BLACK HILLS CORP SD

December 31, 2023, 2022 and 2021

(1)BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Corporation is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities and Gas Utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.

Use of Estimates and Basis of Presentation

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.

Principles of Consolidation

The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, have been consolidated. All intercompany balances and transactions have been eliminated in consolidation.

We use the proportionate consolidation method to account for our ownership interest in any jointly-owned facility. See Note 6 for additional information.

Non-controlling Interests

We account for changes in our controlling interests of subsidiaries according to ASC 810, Consolidation. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that non-controlling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the non-controlling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 12 for additional information.

Variable Interest Entities

We evaluate arrangements and contracts with other entities to determine if they are VIEs and if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, non-controlling interest and results of activities of a VIE in its consolidated financial statements.

A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and non-controlling interests at fair value and subsequently account for the VIE as if it were consolidated.

Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See Note 12 for additional information.

Cash, Cash Equivalents and Restricted Cash

We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We maintain cash accounts for various specified purposes, which are classified as restricted cash.

Revenue Recognition

Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. Our primary types of revenue contracts are:

•

Regulated natural gas and electric utility services tariffs - Our Utilities have regulated operations, as defined by ASC 980, Regulated Operations, that provide services to regulated customers under tariff rates, charges, terms and conditions of service and prices determined by the jurisdictional regulators designated for our service territories. Our regulated services primarily encompass single performance obligations for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the state or federal regulatory commissions to establish contractual rates between the utility and its customers. All of our Utilities’ regulated sales are subject to regulatory-approved tariffs.

•

Power sales agreements - Our Electric Utilities segment has long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, we also sell excess energy to other load-serving entities on a short-term basis. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered. Certain energy sale and purchase transactions with the same counterparty and at the same delivery point are netted to reflect the economic substance of the arrangement.

The majority of our revenue contracts are based on variable quantities delivered. Any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer.

Revenue Not in Scope of ASC 606

Other revenues included in the tables in Note 4 include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 842, Leases, derivative revenue under ASC 815, Derivatives and Hedging, and alternative revenue programs revenue under ASC 980, Regulated Operations.

Significant Judgments and Estimates

Unbilled Revenue

To the extent that deliveries have occurred, but a bill has not been issued, our Utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month, the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets.

Contract Balances

The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts receivable, which is further discussed below.

See Note 4 for additional information.

Accounts Receivable and Allowance for Credit Losses

Accounts receivable are stated at billed and estimated unbilled amounts, net of allowance for credit losses, and do not bear interest. We maintain an allowance for credit losses which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectability.

In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for credit losses to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, expected losses, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.

We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties.

Following is a summary of accounts receivable as of December 31 (in millions):

Changes to allowance for credit losses for the years ended December 31, were as follows (in millions):

Materials, Supplies and Fuel

Materials and supplies represent parts and supplies for our business operations. Fuel represents diesel oil and gas used by our electric generating facilities to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are recorded using the weighted-average cost method and are valued at the lower-of-cost or net realizable value. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas.

The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in millions):

Property, Plant and Equipment

Property, plant and equipment are stated at cost, which includes construction-related direct labor and material costs, indirect construction costs including labor and related costs of departments associated with supporting construction activities, and AFUDC. Additions to and significant replacements of property are charged to property, plant and equipment at cost. We also classify our Cushion Gas as Property, plant and equipment. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.

We receive contributions in aid of construction (CIACs) from third parties that are generally intended to defray all or a portion of the costs for certain capital projects. Such CIAC costs are recorded as a reduction to Property, plant, and equipment.

The cost of regulated utility property, plant and equipment retired, or otherwise disposed in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs related to our regulated properties that do not have legal retirement obligations are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other operating assets result in gains or losses recognized as a reduction to Operations and maintenance expense.

See Note 5 for additional information.

Depreciation

Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various classes of property. The composite depreciation method is applied to regulated utility property. Depreciation studies are conducted periodically to update composite rates and are approved by state utility commissions and/or the FERC when required. Capitalized mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-regulated power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run.

AFUDC

Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. The following table presents AFUDC amounts (in millions) for the years ended December 31:

We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets.

Asset Retirement Obligations

Accounting standards for AROs associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations, and regulated operations without a corresponding recovery mechanism, is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. The accounting for the obligation for regulated operations with a regulatory mechanism has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability.

We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations. See Note 7 for additional information.

Goodwill and Intangible Assets

Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life are amortized over their estimated useful lives.

We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns our testing date with our financial planning process.

The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment.

Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. These valuations require significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business plans and adjusted as appropriate for our view of market participant assumptions, with long range cash flows estimated using a terminal value calculation; 2) estimates of long-term growth rates for our businesses; 3) the determination of an appropriate weighted-average cost of capital or discount rate; and 4) the utilization of market information such as recent sales transactions for comparable assets within the utility and energy industries.

We believe that goodwill reflects the inherent value of the relatively stable, long-lived cash flows of our Utilities businesses, considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our Utilities, and those businesses vertically integrated. Goodwill amounts have not changed since 2016.

As of December 31,2023 and 2022, Goodwill balances were as follows (in millions):

Our intangible assets represent contract intangibles, easements, rights-of-way, customer listings and trademarks. The finite-lived intangible assets are amortized using a straight-line method based on estimated useful lives; these assets are currently being amortized from 2 years to 41 years. Changes to intangible assets for the years ended December 31, were as follows (in millions):

(a)

Amortization expense for existing intangible assets is expected to be $1.2 million for each year of the next five years.

Accrued Liabilities

The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of December 31 (in millions):

Fair Value Measurements

Financial Instruments

We use the following fair value hierarchy for determining inputs for our financial instruments. Our assets and liabilities for financial instruments are classified and disclosed in one of the following fair value categories:

Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis.

Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 — Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable, such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

Valuation Methodologies for Derivatives

The wholesale electric energy and natural gas commodity contracts for our Utilities are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2). For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a credit valuation adjustment based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position.

See Notes 10 and 13 for additional information.

Derivatives and Hedging Activities

All our derivatives are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time and pricing is clearly and closely related to the asset being purchased or sold. Normal purchase and sales contracts are recognized when the underlying physical transaction is completed under the accrual basis of accounting.

In addition, certain derivative contracts approved by regulatory authorities are either recovered or refunded through customer rates. Any changes in the fair value of these approved derivative contracts are deferred as a regulatory asset or regulatory liability pursuant to ASC 980, Regulated Operations.

We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The gain or loss on these designated derivatives is deferred in AOCI and reclassified into earnings when the corresponding hedged transaction is recognized in earnings. Changes in the fair value of all other derivative contracts are recognized in earnings.

We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. We reflect the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when a legal right of offset exists. Therefore, the gross amounts are not indicative of either our actual credit or net economic exposures.

The cash impacts of settled derivatives are recorded as operating activities on the Consolidated Statements of Cash Flows.

See Notes 9,10 and 11 for additional information.

Debt Discounts, Premiums and Deferred Financing Costs

Deferred financing costs include loan origination fees, underwriter fees, legal fees and other costs directly attributable to the issuance of debt. Debt discounts, premiums and deferred financing costs are amortized over the estimated useful life of the related debt. Unamortized discounts, premiums and deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities. See Note 8 for additional information.

Regulatory Accounting

Our regulated Utilities are subject to cost-of-service regulation and earnings oversight from federal and state regulatory commissions. Our Utilities account for income and expense items in accordance with accounting standards for regulated operations. These accounting policies differ in some respects from those used by our non-regulated businesses. Under these regulated operations accounting standards:

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Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.

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Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Management continually assesses the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.

If changes in the regulatory environment occur, we may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from our balance sheet. Such changes could adversely affect our results of operations, financial position or cash flows.

See Note 2 for additional information.

Income Taxes

The Company is subject to federal income tax as well as income tax in various state and local jurisdictions. The Company and its subsidiaries file consolidated federal income tax returns. Each subsidiary records both federal and state income taxes as if it were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.

We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements.

It is our policy to apply the flow-through method of accounting for ITCs. Under the flow-through method, ITCs are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the ITC being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit.

We recognize interest income or interest expense and penalties related to income tax matters in Income tax expense on the Consolidated Statements of Income.

We have elected to account for transferable clean energy tax credits, including PTCs and ITCs within the provision for income taxes.

We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities or in Deferred income tax liabilities, net on the accompanying Consolidated Balance Sheets. See Note 15 for additional information.

Earnings per Share of Common Stock

Basic earnings per share is computed by dividing Net income available for common stock by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to equity units, outstanding stock options, restricted stock and performance shares under our equity compensation plans.

A reconciliation of share amounts used to compute earnings per share is as follows for the years ended December 31 (in millions, except earnings per share amounts):

The following securities were excluded from the diluted earnings per share computation for the years ended December 31 because of their anti-dilutive nature:

Share-Based Compensation

We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation, 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. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures. See Note 14 for additional information.

Pension and Other Postretirement Plans

We recognize on our Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other postretirement plans with current-year changes in actuarial gains or losses recognized in AOCI, except for those plans at certain of our regulated utilities that can recover portions of their pension and postretirement obligations through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of ASC 715, Compensation-Retirement Benefits, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.

Recently Issued Accounting Standards

Improvements to Reportable Segment Disclosures, ASU 2023-07

In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segment Disclosures, which expands public entities’ segment disclosures by requiring disclosure of significant segment expenses that are regularly reviewed by the CODM and included within each reported measure of segment profit or loss, an amount and description of its composition for other segment items, and interim disclosures of a reportable segment’s profit or loss and assets. The ASU also allows, in addition to the measure that is most consistent with GAAP, the disclosure of additional measures of segment profit or loss that are used by the CODM in assessing segment performance and deciding how to allocate resources. The ASU is effective for our Annual Report on Form 10-K for the fiscal year ended December 31, 2024, and subsequent interim periods, with early adoption permitted. We do not expect the ASU to have an impact on our financial position, results of operations and cash flows; however, are currently evaluating the impact on our consolidated financial statement disclosures.

Improvements to Income Tax Disclosures, ASU 2023-09

In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, which expands public entities’ annual disclosures by requiring disclosure of tax rate reconciliation amounts and percentages for specific categories, income taxes paid disaggregated by federal and state taxes, and income tax expense disaggregated by federal and state taxes jurisdiction. The ASU is effective for our Annual Report on Form 10-K for the fiscal year ended December 31, 2025, with early adoption permitted. We do not expect the ASU to have an impact on our financial position, results of operations and cash flows; however, are currently evaluating the impact on our consolidated financial statement disclosures.

(2)REGULATORY MATTERS

We had the following regulatory assets and liabilities as of December 31 (in millions):

(a)

Timing of Winter Storm Uri incremental cost recovery and associated carrying costs vary by jurisdiction. See further information below.

(b)

Recovery/repayment of costs, but we are not allowed a rate of return.

(c)

In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.

Regulatory assets represent items we expect to recover from customers through probable future rates.

Winter Storm Uri - Our Utilities have received commission approval to recover incremental fuel, purchased power and natural gas costs associated with Winter Storm Uri. In certain jurisdictions, we also received commission approval to recover carrying costs. As of December 31, 2023, we estimate that our remaining Winter Storm Uri regulatory asset has a weighted-average recovery period of 2.2 years.

Deferred Energy and Fuel Cost Adjustments - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our Electric Utilities’ customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state regulatory commission. Our Electric Utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state regulatory commissions.

Deferred Gas Cost Adjustments - Our regulated Gas Utilities have GCA provisions that allow them to pass the cost of gas on to their customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic monthly, quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state regulatory commissions.

Gas Price Derivatives - Our regulated Gas Utilities, as allowed or required by state regulatory commissions, have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities. Gas price derivatives at December 31, 2023 are hedged over a maximum forward term oftwo years.

Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.

Employee Benefit Plans and Related Deferred Taxes - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in regulatory assets rather than in AOCI. In addition, this regulatory asset includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment.

Environmental- Environmental costs associated with certain former manufactured gas plant sites. These costs are first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining cost will be requested for recovery in future rate filings. Recovery for these specific environmental costs has not yet been approved by the applicable state regulatory commission and therefore, the recovery period is unknown at this time.

Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue.

Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer and result in lower utility rates in the year in which the tax benefits are realized. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a net tax benefit for costs considered currently deductible for tax purposes but are capitalized for book purposes.

Decommissioning Costs - South Dakota Electric and Colorado Electric received approval in 2014 for recovery of the remaining net book values and decommissioning costs of their decommissioned coal plants. In 2018, Arkansas Gas received approval to record Liquefied Natural Gas Plant decommissioning costs as a regulatory asset and received approval in 2020 to begin recovering those costs over three years.

Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.

Deferred Energy and Gas Costs - Deferred energy and gas costs that have been over-recovered through customer rates and will be returned to customers in future periods.

Employee Benefit Plans and Related Deferred Taxes - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with ASC 715, Compensation-Retirement Benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under ASC 715, Compensation-Retirement Benefits, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment.

Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs for which there is no legal obligation for removal included in depreciation expense.

Excess Deferred Income Taxes - The revaluation of the regulated utilities' deferred tax assets and liabilities due to the passage of the TCJA was recorded as excess deferred income taxes to be refunded to customers primarily using the normalization principles as prescribed in the TCJA. A majority of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets.

Recent Regulatory Activity

Arkansas Gas

On December 4, 2023, Arkansas Gas filed a rate review with the APSC seeking recovery of significant infrastructure investments in its 7,200-mile natural gas pipeline system. The rate review requests $44.1 million in new annual revenue with a capital structure of 48% equity and 52% debt and a return on equity of 10.5%. The request seeks to finalize rates in the fourth quarter of 2024.

Colorado Gas

RMNG Rate Review

On July 12, 2023, the CPUC approved a settlement agreement for RMNG's rate review filed on October 7, 2022. The agreement is expected to generate $8.2 million in new annual revenue and established a weighted average cost of capital of 6.93% with a capital structure that reflects an equity range of 50% to 52% and a debt range of 50% to 48% and a return on equity range of 9.5% to 9.7%. The settlement also shifted $8.3 million of SSIR revenue to base rates and terminated the SSIR. New rates were effective July 15, 2023.

Colorado Gas Rate Review

On May 9, 2023, Colorado Gas filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its 10,000-mile natural gas pipeline system. In the fourth quarter of 2023, Colorado Gas reached a settlement agreement with the CPUC staff and various intervenors for a general rate increase, which is subject to CPUC approval. The settlement is expected to generate $20.2 million of new annual revenue with a capital structure of 50.87% equity and 49.13% debt and a return on equity of 9.3%. If approved, new rates will be effective in February 2024.

Wyoming Gas

On May 18, 2023, Wyoming Gas filed a rate review with the WPSC seeking recovery of significant infrastructure investments in its 6,400-mile natural gas pipeline system. On January 17, 2024, the WPSC approved a settlement agreement for a general rate increase which is expected to generate $13.9 million in new annual revenue with a capital structure of 51% equity and 49% debt and a return on equity of 9.85%. New rates were effective February 1, 2024. The agreement also included approval of a four-year extension of the Wyoming Integrity Rider.

Wyoming Electric

On June 1, 2022, Wyoming Electric filed a rate review with the WPSC seeking recovery of significant infrastructure investments in its 1,330-mile electric distribution and 59-mile electric transmission systems. On January 26, 2023, the WPSC approved a settlement agreement with intervening parties for a general rate increase. The settlement is expected to generate $8.7 million in new annual revenue with a capital structure of 52% equity and 48% debt and a return on equity of 9.75%. New rates were effective March 1, 2023. The agreement also included approval of a new rider that will be filed annually to recover transmission investments and expenses.

(3)COMMITMENTS, CONTINGENCIES AND GUARANTEES

Unconditional Purchase Obligations

We have various PPAs and transmission service agreements, which extend to 2032, to support our Electric Utilities' capacity and energy needs beyond our regulated power plants' generation.

Our Utilities purchase natural gas, including transportation and storage capacity, to meet customers' needs under short-term and long-term purchase contracts. These contracts extend to 2044.

The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services and natural gas transportation and storage agreements (in millions):

(a) This schedule does not reflect renewable energy PPA future obligations since these agreements vary based on weather conditions.

Lease Agreements

Lessee

We lease from third parties certain office and operation center facilities, communication tower sites, equipment and materials storage. Our leases have remaining terms ranging from less thanone year to 32 years, including options to extend that are reasonably certain to be exercised. Our operating and finance leases were not material to the Company’s Consolidated Financial statements.

Lessor

We lease to third parties certain generating station ground leases, communication tower sites and a natural gas pipeline. These leases have remaining terms ranging from less thanone year to 31 years. Lease revenue was not material for the years ended December 31, 2023, 2022 and 2021.

As of December 31,2023, scheduled maturities of operating lease payments to be received in future years were as follows (in millions):

Environmental Matters

We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. Laws and regulations can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies.

Reclamation Liability

For our Pueblo Airport Generation site, we posted a bond with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero-discharge facility. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.

Under our land leases for our wind generation facilities, we are required to reclaim land where we have placed wind turbines. The reclamation liabilities are recorded at the present value of the estimated future cost to reclaim the land.

Under its mining permit, WRDC is required to reclaim all land where it has mined reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.

See Note 7 for additional information.

Manufactured Gas Plant

In 2008, we acquired whole and partial liabilities for former manufactured gas plant sites in Nebraska and Iowa, which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.4 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. We also have a $2.7 million regulatory asset for manufactured gas plant sites; see Note 2 for additional information. As of December 31, 2023, we had $4.1 million and $0.6 million accrued for remediation of the manufactured gas plant sites in Iowa and Nebraska, respectively. Iowa's liabilities are included in Accrued Liabilities and Nebraska's liabilities are included in Other deferred credits and other liabilities on our Consolidated Balance Sheets. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.

Contingencies and Legal Proceedings

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the consolidated financial statements to satisfy alleged liabilities are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations will not exceed the amounts reflected in the consolidated financial statements.

We record gain contingencies when realized and expected recoveries under applicable insurance contracts when we are assured of recovery.

GT Resources, LLC v. Black Hills Corporation, Case No. 2020CV30751 (U.S. District Court for the City and County of Denver, Colorado)

On April 13, 2022, a jury awarded $41 million for claims made by GT Resources, LLC (“GTR”) against BHC and two of its subsidiaries (Black Hills Exploration and Production, Inc. and Black Hills Gas Resources, Inc.), which ceased oil and natural gas operations in 2018 as part of BHC’s decision to exit the exploration and production business. The claims involved a dispute over a 2.3 million-acre concession award in Costa Rica which was acquired by a BHC subsidiary in 2003. GTR retained rights to receive a royalty interest on any hydrocarbon production from the concession upon the occurrence of contingent events. GTR contended that BHC and its subsidiaries failed to adequately pursue the opportunity and failed to transfer the concession to GTR. We appealed this verdict to the Colorado Court of Appeals. On October 19, 2023, the Appellate Court reversed and remanded the case with directions limiting any retrial to the narrow issue of whether there was improper interference with the prospective conveyance of the concession. We continue to believe this lawsuit has no merit and will vigorously defend it. At this time, we do not believe any losses from this matter will have a material impact on our financial position, results of operations and cash flows.

Gain Contingency -- Wygen 1 Business Interruption Insurance Recovery

In September 2021, Wygen I experienced an unplanned outage that continued until December 2021. For the year ended December 31, 2021, the outage resulted in lost revenues at our subsidiaries Black Hills Wyoming and WRDC. A claim for these losses was submitted under ourbusiness interruption insurance policy. During the third quarter of 2023 we recovered $5.0 million from our business interruption insurance, which was recognized as Revenue in our Consolidated Statements of Income for year ended December 31, 2023.

Indemnification

In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities.

Guarantees

We have entered into various parent company-level guarantees providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. These guarantees do not represent incremental consolidated obligations, but rather, represent guarantees of subsidiary obligations to allow those subsidiaries to conduct business without posting other forms of assurance. The agreements, which are off-balance sheet commitments, include support for business operations, indemnification for reclamation and surety bonds. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by these guarantees, such liabilities are included in our Consolidated Balance Sheets.

We had the following guarantees in place as of (in millions):

(4)REVENUE

The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reportable segments, for the years ended December 31,2023, 2022 and 2021. Sales tax and other similar taxes are excluded from revenues.

(5)PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment at December 31 consisted of the following (dollars in millions):

(a) The plant acquisition adjustment, which relates to the acquisition of our ownership interest in Wyodak Plant, is included in rate base and is being recovered with 7 years remaining.

(a) Depreciation of Cushion Gas is determined by the respective regulatory jurisdiction in which the Cushion Gas resides. In 2022, assets classified as Cushion gas - depreciable were fully depreciated and removed from gross plant in service and accumulated depreciation.

(6)JOINTLY OWNED FACILITIES

Our consolidated financial statements include our share of several jointly-owned facilities as described below. Our share of the facilities’ expenses is reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income. Each owner of the facility is responsible for financing its investment in the jointly-owned facilities.

At December 31,2023, our interests in jointly-owned generating facilities and transmission systems were (in millions):

(a)

In addition to supplying South Dakota Electric with coal for its share of the Wyodak Plant, our mine supplies PacifiCorp’s share of the coal under a separate long-term agreement through December 31, 2026, with an annual renewal option for one-year extensions. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves.

(b)

South Dakota Electric retains responsibility for plant operations. WRDC supplies fuel to Wygen III for the life of the plant.

(c)

Black Hills Wyoming retains responsibility for plant operations. WRDC supplies fuel to Wygen I for the life of the plant.

(7)ASSET RETIREMENT OBLIGATIONS

We have identified legal obligations related to reclamation of mining sites; removal of fuel tanks, transformers containing polychlorinated biphenyls, an evaporation pond; and reclamation of wind turbine sites at our Electric Utilities segment. In addition, we have identified legal obligations related to retirement of gas pipelines, wells and compressor stations at our Gas Utilities and removal of asbestos at our Utilities. We periodically review and update estimated costs related to these AROs. The actual cost may vary from estimates due to regulatory requirements, changes in technology and increased labor, materials and equipment costs.

The following tables present the details of AROs which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in millions):

(a)

The Revisions to Prior Estimates were primarily driven by changes in estimates associated with natural gas wells and compressor stations.

We also have legally required AROs related to certain assets within our electric transmission and distribution systems. These retirement obligations are pursuant to an easement or franchise agreement and are only required if we discontinue our utility service under such easement or franchise agreement. Accordingly, it is not possible to estimate a time period when these obligations could be settled, and therefore, a liability for the cost of these obligations cannot be measured at this time.

(8)FINANCING

Shelf Registration Statement

We maintain an effective shelf registration statement with the SEC under which we may issue, from time to time, an unspecified amount of senior debt securities, subordinate debt securities, common stock, preferred stock, warrants and other securities. In anticipation of the approaching expiration of our previous shelf registration statement on Form S-3 originally filed on August 4, 2020 (Registration No. 333-240320), we filed a new shelf registration statement on Form S-3 on June 16, 2023 (Registration No. 333-272739).

Short-term debt

Revolving Credit Facility and CP Program

On May 9, 2023, we amended and restated our corporate Revolving Credit Facility, which replaced LIBOR as a benchmark interest rate with the SOFR. The adoption of SOFR as a benchmark interest rate was in advance of the scheduled elimination of LIBOR as a benchmark interest rate on June 30, 2023. No other significant terms or conditions, including borrowing capacity, credit spreads or financial covenants were modified under these amendments and restatements.

We have a $750 million Revolving Credit Facility that matures on July 19, 2026, withtwo one-year extension options (subject to consent from lenders). This facility includes an accordion feature that allows us to increase total commitments up to $1.0 billion with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment. Borrowings continue to be available under a base rate or various SOFR rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our Corporate credit rating from S&P, Fitch and Moody's for our senior unsecured long-term debt. Based on our current credit ratings, the margins for base rate borrowings, SOFR borrowings and letters of credit were 0.125%,1.125% and 1.125%, respectively, at December 31,2023. Based on our credit ratings, the commitment fee on unused amounts was 0.175%.

We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption.

Our Revolving Credit Facility and CP Program, which are classified as Notes payable on the Consolidated Balance Sheets, had the following borrowings, outstanding letters of credit, and available capacity at December 31 (dollars in millions):

(a)

Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.

Revolving Credit Facility and CP Program borrowing activity for the years ended December 31 was as follows (in millions):

Deferred Financing Costs on the Revolving Credit Facility

Total accumulated deferred financing costs on the Revolving Credit Facility of $8.9 million are being amortized over its estimated useful life and were included in Interest expense on the accompanying Consolidated Statements of Income. See below for additional details.

Long-term debt

Long-term debt outstanding was as follows (dollars in millions):

(a)

Variable interest rate.

(b)

A reimbursement agreement is in place with Wells Fargo on behalf of Wyoming Electric for the $10 million bonds due March 1, 2027. In the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds.

(c)

Includes deferred financing costs associated with our Revolving Credit Facility of $1.1 million and $1.8 million as of December 31,2023 and December 31, 2022, respectively.

Scheduled maturities of long-term debt and associated interest payments by year are shown below (in millions):

(a)

Long-term debt amounts do not include deferred financing costs or discounts or premiums on debt. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2023.

Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2023. See below for additional information.

Substantially all of the tangible utility property of South Dakota Electric and Wyoming Electric is subject to the lien of indentures securing their first mortgage bonds. First mortgage bonds of South Dakota Electric and Wyoming Electric may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures.

Debt Transactions

On September 15, 2023, we completed a public debt offering of $450 million,6.15% senior unsecured notes due May 15, 2034. Proceeds from the offering, which were net of $7.6 million of deferred financing costs, along with available cash were used to repay all of our $525 million principal amount outstanding notes on their November 30, 2023 maturity date and for other general corporate purposes.

On March 7, 2023, we completed a public debt offering of $350 million,5.95%five year senior unsecured notes due March 15, 2028. The proceeds from the offering, which were net of $4.2 million of deferred financing costs, were used to repay notes outstanding under our CP Program and for other general corporate purposes.

Debt Covenants

Revolving Credit Facility

We were in compliance with all of our Revolving Credit Facility covenants as of December 31, 2023. We are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Subject to applicable cure periods, a violation of this covenant would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. As of December 31, 2023, our Consolidated Indebtedness to Capitalization Ratio was 0.58 to 1.00.

Wyoming Electric

Wyoming Electric was in compliance with all covenants within its financing agreements as of December 31, 2023. Wyoming Electric is required to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of December 31, 2023, Wyoming Electric's debt to capitalization ratio was 0.51 to 1.00.

Dividend Restrictions

Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends when a default or event of default occurs.

Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries.

Our Utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of December 31, 2023, the amount of restricted net assets at our Utilities that may not be distributed to our utility holding company in the form of a loan or dividend was approximately $142.6 million.

South Dakota Electric and Wyoming Electric are generally limited to the amount of dividends allowed to be paid to our utility holding company under certain financing agreements.

Equity

Although our aforementioned shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions imposed by federal and state regulatory authorities. Our articles of incorporation authorize the issuance of 100 million shares of common stock and 25 million shares of preferred stock. As of December 31,2023, we had approximately 68 million shares of common stock outstanding and no shares of preferred stock outstanding.

At-the-Market Equity Offering Program

As previously disclosed, on August 4, 2020, we entered into an Amended and Restated Equity Distribution Sales Agreement ("Previous Sales Agreement") to sell shares of common stock up to an aggregate of $400 million, from time to time, through our ATM program utilizing our shelf registration statement. In conjunction with the new shelf registration statement filing discussed above, we entered into a new Equity Distribution Sales Agreement ("Sales Agreement") on June 16, 2023. We also terminated the Previous Sales Agreement on June 16, 2023. The Sales Agreement is similar to the Previous Sales Agreement and allows us to sell shares of common stock up to an aggregate of $400 million through our ATM program.

ATM activity for the years ended December 31 was as follows (in millions, except Average price per share amounts):

Shareholder Dividend Reinvestment and Stock Purchase Plan

Effective as of July 7, 2023, we terminated our DRSPP. On July 10, 2023, we filed a post-effective amendment to amend the Registration Statement on Form S-3 (File No. 333-240319) filed with the SEC on August 4, 2020. The filing of this post-effective amendment de-registered all shares of common stock that were issuable under the DRSPP but not sold as of July 7, 2023. With the termination of the DRSPP, a direct stock purchase plan is being offered which will allow shareholders to continue making share transactions. This plan is sponsored and administered solely by EQ Shareowner Services, our transfer agent.

(9)RISK MANAGEMENT AND DERIVATIVES

Market and Credit Risk Disclosures

Our activities in the energy industry expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk.

Market Risk

Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. We are exposed, but not limited to, the following market risks:

•

Commodity price risk associated with our retail natural gas and wholesale electric power marketing activities and our fuel procurement for several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as the COVID-19 pandemic, weather (e.g. Winter Storm Uri), geopolitical events, market speculation, recession, inflation, pipeline constraints, and other factors that may impact natural gas and electric supply and demand; and

•

Interest rate risk associated with future debt, including reduced access to liquidity during periods of extreme capital markets volatility, such as the 2008 financial crisis and the COVID-19 pandemic.

Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.

We attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements and mitigating credit exposure with less creditworthy counterparties through parental guarantees, cash collateral requirements, letters of credit and other security agreements.

We perform periodic credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses and any specific customer collection issue that is identified. Our credit exposure at December 31, 2023 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies.

Derivatives and Hedging Activity

Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 10.

The operations of our Utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to natural gas price volatility. Therefore, as allowed or required by state utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.

For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with state regulatory commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income.

We periodically have wholesale power purchase and sale contracts used to manage purchased power costs and load requirements associated with serving our electric customers that are considered derivative instruments due to not qualifying for the normal purchase and normal sales exception to derivative accounting. Changes in the fair value of these commodity derivatives are recognized in the Consolidated Statements of Income.

To support our Choice Gas Program customers, we buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales during time frames ranging from January 2024 through October 2025. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at least quarterly.

The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our utilities are comprised of both short and long positions. We had the following net long positions as of:

(a)

Term reflects the maximum forward period hedged.

(b)

As of December 31,2023,2,101,700 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges.

(c)

Volumes exclude derivative contracts that qualify for the normal purchase, normal sales exception permitted by GAAP.

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At December 31, 2023, the Company posted $2.0 million related to such provisions, which is included in Other current assets on the Consolidated Balance Sheets.

Derivatives by Balance Sheet Classification

The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in millions):

Derivatives Designated as Hedge Instruments

The impact of cash flow hedges on our Consolidated Statements of Comprehensive Income and Consolidated Statements of Income is presented below for the years ended December 31,2023, 2022 and 2021. Note that this presentation does not reflect the gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.

As of December 31, 2023, $5.9 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income for the years ended December 31, 2023, 2022 and 2021. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.

As discussed above, financial instruments used in our regulated Gas Utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in a Regulatory asset related to these financial instruments used in our Gas Utilities were $5.1 million and $8.8 million at December 31, 2023 and 2022, respectively.

Forour Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Consolidated Statements of Income.

(10)FAIR VALUE MEASUREMENTS

Recurring Fair Value Measurements

Derivatives

Valuation methodologies for our derivatives are detailed within Note 1. The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments.

(a)

As of December 31, 2023,$1.9 million of our commodity derivative gross assets and $3.3 million of our commodity derivative gross liabilities, as well as related gross collateral amounts, were subject to master netting agreements.

(a)

As of December 31, 2022, $4.3 million of our commodity derivative assets and $4.8 millionof our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements.

Pension and Postretirement Plan Assets

A discussion of the fair value of our Pension and Postretirement Plan assets is included in Note 13.

Other Fair Value Measurements

The carrying amount of cash and cash equivalents, restricted cash and equivalents and short-term borrowings approximates fair value due to their liquid or short-term nature. Cash, cash equivalents and restricted cash are classified in Level 1 in the fair value hierarchy. Notes payable consist of commercial paper borrowings and are not traded on an exchange; therefore, they are classified as Level 2 in the fair value hierarchy.

The following table presents the carrying amounts and fair values of financial instruments not recorded at fair value on the Consolidated Balance Sheets at December 31 (in millions):

(a)

Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. Carrying amount of long-term debt is net of deferred financing costs.

(11)OTHER COMPREHENSIVE INCOME

We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized.

The following table details reclassifications out of AOCI and into Net income. The amounts in parentheses below indicate decreases to Net income in the Consolidated Statements of Income for the period, net of tax (in millions):

Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in millions):

(12)VARIABLE INTEREST ENTITY

Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. In 2016, Black Hills Electric Generation sold a 49.9%, non-controlling interest in Black Hills Colorado IPP to a third-party buyer. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Colorado Electric.

Net income available for common stock for the years ended December 31, 2023, 2022 and 2021 was reduced by$13.8 million,$12.4 million, and $14.5 million, respectively, attributable to this non-controlling interest. The net income allocable to the non-controlling interest holder is based on ownership interest with the exception of certain agreed upon adjustments. Distributions of net income attributable to this non-controlling interest are due within 30 days following the end of a quarter but may be withheld as necessary by Black Hills Electric Generation.

Black Hills Colorado IPP has been determined to be a VIE in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations.

We have recorded the following assets and liabilities on our Consolidated Balance Sheets related to the VIE described above as of December 31 (in millions):

(13)EMPLOYEE BENEFIT PLANS

Defined Contribution Plans

We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation in the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis.

The 401(k) Plan provides a Company matching contribution for all eligible participants. Certain eligible participants who are not currently accruing a benefit in the Pension Plan also receive a Company retirement contribution based on the participant’s age and years of service. Vesting of all Company and matching contributions occurs at 20% per year with 100% vesting when the participant has 5 years of service with the Company.

Defined Benefit Pension Plan

We haveone defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The Pension Plan covers certain eligible employees of the Company. The benefits for the Pension Plan are based on years of service and calculations of average earnings during a specific time period prior to retirement. The Pension Plan is closed to new employees and frozen for certain employees who did not meet age and service-based criteria.

The Pension Plan assets are held in a Master Trust. Our Board of Directors has approved the Pension Plan’s investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Pension Plan’s benefit payment obligations. The Pension Plan’s assets consist primarily of equity, fixed income and hedged investments.

The expected rate of return on the Pension Plan assets is determined by reviewing the historical and expected returns of both equity and fixed income markets, taking into account asset allocation, the correlation between asset class returns and the mix of active and passive investments. The Pension Plan utilizes a dynamic asset allocation where the target range to return-seeking and liability-hedging assets is determined based on the funded status of the Plan. As of December 31, 2023, the expected rate of return on pension plan assets was based on the targeted asset allocation range of 20% to 28% return-seeking assets and 72% to 80% liability-hedging assets.

Our Pension Plan is funded in compliance with the federal government’s funding requirements.

Plan Assets

The percentages of total plan asset by investment category for our Pension Plan at December 31 were as follows:

Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are funded on a cash basis as benefits are paid.

Non-pension Defined Benefit Postretirement Healthcare Plan

BHC sponsors a retiree healthcare plan (Healthcare Plan) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plan for participating business units are pre-funded via VEBA trusts. Pre-65 retirees as well as a grandfathered group of post-65 retirees receive their retiree medical benefits through the Black Hills self-insured retiree medical plans.

Healthcare coverage for post-65 Medicare-eligible retirees is provided through an individual market healthcare exchange. We fund the Healthcare Plan on a cash basis as benefits are paid. The Healthcare Plan provides for partial pre-funding via VEBA trusts. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees located in the states of Arkansas, Iowa and Kansas. We do not pre-fund the Healthcare Plan for those employees outside Arkansas, Iowa and Kansas.

Plan Contributions

Contributions to the Pension Plan are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Healthcare benefits include company and participant paid premiums.

Contributions for the years ended December 31 were as follows (in millions):

We do not have any required contributions to our Pension Plan in 2024; however, we expect to make $2.3 million in contributions.

Fair Value Measurements

The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in millions):

(a)

Certain investments that are measured at fair value using NAV per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above.

Additional information about assets of the benefit plans, including methods and assumptions used to estimate the fair value of these assets, is as follows:

Pension Plan

Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Pension Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Pension Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2.

The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance:

Common Collective Trust-Real Estate Funds: These funds are valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments and rely on these reports for pricing the units of the fund.

Hedge Funds: These funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined, aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments.10% of the shares may be redeemed at the end of each month with a 15-day notice and full redemptions are available at the end of each quarter with 60-day notice and is limited to a percentage of the total net assets value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds.

Non-pension Defined Benefit Postretirement Healthcare Plan

Cash and Cash Equivalents: This represents an investment in Northern Institutional Government Assets Portfolio, which is a government money market fund. As shares held reflect quoted prices in an active market, they are categorized as Level 1.

Components of Net Periodic Expense

The following table provides a reconciliation of components of the net periodic expense (in millions):

Service costs are recorded in Operations and maintenance expense while non-service costs are recorded in Other expense on the Consolidated Statements of Income.

Actuarial gains and losses are amortized using a straight-line method over the average remaining service period of active plan participants or over the average remaining lifetime of the remaining plan participants if the plan is viewed as “all or almost all” inactive participants.

Other Plan Information

The following tables provide a reconciliation of the employee benefit plan obligations and fair value of employee benefit plan assets, amounts recognized on our Consolidated Balance Sheets, accumulated benefit obligation and elements of AOCI (in millions):

In 2012, we froze our Pension Plan and closed it to new participants. Since then, we have implemented various de-risking strategies including lump sum buyouts, the purchase of annuities and the reduction of return-seeking assets over time to a more liability-hedged portfolio. As a result, capital markets volatility had a limited impact to our unfunded status.

Assumptions

(a)

The estimated discount rate for the Defined Benefit Pension Plan is 5.0% for the calculation of the 2024 net periodic pension costs.

(b)

The expected rate of return on plan assets for the Defined Benefit Pension Plan is 6.0% for the calculation of the 2024 net periodic pension cost.

The healthcare benefit obligation at December 31 was determined as follows:

The following benefit payments to employees, which reflect future service, are expected to be paid (in millions):

(14)SHARE-BASED COMPENSATION PLANS

Our Amended and Restated 2015 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options, performance shares and performance share units. We had 2,132,275 shares available to grant at December 31, 2023.

Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting standards for stock compensation and is recognized over the vesting periods of the individual awards. As of December 31, 2023, total unrecognized compensation expense related to non-vested stock awards was $10.6 million and is expected to be recognized over a weighted-average period of 1.7 years. Stock-based compensation expense, which is included in Operations and maintenance on the accompanying Consolidated Statements of Income, was as follows for the years ended December 31 (in millions):

Restricted Stock

The fair value of restricted stock and restricted stock unit awards equals the market price of our stock on the date of grant.

The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over three years, contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period.

A summary of the status of the restricted stock and restricted stock units at December 31,2023, was as follows:

The weighted-average grant-date fair value of restricted stock granted, and the total fair value of shares vested during the years ended December 31, were as follows:

As of December 31, 2023, therewas $6.3 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 1.6 years.

Performance Share Units

Beginning in 2021, certain officers of the Company, and its subsidiaries, were granted performance share units which have athree-year vesting period, do not have voting rights until vested, and are subject to three specified conditions. A market condition of relative total shareholder return and two equally weighted performance metrics of average earnings per share and the average cost to serve. Beginning in 2023, the metric of natural gas emissions reduction by 2035 was added, resulting in three equally weighted performance metrics. The units are paid 100% in common stock should conditions be met and can range from 0% to 200% of the target award. Dividend equivalents are accrued during the vesting period and paid out based on the final number of shares awarded. In the event of participant’s death or retirement at age 55 or older, shares awarded vest on a pro-rata basis commensurate with the months of service performed over thethree-year period.

Performance Share Units - Market Condition

The fair value of each share unit is based on the Company’s closing price at December 31 of the year prior to the award and a Monte Carlo simulation. The Monte Carlo simulation is used to estimate expected share payout based on the Company’s TSR for athree-year performance period relative to the designated peer group beginning January 1 of the award year. The significant assumptions included in the company's Monte Carlo simulations were as follows:

Performance Share Units - Performance Condition

A performance condition share unit vests at the end of the three-year performance period if the specified performance conditions are achieved. The conditions are based on the Company’s average earnings per share, the average cost to serve and natural gas emissions reductions by 2035. The grant-date fair value for an individual outcome of a performance condition is determined by the closing common share price on the grant date or, beginning in 2023, the average ten-day closing common share price preceding the grant date.

The following table summarizes the performance share unit activity for the year ended December 31,2023:

As of December 31, 2023, therewas $4.0 million of unrecognized compensation expense related to outstanding performance share/units that is expected to be recognized over a weighted-average period of 1.8 years.

On January 25, 2024, the Compensation Committee of our Board of Directors confirmed a payout equal to 16.21% of target shares valued at $0.5 million. The payout was fully accrued at December 31,2023.

Performance Share Plan

Prior to 2021, certain officers of the Company and its subsidiaries became participants in a market-based performance share award plan. Performance shares are awarded based on our total shareholder return over designated performance periods as measured against a selected peer group. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria.

These performance share awards were paid 50% in cash and 50% in common stock.

The outstanding performance periods at December 31,2023 were as follows:

A summary of the status of the Performance Share Plan at December 31, 2023 was as follows:

(a)

The grant date fair values for the performance shares granted in 2020 were determined by Monte Carlo simulation using a blended volatility of 18%, comprised of 50% historical volatility and 50% implied volatilityand the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date.

Performance plan payouts have been as follows (in millions, except stock issued):

(15)INCOME TAXES

IRS Revenue Procedure 2023-15

On April 14, 2023, the IRS released Revenue Procedure 2023-15 “Amounts paid to improve tangible property.” The Revenue Procedure provides a safe harbor method of accounting that taxpayers may use to determine whether costs to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized. The revenue procedure may be adopted in tax years ending after May 1, 2023. We are currently assessing the Revenue Procedure to determine its impact on our tax repairs deduction.

Income Tax Expense (Benefit)

Income tax expense (benefit) from continuing operations for the years ended December 31 was (in millions):

Effective Tax Rates

The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:

(a)

The state effective tax rate contains the tax expense attributable to multiple statutory state rate changes in the Company's state jurisdictions. For the year ended December 31, 2023, we recognized an $8.2 million tax benefit from a Nebraska income tax rate decrease.

(b)

The effective tax rate reflects the income attributable to the non-controlling interest in Black Hills Colorado IPP for which a tax provision was not recorded.

(c)

Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction for repair costs and certain indirect costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method.

(d)

Primarily TCJA - see Note 2 for additional information.

(e)

Primarily related to one-time bill credits of TCJA benefits delivered to Colorado Electric and Nebraska Gas customers in 2021. These bill credits, which resulted in a reduction in revenue, were offset by a reduction in income tax expense and resulted in a minimal impact to Net income for the year ended December 31, 2021.

Deferred Tax Assets and Liabilities

The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in millions):

Net Operating Loss and Tax Credit Carryforwards

At December 31,2023, we have federal NOL and state NOL and tax credit carryforwards that will expire at various dates as follows (in millions):

(a)

The carryforward balance is reflected on the basis of apportioned tax losses to jurisdictions imposing state income taxes.

As of December 31, 2023, we had a $1.0 million valuation allowance against the state NOL carryforwards. Our 2023 analysis of the ability to utilize such NOLs resulted inno increase in the valuation allowance. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the NOLs, the offsetting amount will affect tax expense.

As of December 31, 2023, we had a $14.4 million valuation allowance against the state ITC carryforwards. Our 2023 analysis of the ability to utilize such ITC resulted in a slight decrease in the valuation allowance.

Unrecognized Tax Benefits

The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in millions):

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $6.5 million.

We recognizedno interest expense associated with income taxes for the years ended December 31,2023, 2022 and 2021. We hadno accrued interest (before tax effect) associated with income taxes at December 31,2023 and 2022.

As of December 31, 2023, we do not have any tax positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease on or before December 31, 2024.

We are subject to federal income tax as well as income tax in various state and local jurisdictions. As of December 31, 2023, tax years for 2020, 2021, and 2022 are subject to examination by the tax authorities. With few exceptions, we are no longer subject to U.S. or state exam for years before 2020. Tax years 2017 and 2018 was open as of December 31, 2023.

(16)BUSINESS SEGMENT INFORMATION

Our Chief Executive Officer, who is considered to be our CODM, reviews financial information presented on an operating segment basis for purposes of making decisions, allocating resources and assessing financial performance. Our operating segments are based on our method of internal reporting, which is generally segregated by differences in products and services. All of our operations and assets are located within the United States.

Our Electric Utilities segment includes the operating results of the regulated electric utility operations of Colorado Electric, South Dakota Electric, and Wyoming Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota and Wyoming. We also own and operate non-regulated power generation and mining businesses that are vertically integrated with our Electric Utilities.

Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming.

Corporate and Other represents certain unallocated expenses for administrative activities that support our operating segments. Corporate and Other also includes business development activities that are not part of our operating segments and inter-segment eliminations.

Our CODM assesses the performance of our operating segments based on operating income. Our CODM reviews capital expenditures by operating segment rather than any individual or total asset amount. Our operating segments are equivalent to our reportable segments.

Segment information was as follows (in millions):

(a)

Includes accruals for property, plant and equipment as disclosed in the Supplemental Cash Flow Information to the Consolidated Statement of Cash Flows.

(17)SUBSEQUENT EVENTS

Except as described in Note 2, there have been no events subsequent to December 31, 2023 which would require recognition in the Consolidated Financial Statements or disclosures.