NorthWestern Energy Group Inc

(10) Unsecured Credit Facilities

On November 29, 2023, NW Corp amended its existing $425.0 million revolving credit facility (the Amended Facility) to address the holding company reorganization and extended the maturity date of the facility to November 29, 2028. The Amended Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points. After the completion of the holding company reorganization on January 1, 2024, NW Corp owns and operates only the Montana regulated utility, and the base capacity of the Amended Facility automatically reduced to $400.0 million.

On October 28, 2022, we entered into a $100.0 million Credit Agreement (the Additional Credit Facility) to supplement our existing $425.0 million revolving credit facility. The Additional Credit Facility has a maturity date of April 28, 2024. The Additional Credit Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points, plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points. As of December 31, 2023, there were no amounts outstanding under this Additional Credit Facility.

On March 25, 2023, we amended our existing $25.0 million swingline credit facility (the Swingline Facility) to extend the maturity date of the facility from March 27, 2024 to March 27, 2025. The Swingline Facility does not amortize and is unsecured. Borrowings may be made at interest rates equal to (a) SOFR, plus a margin of 90.0 basis points, or (b) a base rate, plus a margin of 12.5 basis points. As of December 31, 2023, there were no amounts outstanding under this Swingline Facility.

On January 2, 2024, NW Corp terminated its $100.0 million Additional Credit Facility. On January 4, 2024, NW Corp terminated its $25.0 million Swingline Facility.

On November 29, 2023, NorthWestern Energy Group and its subsidiary, NWE Public Service, entered into a new $200.0 million unsecured revolver credit facility with base sublimits of $50.0 million for NorthWestern Energy Group and $150.0 million for NWE Public Service (the HoldCo and NWE Public Service Credit Facility). The HoldCo and NWE Public Service Credit Facility has a maturity date of November 29, 2028. Upon the completion of the holding company reorganization on January 1, 2024, this credit facility became effective. The HoldCo and NWE Public Service Credit Facility has uncommitted features that allow both NorthWestern Energy Group and NWE Public Service to request one-year extensions to the maturity date and increase the size of the credit facility by an additional $50 million. The credit facility also gives us the flexibility to adjust the sublimits as needed, provided that NorthWestern Energy Group's base sublimit cannot exceed $100.0 million and NWE Public Service's sublimit cannot exceed $200.0 million. Borrowings may be made at interest rates equal to (a) SOFR, plus a credit spread adjustment of 10.0 basis points plus a margin of 100.0 to 175.0 basis points, or (b) a base rate, plus a margin of 0.0 to 75.0 basis points.

Commitment fees for the unsecured revolving lines of credit were $0.6 million and $0.1 million for the years ended December 31, 2023 and 2022.

The availability under the facilities in place for the years ended December 31 is shown in the following table (in millions):

(1) Upon the completion of the holding company reorganization on January 1, 2024, the base capacity of this facility decreased to $400.0 million.

(2) NW Corp terminated the $100.0 million Additional Credit Facility on January 2, 2024, and the $25.0 million Swingline Facility on January 4, 2024.

(3) As discussed above, upon the completion of the holding company reorganization on January 1, 2024, our total consolidated base capacity increased to $600.0 million and our net availability increased to $282.0 million.

Our credit facilities include covenants that require us to meet certain financial tests, including a maximum debt to capitalization ratio not to exceed 65 percent. The facilities also contain covenants which, among other things, limit our ability to engage in any consolidation or merger or otherwise liquidate or dissolve, dispose of property, and enter into transactions with affiliates. A default on the Montana First Mortgage Bonds would trigger a cross default on the Amended Facility; however, a default on the Amended Facility would not trigger a default on the Montana First Mortgage Bonds. A default on the South Dakota First Mortgage Bonds would trigger a cross default on the NWE Public Service sublimit of the HoldCo and NWE Public Service Credit Facility; however, a default on the HoldCo and NWE Public Service Credit Facility would not trigger a default on the South Dakota First Mortgage Bonds.

(11) Long-Term Debt and Finance Leases

Long-term debt and finance leases consisted of the following (in thousands):

Secured Debt

First Mortgage Bonds and Pollution Control Obligations

The South Dakota First Mortgage Bonds are a series of general obligation bonds issued under our South Dakota indenture. These bonds are secured by substantially all of our South Dakota and Nebraska electric and natural gas assets. The South Dakota indenture was transferred from NW Corp to NWE Public Service upon the completion of the holding company reorganization on January 1, 2024.

The Montana First Mortgage Bonds are a series of general obligation bonds issued under our Montana indenture. These bonds are secured by substantially all of our Montana electric and natural gas assets.

On March 30, 2023, we issued and sold $239.0 million aggregate principal amount of Montana First Mortgage Bonds (the bonds) at a fixed interest rate of 5.57 percent maturing on March 30, 2033. On this same day, we issued and sold $31.0 million

aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.57 percent maturing on March 30, 2033. On May 1, 2023, we issued and sold an additional $30 million aggregate principal amount of South Dakota First Mortgage Bonds at a fixed interest rate of 5.42 percent maturing on May 1, 2033. These bonds were issued in transactions exempt from the registration requirements of the Securities Act of 1933. Proceeds were used to repay a portion of our outstanding borrowings under our revolving credit facilities and for other general corporate purposes.

On June 29, 2023, the City of Forsyth, Rosebud County, Montana issued $144.7 million principal amount of Pollution Control Revenue Refunding Bonds (2023 Pollution Control Bonds) on our behalf. The 2023 Pollution Control Bonds were issued at a fixed interest rate of 3.88 percent maturing on July 1, 2028. The proceeds of the issuance were loaned to us pursuant to a Loan Agreement and were deposited directly with U.S. Bank Trust Company, National Association, as trustee, for the redemption of the 2.00 percent, $144.7 million City of Forsyth Pollution Control Revenue Refunding Bonds due on August 1, 2023 that had previously been issued on our behalf. Pursuant to the Loan Agreement, we are obligated to make payments in such amounts and at such times as will be sufficient to pay, when due, the principal and interest on the 2023 Pollution Control Bonds. Our obligations under the Loan Agreement are secured by delivery of a like amount of our Montana First Mortgage Bonds, which are secured by our Montana electric and natural gas assets. So long as we are making payments under the Loan Agreement, no payments under these mortgage bonds will be due. The 2023 Pollution Control Bonds were issued in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended.

As of December 31, 2023, we were in compliance with our financial debt covenants.

Maturities of Long-Term Debt

The aggregate minimum principal maturities of long-term debt and finance leases, during the next five years are $103.3 million in 2024, $303.6 million in 2025, $106.9 million in 2026, and $497.7 million in 2028.

(12) Income Taxes

Income tax (benefit) expense is comprised of the following (in thousands):

Our effective tax rate typically differs from the federal statutory tax rate primarily due to production tax credits and the regulatory impact of flowing through the federal and state tax benefit of repairs deductions, state tax benefit of accelerated tax depreciation deductions (including bonus depreciation when applicable), and production tax credits. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.

The following table reconciles our effective income tax rate to the federal statutory rate:

The table below summarizes the significant differences in income tax expense (benefit) based on the differences between our effective tax rate and the federal statutory rate (in thousands).

The components of the net deferred income tax liability recognized in our Consolidated Balance Sheets are related to the following temporary differences (in thousands):

As of December 31, 2023, our total federal NOL carryforward was approximately $447.8 million. Our federal NOL carryforward does not expire. Our state NOL carryforward as of December 31, 2023 was approximately $362.1 million. If unused, our state NOL carryforwards will expire in 2033. We believe it is more likely than not that sufficient taxable income will be generated to utilize these NOL carryforwards.

At December 31, 2023, our total production tax credit carryforward was approximately $94.3 million. If unused, our production tax credit carryforwards will expire as follows: $1.8 million in 2035, $10.9 million in 2036, $11.1 million in 2037, $10.9 million in 2038, $11.5 million in 2039, $13.1 million in 2040, $11.5 million in 2041, $13.2 million in 2042, and $10.4 million in 2043. We believe it is more likely than not that sufficient taxable income will be generated to utilize these production tax credit carryforwards.

Uncertain Tax Positions

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. The change in unrecognized tax benefits is as follows (in thousands):

Our unrecognized tax benefits include approximately $24.4 million and $27.9 million related to tax positions as of December 31, 2023 and 2022, that if recognized, would impact our annual effective tax rate. On April 14, 2023, the Internal Revenue Service (IRS) issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting for gas repairs expenditures. During the year ended December 31, 2023, we adopted this method and decreased our total unrecognized tax benefits by $0.5 million and recognized an income tax benefit of approximately $3.2 million for previously unrecognized tax benefits. In the next twelve months we expect the statute of limitations to expire for certain uncertain tax benefits, which would result in a decrease to our total unrecognized tax benefits of approximately $16.9 million.

Our policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2023, we have accrued $4.5 million for the payment of interest and penalties in the Consolidated Balance Sheets. As of December 31, 2022, we had $1.4 million accrued for the payment of interest and penalties.

Tax years 2020 and forward remain subject to examination by the IRS and state taxing authorities. During the first quarter of 2023 the IRS commenced and concluded a limited scope examination of our 2019 amended federal income tax return. This examination resulted in a reduction to our previously claimed alternative minimum tax credit refund that is reflected in the table above.

(13) Comprehensive Income (Loss)

The following tables display the components of Other Comprehensive Income (Loss), after-tax, and the related tax effects (in thousands):

Balances by classification included within AOCL on the Consolidated Balance Sheets are as follows, net of tax (in thousands):

The following table displays the changes in AOCL by component, net of tax (in thousands):

(14) Employee Benefit Plans

Pension and Other Postretirement Benefit Plans

We sponsor and/or contribute to pension and postretirement health care and life insurance benefit plans for eligible employees. The pension plan for our South Dakota and Nebraska employees is referred to as the NorthWestern Corporation plan, the pension plan for our Montana employees is referred to as the NorthWestern Energy plan, and collectively they are referred to as the Plans. We utilize a number of accounting mechanisms that reduce the volatility of reported pension costs. 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. If necessary, the excess is amortized over the average remaining service period of active employees. The Plans' funded status is recognized as an asset or liability in our Consolidated Financial Statements. See Note 4 - Regulatory Assets and Liabilities, for further discussion on how these costs are recovered through rates charged to our customers.

Benefit Obligation and Funded Status

Following is a reconciliation of the changes in plan benefit obligations and fair value of plan assets, and a statement of the funded status (in thousands):

(1) In October 2023, we entered into a group annuity contract from an insurance company to provide for the payment of pension benefits to 285 NorthWestern Energy Pension Plan participants. We purchased the contract with $51.9 million of plan assets. The insurance company took over the payments of these benefits starting January 1, 2024. This transaction settled $51.9 million of our NorthWestern Energy Pension Plan obligation. As a result of this transaction, during the twelve months ended December 31, 2023, we recorded a non-cash, non-operating settlement charge of $4.4 million. This charge is recorded within other income, net on the Consolidated Statements of Income. As discussed within Note 4 – Regulatory Assets and Liabilities, the MPSC allows recovery of pension costs on a cash funding basis. As such, this charge was deferred as a regulatory asset on the Consolidated Balance Sheets, with a corresponding decrease to operating and maintenance expense on the Consolidated Statements of Income.

The actuarial gain/loss is primarily due to the change in discount rate assumption and actual asset returns compared with expected amounts. The total projected benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were as follows (in millions):

As of December 31, 2023, the fair value of the NorthWestern Corporation pension plan assets exceed the total projected and accumulated benefit obligation and are therefore excluded from this table.

Net Periodic Cost (Credit)

The components of the net costs (credits) for our pension and other postretirement plans are as follows (in thousands):

(1) Settlement losses are related to partial annuitization of NorthWestern Energy Pension Plan effective October 24, 2023 and December 1, 2021, respectively.

(2) Net periodic benefit costs for pension and postretirement benefit plans are recognized for financial reporting based on the authorization of each regulatory jurisdiction in which we operate. A portion of these costs are recorded in regulatory assets and recognized in the Consolidated Statements of Income as those costs are recovered through customer rates.

For the years ended December 31, 2023, 2022, and 2021, Service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income, net on the Consolidated Statements of Income.

For purposes of calculating the expected return on pension plan assets, the market-related value of assets is used, which is based upon fair value. The difference between actual plan asset returns and estimated plan asset returns are amortized equally over a period not to exceed five years.

Actuarial Assumptions

The measurement dates used to determine pension and other postretirement benefit measurements for the plans are December 31, 2023 and 2022. The actuarial assumptions used to compute net periodic pension cost and postretirement benefit cost are based upon information available as of the beginning of the year, specifically, market interest rates, past experience and management's best estimate of future economic conditions. Changes in these assumptions may impact future benefit costs and obligations. In computing future costs and obligations, we must make assumptions about such things as employee mortality and turnover, expected salary and wage increases, discount rate, expected return on plan assets, and expected future cost increases. Two of these assumptions have the most impact on the level of cost: (1) discount rate and (2) expected rate of return on plan assets. During 2022, the plan's actuary conducted an experience study to review five years of plan experience and update these assumptions.

On an annual basis, we set the discount rate using a yield curve analysis. This analysis includes constructing a hypothetical bond portfolio whose cash flow from coupons and maturities matches the year-by-year, projected benefit cash flow from our plans. The decrease in the discount rate during 2023 increased our projected benefit obligation by approximately $10.5 million.

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. Based on the target asset allocation for our pension assets and future expectations for asset returns, we increased our long term rate of return on assets assumption for NorthWestern Energy Pension Plan to 6.65 percent and increased our assumption on the NorthWestern Corporation Pension Plan to 5.15 percent for 2024.

The weighted-average assumptions used in calculating the preceding information are as follows:

The postretirement benefit obligation is calculated assuming that health care costs increase by a 5.00 percent fixed rate. The company contribution toward the premium cost is capped, therefore future health care cost trend rates are expected to have a minimal impact on company costs and the accumulated postretirement benefit obligation.

Investment Strategy

Our investment goals with respect to managing the pension and other postretirement assets are to meet current and future benefit payment needs while maximizing total investment returns (income and appreciation) after inflation within the constraints of diversification, prudent risk taking, Prudent Man Rule of the Employee Retirement Income Security Act of 1974 and liability-based considerations. Each plan is diversified across asset classes to achieve optimal balance between risk and return and between income and growth through capital appreciation. Our investment philosophy is based on the following:

•Each plan should be substantially invested as long-term cash holdings reduce long-term rates of return;

•Pension Plan portfolio risk is described by volatility in the funded status of the Plans;

•It is prudent to diversify each plan across the major asset classes;

•Equity investments provide greater long-term returns than fixed income investments, although with greater short-term volatility;

•Fixed income investments of the plans should strongly correlate with the interest rate sensitivity of the plan’s aggregate liabilities in order to hedge the risk of change in interest rates negatively impacting the pension plans overall funded status, (such assets will be described as Liability Hedging Fixed Income assets);

•Allocation to foreign equities increases the portfolio diversification and thereby decreases portfolio risk while providing for the potential for enhanced long-term returns;

•Private real estate and broad global opportunistic fixed income asset classes can provide diversification to both equity and liability hedging fixed income investments and that a moderate allocation to each can potentially improve the expected risk-adjusted return for the NorthWestern Energy Pension Plan investments over full market cycles;

•Active management can reduce portfolio risk and potentially add value through security selection strategies;

•A portion of plan assets should be allocated to passive, indexed management funds to provide for greater diversification and lower cost; and

•It is appropriate to retain more than one investment manager, provided that such managers offer asset class or style diversification.

Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.

The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense. In the optimization study, assumptions are formulated about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes, and making adjustments to reflect future conditions expected to prevail over the study period. Based on this, the target asset allocation established, within an allowable range of plus or minus 5 percent, is as follows:

The actual allocation by plan is as follows:

Generally, the asset mix will be rebalanced to the target mix as individual portfolios approach their minimum or maximum levels. The guidelines allow for a transition to targets over time as assets are reallocated to newly-approved asset classes of opportunistic fixed income and private real estate. Debt securities consist of U.S. and international instruments including emerging markets and high yield instruments, as well as government, corporate, asset backed and mortgage backed securities. While the portfolio may invest in high yield securities, the average quality must be rated at least “investment grade" by rating agencies. Equity, real estate and fixed income portfolios may be comprised of both active and passive management strategies. Performance of fixed income investments is measured by both traditional investment benchmarks as well as relative changes in the present value of the plan's liabilities. Equity investments consist primarily of U.S. stocks including large, mid and small cap stocks. We also invest in global equities with exposure to developing and emerging markets. Equity investments may also be diversified across investment styles such as growth and value. Derivatives, options and futures are permitted for the purpose of reducing risk but may not be used for speculative purposes. Real estate investments will consist of global equity or debt interests in tangible property consisting of land, buildings, and other improvements in commercial and residential sectors.

Our plan assets are primarily invested in common collective trusts (CCTs), which are invested in equity and fixed income securities. In accordance with our investment policy, these pooled investment funds must have an adequate asset base relative to their asset class and be invested in a diversified manner and have a minimum of three years of verified investment performance experience or verified portfolio manager investment experience in a particular investment strategy and have management and oversight by an investment advisor registered with the SEC. Investments in a collective investment vehicle are valued by multiplying the investee company’s net asset value per share with the number of units or shares owned at the valuation date. Net asset value per share is determined by the trustee. Investments held by the CCT, including collateral invested for securities on loan, are valued on the basis of valuations furnished by a pricing service approved by the CCT’s investment manager, which determines valuations using methods based on quoted closing market prices on national securities exchanges, or at fair value as determined in good faith by the CCT’s investment manager if applicable. The funds do not contain any redemption restrictions. The direct holding of NorthWestern Energy Group stock is not permitted; however, any holding in a diversified mutual fund or collective investment fund is permitted.

Cash Flows

In accordance with the Pension Protection Act of 2006 (PPA), and the relief provisions of the Worker, Retiree, and Employer Recovery Act of 2008 (WRERA), we are required to meet minimum funding levels in order to avoid required contributions and benefit restrictions. We have elected to use asset smoothing provided by the WRERA, which allows the use of asset averaging, including expected returns (subject to certain limitations), for a 24-month period in the determination of funding requirements. Additional funding relief was passed in the American Rescue Plan Act of 2021, providing for longer amortization and interest rate smoothing, which we elected to use. We expect to continue to make contributions to the pension plans in 2024 and future years that reflect the minimum requirements and discretionary amounts consistent with the amounts recovered in rates. Additional legislative or regulatory measures, as well as fluctuations in financial market conditions, may impact our funding requirements.

Due to the regulatory treatment of pension costs in Montana, pension costs for 2023, 2022 and 2021 were based on actual contributions to the plan. Annual contributions to each of the pension plans are as follows (in thousands):

We estimate the plans will make future benefit payments to participants as follows (in thousands):

Defined Contribution Plan

Our defined contribution plan permits employees to defer receipt of compensation as provided in Section 401(k) of the Internal Revenue Code. Under the plan, employees may elect to direct a percentage of their gross compensation to be contributed to the plan. We contribute various percentage amounts of the employee's gross compensation contributed to the plan. Matching contributions for the years ended December 31, 2023, 2022 and 2021 were $13.2 million, $12.3 million, and $11.8 million, respectively.

(15) Stock-Based Compensation

We grant stock-based awards through our Amended and Restated Equity Compensation Plan (ECP), which includes restricted stock awards and performance share awards. As of December 31, 2023, there were 649,884 shares of common stock remaining available for grants. The remaining vesting period for awards previously granted ranges from one tofour years if the service and/or performance requirements are met. Nonvested shares do not receive dividend distributions. The long-term incentive plan provides for accelerated vesting in the event of a change in control.

We account for our share-based compensation arrangements by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. The compensation cost is based on the fair value of the grant on the date it was awarded.

Performance Unit Awards

Performance unit awards are granted annually under the ECP. These awards vest at the end of the three-year performance period if we have achieved certain performance goals and the individual remains employed by us. The exact number of shares issued will vary from 0 percent to 200 percent of the target award, depending on actual company performance relative to the performance goals. Beginning in 2023, these awards contain service-, market-, and performance-based components. The service-based component of these awards, representing 30 percent of the award, vest at the end of the three-year performance period as long as the individual has remained employed with us over that term. The performance goals are independent of each other and equally weighted at 35 percent of the award, and are based on two metrics: (i) EPS growth level and average return on equity; and (ii) total shareholder return relative to a peer group. Performance unit awards issued prior to 2023 included both the market- and performance-based components discussed above.

Fair value is determined for each component of the performance unit awards. The fair value of the service-based component is estimated based upon the closing market price of our common stock as of the grant date less the present value of expected dividends. The fair value of the performance-based component is estimated based upon the closing market price of our common stock as of the grant date less the present value of expected dividends, multiplied by an estimated performance multiple determined on the basis of historical experience, which is subsequently trued up at vesting based on actual performance. The fair value of the market-based component is estimated using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to the peer group. The following summarizes the significant assumptions used to determine the fair value of performance shares and related compensation expense as well as the resulting estimated fair value of performance shares granted:

The risk-free interest rate was based on the U.S. Treasury yield of a three-year bond at the time of grant. The expected term of the performance shares isthree years based on the performance cycle. Expected volatility was based on the historical volatility for the peer group. Both performance goals are measured over the three-year vesting period and are charged to compensation expense over the vesting period based on the number of shares expected to vest.

A summary of nonvested shares as of and changes during the year ended December 31, 2023, are as follows:

Retirement/Retention Restricted Share Awards

In December 2011, an executive retirement / retention program was established that provides for the annual grant of restricted share units. Awards granted before 2022 are subject to a five-year performance and vesting period. The performance measure for these awards requires net income for the calendar year of at least three of the five full calendar years during the performance period to exceed net income for the calendar year the awards are granted. Awards granted in 2022 no longer contain this performance measure, instead these awards will vest after five full calendar years if the employee remains employed during that service period. No retirement/retention restricted shares were granted during the year ended December 31, 2023. Once vested, the awards will be paid out in shares of common stock in five equal annual installments after a recipient has separated from service. The fair value of these awards is measured based upon the closing market price of our common stock as of the grant date less the present value of expected dividends.

A summary of nonvested shares as of and changes during the year ended December 31, 2023, are as follows:

We recognized total stock-based compensation expense of $3.6 million, $4.2 million, and $3.9 million for the years ended December 31, 2023, 2022, and 2021, respectively, and related income tax benefit of $(1.0) million, $(1.3) million, and $(0.2) million for the years ended December 31, 2023, 2022, and 2021, respectively. As of December 31, 2023, we had $6.5 million of unrecognized compensation cost related to the nonvested portion of our outstanding awards. The cost is expected to be recognized over a weighted-average period of 2 years. The total fair value of shares vested was $4.4 million, $4.3 million, and $4.2 million for the years ended December 31, 2023, 2022 and 2021, respectively.

(16) Common Stock

We have 250,000,000 shares authorized consisting of 200,000,000 shares of common stock with a $0.01 par value and 50,000,000 shares of preferred stock with a $0.01 par value. Of the common stock,2,865,957 shares are reserved for the incentive plan awards. For further detail of grants under this plan see Note 15 - Stock-Based Compensation.

Repurchase of Common Stock

Shares tendered by employees to us to satisfy the employees' tax withholding obligations in connection with the vesting of restricted stock awards totaled 4,167 and 16,120 during the years ended December 31, 2023 and 2022, respectively, and are reflected in treasury stock. These shares were credited to treasury stock based on their fair market value on the vesting date.

Issuance of Common Stock

In April 2021, NW Corp entered into an Equity Distribution Agreement pursuant to which we could offer and sell shares of our common stock from time to time, having an aggregate gross sales price of up to $200.0 million, through an At-the-Market (ATM) offering program. During the twelve months ended December 31, 2023, NW Corp issued 1,432,738 shares of our common stock under the ATM program at an average price of $52.02, for net proceeds of $73.6 million, which is net of sales commissions and other fees paid of approximately $0.9 million. We have completed the ATM offering program under this Equity Distribution Agreement.

Dividend Restrictions

Due to our holding company structure, liquidity necessary to pay dividends to holders of our common stock is generally provided by dividend distributions from our utility subsidiaries. Under various state regulatory agreements, debt agreements and the Federal Power Act, our utility subsidiaries have restrictions, including minimum equity ratios, that limit the amount of dividend distributions that can be made.

Pursuant to the MPSC regulatory agreement with NW Corp, if NW Corp's secured credit ratings are above BBB- for S&P Global Ratings and Baa3 for Moody's Investor Services, NW Corp may declare or pay dividends as long as NW Corp's common equity ratio is 40 percent or above. If NW Corp's secured credit ratings are BBB- for S&P Global Ratings or Baa3 for Moody's Investor Services, NW Corp may declare or pay dividends as long as NW Corp's common equity ratio is 43 percent or above. If NW Corp's secured credit ratings fall below BBB- with S&P Global Ratings or Baa3 with Moody's Investor Services, NW Corp may not declare or pay dividends to NorthWestern Energy Group.

NorthWestern Energy Group, NW Corp, and NWE Public Service's ability to pay dividends is also limited by the terms of various debt agreements, pursuant to which, NorthWestern Energy Group, NW Corp, and NWE Public Service are required to maintain a debt to capitalization ratio of no more than 0.65 to 1.00.

As of December 31, 2023, approximately $920.0 million of NW Corp unrestricted net assets were available for the payment of dividends to NorthWestern Energy Group under our most restrictive dividend restriction.

(17) Earnings Per Share

Basic earnings per share are computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the potential dilution of common stock equivalent shares that could occur if unvested shares were to vest. Common stock equivalent shares are calculated using the treasury stock method, as applicable. The dilutive effect is computed by dividing earnings applicable to common stock by the weighted average number of common shares outstanding plus the effect of the outstanding unvested restricted stock and performance share awards. Average shares used in computing the basic and diluted earnings per share are as follows:

(1) Performance share awards are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the award.

(2) Forward equity shares are included in diluted weighted average number of shares outstanding based upon what would be issued if the end of the most recent reporting period was the end of the term of the forward sale agreement.

As of December 31, 2023, there were 25,913 shares from performance and restricted share awards which were antidilutive and excluded from the earnings per share calculations.

(18) Commitments and Contingencies

Qualifying Facilities Liability

Our QF liability primarily consists of unrecoverable costs associated with three contracts covered under the PURPA. These contracts require us to purchase minimum amounts of energy at prices ranging from $67 to $136 per MWH through 2029. As of December 31, 2023, our estimated gross contractual obligation related to these contracts was approximately $303.1 million through 2029. A portion of the costs incurred to purchase this energy is recoverable through rates, totaling approximately $266.5 million through 2029. As contractual obligations are settled, the related purchases and sales are recorded within Fuel, purchased power and direct transmission expense and Electric revenues in our Consolidated Statements of Income. The present value of the remaining liability is recorded in Other noncurrent liabilities in our Consolidated Balance Sheets. The following summarizes the change in the liability (in thousands):

(1) The primary components of the change in settlement amounts includes (i) a lower periodic adjustment of $4.2 million due to actual price escalation, which was less than previously modeled; and (ii) higher costs of approximately $1.0 million, due to a $0.8 million reduction in costs for the adjustment to actual output and pricing for the current contract year as compared with a $1.8 million reduction in costs in the prior period.

The following summarizes the estimated gross contractual obligation less amounts recoverable through rates (in thousands):

(1) This net unrecoverable amount represents the undiscounted difference between the total gross obligations and recoverable amounts. The ending QF liability in the table above represents the present value of this net unrecoverable amount.

Long Term Supply and Capacity Purchase Obligations

We have entered into various commitments, largely purchased power, electric transmission, coal and natural gas supply and natural gas transportation contracts. These commitments range from one to 24 years. Costs incurred under these contracts are included in Fuel, purchased power and direct transmission expense in the Consolidated Statements of Income and were approximately $340.0 million, $328.0 million and $286.7 million for the years ended December 31, 2023, 2022, and 2021, respectively. As of December 31, 2023, our commitments under these contracts were $321.9 million in 2024, $244.1 million in 2025, $263.4 million in 2026, $243.6 million in 2027, $225.9 million in 2028, and $1.5 billion thereafter. These commitments are not reflected in our Consolidated Financial Statements.

Hydroelectric License Commitments

With the 2014 purchase of hydroelectric generating facilities and associated assets located in Montana, we assumed two Memoranda of Understanding (MOUs) existing with state, federal and private entities. The MOUs are periodically updated and renewed and require us to implement plans to mitigate the impact of the projects on fish, wildlife and their habitats, and to increase recreational opportunities. The MOUs were created to maximize collaboration between the parties and enhance the possibility to receive matching funds from relevant federal agencies. Under these MOUs, we have a remaining commitment to spend approximately $22.4 million between 2024 and 2040. These commitments are not reflected in our Consolidated Financial Statements.

ENVIRONMENTAL LIABILITIES AND REGULATION

Environmental Matters

The operation of electric generating, transmission and distribution facilities, and gas gathering, storage, transportation and distribution facilities, along with the development (involving site selection, environmental assessments, and permitting) and construction of these assets, are subject to extensive federal, state, and local environmental and land use laws and regulations. Our activities involve compliance with diverse laws and regulations that address emissions and impacts to the environment, including air and water, protection of natural resources, avian and wildlife. We monitor federal, state, and local environmental initiatives to determine potential impacts on our financial results. As new laws or regulations are implemented, our policy is to assess their applicability and implement the necessary modifications to our facilities or their operation to maintain ongoing compliance.

Our environmental exposure includes a number of components, including remediation expenses related to the cleanup of current or former properties, and costs to comply with changing environmental regulations related to our operations. At present, our environmental reserve, which relates primarily to the remediation of former manufactured gas plant sites owned by us or for which we are responsible, is estimated to range between $21.0 million to $31.4 million. As of December 31, 2023, we had a reserve of approximately $25.3 million, which has not been discounted. Environmental costs are recorded when it is probable we are liable for the remediation and we can reasonably estimate the liability. We use a combination of site investigations and monitoring to formulate an estimate of environmental remediation costs for specific sites. Our monitoring procedures and development of actual remediation plans depend not only on site specific information but also on coordination with the different environmental regulatory agencies in our respective jurisdictions; therefore, while remediation exposure exists, it may be many years before costs are incurred.

The following summarizes the change in our environmental liability (in thousands):

Over time, as costs become determinable, we may seek authorization to recover such costs in rates or seek insurance reimbursement as available and applicable; therefore, although we cannot guarantee regulatory recovery, we do not expect these costs to have a material effect on our consolidated financial position or results of operations.

Manufactured Gas Plants - Approximately $19.8 million of our environmental reserve accrual is related to the following manufactured gas plants.

South Dakota - A formerly operated manufactured gas plant located in Aberdeen, South Dakota, has been identified on the Federal Comprehensive Environmental Response, Compensation, and Liability Information System list as contaminated with coal tar residue. We are currently conducting feasibility studies, implementing remedial actions pursuant to work plans approved by the South Dakota Department of Agriculture and Natural Resources, and conducting ongoing monitoring and operation and maintenance activities. As of December 31, 2023, the reserve for remediation costs at this site was approximately $8.0 million, and we estimate that approximately $2.9 million of this amount will be incurred through 2028.

Nebraska - We own sites in North Platte, Kearney, and Grand Island, Nebraska on which former manufactured gas facilities were located. We are currently working independently to fully characterize the nature and extent of potential impacts associated with these Nebraska sites. Our reserve estimate includes assumptions for site assessment and remedial action work. At present, we cannot determine with a reasonable degree of certainty the nature and timing of any risk-based remedial action at our Nebraska locations.

Montana - We own or have responsibility for sites in Butte, Missoula, and Helena, Montana on which former manufactured gas plants were located. The Butte and Helena sites, both listed as high priority sites on Montana’s state superfund list, were placed into the MDEQ voluntary remediation program for cleanup due to soil and groundwater impacts. Soil and coal tar were removed at the sites in accordance with the MDEQ requirements. Groundwater monitoring is conducted semiannually at both sites. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of additional remedial actions and/or investigations, if any, at the Butte site.

In August 2016, the MDEQ sent us a Notice of Potential Liability and Request for Remedial Action regarding the Helena site. In October 2019, we submitted a third revised Remedial Investigation Work Plan (RIWP) for the Helena site addressing MDEQ comments. The MDEQ approved the RIWP in March 2020 and field work was completed in 2022. We submitted a Remedial Investigation Report (RI Report) summarizing the work completed to MDEQ in March 2022 and are awaiting its review and comments as to any additional field work. We now expect the MDEQ review of the RI Report to be concluded in 2024, and any additional field work to commence following that.

MDEQ has indicated it expects to proceed in listing the Missoula site as a Montana superfund site. After researching historical ownership, we have identified another potentially responsible party with whom we have entered into an agreement allocating third-party costs to be incurred in addressing the site. The other party has assumed the lead role at the site and has expressed its intention to submit a voluntary remediation plan for the Missoula site to MDEQ. At this time, we cannot estimate with a reasonable degree of certainty the nature and timing of risk-based remedial action, if any, at the Missoula site.

Global Climate Change - National and international actions have been initiated to address global climate change and the contribution of GHG including, most significantly, carbon dioxide (CO 2) and methane emissions from natural gas. These actions include legislative proposals, Executive, Congressional and EPA actions at the federal level, state level activity, investor activism and private party litigation relating to emissions. Coal-fired plants have come under particular scrutiny due to their level of emissions. We have joint ownership interests in four coal-fired electric generating plants, all of which are operated by other companies. We are responsible for our proportionate share of the capital and operating costs while being entitled to our proportionate share of the power generated.

Proposed EPA Rules- Congress has not passed any federal climate change legislation regarding GHG emissions from coal fired plants, and we cannot predict the timing or form of any potential legislation. Section 111(d) of the Clean Air Act (CAA) confers authority on EPA and the states to regulate emissions, including GHGs, from existing stationary sources. In May 2023, 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.

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.

Future additional environmental requirements - federal or state - could cause us to incur material costs of compliance, increase our costs of procuring electricity, decrease transmission revenue and impact cost recovery. Technology to efficiently capture, remove and/or sequester such GHG emissions or hazardous air pollutants may not be available within a timeframe consistent with the implementation of any such requirements.

Regional Haze Rules - In January 2017, the EPA published amendments to the requirements under the CAA for state plans for protection of visibility - regional haze rules. Among other things, these amendments revised the process and requirements for the state implementation plans and extended the due date for the next periodic comprehensive regional haze state implementation plan revisions from 2018 to 2021.

The states of Montana, North Dakota and South Dakota have developed and submitted to the EPA, for its approval, their respective State Implementation Plans (SIP) for Regional Haze compliance. While these states, among others, did not meet the EPA’s July 31, 2021 submission deadline, they were all submitted in 2022. The Montana SIP as drafted and submitted to EPA does not call for additional controls for our interest in Colstrip Unit 4. The draft North Dakota SIP does not require any additional controls at the Coyote generating facility. Similarly, the draft South Dakota SIP does not require any additional controls at the Big Stone generating facility. Until these SIPs are finalized and approved by EPA, the potential remains that installation of additional emissions controls might be required at these facilities.

Jointly Owned Plants - We have joint ownership in generation plants located in South Dakota, North Dakota, Iowa, and Montana that are or may become subject to the various regulations discussed above that have been or may be issued or proposed.

Other - We continue to manage equipment containing polychlorinated biphenyl (PCB) oil in accordance with the EPA's Toxic Substance Control Act regulations. We will continue to use certain PCB-contaminated equipment for its remaining useful life and will, thereafter, dispose of the equipment according to pertinent regulations that govern the use and disposal of such equipment.

We routinely engage the services of a third-party environmental consulting firm to assist in performing a comprehensive evaluation of our environmental reserve. Based upon information available at this time, we believe that the current environmental reserve properly reflects our remediation exposure for the sites currently and previously owned by us. The portion of our environmental reserve applicable to site remediation may be subject to change as a result of the following uncertainties:

•We may not know all sites for which we are alleged or will be found to be responsible for remediation; and

•Absent performance of certain testing at sites where we have been identified as responsible for remediation, we cannot estimate with a reasonable degree of certainty the total costs of remediation.

LEGAL PROCEEDINGS

State of Montana - Riverbed Rents

On April 1, 2016, the State of Montana (State) filed a complaint on remand (the State’s Complaint) with the Montana First Judicial District Court (State District Court), naming us, along with Talen Montana, LLC (Talen) as defendants. The State claimed it owns the riverbeds underlying 10 of our, and formerly Talen’s, hydroelectric facilities (dams, along with reservoirs and tailraces) on the Missouri, Madison and Clark Fork Rivers, and seeks rents for Talen’s and our use and occupancy of such lands. The facilities at issue include the Hebgen, Madison, Hauser, Holter, Black Eagle, Rainbow, Cochrane, Ryan, and Morony facilities on the Missouri and Madison Rivers and the Thompson Falls facility on the Clark Fork River. We acquired these facilities from Talen in November 2014.

The litigation has a long prior history. In 2012, the United States Supreme Court issued a decision holding that the Montana Supreme Court erred in not considering a segment-by-segment approach to determine navigability and relying on present day recreational use of the rivers. It also held that what it referred to as the Great Falls Reach “at least from the head of the first waterfall to the foot of the last” was not navigable for title purposes, and thus the State did not own the riverbeds in that segment. The United States Supreme Court remanded the case to the Montana Supreme Court for further proceedings not inconsistent with its opinion. Following the 2012 remand, the case laid dormant for four years until the State’s Complaint was filed with the State District Court. On April 20, 2016, we removed the case from State District Court to the United States District Court for the District of Montana (Federal District Court). On August 1, 2018, the Federal District Court granted our and Talen’s motions to dismiss the State’s Complaint as it pertains to the navigability of the riverbeds associated with four of our hydroelectric facilities near Great Falls. A bench trial before the Federal District Court commenced January 4, 2022, and concluded on January 18, 2022, which addressed the issue of navigability concerning our other six facilities. On August 25, 2023, the Federal District Court issued its Findings of Fact, Conclusions of Law and Order (the "Order"), which found all but one of the segments of the riverbeds in dispute not navigable, and thus not owned by the State of Montana. The one segment found navigable, and thus owned by the State, was the segment on which the Black Eagle development was located. The State filed a motion to pursue an interlocutory appeal of the Order, and on January 2, 2024, the Federal District Court certified the Order for appeal to the 9th Circuit Court of Appeals. Damages were bifurcated by agreement and will be tried separately for the Black Eagle segment, and any other segments found navigable should an appeal be granted and other segments found navigable.

We dispute the State’s claims and intend to continue to vigorously defend the lawsuit. If the Federal District Court calculates damages as the State District Court did in 2008, we do not anticipate the resulting annual rent for the Black Eagle segment would have a material impact to our financial position or results of operations. We anticipate that any obligation to pay the State rent for use and occupancy of the riverbeds would be recoverable in rates from customers, although there can be no assurances that the MPSC would approve any such recovery.

Colstrip Arbitration

The remaining depreciable life of our investment in Colstrip Unit 4 is through 2042. The six owners of Colstrip Units 3 and 4 currently share the operating costs pursuant to the terms of an Ownership and Operation Agreement (O&O Agreement). However, several of the owners are mandated by Washington and Oregon law to eliminate coal-fired resources in 2025 and 2029, respectively.

As a result of the mandate, the owners have disagreed on various operational funding decisions, including whether closure requires each owner’s consent under the O&O Agreement. On March 12, 2021, we initiated an arbitration under the O&O Agreement (the “Arbitration”), to resolve the issues of whether closure requires each owner's consent and to clarify each owner's obligations to continue to fund operations until all joint owners agree on closure. The owners previously initiated efforts to identify arbitrators and have agreed to stay the Arbitration through March 31, 2024, while they explore a potential resolution to their disagreements.

Colstrip Coal Dust Litigation

On December 14, 2020, a claim was filed against Talen in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. Talen is one of the co-owners of Colstrip Unit 3, and the operator of Units 3 and 4. The plaintiffs allege they have suffered adverse effects from coal dust generated during operations associated with Colstrip. On August 26, 2021, the claim was amended to add in excess of 100 plaintiffs. It also added NorthWestern, the other owners of Colstrip, and Westmoreland Rosebud Mining LLC, as defendants. Plaintiffs are seeking economic damages, costs and disbursements, punitive damages, attorneys’ fees, and an injunction prohibiting defendants from allowing coal dust to blow onto plaintiffs’ properties. Since this lawsuit remains in its discovery stages, we are unable to predict outcomes. We continue to evaluate a range of reasonably possible losses.

BNSF Demands for Indemnity and Remediation Costs

NorthWestern has received a demand for indemnity from BNSF Railway Company (BNSF) for past and future environmental investigation and remediation costs incurred by BNSF at one of the three operable units at the Anaconda Copper Mining (ACM) Smelter and Refinery Superfund Site, located near Great Falls, Montana. Smelter and refining operations at the site commenced in 1893 and continued until 1980.

NorthWestern owns property in the Railroad Corridor sub-section of Operable Unit 1. BNSF claims it is entitled to indemnity and contribution from NorthWestern for the costs it has and will incur to investigate and remediate contamination in Operable Unit 1. NorthWestern and BNSF have settled the majority of the dispute for a non-material sum. Any potential remaining claims are not expected to be material.

Yellowstone County Generating Station Air Permit

On October 21, 2021, the Montana Environmental Information Center and the Sierra Club filed a lawsuit in Montana State District Court, against the MDEQ and NorthWestern, alleging that the environmental analysis conducted by MDEQ prior to issuance of the Yellowstone County Generating Station's air quality construction permit was inadequate. On April 4, 2023, the Montana District Court issued an order finding MDEQ's environmental analysis was deficient in not addressing exterior lighting and greenhouse gases and remanded it back to MDEQ to address the deficiencies and vacated the air quality permit pending that remand. As a result of the vacatur of the permit, we paused construction. On June 8, 2023, the Montana District Court granted our motion to stay the order vacating the air quality permit pending the outcome of our notice of appeal with the Montana Supreme Court. Oral argument is scheduled for April 22, 2024 and a determination of the appeal will follow. We recommenced construction in June 2023 and expect the plant to be operational no later than the end of the third quarter 2024. The ultimate resolution of the lawsuit challenging the Yellowstone County Generating Station air quality permit could delay the project and increase costs.

During the litigation of the air permit, Montana House Bill 971 was signed into law, preventing the MDEQ from, except under certain exceptions, evaluating greenhouse gas emissions and corresponding impacts to the climate in environmental reviews of large projects such as coal mines and power plants. On June 1, 2023, the MDEQ issued its supplemental environmental assessment that contained the updated exterior lighting analysis, and the MDEQ indicated that no other analysis was necessary. The comment period concerning the MDEQ’s supplemental air quality permit ended on July 3, 2023. On August 4, 2023, the Montana First Judicial District Court in Held v. State of Montana, a separate case by Montana youths alleging climate damages, issued its order finding House Bill 971 unconstitutional delaying the issuance of the revised Yellowstone County Generating Station's air permit. The Montana Supreme Court granted NorthWestern permission to participate in the Held appeal. The outcome of the Held case could pose additional delays and costs for the Yellowstone County Generating Station.

Other Legal Proceedings

We are also subject to various other legal proceedings, governmental audits and claims that arise in the ordinary course of business. In our opinion, the amount of ultimate liability with respect to these other actions will not materially affect our financial position, results of operations, or cash flows.

(19) Revenue from Contracts with Customers

Accounting Policy

Our revenues are primarily from tariff based sales. We provide gas and/or electricity to customers under these tariffs without a defined contractual term (at-will). As the revenue from these arrangements is equivalent to the electricity or gas supplied and billed in that period (including estimated billings), there will not be a shift in the timing or pattern of revenue recognition for such sales. We have also completed the evaluation of our other revenue streams, including those tied to longer term contractual commitments. These revenue streams have performance obligations that are satisfied at a point in time, and do not have a shift in the timing or pattern of revenue recognition.

Customers are billed monthly on a cycle basis. To match revenues with associated expenses, we accrue unbilled revenues for electric and natural gas services delivered to customers, but not yet billed at month-end.

Nature of Goods and Services

We currently provide retail electric and natural gas services to three primary customer classes. Our largest customer class consists of residential customers, which include single private dwellings and individual apartments. Our commercial customers consist primarily of main street businesses, and our industrial customers consist primarily of manufacturing and processing businesses that turn raw materials into products.

Electric Segment - Our regulated electric utility business primarily provides generation, transmission, and distribution services to our customers in our Montana and South Dakota jurisdictions. We recognize revenue when electricity is delivered to the customer. Payments on our tariff based sales are generally due in 20-30 days after the billing date.

Natural Gas Segment -Our regulated natural gas utility business primarily provides production, storage, transmission, and distribution services to our customers in our Montana, South Dakota, and Nebraska jurisdictions. We recognize revenue when natural gas is delivered to the customer. Payments on our tariff based sales are generally due in 20-30 days after the billing date.

Disaggregation of Revenue

The following tables disaggregate our revenue for the twelve months ended by major source and customer class (in millions):

(20) Segment and Related Information

Our reportable business segments are primarily engaged in the electric and natural gas utility businesses. The remainder of our business activities are presented as other, which primarily consists of unallocated corporate costs and some limited unregulated activity within the energy industry.

We evaluate the performance of these segments based on utility margin. The accounting policies of the operating segments are the same as the parent except that the parent allocates some of its operating expenses to the operating segments according to a methodology designed by management for internal reporting purposes and involves estimates and assumptions.

Financial data for the business segments for the twelve months ended are as follows (in thousands):

(21) Fourth Quarter Financial Data (Unaudited)

Our fourth quarter financial information has not been audited, but, in management's opinion, includes all adjustments necessary for a fair presentation. Amounts presented are in thousands, except per share data:

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF NORTHWESTERN ENERGY GROUP

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

CONDENSED BALANCE SHEET

CONDENSED STATEMENTS OF CASH FLOWS

NOTES TO CONDENSED FINANCIAL STATEMENTS

(1) Basis of Presentation

NorthWestern Energy Group is an energy services holding company that conducts substantially all of its business operations through its subsidiaries, NW Corp and NWE Public Service. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These financial statements, in which NorthWestern Energy Groups' subsidiary has been included using the equity method of accounting, should be read in conjunction with the consolidated financial statements and notes thereto of NorthWestern Energy Group contained elsewhere within this Form 10-K.

There were $39.0 million of cash dividends paid to NorthWestern Energy Group from wholly-owned subsidiaries for the year ended December 31, 2023.