NorthWestern Energy Group, Inc. (NWE) FY 2023 MD&A

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following includes a discussion of our results of operations and cash flows for the year ended December 31, 2023 compared to the year ended December 31, 2022, on both a consolidated basis and on a segment basis. For a discussion of our financial results and cash flows for the year ended December 31, 2022 compared with the year ended December 31, 2021, see Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2022.

This discussion should be read in conjunction with our Consolidated Financial Statements and related notes contained elsewhere in this Annual Report on Form 10-K. For additional information related to our segments, see Note 20 - Segment and Related Information, to the Consolidated Financial Statements.

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Utility Margin, that is considered a “non-GAAP financial measure.” 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. The following discussion includes a reconciliation of Utility Margin to Gross Margin, the most directly comparable GAAP measure.

We believe 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 for 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.

OVERVIEW

NorthWestern Energy Group, doing business as NorthWestern Energy, provides electricity and/or natural gas to approximately 775,300 customers in Montana, South Dakota, Nebraska, and Yellowstone National Park. Our operations in Montana and Yellowstone National Park are conducted through our subsidiary, NW Corp, and our operations in South Dakota and Nebraska are conducted through our subsidiary, NWE Public Service. As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 2023, 2022 and 2021. Following is a discussion of our strategy and significant trends.

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 are focused on delivering long-term shareholder value through:

•Infrastructure investment focused on a stronger and smarter grid to improve the customer experience, while enhancing grid reliability and safety. This includes automation in customer meters, distribution and substations that enables the use of proven new technologies.

•Investing in and integrating supply resources that balance reliability, cost, capacity, and sustainability considerations with more predictable long-term commodity prices.

•Continually improving our operating efficiency. Financial discipline is essential to earning our authorized return on invested capital and maintaining a strong balance sheet, stable cash flows, and quality credit ratings to continue to attract cost-effective capital for future investment.

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We expect to pursue these investment opportunities and manage our business in a manner that allows us to be flexible in adjusting to changing economic conditions by adjusting the timing and scale of the projects.

In 2023, approximately 55 percent of our retail needs from our owned and long-term contracted resources originated from carbon-free resources, compared to approximately 40 percent for the total U.S. electric power industry. We are committed to providing customers with reliable and affordable electric and natural gas services while also being good stewards of the environment. Towards this end, our efforts towards a carbon-free future are outlined through our goal to achieve net zero carbon emissions by 2050. Our vision for the future builds on the progress we have made, including our hydroelectric system in Montana, which is 100 percent carbon free and is readily available capacity. For us, wind generation is a close second and continues to grow. While utility-scale solar energy has not been a significant portion of our energy mix to date, we recently entered into power purchase agreements with two solar projects totaling 160-megawatts that began delivering energy to our Montana customers in 2023. We expect solar to further evolve along with advances in energy storage. We are committed to working with our customers and communities to help them achieve their sustainability goals and add new technology on our system.

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HOW WE PERFORMED IN 2023 COMPARED TO OUR 2022 RESULTS

(1) Exclusive of depreciation and depletion shown separately below

(2) Excluding fuel, purchased supply, and direct transmission expense

Consolidated net income in 2023 was $194.1 million as compared with $183.0 million in 2022. This increase was primarily due to new base rates resulting from the Montana rate review, lower non-recoverable Montana electric supply costs, higher Montana property tax tracker collections, and lower property and other taxes not recoverable within trackers, partly offset by lower electric and natural gas retail volumes, higher depreciation and depletion expense, higher interest expense, higher operating, maintenance, and administrative expenses, and higher income tax expense.

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SIGNIFICANT TRENDS AND REGULATION

Regulatory Update

Rate reviews are necessary to recover the cost of providing safe, reliable service, while contributing to earnings growth and achieving our financial objectives. We regularly review the need for electric and natural gas rate relief in each state in which we provide service.

Montana Rate Review Filing – On October 27, 2023, the MPSC issued a final order approving the settlement agreement filed April 3, 2023. Final rates, adjusting from interim to settled rates, were effective November 1, 2023. For additional information related to our Montana Rate Review Filing, see Note 3 - Regulatory Matters to the Consolidated Financial Statements.

South Dakota Electric Rate Review Filing – In June 2023, we filed a South Dakota electric rate review filing (2022 test year) for an annual increase to electric rates totaling approximately $30.9 million. Our request was based on a rate of return of 7.54 percent, a capital structure including 50.5 percent equity, and rate base of $787.3 million. In January 2024, the SDPUC issued a final order approving the settlement agreement between NorthWestern and SDPUC Staff for an annual increase in base rates of approximately $21.5 million and an authorized rate of return of 6.81 percent. The approved settlement is based on a capital structure of 50.5 percent equity and a rate base of $791.8 million. Final rates were effective January 10, 2024. In addition, the SDPUC approved a phase in rate plan rider that allows for the recovery of capital investments not yet included in base rates.

Holding Company Reorganization – On October 2, 2023, NW Corp and NorthWestern Energy Group completed a merger transaction pursuant to which NorthWestern Energy Group became the holding company parent of NW Corp. In this reorganization, shareholders of NW Corp (the predecessor publicly held parent company) became shareholders of NorthWestern Energy Group, maintaining the same number of shares and ownership percentage as held in NW Corp immediately prior to the reorganization. NW Corp became a wholly-owned subsidiary of NorthWestern Energy Group. The transaction was effected pursuant to a merger pursuant to Section 251(g) of the General Corporation Law of the State of Delaware, which provides for the formation of a holding company without a vote of the shareholders of the constituent corporation. Immediately after consummation of the reorganization, NorthWestern Energy Group had, on a consolidated basis, the same assets, businesses and operations as NW Corp had immediately prior to the consummation of the reorganization. As a result of the reorganization, NorthWestern Energy Group became the successor issuer to NW Corp pursuant to Rule 12g-3(a) of the Securities Exchange Act of 1934, and as a result, NorthWestern Energy Group's common stock was deemed registered under Section 12(b) of the Securities Exchange Act of 1934. On January 1, 2024, we completed the second and final phase of the holding company reorganization. NW Corp contributed the assets and liabilities of its South Dakota and Nebraska regulated utilities to NWE Public Service, and then distributed its equity interest in NWE Public Service and certain other subsidiaries to NorthWestern Energy Group, resulting in NW Corp owning and operating the Montana regulated utility and NWE Public Service owning and operating the Nebraska and South Dakota utilities, each as a direct subsidiary of NorthWestern Energy Group.

Power Costs and Credits Adjustment Mechanism - The MPSC's September 2022 decision approving interim rates related to our Montana rate review included a $61.1 million increase to the PCCAM Base, from $138.7 million to $199.8 million, effective October 1, 2022. The MPSC's October 2023 decision approving the Montana rate review settlement agreement increased the PCCAM Base to $208.4 million, with retroactive application to July 1, 2022. We have under-collected our total Montana electric supply costs for the July 2022 through June 2023 PCCAM year by approximately $14.5 million, which includes a $2.9 million increase to our under-collection for this tracker period to reflect the retroactive application of the higher PCCAM Base rates effective July 1, 2022. As of December 31, 2023, we have over-collected our total Montana electric supply costs for the July 2023 through June 2024 PCCAM year by approximately $4.7 million.

Under the PCCAM, net costs higher or lower than the PCCAM Base (excluding QF costs) are allocated 90 percent to Montana customers and 10 percent to shareholders. For the twelve months ended December 31, 2023, we over collected supply costs of $32.9 million resulting in a reduction to our under collection of costs, and recorded an increase in pre-tax earnings of $7.0 million (10 percent of the PCCAM Base cost variance), which is inclusive of a $3.2 million increase in pre-tax earnings related to the retroactive application of higher PCCAM Base rates to July 1, 2022. For the twelve months ended December 31, 2022, we under collected costs of $64.8 million resulting in an increase to the under collection of costs, and recorded a reduction in pre-tax earnings of $7.2 million.

As discussed above, the approved Montana rate review settlement provides for an update to the PCCAM by adjusting the base costs from $138.7 million to $208.4 million and providing for more timely quarterly recovery of deferred balances instead of annual recovery. The updated $208.4 million PCCAM Base is retroactive to an effective date of July 1, 2022.

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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.

Electric Resource Planning - Montana

Yellowstone County 175 MW plant - Construction of the new generation facility continues to progress and we expect the plant to be operational no later than the end of the third quarter 2024. The lawsuit challenging the YCGS air quality permit, which required us to suspend construction activities for a period of time, as well as additional related legal and construction challenges, delayed the project timing and have increased costs. As of December 31, 2023, total costs of approximately $240.0 million have been incurred, with expected total costs of approximately $310.0 million to $320.0 million. See Note 18 - Commitments and Contingencies to the Consolidated Financial Statements included herein for additional information regarding legal challenges impacting YCGS.

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 also is 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 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 IRP 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 submitted an IRP to the MPSC on April 28, 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 are expected to reduce our exposure to market purchases.

Proposed EPA Rules

In May 2023, the EPA proposed new GHG emissions standards for coal and natural gas-fired plants. In particular, the proposed rules would (i) strengthen the current New Source Performance Standards for newly built fossil fuel-fired stationary combustion turbines (generally natural gas-fired); (ii) establish emission guidelines for states to follow in limiting carbon pollution from existing fossil fuel-fired steam generating electric generating units (including coal, oil and natural gas-fired units); and (iii) establish emission guidelines for large, frequently used existing fossil fuel-fired stationary combustion turbines (generally natural gas-fired). In addition, in April 2023, EPA proposed to amend the MATS. Among other things, MATS currently sets stringent emission limits for acid gases, mercury, and other hazardous air pollutants from new and existing electric generating units. We are in compliance with existing MATS requirements. The proposed amendment of the MATS would strengthen the MATS requirements, and if adopted as written, both the GHG and MATS proposed rules could have a material negative impact on our coal-fired plants, including requiring potentially expensive upgrades or the early retirement of Colstrip Unit's 3 and 4 due to the rules making the facility uneconomic.

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Previous efforts by the EPA were met with extensive litigation and we anticipate a similar response if the proposed rules are adopted. As MATS and GHG regulations are implemented, it could result in additional material compliance costs. We will continue working with federal and state regulatory authorities, other utilities, and stakeholders to seek relief from any MATS or GHG regulations that, in our view, disproportionately impact customers in our region.

Electric Resource Supply - 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 anticipate filing the next resource plan in the summer of 2024.

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SIGNIFICANT INFRASTRUCTURE INVESTMENTS AND INITIATIVES

Our estimated capital expenditures for the next five years, including our electric and natural gas transmission and distribution and electric generation infrastructure investment plan, are as follows (in millions):

Electric Supply Resource Plans - Our energy resource plans identify portfolio resource requirements including potential investments. For additional information related to our electric supply resource plans, see Item 1. Business, where we discuss electric resource planning for our Montana and South Dakota jurisdictions.

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. Over $1.8 billion or 75 percent of our capital forecast above is projected to be spent on our distribution and transmission system. Beginning in 2021, and continuing through 2025, we expect to install automated metering infrastructure in Montana at a total cost of approximately $134.0 million, of which $41.7 million remains and is reflected in the five year capital forecast above.

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RESULTS OF OPERATIONS

Our consolidated results include the results of our divisions and subsidiaries constituting each of our business segments. The overall consolidated discussion is followed by a detailed discussion of utility margin by segment.

Factors Affecting Results of Operations

Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.

Revenues are also impacted by customer growth and usage, the latter of which is primarily affected by weather and the impact of energy efficiency initiatives and investment. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers. We measure this effect using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.

Fuel, purchased supply and direct transmission expenses are costs directly associated with the generation and procurement of electricity and natural gas. These costs are generally collected in rates from customers and may fluctuate substantially with market prices and customer usage.

Operating and maintenance expenses are costs associated with the ongoing operation of our vertically-integrated utility facilities which provide electric and natural gas utility products and services to our customers. Among the most significant of these costs are those associated with direct labor and supervision, repair and maintenance expenses, and contract services. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in volumes.

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OVERALL CONSOLIDATED RESULTS

Year Ended December 31, 2023 Compared with Year Ended December 31, 2022

Consolidated net income in 2023 was $194.1 million as compared with $183.0 million in 2022, an increase of $11.1 million. As described in more detail below, this increase was primarily due to new base rates resulting from the Montana rate review, lower non-recoverable Montana electric supply costs, higher Montana property tax tracker collections, and lower property and other taxes not recoverable within trackers, partly offset by lower electric and natural gas retail volumes, higher depreciation and depletion expense, higher interest expense, higher operating, maintenance, and administrative expenses, and higher income tax expense.

Consolidated gross margin in 2023 was $416.3 million as compared with $376.9 million in 2022, an increase of $39.4 million or 10.5 percent. This increase was primarily due to new base rates resulting from the Montana rate review, lower non-recoverable Montana electric supply costs, higher Montana property tax tracker collections, and lower property and other taxes not recoverable within trackers, partly offset by lower electric and natural gas retail volumes, higher depreciation and depletion expense, and higher operating and maintenance expense.

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

Consolidated utility margin in 2023 was $1,001.9 million as compared with $985.8 million in 2022, an increase of $16.1 million, or 1.6 percent.

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Primary components of the change in utility margin include the following (in millions):

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above.

Lower non-recoverable Montana electric supply costs were driven by higher electric supply revenues, lower electric supply costs, and $3.2 million for the retroactive application of higher PCCAM base rates approved in the Montana rate review.

Lower electric retail volumes were driven by unfavorable weather in Montana impacting residential demand and lower commercial demand as compared to the prior year, partly offset by customer growth. Lower natural gas retail volumes were driven by unfavorable weather in Montana, partly offset by favorable weather in Nebraska and customer growth.

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Consolidated operating expenses, excluding fuel, purchased supply and direct transmission expense, were $701.4 million in 2023, as compared with $722.7 million in 2022. Primary components of the change include the following (in millions):

(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.

Consolidated operating income in 2023 was $300.5 million as compared with $263.1 million in 2022. This increase was primarily due to new base rates resulting from the Montana rate review, lower non-recoverable Montana electric supply costs, higher Montana property tax tracker collections, and lower property and other taxes not recoverable within trackers, partly offset by lower electric and natural gas retail volumes, higher depreciation and depletion expense, and higher operating, maintenance, and administrative expense.

Consolidated interest expense in 2023 was $114.6 million, as compared with $100.1 million in 2022. This increase was due to higher borrowings and interest rates, partly offset by higher capitalization of AFUDC.

Consolidated other income in 2023 was $15.8 million, as compared with $19.4 million in 2022. This decrease was primarily due to an increase in the non-service cost component of pension expense, partly offset by the prior year CREP penalty and higher capitalization of AFUDC.

Consolidated income tax expense in 2023 was $7.5 million, as compared to an income tax benefit of $0.6 million in 2022. Our effective tax rate for the twelve months ended December 31, 2023 was 3.7 percent as compared with (0.3) percent for the same period of 2022. Income tax expense for the twelve months ended December 31, 2023, includes a one-time $3.2 million expense for the reduction of previously claimed alternative minimum tax credits as well as a $3.2 million benefit related to a reduction in our unrecognized tax benefits. We currently estimate our effective tax rate will range between 12.0 percent to 14.0 percent in 2024. Based on the significant NOL we generated during the year ended December 31, 2023, we anticipate paying minimal cash for income taxes into 2028.

The following table summarizes the differences between our effective tax rate and the federal statutory rate (in millions):

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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.

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ELECTRIC OPERATIONS

We have various classifications of electric revenues, defined as follows:

•Retail: Sales of electricity to residential, commercial and industrial customers, and the impact of regulatory mechanisms.

•Regulatory amortization: Primarily represents timing differences for electric supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expense and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.

•Transmission: Reflects transmission revenues regulated by the FERC.

•Wholesale and other are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expense.

Year Ended December 31, 2023 Compared with Year Ended December 31, 2022

(1) Exclusive of depreciation and depletion.

(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.

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The following summarizes the components of the changes in electric utility margin for the years ended December 31, 2023 and 2022 (in millions):

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

Lower non-recoverable Montana electric supply costs were driven by higher electric supply revenues, lower electric supply costs, and $3.2 million for the retroactive application of higher PCCAM base rates approved in the Montana rate review.

Lower retail volumes were driven by unfavorable weather in Montana impacting residential demand and lower commercial demand as compared to the prior year, partly offset by customer growth.

The adjustment to our electric QF liability (unrecoverable costs associated with contracts covered by the Public Utility Regulatory Policies Act of 1978 (PURPA) as part of a 2002 stipulation with the MPSC and other parties) reflects a $5.0 million gain in 2023, as compared with a $5.1 million gain for the same period in 2022, due to the combination of:

•A $0.8 million favorable reduction in costs for the current contract year to record the annual adjustment for actual output and pricing as compared with a $1.8 million favorable reduction in costs in the prior period; and

•A favorable adjustment, decreasing the QF liability by $4.2 million, reflecting annual actual contract price escalation for the 2023-2024 contract year, which was less than previously estimated. The 2023-2024 contract year is the last year of the contract that contains variable pricing terms. This is compared to a favorable adjustment of $3.3 million in the prior year due to less than previously estimated actual price escalation.

The change in regulatory amortization revenue is due to timing differences between when we incur electric supply costs and when we recover these costs in rates from our customers, which has a minimal impact on utility margin. Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.

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NATURAL GAS OPERATIONS

We have various classifications of natural gas revenues, defined as follows:

•Retail: Sales of natural gas to residential, commercial and industrial customers, and the impact of regulatory mechanisms.

•Regulatory amortization: Primarily represents timing differences for natural gas supply costs and property taxes between when we incur these costs and when we recover these costs in rates from our customers, which is also reflected in fuel, purchased supply and direct transmission expenses and therefore has minimal impact on utility margin. The amortization of these amounts are offset in retail revenue.

•Wholesale: Primarily represents transportation and storage for others.

Year Ended December 31, 2023 Compared with Year Ended December 31, 2022

(1) Exclusive of depreciation and depletion.

(2) Non-GAAP financial measure. See “Non-GAAP Financial Measure” above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

(1) Montana electric and natural gas heating degree days may differ due to differences in service territory.

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The following summarizes the components of the changes in natural gas utility margin for the years ended December 31, 2023 and 2022 (in millions):

(1) Non-GAAP financial measure. See "Non-GAAP Financial Measure" above. Also see "Overall Consolidated Results" above for reconciliation of gross margin to utility margin.

Lower retail volumes were driven by unfavorable weather in Montana, partly offset by favorable weather in Nebraska and customer growth.

Our wholesale and other revenues are largely utility margin neutral as they are offset by changes in fuel, purchased supply and direct transmission expenses.

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LIQUIDITY AND CAPITAL RESOURCES

Liquidity

We require liquidity to support and grow our business, and use our liquidity for working capital needs, capital expenditures, investments in or acquisitions of assets, and to repay debt. For NorthWestern Energy Group, liquidity is primarily provided through its revolving credit facility and dividends from its utility operating subsidiaries, NW Corp and NWE Public Service. These subsidiaries are subject to certain restrictions that may limit the amount of their dividend distributions. See Note 16 - Common Stock to the Consolidated Financial Statements for more information regarding these dividend restrictions.

We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future utility rate increases should be sufficient to fund our operations, service existing debt, pay dividends, and fund capital expenditures. We plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases, and expect to continue targeting a long-term dividend payout ratio of 60 - 70 percent of earnings per share; however, there can be no assurance that we will be able to meet these targets.

As of December 31, 2023, our total consolidated net liquidity was approximately $241.2 million, including $9.2 million of cash and $232.0 million of revolving credit facility availability with no letters of credit outstanding.

Cash Flows

The following table summarizes our consolidated cash flows (in millions):

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Operating Activities

As of December 31, 2023, cash, cash equivalents, and restricted cash were $25.2 million as compared with $22.5 million as of December 31, 2022. Cash provided by operating activities totaled $489.2 million for the year ended December 31, 2023 as compared with $307.2 million for the year ended December 31, 2022. As shown in the table below, this increase in operating cash flows is primarily due to a $123.9 million improvement in net cash inflows for previously uncollected energy supply costs and interim and final rates from our Montana rate review.

As discussed above, on October 27, 2023 the MPSC issued their final order approving our Montana rate review settlement which included an update to the PCCAM by adjusting the base costs from $138.7 million to $208.4 million and providing for more timely quarterly recovery of deferred balances instead of annual recovery. The updated $208.4 million PCCAM Base is retroactive to an effective date of July 1, 2022. As of December 31, 2023, we have under-collected our total Montana electric supply costs for the July 2022 through June 2023 PCCAM year by approximately $14.5 million that we began collecting in October 2023. As of December 31, 2023, we have over-collected our total Montana electric supply costs for the July 2023 through June 2024 PCCAM year by approximately $4.7 million.

With the adjusted PCCAM Base, we anticipate continued improvements in our cash flows from operations. However, continued higher overall market prices, which could be further exacerbated by extreme weather events, could create additional costs with deferred recovery that would offset these anticipated cash flow improvements.

Investing Activities

Cash used in investing activities totaled $570.8 million during the year ended December 31, 2023, as compared with $516.8 million during 2022. Plant additions during 2023 include capital maintenance additions of approximately $321.9 million and capacity related capital expenditures of approximately $245.0 million. Plant additions during 2022 included capital maintenance additions of approximately $295.4 million and capacity related capital expenditures of approximately $219.7 million. As discussed above in the “Significant Infrastructure Investments and Initiatives” section, our capital expenditures are forecasted to be $500 million in 2024.

Financing Activities

Cash provided by financing activities totaled $84.3 million during the year ended December 31, 2023 as compared with $213.3 million during the year ended December 31, 2022. During the year ended December 31, 2023, cash provided by financing activities reflects net proceeds from the issuance of debt of $300.0 million and proceeds received from the issuance of common stock of $73.6 million, partly offset by payment of dividends of $154.1 million and net repayments under our revolving lines of credit of $132.0 million. During the year ended December 31, 2022, cash provided by financing activities reflects proceeds received from the issuance of common stock of $277.0 million and net issuances under our revolving lines of credit of $77.0 million, partly offset by payment of dividends of $140.1 million.

Cash Requirements and Capital Resources

We believe our cash flows from operations, existing borrowing capacity, debt and equity issuances and future rate increases should be sufficient to satisfy our material cash requirements over the short-term and the long-term. As a rate-regulated utility our customer rates are generally structured to recover expected operating costs, with an opportunity to earn a return on our invested capital. This structure supports recovery for many of our operating expenses, although there are situations where the timing of our cash outlays results in increased working capital requirements. Due to the seasonality of our utility business, our short-term working capital requirements typically peak during the coldest winter months and warmest summer months when we cover the lag between when purchasing energy supplies and when customers pay for these costs. Our credit facilities may also be utilized for funding cash requirements during seasonally active construction periods, with peak activity during warmer months. Our cash requirements also include a variety of contractual obligations as outlined below in the “Contractual Obligations and Other Commitments” section.

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Our material cash requirements are also related to investment in our business through our capital expenditure program, which is discussed above in the “Significant Infrastructure Investments and Initiatives” section. Our capital expenditures are forecasted to be $500 million in 2024, $506 million in 2025, and $463 million in 2026. We anticipate funding capital expenditures through cash flows from operations, available credit sources, debt issuances and future rate increases. The actual amount of capital expenditures is subject to certain factors including the impact that a material change in operations, available financing, supply chain issues, or inflation could impact our current liquidity and ability to fund capital resource requirements. Events such as these could cause us to defer a portion of our planned capital expenditures, as necessary. To fund our strategic growth opportunities, we evaluate the additional capital need in balance with debt capacity and equity issuances that would be intended to allow us to maintain investment grade ratings.

Credit Facilities

Liquidity is generally provided by internal operating cash flows and the use of our unsecured revolving credit facilities. We utilize availability under our revolving credit facilities to manage our cash flows due to the seasonality of our business and to fund capital investment. Cash on hand in excess of current operating requirements is generally used to invest in our business and reduce borrowings.

For further information on our credit facilities, see Note 10 - Unsecured Credit Facilities to the Consolidated Financial Statements included herein.

The following table presents additional information about borrowings under our revolving credit facilities during the year ended December 31, 2023 (in millions):

As discussed further within Note 10 - Unsecured Credit Facilities, our credit facility availability as of December 31, 2023 was $232.0 million. With the completion of the holding company reorganization and associated restructuring of our credit facilities on January 1, 2024, our total credit facility availability increased by $50.0 million to $282.0 million.

As of February 9, 2024, availability under our revolving credit facilities was approximately $325.0 million, and there were no letters of credit outstanding.

Long-term Debt and Equity

We generally issue long-term debt to refinance other long-term debt maturities and borrowings under our revolving credit facilities, as well as to fund long-term capital investments and strategic opportunities. We have $100 million of debt maturing in 2024, which we intend to refinance.

For further information on our long-term debt, see Note 11 - Long-Term Debt and Finance Leases to the Consolidated Financial Statements included herein.

We generally issue equity securities to fund long-term investment in our business. We evaluate our equity issuance needs to support our plan to maintain a 50 - 55 percent debt to total capital ratio excluding finance leases.

For further information regarding equity, see Note 16 - Common Stock to the Consolidated Financial Statements included herein.

Credit Ratings

In general, less favorable credit ratings make debt financing more costly and more difficult to obtain on terms that are favorable to us and our customers, may impact our trade credit availability, and could result in the need to issue additional equity securities. Fitch Ratings (Fitch), Moody's Investors Service (Moody's), and S&P Global Ratings (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate the agencies’ assessment of our ability to pay interest and principal when due on our debt. As of February 9, 2024, our current ratings with these agencies are as follows:

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(1) This Fitch Issuer Rating represents the Issuer Default Rating.

(2) As part of completing the holding company reorganization, NorthWestern Energy Group and NWE Public Service received their credit ratings from these agencies in December 2023. These agencies also affirmed their ratings for NW Corp.

A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

Contractual Obligations and Other Commitments

We have a variety of contractual obligations and other commitments that require payment of cash at certain specified periods. With the exception of maturities of long-term debt, we anticipate funding these obligations through cash flows from operations. The following table summarizes our contractual cash obligations and commitments as of December 31, 2023. See additional discussion in Note 18 - Commitments and Contingencies to the Consolidated Financial Statements.

(1) Represents cash payments for long-term debt and excludes $13.1 million of debt discounts and debt issuance costs, net.

(2) We have estimated cash obligations related to our pension and other postretirement benefit programs for five years, as it is not practicable to estimate thereafter. The pension and other postretirement benefit estimates reflect our expected cash contributions, which may be in excess of minimum funding requirements.

(3) Certain QFs require us to purchase minimum amounts of energy at prices ranging from $67 to $136 per MWH through 2029. Our estimated gross contractual obligation related to these QFs is approximately $303.1 million. A portion of the costs incurred to purchase this energy is recoverable through rates authorized by the MPSC, totaling approximately $266.5 million.

(4) We have entered into various purchase commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts (exclusive of the qualifying facilities liability discussed above). These commitments range from one to 24 years.

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The energy supply costs incurred under these contracts are generally recoverable through rate mechanisms approved by the MPSC, as further described in Note 3 - Regulatory Matters.

(5) Contractual interest payments include our revolving credit facilities, which have a variable interest rate. We have assumed an average interest rate of 6.71 percent on the outstanding balance through maturity of the credit facilities.

(6) Represents significant firm purchase commitments for construction of planned capital projects.

(7) The table above excludes potential tax payments related to uncertain tax positions as they are not practicable to estimate. Additionally, the table above excludes reserves for environmental remediation (See Note 18 - Commitments and Contingencies) and AROs (see Note 6 - Asset Retirement Obligations) as the amount and timing of cash payments may be uncertain.

Other Obligations - As a co-owner of Colstrip, we provided surety bonds of approximately $15.7 million and $17.3 million as of December 31, 2023 and 2022, respectively, to ensure the operation and maintenance of remedial and closure actions are carried out related to the Administrative Order on Consent Regarding Impacts Related to Wastewater Facilities Comprising the Closed-Loop System at Colstrip Steam Electric Stations, Colstrip Montana (the AOC) as required by the MDEQ. As costs are incurred under the AOC, the surety bonds will be reduced.

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CRITICAL ACCOUNTING ESTIMATES

Management's discussion and analysis of financial condition and results of operations is based on our Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these Consolidated Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and other assumptions that are believed to be proper and reasonable under the circumstances. We continually evaluate the appropriateness of our estimates and assumptions. Actual results could differ from those estimates.

We have identified the policies and related procedures below that contain accounting estimates that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on our financial condition or results of operations.

Regulatory Assets and Liabilities

Our operations are subject to the provisions of ASC 980, Regulated Operations (ASC 980). Our regulatory assets are the probable future revenues associated with certain costs to be recovered from customers through the ratemaking process, including our estimate of amounts recoverable for natural gas and electric supply purchases. Regulatory liabilities are the probable future reductions in revenues associated with amounts to be credited to customers through the ratemaking process. We determine which costs are recoverable by consulting previous rulings by state regulatory authorities in jurisdictions where we operate or other factors that lead us to believe that cost recovery is probable. This accounting treatment is impacted by the uncertainties of our regulatory environment, anticipated future regulatory decisions and their impact. If any part of our operations becomes no longer subject to the provisions of ASC 980, or facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery, we would record a charge to earnings, which could be material. In addition, we would need to determine if there was any impairment to the carrying costs of the associated plant and inventory assets.

While we believe that our assumptions regarding future regulatory actions are reasonable, different assumptions could materially affect our results. See Note 4 - Regulatory Assets and Liabilities, to the Consolidated Financial Statements for further discussion.

Pension and Postretirement Benefit Plans

We sponsor and/or contribute to pension, postretirement health care and life insurance benefits for eligible employees. Our reported costs of providing pension and other postretirement benefits, as described in Note 14 - Employee Benefit Plans, to the Consolidated Financial Statements, are dependent upon numerous factors including the provisions of the plans, changing employee demographics, rate of return on plan assets and other economic conditions, and various actuarial calculations, assumptions, and accounting mechanisms. As a result of these factors, significant portions of pension and other postretirement benefit costs recorded in any period do not reflect (and are generally greater than) the actual benefits provided to plan participants. Due to the complexity of these calculations, the long-term nature of the obligations, and the importance of the assumptions utilized, the determination of these costs is considered a critical accounting estimate.

Assumptions

Key actuarial assumptions utilized in determining these costs include:

•Discount rates used in determining the future benefit obligations;

•Expected long-term rate of return on plan assets; and

•Mortality assumptions.

We review these assumptions on an annual basis and adjust them as necessary. The assumptions are based upon market interest rates, past experience and management's best estimate of future economic conditions.

We set the discount rate using a yield curve analysis, which projects benefit cash flows into the future and then discounts those cash flows to the measurement date using a yield curve. This is done by constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year projected benefit cash flow from our plans. Based on this analysis as of December 31, 2023, our discount rate on both the NorthWestern Corporation pension plan and NorthWestern Energy pension plan is 4.95-5.00 percent.

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In determining the expected long-term rate of return on plan assets, we review historical returns, the future expectations for returns for each asset class weighted by the target asset allocation of the pension and postretirement portfolios, and long-term inflation assumptions. Our expected long-term rate of return on assets assumptions are 5.15% percent and 6.65% percent on the NorthWestern Corporation and NorthWestern Energy pension plan, respectively, for 2024.

Cost Sensitivity

The following table reflects the sensitivity of pension costs to changes in certain actuarial assumptions (in thousands):

Accounting Treatment

We recognize the funded status of each plan as an asset or liability in the Consolidated Balance Sheets. Differences between actuarial assumptions and actual plan results are deferred and are recognized into earnings only when the accumulated differences exceed 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets, which reduces the volatility of reported pension costs. If necessary, the excess is amortized over the average remaining service period of active employees.

Due to the various regulatory treatments of the plans, our Consolidated Financial Statements reflect the effects of the different rate making principles followed by the jurisdictions regulating us. Pension costs in Montana and other postretirement benefit costs in South Dakota are included in rates on a pay as you go basis for regulatory purposes. Pension costs in South Dakota and other postretirement benefit costs in Montana are included in rates on an accrual basis for regulatory purposes. Regulatory assets have been recognized for the obligations that will be included in future cost of service.

Income Taxes

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. Deferred income tax assets and liabilities represent the future effects on income taxes from temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The probability of realizing deferred tax assets is based on forecasts of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. We establish a valuation allowance when it is more likely than not that all, or a portion of, a deferred tax asset will not be realized. Exposures exist related to various tax filing positions, which may require an extended period of time to resolve and may result in income tax adjustments by taxing authorities. We have reduced deferred tax assets or established liabilities based on our best estimate of future probable adjustments related to these exposures. On a quarterly basis, we evaluate exposures in light of any additional information and make adjustments as necessary to reflect the best estimate of the future outcomes. We believe our deferred tax assets and established liabilities are appropriate for estimated exposures; however, actual results may differ significantly from these estimates.

The interpretation of tax laws involves uncertainty. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows and adjustments to tax-related assets and liabilities could be material. The uncertainty and judgment involved in the determination and filing of income taxes is accounted for by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the Consolidated Financial Statements. We recognize tax positions that meet the more-likely-than-not threshold as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. We have unrecognized tax benefits of approximately $28.1 million as of December 31, 2023. The resolution of tax matters in a particular future period could have a material impact on our provision for income taxes, results of operations and our cash flows. See Note 12 - Income Taxes to the Consolidated Financial Statements for further discussion.

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NEW ACCOUNTING STANDARDS

See Note 2 - Significant Accounting Policies, to the Consolidated Financial Statements, included in Item 8 herein for a discussion of new accounting standards.

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