| SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF CONSOLIDATION: Our consolidated financial statements include the accounts of the Association, our wholly owned and majority owned subsidiaries, and certain variable interest entities for which we or our subsidiaries are the primary beneficiaries. See Note 13—Variable Interest Entities. Our consolidated financial statements also include our undivided interests in jointly owned facilities. All significant intercompany balances and transactions have been eliminated in consolidation. The accompanying consolidated statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) as applied to regulated enterprises. JOINTLY OWNED FACILITIES: We own undivided interests in two jointly owned generating facilities that are operated by the operating agent of each facility under joint facility ownership agreements with other utilities as tenants in common. These projects include the Yampa Project (operated by us) and the Missouri Basin Power Project (“MBPP”) (operated by Basin Electric Power Cooperative (“Basin”)). Each participant in these agreements receives a portion of the total output of the generation facilities, which approximates its percentage ownership. Each participant provides its own financing for its share of each facility and accounts for its share of the cost of each facility. The operating agent for each of these projects allocates the fuel and operating expenses to each participant based upon its share of the use of the facility. Therefore, our share of the plant asset cost, interest, depreciation and operating expenses is included in our consolidated financial statements. See Note 3—Property, Plant and Equipment. SEGMENT REPORTING: We were organized for the purpose of supplying wholesale power to our Utility Members and do so through the utilization of a portfolio of resources, including generation and transmission facilities, long‑term purchase contracts and short‑term energy purchases. In support of our coal-fired generating resources, we have direct ownership in coal mines. Our Board serves as our chief operating decision maker who manages and reviews our operating results and allocates resources as one operating segment. Therefore, we have one reportable segment for financial reporting purposes. Our significant segment expenses include purchased power expense and fuel expense, which are regularly provided to our chief operating decision maker. As we have only one operating segment, these values agree to those disclosed in our Consolidated Statement of Operations. USE OF ESTIMATES: The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, 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. Actual results may differ from those estimates. IMPAIRMENT EVALUATION: Long-lived assets (property, plant and equipment, intangible assets, investments and preliminary surveys and investigation costs) that are held and used are evaluated for impairment whenever events or changes in circumstances indicate the carrying value of an asset may not be recoverable. An impairment loss is recognized when estimated undiscounted cash flows expected to result from the use of the asset plus net proceeds expected from disposition of the asset (if any) are less than the carrying value of the asset. When an impairment loss is recognized, the carrying amount of the asset is reduced to its estimated fair value based on quoted market prices or other valuation techniques. In 2023 as part of preparing our financial statements, we recognized an impairment loss of $261.6 million associated with the planned early retirement of Craig Generating Station Units 2 and 3. In 2022, we recognized an impairment loss of $3.7 million associated with the early retirement of the Rifle Generating Station. We also recognized an impairment loss of $25.4 million associated with additional asset retirement obligations at the Nucla and Escalante Generating Stations related to a change in cost estimates. There were no impairments of long-lived assets recognized in 2021. These impairment losses were deferred in accordance with the accounting requirements related to regulated operations at the discretion of our Board and subject to FERC approval, if applicable. See Note 2—Accounting for Rate Regulation. VARIABLE INTEREST ENTITIES: We evaluate our arrangements and relationships with other entities, including our investments in other associations in accordance with the accounting standard related to consolidation of variable interest entities. This guidance requires us to identify variable interests (contractual, ownership or other financial interests) in other entities and whether any of those entities in which we have a variable interest meet the criteria of a variable interest entity. An entity is considered to be a variable interest entity when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. In making this assessment, we consider the potential that our arrangements and relationships with other entities provide subordinated financial support, the potential for us to absorb losses or rights to residual returns of an entity, the ability to directly or indirectly make decisions about the entity’s activities and other factors. If an entity that we have a variable interest in meets the criteria of a variable interest entity, we must determine whether we are the primary beneficiary of that entity. The primary beneficiary is the entity that has the power to direct the activities of the variable interest entity that most significantly impact the variable interest entity’s economic performance, and the obligation to absorb losses or the right to receive benefits from the variable interest entity that could be potentially significant to the variable interest entity. If we are determined to be the primary beneficiary of (has controlling financial interest in) a variable interest entity, then we would be required to consolidate that entity. In certain situations, it may be determined that power is shared among multiple unrelated parties such that no one party has the power to direct the activities of a variable interest entity that most significantly impact the variable interest entity’s economic performance (decisions about those activities require the consent of each of the parties sharing power). In accordance with the accounting guidance prescribed by consolidation of variable interest entities, if the determination is made that power is shared among multiple unrelated parties, then no party is the primary beneficiary. See Note 13—Variable Interest Entities. ACCOUNTING FOR RATE REGULATION: In accordance with the accounting requirements related to regulated operations, some revenues and expenses have been deferred at the discretion of our Board, subject to FERC approval, if based on regulatory orders or other available evidence, it is probable that these amounts will be refunded or recovered through future rates. Regulatory assets are costs we expect to recover from our Utility Members based on rates approved by the applicable authority. Regulatory liabilities represent probable future reductions in rates associated with amounts that are expected to be refunded to our Utility Members based on rates approved by the applicable authority. Expected recovery of deferred costs and returning deferred credits are based on specific ratemaking decisions by FERC or precedent for each item. We recognize regulatory assets as expenses and regulatory liabilities as operating revenue, other income, or a reduction in expense concurrent with their recovery through rates. Regulatory assets and liabilities are as follows (dollars in thousands): December 31, December 31, Regulatory assets Deferred income tax expense (1) $ 15,223 $ 19,279 Deferred prepaid lease expense – Springerville Unit 3 Lease (2) 74,551 76,842 Goodwill – J.M. Shafer (3) 37,749 40,598 Goodwill – Colowyo Coal (4) 33,062 34,095 Deferred debt prepayment transaction costs (5) 106,417 115,045 Deferred Holcomb expansion impairment loss (6) 74,795 79,470 New Horizon Mine environmental obligation (7) 44,869 — Unrecovered plant (8) 532,817 285,092 Total regulatory assets 919,483 650,421 Regulatory liabilities Interest rate swap - realized gain (9) and other 1,854 2,341 Membership withdrawal (10) 463 47,590 Total regulatory liabilities 2,317 49,931 Net regulatory asset $ 917,166 $ 600,490 ___________________________________________ (1) A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues. (2) Represents deferral of the loss on acquisition related to the Springerville Generating Station Unit 3 (“Springerville Unit 3”) prepaid lease expense upon acquiring a controlling interest in the Springerville Unit 3 Partnership LP (“Springerville Partnership”) in 2009. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation, amortization and depletion expense in the amount of $2.3 million annually through the 47-year period ending in 2056 and recovered from our Utility Members in rates. (3) Represents goodwill related to our acquisition of Thermo Cogeneration Partnership, LP (“TCP”) in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $2.8 million annually through the 25-year period ending in 2036 and recovered from our Utility Members in rates. (4) Represents goodwill related to our acquisition of Colowyo Coal Company LP (“Colowyo Coal”) in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $1.0 million annually through the 44-year period ending in 2056 and recovered from our Utility Members in rates. (5) Represents transaction costs that we incurred related to the prepayment of our long-term debt in 2014. These costs are being amortized to depreciation, amortization and depletion expense in the amount of $8.6 million annually over the 21.4-year period ending in 2036 and recovered from our Utility Members in rates. (6) Represents deferral of the impairment loss related to development costs, including costs for the option to purchase development rights for the expansion of the Holcomb Generating Station. The regulatory asset for the deferred impairment loss is being amortized to other operating expenses in the amount of $4.7 million annually over the 20-year period ending in 2039 and recovered from our Utility Members in rates. (7) Represents $44.9 million of New Horizon Mine environmental obligation expense that was recorded in 2022 and reversed as a regulatory item in 2023 as part of our June 2023 Class A rate schedule (A-41) filing with FERC with a planned January 1, 2024 effective date. The regulatory asset for the deferred environmental obligation expense will be amortized to expense in the amount of $1.8 million annually over 25 years beginning in 2024 through 2048 and recovered from our Utility Members in rates. (8) Represents deferral of the impairment losses and other closure costs related to the early retirement of the Escalante, Rifle and Craig Generating Station Units 2 and 3. The deferred impairment loss for Escalante Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $12.2 million annually over the 25-year period ending in 2045, which was the depreciable life of Escalante Generating Station, and recovered from our Utility Members through rates. The annual amortization approximates the former annual Escalante Generating Station depreciation for the remaining life of the asset. The deferred impairment loss for Rifle Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $0.6 million annually through 2028, which was the depreciable life of the Rifle Generating Station, and recovered from our Utility Members in rates. Because of our June 2023 Class A rate schedule (A-41) filing that uses a formula rate and the during evaluation of the probability of such filing as part of preparing these financial statements, we recognized the early retirement of Craig Station Units 2 and 3 that is part of our rate filing with FERC and thus we concluded the impairment of incurred costs is probable of recovery through future rates. We recognized an impairment loss of $261.6 million and deferred the loss in accordance with accounting for rate regulation. The deferred impairment loss will be amortized to depreciation, amortization and depletion expense beginning in October 2028 through 2039 for Craig Generating Station Unit 2 and January 2030 through 2043 for Craig Generating Station Unit 3. These amortization periods are the depreciable lives of Craig Generating Station Unit 2 and 3. The annual amortization is expected to approximate the former annual Craig Generation Station Unit 2 and 3 depreciation for the remaining life of the asset. (9) Represents deferral of a realized gain of $4.6 million related to the October 2017 settlement of a forward starting interest rate swap. This realized gain was deferred as a regulatory liability and is being amortized to interest expense over the 12-year term of the First Mortgage Obligations, Series 2017A and refunded to Utility Members through reduced rates when recognized in future periods. (10) Represents the deferral of the recognition of other operating revenues related to the withdrawal of former Utility Members from membership in us. The deferred membership withdrawal income will be refunded to Utility Members through reduced rates when recognized in operating revenues. During 2023, $47.1 million was recognized in operating revenues as part of our rate stabilization measures. ELECTRIC PLANT AND DEPRECIATION: Electric plant is stated at cost. The cost of internally constructed assets includes payroll, overhead costs and interest charged during construction. Interest rates charged during construction were 5.2 percent for 2023, 2.3 percent for 2022 and 4.4 percent for 2021. During 2022, Tri-State transitioned from using the "Indirect Costs" ("IDC") rate to the FERC prescribed "Allowance For Funds Used During Construction" ("AFUDC") rate. AFUDC is defined as the gross allowance for borrowed funds used during construction. The AFUDC rate is calculated with the assumption that short-term debt is the first source of funds used for construction. Any construction not covered by the short-term debt is then assumed to be covered by long-term debt. The AFUDC rate varies from the IDC rate, which assumes that total debt was used to cover construction costs. The amount of interest capitalized during construction was $4.8, $1.5 and $3.8 million during 2023, 2022 and 2021, respectively. At the time that units of electric plant are retired, original cost and cost of removal, net of the salvage value, are charged to the allowance for depreciation. Replacements of electric plant that involve less than a designated unit value are charged to maintenance expense when incurred. Electric plant is depreciated based upon estimated depreciation rates and useful lives that are periodically re‑evaluated. See Note 3—Property, Plant and Equipment. COAL RESERVES AND DEPLETION: Coal reserves are recorded at cost. Depletion of coal reserves is computed using the units‑of‑production method utilizing only proven and probable reserves. LEASES: We determine if an arrangement is a lease upon commencement of the contract. If an arrangement is determined to be a long-term lease (greater than 12 months), we recognize a right-of-use asset and lease liability based on the present value of the future minimum lease payments over the lease term at the commencement date. As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. Our lease terms may also include options to extend or terminate the lease when it is reasonably certain that we will exercise those options. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term. Right-of-use assets are included in other deferred charges, the current portion of lease liabilities is included in accrued expenses and the long-term portion of lease liabilities is included in other deferred credits and other liabilities on our consolidated statements of financial position. See Note 11—Leases. We have elected to apply the short-term lease exception for contracts that have a lease term of twelve months or less and do not include an option to purchase the underlying asset. Therefore, we do not recognize a right-of-use asset or lease liability for such contracts. We recognize short-term lease payments as expense on a straight-line basis over the lease term. Variable lease payments that do not depend on an index or rate are recognized as incurred. INVESTMENTS IN OTHER ASSOCIATIONS: Investments in other associations include investments in the patronage capital of other cooperatives and other required investments in the organizations. Our investment in a cooperative increases when a cooperative allocates patronage capital credits to us, and it decreases when we receive a cash retirement of the allocated capital credits from the cooperative. A cooperative allocates its patronage capital credits to us based upon our patronage (amount of business done) with the cooperative. Investments in other associations are as follows (dollars in thousands): December 31, December 31, Basin Electric Power Cooperative $ 135,652 $ 127,640 National Rural Utilities Cooperative Finance Corporation - patronage capital 12,451 12,172 National Rural Utilities Cooperative Finance Corporation - capital term certificates 15,054 15,054 CoBank, ACB 18,809 16,727 Other 5,718 5,884 Investments in other associations $ 187,684 $ 177,477 Our investments in other associations are considered equity securities without readily determinable fair values, and as such are measured at cost minus impairment. We have evaluated these investments for indicators of impairment. There were no impairments of these investments recognized during 2023, 2022 or 2021. CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS: We consider highly liquid investments with an original maturity of three months or less to be cash equivalents. The fair value of cash equivalents approximates their carrying values due to their short-term maturity. Restricted cash and investments represent funds designated by our Board for specific uses and funds restricted by contract or other legal reasons. A portion of the funds have been restricted by contract and are expected to be settled within one year. These funds are therefore classified as current on our consolidated statements of financial position. The other funds are restricted by contract or other legal reasons and are expected to be settled beyond one year. These funds are classified as noncurrent and are included in other assets and investments on our consolidated statements of financial position. MARKETABLE SECURITIES: We hold marketable securities in connection with the directors’ and executives’ elective deferred compensation plans which consist of investments in stock funds, bond funds and money market funds. These securities are measured at fair value on a recurring basis with changes in fair value recognized in earnings. The estimated fair value of the investments is based upon their active market value (Level 1 inputs) and is included in other noncurrent assets on our consolidated statements of financial position. The cost and estimated fair value of the investments at December 31, 2023 were $0.6 million and $0.5 million, respectively. The cost and estimated fair value of the investments at December 31, 2022 were $0.6 million and $0.5 million, respectively. INVENTORIES: Coal inventories at our owned generating facilities are stated at LIFO (last‑in, first‑out) cost and were $29.0 million and $3.7 million as of December 31, 2023 and 2022, respectively. The remaining coal inventories, other fuel, and materials and supplies inventories are stated at average cost. In 2023, there was no lower coal fuel expense as a result of a LIFO inventory liquidation at our generating facilities. OTHER DEFERRED CHARGES: We make expenditures for preliminary surveys and investigations for the purpose of determining the feasibility of contemplated generation and transmission projects. If construction results, the preliminary survey and investigation expenditures will be reclassified to electric plant - construction work in progress. If the work is abandoned, the related preliminary survey and investigation expenditures will be charged to the appropriate operating expense account, or the expense could be deferred as a regulatory asset to be recovered from our Utility Members through rates subject to approval by our Board and FERC. We make advance payments to the operating agents of jointly owned facilities to fund our share of costs expected to be incurred under each project, including MBPP – Laramie River Station and Yampa Project – Craig Generating Station Units 1 and 2. We also make advance payments to the operating agent of Springerville Unit 3. A right-of-use asset represents a lessee's right to control the use of the underlying asset for the lease term. Right-of-use assets are included in other deferred charges and presented net of accumulated amortization. See Note 11—Leases. Other deferred charges are as follows (dollars in thousands): December 31, December 31, Preliminary surveys and investigations $ 12,845 $ 13,048 Advances to operating agents of jointly owned facilities 2,750 7,324 Operating lease right-of-use assets 6,477 6,771 Other 14,049 13,302 Total other deferred charges $ 36,121 $ 40,445 DEBT ISSUANCE COSTS: We account for debt issuance costs as a direct deduction of the associated long-term debt carrying amount consistent with the accounting for debt discounts and premiums. Deferred debt issuance costs are amortized to interest expense using an effective interest method over the life of the respective debt. ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS : We account for current obligations associated with the future retirement of tangible long-lived assets and environmental reclamation in accordance with the accounting guidance relating to asset retirement and environmental obligations. This guidance requires that legal obligations associated with the retirement of long-lived assets be recognized at fair value at the time the liability is incurred and capitalized as part of the related long-lived asset. Over time, the liability is adjusted to its present value by recognizing accretion expense, and the capitalized cost of the long-lived asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. In the absence of quoted market prices, we determine fair value by using present value techniques in which estimates of future cash flows associated with retirement activities are discounted using a credit adjusted risk‑free rate and a market risk premium. As changes in estimates occur, such as mine plans, estimated costs, and timing of the performance of reclamation activities, we make revisions to the asset and obligation at the appropriate discount rate. Upon settlement of an asset retirement obligation, we apply payment against the estimated liability and incur a gain or loss if the actual retirement costs differ from the estimated recorded liability. Environmental reclamation costs are accrued based on management’s best estimate at the end of each period of the costs expected to be incurred. Such cost estimates may include ongoing care, maintenance and monitoring costs. Changes in reclamation estimates are reflected in earnings in the period an estimate is revised. Estimates of future expenditures for environmental reclamation obligations are not discounted. See Note 4—Asset Retirement and Environmental Reclamation Obligations. OTHER DEFERRED CREDITS AND OTHER LIABILITIES: In 2015, we renewed transmission right-of-way easements on tribal nation lands where certain of our electric transmission lines are located. We will pay $25.7 million for these easements from 2023 through the individual easement terms ending between 2036 and 2040. The present value of the remaining easement payments was $17.9 million and $18.6 million as of December 31, 2023 and December 31, 2022, respectively, which is recorded as other deferred credits and other liabilities. OATT deposits represent refundable transmission customer deposits related to interconnection and transmission requests from third parties. An OATT deposit is refundable should the interconnection or transmission request not move forward. Financial liabilities-reclamation represent financial obligations that we have for our share of the reclamation costs at jointly owned facilities in which we have undivided interests in. A contract liability represents an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration from the customer. We have received deposits from others and these deposits are reflected in contract liabilities (unearned revenue) until recognized in other operating revenues over the life of the agreement. We have received deposits from various parties and those that may still be required to be returned are a liability and these are reflected in customer deposits. The following other deferred credits and other liabilities are reflected on our consolidated statements of financial position (dollars in thousands): December 31, December 31, Transmission easements $ 17,862 $ 18,636 OATT deposits 27,872 17,476 Financial liabilities - reclamation 16,895 12,429 Customer deposits 12,091 8,616 Contract liabilities (unearned revenue) - noncurrent 3,125 3,765 Operating lease liabilities - noncurrent 1,396 1,251 Other 4,884 6,201 Total other deferred credits and other liabilities $ 84,125 $ 68,374 PATRONAGE CAPITAL: Our net margins are treated as advances of capital from our Members and are allocated to our Utility Members on the basis of their electricity purchases from us and to our Non-Utility Members as provided in their respective membership agreements. Margins not yet distributed to Members constitute patronage capital. Patronage capital is held for the account of our Members and is distributed through patronage capital retirements when our Board deems it appropriate to do so, subject to debt instrument restrictions. ELECTRIC SALES REVENUE: Revenue from electric energy deliveries is recognized when delivered. See Note 10—Revenue. OTHER OPERATING REVENUE: Other operating revenue consists primarily of wheeling, transmission, and coal sales revenue. See Note 10—Revenue. INCOME TAXES: We are a taxable cooperative subject to federal and state taxation. As a taxable electric cooperative, we are allowed a tax exclusion for margins allocated as patronage capital. We utilize the liability method of accounting for income taxes which requires that deferred tax assets and liabilities be determined based on the expected future income tax consequences of events that have been recognized in the consolidated financial statements. We adopted the normalization method effective January 1, 2020 pursuant to FERC regulation. Our subsidiaries not subject to FERC regulation continued to use a flow-through method for recognizing deferred income taxes whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability, as approved by our Board. A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be settled or received through future rate revenues. Under this regulatory accounting approach, any income tax expense or benefit on our consolidated statements of operation includes only the current portion. Pursuant to our new Class A rate that uses a formula rate filed with FERC, we will follow the flow-through method which will not have a material impact on our financial statements. See Note 9—Income Taxes. INTERCHANGE POWER: We occasionally engage in interchanges, or non‑cash swapping, of energy. Based on the assumption that all energy interchanged will eventually be received or delivered in‑kind, interchanged energy is generally valued at the average cost of fuel to generate power. Additionally, portions of the energy interchanged are valued per contract with the utility involved in the interchange. When we are in a net energy advance position, the advanced energy balance is recorded as an asset. If we owe energy, the net energy balance owed to others is recorded as a liability. The net activity for the year is included in purchased power expense. The interchange liability balance of $4.1 million and $4.7 million at December 31, 2023 and 2022, respectively, is included in accounts payable. The net interchange activity recorded in purchased power expense was a credit of $2.1 million in 2023, an expense of $1.5 million in 2022 and an expense of $0.6 million in 2021. ACCOUNTING PRONOUNCEMENTS - NOT YET ADOPTED : In December 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update (“ASU”) 2023-09 – Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The purpose of ASU 2023-09 is to enhance the transparency and decision usefulness of income tax disclosures by providing additional information related to the following: (1) Rate reconciliation: ASU 2023-09 requires a tabular rate reconciliation using both percentages and dollar amounts of the reported income tax expense (or benefit) from continuing operations to the product of income (or loss) from continuing operating before income taxes and the applicable statutory federal income tax rate of the county of domicile using specific categories. The following specific categories are required to be disclosed in the rate reconciliation; state and local income tax (qualitative disclosure required for states that make up over 50% of this category), foreign tax effect, effect of changes in tax laws or rates enacted in the current period, effect of cross-border tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items, changes in unrecognized tax benefits, and any other item that meets the 5 percent threshold. (2) Income taxes paid: ASU 2023-09 requires all reporting entities to disclose the year-to-date amount of income taxes paid (net of refunds received) disaggregated by federal, state, and foreign jurisdictions. It also requires additional disaggregation of income taxes paid to an individual jurisdiction equal to or greater than 5 percent of total income taxes paid (net of refunds). Entities are required to disclose pre-tax income (or loss) from continuing operations disaggregated by domestic and foreign along with income tax expense (or benefit) disaggregated by federal, state, and foreign components. ASU 2023-09 is effective for public business entities for annual periods beginning after December 15, 2024, with early adoption and retrospective or prospective application permitted. We have evaluated the impact of ASU 2023-09 and believe that the adoption of this update will not have a material impact on our consolidated financial statement disclosures. |
