2022 Third Quarter Earnings Webcast October 25, 2022 Rainbow Dam, MT
Presenting Today 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 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 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 10-K and 10-Q along with other public filings with the SEC. Bob Rowe CEO Crystal Lail Vice President & CFO Brian Bird President & COO
Financial results below expectations for the quarter… • Net income of $27.4 million or $0.47 diluted earnings per share • Non-GAAP EPS of $24.3 or $0.42 diluted earning per share • Expected long-term annual EPS growth rate of 3% - 6% off 2020 base(1) Montana rate review filed on August 8th … • Interim rates approved in September and effective October 1st to help mitigate the significant regulatory lag and the under-recovery of purchased power costs that are pressuring credit metrics South Dakota Integrated Resource Plan filed on September 6th… $582 million capital plan for 2022 remains on track… Ongoing Dividend Commitment… • Quarterly dividend of $0.63 per share payable December 30, 2022 (12/15/22 record date) Recent Highlights 3 (1) 2020 Diluted Non-GAAP EPS of $3.35
Summary Financial Results 4 (1) (Third Quarter) (1) Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure.
EPS Bridge to Third Quarter 2022 5 We estimate favorable weather in the third quarter 2022 resulted in a $4.2 million pretax benefit as compared to normal and a $0.8 million benefit as compared to third quarter 2021. See slide 7 and “Non-GAAP Financial Measures” slide in the appendix for additional detail on this measure. After-tax Earnings Per Share
Utility Margin Bridge to Q3 2022 6 $3.2 Million (1.4%) decrease in Utility Margin due to items that impact Net Income. NOTE: Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure. Pre-tax Millions
Q3 2022 GAAP to Non-GAAP Earnings 7 The adjusted non-GAAP measures presented in the table are being shown to reflect significant items that are non- recurring or a variance from normal weather, however they should not be considered a substitute for financial results and measures determined or calculated in accordance with GAAP. (1) 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 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 above 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). (2) Utility Margin is a non-GAAP Measure See the slide titled “Explaining Utility Margin” for additional disclosure. (in millions) Three Months Ended Sept. 30, 2022 F a v o ra b le W e a th e r M o v e P e n s io n E x p e n s e t o O G & A ( d is a g g re g a te d w it h A S U 2 0 1 7 -0 7 ) N o n -e m p lo y e e D e fe rr e d C o m p e n s a ti o n Three Months Ended Sept. 30, 2022 Three Months Ended Sept. 30, 2021 Q F L ia b il it y - a d ju s tm e n t a s s o c ia te d w it h o n e - ti m e c la ri fi c a ti o n o f c o n tr a c t te rm N o n -e m p lo y e e D e fe rr e d C o m p e n s a ti o n M o v e P e n s io n E x p e n s e t o O G & A (d is a g g re g a te d w it h A S U 2 0 1 7 -0 7 ) F a v o ra b le W e a th e r Three Months Ended Sept. 30, 2021 Revenues $335.1 (4.2) $330.9 $7.0 2.2% $323.9 1.3 (3.4) $326.0 Fuel, supply & dir. tx 109.0 109.0 10.3 10.4% 98.7 98.7 Utility Margin 226.1 (4.2) - - 221.9 (3.3) -1.5% 225.2 1.3 - - (3.4) 227.3 Op. Expenses OG&A Expense 82.8 (1.7) 0.6 81.7 1.8 2.3% 79.9 0.1 (1.1) 80.9 Prop. & other taxes 46.5 46.5 2.9 6.7% 43.6 43.6 Depreciation 48.6 48.6 1.5 3.2% 47.1 47.1 Total Op. Exp. 177.9 - (1.7) 0.6 176.8 6.2 3.6% 170.6 - 0.1 (1.1) - 171.6 Op. Income 48.2 (4.2) 1.7 (0.6) 45.1 (9.5) -17.4% 54.6 1.3 (0.1) 1.1 (3.4) 55.7 Interest expense (25.3) (25.3) (2.0) -8.6% (23.3) (23.3) Other (Exp.) Inc., net 4.2 (1.7) 0.6 3.1 (1.2) -27.9% 4.3 0.1 (1.1) 5.3 Pretax Income 27.1 (4.2) - - 22.9 (12.7) -35.7% 35.6 1.3 - - (3.4) 37.7 Income tax 0.3 1.1 - - 1.4 3.4 172.7% (2.0) (0.3) - - 0.9 (2.5) Net Income $27.4 (3.1) - - $24.3 ($9.3) -27.7% $33.6 1.0 - - (2.5) $35.2 ETR -0.9% 25.3% - - -6.0% 5.5% 25.3% - - 25.3% 6.6% Diluted Shares 56.6 56.6 4.6 8.8% 52.0 52.0 Diluted EPS $0.47 (0.05) - - $0.42 ($0.23) -35.4% $0.65 0.02 - - (0.05) $0.68 Variance $ % (1) 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 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 above 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). (2) Utility Margin is a non-GAAP Measure See the slide titled “Explaining Utility Margin” for additional disclosure. Three Months Ended September 30, GAAP Non GAAP Non-GAAP Variance Non GAAP GAAP (1) (2) (1) Non-GAAP AdjustmentsNon-GAAP Adjustments
Cash Flow 8 (YTD thru 9/30) Cash from Operating Activities increased by $87.7 million primarily due to: • $76.5 million increase in collection of energy supply costs from customers, which includes costs incurred during a February 2021 prolonged cold weather event, and the under-collected position of Montana’s PCCAM for the July 2020 – June 2021 period; and Funds from Operations decreased by $15.6 million primarily due to lower net income. Under-collected Supply Costs (in millions) Beginning (Jan. 1) Ending (Sep. 30) Outflow 2021 $3.9 $84.5 ($80.6) 2022 $97.8 $101.9 ($4.1) 2022 Improvement (less outflow) $76.5
Narrowing 2022 Earnings Guidance NorthWestern adjusts 2022 earnings guidance range to $3.20 to $3.35 (previously $3.20 to $3.40) per diluted share based upon, but not limited to, the following major assumptions and expectations: • Normal weather in our electric and natural gas service territories; • Inclusion of electric & natural gas interim rates effective October 1, 2022 as granted by the MPSC (subject to refund) • A consolidated income tax rate of approximately 0% to 3% of pre-tax income; and • Diluted shares outstanding of approximately 55.8 million to 56.4 million (previously 55.6 million to 56.2 million). • Dividend payout ratio is expected to exceed 60%-70% targeted range for 2022. • We continue to target a long-term earnings per share growth rate of 3%-6% off a 2020 base year. • NorthWestern expects to issue 2023 earnings guidance and update our 5 year capital projections following an outcome in our Montana electric and natural gas rate review. Note: See “Detailed 2022 Earnings Bridge” slide in the Appendix for additional information.9
Capital Investment Forecast and Funding 10 NorthWestern’s $582 million Capital Plan for 2022 remains on track… $2.4 billion of low-risk capital investment forecasted over the next five years to address generation capacity, grid modernization and renewable energy integration. This sustainable level of capex is expected to drive annualized rate base growth of approximately 4%-5%. We expect to finance this capital with a combination of cash flows from operations, first mortgage bonds and equity issuances. Financing plans are subject to change and balance our intention to protect our current credit ratings. (targeting a 14%-15% FFO to Debt ratio) $1.7 Billion investment over last 5 years
Montana Rate Review 11 Requested base rate increase supports over a billion dollars invested in Montana critical infrastructure, while keeping operating costs below the rate of inflation, since our last rate reviews. (Test years: 2015 natural gas and 2017 electric) Approximately 42% of the requested total electric and natural gas revenue increase is driven by flow-through costs including market power purchases and property taxes. With the requested rate relief, including the substantial flow- through costs, our total customer bill increases are in line with inflation.
MT Rate Review – Interim Rates / Procedural Schedule 12 September 28th, the MPSC approved the recommendations of the staff for interim rates, subject to refund, which increased rates by the following: • Base electric rates $29.4 million • PCCAM rates $61.1 million • Base natural gas rates $1.7 million Final rates, once approved, will be retroactive back to interim effective date. Interim Rates effective October 1, 2022 Procedural Schedule Key dates are currently expected: 12-19-22: Intervenor testimony 03-06-23: NorthWestern rebuttal testimony and cross- intervenor testimony 04-03-23: Hearing commences
175 megawatt Yellowstone County generating project in Montana… • Construction began in April 2022 • Construction costs of approximately $275 million with $98.1 million invested to date • Current schedule anticipates commercial operation during 2024 Electric Supply Resource Plans South Dakota • Filed an updated integrated resource plan in September 2022 • Plan identifies 43 megawatts as retire and replace candidates with potential for competitive solicitation during 2023-2024 Looking Forward 13 The recently completed 58-megawatt Bob Glanzer Generating Station in Huron, South Dakota, provides on-demand resources to support the variability of wind and solar projects coming onto our system and the grid in our region and help serve our customers during extended periods of peak demand. Montana • Expect to submit an integrated resource plan to the MPSC by the end of 2022 followed by an all-source competitive solicitation request for capacity available in 2026.
14 Years of Extraordinary Leadership 14 During Rowe’s tenure, NorthWestern Energy has: o Increased the critical energy infrastructure dedicated to serve our customers from $2.5 billion in 2008 to more than $7 billion in 2022, and more than tripled the company’s value. o Acquired or developed energy supply resources with long-term value, notably the 456 megawatt Montana hydro system, the 150 megawatt Dave Gates Generating Station in Montana, the 80 megawatt Aberdeen Generating Units in South Dakota, 131 megawatt of owned wind generation in Montana and South Dakota and recently, the 58 megawatt Bob Glanzer Generating Station in Huron, S.D. o Invested more than a billion dollars in clean energy resources. The hydro system, along with owned and contracted wind and other resources, positions NorthWestern Energy so that approximately 60 percent of the electricity provided to our customers in Montana and South Dakota is from carbon-free resources. o Invested $1.1 billion in infrastructure to modernize and increase the reliability and flexibility of our energy delivery system, and supported the deployment of technology throughout the company. o Reduced customers’ exposure to the volatile regional energy markets by buying or building generation resources dedicated to serve our customers at prices based on the cost of production. Rowe emphasizes that, “In Montana especially, this is critical unfinished work.” o Partnered with the communities we serve on economic development and to meet customer and community needs. o Helped build a company culture dedicated to service and safety.
14 Years of Extraordinary Leadership 15 “Bob Rowe is passionate about NorthWestern Energy’s culture, built on collaborative interaction, mentorship and fellowship. Our outstanding employee group, demonstrating a commitment to safety, commitment to our customers, commitment to our environment, and commitment to our communities is a testament to Bob’s relentless focus on promoting and supporting that culture. Bob’s vision of this company’s role in a rapidly changing energy future has successfully achieved the balance critical to our successes today, tomorrow and for years into the future. Brian is a respected industry financial leader with an excellent understanding of NorthWestern Energy’s operations. He has been instrumental in guiding the company to today’s solid financial footing.” Dana Dykhouse Chairman of the Board NorthWestern Energy
Conclusion 16 Pure Electric & Gas Utility Solid Utility Foundation Best Practices Corporate Governance Attractive Future Growth Prospects Strong Earnings & Cash Flows
17 Appendix
Our Net-Zero Vision 18 Over the past 100 years, NorthWestern Energy has maintained our commitment to provide customers with reliable and affordable electric and natural gas service while also being good stewards of the environment. We have responded to climate change, its implications and risks, by increasing our environmental sustainability efforts and our access to clean energy resources. But more must be done. We are committed to achieving net zero emissions by 2050. • Committed to achieving net-zero by 2050 for Scope 1 and 2 emissions • Must balance Affordability, Reliability and Sustainability in this transition • No new carbon emitting generation additions after 2035 • Pipeline modernization, enhanced leak detection and development of alternative fuels for natural gas business • Electrify fleet and add charging infrastructure • Carbon offsets likely needed to ultimately achieve net-zero • Please visit www.NorthWesternEnergy.com/NetZero to learn more about our Net Zero Vision. Appendix
Decrease in utility margin due to the following factors: $ (4.7) Lower transmission revenue (1.3) Higher non-recoverable Montana electric supply costs (0.6) Lower natural gas retail volumes 2.1 Higher electric retail volumes 1.3 Prior year unfavorable electric QF liability adjustment $ (3.2) Change in Utility Margin Items Impacting Net Income 19 Utility Margin (Third Quarter) (dollars in millions) Three Months Ended September 30, 2022 2021 Variance Electric $ 196.7 $ 198.1 $ (1.4) (0.7%) Natural Gas 29.4 29.2 0.2 0.7% Total Utility Margin $ 226.1 $ 227.3 $ (1.2) (0.5%) $ 2.2 Higher property taxes recovered in revenue, offset in property tax expense (0.4) (0.1) Lower revenue from higher production tax credits, offset in income tax expense (0.1) Lower operating expenses recovered in revenue, offset in O&M expense $ 2.0 Change in Utility Margin Offset Within Net Income $ (1.2) Decrease in Utility Margin (1) Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure. (1) Appendix
Increase in operating expenses due to the following factors: $ 1.5 Higher depreciation expense due to plant additions 0.7 Higher property tax expense due to a decrease in the estimated state and local taxes 0.5 Increase in uncollectible accounts (due to prior year collection of previously written off balances) 0.4 Higher line clearance expenses 0.4 Higher litigation expenses 0.4 Higher travel expenses (1.2) Prior year write-off of preliminary construction costs (0.6) Lower labor and benefits (1) (0.3) Lower technology implementation and maintenance expense 2.3 Other miscellaneous $ 4.1 Change in Operating Expense Items Impacting Net Income Operating Expenses 20 (Third Quarter) (dollars in millions) Three Months Ended September 30, 2022 2021 Variance Operating & maintenance $ 54.7 $ 56.0 ($ 1.3) (2.3%) Administrative & general 28.1 24.9 3.2 12.9% Property and other taxes 46.5 43.6 2.9 6.7% Depreciation and depletion 48.6 47.1 1.5 3.2% Operating Expenses $ 177.9 $ 171.6 $ 6.3 3.7% $ 2.2 Higher property and other taxes recovered in trackers, offset in revenue 0.6 Higher pension and other postretirement benefits, offset in other income (0.5) Lower non-employee directors deferred compensation, offset in other income (0.1) Lower operating and maintenance expenses recovered in trackers, offset in revenue $ 2.2 Change in Operating Expense Items Offset Within Net Income $ 6.3 Increase in Operating Expenses $1.9 Appendix (1) We have included the change in the non- service cost component of our pension and other postretirement benefits, which is recorded within other income on our Condensed Consolidated Statements of Income, within the labor and benefits amount above in order to present the total change in labor benefits expenses. This change is offset below within this table as it does not affect our operating expenses.
Operating to Net Income 21 (dollars in millions) Three Months Ended September 30, 2022 2021 Variance Operating Income $ 48.2 $ 55.7 $ (7.5) (13.5%) Interest expense (25.3) (23.3) (2.0) (8.6%) Other income, net 4.2 5.3 (1.1) (20.8%) Income Before Taxes 27.1 37.7 (10.6) (28.1%) Income tax benefit (expense) 0.3 (2.5) 2.8 (112.0%) Net Income $ 27.4 $ 35.2 $ (7.8) (22.3%) (Third Quarter) $2.0 million increase in interest expenses was primarily due to higher interest on borrowings under our revolving credit facilities, partly offset by higher capitalization of AFUDC. $1.1 million decrease in other income was primarily due to a decrease in the value of deferred shares held in trust for non-employee directors deferred compensation, partly offset by a decrease in the non-service costs component of pension expense. $2.8 million Income tax improvement was primarily due to lower pre-tax income. Appendix
Tax Reconciliation 22 Appendix (Third Quarter)
EPS Range to Meet Guidance 23 The adjusted non- GAAP measures presented in the table are being shown to reflect significant items that are non- recurring or a variance from normal weather, however they should not be considered a substitute for financial results and measures determined or calculated in accordance with GAAP. Appendix
2022 YTD GAAP to Non-GAAP Earnings 24 The adjusted non-GAAP measures presented in the table are being shown to reflect significant items that are non- recurring or a variance from normal weather, however they should not be considered a substitute for financial results and measures determined or calculated in accordance with GAAP. (1) 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 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 above 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). (2) Utility Margin is a non-GAAP Measure See the slide titled “Explaining Utility Margin” for additional disclosure. Appendix
Weather / Hydro Conditions 25 Stream flows in the basins that house our hydro dams are at normal or below normal and in a few cases much below the 30- year medians. (Missouri, Madison & Clark Fork Rivers and West Rosebud Creek basins) We estimated a $4.2 million pre-tax benefit as compared to normal and a $0.8 million benefit as compared to Q3 2021 with a higher temps from July-September. Appendix
Quarterly PCCAM Impacts 26 Appendix In 2017, the Montana legislature revised the statute regarding our recovery of electric supply costs. In response, the MPSC approved a new design for our electric tracker in 2018, effective July 1, 2017. The revised electric tracker, or PCCAM established a baseline of power supply costs and tracks the differences between the actual costs and revenues. Variances in supply costs above or below the baseline are allocated 90% to customers and 10% to shareholders, with an annual adjustment. From July 2017 to May 2019, the PCCAM also included a "deadband" which required us to absorb the variances within +/- $4.1 million from the base, with 90% of the variance above or below the deadband collected from or refunded to customers. In 2019, the Montana legislature revised the statute effective May 7, 2019, prohibiting a deadband, allowing 100% recovery of QF purchases, and maintaining the 90% / 10% sharing ratio for other purchases. Pre-tax Millions
Qualified Facility Earnings Adjustment 27 Appendix 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.
Balance Sheet 28 Debt to Total Capitalization down from last year and remains within our targeted 50% - 55% range. Appendix
29 Segment ResultsAppendix (1) (1) (Third Quarter) (1) Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure.
30 Electric SegmentAppendix (1) (Third Quarter) (1) Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure.
31 Natural Gas SegmentAppendix (1) (Third Quarter) (1) Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure.
Decrease in utility margin due to the following factors: $ (5.6) Lower transmission revenue (lower demand from market conditions & lower pricing) (2.8) Less favorable electric QF liability adjustment (1.6) Higher non-recoverable Montana electric supply costs (0.8) Lower Montana natural gas production asset rates (annual step down) 5.6 Higher electric retail volumes 2.3 Higher natural gas retail volumes 0.6 Other $ (2.3) Change in Utility Margin Impacting Net Income 32 Utility Margin (YTD Through 9/30) (dollars in millions) Nine Months Ended September 30, 2022 2021 Variance Electric $ 576.5 $ 580.2 ($ 3.7) (0.6%) Natural Gas 137.1 133.7 3.4 2.5% Total Utility Margin $ 713.6 $ 713.9 ($ 0.3) 0.0% $ 2.0 Higher operating expenses recovered in revenue, offset in O&M expense 1.9 Higher property taxes recovered in revenue, offset in property tax expense 0.3 Higher gas production taxes recovered in revenue, offset in property & other taxes (2.2) Lower revenue from higher production tax credits, offset in income tax expense $ 2.0 Change in Utility Margin Offset Within Net Income $ (0.3) Decrease in Utility Margin (1) Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure. (1) Appendix
Increase in operating expenses due to the following factors: $ 4.8 Higher depreciation due to plant additions 2.2 Increase in uncollectible accounts (due to prior year collection of previously written off balances) 1.8 Higher insurance expense 1.5 Higher technology implementation and maintenance expense 1.1 Higher travel expenses 0.8 Higher line clearing expense 0.8 Higher litigation 0.2 Higher labor and benefits (1) (1.2) Prior year write-off of preliminary construction costs (0.4) Lower expenses at our electric generation facilities 1.2 Other miscellaneous $ 12.8 Change in Operating Expense Items Impacting Net Income Operating Expenses 33 (YTD Through 9/30) (dollars in millions) Nine Months Ended September 30, 2022 2021 Variance Operating & maintenance $ 160.8 $ 159.3 $ 1.5 0.9% Administrative & general 87.0 79.6 7.4 9.3% Property and other taxes 140.2 138.3 1.9 1.4% Depreciation and depletion 145.7 140.9 4.8 3.4% Operating Expenses $ 533.7 $ 518.1 $ 15.6 3.0% $ 2.0 Higher operating and maintenance expenses recovered in trackers, offset in revenue 1.9 Higher property and other taxes recovered in trackers, offset in revenue 0.8 Higher pension and other postretirement benefits, offset in other income (1.9) Lower non-employee directors deferred compensation, offset in other income $ 2.8 Change in Operating Expense Items Offset Within Net Income $ 15.6 Increase in Operating Expenses $8.9 Appendix (1) We have included the change in the non- service cost component of our pension and other postretirement benefits, which is recorded within other income on our Condensed Consolidated Statements of Income, within the labor and benefits amount above in order to present the total change in labor benefits expenses. This change is offset below within this table as it does not affect our operating expenses.
Operating to Net Income 34 (dollars in millions) Nine Months Ended September 30, 2022 2021 Variance Operating Income $ 179.9 $ 195.7 $ (15.8) (8.1%) Interest expense (73.1) (70.3) (2.8) (4.0%) Other income, net 11.8 13.9 (2.1) (15.1%) Income Before Taxes 118.6 139.4 (20.8) (14.9%) Income tax expense (2.3) (3.9) 1.6 (41.0%) Net Income $ 116.3 $ 135.5 $ (19.2) (14.2%) (YTD Through 9/30) $2.8 million increase in interest expenses was primarily due to higher interest on borrowings under our revolving credit facilities, partly offset by higher capitalization of AFUDC. $2.1 million decrease in other income primarily due to a CREP penalty of $2.5 million, which relates to litigation we have been involved in associated with our past progress towards meeting obligations to acquire renewable energy projects as mandated by the recently repealed Montana CREP requirement, and a decrease in the value of deferred shares held in trust for non-employee directors deferred compensation. These unfavorable items are partly offset by a decrease in the non-service cost component of pension expense and higher capitalization of AFUDC. $1.6 million decrease in income tax expense was primarily due lower pretax income offset by lower permanent and flow-through deductions. Appendix
Tax Reconciliation 35 Appendix (YTD Through 9/30)
36 Segment ResultsAppendix (1) (1) (YTD Through 9/30) (1) Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure.
37 Electric SegmentAppendix (1) (YTD Through 9/30) (1) Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure.
38 Natural Gas SegmentAppendix (1) (YTD Through 9/30) (1) Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure.
De-risking the Montana Capacity Deficit NorthWestern has made significant progress to de-risk the capacity deficit between now and 2025. These near term capacity solutions allow time for clarity on Colstrip arbitration, further development in the western markets, and ongoing technological advances. We expect to submit an updated integrated resource plan by the end of 2022 or early 2023*, followed by an all-source competitive solicitation request for capacity available in 2026. * Due to the significant impact of our ownership in Colstrip Unit 4 to the capacity available in our portfolio, the outcome in the arbitration amongst the co- owners may affect the timing of the submission of this plan. 39 Appendix
Alternative Capacity Considerations 40 We expect to build the 175MW nameplate Yellowstone County Reciprocating Internal Combustion Engine (RICE) generation facility for approximately $275 million with capacity generation output of roughly 160 MW*. If we were to build wind or solar to provide the equivalent 160 MW of capacity, we estimate a range of roughly $2.1 billion to $4.1 billion in capital costs – roughly 8 to 15 times our RICE units investment. * Natural gas Reciprocating Internal Combustion Engine (RICE) facility capacity credit of 96.5% is further adjusted for altitude levels at our Yellowstone County location (160 MW capacity contribution versus 175 MW nameplate). Note: Capacity Credit factors are based on Effective Load Carrying Capability (ELCC) as of Dec. 2021. The cost per kW per fuel type Cost and Performance Characteristics of New Generating Technologies, Annual Energy Outlook 2022 (eia.gov) Cost Calculation: 160 MW of capacity from Yellowstone County RICE Facility. 160 MW divided by Capacity Credit then times the cost per fuel type equals total capex investment. Note: Each dollar sign above represents $100 million of investment and the shaded area below represents the land requirement, according to generation type, to provide required capacity. Wind Farm ~60,400 acres Solar Farm ~18,500 acres Land RequirementYellowstone County RICE Facility ~10 acres Appendix
Rate Base & Authorized Return Summary 41 Appendix (1) The revenue requirement associated with the FERC regulated portion of Montana electric transmission and ancillary services are included as revenue credits to our MPSC jurisdictional customers. Therefore, we do not separately reflect FERC authorized rate base or authorized returns. (2) The Montana gas revenue requirement includes a step down which approximates annual depletion of our natural gas production assets included in rate base. (3) For those items marked as "n/a," the respective settlement and/or order was not specific as to these terms. Coal Generation Rate Base as a percentage of Total Rate Base Revenue from coal generation is not easily identifiable due to the use of bundled rates in South Dakota and other rate design and accounting considerations. However, NorthWestern is a fully regulated utility company for which rate base is the primary driver for earnings. The data to the left illustrates that NorthWestern only derives approximately 10 -14% of earnings from its jointly owned coal generation rate base.
Management believes that Utility Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Utility 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, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates and other factors impact our results of operations. Our Utility Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report. Explaining Utility Margin 42 (1) Utility Margin is a non-GAAP Measure. Appendix
Non-GAAP Financial Measures 43 Appendix
Non-GAAP Financial Measures 44 Appendix This presentation includes financial information prepared in accordance with GAAP, as well as other financial measures, such as Utility Margin, Adjusted Non-GAAP pretax income, Adjusted Non-GAAP net income and Adjusted Non-GAAP 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 excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. We define Utility Margin as Operating Revenues less fuel, purchased supply and direct transmission expense (exclusive of depreciation and depletion) as presented in our Consolidated Statements of Income. This measure differs from the GAAP definition of Gross Margin due to the exclusion of Operating and maintenance, Property and other taxes, and Depreciation and depletion expenses, which are presented separately in our Consolidated Statements of Income. A reconciliation of Utility Margin to Gross Margin, the most directly comparable GAAP measure, is included in this presentation. Management believes that Utility Margin provides a useful measure for investors and other financial statement users to analyze our financial performance in that it excludes the effect on total revenues caused by volatility in energy costs and associated regulatory mechanisms. This information is intended to enhance an investor's overall understanding of results. Under our various state regulatory mechanisms, as detailed below, our supply costs are generally collected from customers. In addition, Utility 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, as well as to analyze how changes in loads (due to weather, economic or other conditions), rates and other factors impact our results of operations. Our Utility Margin measure may not be comparable to that of other companies' presentations or more useful than the GAAP information provided elsewhere in this report. Management also believes the presentation of Adjusted Non-GAAP pre-tax income, Adjusted Non-GAAP net income and Adjusted Non-GAAP Diluted EPS is more representative of normal earnings than GAAP pre-tax income, net income and 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.
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