2019 - Full Year Earnings Webcast February 13, 2020

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 Chief Financial Officer factors that may affect our results are listed in certain of our press releases and disclosed in the Company’s 10-K along with other public filings with the SEC. 2

2019 and Recent Highlights • Net income for 2019 was $202.1 million. This is a $5.1 million, or 2.6%, increase as compared to the same period in 2018. • Diluted earnings per share (EPS) were $3.98. This is a $0.06, or 1.5%, increase as compared to 2018 o Non-GAAP Adjusted EPS were $3.42. This is a $0.03, or 0.9% increase as compared to 2018 • The Board of Directors declared a quarterly dividend of $0.60 per share (a 4.3% increase) payable March 31st to shareholders of record as of March 13th, 2020. • NorthWestern issued its Carbon Reduction Vision for our electric generating portfolio in Montana. o Targeting a 90% reduction in carbon intensity by 2045 (as compared to 2010 baseline) • December 2019 - announced transaction to acquire an incremental 25% (185 megawatts) of Colstrip Unit 4 from Puget Sound Energy for one dollar. o In February 2020, we filed a request for approval, of the Colstrip acquisition, with the MPSC. • December 2019 - the Montana Public Service Commission issued a final order approving our electric rate case settlement. • February 2020 – issued an all-source competitive solicitation request for up to 280 MW’s of peaking and flexible capacity to be available for commercial operation in early 2023. 3

Summary Financial Results (Full Year) (1) 4 (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure See appendix for additional disclosure.

Gross Margin (Full Year) (dollars in millions) Twelve Months Ended December 31, 2019 2018 Variance Electric $ 741.6 $ 726.5 $ 15.1 2.1% Natural Gas 198.3 192.6 5.7 3.0% Total Gross Margin (1) $ 939.9 $ 919.1 $ 20.8 2.3% Increase in gross margin due to the following factors: $ 22.1 Tax Cuts and Jobs Act impact (settlement in 2018) 10.9 Natural gas retail volumes 6.4 Electric retail volumes 4.4 Montana electric rates 3.9 Montana electric supply cost recovery (20.9) Electric Qualifying Facilities liability adjustment (5.6) Electric transmission (1.5) Montana natural gas production rates 0.5 Other $ 20.2 Change in Gross Margin Impacting Net Income $ 3.0 Property taxes recovered in trackers (1.7) Production tax credits flowed-through trackers (0.7) Operating expenses recovered in trackers $ 0.6 Change in Gross Margin Offset Within Net Income $ 20.8 Increase 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 (Full Year) We estimate overall favorable weather in 2019 resulted in a $7.3 million pretax benefit as compared to normal and a $6.0 million benefit as compared to 2018. 6

Operating Expenses (Full Year) (dollars in millions) Twelve Months Ended December 31, 2019 2018 Variance Operating, general & admin. $ 318.2 $ 307.1 $ 11.1 3.6% Property and other taxes 171.9 171.3 0.6 0.4% Depreciation and depletion 172.9 174.5 (1.6) (0.9%) Operating Expenses $ 663.0 $ 652.9 $ 10.1 1.5% Increase in operating, general & administrative expense due to the following factors: $ 4.2 Hazard trees 3.7 Generation maintenance 2.2 Labor, due to compensation increases 1.7 Distribution maintenance 1.5 Gas transmission maintenance 1.5 General legal costs 1.2 Technology costs 1.2 Employee benefits, primarily pension related 0.9 Western Energy Imbalance Market costs (0.8) Other miscellaneous $ 17.3 Change in OG&A Items Impacting Net Income ($7.8) Pension and other postretirement benefits (0.7) Operating expenses recovered in trackers 2.3 Non-employee directors deferred compensation $ (6.2) Change in OG&A Items Offset Within Net Income $ 11.1 Increase in Operating, General & Administrative Expenses 7

Operating to Net Income (Full Year) (dollars in millions) Twelve Months Ended December 31, 2019 2018 Variance Operating Income $ 276.9 $ 266.3 $ 10.6 4.0% Interest Expense (95.1) (92.0) (3.1) (3.4%) Other Income 0.4 4.0 (3.6) (91.0%) Income Before Taxes 182.2 178.3 3.9 2.2% Income Tax Benefit 19.9 18.7 1.2 6.1% Net Income $ 202.1 $ 197.0 $ 5.1 2.6% $3.1 million increase in interest expenses was primarily due to higher borrowings. $3.6 million decrease in other income was due to a $7.8 million increase in pension expense that was partly offset by a $2.3 million 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 expense with no impact to net income. This unfavorable variance was partly offset by $1.6 million higher capitalization of Allowance for Funds Used During Construction (AFUDC). $1.2 million increase in income tax benefit due primarily due to the release of approximately $22.8 million of unrecognized tax benefits, including $2.7 million of accrued interest and penalties, due to the lapse of statutes of limitation in the second quarter of 2019. These tax adjustments were partly offset by an income tax benefit in 2018 of $19.8 million associated with the final measurement of 8 excess deferred taxes associated with the Tax Cuts and Jobs Act.

Income Tax Reconciliation (Full Year) 9

Balance Sheet Debt to Capitalization remains at lower end of our targeted 50% - 55% range. 10

Cash Flow Cash from operating activities decreased by $85.3M primarily due to: •Under collection of supply costs………..($35.5M) •Tax Cuts and Jobs Act customer refunds...($20.5M) •Generation inter- connection refunds…...($22.1M) •Receipt of insurance proceeds in 2018……....($6.1M) •Other miscellaneous…...($1.1M) 11

Adjusted Non-GAAP Earnings (Full Year) The adjusted non-GAAP measures presented in the table are being shown to reflect significant items that are non-recurring or 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) Impact of Tax Cuts & Jobs (TCJA) Jurisdictional Settlements includes the addback of $6.1M pretax revenue deferred for customer refunds in excess of the income tax benefits realized in 2018 and $3.3M of pretax expense related to hazard tree removal that was originally proposed to be funded with 50% of TCJA benefits (in lieu of customer refunds). This treatment was ultimately conceded in the settlement in exchange for agreement by the stipulating parties to not oppose a known-and-measureable adjustment equal to the actual 2018 expenditures for hazard tree removal included in our Montana electric rate review 2017 test year. These increases to Non-GAAP earnings were more than offset by the removal of a $19.8M income tax benefit in 2018 related to the final adjustment of excess deferred taxes and $2.4M of increased tax expense related to the two pretax items previously discussed (($6.1M + $3.3M ) x 25.3% = $2.4M). These sum to $22.2M (or $19.8M + $2.4M) increase to income tax expense and ultimately result in $12.8M reduction to GAAP Net Income. (3) Due to our expectations regarding remeasurement of our Qualifying Facilities (QF) liability, effective 2019 we no longer reflect this adjustment as a non-GAAP measure . Absent an adjustment to remove the QF liability benefit, our 2018 Adjusted Non-GAAP Diluted EPS would have been $3.65 twelve months ended December 31, 2018. The 2019 QF adjustment, as noted in our gross margin 12 discussion herein, was $6.3 million ($3.3 million liability reduction plus $3.0 million lower actual output and pricing).

Diluted Earnings Per Share Non-GAAP Adjusted EPS Growth Averaged 5.4% from 2013 - 2019 NorthWestern affirms its 2020 earnings guidance range of $3.45 - $3.60 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; • A consolidated income tax rate of approximately (2%) to 3% of pre-tax income; and • Diluted shares outstanding of approximately 50.9 million. 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. See “Non-GAAP Financial Measures” slide in appendix for “Non-GAAP Adjusted EPS” 13

2019 Non-GAAP to 2020 EPS Bridge NorthWestern affirms its 2020 earnings guidance range of $3.45 - $3.60 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; • A consolidated income tax rate of approximately (2%) to 3% of pre-tax income; and • Diluted shares outstanding of approximately 50.9 million. *2020 earnings drivers shown above are calculated using a 25.3% effective tax rate. The tax benefit included above is predicated upon increased investment related to certain repairs that are eligible for immediate tax deduction. We expect NOLs to be available into 2021 with alternative minimum tax credits and production tax credits to be available into 2023 to reduce cash taxes. Additionally, we anticipate our effective tax rate to reach approximately 10% by 2023. 14

Our Carbon Reduction Vision for Montana 90% carbon reduction by 2045 NorthWestern Energy commits to reduce the carbon intensity of our electric energy portfolio for Montana 90% by 2045.* * As compared with our 2010 carbon intensity as a baseline Already over 60% carbon free Today, NorthWestern Energy serves Montana with an electric portfolio that is over 60% carbon free and more than two times better than the total U.S electric power industry (28% carbon free). Over the last decade, we have already reduced the carbon intensity of our energy generation in Montana by more than 50%. How we’re going to get there Our vision for the future builds on the progress we have already made, and on our legal obligation to provide safe, reliable and affordable energy service. The foundation of our supply portfolio is our hydro system, which is 100% carbon free and is available 24 hours a day, 365 days a year. Over the coming years, we expect to see additional renewables (nameplate wind will soon pass hydro, and both exceed Colstrip); energy efficiency; changing dispatch of thermal resources (used to meet peak and integration of intermittent resources); decreasing cost and increasing functionality of emerging technologies. We are committed to working with our customers and communities to help them achieve their sustainability goals and add new technology on our system. Success in meeting and exceeding our goal will depend on consistent and clear public policy support. 15

25% of Colstrip Unit 4 Acquisition On December 9, 2019 NorthWestern (NWE) executed a Purchase and Sale Agreement for the acquisition of Puget Sound Energy’s (PSE) 25% ownership interests in Colstrip Unit 4 (CU4). • Generating Capacity: 185 MW (bringing our total ownership to 407 MW, or 55% of CU4) • Purchase Price: $1.00 • PSE will remain responsible for its current pro rata ownership share of environmental and pension liabilities attributed to events or conditions existing prior to closing of the transaction and for any demolition, reclamation, or remediation costs associated with the existing facilities that comprise CU4. • PSE will enter a Power Purchase Agreement (PPA) with NWE to purchase 90 MW of power for approximately 5 years – indexed to hourly Mid-Columbia power prices. • Net proceeds from the PPA will be placed in a fund and applied against future decommissioning and remediation costs related to the existing 30%, or 222 MW, ownership in CU4. • PPA includes a price floor that reflects the recovery of all fixed operating and maintenance and variable generation costs. • The transaction is conditioned upon MPSC Pre-Approval (filed in February 2020). • Entered a separate agreement (predicated on approval of generation transaction) to acquire an additional 95MW interest in the 500 kV Colstrip Transmission System for net book value at time of sale – expected to be $2.5 to $3.8 million. • Timeline • Q1 2020 – MPSC pre-approval of the CU4 acquisition and FERC Section 203 authorization • Q3 2020 – FERC Decision on Section 203 filing • Q4 2020 – MPSC Decision on pre-approval filing NWE currently has a 46% reserve margin deficit during peak periods. This exposes our customers to greater market exposure than any of our regional peers. In addition, planned retirements in the Pacific Northwest region exceeding 3,600 MW will compound our market exposure. Acquiring the 25% interest in Colstrip Unit 4 16 will limit this impact and provide a bridge to future generation technologies.

NWE Energy Supply Resource Plans South Dakota Electricity Supply Resource Plan • Published fall of 2018, the plan focuses on modernization of our fleet to improve reliability and flexibility, maintain compliance in Southwest Power Pool, and lowering operating costs. The plan identified 90MWs of existing generation that should be retired and replaced over the next 10 years. • On April 15, 2019, we issued a request for proposals for 60 MW of flexible capacity resources to begin serving South Dakota customers by the end of 2021. • As a result of the competitive solicitation process, we expect to construct and own natural gas fired reciprocating internal combustion engines at a brownfield site in Huron, South Dakota. Dependent upon manufacturer selection, we anticipate 55-60 MW of new capacity to be online by late 2021 at a total investment of approximately $80 million. The selected proposal is subject to the execution of construction contracts and obtaining the applicable environmental and construction related permits. Montana Electricity Supply Resource Plan Ryan Dam Upgrade • The plan supports the goal of developing resources that will address the changing energy landscape in Montana to meet our customers’ electric energy needs in a reliable and affordable manner. • We are currently 630 MW short of our peak needs, which we procure in the market. We forecast that our energy portfolio will be 725 MW short by 2025, considering expiring contracts and a modest increase in customer demand. • We issued a competitive all-source solicitation request in February 2020 for up to 280 MW* of peaking and flexible capacity to be available for commercial operation in early 2023. An independent evaluator is being used to administer the solicitation process and evaluate proposals, with the successful project(s) selected by the first quarter of 2021. We expect the process will be repeated in subsequent years to provide a resource-adequate energy and capacity portfolio by 2025. 17 * Open to all types of resources that meet our peak and flexible capacity needs

Looking Forward Regulatory • In December 2019, the MPSC issued a final order approving our electric rate case settlement in our Montana electric rate case, effective April 1, 2019, that would result in an annual increase to electric revenue of approximately $6.5 million (based upon a 9.65% ROE, rate base and capital structure as filed) and a $9.3 million decrease in depreciation expense. Various parties have filed petitions for reconsideration of parts of the order and we expect the MPSC to issue an order on these requests during the first quarter of 2020. • In May 2019, we submitted a filing with FERC for our Montana transmission assets. In June 2019, the FERC issued an order accepting our filing, granting interim rates (effective July 1 and subject to refund), establishing settlement procedures and terminating our related Tax Cuts and Jobs Act filing. A settlement judge has been appointed and settlement negotiations are ongoing. We expect to submit a compliance filing with the MPSC upon resolution of our Montana FERC case adjusting the proposed credit in our Montana retail rates. Continue to Invest in our Transmission & Distribution Infrastructure • Comprehensive infrastructure program to ensure safety, capacity and reliability. • Natural gas pipeline investment (SAFE PIPES Act, Integrity Verification Process and Pipeline & Hazardous Materials Safety Administration proposed regulations). • Grid modernization, advanced distribution management system and advanced metering infrastructure investment Plans to join Western Energy Imbalance Market (EIM) in April 2021 • Real-time energy market could mean lower cost of energy for Montana customers, more efficient use of renewables and greater power grid reliability. Cost Control Efforts • Continue to monitor costs, including labor, benefits and property tax valuations. 18

Capital Investment Forecast $1.8 billion of total capital investment over five years We anticipate financing this capital with a combination of cash flow from operations (aided by NOLs available into 2021), first mortgage bonds and equity issuances. Based on current expectations, any equity issuance would be late 2020 or early 2021 and would be sized to maintain and protect current credit ratings. Significant capital investments that are not in the projections or negative regulatory actions could necessitate additional equity funding. Based on the results of the recent competitive solicitation process in South Dakota, $80 million of incremental investment for SD generation is included above (spread between 2020-2021). Capital projections above do not include investment necessary to address identified generation capacity issues in Montana. These additions could increase the capital forecast above in excess of $200 million over the next five years. 19

Conclusion Best Attractive Pure Strong Solid Utility Practices Future Electric & Earnings & Foundation Corporate Growth Gas Utility Cash Flows Governance Prospects 20

Appendix 21

Appendix Segment Results (Full Year) (1) (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. 22 See appendix for additional disclosure.

Appendix Electric Segment (Full Year) (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. 23 See appendix for additional disclosure.

Appendix Natural Gas Segment (Full Year) (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. 24 See appendix for additional disclosure.

Appendix Summary Financial Results (Three Months Ended December 31) (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. 25 See appendix for additional disclosure.

Appendix Gross Margin (Three Months Ended December 31) (dollars in millions) Three Months Ended December 31, 2019 2018 Variance(1) Electric $ 186.1 $ 176.6 $ 9.5 5.4% Natural Gas 59.7 59.8 (0.1) 0.1% Total Gross Margin $ 245.8 $ 236.4 $ 9.4 4.0% Increase in gross margin due to the following factors: (1) Gross Margin, defined as revenues less cost of $ 6.7 Tax Cuts and Jobs Act impact sales, is a non-GAAP 3.3 Electric retail volumes Measure See appendix 1.9 Natural gas retail volumes for additional disclosure. 1.6 Montana electric rates, subject to refund 0.1 Montana natural gas rates (1.5) Electric transmission (1.0) Montana electric supply cost recovery 2.6 Other $ 13.7 Change in Gross Margin Impacting Net Income $ (3.4) Production tax credits flowed-through trackers (1.5) Property taxes recovered in trackers 0.6 Operating expenses recovered in trackers $ (4.3) Change in Gross Margin Offset Within Net Income $ 9.4 Increase in Gross Margin 26

Appendix Weather (Three Months Ended December 31) We estimate unfavorable weather for the 4th quarter 2019 has contributed approximately $0.7M pretax detriment as compared to normal but $0.3M pretax benefit as compared to the same period in 2018. 27

Appendix Operating Expenses (Three Months Ended December 31) (dollars in millions) Three Months Ended December 31, 2019 2018 Variance Operating, general & admin. $ 79.3 $ 85.2 $ (5.9) (6.9%) Property and other taxes 38.7 43.0 (4.3) (10.0%) Depreciation and depletion 43.1 43.6 (0.5) (1.1%) Operating Expenses $ 161.1 $ 171.8 $ (10.7) (6.2%) Decrease in Operating, general & admin expense due to the following factors: $ (4.1) Employee benefits 1.3 Generation maintenance 0.6 Labor 0.5 Distribution maintenance 0.4 Energy Imbalance Management (EIM) costs 0.3 Hazard trees 0.3 Gas transmission 0.1 Legal costs (3.6) Other $ (4.2) Change in OG&A Items Impacting Net Income $ (1.6) Pension and other postretirement benefits (0.7) Non-employee directors deferred compensation 0.6 Operating expense recovered in trackers $ (1.7) Change in OG&A Items Offset Within Net Income $ (5.9) Decrease in Operating, General & Administrative Expenses 28

Appendix Operating to Net Income (Three Months Ended December 31) (dollars in millions) Three Months Ended December 31, 2019 2018 Variance Operating Income $ 84.7 $ 64.6 $ 20.1 31.1% Interest Expense (24.1) (23.8) (0.3) (1.3%) Other (Expense) / Income (0.5) 2.2 (2.7) (120.5%) Income Before Taxes 60.1 43.0 17.1 39.8% Income Tax (Expense) / Benefit (0.1) 23.4 (23.5) (100.4%) Net Income $ 60.0 $ 66.4 $ (6.4) (9.7%) $0.3 million increase in interest expenses was primarily due to higher borrowings. $2.7 million increase in other expense was due to a $1.6 million increase in other pension expense and a $0.7 million decrease in the value of deferred shares held in a trust for non-employee directors deferred compensation, both of which are offset in operating, general and administrative expense with no impact to net income. $23.5 million increase in income tax expense was primarily due to the approximately $22.2 million tax benefit in 2018 from the Tax Cuts and Jobs Act jurisdictional settlements as well as higher pre-tax income in 2019. 29

Appendix Income Tax Reconciliation (Three Months Ended December 31) 30

Appendix Adjusted Non-GAAP Earnings (Three Months Ended December 31) The adjusted non- GAAP measures presented in the table are being shown to reflect significant items that were non- recurring or 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) Impact of Tax Cuts & Jobs (TCJA) Jurisdictional Settlements includes the addback of $6.1M pretax revenue deferred for customer refunds in excess of the income tax benefits realized in 2018 and $3.3M of pretax expense related to hazard tree removal that was originally proposed to be funded with 50% of TCJA benefits (in lieu of customer refunds). This treatment was ultimately conceded in the settlement in exchange for agreement by the stipulating parties to not oppose a known-and-measureable adjustment equal to the actual 2018 expenditures for hazard tree removal included in our Montana electric rate review 2017 test year. These increases to Non-GAAP earnings were more than offset by the removal of a $19.8M income tax benefit in 2018 related to the final adjustment of excess deferred taxes and $2.4M of increased tax expense related to the two pretax items previously discussed (($6.1M + $3.3M ) x 25.3% = $2.4M). These sum to $22.2M (or $19.8M + $2.4M) increase to income tax expense and ultimately result in 31 $12.8M reduction to GAAP Net Income.

Appendix Segment Results (Three Months Ended December 31) (1) (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. 32 See appendix for additional disclosure.

Appendix Electric Segment (Three Months Ended December 31) (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. 33 See appendix for additional disclosure.

Appendix Natural Gas Segment (Three Months Ended December 31) (1) (1) Gross Margin, defined as revenues less cost of sales, is a non-GAAP Measure. 34 See appendix for additional disclosure.

Appendix Montana Electric Rate Case September 2018 Filing (Docket D2018.2.12) • Filed based on 2017 test year and $2.34 billion of rate base. The filing also requests approval to: • Requested $34.9 million annual increase to electric rates. • Capitalize Demand Side Management Costs; • On April 5, 2019, we filed rebuttal testimony that updated and • Establish a new baseline for PCCAM costs; • Place Two Dot Wind in rate base; and lowered our requested increase to $30.7 million. This update • Create new net metering customer class and rate for responded to intervenor testimony and included certain known new residential private generation. and measurable adjustments. • Request includes a 10.65% return on equity, 4.26% cost of debt, 49.4% equity & 7.42% return on rate base1 • In March 2019, the MPSC issued an order approving an increase in rates of approximately $10.5 million on an interim and refundable basis effective April 1, 2019. Update • In May 2019, we reached a settlement with all parties who filed comprehensive revenue requirement, cost allocation, and rate design testimony in our Montana electric rate case. If the MPSC approves the settlement, it will result in an annual increase to electric revenue of approximately $6.5 million (based upon a 9.65% return on equity and rate base and capital structure as filed) and an annual decrease in depreciation expense of approximately $9 million. • A comprehensive hearing was held in May 2019 with post-hearing briefing completed in late August 2019. • MPSC staff recommended that the MPSC approve and adopt the settlement as filed in September 2019. • The MPSC issued a final order approving our electric rate case settlement effective April 1, 2019. Next Steps • Various parties have filed petitions for reconsideration of parts of the order and we expect the MPSC to issue an order on these requests during the first quarter of 2020. • As of December 31, 2019 we have recognized revenue of approximately $4.4 million, reduced depreciation expense by approximately $8.9 million, and have deferred approximately $2.9 million of the interim revenues based on the proposed settlement. Any difference between the interim and final approved rates will be refunded to customers. 35 1. Except for Colstrip Unit 4 which has an lifetime ROR of 8.25% per D2008.6.69 (Order No. 6925f)

Appendix Qualified Facility Earnings Adjustment The gain in 2019 for our QF liability was $6.3 million in total, it was comprised of $3.3 million adjustment to the liability and $3.0 million lower actual costs over last 12 months (QF contract year). This $6.6 million benefit is $20.9 million less than the $27.2 million total benefit we recognized in Q2 last year. Due to our expectations regarding remeasurement of our QF liability, we no longer reflect this adjustment as a non-GAAP measure. Absent a QF liability adjustment, our 2018 Adjusted Non-GAAP Diluted EPS would have been $0.89 and $2.00 for the three and six months ended June 30, 2018, respectively. 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 Quarterly PCCAM Impacts 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. 37

Appendix Rate Base & Authorized Return Summary 38

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 39 measures.

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