1 1 Investor Update July/August 2013
2 FORWARD LOOKING STATEMENT 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.
3 ABOUT NORTHWESTERN 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
4 NWE: AN INVESTMENT FOR THE LONG TERM 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 – 5 years 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 (natural gas and electric) – Distribution System Infrastructure Program (DSIP) – Transmission opportunities within our service territory
5 NORTHWESTERN ENERGY PROFILE 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% Nebreska 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) ate 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 Natural Gas $56 M Other ($8 M) Electric $245 M EBITDA EBITDA - Earnings before Interest, Tax, Depreciation and Amortization - For the 12 mo ths nding 6/30/13 - N adjustments made for ALJ decision on DGGS, MSTI impairment or CELP's favorable decision in Q3 & Q4 of 2012 Stock Price * $42.05 Outstanding Shares 38.4M Market Capitalization * $1.61B Net Debt $1.02B Total Enterprise Value * $2.63B EBITDA - Trailing 12 months $293M Market Capitalization to Book Equity * 1.61 Avg. Common Shares Outstanding 37.4M Debt/Total Capitalization 52.8% Enterprise Value / EBITDA * 9.02x Dividend 2013 - 1st half annualized $1.52 Annualized Dividend Yield * 3.61% Total Customer Count 673,200 Employees 1,430 Profile Data All data as of 6/30/13, unless noted with * * Market Data as of 7/26/13 Net Debt is net of cash and excludes capital leases
6 A STRONG & WELL ROUNDED BOARD & EXECUTIVE TEAM 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 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
7 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 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. 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 2012 Northwestern Corporation was a finalist in the category of "Best Proxy Statement" given by the Corporate Secretary - Governance, Risk & Compliance organization. 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." NWE CORPORATE RESPONSIBILITY
8 BETTER THAN AVERAGE ECONOMIC INDICATORS Top Left: Unemployment rate consistently below National Average for our service territory. National Ranking (NE 2nd, SD 2nd & MT 9th) 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 (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 7-18-13 Unemployment Rate (as reported in May each year) 3.47% 4.46% 5.60% 3.67% 0% 1% 2% 3% 4% 5% 6% US National Average Montana South Dakota Nebraska Source: Eco ic & Social Research Institute (ESRI) via SNL Database 7-18-13 Projected P pul tion Growth 2012-2017 (cumulative growth) 0.25% 0.30% 0.25% 0.21% 0.29% 0.21% .00% 0.05% 0.10% 0.15% 0.20% 0.25% 0.30% 0.35% 2007 2008 2009 2010 2011 2012 Write-Off to Revenue Ratio
9 A DIVERSIFIED ELECTRIC AND GAS UTILITY Above data reflects full year 2012 results . Jurisdiction and service type based upon gross margin contribution. 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 83% Residential 16% Commercial 1% Industrial 84% Montana 14% South Dakota 2% Nebraska 78% Electric 22% Natural Gas
10 STRONG UTILITY FOUNDATION 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 Strong utility operations: Solid system reliability (EEI 2nd quartile); A NWE customer could expect, 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 that exceeds survey average (JD Powers) 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) $- $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 600 7 0 800 2009 2010 2011 2012 In de x S co re NorthWestern Energy Score JD Power 26 Combination Electric and natural gas compa y average JD Power - Customer Service Index Score EEI – 2nd Quartile Performance
11 Details regarding “Adjusted” EPS can be found in the “Adjusted EPS Schedule” page of the appendix 2013 EARNINGS GUIDANCE 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; • Excludes any unanticipated costs due to Colstrip Unit 4 outage; and • Diluted average shares outstanding of 38.1 million 2013 Initial Diluted GAAP EPS Range of $2.40-2.55 and a midpoint of $2.48 is now updated to $2.45-$2.60 per share with a midpoint of $2.53 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 a dividend yield of 3-4%, should provide good results for investors over foreseeable future. $1.78 $2.02 $2.14 $2.53 $2.66 $2.53 $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 Initial Guidance Range Non-GAAP "Adjusted" EPS Diluted Earnings Per Share Midpoint
12 $1.32 $1.34 $1.36 $1.44 $1.48 1.52 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 2008 2009 2010 2011 2012 2013E Annual Dividend Per Share Payout Ratio (based on GAAP EPS) Dividend Per Share and Payout Ratio 8.5% 9.5% 9.6% 11.0% 11.0% 10. % 0.0% 2.0% .0% 6.0% 8.0% 10.0% 12.0% 2008 2009 2010 2011 2012 2013E $M illio ns Return on Equity 5 YEAR TRACK RECORD OF DELIVERING RESULTS 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) Average Return on Equity : 9.8% 5 Year (2008-12) CAGR Dividend: 2.9% Current Dividend Yield Approximately 3.6% 1. ROE in 2011 & 2012, on a Non-GAAP “adjusted” basis, would be 10.5% and 9.8% respectively. 2. 2013 ROE and 2013 Dividend payout ratio estimate based on midpoint of updated and increased guidance range of $2.45 - $2.60. 3. 2011 and 2012 Dividend Payout Ratio based upon Non-GAAP Adjusted EPS would be 60% and 62% respectively. 1 3 3 1 2 2 Details regarding “Adjusted” EPS can be found in the “Adjusted EPS Schedule” page of the appendix
13 STRONG CASH FLOWS While maintenance capex and dividend payments have continued to grow over the past 5 years (6.5% 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. $350 $476 $434 $457 $255 $495 $596 $358 $429 $201 $0 $100 $200 $300 $400 $500 $600 $700 2008 2009 2010 2011 2012 Mi llio ns Net Operating Loss (NOL) Carryforward Balance Federal State (Montana) (1) - ($20 ) ($150) ($100) ($50) $0 $50 $100 $150 $200 $250 $300 008 2009 2010 2011 2012 Mi llio ns CFO Maintenance Capex Dividends Free Cash Flow (2) Components of Free Cash Flow (1) 2009 Cash Flow from Operations (CFO) is adjusted to add back pension funding in excess of expense and Ammondson settlement paid) (2) Free Cash Flow = CFO less maintenance capex and dividends)
14 We sta r E ne rgy , In c. 58 % Gr ea t P lai ns En erg y In c. 59 % Ida ho Po we r C o. 60 % Em pir e D istr ict Ele ctr ic C o. 65 % UIL Ho ldi ng s C orp . 66 % MG E E ne rgy , In c. 67 % El P aso Ele ctr ic C o. 69 % Av ista Co rp. 69 % AL LET E, I nc. 71 % Po rtla nd Ge n. Ele c. C o. 74 % Bla ck Hil ls C orp . 74 % Un iSo urc e E ne rgy Co rp. 76 % No rth We ste rn Co rp. 78 % PN M Re sou rce s, I nc. 78 % Ve ctr en Co rp. 78 % Cle co Co rp. 80 % 40% 50% 60% 70% 80% 90% 100% Pension Funded Status as of 12/31/2012 SOLID PENSION FUNDING We calculate our pension obligation with conservative estimates relative to our peers. Updated 2013 pension assumptions include an expected long-term rate of return of 7.00% and discount rate assumed at 3.55%-3.80%. As of result of significant pension contributions in 2009 and 2010 and solid market returns over the past several years, we are better positioned than most of our peers at December 31, 2012. 2012 NWE Pension Assumptions: Target allocation: 50% equity and 50% fixed income Expected long-term rate of return: 7.00% vs Peer Avg. of 7.48% Discount rate : 3.55% – 3.80% vs Peer Avg of 4.66% Plan Assets as of 12/31/12 were $472.9 million Note: Size of bubble represents relative size of pension plan assets
15 BALANCE SHEET STRENGTH AND LIQUIDITY $0 $50 $100 $150 $200 $250 $300 Q3 '09 Q4 Q1 Q2 Q3 '10 Q4 Q1 Q2 Q3 '11 Q4 Q1 Q2 Q3 '12 Q4 Q1 Q2 M illio ns Liquidity Actual >$100M Target No Significant maturities until 2016 $0 $50 $100 $150 $200 $250 $300 M illi on s Year Debt Maturity ScheduleSenior Secured Rating Senior Unsecured Rating Commercial Paper Outlook Fitch A- BBB+ F2 Positive 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 ny other rating. Credit Ratings 50.4% 54.0% 55.5% 54.8% 54.3% 30% 40% 50% 60% 2008 2009 2010 2011 2012 Debt to Capital Ratio Annual ratio is average of each quarter end debt/cap ratio Excludes Basin Creek capital leases Goal: 50% - 55%
16 HARD ASSETS PROVIDING REAL VALUE (Left) We believe continued investment in our system to provide safe, reliable, environmentally responsible and cost- effective service for our customers will produce additional value for our shareholders. (Below) NWE Total Shareholder Return has outperformed our peer group average, the S&P 600 index (on which we are listed) and the Dow Jones Utility Average thru December 31, 2012. $- $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 20 8 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 51.16% 15 Peer Avg. * 34.97% S&P 600 14.58% DJUA 5.14% 0% 10% 20% 30% 40% 50% 60% 5 Year Total Shareholder Return NWE 53.01% 15 Peer Avg. * 49.19% S&P 600 48.42% DJUA 29.53% -10% 0% 10% 20% 30% 40% 50% 60% 3 Year Total Shareholder Return * Peer Group: ALE, AVA, BKH, CNL, EDE, EE, GXP, IDA, MGEE, PNM, POR, UIL, UNS, VVC, WR
17 GROWTH WITH LITTLE IMPACT TO CUSTOMERS Over the past 5 years we have begun to rebuild our Montana energy supply portfolio and invested to enhance system safety, reliability and capacity. We have made these enhancements while delivering solid earnings growth to our investors with minimal impact to our customers’ bills. 2008-2012 CAGRs Estimated Rate Base: 14.5% GAAP Diluted EPS: 10.6% El. retail rev./ MWh : 1.9% N. Gas retail rev./Dkt: (6.2%) $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 $69.57 $68.78 $70.03 $73.26 $74.95 $60 $70 $80 $90 2008 2009 2010 2011 2012 Re il Electric Rev nue per Megawatt hour (MWh) $11. 0 $9.80 $9.11 $8.92 $8.66 $- $3 $6 $9 $12 $15 2008 2009 2010 2011 2012 R tail Natural Gas Revenue per Dekatherm (Dkt)
18 NET INVESTMENT IN EXISTING BUSINESS Maintenance capital expenditures have cumulatively outpaced depreciation by $160 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 $250 2008 2009 2010 2011 2012 2013E ($m illi on s) Maintenance Capex vs. Depreciation Distribution System Infrastructure Project (DSIP) Capital Maintenance capex Depreciation Cumulative capex in excess of depreciation
19 2012 MONTANA NATURAL GAS RATE FILING We are dedicated to operating a safe and reliable natural gas system that requires ongoing infrastructure investment. -Feb. 8: The Montana Consumer Counsel recommended a $4.1 million increase based upon a 9.0% ROE (45% equity) and other adjustments. -Apr. 15: We reached a Stipulation Agreement with interveners to increase delivery rates by approximately $11.5 million based on a 9.8% ROE. -Apr. 23: MPSC approved the Stipulation Agreement by a 4-1 vote and directed the commission staff to prepare a Final Order approving the $11.5 million increase and the Stipulation related to the Allocated Cost of Service Rate Design. -Final order was received May 7, 2013. D2009.9.129 Final Order Cost of Equity 10.25% Cost of Debt 5.76% Equity % of Total Capitalization 48.00% Rate of Return 7.92% 2008 2011 Revenue ($Millions) Test Year Test Year Incr. (Decr.) Normalized Revenue (excludes supply) $105.6 $105.5- - Operations & maintenance expense 20.9 24.9 4.0 Customer & sales expense 5.7 5.8 0.2 Administrative & general Expense 15.5 18.0 2.5 Depreciation 11.7 13.0 1.4 Amortizations 5.4 4.9 (0.5) Taxes, other than income 21.4 25.0 3.7 Income taxes 4.7 (0.9) (5.6) Total Cost of Service $85.3 $90.8 $5.5 Net investment in rate base 256.8 309.5 Rate of Return 7.92% 7.83% Return on rate base $20.3 $24.2 $3.9 Gross-up for income taxes $6.2 Revenue deficiency grossed up for income taxes $15.6 September 2012 Request D2012.9.94 10.50% 5.39% 47.67% 7.83% $0 $50 $100 $150 $200 $250 $300 2008 2011 Pass- through Natural Gas Supply Costs Pass- through Natural Gas Supply Costs - Increased Cost of Service: $5.5M - Increased capital investment: $3.9M Revenue Increase due to: - Income tax gross up: $6.2M Montana Natural Gas Revenue Requirement 2009 Final Order as compared to Test Year 2011 ($millions)
20 INVESTMENT OPPORTUNITY OUTLOOK Energy Supply – Big Stone/Neal pollution control – South Dakota natural gas peaking generation – Montana Spion Kop Wind facility - completed – Other vertical integration opportunities in Montana including gas reserves or base load generation Transmission – Network upgrades – Jack Rabbit - Big Sky 161kV line – Carbon - Stillwater 100kV – Colstrip 500kV upgrade Distribution – Distribution System Infrastructure Project (DSIP)
21 High High to Medium High High High 2013 2014 2015 2016 2017 2018 Distribution System Infrastructure Project (DSIP) Colstrip 500 kV Upgrade Incremental natural gas reserves Spion Kop - Montana wind (40 MW) South Dakota peaking generator (60 MW) Neal pollution control equipment Big Stone pollution control equipment Distribution Transmission Generation INVESTMENT PROJECT SUMMARY Several opportunities exist to further increase and diversify earnings as compared to our approximately $1.8 billion of rate base today. Additional opportunities for baseload generation in Montana are currently being evaluated and may be incorporated as their scope and timeline become more defined. Figures above do not include maintenance capital investment in excess of depreciation. In May 2013, we announced the acquisition of the Bear Paw Basin Natural Gas Reserves and Havre Pipeline from Devon Energy for $70.2M. The $100-200 million range includes this purchase. Note: Color / label indicate NorthWestern Energy's current probability of execution and timing of expenditures. In commercial operation December 2012 In commercial operation April 2013 Total Project Capital Opportunity ($millions) Low High Jurisdiction $95 to $110 SDPUC $25 to $30 SDPUC $55 to $55 SDPUC $84 to $84 MPSC $100 to $200 MPSC $40 to $75 FERC $250 to $300 MPSC $649 to $854
22 4.4 14% 18.6 59% 8.3 27% Dave Gates Generation MT Retail SD/NE Retail Total Natural Gas Needs (in Bcf) 0.5 2% 1.6 9% 16.5 89% Battle Creek Bear Paw Market Purchase Natural Gas Supply for Retail Sales (in Bcf) NATURAL GAS NEEDS AND SUPPLY Top Left: Approximately 14% of our total natural gas needs go toward electric generation and the remaining 86% is sold to our retail customers Top: We own approximately 11% of our total retail needs in Montana. In May 2013, we announced our intention to purchase the Bear Paw Basin Natural Gas Reserves from Devon Energy. This transaction is expected to increase our owned supply for Montana retail gas sales to 37%. Left: As we continue to add to our natural gas reserves to our portfolio, we can significantly reduce supply cost volatility for our customers. Battle CreekBear Paw MONTANA GAS RESERVES All Data from 2012 $- $20 $40 $60 $80 $100 $120 $140 $160 Transmission, Distribution & Storage Natural Gas Supply Costs 10 Ye r Fluc ation in a 100 Therm Bill (Montana Residential Customers of NorthWestern)
23 MONTANA ELECTRIC GENERATION OPPORTUNITY The total load served over our Montana system is approximately 11 million MWh. The load we currently have responsibility for providing supply is approximately 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 Percentage of Owned Resources for Retail Use Peer Average Sources: 2012 FERC Form 1 - Sources and Disposition of Energy * PNM includes data from 2011 FERC Form 1 - 100 200 300 400 500 600 700 Gi ga wa tt h ou rs O ned 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)
24 DISTRIBUTION INVESTMENT OUTLOOK Distribution System Infrastructure Project (DSIP) The Project addresses the emerging issue of our aging infrastructure and prepares our natural gas and electric distribution systems for the next generation of technology. For the electric distribution system, the Program’s goals are: • Arrest and reverse the trend of aging infrastructure; • Build appropriate margin (capacity) back into the system; • Maintain reliability over the long-term, and improve it for our rural customers; and, • Position NWE to adopt Smart Grid, by accomplishing those tasks that are necessary, whether or not Smart Grid is eventually deployed on a wide scale, and regardless of what form of Smart Grid is eventually deployed. For the natural gas distribution system, the Program's goals are: • Embrace the industry's new performance-driven model Natural Gas Distribution Integrity Management Program (DIMP); • Employ state-of-the-art analytical capabilities to proactively manage safety; and, • Improve leak rate performance. NorthWestern, Delivering quality at a great value — yesterday, today and tomorrow… As a NorthWestern Energy customer, you expect and deserve top quality at a reasonable cost – in other words, great value. We agree. NorthWestern Energy has one of the safest and most reliable electric and natural gas distribution systems in the country, and we want to keep it that way. That’s why we created a multi-year project to aggressively replace aging infrastructure and to prepare our network to support the next generation of new technology. We requested and received MPSC approval of an accounting order to defer certain incremental O&M expenses during 2011 and 2012 and amortize these expenses associated with the phase-in portion of the DSIP. The amortization of the 2011 & 2012 expenses will be approximately $3.1 million annually over five years beginning in 2013. ($millions) Incremental Incremental Incremental Incremental CAPEX O&M CAPEX O&M CAPEX O&M CAPEX O&M Electric Utility T t l 21.3 7.4 44.9 7.6 168.2 41.2 234.4 56.2 Natural Gas Utility Total 12.4 2.5 8.0 1.5 32.1 12.8 52.5 16.8 Other Total - 7.1 - 1.1 - 7.7 - 15.9 Project Total 33.7$ 16.9$ 52.9$ 10.2$ 200.3$ 61.8$ 286.9$ 88.9$ 2011 & 2012 2013 2014 - 2017 2011 - 2017 Total Actual Estimated Cost w/inflation
25 CAPITAL SPENDING DSIP – Distribution System Infrastructure Project - $253M 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. $160 $163 $155 $151 $147 $53 $50 $50 $50 $50 $44 $33 $28 $- $50 $100 $150 $200 $250 $300 2013 2014 2015 2016 2017 $M illio ns Capital Spending Maintenance Capex Distribution System Infrastructure Project (DSIP) Energy Supply (primarily SD environmental projects) Source: 2012 10-K. Energy Supply estimates updated to reflect reduction in Big Stone AQCS budget in April 2013. Capital spending projections do not include potential future electric or natural gas energy supply additions or capital related to our Gas Transmission Infrastructure Project (GTIP*).
26 CONCLUSION Fully- regulated utility Best practices corporate governance Financially sound Strong cash flows Attractive dividend Realistic investment opportunities to invest Free Cash Flow Aberdeen Peaker Plant Ground Breaking October 14, 2011 Aberdeen Peaker Plant Ribbon Cutting July 23, 2013
27 APPENDIX
28 EARNINGS RECONCILIATION NORTHWESTERN CORPORATION Six Months Ended June 30, 2013 ($millions, except EPS) Si x M on th s E nd ed , Ju ne 30 , 2 01 2 Na tur al Ga s r eta il v olu me s Ele ctr ic ret ail vo lum es Na tur al ga s p rod uc tio n Ele ctr ic tra ns mi ss ion ca pa cit y Sp ion K op Ele ctr ic QF su pp ly co sts Mo nta na pr op ert y t ax tra ck er Mo nta na na tur al ga s r ate in cre as e Na tur al ga s t ran sp ort ati on ca pa cit y DG GS DS M los t re ve nu es Op era tin g e xp en se s r ec ov ere d i n t rac ke rs Di str ibu tio n S ys tem In fra str uc tur e Pr oje ct (D SI P) ex pe ns es Na tur al ga s p rod uc tio n Pla nt op era tor co sts La bo r No ne mp loy ee di rec tor s d efe rre d co mp en sa tio n Pe ns ion an d e mp loy ee be ne fits Op era tin g e xp en se s r ec ov ere d i n t rac ke rs Flo w- thr ou gh re pa irs de du cti on 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 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 Si x M on th s E nd ed , Ju ne 30 , 2 01 3 Gross Margin 318.9$ 3.2 3.2 5.8 4.0 3.0 1.0 1.0 0.9 0.9 (5.1) (4.9) (0.4) 2.6 334.1 Operating Expenses Op.,Gen., & Administrative 132.7 5.5 1.6 1.4 1.1 1.1 (7.6) (0.7) 1.1 136.2 Prop. & other taxes 49.6 2.0 51.6 Depreciation 52.9 3.8 56.6 Total Operating Expense 235.1 - - - - - - - - - - - - 5.5 1.6 1.4 1.1 1.1 (7.6) (0.7) - - - - - - 6.9 244.4 Operating Income 83.8 3.2 3.2 5.8 4.0 3.0 1.0 1.0 0.9 0.9 (5.1) (4.9) (0.4) (5.5) (1.6) (1.4) (1.1) (1.1) 7.6 0.7 - - - - - - (4.3) 89.7 Interest Expense (31.9) (2.1) (33.9) Other Income (Expense) 2.2 1.5 3.6 Income Before Inc. Taxes 54.1 3.2 3.2 5.8 4.0 3.0 1.0 1.0 0.9 0.9 (5.1) (4.9) (0.4) (5.5) (1.6) (1.4) (1.1) (1.1) 7.6 0.7 - - - - - (4.9) 59.4 Income Tax Benefit (Expense)1 (10.6) (1.2) (1.2) (2.2) (1.5) (1.2) (0.4) (0.4) (0.3) (0.3) 2.0 1.9 0.2 2.1 0.6 0.5 0.4 0.4 (2.9) (0.3) 2.1 0.6 1.6 (0.5) 1.5 - 2.1 (7.2) Net Income (Loss) 43.5$ 2.0 2.0 3.6 2.5 1.8 0.6 0.6 0.6 0.6 (3.1) (3.0) (0.2) (3.4) (1.0) (0.9) (0.7) (0.7) 4.7 0.4 2.1 0.6 1.6 (0.5) 1.5 - (2.9) 52.2 Fully Diluted Shares 36.62 1.24 - 37.87 Fully Diluted EPS 1.19$ 0.05 0.05 0.10 0.07 0.05 0.02 0.02 0.02 0.02 (0.08) (0.08) (0.01) (0.09) (0.03) (0.02) (0.02) (0.02) 0.12 0.01 0.06 0.02 0.04 (0.01) 0.04 (0.05) (0.09) 1.38$ 1.) Income Tax Benefit (Expense) calculation on reconciling items assumes normal effective tax rate of 38.5%.
29 ADJUSTED EPS SCHEDULE Note: No one-time adjustments for Q1 2013 2013 updated and increased EPS guidance range is $2.45 - $2.60 – midpoint of $2.53 Updated and increased 2013 EPS guidance range of $2.45 - $2.60 with a midpoint of $2.53 2013 Actual Actual Q1 2013 Q2 2013 FY 2013 Reported EPS 1.01$ 0.37$ 2.55$ Non-GAAP Adjustments: Weather (0.02) (0.02) - - Adjusted EPS 1.01$ 0.35$ 2.53$ 2012 Actual Actual Actual Actual Q1 2012 Q2 2012 Q3 2012 Q4 2012 FY 2012 Reported 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 DGGS deferral (0.05) (0.05) Lost revenue recovery related to 2010/2011 (0.05) (0.05) FERC ALJ Decision related to 2011 0.12 0.12 MSTI write-off 0.40 0.40 CELP Decision (favorable) (0.79) (0.79) Income tax adjus ment - benefit from MT NOL (0.06) (0.06) Adjusted EPS 0.92$ 0.31$ 0.36$ 0.78$ 2.37$ Estimated 2nd Half 2013 $1.17 $1.17
30 CONSOLIDATED STATEMENT OF INCOME (in thousands) 2013 2012 Variance Operating Revenues 573,181$ 553,703$ 19,478$ Cost of Sales 239,109 234,823 4,286 Gross Margin 334,072 318,880 15,192 Operating Expenses Operating, general & administrative 136,201 132,669 3,532 Property and other taxes 51,569 49,599 1,970 Depreciation 56,632 52,859 3,773 Total Operating Expenses 244,402 235,127 9,275 Operating Income 89,670 83,753 5,917 Interest Expense (33,920) (31,855) (2,065) Other Income 3,643 2,160 1,483 Income Before Taxes 59,393 54,058 5,335 Income Taxes (7,150) (10,577) 3,427 Net Income 52,243$ 43,481$ 8,762$ Average Common Share Outstanding 37,740 36,482 1,258 Basic Earnings Per Average Common Share 1.38$ 1.19$ 0.19$ Diluted Earnings Per Average Common Share 1.38$ 1.19$ 0.19$ Six Months Ended June 30,
31 CONSOLIDATED STATEMENT OF CASH FLOWS (in thousands) 2013 2012 Net Income 52,243$ 43,481$ Depreciation 56,632 52,859 Amort. of debt issue costs, discount, and deferred hedge gain 193 180 Amortization of restricted stock 1,249 1,638 Equity portion of allowance for funds used during construction (2,194) (1,831) Gain on disposition of assets (705) (122) Deferred income taxes 32,393 27,067 Changes in current assets and liabilities 4,607 26,846 Other noncurrent assets and liabilities (14,607) (5,051) Cash provided by operating activities 129,811 145,067 PP&E additions (88,549) (97,812) Asset acquisition - - Proceeds from sale of assets 747 149 Cash used in investing activities (87,802) (97,663) Treasury stock activity (1,179) (624) Proceeds from issuance of common stock, net 43,781 23,876 Dividends on common stock (28,627) (26,927) Repayment of long-term debt (73) (3,833) Repayments of short-term borrowings, net (57,940) (36,965) Financing Costs - (754) Cash used in financing activities (44,038) (45,227) Increase (decrease) in Cash and Cash Equivalents (2,029) 2,177 Beginning Cash 9,822 5,928 Ending Cash 7,793$ 8,105$ Six Months Ending June 30,
32 CONSOLIDATED BALANCE SHEET (in thousands) June 30, December 31, 2013 2012 Cash 7,793 9,822 Restricted cash 8,068 6,700 Accounts receivable, net 116,526 143,695 Inventories 47,610 54,161 Other current assets 66,084 88,750 Goodwill 355,128 355,128 PP&E and other non-current assets 2,949,839 2,827,277 Total Assets 3,551,048$ 3,485,533$ Payables 58,287 83,746 Current maturities of long-term debt & capital leases 1,656 1,612 Short-term borrowings 64,994 122,934 Other current liabilities 227,546 240,973 Long-term debt & capital leases 1,085,824 1,086,636 Other non-current liabilities 1,110,491 1,015,600 Shareholders' equity 1,002,250 934,032 Total Liabilities and Equity 3,551,048$ 3,485,533$ Capitalization: Current maturities of long-term debt & capital leases 1,656 1,612 Short Term borrowings 64,994 122,934 Long Term Debt & Capital Leases 1,085,824 1,086,636 Less: Basin Creek Capital Lease (32,211) (32,918) Shareholders' Equity 1,002,250 934,032 Total Capitalization 2,122,513$ 2,112,296$ Ratio of Equity to Capitalization 47.2% 44.2% Ratio of Debt to Capitalization 52.8% 55.8%
33 EFFECTIVE TAX RATE RECONCILIATION 2013 2012 Income Before Income Taxes $59.4 $54.1 Income tax calculated at 35% Federal statutory rate 20.8 18.9 Permanent or flow through adjustments Flow-through repairs deductions (9.8) (7.7) Flow-through of state bonus depreciation deduction (2.5) (1.9) Production tax credits (1.7) - Prior year permanent return to accrual adjustments 0.5 - State income tax & other, net (0.2) 1.3 (13.64) (8.34) Income tax expense $7.2 $10.6 Effective Tax Rate 12.0% 19.6% Six Months Ended June 30, (in millions)
34 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 2012 SYSTEM STATISTICS 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 (2) •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)
35 ENVIRONMENTAL CONTROLS Sulfur Oxide (SOX) Mercury Plant Name SCR SNCR Low Nox Burner SOFA Scrubber ESP BagHouse HG Control Injection Colstrip 3 & 4 x x x x Big Stone nis x DGGS (Natural Gas) x Coyote x x Neal #4 x x Sulfur Oxide (SOX) Mercury Plant Name SCR SNCR Low Nox Burner SOFA Scrubber ESP BagHouse HG Control Injection Colstrip 3 & 4 Big Stone x x x x x DGGS (Natural Gas) Coyote x x Neal #4 x x x x x Nitrogen Oxide (NOX) Particulate Matter Primary Pollutant Controlled Primary Pollutant Controlled PRESENT PLANNED / REQUIRED Nitrogen Oxide (NOX) Particulate Matter Controls Acronyms SCR Selective Catalytic Reduction SNCR Selective Non-Catalytic Reduction SOFA Separated over fire air to help get NOX out ESP Electrostatic precipitator primarily particulate matter HG Mercury Control Technology (primarily chemical injection and activated carbon) nis Not in Service
36 OUR COMMISSIONERS 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-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 Name Pa ty Began Se ving 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 term is 1 year. Nebraska Public Service Commission
37 SOUTH DAKOTA ELECTRIC SUPPLY CAPEX We are planning on spending approximately $180 million on capital expenditures on our South Dakota electric supply plants. $8 $14 $55 Range of $87m - $102m Range of $11m - $16m $0 $20 $40 $60 $80 $100 $120 Big Stone Neal 4 Aberdeen Peaker Planned Spent SD Electric Supply CapEx - Spent and Planned (in millions)
38 MONTANA MAJOR TRANSMISSION PROJECTS NorthWestern Energy continues to make significant investments to upgrade our transmission system to add capacity and improve reliability. Two such projects are: Jack Rabbit – Big Sky 161kV Line and Carbon - Stillwater 100kV line and substation upgrades. With a total capital investment of approximately $80M, these are two of several projects in our maintenance capex program that are necessary to meet customer needs and load growth in the region. Jack Rabbit – Big Sky 161kV Line Carbon - Stillwater 100kV - 5.0 10.0 15.0 20.0 25.0 30.0 2012 2013 2014 2015 2016 2017 $M illio ns Carbon - Stillwater Jack Rabbit - Big Sky Estimated Capital Expenditures
39 FERC’s ALJ RULING – WE GOT THE CRUST Relying on the regulatory process to provide an equitable outcome should be as American as…. apple pie. -20% -15% -10% -5% 0% 5% 10% 15% 20% MPSC FERC Total Return on EquityFERC MPSC -20% -15% -10% -5% 0% 5% 10% 15% 20% MPSC FERC Total Return on Equity (w/ Initial Decision) FERC MPSC FERC Total Direct (45MW) 45/105 39/105 21/105 105/105 43% 37% 20% 100% Fixed Costs ($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.
40 THE BACK STORY ON DGGS 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)”.
41 THE BACK STORY ON DGGS (CONTINUED) 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.