Additional information regarding this release can be found in the earnings presentation found at: www.northwesternenergy.com/about-us/investors/financials/earnings

Fourth Quarter Financial Results

Net income for the three months ending December 31, 2022 was $66.7 million, or $1.16 per diluted share, as compared with net income of $51.3 million, or $0.96 per diluted share, for the same period in 2021. This increase of $15.4 million in net income was primarily due to increased revenue from higher electric and natural gas retail volumes due to favorable weather and customer growth and Montana electric and natural gas interim rates (which are subject to refund). These favorable impacts were partly offset by higher operating expense (including depreciation and property taxes) and interest expense. The increase in per share earnings for the quarter was partially offset by equity issuances during the year, which increased average common shares outstanding. Equity issuances resulted in $0.09 of earnings per share dilution offsetting a $0.29 increase in earnings per share due to higher net income (a net $0.20 increase in diluted earnings per share for the quarter).

Non-GAAP Adjusted diluted earnings per share for the quarter was $1.13 as compared to $1.04 for the same period last year. See “Significant items not contemplated in Guidance” and “Non-GAAP Financial Measures” sections below for additional information on these measures, including a reconciliation of GAAP diluted earnings per share to Non-GAAP adjusted diluted earnings per share.

Financial Results

Reconciliation of Primary Changes from 2021 to 2022 Results

Significant Trends and Regulation

Regulatory Update

Rate Review Filings – On August 8, 2022, we filed a Montana electric and natural gas rate review filing (2021 test year) under Docket 2022.07.78. A summary of our requests within this rate review is below:

Within this rate review filing we requested an increase to the PCCAM base rate (PCCAM Base) of $68.1 million as well as structural revisions to the PCCAM mechanism to provide customers with prices that better reflect the cost of services received. We also proposed to implement a revised electric only pilot for the Fixed Cost Recovery Mechanism (FCRM) beginning July 1, 2023, or alternatively to terminate the FCRM. Our rate review filing also includes proposals for more timely cost recovery beyond the test period, including critical reliability resources, such as the Yellowstone County Generating Station, our Enhanced Wildfire Mitigation plan, and business technology maintenance costs.

Interim Rates – On September 28, 2022, the Montana Public Service Commission (MPSC) approved the recommendations of the MPSC Staff for interim rates, subject to refund, which increased base electric rates $29.4 million, PCCAM Base rates $61.1 million, and base natural gas rates $1.7 million, effective October 1, 2022.

Key dates in the procedural schedule are expected to be as follows:

• NorthWestern rebuttal testimony and cross-intervenor testimony – March 6, 2023

• Hearing commences – April 11, 2023

Montana PCCAM – The Montana PCCAM Base of $138.7 million, approved in 2019, no longer reflects an accurate current forecast of our normal fuel and power costs. The MPSC's September 28, 2022 decision approving interim rates, which are subject to refund, in our rate review included an increase to the PCCAM Base of $61.1 million, on an interim basis, effective October 1, 2022. As of December 31, 2022, we have under-collected our total Montana electric supply costs for the current July 2022 through June 2023 PCCAM year by approximately $44.8 million. Absent the interim rate PCCAM Base increase, as of December 31, 2022, our under-collected position would have been approximately $55.9 million. Under-collections are not reflected in customer bills and are not recovered until the subsequent power cost adjustment year, adversely affecting our cash flows and liquidity.

Under the PCCAM, under and over-collection of non-qualifying facility related net costs are allocated 90% to Montana customers and 10% to shareholders. For the twelve months ended December 31, 2022, we deferred $64.8 million of costs to be collected from customers (90% of the costs above base) and recorded a reduction in pre-tax earnings of $7.2 million (10% of the variance). For the twelve months ended December 31, 2021, we deferred $48.7 million of costs for future collection from customers and recorded a reduction in pre-tax earnings of $5.4 million.

Our electric supply from owned and long-term contracted resources is not adequate to meet our peak-demand needs. Because of this, the volatility of market prices for energy on peak-demand days, even if only for a few days in duration, exposes us to potentially significant market purchases that could negatively impact our results of operations and cash flows. See the Electric Resource Planning – Montana section below for how we are working to address this market exposure.

Holding Company Filings – On June 1, 2022, we filed a legal corporate restructuring application (Restructuring Plan) with the state commissions in Montana, South Dakota and Nebraska and the Federal Energy Regulatory Commission (FERC). Currently, our utility businesses are held in the same legal entity. Under the proposed Restructuring Plan, we would legally separate our Montana public utility business from our South Dakota and Nebraska public utility business and establish a holding company to hold the ownership interests of all of the subsidiaries. The purpose of the reorganization is to integrate our organizational structure to be more transparent and in line with the public utility industry.

The Restructuring Plan does not propose and we do not expect any procedural or substantive change in how the state public utility commissions regulate those services. Implementation of the Restructuring Plan is subject to receipt of all regulatory approvals. On July 26, 2022, the Nebraska Public Service Commission approved our Restructuring Plan application. On August 3, 2022, the South Dakota Public Utilities Commission approved the application. On November 29, 2022, the FERC approved the application. NorthWestern reached settlement terms with the intervenors in the Montana proceeding, and the MPSC is reviewing those terms.

Electric Resource Planning – Montana

Yellowstone County 175 MW plant – Construction at the site began in April 2022 with a current schedule that is expected to allow the plant to serve our Montana customers during 2024 with total construction costs of approximately $275.0 million ($154.9 million incurred through December 31, 2022).

On October 21, 2021, the Montana Environmental Information Center and the Sierra Club filed a lawsuit in Montana State Court, against the Montana Department of Environmental Quality and us, alleging that the environmental analysis conducted prior to issuance of the Yellowstone County Generating Station's air quality permit was inadequate. The Montana District Court judge held oral argument on June 20, 2022. We expect a decision in 2023. This lawsuit, as well as additional legal challenges related to the Yellowstone County Generating Station, could delay the project timing. Construction is ongoing while we are awaiting this decision.

Acquisition of Colstrip Interest – On January 16, 2023, we entered into a definitive agreement (the Avista Agreement) with Avista Corporation (Avista) to acquire Avista's 15 percent interest in each of Units 3 and 4 at the Colstrip Generating Station, a coal-fired, base-load electric generation facility located in Colstrip, Montana. The Avista Agreement provides that the purchase price will be $0 and that we will acquire Avista's interest effective December 31, 2025, subject to the satisfaction of the closing conditions contained within the Avista Agreement. Under the terms of this Avista Agreement, we will be responsible for operating costs starting on January 1, 2026; while Avista will retain responsibility for its pre-closing share of environmental and pension liabilities attributed to events or conditions existing prior to the closing of the transaction and for any future decommission and demolition costs associated with the existing facilities that comprise Avista's interest.

The Avista Agreement contains customary representations and warranties, covenants, and indemnification obligations, and the Avista Agreement is subject to customary conditions and approvals, including approval from the FERC. Closing is also conditioned on our ability to enter into a new coal supply agreement for Colstrip by December 31, 2024. Such coal supply agreement must provide a sufficient amount of coal to Colstrip to permit the generation of electric power by the maximum permitted capacity of the interest in Colstrip then held by us during the period from January 1, 2026 through, December 31, 2030.

Either party may terminate the Avista Agreement if any requested regulatory approval is denied or if the closing has not occurred by December 31, 2025 or if any law or order would delay or impair closing. The Avista Agreement may be subject to the exercise by other Colstrip owners of a right of first refusal set forth in the Ownership & Operation (O&O) Agreement. Should any other owners exercise such rights, we intend to exercise our right of first refusal under the O&O Agreement to the fullest extent permitted, and Avista has agreed that it will not exercise its right of first refusal.

The acquisition of an additional interest under this Avista Agreement in 2026 will provide capacity to help us meet our obligation to provide reliable and cost effective power to our customers in Montana, while allowing opportunity for us to identify and plan for newer technologies to provide reliable, affordable and carbon free power through our Integrated Resource Planning process.

Future Integrated Resource Planning – Resource adequacy in the Western third of the U.S. has been declining with the retirement of thermal power plants. Our owned and long-term contracted resources are inadequate to supply the necessary capacity we require to meet our peak-demand loads, which exposes us to large quantities of market purchases at typically high and volatile energy prices. To comply with regulatory resource planning requirements, we expect to submit an integrated resource plan to the MPSC by the end of March 2023.

We remain concerned regarding an overall lack of capacity in the West and our owned and long-term contracted capacity deficit to meet peak-demand loads. The construction of the Yellowstone County Generating Station and acquisition of Avista's Colstrip Units 3 and 4 interests, as discussed above, will reduce our exposure to market purchases at typically high and volatile energy prices.

Electric Resource Supply – South Dakota

Our new Bob Glanzer Generating Station was operational as of May 27, 2022. The 58 MW natural gas plant is located in Huron, South Dakota.

Our electric supply resource plans for South Dakota continue to identify portfolio requirements including potential investments resulting from a completed competitive solicitation process. We filed an updated integrated resource plan on September 6, 2022, which is consistent with the prior plan laying out a retire-and-replace generation asset strategy. A decision on what process to use, and what type of generation technology to add, is expected to be made in the first half of 2023.

Supply Chain and Inflation Challenges

We place significant reliance on our third-party business partners to supply materials, equipment and labor necessary for us to operate our utility and reliably serve current customers and future customers. As a result of current macroeconomic conditions, both nationally and globally, we have recently experienced issues with our supply chain for materials and components used in our operations and capital project construction activities. Issues include higher prices, scarcities/shortages, longer fulfillment times for orders from our suppliers, workforce availability, and wage increases. Should challenges with product and services availability and price inflation continue, we could have difficulty timely completing the operations activities necessary to serve our customers safely and reliably, and/or achieving our capital investment program, which ultimately could result in higher customer utility rates, longer outages, and could have a material adverse impact on our business, financial condition and operations.

Enhanced Wildfire Mitigation

With changing weather conditions which include more significant wind events, drought conditions, and warmer air temperatures, we do not consider the fire season specific to a time of year, but rather a condition that may exist at any time of year. Each year’s weather conditions impact these situations differently: early season rains encourage plant growth which fuels fires later in the growing season, and winters with little snow leave dry plant material available for late season fires. The threat is not only in forested areas, where insect infestations and resulting tree death has been severe, but across the entire system including rural areas where grassland fires could be ignited, along with urban areas where extreme weather conditions pose a great risk to heavily populated areas.

Recognizing the risk of significant wildfires in Montana, we continue to proactively seek to mitigate wildfire risk. We have developed an Enhanced Wildfire Mitigation Plan addressing five key areas: situational awareness, operational practices, system preparedness, vegetation management, and public communications and outreach. This plan builds upon several key initiatives that were initiated and executed over the past decade including nearly $80 million spent on vegetation management and hazard tree removal programs and our growing annual investment to harden our transmission and distribution system infrastructure. Because of ever-increasing wildfire risk, our plan includes greater focus on situational awareness to monitor changing environmental conditions, operational practices that are more reactive to changing conditions, increased frequency of patrol and repairs, and more robust system hardening programs that target higher risk segments in our transmission and distribution systems. We included a request for expected costs associated with the mitigation plan in our 2022 Montana rate review.

Earnings Drivers

Gross Margin

Consolidated gross margin in 2022 was $376.9 million as compared with $377.7 million in 2021, a decrease of $0.8 million or 0.2 percent. This decrease was primarily due to lower transmission revenues due to the prior year recognition of deferred transmission revenue and lower prices, a less favorable QF liability adjustment as compared to the prior year, higher operating and maintenance expense, and higher depreciation and depletion, partly offset by higher electric and natural gas retail volumes due to favorable weather and customer growth and the interim rate increase, which is subject to refund.

Utility Margin⁽¹⁾

Consolidated utility margin in 2022 was $985.8 million as compared with $946.8 million in 2021, an increase of $39.0 million, or 4.1 percent. Primary components of the change in utility margin include the following:

Higher electric retail volumes were driven by overall favorable weather in all jurisdictions and customer growth. Higher natural gas retail volumes were driven by favorable weather in all jurisdictions and customer growth. Interim rates in our Montana rate review were effective October 1, 2022, and are subject to refund pending an outcome in the proceeding.

The less favorable adjustment to our electric QF liability (unrecoverable costs associated with PURPA contracts as part of a 2002 stipulation with the MPSC and other parties) reflects a $5.1 million gain in 2022, as compared with a $7.5 million gain for the same period in 2021, due to the combination of:

• A $1.8 million favorable reduction in costs for the current contract year to record the annual adjustment for actual output and pricing as compared with a $2.6 million favorable reduction in costs in the prior period;

• A favorable adjustment, decreasing the QF liability by $3.3 million, reflecting annual actual contract price escalation for the 2022-2023 contract year, which was less than previously estimated, partly offset by an increase in estimated contract prices for the 2023-2024 contract year, which is the last year of the contract that contains variable pricing terms. This is compared to an unfavorable adjustment of $2.1 million in the prior year due to higher actual price escalation; and

• A favorable adjustment in the prior year, decreasing the QF liability by approximately $7.0 million, associated with a one-time clarification in contract term.
  

Operating, General and Administrative Expenses

Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $722.7 million in 2022, as compared with $671.1 million in 2021. Primary components of the change include the following:

Operating Income

Consolidated operating income in 2022 was $263.1 million as compared with $275.7 million in 2021. This decrease was primarily due to lower transmission revenues due to the prior year recognition of deferred transmission revenue and lower prices, a less favorable QF liability adjustment as compared to the prior year, higher operating and maintenance expense, higher administrative and general expense, higher property tax expense, and higher depreciation and depletion, partly offset by higher electric and natural gas retail volumes due to favorable weather and customer growth, and the interim rate increase, which is subject to refund pending an outcome in the proceeding.

Interest Expense

Consolidated interest expense in 2022 was $100.1 million, as compared with $93.7 million in 2021. This increase was primarily due to higher interest rates on borrowings under our revolving credit facilities partly offset by higher capitalization of allowance for funds used during construction (AFUDC).

Other Income

Consolidated other income in 2022 was $19.4 million, as compared with $8.3 million in 2021. This increase was primarily due to a decrease in the non-service cost component of pension expense and higher capitalization of AFUDC, partly offset by a $2.5 million Montana Community Renewable Energy Projects (CREP) penalty, 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.

Income Tax

Consolidated income tax benefit in 2022 was $0.6 million, as compared to an income tax expense of $3.4 million in 2021. Our effective tax rate for the twelve months ended December 31, 2022 was (0.3) percent as compared with 1.8 percent for the same period of 2021.

The following table summarizes the differences between our effective tax rate and the federal statutory rate:

Our effective tax rate typically differs from the federal statutory tax rate primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable) and production tax credits.

Net Income

Consolidated net income in 2022 was $183.0 million as compared with $186.8 million in 2021, a decrease of $3.8 million. This decrease was primarily due to higher operating costs, higher depreciation expense, higher interest expense, higher property taxes that were not offset in revenues, lower transmission revenues due to the prior year recognition of deferred transmission revenue and lower prices, and a less favorable QF liability adjustment as compared to the prior year, partly offset by higher electric and natural gas retail volumes due to favorable weather and customer growth and higher Montana electric and natural gas interim rate revenue, which is subject to refund.

Liquidity and Capital Resources

As of December 31, 2022, our total net liquidity was approximately $108.5 million, including $8.5 million of cash and $100.0 million of revolving credit facility availability with no letters of credit outstanding. This compares to total net liquidity one year ago at December 31, 2021 of $79.8 million.

Dividend Declared

NorthWestern's Board of Directors declared a quarterly common dividend of $0.64 per share (a 1.6% increase over the prior quarter's dividend) payable March 31, 2023 to common shareholders of record as of March 15, 2023. Over the longer-term, we expect to maintain a dividend payout ratio within a targeted 60-70% range.

Significant items not contemplated in Guidance

We reported GAAP earnings of $3.25 per diluted share for the year-ended December 31, 2022 and $3.60 per diluted share for the same period in 2021. Adjusted Non-GAAP earnings per diluted share for the same periods are $3.18 and $3.51, respectively. A reconciliation of items not factored into our Adjusted Non-GAAP diluted earnings per share are summarized below. The amount below represents a non-GAAP measure that may provide users of this data with additional meaningful information regarding the impact of certain items on our expected earnings. More information on this measure can be found in the "Non-GAAP Financial Measures" section below.

Revision to non-GAAP weather normalization method – Up to, and including, Q3 2022, our weather normalizing adjustment included the estimated impact from four customer classes; commercial electric, residential electric, commercial natural gas and residential natural gas. Due to a statistically low correlation coefficient of our commercial electric customers’ usage patterns, we will no longer include a weather normalizing adjustment for this customer class. As a result, the weather adjustment in the fourth quarter reflects the reversal of the first three quarters of commercial electric customer impact (eliminating the commercial electric impact for the year). See table that follows.

2023 Earnings Guidance and Capital Expenditures Forecast

NorthWestern expects to issue 2023 earnings guidance following an outcome in the currently pending Montana general rate review. Our estimated capital expenditures for 2023 are $510 million. Over the next five years (2023 to 2027) we estimate investment of $2.4 billion in our electric and natural gas transmission and distribution and electric generation infrastructure.

Company Hosting Investor Webinar

NorthWestern will host an investor webinar on Friday, February 17, 2023, at 3:30 p.m. Eastern time to review its financial results for the year ending December 31, 2022.

To register for the webinar, please visit www.northwesternenergy.com/earnings-registration. Please go to the site at least 15 minutes in advance of the webinar to register. An archived webcast will be available shortly after the event and remain active for one year.

NorthWestern Energy – Delivering a Bright Future

NorthWestern Corporation, doing business as NorthWestern Energy, provides essential energy infrastructure and valuable services that enrich lives and empower communities while serving as long-term partners to our customers and communities. We work to deliver safe, reliable, and innovative energy solutions that create value for customers, communities, employees, and investors. We do this by providing low-cost and reliable service performed by highly-adaptable and skilled employees. We provide electricity and / or natural gas to approximately 764,200 customers in Montana, South Dakota, Nebraska, and Yellowstone National Park. We have provided service in South Dakota and Nebraska since 1923 and in Montana since 2002.

Non-GAAP Financial Measures

This press release 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 the press release above.

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.

Special Note Regarding Forward-Looking Statements

This press release contains forward-looking statements within the meaning of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, including, without limitation, the information under "Significant Items Not Contemplated in Earnings." Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. We caution that while we make such statements in good faith and believe such statements are based on reasonable assumptions, including without limitation, management's examination of historical operating trends, data contained in records and other data available from third parties, we cannot assure you that we will achieve our projections. Factors that may cause such differences include, but are not limited to:

• adverse determinations by regulators, as well as potential adverse federal, state, or local legislation or regulation, including costs of compliance with existing and future environmental requirements, could have a material effect on our liquidity, results of operations and financial condition;

• the impact of extraordinary external events and natural disasters, such as a wide-spread or global pandemic, geopolitical events, earthquake, flood, drought, lightning, weather, wind, and fire, could have a material effect on our liquidity, results of operations and financial condition;

• acts of terrorism, cybersecurity attacks, data security breaches, or other malicious acts that cause damage to our generation, transmission, or distribution facilities, information technology systems, or result in the release of confidential customer, employee, or Company information;

• supply chain constraints, recent high levels of inflation for product, services and labor costs, and their impact on capital expenditures, operating activities, and/or our ability to safely and reliably serve our customers;

• changes in availability of trade credit, creditworthiness of counterparties, usage, commodity prices, fuel supply costs or availability due to higher demand, shortages, weather conditions, transportation problems or other developments, may reduce revenues or may increase operating costs, each of which could adversely affect our liquidity and results of operations;

• unscheduled generation outages or forced reductions in output, maintenance or repairs, which may reduce revenues and increase operating costs or may require additional capital expenditures or other increased operating costs; and

• adverse changes in general economic and competitive conditions in the U.S. financial markets and in our service territories.
  

Our 2022 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, reports on Form 8-K and other Securities and Exchange Commission filings discuss some of the important risk factors that may affect our business, results of operations and financial condition. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.