2023 Second Quarter Earnings Webcast July 26, 2023 Beethoven Wind, South Dakota 8-K July 24, 2023
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. Crystal Lail Vice President & CFO Brian Bird President & CEO
Regulatory execution • Filed South Dakota electric rate review • Reached constructive multi-party settlement in Montana rate review (currently pending commission approval) Yellowstone County Generating Station • Legislative and judicial support for construction. After initial pause in construction, we resumed construction in June 2023 and expect the facility to be serving customers during the third quarter 2024. • Invested approx. $203.6 million of the estimated $275 million project total Strong and growing service territories. • Overall 1.4% customer growth (vs second quarter 2022) • Lowest unemployment rates in the nation SD #1 (1.9%), NE #1 (1.9%) and MT #6 (2.2%) (US Bureau of Labor Statistics, July 19, 2023) Second Quarter 3 NorthWestern recognized as one of America’s Greatest Workplaces 2023 by Newsweek.
Second Quarter 2023 Financial Results 4 *See slide 10 and “Non-GAAP Financial Measures” slide in the appendix for additional detail on this measure. Second Quarter Net Income vs Prior Period •GAAP: ↓ $10.7 Million (or 35.9%) •Non-GAAP*: ↓ $9.7 Million (or 32.2%) •Non-GAAP Pro Forma: ↓ $0.8 Million (or 2.7%) (Impact if MT Rate Review Settlement approved as filed) Second Quarter EPS vs Prior Period •GAAP: ↓ $0.22 (or 40.7%) •Non-GAAP*: ↓ $0.19 (or 35.2%) •Non-GAAP Pro Forma: ↓ $0.04 (or 7.4%) (Impact if MT Rate Review Settlement approved as filed)
*See slide 45 and “Non-GAAP Financial Measures” slide in the appendix for additional detail on this measure. Year-to-Date 2023 Financial Results 5 Year-to-Date Net Income vs Prior Period •GAAP: ↓ $7.3 Million (or 8.2%) •Non-GAAP*: ↓ $6.3 Million (or 7.0%) •Non-GAAP Pro Forma: ↑ $14.3 Million (or 15.9%) (Impact if MT Rate Review Settlement approved as filed) Year-to-Date EPS vs Prior Period •GAAP: ↓ $0.25 (or 15.4%) •Non-GAAP*: ↓ $0.23 (or 14.1%) •Non-GAAP Pro Forma: ↑ $0.12 (or 7.4%) (Impact if MT Rate Review Settlement approved as filed)
Second Quarter Financial Results 6 (1) (1) Decrease in revenues is primarily related to pass-through supply costs and non-cash regulatory amortizations. (2) Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure. (2)
Second Quarter EPS Bridge 7 Improvement in Utility Margin offset by higher expenses and share count dilution. After-tax Earnings Per Share See slide 10 and “Non-GAAP Financial Measures” slide in the appendix for additional detail on this measure. Change in Items impacting Net Income
Second Quarter Utility Margin Bridge 8 $2.9 Million or 1.3% increase 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
Second Quarter OA&G Bridge 9 $7.2 Million or 8.9% increase in OA&G Expense 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
Second Quarter Non-GAAP Earnings 10 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 June 30, 2023 U nf av or ab le W ea th er M ov e Pe ns io n Ex pe ns e to O G & A (d is ag gr eg at ed w ith A SU 2 01 7- 07 ) N on -e m pl oy ee D ef er re d C om pe ns at io n Three Months Ended June 30, 2023 Three Months Ended June 30, 2022 C om m un ity R en ew ab le E ne rg y Pr oj ec t Pe na lty (n ot ta x de du ct ib le ) N on -e m pl oy ee D ef er re d C om pe ns at io n M ov e Pe ns io n Ex pe ns e to O G & A (d is ag gr eg at ed w ith A SU 2 01 7- 07 ) Fa vo ra bl e W ea th er Three Months Ended June 30, 2022 Revenues $290.5 1.8 $292.3 ($27.8) -8.7% $320.1 (2.9) $323.0 Fuel, supply & dir. tx 67.6 67.6 (27.4) -28.8% 95.0 95.0 Utility Margin 222.9 1.8 - - 224.7 (0.4) -0.2% 225.1 - - - (2.9) 228.0 Op. Expenses OG&A Expense 84.8 - - 84.8 5.9 7.5% 78.9 0.1 (1.7) 80.5 Prop. & other taxes 40.1 40.1 (6.8) -14.5% 46.9 46.9 Depreciation 52.4 52.4 4.2 8.7% 48.2 48.2 Total Op. Exp. 177.3 - - - 177.3 3.3 1.9% 174.0 - 0.1 (1.7) - 175.6 Op. Income 45.6 1.8 - - 47.4 (3.7) -7.2% 51.1 - (0.1) 1.7 (2.9) 52.4 Interest expense (28.4) (28.4) (4.4) -18.3% (24.0) (24.0) Other (Exp.) Inc., net 4.1 - - 4.1 0.3 8.0% 3.8 2.5 0.1 (1.7) 2.9 Pretax Income 21.3 1.8 - - 23.1 (7.7) -25.0% 30.8 2.5 - - (2.9) 31.2 Income tax (2.2) (0.5) - - (2.7) (2.0) -285.7% (0.7) - - - 0.7 (1.4) Net Income $19.1 1.3 - - $20.4 ($9.7) -32.2% $30.1 2.5 - - (2.2) $29.8 ETR 10.1% 25.3% - - 11.7% 2.3% 0.0% - - 25.3% 4.6% Diluted Shares 59.8 59.8 4.7 8.5% 55.1 55.1 Diluted EPS $0.32 0.03 - - $0.35 ($0.19) -35.2% $0.54 0.04 - - (0.04) $0.54 Variance $ % Three Months Ended June 30, GAAP Non GAAP Non-GAAP Variance Non GAAP GAAP (1)(1) (2) Non-GAAP AdjustmentsNon-GAAP Adjustments
Cash Flow 11 Cash from Operating Activities increased by $61 million driven by a $62.1 million increase in collection of energy supply costs from customers. Funds from Operations decreased by $10.3 million over prior period. Net Under-Collected Supply Costs (in millions) Beginning (Jan. 1) Ending (March. 31) Inflow 2022 $99.1 $75.8 $23.3 2023 $115.4 $30.0 $85.4 2023 Improvement (less outflow) $62.1 We issued $10.8 million of equity under an At-the-Market equity program and anticipate issuing the remaining availability of approx. $64 million under the program during 2023. Debt financing during the quarter • Received remaining $50 million of the $270 million, 5.57% coupon, 30 year Montana FMBs priced in Q1 • Issued and received $30 million, 5.42% coupon, 10 year, South Dakota FMBs • Refinanced $144.7 million, 3.88% coupon, 5 year Pollution Control Revenue Refunding Bonds Financing plans (targeting a FFO to Debt ratio > 14%) are expected maintain our current credit ratings and are subject to change.
2023 earnings guidance is expected to be provided following an outcome in our pending Montana rate review Anticipate constructive and collaborative process with commission and staff in the South Dakota review $510 million capital plan for 2023 (inclusive of $80 million of investment specific to Yellowstone County Generating Station) Long-term growth targets remain; 3-6% EPS and 4-5% rate base 2023 annualized dividend of $2.56 is expected to be above targeted 60-70% payout ratio. Over the longer- term, we expect to maintain a dividend payout ratio within a targeted 60-70% range Financing plans are intended to maintain current credit ratings (targeting FFO to debt ratio greater than 14%) Financial Outlook 12 Rowe Dam at Mystic Lake, Montana
Montana Rate Review 13 The MPSC approved the recommendations of the staff for interim rates, subject to refund, effective October 1, 2022. Interim Rates Anticipated Next Steps • Post-hearing briefing concluded in June 2023. • We anticipate a decision from the MPSC on the Settlement Agreement during the third quarter 2023. Settlement Reached On April 3rd, NWE and the primary intervenors reached a Settlement Agreement for electric and natural gas rates and several key provisions including 9.65% and 9.55% ROE for electric and natural gas respectively (with 48% equity capitalization). The settlement was filed with the MPSC for their review. Final rates, once approved, will be retroactive back to interim effective date of October 1, 2022. Requested base rate increase supports over a billion dollars invested in Montana critical infrastructure - since our last rate reviews - while keeping operating costs below the rate of inflation. (Test years: 2015 nat. gas and 2017 electric)
South Dakota Rate Review 14 • First rate review since 2015. Seeking recovery of nearly 30 percent of rate base that is not included in South Dakota electric rates today. • Requested base rate increase driven by more than $267 million invested in South Dakota critical electric infrastructure, while keeping operating costs below the rate of inflation, since our last electric rate review. • Roughly 99% of the requested increase is driven by infrastructure investment, which includes cost of debt and equity capital and depreciation. • Increases in the typical customer bill since the last rate review are in line with inflation. Request to update our rates to reflect the current cost to provide safe and reliable service to our customers See Appendix for additional filing details.
Capital Investment 15 $2.4 billion of forecasted low-risk capital investment opportunity… • Capital investment addresses generation and transmission capacity constraints, grid modernization and renewable energy integration. This does not include any incremental opportunities related to additional supply investment. • This sustainable level of capex is expected to drive an 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. Over $2.1 Billion investment* over last 5 years * Historical Capital Investment includes property, plant and equipment additions, acquisitions and capital expenditures included in accounts payable. 5 Year History of Capital Investment 5 Year Forecast of Capital Investment ($millions, unless stated otherwise) Yellowstone County Generating Station
Conclusion 16 Pure Electric & Gas Utility Solid Utility Foundation Best Practices Corporate Governance Attractive Future Growth Prospects Strong Earnings & Cash Flows
17 Appendix
Regulated Utility Five-Year Capital Forecast 18 Appendix $2.4 billion of highly-executable and low-risk capital investment Electric Supply Resource Plans - Our energy resource plans identify portfolio resource requirements including potential investments. Included within our projections is approximately $120.0 million (in 2023 and 2024) of capital to complete construction of the 175 MW Yellowstone County Generating Station to be on line in 2024. Distribution and Transmission Modernization and Maintenance - The primary goals of our infrastructure investments are to reverse the trend in aging infrastructure, maintain reliability, proactively manage safety, build capacity into the system, and prepare our network for the adoption of new technologies. We are taking a proactive and pragmatic approach to replacing these assets while also evaluating the implementation of additional technologies to prepare the overall system for smart grid applications. Beginning in 2021, and continuing through 2025, we are installing automated metering infrastructure in Montana at a total cost of approximately $112.0 million, of which, $66.1 million remains and is reflected in the five year capital forecast.
Rate Base & Authorized Return Summary 19 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. (4) On August 8, 2022, we filed a Montana electric and natural gas rate review filing (2021 test year) requesting an increase to our authorized rate base, return on equity, and equity level in our capital structure. We expect a final order regarding this rate review in 2023. 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 9 -14% of earnings from its jointly owned coal generation rate base.
20 Appendix South Dakota & Montana Rate Review
South Dakota Rate Review 21 Infrastructure investment drives nearly 99%* of the requested base rate adjustment * $19.0 million Cost of Capital plus $17.2 million Infrastructure Investment as a percent of $36.6 million Total Change in Cost of Service. Appendix
South Dakota Rate Review 22 Electric $19.14 Per month Increase for an average residential electric customer that uses 750 kWh if our requested rate increase is approved. Appendix
South Dakota Rate Review 23 Appendix Since our last rate adjustment, NorthWestern’s typical residential electric customer bills have maintained a pace well below inflation. This request, if granted in full, would still result in customer bills in line with inflation.
Montana Rate Review 24 Appendix 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. 49% is driven by capital investment to ensure the safety and reliability of the energy system.
25 Appendix Colstrip Transfer
NorthWestern Energy executed an agreement with Avista Corporation (Exit Agreement) for the transfer of Avista’s ownership interests in Colstrip Units 3 and 4. • Effective date of transfer: December 31, 2025 • Generating capacity: 222 MW (bringing our total ownership to 444 MW) • Transfer price: $0.00 Colstrip Transaction Overview 26 • NorthWestern will be responsible for operational and capital costs beginning January 1, 2026. • The agreement does not require approval by the Montana Public Service Commission (MPSC). We expect to work with the MPSC in a future docket for cost recovery in 2026. • NorthWestern will have the right to exercise Avista’s vote with respect to capital expenditures1 between now and 2025 with Avista responsible for its pro rata share2. • Avista will retain its existing environmental and decommissioning obligations through life of plant. • Under the Colstrip Ownership & Operating Agreement, each of the owners will have a 90-day period in which to evaluate the transaction between NorthWestern and Avista to determine whether to exercise their respective right of first refusal. • We filed our Montana Integrated Resource Plan on April 28, 2023. This transaction is expected to satisfy our capacity needs in Montana for at least the next 5 years. 1. Avista retains the vote related to remediation activities. 2. Avista bears its current project share (15%) costs through 2025, other than “Enhancement Work Costs” for which it bears a time-based pro-rata share. Enhancement Work Costs are costs that are not performed on a least-costs basis or are intended to extend the life of the facility beyond 2025. See the Exit Agreement for additional detail. Appendix
Facility Ownership Overview 27 NorthWestern is actively working with the other owners to resolve outstanding issues, including the associated pending legal proceedings. Additionally, the owners intend to pursue a mutually beneficial reallocation (swap) of megawatts between the two units that would ideally provide NorthWestern with a controlling (> 370 megawatts) share of Unit 4. Appendix
Why Colstrip? 28 Reliable • Existing resource, ready to serve our Montana customers. Avoids lengthy planning, permitting and construction of a new facility that would stretch in-service beyond 2026. • Reduces reliance on imported power and volatile markets, providing increased energy independence. • In-state and on-system asset mitigating the transmission constraints we experience importing capacity. • Adds critical long-duration, 24/7 on-demand generation necessary for balancing our existing portfolio. Affordable • 222 MW of capacity with no upfront capital costs and stable operating costs going forward. o Equivalent new build would cost in excess of $500 million. o Incremental operating costs are known and reasonable. Resulting variable generation costs represent a 90%+ discount to market prices incurred during December’s polar vortex. • In addition to no upfront capital, low and stably priced mine-mouth coal supply costs. Sustainable • We remain committed to our net zero goal by 2050. This additional capacity, with a remaining life of up to 20 years, helps bridge the interim gap and will likely lead to less carbon post 2040. • Yellowstone County Generating Station is potentially our last natural gas resource addition in Montana. • Partners are committed to evaluate non-carbon long-duration alternative resources for the site. • Keeps the existing plant open and retains its highly skilled jobs vital to the Colstrip community. • Protects existing ownership interests with an ultimate goal of majority ownership of Unit 4. NorthWestern Energy executed an agreement with Avista Corporation for the transfer of Avista’s ownership interests in Colstrip Units 3 & 4. • Effective date of transfer: 12/31/2025 • Generating capacity: 222 MW • Transfer price: $0.00 Appendix
Reduces Risk • We are in a supply capacity crisis due to lack of resource adequacy, with approx. 40% of our customers’ peak needs on the market. This transaction will reduce our need to import expensive capacity during critical times. • Establishes clarity regarding operations past 2025 Washington state legislation deadline. • Reduces PCCAM risk sharing for customers and shareholders. Bill Headroom • Stable pricing reduces impact of market volatility and high energy prices on customers. Aligned with ‘All of the Above’ energy transition in Montana • Supports our generating portfolio that is nearly 60% carbon-free today. • Provides future opportunity at the site while supporting economic development in Montana. • Agreement considers the appropriate balance of reliability, affordability and sustainability. 29 Why Colstrip?Appendix
December 2022 Polar Vortex 30 The chart illustrates the actual resource specific contribution of energy, the capacity deficit we faced, and the market price of power during the late December 2022 multi-day cold weather event in Montana. As a result of our capacity deficit, we were reliant upon the high and volatile power market a majority of the time to meet customer demand. Appendix
Our Net-Zero Vision 31 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
32 Appendix Second Quarter and Year-to-Date Financial Information
Decrease in utility margin due to the following factors: $ 7.1 Montana interim rates 3.3 Montana property tax tracker collections 3.0 Lower non-recoverable Montana electric supply costs 0.4 Higher Montana natural gas transportations (5.3) Lower natural gas retail volumes (3.5) Lower electric retail volumes (1.7) Lower transmission revenue (market conditions & lower transmission rates) (0.4) Other $ 2.9 Change in Utility Margin Impacting Net Income 33 Utility Margin (2nd Quarter) (dollars in millions) Three Months Ended June 30, 2023 2022 Variance Electric $ 186.9 $ 185.7 $ 1.2 0.6% Natural Gas 36.0 42.3 (6.3) (14.9)% Total Utility Margin $ 222.9 $ 228.0 $ (5.1) (2.2)% $ (7.2) Lower property taxes recovered in revenue, offset in property & other tax expense (1.4) Lower operating expenses recovered in revenue, offset in O&M expense (0.4) Lower natural gas production taxes recovered in revenue, offset in property & other taxes 1.0 Higher revenue from lower production tax credits, offset in income tax expense $ (8.0) Change in Utility Margin Offset Within Net Income $ (5.1) 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: $ 4.4 Higher labor and benefits (1) 4.2 Higher depreciation due to plant additions 0.9 Higher other state and local tax expenses 0.8 Increase in uncollectible accounts 0.4 Higher insurance expense (0.2) Lower expenses at our electric generation facilities 1.8 Other miscellaneous $ 12.3 Change in Operating Expense Items Impacting Net Income Operating Expenses 34 (2nd Quarter) (dollars in millions) Three Months Ended June 30, 2023 2022 Variance Operating & maintenance $ 54.8 $ 53.3 $ 1.5 2.8% Administrative & general 30.0 27.2 2.8 10.3% Property and other taxes 40.1 46.9 (6.8) (14.5)% Depreciation and depletion 52.4 48.2 4.2 8.7% Operating Expenses $ 177.3 $ 175.6 $ 1.7 1.0% $ (7.2) Lower property taxes recovered in trackers, offset in revenue (1.7) Lower pension and other postretirement benefits, offset in other income (1.4) Lower operating and maintenance expenses recovered in trackers, offset in revenue (0.4) Lower natural gas production taxes recovered in trackers, offset in revenue 0.1 Lower non-employee directors deferred compensation, offset in other income $ (10.6) Change in Operating Expense Items Offset Within Net Income $ 1.7 Increase in Operating Expenses $4.3 Appendix (1) In order to present the total change in labor and benefits, 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. This change is offset within this table as it does not affect our operating expenses.
Operating to Net Income 35 (dollars in millions) Three Months Ended June 30, 2023 2022 Variance Operating Income $ 45.6 $ 52.4 $ (6.8) (13.0)% Interest expense (28.4) (24.0) (4.4) (18.3)% Other income, net 4.1 2.9 1.2 41.4% Income Before Taxes 21.3 31.2 (9.9) (31.7)% Income tax expense (2.2) (1.4) (0.8) (57.1)% Net Income $ 19.1 $ 29.8 $ (10.7) (35.9)% (2nd Quarter) $4.4 million increase in interest expenses was primarily due to higher borrowings and interest rates, partly offset by higher capitalization of AFUDC. $1.2 million increase in other income, net was primarily due to the prior year CREP penalty, partly offset by an increase in the non-service component of pension expense $0.8 million increase in income tax expense was primarily due to lower flow-through repairs deductions and lower production tax credits partly offset by lower pre-tax income. Appendix
Tax Reconciliation 36 Appendix (2nd Quarter)
37 Segment ResultsAppendix (1) (1) (2nd Quarter) (1) Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure.
Weather / Hydro Conditions 38 Snow water equivalents generally in line with the 30-year medians. (Missouri, Madison & Clark Fork Rivers and West Rosebud Creek basins) We estimated a $1.8 million pre-tax detriment as compared to normal and a $4.7 million detriment as compared to Q2 2022. Appendix (2nd Quarter) Real-Time Streamflows versus 30-Year Normal
39 Electric SegmentAppendix (1) (2nd Quarter) (1) Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure.
40 Natural Gas SegmentAppendix (1) (2nd Quarter) (1) Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure.
Increase in utility margin due to the following factors: $ 15.6 Montana interim rates (subject to refund) 6.3 Higher electric retail volumes 4.3 Lower non-recoverable Montana electric supply costs 3.5 Montana property tax tracker collections 1.5 Montana natural gas transportation (1.6) Lower natural gas retail volumes (0.5) Lower transmission revenue (market conditions & lower transmission rates) (0.3) Other $ 28.8 Change in Utility Margin Impacting Net Income 41 Utility Margin (YTD thru 2nd Quarter) (dollars in millions) Six Months Ended June 30, 2023 2022 Variance Electric $ 404.1 $ 379.8 $ 24.3 6.4% Natural Gas 107.9 107.5 0.4 0.4% Total Utility Margin $ 512.0 $ 487.3 $ 24.7 5.1% $ (4.6) Lower property taxes recovered in revenue, offset in property & other tax expense (1.7) Lower operating expenses recovered in revenue, offset in O&M expense (0.5) Lower natural gas production taxes recovered in revenue, offset in property & other taxes 2.7 Higher revenue from lower production tax credits, offset in income tax expense $ (4.1) Change in Utility Margin Offset Within Net Income $ 24.7 Increase 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: $ 8.5 Higher depreciation due to plant additions 7.5 Higher labor and benefits (1) 3.2 Higher expenses at our electric generation facilities 1.1 Increase in uncollectible accounts 1.0 Higher insurance expense 0.7 Higher other state and local tax expense (0.4) Lower technology implementation and maintenance expenses 1.4 Other miscellaneous $ 23.0 Change in Operating Expense Items Impacting Net Income Operating Expenses 42 (YTD thru 2nd Quarter) (dollars in millions) Six Months Ended June 30, 2023 2022 Variance Operating & maintenance $ 110.7 $ 106.1 $ 4.6 4.3% Administrative & general 64.7 58.9 5.8 9.8% Property and other taxes 89.3 93.7 (4.4) (4.7)% Depreciation and depletion 105.6 97.1 8.5 8.8% Operating Expenses $ 370.3 $ 355.8 $ 14.5 4.1% $ (4.6) Lower property taxes recovered in trackers, offset in revenue (1.7) Lower operating and maintenance expenses recovered in trackers, offset in revenue (1.5) Lower pension and other postretirement benefits, offset in other income (0.5) Lower natural gas production taxes recovered in trackers, offset in revenue (0.2) Lower non-employee directors deferred compensation, offset in other income $ (8.5) Change in Operating Expense Items Offset Within Net Income $ 14.5 Increase in Operating Expenses $10.4 Appendix (1) In order to present the total change in labor and benefits, 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. This change is offset within this table as it does not affect our operating expenses.
Operating to Net Income 43 (dollars in millions) Six Months Ended June 30, 2023 2022 Variance Operating Income $ 141.6 $ 131.5 $ 10.1 7.7% Interest expense (56.4) (47.7) (8.7) (18.2)% Other income, net 8.8 7.6 1.2 15.8% Income Before Taxes 94.0 91.4 2.6 2.8% Income tax expense (12.4) (2.5) (9.9) (396.0)% Net Income $ 81.6 $ 88.9 $ (7.3) (8.2)% (YTD thru 2nd Quarter) $8.7 million increase in interest expenses was primarily due to higher borrowings and interest rates, partly offset by higher capitalization of AFUDC. $1.2 million increase in other income, net was primarily due to the prior year CREP penalty, partly offset by an increase in the non-service component of pension expense $9.9 million increase in income tax expense was primarily due to lower flow-through items (repairs deductions and lower production tax credits) and higher pre-tax income. Appendix
Tax Reconciliation 44 Appendix (YTD thru 2nd Quarter)
Year-to-Date Non-GAAP Earnings 45 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 (YTD thru 2nd Quarter)
46 Electric SegmentAppendix (1) (YTD thru 2nd Quarter) (1) Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure.
47 Natural Gas SegmentAppendix (1) (YTD thru 2nd Quarter) (1) Utility Margin is a non-GAAP Measure See appendix slide titled “Explaining Utility Margin” for additional disclosure.
Quarterly PCCAM Impacts 48 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 Q1 Q2 Q3 Q4 Full Year '17/'18 Tracker $3.3 $3.3 '18/'19 Tracker ($5.1) $0.3 (4.8) 2018 (Expense) Benefit $0.0 $0.0 ($1.8) $0.3 ($1.5) Full Year '18/'19 Tracker ($1.6) $4.6 $3.0 '19/'20 Tracker $0.1 ($0.7) (0.6) 2019 (Expense) Benefit ($1.6) $4.6 $0.1 ($0.7) $2.4 Full Year ($9.4) ($9.4) '19/'20 Tracker ($0.1) $0.2 $0.1 Recovery of modeling costs $0.7 $0.7 '20/'21 Tracker ($0.6) ($0.3) ($0.9) 2020 (Expense) Benefit $0.6 $0.2 ($0.6) ($0.3) ($0.1) Full Year '20/'21 Tracker ($0.8) ($0.5) ($1.3) '21/'22 Tracker ($2.7) ($1.4) ($4.1) 2021 (Expense) Benefit ($0.8) ($0.5) ($2.7) ($1.4) ($5.4) Q1 Q2 Q3 Q4 Full Year '21/'22 Tracker ($0.8) ($0.8) ($1.6) '22/'23 Tracker ($4.0) ($1.6) ($5.6) 2022 (Expense) Benefit ($0.8) ($0.8) ($4.0) ($1.6) ($7.2) Q1 Q2 Q3 Q4 Year-to-Date '22/'23 Tracker $0.5 $2.2 $2.7 '23/'24 Tracker $0.0 2023 (Expense) Benefit $0.5 $2.2 $0.0 $0.0 $2.7 Year-over-Year Variance $1.3 $3.0 $4.3 CU4 Disallowance ('18/'19 Tracker) First full year recorded in Q3
Qualified Facility Earnings Adjustment 49 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 50 Debt to Total Capitalization slightly below our targeted 50% - 55% range. Appendix
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 51 (1) Utility Margin is a non-GAAP Measure. Appendix
Non-GAAP Financial Measures 52 Appendix
Non-GAAP Financial Measures 53 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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