Echo Lake Nordic Trail - Montana Wells Fargo Energy Symposium December 5-6, 2018 New York 8-K December 4, 2018
2 Forward Looking Statements Forward Looking Statements During the course of this presentation, there will be forward-looking statements within the meaning of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address our expected future business and financial performance, and often contain words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” or “will.” The information in this presentation is based upon our current expectations as of the date hereof unless otherwise noted. Our actual future business and financial performance may differ materially and adversely from our expectations expressed in any forward-looking statements. We undertake no obligation to revise or publicly update our forward-looking statements or this presentation for any reason. Although our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. The factors that may affect our results are listed in certain of our press releases and disclosed in the Company’s most recent Form 10-K and 10-Q along with other public filings with the SEC. Company Information NorthWestern Corporation Corporate Office Investor Relations Officer dba: NorthWestern Energy 3010 West 69th Street Travis Meyer Ticker: NWE Sioux Falls, SD 57108 605-978-2967 Trading on the NYSE (605) 978-2900 travis.meyer@northwestern.com www.northwesternenergy.com
3 About NorthWestern South Dakota Operations Electric 63,600 customers 3,560 miles – transmission & distribution lines 440 MW nameplate owned power generation Natural Gas 46,500 customers 1,681 miles of transmission and distribution pipeline Montana Operations Electric 369,100 customers 24,495 miles – transmission & distribution lines 809 MW nameplate owned power generation Natural Gas 196,700 customers 7,287 miles of transmission and distribution pipeline Nebraska Operations 17.75 Bcf of gas storage capacity Natural Gas Own 55.9 Bcf of proven natural gas reserves 42,400 customers 790 miles of distribution pipeline Data as of 12/31/2017
4 NWE - An Investment for the Long Term • 100% regulated electric & natural gas utility business Black Eagle dam Pure Electric & with over 100 years of operating history Gas Utility • Solid economic indicators in service territory • Diverse electric supply portfolio ~56% hydro & wind • Residential electric & gas rates below national average Solid Utility • Solid system reliability (EEI 2nd quartile) Foundation • Low leaks per 100 miles of pipe (AGA 1st quartile) • Solid JD Power Overall Customer Satisfaction scores Strong • Consistent track record of earnings & dividend growth • Strong cash flows aided by net operating loss carry- Earnings & forwards anticipated to be available into 2020 Cash Flow • Strong balance sheet & investment grade credit ratings Attractive • Disciplined maintenance capital investment program to ensure safety and reliability • Significant investment in renewable resources (hydro & wind) will provide long-term Future Growth energy supply pricing stability for the benefit of customers for many years to come Prospects • Further opportunity for energy supply investment to meet significant capacity shortfalls Financial Goals • Debt to total capitalization ratio of 50%-55% with liquidity of $100 million or greater • Targeted 6%-9% long-term total shareholder return (eps growth plus dividend yield) & Metrics • Targeted dividend payout ratio of 60%-70% Best Practices Corporate Governance
5 A Diversified Electric and Gas Utility September 2018 Montana electric rate review, filed with rate base of $2.34 billion, calculated with 13th month average and known and measurable adjustments. NorthWestern’s ‘80/20’ rules: Approximately 80% Electric, 80% Residential and 80% Montana Data as reported in our 2017 10-K Over $3.5 billion of rate base investment to serve our customers
6 Highly Carbon-Free Supply Portfolio Based upon 2017 MWH’s of owned and long-term contracted resources. Approximately 56% of our total company owned and contracted supply is carbon-free. NorthWestern does not own all the renewable energy certificates (RECs) generated by contracted wind, and periodically sells its own RECs with proceeds benefiting retail customers. Accordingly, we cannot represent that 100% of carbon-free energy in the portfolio was delivered to our customers.
7 Strong Utility Foundation . Solid and improving JD Power Overall Customer Satisfaction Scores . Residential electric and natural gas rates below national average . Solid electric system reliability and low gas leaks per mile
8 Solid Economic Indicators Source: NorthWestern customer growth - 2008-2016 Forms 10-K Unemployment Rate: US Department of Labor via SNL Database 2/21/17 Electric: EEI Statistical Yearbook (published December 2015, table 7.2) Natural Gas: EIA.gov (Data table "Number of Natural Gas Consumers") Source: Company 10K’s, 2015/2016 EEI Statistical Yearbook – Table 7.2 and EIA.gov Black Eagle Power House • Customer growth rates historically exceed National Averages. • Projected population growth in our service territories in-line or better than the National Average.
9 A History of Growth $3.30-$3.50 $3.10 - $3.30 $2.60$3.20 - $2.75-$3.40 2008-2017 CAGR’s: GAAP EPS: 7.3% - Non-GAAP EPS: 6.8% - Dividend: 5.3% See appendix for “Non-GAAP Financial Measures”
10 Track Record of Delivering Results * Peer Group: ALE, BKH, EE, IDA, MGEE, NWN, OGE, OTTR, PNM, POR, SR, & VVC Return on Equity on GAAP Earnings within 9.5% - 11.0% band over the last 6 years with average of 9.9%. See appendix for “Non-GAAP Financial Measures” Total Shareholder Return is better than our 12 peer average for the 1 & 10 year periods but lags in the 3 & 5 year periods, due primarily to concerns over Montana regulatory decisions.
11 Investment for Our Customers’ Benefit Over the past 8 years we have been reintegrating our Montana energy supply portfolio and making additional investments across our entire service territory to enhance system safety, reliability and capacity. We have made these enhancements with minimal impact to customers’ bills while maintaining bills lower than the US average. As a result we have also been able to deliver solid earnings growth for our investors. 2008-2017 CAGRs Estimated Rate Base: 13.3% GAAP Diluted EPS: 7.3% 2008-2017 CAGRs NWE typical electric bill: 2.1% NWE typical natural gas bill: (6.1%) 2008-2017 CAGRs US average electric bill: 1.7%* US average natural gas bill: (2.6%)**
12 Balance Sheet Strength and Liquidity Investment grade credit ratings, generally liquidity in excess of $100 million target, debt to cap within our targeted 50%-55% range and no long-term debt maturities until 2023.
13 Strong Cash Flows While maintenance capex and total dividend payments have continued to grow since 2011 (12.9% and 13.0% CAGR respectively), Cash Flow from Operations (CFO) has, on average, exceeded maintenance capex and dividend payments by approximately $24 million per year. 2016 CFO is less than 2015 largely due to $30.8M refund to customers related to FERC/DGGS ruling and $7.2M refund to customers for difference in SD Electric interim & final rates. We expect NOLs to be available into 2020 with alternative minimum tax credits and production tax credits to be available into 2022 to reduce cash taxes. Additionally, we anticipate our effective tax rate to approach 10% by 2022. (See appendix for “Non-GAAP Financial Measures” relating to free cash flow and disclaimer on NOLs)
14 2018 Earnings Guidance $3.30-$3.45 $3.10 - $3.30 $2.60 - $2.75 NorthWestern reaffirms its 2018 earnings guidance range of $3.35 - $3.50 per diluted share is based upon, but not limited to, the following major assumptions and expectations: • Normal weather in our electric and natural gas service territories; • Exclusion of Montana and South Dakota TCJA settlement impacts in excess of the actual 2018 income tax expense reduction; • Recovery of Montana energy supply costs per our understanding of the pending PCCAM final order; • A consolidated income tax rate of approximately 0% to 5% of pre-tax income; and • Approximately 50.1 million diluted average shares outstanding. Continued investment in our system to serve our customers and communities is expected to provide a targeted long term 6-9% total return to our investors through a combination of earnings growth and dividend yield. However, negative outcomes in upcoming regulatory proceedings may result in near-term returns below our 6-9% targeted range. Generation investment to reduce or eliminate our capacity shortfall could allow us to achieve the higher-end of our range over the long term. See appendix for additional disclosures regarding “Non-GAAP Financial Measures” See “Non-GAAP Financial Measures” slide in appendix for “Non-GAAP “Adjusted EPS”.
15 Summary Financial Results (Nine Months Ended September 30) (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. See appendix for additional disclosure.
16 Maintaining Full Year Non-GAAP Guidance In order to meet 2018 guidance, we $3.30will- $3.45need to deliver $3.10 - $3.30 $2.60EPS - $2.75 of $1.03 - $1.18 during the fourth quarter of the year. This compares to $0.95 earned in the fourth quarter of 2017. The non-GAAP measures presented in the table to the left are being shown to reflect significant items that were not contemplated in our original guidance, however they should not be considered a substitute for financial results and measures determined or calculated in accordance with GAAP. See appendix for additional disclosures regarding “Non-GAAP Financial Measures” See “Non-GAAP Financial Measures” slide in appendix for “Non-GAAP “Adjusted EPS”.
17 Regulatory & Legal Update Power Cost and Credit Adjustment Mechanism (PCCAM) • In May 2017, the MPSC initiated a docket to implement House Bill 193 (HB193), which removed statutory language mandating tracking of electricity supply costs and replaced West Rosebud Creek, MT it with language that gives the MPSC discretionary authority. • In July 2017, we filed a proposal for the PCCAM that incorporates a sharing ratio of 90/10 between customers and shareholders for supply expenses above and below an established baseline. • In November 2018, the MPSC voted to approve a PCCAM with the following provisions: • Adopt the MPSC Staff's recommendation with regard to categories and amounts of base supply costs, which are consistent with what we proposed; • A sharing mechanism that includes a +/- $4.1 million deadband around the base, with differences beyond the deadband shared 90% customers and 10% shareholders; and • Retroactive implementation to the effective date of HB 193 (July 1, 2017). • We have recorded a $1.8 million net reduction in revenue to be recovered from customers. This includes an approximately $3.3 million increase in revenues for the PCCAM period 2017/2018 offset by an approximately $5.1 million reduction in revenues for the first three months of the 2018/2019 PCCAM period. We are currently reviewing the final order issued on November 29, 2018. Colstrip Unit 4 - Disallowance of 2013 Replacement Power Costs • In May 2016, the MPSC issued a final order disallowing recovery of certain costs • In September 2016, we appealed the order to the Montana District Court arguing the decision was arbitrary and capricious and violated Montana law. • In July 2018, the District Court issued a decision upholding the MPSC’s order disallowing recovery of the replacement power costs. We have elected not to appeal this decision to Montana Supreme Court.
18 Estimated Impacts of the Tax Cuts & Jobs Act South Dakota – In September 2018, the South Dakota Public Utility Commission Black Eagle Power House approved a settlement agreement resulting in a one-time refund to electric and natural gas customers of $3.0 million by October 31, 2018. This includes a two-year rate moratorium, ensuring rates remain static until January1, 2021. Nebraska – In August 2018, the Nebraska Public Service Commission approved a settlement between us and the cities of Grand Island, Kearney and North Platte to evaluate the impact of the TCJA on an annual basis. This is consistent with our proposal to use any calculated customer benefit to defer planned future rate filings and had no impact on our financial statements. Montana – In March 2018, we submitted a filing to the MPSC calculating the estimated benefit of the TCJA related savings to customers using two alternatives - current year and historical test year methodologies. On November 9th, we reached an all-party agreement with intervenors to provide a one-time credit of $20.5 million to eligible customers commencing within 30 days of MPSC approval. This includes a $19.2 million credit to electric customers and $1.3 million credit to natural gas customers. In addition to the one-time bill credit, the settlement also reduces rates for all natural gas customers by approximately $1.3 million annually beginning January 1, 2019. The MPSC voted 5-0 to approve the stipulation during a November 27, 2018 work session. NorthWestern previously disclosed a range of possible financial impacts related to the outcome of the TCJA and indicated that a portion of the settlements resolution may be excluded from 2018 adjusted non-GAAP earnings guidance. NorthWestern expects to exclude from 2018 earnings settlement impacts in excess of the 2018 reduction in income taxes. As a result of tax reform, we updated our 2018 effective tax rate assumption to 0% - 5% (8% - 12% prior to TCJA) and reduced our deferred tax liability by $321 million as of December 31, 2017. This reduction was offset in regulatory assets and liabilities. Net Operating Losses are now anticipated to be fully utilized in 2020 (previously 2021). We currently believe our debt coverage ratios will be adequate to maintain existing credit ratings. However, further negative regulatory actions could lead to credit downgrades and could necessitate additional equity issuances.
19 Montana Electric Rate Case Background • First general electric rate case in Montana since 2009. Mystic Dam Black Eagle Power House • While we have efficiently managed operating and administrative costs, increased Montana property taxes and significant investment in the system have compelled the request for rate relief. Filing (Docket D2018.2.12) • Filed with the MPSC in September 2018 based on 2017 test year and $2.34 billion of rate base. • Requesting $34.9 million annual increase to electric rates. This reflects a 6.6% increase to Montana electric revenues and a 7.4% increase to the typical residential bill. • 10.65% return on equity, 4.26% cost of debt, 49.4% equity and 7.42% return on rate base1 • Requested $13.8 million interim increase effective Nov. 1, 2018 (awaiting decision). • Requests the following additional items o Approval to capitalize Demand Side Management Costs o Establish a new baseline for PCCAM costs o Place Two Dot Wind project in rate base o Approval of new net metering customer class and rate for new residential private generation customers Timeline • January 18, 2019: Final day for NWE to respond to discovery • February 8, 2019: Final day for intervenor testimony • April 5, 2019: Final day for NWE rebuttal testimony & cross intervenor testimony • May 8, 2019: Final day for NWE and intervenors to file pre-hearing memoranda • May 13, 2019: Hearing commences 1. Except for Colstrip Unit 4 which has an lifetime ROR of 8.25% per D2008.6.69 (Order No. 6925f)
20 Experienced Leadership & Solid Corp. Governance Board of Directors (left to right) Linda G. Sullivan – Independent Director since April 27, 2017 – Audit Committee (Chair) Dana J. Dykhouse – Independent Director since January 30, 2009 – Human Resources (Chair) and Audit Committees Britt E. Ide – Independent Director since April 27, 2017 – Governance & Innovation Committee Jan R. Horsfall – Independent Director since April 23, 2015 – Audit and Governance & Innovation Committees Anthony T. Clark – Independent Director since December 6, 2016 – Governance & Innovation Committee Robert C. Rowe - CEO & President – Director since August 13, 2008 Dr. E. Linn Draper Jr. –Retired (April 2018) Chairman of the Board Julia L. Johnson – Independent Director since November 1, 2004 – Governance & Innovation (Chair) and Human Resources Committees Stephan P. Adik – Chairman of the Board - Independent Director since November 1, 2004 Executive Management Team (left to right) Crystal D. Lail – VP & Controller – current position since 2015 Curtis T. Pohl – VP Distribution – current position since 2003 Bobbi L. Schroeppel – VP Customer Care, Communications & Human Resources – current position since 2002 Brian B. Bird – CFO – current position since 2003 Heather H. Grahame – General Counsel and Vice President – Regulatory and Federal Government Affairs– current position since 2010 Robert C. Rowe - President & CEO – current position since 2008 John D. Hines – VP Supply – current position since 2011 Michael R. Cashell – VP Transmission – current position since 2011
21 Recent Significant Achievements Strong year for safety at NorthWestern • Continue to be a top performer among Edison Electric Institute member companies. Record best customer satisfaction scores with JD Power & Associates • Once again received our best JD Powers overall satisfaction survey score in 2017. Corporate Governance Finalist • In 2018 NorthWestern’s proxy statement was again (6 of last 7 years) recognized as a finalist for “Best Proxy Statement (Small to Mid Cap)” by Corporate Secretary Magazine. We won the award in 2014. Board Diversity Recognition • Recognized for gender diversity on its board of directors by 2020 Women on Boards. Three of the company’s eight independent directors are female. Second Annual Environmental Report • Published in December 2017, this report highlights our commitment to the stewardship of natural resources and our sustainable business practices. Echo Lake Nordic Trail Acquired Two Dot Wind Farm • June 2018 acquired 9.7 MW wind project, near Geyser, Montana, from NJR Clean Energy Ventures, for $18.5 million.
22 Looking Forward Regulatory • Review implications and next steps of final order issued on November 29, 2018 for Power Cost and Credit Adjustment Mechanism. • MPSC staff and commissioners to review Montana general electric rate review, filed in September 2018. Continue to Invest in our T&D infrastructure • Transition from DSIP/TSIP to overall infrastructure capital investment plan • Natural gas pipeline investment (Integrity Verification Much of our focus over the remainder of the year will Process and PHMSA1 Requirements) be on the electric rate review in Montana, controlling costs to benefit all stakeholders and • Grid modernization, advanced distribution management continuing to invest in our core business to provide system and advanced metering infrastructure investment safe and reliable energy for all of our customers. Electricity Resource Procurement Plan • Montana: Least cost / lowest risk approach to address intermittent capacity and reserve margin needs. Per MPSC direction, a draft ERPP is to be filed by March 15, 2019 followed by 60 day public comment period. The final report, to be published mid-2019, will address public comments. • South Dakota’s plan published September 2018, with implementation in process. Cost Control Efforts • Continue to monitor costs, including labor, benefits and property tax valuations to mitigate increases. 1 PHMSA: Pipeline and Hazardous Materials Safety Administration
23 Capital Investment Forecast $1.6 billion estimated cumulative 5 year capital investment. We anticipate funding the expenditures with a combination of cash flows (aided by NOLs available into 2020) and long-term debt issuances. Significant capital investments, that are not in the above projections, or further negative regulatory actions could necessitate additional equity issuances. Capital projections above do not include investment to address capacity issues as identified in the recently published South Dakota Electricity Supply Resource Procurement Plan nor the Montana plan to be released in 2019.
24 South Dakota Electric Supply Resource Plan NorthWestern and HDR EngineeringBlack Eagle Power House investigated various retirement & replacement scenarios to assess potential for modernizing its generation fleet and improve reliability and operational flexibility. The distributed generation fleet as shown in Scenario 5* (below) is the best solution to meet the Southwest Power Pool’s 12% planning reserve margin and benefit the system through: • Improved transmission reliability and lower system losses; • Improved restoration times; • Increased natural gas supply diversity; • Additional localized ancillary services; • Staged approach to incorporate new technologies, adjust to changing load centers and moderate customer rate impacts; and • Broadened tax base and multiple economic development opportunities across several communities. * Scenario 7 is a potential alternative as it is similar to Scenario 5 but spreads out retirement and replacements over a longer 10 year period. * Capacity solutions, including the scenarios on this page, will ultimately be subject to a competitive solicitation process to ensure least cost and lowest risk alternatives are procured. * Capital investment related to this resource plan is not included in our current 5 year capital estimates. It is anticipated a portion of this investment will be incorporated into our updated capital estimates that will be provided in February 2019.
25 South Dakota Electric Supply Resource Plan Scenario 5, or potentially Scenario 7 (investment Black Eagle Power House spread out over longer period), are the optimal choices in our SD Electric Resource Plan to pursue. We would retire older generating facilities and build Reciprocating Internal Combustion Engine Facilities (18 MW each) in five locations within our service territory starting in 2022. For more information go to http://www.northwesternenergy. com/docs/default- source/documents/investor/sd- 2018-plan.pdf * Capacity solutions, including the scenarios on this page, will ultimately be subject to a competitive solicitation process to ensure least cost and lowest risk alternatives are procured. * Capital investment related to this resource plan is not included in our current 5 year capital estimates. It is anticipated a portion of this investment will be incorporated into our updated capital estimates that will be provided in February 2019.
26 Montana Critical Capacity Shortfall NorthWestern’s current planning reserve margin is negative 28%. The 2015 Energy Resource Procurement Plan (ERPP) projected this to grow to negative 50% by 2035 without the addition of incremental owned or contracted portfolio resources. Per MPSC direction, a draft ERPP is to be filed by March 15, 2019 followed by 60 day public comment period. The final report, to be published mid-2019, will address public comments.
27 Conclusion Best Practices Corporate Governance Attractive Future Pure Electric Growth & Gas Utility Prospects Strong Solid Utility Earnings & Foundation Cash Flows
28
Appendix 29 Summary Financial Results (Third Quarter) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. See appendix for additional disclosure.
Appendix 30 Gross Margin (Third Quarter) (dollars in millions) Three Months Ended September 30, 2018 2017 Variance Electric $ 178.7 $ 183.5 ($ 4.8) (2.6%) Natural Gas 29.0 28.9 0.1 0.3% Total Gross Margin $ 207.7 $ 212.4 ($ 4.7) (2.2%) Decrease in gross margin due to the following factors: $ (3.2) Electric retail volumes (1.8) Power Cost and Credit Adjustment Mechanism (PCCAM) During the first quarter of 2018, we (0.2) Montana natural gas rates revised our presentation of revenues associated with being a market 1.2 Electric transmission participant in the Southwest Power Pool to net them with the associated cost of 0.4 Natural gas retail volumes sales. These revenues were previously recorded gross in electric revenues in the (0.3) Other Condensed Consolidated Statement of Income. This results in a decrease in $ (3.9) Change in Gross Margin Impacting Net Income electric revenue and a corresponding decrease in cost of sales. There was no $ (2.9) Tax Cuts and Jobs Act impact to operating or net income. We assessed the materiality of this change in (1.4) Production tax credits flowed-through trackers presentation, taking into account quantitative and qualitative factors, and 3.0 Property taxes recovered in trackers determined it to be immaterial. We applied the change in presentation 0.5 Operating expenses recovered in trackers prospectively only. $ (0.8) Change in Gross Margin Offset Within Net Income $ (4.7) Decrease in Gross Margin (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure See appendix for additional disclosure.
Appendix 31 Weather (Third Quarter) We estimate unfavorable weather in Q3 2018 resulted in a $1.1M pretax detriment as compared to normal and $1.5M pretax detriment as compared to Q3 2017.
Appendix 32 Operating Expenses (Third Quarter) (dollars in millions) Three Months Ended September 30, 2018 2017 Variance Operating, general & admin. $ 73.8 $ 67.7 $ 6.1 9.0% Property and other taxes 42.5 39.1 3.4 8.7% Depreciation and depletion 43.6 41.5 2.1 5.1% Operating Expenses $ 159.9 $ 148.3 $ 11.6 7.8% Increase in operating, general & admin expense due to the following factors: $ 1.2 Line clearance 0.2 Maintenance costs (1.0) Distribution System Infrastructure Project expense (1.0) Employee benefits (0.5) Labor 2.3 Other $ 1.2 Change in OG&A Items Impacting Net Income $ 2.6 Pension and other postretirement benefits 1.8 Non-employee directors deferred compensation 0.5 Operating expenses recovered in trackers $ 4.9 Change in OG&A Items Offset Within Net Income $ 6.1 Increase in Operating, General & Administrative Expenses $3.4 million increase in property and other taxes due primarily to plant additions and higher annual estimated property valuations in Montana. $2.1 million increase in depreciation and depletion expense primarily due to plant additions.
Appendix 33 Operating to Net Income (Third Quarter) (dollars in millions) Three Months Ended September 30, 2018 2017 Variance Operating Income $ 47.8 $ 64.1 $ (16.3) (25.4%) Interest Expense (22.0) (23.1) 1.1 4.8% Other Income / (Expense) 2.0 (1.8) 3.8 211.1% Income Before Taxes 27.8 39.2 (11.4) (29.1%) Income Tax Benefit / (Expense) 0.4 (2.8) 3.2 114.3% Net Income $ 28.2 $ 36.4 $ (8.2) (22.6%) $1.1 million decrease in interest expenses was primarily due to refinancing of debt in 2017, partly offset by rising interest rates. $3.8 million improvement in other income was due to a decrease in other pension expense and an increase in the value of deferred shares held in trust for non-employee directors deferred compensation, both of which are offset in operating, general, and administrative expenses with no impact to net income. These improvements were partly offset by lower capitalization of AFUDC. $3.2 million decrease in income tax expense due primarily to lower pre-tax income and lower 21% federal corporate tax rate in 2018 as compared to 35.0% in 2017.
Appendix 34 Income Tax Reconciliation (Third Quarter)
Appendix 35 Balance Sheet NorthWestern’s Ratio of debt to total capitalization decreased from 53.7% at 12/31/17 to 51.2% at 9/30/18.
Appendix 36 Cash Flow Cash from operating activities improved by $43 million primarily due to higher net income, improved customer receipts, the receipt of insurance proceeds and lower priced gas storage injections curing the current period.
Appendix 37 Adjusted Non-GAAP Earnings (Third Quarter) Three Months Ended Sept. 30th (1) During the first quarter of 2018, we revised our presentation of revenues associated with being a market participant in the Southwest Power Pool to net them with the associated cost of sales. These revenues were previously recorded gross in electric revenues in the Condensed Consolidated Statement of Income. This results in a decrease in electric revenue and a corresponding decrease in cost of sales. There was no impact to operating or net income. We assessed the materiality of this change in presentation, taking into account quantitative and qualitative factors, and determined it to be immaterial. We applied the change in presentation prospectively. (2) As a result of the adoption of Accounting Standard Update 2017- 07 in March 2018, pension and other employee benefit expense is now disaggregated on the 2017 and 2018 GAAP income statement with portions now recorded in both OG&A expense and Other (Expense) Income lines. To facilitate better understanding of trends in year-over- year comparisons, the non-GAAP adjustment illustrated re-aggregates the expense in OG&A - as it was The adjusted non-GAAP measures presented in the table above are being shown to reflect historically presented prior to the ASU 2017-07 (with no impact to net significant items that were not contemplated in our original guidance, however they income or earnings per share). should not be considered a substitute for financial results and measures determined or calculated in accordance with GAAP.
Appendix 38 Gross Margin (Nine Months Ended September 30) (dollars in millions) Nine Months Ended September 30, 2018 2017 Variance(1) Electric $ 549.9 $ 528.0 $ 21.9 4.1% Natural Gas 132.8 131.8 1.0 0.8% Total Gross Margin $ 682.7 $ 659.8 $ 22.9 3.5% Increase in gross margin due to the following factors: $ 25.1 Electric QF liability adjustment 4.1 Electric transmission 2.3 Natural gas retail volumes (1) Gross Margin, defined as revenues less cost of 2.0 Montana natural gas rates sales, is a non-GAAP 0.3 Electric retail volumes Measure. (1.8) PCCAM adjustment See appendix for 0.4 Other additional disclosure. $ 32.4 Change in Gross Margin Impacting Net Income $ (16.4) Tax Cuts and Jobs Act deferral (0.5) Production gathering fees (0.2) Production tax credits flowed-through trackers 7.1 Property taxes recovered in trackers 0.5 Operating expenses recovered in trackers $ (9.5) Change in Gross Margin Offset Within Net Income $ 22.9 Increase in Gross Margin
Appendix 39 Weather (Nine Months Ended September 30) We estimate favorable weather through the first 9 months of 2018 has contributed approximately $2.3M pretax benefit as compared to normal and $0.7M pretax benefit as compared to the same period in 2017.
Appendix 40 Operating Expenses (Nine Months Ended September 30) (dollars in millions) Nine Months Ended September 30, 2018 2017 Variance Operating, general & admin. $ 222.0 $ 218.6 $ 3.4 1.6% Property and other taxes 128.3 118.5 9.8 8.3% Depreciation and depletion 130.9 124.5 6.4 5.1% Operating Expenses $ 481.2 $ 461.6 $ 19.6 4.2% Increase in Operating, general & admin expense due to the following factors: $ (3.3) Maintenance costs (2.8) Labor (2.6) Distribution System Infrastructure Project expense 1.9 Employee benefits 1.2 Line clearance 1.1 Other $ (4.5) Change in OG&A Items Impacting Net Income $ 7.9 Pension and other postretirement benefits 0.5 Operating expense recovered in trackers (0.5) Natural gas production gathering expense $ 7.9 Change in OG&A Items Offset Within Net Income $ 3.4 Increase in Operating, General & Administrative Expenses $9.8 million increase in property and other taxes due primarily to plant additions and higher annual estimated property valuations in Montana. $6.4 million increase in depreciation and depletion expense primarily due to plant additions.
Appendix 41 Operating to Net Income (Nine Months Ended September 30) (dollars in millions) Nine Months Ended September 30, 2018 2017 Variance Operating Income $ 201.5 $ 198.2 $ 3.3 1.7% Interest Expense (68.2) (70.0) 1.8 2.6% Other Income / (Expense) 1.8 (3.4) 5.2 152.9% Income Before Taxes 135.1 124.8 10.3 8.3% Income Tax Expense (4.6) (10.0) 5.4 54.0% Net Income $ 130.5 $ 114.8 $ 15.7 13.7% $1.8 million decrease in interest expenses was primarily due to refinancing of debt in 2017, partly offset by rising interest rates. $5.2 million improvement in other income was due to a decrease in other pension expense partly offset by a decrease in the value of deferred shares held in trust for non- employee directors deferred compensation (both of which are offset in operating, general, and administrative expenses with no impact to net income) and lower capitalization of AFUDC. $5.4 million decrease in income tax expense due primarily to a lower statutory federal tax rate of 21.0% compared to 35.0% in 2017, partly offset by higher pre-tax income.
Appendix 42 Income Tax Reconciliation (Nine Months Ended September 30)
Appendix 43 Adjusted Non-GAAP Earnings (Nine Months Ended Sept. 30) (1) During the first quarter of 2018, we revised our presentation of revenues associated with being a market participant in the Southwest Power Pool to net them with the associated cost of sales. These revenues were previously recorded gross in electric revenues in the Condensed Consolidated Statement of Income. This results in a decrease in electric revenue and a corresponding decrease in cost of sales. There was no impact to operating or net income. We assessed the materiality of this change in presentation, taking into account quantitative and qualitative factors, and determined it to be immaterial. We applied the change in presentation prospectively. (2) As a result of the adoption of Accounting Standard Update 2017- 07 in March 2018, pension and other employee benefit expense is now disaggregated on the 2017 and 2018 GAAP income statement with portions now recorded in both OG&A expense and Other (Expense) Income lines. To facilitate better understanding of trends in year-over- year comparisons, the non-GAAP adjustment illustrated re-aggregates the expense in OG&A - as it was historically presented prior to the ASU 2017-07 (with no impact to net income or earnings per share). The adjusted non-GAAP measures presented in the table above are being shown to reflect significant items that were not contemplated in our original guidance, however they should not be considered a substitute for financial results and measures determined or calculated in accordance with GAAP.
Appendix 44 Qualified Facility Earnings Benefit The $25.1 million earnings improvement related to certain Qualified Facilities (QF) contracts in the 2nd quarter 2018 is a result of: • A $17.5 million benefit resulting from the reduction of the estimated future liability of unrecoverable QF costs. The primary driver of the reduction is due to price escalation of a certain variable rate contract that was lower than previously anticipated (when last evaluated in 2015). Due to the periodic nature of this estimated liability adjustment, this benefit has been excluded from non-GAAP earnings. • A $7.6 million benefit due to the annual adjustment to reflect lower actual output and pricing of QF related supply costs driven largely by outages at two QF facilities. Due to the annual nature of this adjustment to actual costs, this benefit was NOT excluded from non-GAAP earnings. Our electric QF liability consists of unrecoverable costs associated with contracts covered under PURPA that are part of a 2002 stipulation with the MPSC and other parties. Risks / losses associated with these contracts are born by shareholders, not customers. Therefore, any mitigation of prior losses and / or benefits of liability reduction also accrues to shareholders.
Appendix 45 Montana Natural Gas Rate Filing $430.2M Montana PSC Docket D2016.9.68 9.55% 4.47% 6.96% $5.1M Derivation of Rate Increase ($Millions) Revenue Request in Initial Application ..... $10.9 Property Tax (adjustment to actual) ….….. ($2.0) Income Tax correction and other misc. ..... 0.5 Rebuttal Revenue Request …………….. $9.4 1st Stipulation with MCC ROE Reduction (10.35% to 9.55%) ...... (2.6) Deprec. Reserve and other misc. …...... (0.2) 1st Stipulation Revenue Request …...... $6.6 2nd Stipulation with MCC / LCG A&G Concession ………………………. (0.8) 2nd Stipulation Revenue Request …...… $5.7 July 20, 2017 MPSC Work Session Remove A&G Concession ……………… 0.8 Accumulated depletion adjustment ……. (1.4) MPSC Settlement ………………..……..… $5.1* * Parties did not object to MPSC’s work session final order.
Appendix 46 NorthWestern Energy Profile Note: Data as reported in our 2017 10-K September 2018 Montana electric rate review, filed with rate base of $2.34 billion, calculated with 13th month average and known and measurable adjustments.
Appendix 47 2017 System Statistics (1) (3) (2) Note: Statistics above are as of 12/31/2017 except for Electric Transmission for Others (1) Nebraska is a natural gas only jurisdiction (2) Dave Gates Generating Station (DGGS) in Montana is a 150 MW nameplate facility but consider it a 105 MW (60 MW FERC & 45MW MPSC jurisdictions) peaker (3) Does not include 9 MW Two Dot wind project in Montana acquired in June 2018
Appendix 48 Our Commissioners Randy Pinocci (R) defeated Doug Kaercher (D) for District 1 representative (held by Vice- Chairman Travis Kavulla who reached term limits). Brad Johnson (R) was re-elected in District 5 over Andy Shirtliff (D). This is Chairman Johnson’s 2nd – 4 year term on the PSC. Kristie Fiegen (R) was re-elected over Wayne Frederick (D). This is Chairperson Fiegen’s 2nd – 6 year term on the PUC. Dan Watermeier (R) defeated Christa Yoakum (D) for District 1 representative (held by Frank Landis who did not seek re-election). Tim Schram (R) was re-elected in District 3 over Mike Forsythe (D). This is commissioner Schram’s 3rd – 6 year term on the PSC.
Appendix 49 Non-GAAP Financial Measures (1 of 3) These materials include financial information prepared in accordance with GAAP, as well as other financial measures, such as Gross Margin and Adjusted Diluted EPS, that are considered “non-GAAP financial measures.” 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) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. 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. Adjusted Diluted EPS is another non-GAAP measure. The Company believes the presentation of Adjusted Diluted EPS is more representative of our normal earnings than the GAAP EPS due to the exclusion (or inclusion) of certain impacts that are not reflective of ongoing earnings. The presentation of these non-GAAP measures is intended to supplement investors' understanding of our financial performance and not to replace other GAAP measures as an indicator of actual operating performance. Our measures may not be comparable to other companies' similarly titled measures.
Appendix 50 Non-GAAP Financial Measures (2 of 3) Disclaimer on Net Operating Net Operating Losses (NOL’s): The expected tax rate and the expected availability of NOLs are subject to significant business, economic, regulatory and competitive uncertainties and contingencies, many of which are beyond the control of the Company and its management, and are based upon assumptions with respect to future decisions, which are subject to change. Actual results will vary and those variations may be material. For discussion of some of the important factors that could cause these variations, please consult the “Risk Factors” section of our most recent 10-K filed with the SEC.
Appendix 51 Non-GAAP Financial Measures (3 of 3) The data presented in this presentation includes financial information prepared in accordance with GAAP, as well as other Non-GAAP financial measures such as Gross Margin (Revenues less Cost of Sales), Free Cash Flows (Cash flows from operations less maintenance capex and dividends) and Net Debt (Total debt less capital leases), that are considered “Non-GAAP financial measures.” 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. The presentation of Gross Margin, Free Cash Flows and Net Debt 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 and Net Debt measures may not be comparable to other companies’ similarly labeled measures. Furthermore, these measures are not intended to replace measures as determined in accordance with GAAP as an indicator of operating performance.
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