2018 Third Quarter Earnings Webcast October 24, 2018
Presenting Today 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 Bob Rowe, statements often address our expected future business President & CEO 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 of this document 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 Brian Bird, assumptions, actual results may differ materially. The Vice President & CFO factors that may affect our results are listed in certain of our press releases and disclosed in the Company’s 10-K and 10-Q along with other public filings with the SEC. 2
Third Quarter Highlights • Net income for the quarter decreased $8.2 million, Beethoven Wind Farm, near Tripp, SD or 22.6%, as compared to the same period in 2017. This decrease was primarily due to unfavorable weather, reduced recovery of energy supply costs and increased operating expenses. These increases were partially offset by lower interest and income tax expense. • Diluted earnings per share decreased $0.19, or 25.3%, as compared to the same period in 2017. • Adjusted Non-GAAP* earnings per share decreased $0.16, or 21.6%, as compared to the same period in 2017. • We filed an electric general rate review with the Montana Public Service Commission at the end of September. We are requesting a $34.9 million, or 6.6% annual increase to base revenues. • The Board of Directors declared a quarterly dividend of $0.55 per share payable December 31st to shareholders of record as of December 14th, 2018. * See slides 12, 32 & 37 for additional information and Non-GAAP disclosures. 3
Summary Financial Results (Third Quarter) (1) 4 (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure See appendix for additional disclosure.
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 (1) $ 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) (0.2) Montana natural gas rates 1.2 Electric transmission 0.4 Natural gas retail volumes (0.3) Other $ (3.9) Change in Gross Margin Impacting Net Income $ (2.9) Tax Cuts and Jobs Act (1.4) Production tax credits flowed-through trackers 3.0 Property taxes recovered in trackers 0.5 Operating expenses recovered in trackers $ (0.8) Change in Gross Margin Offset Within Net Income $ (4.7) Decrease in Gross Margin 5 (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure See appendix for additional disclosure.
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. 6
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 7 due to plant additions.
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. 8
Income Tax Reconciliation (Third Quarter) 9
Balance Sheet 10
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. 11
Adjusted Non-GAAP Earnings (Third Quarter) (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 - The adjusted non-GAAP measures presented in the table above are being shown to reflect as it was historically presented significant items that were not contemplated in our original guidance, however they should prior to the ASU 2017-07 (with no not be considered a substitute for financial results and measures determined or calculated impact to net income or earnings 12 per share). in accordance with GAAP.
2018 Earnings Guidance $3.30$3.30-$3.45-$3.50 $3.10 - $3.30 $2.60$3.20 - $2.75-$3.40 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; • Equitable regulatory treatment in the process of passing Tax Cuts and Jobs Act benefits on to customers; • 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 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 See appendixcapacity for additional shortfall disclosures could regardingallow us “Non to- GAAPachieve Financial the higherMeasures-end” of our range over the long term. 13 See “Non-GAAP Financial Measures” slide in appendix for “Non-GAAP “Adjusted EPS”.
Maintaining Full Year Non-GAAP Guidance In order to meet 2018 guidance,$3.30$3.30-$3.45-$3.50 we will $3.10 - $3.30 need$2.60 to$3.20 - $2.75 deliver-$3.40 EPS 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. 14 See “Non-GAAP Financial Measures” slide in appendix for “Non-GAAP “Adjusted EPS”.
Looking Forward Regulatory Black Eagle Power House • Regulatory treatment of tax reform - determine best way to provide long-term benefit to customers and system $3.30$3.30-$3.45-$3.50 $3.10 - $3.30 while keeping investors whole. $2.60$3.20 - $2.75-$3.40 • MPSC has voted on new Power Cost and Credit Adjustment Mechanism, but final order not yet issued. • 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 Much of our focus over the remainder of the year will capital investment plan be on the electric rate review in Montana, • Natural gas pipeline investment (Integrity Verification controlling costs to benefit all stakeholders and Process and PHMSA1 Requirements) continuing to invest in our core business to provide safe and reliable energy for all of our customers. • Grid modernization, advanced distribution management system and advanced metering infrastructure investment Update Electricity Resource Procurement Plan in Montana • Montana: Least cost / lowest risk approach to address intermittent capacity and reserve margin needs. • 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. Pipeline & Hazardous Materials Safety Administration (PHMSA) 15
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 September 2018, the MPSC held a work session and 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 expect a final order to be issued during the fourth quarter of 2018 and 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. 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. 16
Estimated Impacts of the Tax Cuts & Jobs Act South Dakota – In September 2018, the South Dakota Public Utility Commission 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 customers rates remain static until January 1, 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 alternative methods. • The Current Method was calculated based on the expected tax expense reduction in 2018, with no impact to net income. • The Historic Method was calculated by revising the revenue requirements in the last applicable test years. • For our electric customers, we proposed to use 50% of the benefit as a direct refund to customers, and to use the other 50% to remove trees outside our electric transmission and distribution lines rights of way, which pose risks to our system including disruption of service, property damage, and/or forest fires. We have begun work to remove trees outside our right of way. As of September 30, 2018, have deferred $0.7 million of tree removal costs and have deferred $13.3 million of revenue. • The MPSC held a hearing in August 2018 and expect a decision in the matter by the end of 2018. The expected full year 2018 total company revenue reduction for the Current Method is $18-$23 million ($3M for South Dakota plus $15-20M for the Montana current method) which would be offset by a nearly equal reduction in income tax expense and have no impact to net income. Application of the Historic Method in Montana would result in customer refunds that exceed the expected benefit of TCJA and would result in an additional reduction in pretax earnings and cash flow of approximately $5-$10 million. As a result of tax reform, we have 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. 17
South Dakota Electric Supply Resource Plan NorthWestern and HDR Engineering 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. For more information go to www.northwesternenergy.co m/our company/regulatory * Capital investment related to this resource plan is not included in our current 5 year capital estimates. It is anticipated a portion of this environment/learn more 18 investment will be incorporated into our updated capital estimates that will be provided in February 2019.
Montana Electric Rate Case Background • First general electric rate case in Montana since 2009. Mystic Dam • 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. • Requests the following additional items • Approval to capitalize Demand Side Management Costs • Establish a new baseline for PCCAM costs • Place Two Dot Wind in rate base • Approval of new net metering customer class and rate for new residential private generation customers Timeline • We expect a decision on interim rates by the end of 2018. • If the MPSC does not issue an order within nine months of our filing, new rates may be placed into effect on an interim and refundable basis. • A procedural schedule has not yet been issued. 19 1. Except for Colstrip Unit 4 which has an lifetime ROR of 8.25% per D2008.6.69 (Order No. 6925f)
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 expected to be released in the fourth quarter 2018. 20
Conclusion Best Practices Corporate Governance Attractive Future Pure Electric Growth & Gas Utility Prospects Strong Solid Utility Earnings & Foundation Cash Flows 21
Appendix 22
Appendix Segment Results (Third Quarter) (1) (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. 23 See appendix for additional disclosure.
Appendix Electric Segment (Third Quarter) (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. 24 See appendix for additional disclosure.
Appendix Natural Gas Segment (Third Quarter) (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. 25 See appendix for additional disclosure.
Appendix Summary Financial Results (Nine Months Ended September 30) (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. 26 See appendix for additional disclosure.
Appendix 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 27
Appendix 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. 28
Appendix 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 29 due to plant additions.
Appendix 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. 30
Appendix Income Tax Reconciliation (Nine Months Ended September 30) 31
Appendix Adjusted Non-GAAP Earnings (Nine Months Ended September 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 32 determined or calculated in accordance with GAAP.
Appendix Segment Results (Nine Months Ended September 30) (1) (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. 33 See appendix for additional disclosure.
Appendix Electric Segment (Nine Months Ended September 30) (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. 34 See appendix for additional disclosure.
Appendix Natural Gas Segment (Nine Months Ended September 30) (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. 35 See appendix for additional disclosure.
Appendix Qualified Facility Earnings Benefit The $25.1 million earnings improvement, recorded in the 2nd quarter of 2018, related to certain Qualified Facilities (QF) contracts 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 that was lower than the three percent assumption in the liability, which was also adjusted 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 has NOT been 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 accrue to shareholders. 36
Appendix Non-GAAP Financial Measures 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 37 measures.
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