1 2013 Investor / Analyst Day New York City, NY | December 09, 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.
Bob Rowe President and CEO 3
• Welcome and opening ………………............... Bob Rowe, President & CEO • Introduction to our Board of Directors ............. E. Linn Draper Jr, Board Chairman • Company and management overview ............. Bob Rowe, President & CEO • Audit Chair perspective …………….….........… Stephen Adik, Audit Chair • A track record of solid financial performance ... Brian Bird, VP & CFO • Operations and Administrative update …......... Bob Rowe, President & CEO • Energy supply …………………………… John Hines, Vice President • Transmission …..……………………….. Mike Cashell, Vice President • Distribution ………………………………. Curt Pohl, Vice President • Regulatory .………….…………………… Pat Corcoran, Vice President • Legal………………………………………. Heather Grahame, VP & General Counsel • Customer Care, HR and Corp. Comm.... Bobbi Schroeppel, Vice President • Financial Reporting & Benefits…………. Kendall Kliewer, VP & Controller • Closing comments……………………………….. Bob Rowe, President & CEO • Question & Answer…………………………........ Board & Management Team Today’s Agenda 4
E. Linn Draper Jr. Chairman of the Board 5
(Left to right) Dir ec tor Si nc e: Bo ard Au dit No mi na tin g & C orp . G ov ern an ce Hu ma n R es ou rce s NA CD G ov ern an ce Fe llow Denton Louis Peoples Nevada Retired Chief Executive Officer and Vice Chairman of the Board of Orange and Rockland Utilities, Inc. 2006 M M M Y Dorothy M. Bradley Montana Retired District Court Administrator for the 18th Judicial Court of Montana. 2009 M M Y E. Linn Draper Jr. Texas Retired Chairman, President and Chief Executive Officer of American Electric Power Co., Inc. Recently recognized by the National Association of Corporate Directors as a one of the top 100 most influential people in the boardroom and corporate governance community. 2004 C Y Robert C. Rowe Montana President and Chief Executive Officer of NorthWestern Corporation. 2008 M Y Stephen P. Adik Indiana Retired Vice Chairman of NiSource, Inc. 2004 M C M Y Julia L. Johnson Florida President and Founder of NetCommunications, LLC and former Chairwoman of the Florida Public Service Commission. 2004 M C M Y Dana J. Dykhouse South Dakota Chief Executive Officer of First PREMIER Bank. 2009 M M M Y Philip L. Maslowe Florida Formerly Executive Vice President and Chief Financial Officer of The Wackenhut Corporation. 2004 M M C Y C = Chairperson or M = Member A Board of National Caliber 6
Bob Rowe President and CEO 7
A Well-Rounded Management Team 8 (Left to right) Ye ars ex pe rie nc e i n f iel d Po sit ion si nc e: Kendall G. Kliewer VP and Controller Responsible for accounting, financial reporting, accounts payable, payroll and compensation and benefits administration. 16 2004 Patrick R. Corcoran VP- Gov't & Regulatory Affairs Responsible for electric and natural gas government and regulatory activities. 34 2001 Brian B. Bird VP and Chief Financial Officer Responsible for finance, treasury, accounting, tax, investor relations, information technology and executive compensation. 28 2003 Bobbi L. Schroeppel VP - Customer Care, Communications & Human Resources Responsible for customer care, economic development, key account management, community relations, corporate communications and human resources. 20 2002 Robert C. Rowe President & Chief Executive Officer 21 years energy and utility industry experience (including 12 years on the Montana Public Service Commission). 21 2008 Curtis T. Pohl VP - Distribution Responsible for electric and natural gas distribution operations, safety and support services. 27 2003 Heather H. Grahame VP and General Counsel Responsible for all in-house and outside legal activities, including FERC compliance, risk management and records management. 29 2010 John D. Hines VP - Supply Responsible for electric and natural gas planning, procurement and generation operations and the environmental function. 24 2011 Michael R. Cashell VP - Transmission Responsible for all electric transmission, substation and relay operations, and natural gas transmission and storage operations. 27 2011
About Northwestern 9 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 10 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 time Attractive future growth prospects – Reintegrating energy supply portfolio (electric and natural gas) – Distribution System Infrastructure Program (DSIP) – Transmission opportunities within our service territory
A Diversified Electric and Gas Utility 11 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. 83% Residential 16% Commercial 1% Industrial 84% Montana 14% South Dakota 2% Nebraska 78% Electric 22% Natural Gas
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 12 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. This 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 201 2011 2012 Write-Off to Revenue Ratio
$0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 $2,000 2008 2009 2010 2011 2012 Milli ons Estimated Rate Base Natural Gas Reserves Spion Kop DGGS Colstrip Unit 4 All other rate base Investment in our System 13 Over the past 5 years we have been adding to our Montana energy supply portfolio and making additional investments to enhance system safety, reliability and capacity. Rate Base estimates as of December 31, 2012 do not include Bear Paw North ($19.5M) or Bear Paw South ($70.2M) natural gas reserves acquisitions. These investments are currently being recovered in our natural gas tracker. Jurisdiction and Service Implementation Date Estimated Rate Base (in millions) (1) Authorized Overall Rate of Return Authorized Return on Equity Authorized Equity Level South Dakota electric (2) September 1981 200.2$ n/a n/a n/a Nebraska natural gas (2) December 2007 23.1$ n/a 10.40% n/a Montana - Colstrip Unit 4 January 2009 356.8$ 8.25% 10.00% 50.0% DGGS (3) January 2011 155.6$ 8.16% 10.25% 50.0% Montana electic delivery (3) January 2011 724.6$ 7.80% 10.25% 48.0% South Dakota natural gas (2) December 2011 62.0$ 7.80% n/a n/a Montana natural gas production November 2012 10.9$ 7.65% 10.00% 48.0% Montana - Spion Kop December 2012 82.1$ 7.00% 10.00% 48.0% Montana natural gas delivery (4) April 2013 353.8$ n/a 9.80% n/a 1,969.1$ (1) Rate base amounts are estimated as of December 31, 2012 (2) For those items marked as "n/a," the respective settlement and/or order was not specific as to these terms. (3) 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. (4) Updated to reflect Final Order received in April 2013 (based on 2011 test year) Rate Base as of 12/31/2012
Strong Corporate Governance 14 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 consecutive time, NorthWestern Corporation was recognized by Forbes as one of "America's Most Trustworthy Companies," which identifies the most transparent and trustworthy businesses that trade on the American exchanges. In the past, Forbes turned to Audit Integrity who recently merged with Corporate Library and Governance Metrics International to form GMI Ratings (GMI). GMI's quantitative and qualitative data analysis looks beyond the raw data on companies' income statement and balance sheets to assess the true quality of corporate accounting and management practices. Each year Forbes recognizes 100 companies out of over 8,000 for this foremost honor. NWE was one of only three utilities to be distinguished with this honor, by Forbes, in 2013. 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 t 42 ompanies 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 15 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 developm nt 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.
Stephen P. Adik Audit Committee Chairman 16
Brian Bird Vice President & CFO 17
$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 18 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 hydro related transaction fees and expenses; and • Diluted average shares outstanding of 38.3 million. A demonstrated track record of solid earnings growth in line with communicated guidance. 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
Track Record of Delivering Results 19 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 3.5% 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
Investment for our Customers’ Benefit Over the past 5 years, we have been adding to our Montana energy supply portfolio and making additional investments 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%) 20 $69.57 $68.78 $70.03 $73.26 $74.95 $60 $70 $80 $90 2 08 2009 2010 2011 2012 Retail Electric Revenue per Megawatt hour (MWh) $11.20 $9.80 $9.11 $8.92 $8.66 $- $3 $6 $9 $12 $15 2008 2009 2010 2011 2012 Retail Natural Gas Revenue per Dekatherm (Dkt) $1.00 $1.25 $1.50 $1.75 $2.00 $2.25 $2.50 $2.75 $3.00 $1,000 $1,250 $1,500 $1,750 $2,000 $2,250 2008 2009 2010 2011 2012 Rate Base and Earnings per Share Estimated Rate Base (Millions) GAAP Diluted EPS Rate Bas e -M illion s EPS -Dollars
Total Shareholder Return 21 Strong total shareholder return since emergence from bankruptcy particularly in the last 5 year. Peer Group: ALE, AVA, BKH, CNL, EE, EDE, GXP, IDA, MGEE, POR, PNM, UIL, UNS, VVC, & WR -50% 0% 50% 100% 150% 200% NWE Peer Average S&P 500 DJU Total Shareholder Return 11/2/04 to 11/29/13 NWE 160.5% Peer Avg. 117.9% DJU 124.7% S&P 500 93.3% NorthWestern Energy - Total Shareholder Return (TSR) since Emergence Comparison November 2, 2014 through November 29, 2013 NWE 69.8% 15 Peer Avg. * 54.3% S&P 600 68.6% DJUA 40.8% 0% 10% 20% 30% 40% 50% 60% 70% 80% 3 Year Total Shareholder Return 12/1/2010 to 11/29/2013 NWE 32.8% 15 Peer Avg. * 20.4% S&P 600 37.7% DJUA 11.6% 0% 5% 10% 15% 20% 25% 30% 35% 40% 1 Year Total Shareholder Return 12/1/2012 to 11/29/2013 NWE 181.7% 15 Peer Avg. * 116.8% S&P 600 163.6% DJUA 58.0% 0% 50% 100% 150% 200% 5 Year Total Shareholder Return 12/1/2008 to 11/29/2013
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 22 (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)
Balance Sheet Strength 23 Annual ratio is average of each quarter end debt/cap ratio Excludes Basin Creek capital leases Goal: 50% - 55% $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 2009 2010 2011 2012 Debt to Capital Ratio 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 Investment Grade 2005 2006 2007 2008 2009 2010 2011 2012 2013* Secured Credit Ratings S&P Moody's Fitch BBB-/Baa3/BBB- BBB/Baa2/BBB BBB+/Baa1/BBB+ BB+/Ba1/BB+ A-/A3/A- A/A2/A 2013 data as of September 30, 2013
Net Investment in Existing Business 24 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
2014 Capital Reconciliation 25 2014 budgeted capital is $272 million, or $18M higher than the anticipated 2014 Capital Requirements as previously reported in our 2012 10-K. $50 $69 $134 $19 $0 $50 $100 $150 $200 $250 $300 2014 Budget 2014 Budgeted Capital (in millions) $50 $68 $119 $18 $0 $50 $100 $150 $200 $250 $300 2014 Included in 10K Common Distribution Transmission Energy Supply Anticipated 2014 Capital as reported in 2012 10-K (in millions) $254 $272
2014 Earnings Guidance 26 Continued investment in our system to serve our customers and communities is expected to provide average earnings growth of 4-6% annually. That, coupled with an anticipated dividend yield of 3-4% creates the potential for a targeted 7-10% total return for our investors. 2014 guidance range of $2.60-$2.75 based upon, but not limited to, the following major assumptions and expectations: • Normal weather in our electric and natural gas service territories for 2014; • Excludes any hydro related transaction fees (including legal and bridge financing) and any potential income generated from the operation of the hydro assets post closing; • A consolidated income tax rate of approximately 14% to 16% of pre-tax income; and • Diluted average shares outstanding of 39.3 million. 2014 broad earnings drivers as provided at November 2013 EEI Financial Conference 2014 guidance announced Estimates above assume a 38.5% effective tax rate Low Midpoint High 2013 EPS Guidance Range $2.45 $2.53 $2.60 2014 Drivers Bear Paw South acquisition $0.06 to $0.10 Full year MT Nat Gas relief $0.08 to $0.12 Other Gross Margin i creases $0.25 to $0.35 OA&G increases ($0.10) to ($0.05) Property Tax increases ($0.10) to ($0.08) Depreciation increase ($0.04) to ($0.02) Interest / Other Income ($0.08) to ($0.04) Dilution-existing equity dribble ($0.08) to ($0.07) $2.44 $2.68 $2.91
Bob Rowe President and CEO 27
Investment Opportunity Outlook 28 • Energy Supply – Pending hydro transaction – Big Stone/Neal pollution control – Additional acquisition opportunities for Montana natural gas reserves • Transmission – Network upgrades • Jack Rabbit - Big Sky 161kV line • Carbon - Stillwater 100kV – Transmission System Infrastructure Project – NERC Alert (Clearances) • 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 29 Energy Supply Distribution Color / label indicate NorthWestern Energy's current probability of execution. * Capital spent as of September 30, 2013. Total does not include $70M Bear Paw South (Devon Reserves and Havre Pipeline) purchase closed December 1, 2013. 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 closed December 1, 2013. In September 2013, we announced the acquisition of 12 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 Base Load Electric Opportunity 30 127% 122% 120% 105% 102% 98% 97% 91% 84% 78% 77% 69% 64% 60% 60% 53% 44% 0% 20% 40% 60% 80% 100% 120% 140% WR GXP EE CNL UNS IDA EDE VVC ALE AVA UIL NWE (Hydro) MGEE PNM BKH POR NWE Peer Average 99% 31% 44% 0% 20% 40% 60% 80% 100% NWE - SD NWE - MT NWE - Total 99% 63% 69% 0% 20% 40% 60% 80% 100% NWE - SD NWE - MT (Hydro) NWE - Total (hydro) Percentage of Owned Generation Resources for Retail Use The load we currently are responsible for providing supply is just over 6 million MWh. Our current owned generation in Montana, including the addition of Spion Kop, provides approximately 31% of the load we serve (2). If approved, this transaction would allow us to approximately double owned resources in Montana and significantly reduce our reliance on third-party power purchase agreements and spot market purchases. Owned Generation Resources NWE 2012 Actual Owned Generation Resources NWE Pro Forma with Hydro (1) 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 (2) Total control area load is approximately 11 million MWh, of which our owned generation would provide approximately 17%
Hydro - Supporting our Values 31 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.
John Hines Vice President – Energy Supply 32
Energy Supply Overview 33 Primary responsibilities: • Undertake planning for effectively meeting the portfolio requirements of our electricity and natural gas customers • Acquire, and where applicable, operate and maintain our electric generation fleet • Operate electric real-time and term (out to 18 months) trading functions • Acquire or perform market purchases of natural gas – Optimize NWE owned storage • Oversee environmental and real estate recovery Priorities: safety; provide low-cost, reliable and stably priced supply; and achieve full cost recovery. Electric (MW) MT SD Total Base load coal 222 210 432 Wind 40 - 40 Other resources 150 166 316 412 376 788 Natural Gas (Bcf) MT SD Total Proven Reserves 84.4 - 84.4 Annual production 7.4 - 7.4 Storage 17.8 - 17.8 (1) Includes 60 MW Aberdeen Peaker placed in service April 2013 (2) Includes 63.0 Bcf of proven reserves with 5.5 Bcf annual production from Bear Paw South acquired on December 1, 2013 Energy Supply statistics for 2012 (1) (2) (2)
Energy Supply Transmission Distribution Common $0 $50 $100 $150 $200 $250 $300 2014 Budget 2014 Capital (in millions) 2014 Energy Supply Capital Budget 34 Colstrip Unit 4 35 3 7 5 $0 $5 $10 $15 $20 $25 $30 $35 $40 Big Stone - environmental upgrades Neal 4 - environmental upgrades Colstrip Unit 4 Maintenance Capex All Other Maintenance Capex M illi on s 2014 Energy Supply Capital (in millions) Energy Supply capital of $50M (gas and electric) accounts for 18% of the overall 2014 capital budget.
Montana Hydro Acquisition 35 • Announced, in September 2013, the acquisition of eleven base load 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 various regulatory approvals, including 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% Rai bow 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
36 Montana Sources of Supply with Hydro Assets (Total Annual Energy - 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 would represent over 50% of our generation portfolio, in Montana, after the close of the pending hydro transaction.
Meeting Customer Demand 37 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 Light Load - Demand Conveyance of Kerr Dam to CSKTMWhs - 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
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: – 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 – 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, close and transition Hydro – Process and Timeline 38 If approved, we expect to close the 3rd quarter of 2014 Ryan Dam
Hydro - A Great Fit at the Right Time 39 – 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.
Big Stone and Neal Air Quality Projects 40 Big Stone Power Plant Neal Power Plant Big Stone Neal Location Northeast South Dakota Northwest Iowa Ownership 23.4% of 475 MW coal plant 8.7% of 644 MW coal plant Project Subject to Best Available Retrofit Technology (BART) requirements of the Regional Haze Rule and are installing an Air Quality Control System (AQCS) to reduce SO2, NOx and particulates Subject to comply with national ambient air quality standards and Mercury & Air Toxics Standards (MATS) and are installing a scrubber, a baghouse, activated carbon and a selective non-catalytic reduction system Capital Outlay Capitalized approximately $28M through 9/30/13. Estimated total share of project is expected to be $95M-$110M including AFUDC and overheads Capitalized approximately $21M through 9/30/13. Total share of project is estimated to be $25M-$30M including AFUDC and overheads Timeline Project is on time and expected to be completed in 2016 Project is on time and expected to be completed in 2014
Battle Creek ~1% Bear Paw North ~8% Bear Paw South ~28% Unfilled ~13% Natural Gas Reserves Opportunity 41 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. $- $20 $40 $60 $80 $100 $120 $140 $160 Transmission, Distribution & Storage Costs Natural Gas Supply Costs 10 Year Fluctuation in a 100 Therm Bill (Montana Residential Customers of NorthWestern) As we continue to add to our natural gas reserves portfolio, we can significantly reduce supply costs volatility for our customers. Battle Creek Bear Paw North Bear Paw South Announcement 9/22/2010 9/4/2012 5/28/2013 Purchase Price ($M) $12.4 $19.5 $62.6 Assets 8.4 Bcf of proven producing reserves plus gathering sy tem 13.4 Bcf of proven producing reserves plus gathering system 63 Bcf of proven producing reserves plus gathering and 82 mile transmission line Recovery Status Rate Based Tracker Tracker (s tarting Dec. 2013)
Southern Bear Paw (Devon) Transaction 42 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 did not seek MPSC pre-approval of the natural gas reserves as a closing condition. • We are utilizing our natural gas tracker to recover cost of gas similar to prior natural gas reserves acquisitions. – 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%. • Transaction closed December 1, 2013, with a total purchase price of $68.8 million ($62.6 million for the proven reserves and $6.2 million for the 82% interest in Havre Pipeline Company). Blaine County Montana Compressor Station
Mike Cashell Vice President – Transmission 43
Transmission Overview 44 • NorthWestern has a robust and methodical planning and prioritization process for transmission systems, with focus on: – Meeting increasing demand in service territories – Meeting reliability requirements – Meeting growing regulatory compliance obligations – Meeting requirements under Open Access Transmission Tariff • Electric Transmission priorities – Safety, reliability, able to grow, optimized with new and existing facilities, responsive to all customers, energy efficient, cost effective and use of effective technologies to further all other objectives • Gas Transmission –similar process of prioritization Transmission for others MT SD Total Electric (GWh) 9,600 100 9,700 Natural Gas (Bcf) 21.0 21.0 System (miles) MT SD Total Electric 6,900 1,300 8,200 Natural gas 2,000 55 2,055 Transmission statistics for 2012
Energy Supply Transmission Distribution Common $0 $50 $100 $150 $200 $250 $300 2014 Budget 2014 Capital (in millions) 10 9 6 6 5 4 3 3 2 21 $0 $5 $10 $15 $20 $25 M illi on s 2014 Transmisson Capital (in millions) 2014 Transmission Capital Budget 45 Transmission capital of $69M (gas and electric) accounts for 25% of the overall 2014 capital budget.
Transmission Projects 46 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 our service territory. Jack Rabbit – Big Sky 161kV Carbon - Stillwater 100kV - 5.0 10.0 15.0 20.0 25.0 30.0 2012 2013 2014 2015 2016 2017 $M illio ns Jack Rabbit - Big Sky Carbon - Stillwater Estimated Capital Expenditures
Transmission System Infrastructure Project 47 Transmission System Infrastructure Program (TSIP) • Gas Transmission Program – Moving beyond basic compliance with federal safety regulations to systematic prioritization and addressing of pipeline integrity management for long-term customer benefit. – Focus is on managing the integrity of the system in the areas of highest potential consequences. • Increase public safety within NorthWestern’s operating area, specifically Class 3 locations. • Electric Transmission Program – Strong Programs currently in place, but initiative underway to evaluate the overall performance and health of our transmission delivery system. – Components include, vegetation management, pole replacement, overhead line maintenance, NERC Compliance, capacity, reliability, technology. Program scope and expenditures still in development.
Transmission System “NERC Alert – Facilities Ratings” 48 • The North American Electric Reliability Corporation (NERC) issued a Recommendation and Guidance to Industry on the "Consideration of Actual Field Conditions in Determination of Facility Ratings." • This recommendation is to verify actual field conditions and compare them to the documented design of the facility. This recommendation applies to all bulk electric transmission system facilities (100 kV and above). These are safety and reliability related improvements. • Investment over the next 3 to 4 years is expected to be as follows: Line Voltage Cost Estimate (Low) $millions Cost Estimate (High) $millions 230 kV - Medium Priority $1.5 $2.1 161 kV - Medium Priority $6.9 $9.6 115 kV - Low Priority $1.7 $2.3 100 kV - Low Priority $20.8 $29.2 Total $30.9 $43.2 NERC expenditure estimates to the left are incremental required investment not included in the 5-year Capital Requirements as previously reported in the 2012 10-K . We anticipate including the estimated timing of this capital in the forthcoming 2013 10-K.
Curt Pohl Vice President – Distribution 49
Distribution Overview 50 Demand MT SD/NE Total Daily MWs 750 172 922 Peak MWs 1,784 324 Annual GWhs 6,400 1,500 7,900 Annual Bcf 19 8 27 Customers MT SD/NE Total Electric 342,000 61,600 403,600 Natural gas 183,300 86,300 269,600 525,300 147,900 673,200 Sy tem (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 (1) Nebraska is a natural gas only jurisdiction Distribution statistics for 2012 (1) Distribution operating philosophy – Simple but effective, grounded in fundamentals • Committed To Safety • Committed to Providing High Level of Customer Service (Reliable) • Focused on Long Term Asset Management Data System information Analyze Asset Management & Planning & engineering Execute Operations & Construction Evaluate Organizational Performance
Frequency of asset replacement Very frequent replacement Replace only at failure Prohibitively Expensive Unacceptable Operations Desired Economic Operating Range Asset Management Approach 51
Energy Supply Transmission Distribution Common $0 $50 $100 $150 $200 $250 $300 2014 Budget 2014 Capital (in millions) 52 23 20 11 4 4 3 17 $0 $10 $20 $30 $40 $50 $60 M illi on s 2014 Distribution Capital (in millions) 2014 Distribution Capital Budget 52 Distribution capital of $134M (gas and electric) accounts for 49% of the overall 2014 capital budget.
DSIP Investment Outlook 53 • Montana Distribution System Infrastructure Project (DSIP) to maintain a safe and reliable electric and natural gas distribution system. – The primary goals: reverse the trend in aging infrastructure, maintain reliability, proactively manage safety, build capacity into the system, and prepare our network for the adoption of new technologies. – Based on our current plans, along with the MPSC's approval of the accounting order, we believe DSIP-related expenses and capital expenditures will be recovered in base rates through future general rate cases. ($millio s) CAPEX O&M CAPEX O&M CAPEX O&M CAPEX O&M CAPEX O&M Electric Utility Total $21 $7 $46 $8 $45 $7 $122 $35 $234 $56 Nat ral Gas Utility Total 12 2 7 1 7 1 26 12 53 17 Other Total - 7 - 1 - 1 - 7 - 16 Project Total $33 $16 $53 $10 $52 $9 $149 $54 $287 $89 Accounting Order (16) 3 3 9 (0) P&L Impact $0 $13 $12 $63 $89 Actual Estimated Cost w/inflation 2011 & 2012 2013 2014 2015 - 2017 2011 - 2017 Total
Pat Corcoran Vice President – Regulatory 54
Regulatory Activities 55 Major Activities Filing Update • Electric and natural gas general rate filings – state and federal – Annual first look cost of service analysis • Montana electricity supply resources approval filings – PPL Montana hydroelectric generation acquisition filing • Federal Energy Regulatory Commission – PPL Montana hydroelectric generation acquisition filings • Section 203 application for transaction approval • Section 205 application for Market-Based rate approval • Natural gas acquisition filings (Montana) – Interim and final cost recovery • Bear Paw North (NFR) • Bear Paw South (Devon)
Regulatory Activities 56 Annual and biennial filings update • Annual compliance filings – Qualifying facilities • Annual tracker filings – Energy supply tracker filings • 2012 Montana electric energy supply filing – Dave Gates Generation Stations (DGGS) outage costs – Demand Side Management (DSM) cost review – Lost revenue adjustment mechanism • Montana property tax tracker filing • Biennial – 2013 electric supply resource procurement plan filing
Heather Grahame – VP & General Counsel 57 Legal • Material legal proceedings disclosed in SEC filings consist of only one matter: Sierra Club and Montana Environmental Information Center v. PPL Montana LLC, etc. • Strong, small internal legal team – Effectively manages external legal costs – Partners with internal clients
Bobbi Schroeppel - VP 58 Customer Care, HR and Corporate Communications • Successful Customer Information System (CIS) implementation at significantly lower costs as compared to other recently installed systems • Improvements in customer service has resulted in best JD Power scores received to date • Continue to attract high quality employees to replace retiring workforce and meet the needs of NorthWestern Energy’s growing operations
Kendall Kliewer – VP & Controller 59 Financial Reporting and Employee Benefits • Timely and transparent financials (transparency a significant factor in Forbes 100 most trustworthy companies) • Taken steps to better manage employee benefit costs while providing a competitive benefits package
Bob Rowe President and CEO 60
Conclusion 61 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
Questions? 62
Appendix 63
Adjusted EPS Schedule 64 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 65 (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 $1.11 Three Months Ended September 30, Nine Months Ended September 30,
3 Month Earnings Reconciliation 66 NORTHWESTERN CORPORATION Three Months Ended September 30, 2013 ($millions, except EPS) Th ree M on ths E nd ed , Se pte mb er 30 , 2 01 2 DG GS DS M los t re ve nu es 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 tra ck ers Ele ctr ic ret ail vo lum es Op era tin g e xp en se s r ec ov ere d i n t rac ke rs Ele ctr ic tra ns mi ss ion 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 La bo r Pla nt op era tor 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 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 Th ree M on ths E nd ed , Se pte mb er 30 , 2 01 3 Gross Margin 142.8$ 10.2 5.0 1.6 1.2 1.2 0.9 (3.5) (1.9) (0.4) - - 0.9 158.0 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 72.5 MSTI impairment 24.0 (24.0) - Prop. & other taxes 24.8 1.2 26.0 Depreciation 26.5 1.6 28.1 Total Operating Expense 138.4 - - - - - - - (1.9) - 3.3 2.8 1.7 1.6 1.5 0.6 (3.1) - - - - - - - (18.3) 126.5 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 31.4 Interest Expense (17.7) 0.6 (17.1) Other Income (Expense) 1.0 2.1 3.1 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 17.5 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) (1.8) 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 15.6 Fully Diluted Shares 37.20 1.44 - 38.65 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 0.40$ 1.) Income Tax Benefit (Expense) calculation on reconciling items assumes normal effective tax rate of 38.5%.
9 Month Earnings Reconciliation 67 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 68 (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 $18.2 Nine Months Ending September 30,
Consolidated Balance Sheet 69 (in millions) Sept. 30, 2013 Dec. 31, 2012 Cash 10.9 9.8 Restricted cash 8.2 6.7 Accounts receivable, net 129.2 143.7 Inventories 62.6 54.2 Other current assets 69.7 88.8 Goodwill 355.1 355.1 PP&E and other non-current assets 2,997.9 2,827.3 Total Assets 3,633.7$ 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 70 (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) / valuati n 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,
-20.4% 10.9% 10.8% 24.1% -3.0% 4.5%4.4% 6.8% 5.7% 5.7% 4.1% 5.3% -30.0% -20.0% -10.0% 0.0% 10.0% 20.0% 30.0% 40.0% 2008 2009 2010 2011 2012 Average '08-'12 Dividend Return Stock Price % Change Realized Total Shareholder Return (Market) 2008-2012 -16.0% 17.7% 16.5% 29.8% 1.1% 9.8% Total Return History 71 The top chart provides a history of annual EPS growth plus dividend yield. The bottom chart provides a history of annual total shareholder market returns. On either measure, historically, on average, we have been able to achieve or exceed our targeted 4-6% earnings growth and 3-4% dividend return over the last 5 years. “Dividend Return” assumes reinvestment of cash dividends. Data source: SNL Financial 22.9% 14.1% 5.9% 18.2% 5.1% 13.3% 4.4% 6.8% 5.7% 5.7% 4.1% 5.3% . 5.0 10.0% 15.0% 20.0% 25.0% 30.0% 2008 2009 2010 20 1 20 2 Average '08-'12 Dividend Return EPS Growth Rate Implied* Total Return (EPS Growth + Dividend Return) 2008-2012 * Hypothetical measur attempting to remove impact of changes in industry P/E valuation multiples 27.3% 20.9% 11.6% 23.9% 9.2% 18.6%
Non-GAAP Financial Measures 72 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
Our Commissioners 73 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 74 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 75 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) 76 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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