Timeline: Project is on schedule and expected to be completed by the April 16, 2016 compliance deadline. Big Stone Power Plant

NEAL - POLLUTION CONTROL EQUIPMENT 32 • Neal 4 – Ownership: 8.7% Partner in 644 MW coal plant – Project: To comply with national ambient air quality standards and Mercury & Air Toxics Standards (MATS), we are installing a scrubber, a baghouse, activated carbon and a selective non-catalytic reduction system. – Capital Outlay: Through September 30th, 2013 we have capitalized approximately $21 million related to this project. NorthWestern has estimated its share of the $270 million project to be approximately $25 - 30 million including AFUDC and overheads. – Timeline: Project is on time and expected to be completed in 2014 Neal Power Plant

Battle Creek ~1% Bear Paw North ~8% Bear Paw South ~28% Unfilled ~13% NATURAL GAS RESERVES OPPORTUNITY 33 • We continue to pursue opportunities to secure low cost gas reserves for our customers. – Remaining 13% unfilled position (assuming successful close on Bear Paw South) to reach our targeted 50% owned supply. – Possible further opportunities to procure reserves to provide 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. Battle Creek Bear Paw North Bear Paw South Announcement 9/22/2010 9/4/2012 5/28/2013 Purchase Pri ($M) $12.4 $19.5 $70.2 Ass ts 8.4 Bcf of proven producing reserves plus gathe ing system 13.4 Bcf of proven producing rese ves plus gathering system 64.6 Bcf of proven producing reserves plus gathering and 82 mile transmissio line Recovery Statu Rate Based Tracker Expected Close Q4, 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) As we continue to add to our natural gas reserves portfolio, we can significantly reduce supply costs volatility for our customers.

SOUTHERN BEAR PAW (DEVON) TRANSACTION 34 • Pending acquisition of Bear Paw South – Entered into an agreement in May of 2013 to purchase 64.6 Bcf proven reserves and 82% interest in Havre Pipeline Company for $70 million. – The regulatory waiver, necessary due to a previous stipulation, filed in June with the MPSC to acquire Havre Pipeline Company was approved in October. – We are not seeking MPSC pre-approval of the natural gas reserves as a closing condition. – Upon closing we anticipate utilizing 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 2013 estimates, transaction is expected to increase owned supply for our Montana retail customers from approximately 9% to 37%. – Expect to close in the fourth quarter 2013. Blaine County Montana Compressor Station

DISTRIBUTION INVESTMENT OUTLOOK 35 • 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 $21 $7 $45 $8 $168 $41 $234 $56 Natural Gas Utility Total 12 2 8 1 32 13 53 17 Other Tot l - 7 - - 8 - 6 Project Total $33 $16 $53 $10 $200 $62 $287 $89 Accounting Order ( ) $3 13 $0 Estimated P&L Impact $0 $1 $75 $89 2011 & 2012 2013 2014 - 2017 2011-17 Total Actual Estimated Cost w/inflation

$160 $163 $155 $151 $147 $53 $50 $50 $50 $50 $44 $33 $28 $- $50 $100 $150 $200 $250 $300 2013 2014 2015 2016 2017 $M illi on s Capital Spending Maintenance Capex Distribution System Infrastructure Project (DSIP) Energy Supply (primarily SD environmental projects) CAPITAL SPENDING 36 DSIP – Distribution System Infrastructure Project - $253 million over the next 5 years. Energy Supply includes the planned environmental spending in South Dakota on Big Stone and Neal 4 power plants, and completion of the new Aberdeen Peaker plant in 2013. * A natural gas transmission system enhancement plan intended to move us beyond basic compliance with federal safety regulations to systematic prioritization and addressing of pipeline integrity management for long-term customer benefit. 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 Gas Transmission Infrastructure Project (GTIP*). Source: 2012 10-K. Energy Supply estimates updated to reflect reduction in Big Stone AQCS budget in April 2013.

CONCLUSION 37 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 38

ADJUSTED EPS SCHEDULE 39 2013 Non- GAAP Adjusted EPS guidance range of $2.45 - $2.60 per diluted share with a midpoint of $2.53 Q1 Q2 Q3 Q4 2013 2013 Reported GAAP diluted EPS $1.01 $0.37 $0.40 $1.78 Non-GAAP Adjustments: Weather (0.02) (0.02) (0.04)$ Hydro Transaction related legal and professional fees 0.05 0.05$ DSM lost revenue recovery - portion related to 2012 (0.04) (0.04)$ 2013 Adjusted diluted EPS $1.01 $0.35 $0.39 $1.75 Q1 Q2 Q3 Q4 2012 2012 Reported GAAP diluted EPS $0.88 $0.31 ($0.10) $1.57 $2.66 Non-GAAP Adjustments: Weather 0.09 0.05 (0.06) 0.06 0.14$ Release of MPSC DGGS deferral (0.05) (0.05)$ DSM Lost revenue recovery related to 2010/2011 (0.05) (0.05)$ DGGS FERC ALJ initial decision - portion related to 2011 0.12 0.12$ MSTI Impairment 0.40 0.40$ Favorable CELP arbitration decision (0.79) (0.79)$ Income tax adjustment - benefit from MT NOL (0.06) (0.06)$ 2012 Adjusted diluted EPS $0.92 $0.31 $0.36 $0.78 $2.37 Year-over-year Improvement Q1 Q2 Q3 Q4 YTD Reported GAAP diluted EPS $0.13 $0.06 $0.50 $0.69 Adjusted diluted EPS $0.09 $0.04 $0.03 $0.16

CONSOLIDATED STATEMENT OF INCOME 40 (in millions, except per share) 2013 2012 2013 2012 Operating Revenues $262.3 $235.9 $835.5 $789.5 Cost of Sales 104.3 93.0 343.4 327.9 Gross Margin 158.0 142.9 492.1 461.6 Operating Expenses Operating, general & administrative 72.5 63.1 208.7 195.7 MSTI impairment - 24.0 - 24.0 Property and other taxes 26.0 24.8 77.5 74.4 Depreciation 28.1 26.5 84.7 79.4 Total Operating Expenses 126.6 138.4 370.9 373.5 Operating Income 31.4 4.4 121.1 88.2 Interest Expense (17.1) (17.7) (51.0) (49.6) Other Income 3.1 1.0 6.8 3.1 Income (Loss) Before Taxes 17.5 (12.4) 76.9 41.7 Income Tax (Expense) Benefit (1.8) 8.6 (9.0) (2.0) Net Income (Loss) $15.6 ($3.8) $67.9 $39.7 Average Common Shares Outstanding 38.5 37.2 38.0 36.7 Basic Earnings per Average Common Share $0.41 ($0.10) $1.79 $1.09 Diluted Earnings per Average Common Share $0.40 ($0.10) $1.78 $1.08 Dividends Declared per Common Share $0.38 $0.37 $1.14 $1.11 Three Months Ended September 30, Nine Months Ended September 30,

3 MONTH EARNINGS RECONCILIATION 41 NORTHWESTERN CORPORATION Three Months Ended September 30, 2013 ($millions, except EPS) Th re e M on th s E nd ed , Se pt em be r 3 0, 20 12 DG GS DS M los t r ev en ue s Sp ion K op Na tur al Ga s p rod uc tio n Mo nta na na tur al ga s r ate in cre as e Pr op ert y t ax tr ac ke rs El ec tric re tai l v olu me s Op era tin g e xp en se s r ec ov ere d i n t rac ke rs El ec tric tr an sm iss ion Di str ibu tio n S ys tem In fra str uc tur e P roj ec t (D SI P) ex pe ns es Hy dro T ran sa cti on re lat ed le ga l a nd pro fes sio na l fe es La bo r Pl an t o pe rat or co sts No ne mp loy ee di rec tor s d efe rre d c om pe ns ati on Ba d d eb t e xp en se Pe ns ion an d e mp loy ee be ne fits Flo w- thr ou gh re pa irs de du cti on s Flo w- thr ou gh of st ate bo nu s d ep rec iat ion de du cti on Pr od uc tio n t ax cr ed its Pr ior ye ar pe rm an en t r etu rn to ac cru al ad jus tm en ts Re co gn itio n o f s tat e n et op era tin g l os s b en efi t / va lua tio n a llo wa nc e r ele as e St ate in co me ta x a nd ot he r, ne t Im pa ct of hig he r s ha re co un t Al l o the r Gross Margin 142.8$ 10.2 5.0 1.6 1.2 1.2 0.9 (3.5) (1.9) (0.4) - - 0.9 Operating Expenses Op.,Gen., & Administrative 63.1 (1.9) 3.3 2.8 1.7 1.6 1.5 0.6 (3.1) 2.9 MSTI impairment 24.0 (24.0) Prop. & other taxes 24.8 1.2 Depreciation 26.5 1.6 Total Operating Expense 138.4 - - - - - - - (1.9) - 3.3 2.8 1.7 1.6 1.5 0.6 (3.1) - - - - - - - (18.3) Operating Income 4.4 10.2 5.0 1.6 1.2 1.2 0.9 (3.5) - (0.4) (3.3) (2.8) (1.7) (1.6) (1.5) (0.6) 3.1 - - - - - - - 19.2 Interest Expense (17.7) 0.6 Other Income (Expense) 1.0 2.1 Income Before Inc. Taxes (12.4) 10.2 5.0 1.6 1.2 1.2 0.9 (3.5) - (0.4) (3.3) (2.8) (1.7) (1.6) (1.5) (0.6) 3.1 - - - - - - - 22.0 Income Tax Benefit (Expense)1 8.6 (3.9) (1.9) (0.6) (0.5) (0.5) (0.3) 1.3 - 0.2 1.3 1.1 0.7 0.6 0.6 0.2 (1.2) 1.3 0.5 0.5 (1.9) (0.1) (0.3) (7.4) Net Income (Loss) (3.8)$ 6.3 3.1 1.0 0.7 0.7 0.6 (2.2) - (0.2) (2.0) (1.7) (1.0) (1.0) (0.9) (0.4) 1.9 1.3 0.5 0.5 (1.9) (0.1) (0.3) - 14.6 Fully Diluted Shares 37.20 1.44 - Fully Diluted EPS (0.10)$ 0.16 0.08 0.03 0.02 0.02 0.01 (0.06) - (0.01) (0.05) (0.05) (0.03) (0.03) (0.02) (0.01) 0.05 0.03 0.01 0.01 (0.05) - (0.01) (0.02) 0.42 1.) Income Tax Benefit (Expense) calculation on reconciling items assumes normal effective tax rate of 38.5%.

9 MONTH EARNINGS RECONCILIATION 42 NORTHWESTERN CORPORATION Nine Months Ended September 30, 2013 ($millions, except EPS) Ni ne M on ths E nd ed , Se pte mb er 30 , 2 01 2 Na tur al ga s p rod uc tio n DG GS Sp ion K op Ele ctr ic tra ns mi ss ion Na tur al ga s r eta il v olu me s Mo nta na na tur al ga s r ate in cre as e Pr op ert y t ax tra ck ers Na tur al ga s t ran sp ora tio n c ap ac ity Ele ctr ic QF su pp ly co sts Op era tin g e xp en se s r ec ov ere d i n t rac ke rs Ele ctr ic ret ail vo lum es Dis trib uti on S ys tem In fra str uc tur e P roj ec t (D SI P) ex pe ns es Hy dro Tr an sa cti on re lat ed le ga l a nd pro fes sio na l fe es Pla nt op era tor co sts La bo r No ne mp loy ee di rec tor s d efe rre d c om pe ns ati on Ba d d eb t e xp en se Pe ns ion an d e mp loy ee be ne fits Flo w- thr ou gh re pa irs de du cti on s Flo w- thr ou gh of st ate bo nu s d ep rec iat ion de du cti on Pr od uc tio n t ax cr ed its Pr ior ye ar pe rm an en t re tur n t o a cc rua l ad jus tm en ts Re co gn itio n o f s tat e n et op era tin g l os s b en efi t / va lua tio n a llo wa nc e r ele as e St ate in co me ta x a nd ot he r, n et Im pa ct of hig he r s ha re co un t All ot he r, n et Ni ne M on ths E nd ed , Se pte mb er 30 , 2 01 3 Gross Margin 461.6$ 7.0 5.1 4.6 3.6 3.4 2.1 1.9 1.1 1.0 (2.4) (0.5) 3.5 492.1 Operating Expenses Op.,Gen., & Administrative 195.7 1.6 (2.4) 8.8 3.3 3.0 2.8 2.6 1.0 (10.7) 3.0 208.7 MSTI impairment 24.0 (24.0) - Prop. & other taxes 74.4 3.1 77.5 Depreciation 79.4 5.3 84.7 Total Operating Expense 373.5 1.6 - - - - - - - - (2.4) - 8.8 3.3 3.0 2.8 2.6 1.0 (10.7) - - - - - - - (12.6) 371.0 Operating Income 88.1 5.4 5.1 4.6 3.6 3.4 2.1 1.9 1.1 1.0 - (0.5) (8.8) (3.3) (3.0) (2.8) (2.6) (1.0) 10.7 - - - - - - - 16.1 121.1 Interest Expense (49.6) (1.4) (51.0) Other Income (Expense) 3.1 3.6 6.8 Income Before Inc. Taxes 41.7 5.4 5.1 4.6 3.6 3.4 2.1 1.9 1.1 1.0 - (0.5) (8.8) (3.3) (3.0) (2.8) (2.6) (1.0) 10.7 - - - - - - 18.3 76.9 Income Tax Benefit (Expense)1 (2.0) (2.1) (2.0) (1.8) (1.4) (1.3) (0.8) (0.7) (0.4) (0.4) - 0.2 3.4 1.3 1.2 1.1 1.0 0.4 (4.1) 3.4 1.1 2.1 (2.4) (0.1) 1.2 - (5.8) (9.0) Net Income (Loss) 39.7$ 3.3 3.1 2.8 2.2 2.1 1.3 1.2 0.7 0.6 - (0.3) (5.4) (2.0) (1.8) (1.7) (1.6) (0.6) 6.6 3.4 1.1 2.1 (2.4) (0.1) 1.2 - 12.5 67.9 Fully Diluted Shares 36.79 1.37 - 38.16 Fully Diluted EPS 1.08$ 0.09 0.08 0.07 0.06 0.06 0.03 0.03 0.02 0.02 - (0.01) (0.14) (0.05) (0.05) (0.04) (0.04) (0.02) 0.17 0.09 0.03 0.06 (0.06) - 0.03 (0.07) 0.34 1.78 1.) Income Tax Benefit (Expense) calculation on reconciling items assumes normal effective tax rate of 38.5%.

CONSOLIDATED STATEMENT OF CASH FLOWS 43 (in millions) 2013 2012 Operating Activities Net Income $67.9 $39.7 Non-Cash adjustments to net income 123.6 124.0 Changes in working capital 6.5 68.7 Other (26.7) (9.8) Cash provided by operating activities 171.3 222.6 Investing Activities PP&E additions (153.9) (157.8) Asset acquisition - (18.4) Other 3.9 0.3 Cash used in investing activities (150.0) (175.9) Financing Activities Proceeds from issuance of common stock, net 44.1 28.5 (Repayments) issuances of long-term debt, net (0.1) 146.1 Repayments of short-term borrowings, net (20.0) (166.9) Dividends on common stock (43.1) (40.6) Other (1.1) (1.5) Cash used in financing activities (20.2) (34.4) Increase in Cash and Cash Equivalents $1.1 $12.3 Beginning Cash $9.8 $5.9 Ending Cash $10.9 $18.2 Nine Months Ending September 30,

CONSOLIDATED BALANCE SHEET 44 (in millions) Sept. 30, 2013 Dec. 31, 2012 Cash 10.9 9.8 Restricted cash 8.2 6.7 Accounts receivable, net 129.2 143.7 Inventories 62.6 54.2 Other current assets 69.7 88.8 Goodwill 355.1 355.1 PP&E and other non-current assets 2,997.9 2,827.3 Total Assets 3,633.7$ 3,485.5$ Payables 63.4 83.7 Current maturities of long-term debt & capital leases 1.7 1.6 Short-term borrowings 103.0 122.9 Other current liabilities 249.9 241.0 Long-term debt & capital leases 1,085.4 1,086.6 Other non-current liabilities 1,126.0 1,015.6 Shareholders' equity 1,004.3 934.0 Total Liabilities and Equity 3,633.7$ 3,485.5$ Capitalization: Current maturities of long-term debt & capital leases 1.7 1.6 Short Term borrowings 103.0 122.9 Long Term Debt & Capital Leases 1,085.4 1,086.6 Less: Basin Creek Capital Lease (31.8) (32.9) Shareholders' Equity 1,004.3 934.0 Total Capitalization 2,162.5$ 2,112.3$ Ratio of Debt to Total Capitalization 53.6% 55.8%

EFFECTIVE TAX RATE RECONCILIATION 45 (in millions) 2013 2012 2013 2012 Income (Loss) Before Income Taxes $17.5 ($12.4) $76.9 $41.7 Income tax calculated at 35% federal statutory rate 6.1 (4.3) 26.9 14.6 Permanent or flow through adjustments: Flow-through repairs deductions (3.1) (1.8) (12.9) (9.5) Flow-through of state bonus depreciation deduction (0.8) (0.3) (3.3) (2.2) Production tax credits (0.5) - (2.1) - Prior year permanent return to accrual adjustments - (1.9) 0.5 (1.9) Recognition of state net operating loss benefit - (0.1) - (0.1) / valuation allowance release State income tax and other, net 0.1 (0.2) (0.1) 1.1 (4.3) (4.3) (17.9) (12.6) Income tax expense (benefit) $1.8 ($8.6) $9.0 $2.0 Three Months Ended September 30, Nine Months Ended September 30,

NON-GAAP FINANCIAL MEASURES 46 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) Short & Long Term Debt and Capital Leases 1,190.0 Less: Cash and Cash Equivalents (10.9) Less: Capital Leases (31.8) Net Debt 1,147.3 Use of No -GAAP Financial Measures - Net Debt as of September 30, 2013 (in millions) 2008 2009 2010 2011 2012 Cash flow from operations 198.3$ 116.8$ 218.9$ 233.8$ 251.2$ Adjustments * 88.4 Cash flow from operations - with adjustment 198.3$ 205.2$ 218.9$ 233.8$ 251.2$ * 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 124.6$ 189.4$ 228.4$ 188.7$ 219.2$ Less: Investment Growth (19.4) (82.7) (113.4) (59.1) (86.0) Maintenance Capex 105.2$ 106.7$ 115.1$ 129.7$ 133.2$ Free Cash Flow Cash Flow fro Op rat ons 198.3$ 205.2$ 218.9$ 233.8$ 251.2$ Less: Mainten n e C pex (105.2) (106.7) (115.1) (129.7) (133.2) Less: Dividen (49.8) (48.2) (49.0) (51.9) (54.2) Free Cash Flow 43.3$ 50.4$ 54.9$ 52.2$ 63.7$ Use of Non-GAAP Financial Measures - Free Cash Flow - 2008 to 2012 2012 (in millions) Electric Gas Other Total Operating Revenues 805.6$ 263.4$ 1.3$ 1,070.3$ Cost of Sales 277.8 117.6 - 395.4 Gross Margin 527.8$ 145.8$ 1.3$ 674.9$ 2012 (in millions) Montana South Dakota Nebraska Total Operating Revenu s 874.1$ 163.9$ 32 4 1,070.3$ Cost of Sales 304.3 69.1 22.1 395.4 Gross Margin 569.8$ 94.8$ 10.3$ 674.9$ 2012 (in thousands) Electric Gas Other Total Operating Reve ues 805.6$ 263.4$ 1.3$ 1,070.3$ Cost of Sal s 277.8 117.6 - 395.4 Gross Margin 527.8 145.8 1.3 674.9 Less: Operati g Ex ses Operating, general & administrative 211.6 76.0 6.4 294.0 Property and other taxes 72.8 24.9 0.0 97.7 EBITDA 243.4$ 44.9$ (5.1)$ 283.3$ Use of Non-GAAP Financial Measures - Gross Margin for 2012 Use of Non-GAAP Financial Measures - EBITDA for 2012 Use of Non-GAAP Financial Measures - Gross Margin for 2012

Energy Supply Transmission Distribution Electric (MW) MT SD Total 2012 Tx for Others MT SD Total Demand MT SD / NE Total Base load coal 222 210 432 Electric (GWh) 9,600 100 9,700 Daily MWs 750 172 922 Wind 40 40 Natural Gas (Bcf) 21.0 - 21.0 Peak MWs 1,784 324 Other resources 150 166 316 Annual GWhs 6,400 1,500 7,900 Annual Bcf 19 8 27 Natural Gas (Bcf) MT SD Total System (miles) MT SD Total Proven reserves 21.4 - 21.4 Electric 6,900 1,300 8,200 Customers MT SD / NE Total Annual production 1.9 - 1.9 Natural gas 2,000 55 2,055 Electric 342,000 61,600 403,600 Storage 17.8 - 17.8 Natural gas 183,300 86,300 269,600 525,300 147,900 673,200 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 2012 SYSTEM STATISTICS 47 Note: Statistics above are as of 12/31/2012 (1) Includes 60 MW Aberdeen Peaker to be placed in service during 2013 (2) Nebraska is a natural gas only jurisdiction •MT electric supply increased 40 MW in 2012 due to the addition of Spion Kop wind. •MT NG reserves includes 13.4 Bcf Bear Paw acquisition in 2012. (1) (2)

OUR COMMISSIONERS 48 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 Anne Boyle (Chair) D Jan-97 Jan-15 Rod Johnson R Jan-93 Jan-17 Frank Landis Jr. 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 ter is 1 year. Nebraska Public Servic Com i sion 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-19 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

FERC’s ALJ RULING – WE GOT THE CRUST 49 Relying on the regulatory process to provide an equitable outcome should be as American as…. apple pie. FERC Total Direct (45MW) 45/105 39/105 21/105 105/105 43% 37% 20% 100% Fixed Costs ($millions) $16.3 $14.2 $7.6 $38.1 Variable Costs (Fuel, etc) 8.3 7.2 3.9 19.3 Revenue Credits (energy sales) (3.3) (2.9) (1.5) (7.7) Net Variable Costs 5.0 4.3 2.3 11.6 Total Revenue Requirement $21.3 $18.5 $9.9 $49.7 Return on Equity 10.25% 10.25% 10.25% 10.25% FERC Total Direct (45MW) 45/105 39/105 7/150 91/108 43% 37% 4% 84% Fixed Costs ($millions) $16.3 $14.2 $1.7 $32.2 Variable Costs (Fuel, etc) 8.3 7.2 - 15.4 Revenue Credits (energy sales) (3.3) (2.9) - (6.2) Net Variable Costs 5.0 4.3 - 9.3 Total Revenue Requirement $21.3 $18.5 $1.7 $41.4 Return on Equity* 10.25% 10.25% -19.79% 4.25% Note: Potential for approximately 7% ROE if fuel costs are able to be recovered through an alternate FERC schedule 12 CP Allocation (19 MW) MPSC 12 CP Allocation (60MW) However, clearly this is not the outcome given the initial decision by FERC's Administrative Law Judge. MPSC NorthWestern entered the construction of Dave Gates Generating Station with full confidence our investors would be made whole. FERC MPSC FERC MPSC -20% -15% -10% -5% 0% 5% 10% 15% 20% MPSC FERC Total Return on Equity -20% -15% -10% -5% 0% 5% 10% 15% 20% MPSC FERC Total Return on Equity (w/ Initial Decision)

THE BACK STORY ON DGGS 50 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. • 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 - FERC decision anticipated in 2014 - If unfavorable outcome, NWE appeal process could extend into 2015 or beyond

THE BACK STORY ON DGGS (continued) 51 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, the Initial Order from the Administrative Law Judge doesn’t support FERC’s previous positions. •The Initial Order from the FERC Administrative Law Judge: • 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, the Initial 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 in this initial order 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 initial decision would seek to either shift costs to state jurisdictional customers or allow them simply to fall between the cracks.

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