| Summary of significant accounting policies | Summary of significant accounting policies: a. Business description Oglethorpe Power Corporation is an electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta, Georgia that operates on a not-for-profit basis. We are owned by 38 retail electric distribution cooperative members in Georgia. We provide wholesale electric power from a combination of owned and co-owned generating units of which our ownership share totals 7,792 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns 733 megawatts of summer planning reserve capacity. In addition, we supply financial and management services to Green Power EMC, which purchases energy from renewable energy facilities totaling 756 megawatts of capacity, including 724 megawatts sourced by solar energy. Georgia Power Company is a co-owner and the operating agent of our nuclear and coal-fired generating units. b. Basis of accounting Our consolidated financial statements include our accounts and the accounts of our majority-owned and controlled subsidiary. We have determined that there are no accounts of variable interest entities for which we are the primary beneficiary. We have eliminated any intercompany profits and transactions in consolidation. We follow generally accepted accounting principles in the United States. We maintain our accounts in accordance with the Uniform System of Accounts of the Federal Energy Regulatory Commission as modified and adopted by the Rural Utilities Service. We also apply the accounting guidance for regulated operations. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of December 31, 2023 and 2022 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2023. Examples of estimates used include items related to our asset retirement obligations. Accounting for asset retirement and environmental obligations requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value when incurred and capitalized as part of the related long-lived asset. In the absence of quoted market prices, we estimate the fair value of our asset retirement obligations using present value techniques, in which estimates of future cash flows associated with retirement activities are discounted using a credit-adjusted risk-free rate. Estimating the amount and timing of future expenditures includes, among other things, making projections of when assets will be retired and ultimately decommissioned, the amount of decommissioning costs, and how costs will escalate with inflation. Actual results could differ from those estimates. c. Patronage capital and membership fees We are organized and operate as a cooperative. Our members paid a total of $190 in membership fees. Patronage capital includes retained net margin. Any excess of revenues over expenditures from operations is treated as an advance of capital by our members and is allocated to each member on the basis of their fixed percentage capacity cost responsibilities in our generation resources. Any distributions of patronage capital are subject to the discretion of our board of directors, subject to first mortgage indenture requirements. Under our first mortgage indenture, we are prohibited from making any distribution of patronage capital to our members if, at the time of or after giving effect to, (i) an event of default exists under the indenture, (ii) our equity as of the end of the immediately preceding fiscal quarter is less than 20% of our total long-term debt and equities, or (iii) the aggregate amount expended for distributions on or after the date on which our equity first reaches 20% of our total long-term debt and equities exceeds 35% of our aggregate net margins earned after such date. This last restriction, however will not apply if, after giving effect to such distribution, our equity as of the end of the immediately preceding fiscal quarter is not less than 30% of our long-term debt and equities. d. Margin policy We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For the years 2023, 2022 and 2021, we achieved a margins for interest ratio of 1.14. e. Revenue recognition As an electric membership cooperative, our principal business is providing wholesale electric service to our members. Our operating revenues are derived primarily from wholesale power contracts we have with each of our 38 members. On November 15, 2023, we and each of our members amended the wholesale power contracts to extend the term from December 31, 2050 to December 31, 2085. These contracts, are substantially identical and obligate our members jointly and severally to pay all expenses associated with owning and operating our power supply business. As a cooperative, we operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. We also sell energy and capacity to non-members through industry standard contracts and negotiated agreements, respectively. We do not have multiple operating segments. Pursuant to our contracts, we primarily provide two services, capacity and energy. Capacity and energy revenues are recognized by us upon transfer of control of promised services to our members and non-members in an amount that reflects the consideration we expect to receive in exchange for those services. Capacity and energy are distinct and we account for them as separate performance obligations. The obligations to provide capacity and energy are satisfied over time as the customer simultaneously receives and consumes the benefit of these services. Both performance obligations are provided directly by us and not through a third party. Each of our members is obligated to pay us for capacity and energy we furnish under its wholesale power contract in accordance with rates we establish. We review our rates periodically but are required to do so at least once every year. Revenues from our members are derived through a cost-plus rate structure which is set forth as a formula in the rate schedule to the wholesale power contracts. The formulary rate provides for the pass-through of our (i) fixed costs (net of any income from other sources) plus a targeted margin as capacity revenues and (ii) variable costs as energy revenues from our members. Power purchase and sale agreements between us and non-members obligate each non-member to pay us for capacity, if any, and energy furnished in accordance with the prices mutually agreed upon. Margins produced from non-member sales are included in our rate schedule formula and reduce revenue requirements from our members. As of December 31, 2023 and 2022, we did not have any significant long-term contracts with non-members. The consideration we receive for providing capacity services to our members is determined by our formulary rate on an annual basis. The components of the formulary rate associated with capacity costs include the annual budget of fixed costs, a targeted margin and income from other sources. Capacity revenues, therefore, vary to the extent these components vary. Fixed costs include items such as fixed operation and maintenance expenses, administrative and general expenses, depreciation and interest. Year to year, capacity revenue fluctuations are generally due to the recovery of fixed operation and maintenance expenses. Fixed costs also include certain costs, such as major maintenance costs, which will be recognized as expense in future periods. Recognition of revenues associated with these future expenses is deferred pursuant to Accounting Standards Codification (ASC) 980, Regulated Operations. The regulatory liabilities are amortized to revenue in accordance with the associated revenue deferral plan as the expenses are recognized. For information regarding regulatory accounting, see Note 1q. Capacity revenues are recognized by us for standing ready to deliver electricity to our customers. Our member capacity revenues are based on the associated costs we expect to recover in a given year and are recognized and billed to our members in equal monthly installments over the course of the year regardless of whether our generation and purchased power resources are dispatched to produce electricity. Non-member capacity revenues are billed and recognized in accordance with the terms of the associated contract. We have a power bill prepayment program pursuant to which our members may prepay future capacity costs and receive a discount. As this program provides us with financing, we adjust our capacity revenues by the amount of the discount, which is based on our avoided cost of borrowing. For additional information regarding our member prepayment program, see Note 1p. We satisfy our performance obligations to deliver energy as energy is delivered to the applicable meter points. We determine the standard selling price for energy we deliver to our members based upon the variable costs incurred to generate or purchase that energy. Fuel expense is the primary variable cost. Energy revenue recognized equals the actual variable expenses incurred in any given accounting period. Our member energy revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members’ service territories, variable operating costs, the availability of electric generation resources, our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights, and by members’ decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers. The standard selling price for our energy revenues from non-members is the price mutually agreed upon. We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 2023, 2022 and 2021, our board approved, and we achieved, a targeted margins for interest ratio of 1.14. Historically, our board of directors has approved adjustments to revenue requirements by year end such that revenue in excess of that required to meet the targeted margins for interest ratio is refunded to the members. Given that our capacity revenues are based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine whether a refund to our members of excess consideration is likely. If so, we reduce our capacity revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. As of December 31, 2023 and December 31, 2022, we recognized refund liabilities totaling $34,266,000 and $28,471,000, respectively. Based on our current agreements with non-members, we do not refund any consideration received from non-members. Sales to members were as follows: (dollars in thousands) 2023 2022 2021 Capacity revenues $ 1,082,368 $ 984,036 $ 946,662 Energy revenues 599,198 990,647 610,447 Total $ 1,681,566 $ 1,974,683 $ 1,557,109 The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2023, 2022 or 2021: 2023 2022 2021 Jackson EMC 15.1 % 16.0 % 15.2 % Cobb EMC 11.4 % 9.5 % 12.3 % GreyStone Power Corporation, an EMC 8.5 % 10.0 % 8.7 % Receivables from contracts with our members at December 31, 2023 and December 31, 2022 were $170,901,000 and $187,401,000, respectively. Energy revenues from non-members were primarily due from the sale of the BC Smith deferring members' output into the wholesale market. In 2023 and 2022, we recognized capacity revenues from non-members relating to our Washington County acquisition, which we acquired in December 2022. Sales to non-members were as follows: (dollars in thousands) 2023 2022 2021 Energy revenues $ 44,995 $ 155,372 $ 47,754 Capacity revenues 13,624 82 — Total $ 58,619 $ 155,454 $ 47,754 Electric capacity and energy revenues are recognized by us without any obligation for returns, warranties or taxes collected. As our members are jointly and severally obligated to pay all expenses associated with owning and operating our power supply business and we perform an on-going assessment of the credit worthiness of non-members and have not had a history of any write-offs from non-members, we have not recorded an allowance for doubtful accounts associated with our receivables from members or non-members. We have a rate management program that allows us to expense and recover interest costs associated with the construction of Vogtle Units No. 3 and No. 4, on a current basis, that would otherwise be deferred or capitalized. The subscribing members of Vogtle Units No. 3 and No. 4 can elect to participate in this program on an annual basis. Under this program, amounts billed to participating members in 2023, 2022 and 2021 were $9,261,000, $14,796,000 and $15,693,000, respectively. The cumulative amount billed since inception of the program totaled $135,693,000. In 2018, we began an additional rate management program that allowed us to recover future expense on a current basis from our members. In general, the program allowed for additional collections over a five-year period with those amounts then applied to billings over the subsequent five-year period. The program is designed primarily as a mechanism to assist our members in managing the rate impacts associated with the commercial operation of the new Vogtle units. During the first quarter of 2022, we began applying billing credits to some of our participating members within this program. In December 2022, collections from our members ended for this rate management program. Under this program, net billing credits and amounts billed to participating members during 2023, 2022 and 2021 were ($52,378,000), $11,774,000 and $143,000,000 respectively. Funds collected through this program are invested and held until applied to members’ bills. Investments that mature and are expected to be applied to members' bills within the next twelve months are included in the Short-term investments line item within our consolidated balance sheets. In conjunction with this program, we are applying regulated operations accounting to defer these revenues and related investment income on the funds collected. Amounts deferred under the program will be amortized to income when applied to members’ bills. The net cumulative amount billed since inception of the program totaled $369,102,000. As of December 31, 2023, $308,507,000 is our remaining liability to be credited to our members' bills. For additional information regarding our revenue deferral plan, see Note 1q. f. Receivables A substantial portion of our receivables are related to capacity and energy sales to our members. These receivables are recorded at the invoiced amount and do not bear interest. Our members are required through the wholesale power contracts to reimburse us for all costs, plus a margin requirement. Receivables from contracts with our members at December 31, 2023, 2022 and 2021 were $170,901,000, $187,401,000 and $143,715,000, respectively. Payment is typically received the following month in which capacity and energy are billed. Estimated energy charges are billed based on the amount of energy supplied during the month and are adjusted when actual costs are available, generally the following month. The remainder of our receivables is primarily related to transactions with non-members from the sale of the BC Smith deferring members' output, affiliated companies and investment income. Our receivables from non-members at December 31, 2023 and 2022 were $30,883,000 and $32,614,000, respectively. Our receivables from non-members were insignificant at December 31, 2021. As a result of our historical experience, the short duration lifetime of our receivables and the short time horizon over which to consider expectations of future economic conditions, we have assessed that non-collection of the cost basis of our receivables is remote. During 2023, 2022 and 2021, no credit losses were recognized on any receivables that arose from contracts with members or non-members. g. Nuclear fuel cost The cost of nuclear fuel is amortized to fuel expense based on usage. The total nuclear fuel expense for 2023, 2022 and 2021 amounted to $84,192,000, $73,871,000, and $77,366,000, respectively. Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants has pursued and continues to pursue legal remedies against the Department of Energy for breach of contract. Georgia Power filed claims against the U.S. government in 2014 (as amended) seeking damages for spent nuclear fuel storage costs at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 covering the period from January 1, 2011 through December 31, 2014. On June 12, 2019, the U.S. Court of Federal Claims granted Georgia Power’s motion for summary judgement on damages not disputed by the U.S. Government and awarded the undisputed damages to Georgia Power. However, these undisputed damages are not collectable by Georgia Power and no amounts will be recognized in our financial statements until the court enters final judgement on the remaining damages. Georgia Power filed additional claims against the U.S. government in 2017 seeking damages for spent nuclear fuel storage costs at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 covering the period from January 1, 2015 through December 31, 2017. On August 13, 2020, Georgia Power filed amended complaints in each of the lawsuits against the U.S. government in the Court of Federal Claims for damages from January 1, 2018 to December 31, 2019. Our share of the claims outstanding for the period January 1, 2011 through December 31, 2019 are approximately $84,000,000. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the consolidated financial statements as of December 31, 2023 or December 31, 2022 for these claims. The final outcome of these matters cannot be determined at this time. Both Plants Hatch and Vogtle have on-site dry spent storage facilities in operation. We expect that facilities at both plants can be expanded to accommodate spent fuel through the expected life of each plant. h. Asset retirement obligations and other retirement costs Asset retirement obligations are legal obligations associated with the retirement of long-lived assets. These obligations represent the present value of the estimated costs for an asset's future retirement discounted using a credit-adjusted risk-free rate, and are recorded in the period in which the liability is incurred. The liabilities we have recognized primarily relate to the decommissioning of our nuclear facilities and coal ash ponds. In addition, we have retirement obligations related to gypsum cells, powder activated carbon cells, landfill sites and asbestos removal. Under the accounting provision for regulated operations, we record a regulatory asset or liability to reflect the difference in timing of recognition of the costs related to nuclear and coal ash related decommissioning for financial statement purposes and for ratemaking purposes. Periodically, we obtain revised cost studies associated with our nuclear and fossil plants' asset retirement obligations. Actual retirement costs may vary from these estimates. The estimated costs of nuclear and coal ash pond decommissioning are based on the most recent studies performed in 2020, 2021 and 2023, respectively. The following table reflects the details of the asset retirement obligations included in the consolidated balance sheets for the years 2023 and 2022. (dollars in thousands) Nuclear Coal Ash Pond Other Total Balance at December 31, 2022 $ 820,106 $ 461,528 $ 62,109 $ 1,343,743 Liabilities incurred 62,841 — — 62,841 Liabilities settled — (14,445) (76) (14,521) Accretion 46,857 16,558 2,492 65,907 Deferred accretion — 5 — 5 Change in cash flow estimates — 321 641 962 Balance at December 31, 2023 $ 929,804 $ 463,967 $ 65,166 $ 1,458,937 (dollars in thousands) Nuclear Coal Ash Pond Other Total Balance at December 31, 2021 $ 778,214 $ 442,686 $ 66,243 $ 1,287,143 Liabilities incurred — — — — Liabilities settled — (10,134) (184) (10,318) Accretion 41,892 12,196 1,865 55,953 Deferred accretion — 479 — 479 Change in cash flow estimates — 16,301 (5,815) 10,486 Balance at December 31, 2022 $ 820,106 $ 461,528 $ 62,109 $ 1,343,743 Asset Retirement Obligations Nuclear Decommissioning. Nuclear decommissioning cost estimates are based on site studies and assume prompt dismantlement and removal of both the radiated and non-radiated portions of the plant from service, as well as the management of spent fuel. We do not have a legal obligation to decommission non-radiated structures and, therefore, these costs are excluded from the related asset retirement obligation and the amounts in the table above. Actual decommissioning costs may vary from these estimates because of, but not limited to, changes in the assumed date of decommissioning, changes in regulatory requirements, changes in technology, and changes in costs of labor, materials and equipment. Our most recent assessment of the nuclear asset obligation for Plant Hatch and Plant Vogtle Units No. 1 and No. 2, which occurred in 2021 resulted in a slight decrease in the obligation for nuclear decommissioning. On March 6, 2023 and February 14, 2024, Plant Vogtle Units No. 3's and No. 4's nuclear reactors achieved self-sustaining nuclear fission, commonly referred to as initial criticality. As a result, in March 2023, we recognized a new nuclear asset retirement obligation for Plant Vogtle Unit No. 3 totaling $62,841,000. We expect to record an asset retirement obligation of approximately $65,000,000 for Plant Vogtle Unit No. 4 in the first quarter of 2024. Our portion of the estimated costs of decommissioning co-owned nuclear facilities for which we have recorded asset retirement obligations as of December 31, 2023 are as follows: (dollars in thousands) 2021 site study Hatch Hatch Vogtle Vogtle Expected start date of decommissioning 2034 2038 2047 2049 Estimated costs based on site study in 2021 dollars: Radiated structures $ 227,000 $ 236,000 $ 200,000 $ 213,000 Spent fuel management 60,000 51,000 58,000 53,000 Non-radiated structures 15,000 21,000 24,000 31,000 Total estimated site study costs $ 302,000 $ 308,000 $ 282,000 $ 297,000 (dollars in thousands) 2020 site study Vogtle Expected start date of decommissioning 2061 Estimated costs based on site study in 2020 dollars: Radiated structures $ 187,000 Spent fuel management 19,000 Non-radiated structures 22,000 Total estimated site study costs $ 228,000 We have established funds to comply with the Nuclear Regulatory Commission regulations regarding the decommissioning of our nuclear plants. See Note 1i for information regarding the nuclear decommissioning funds. We apply the provision of regulated operations to nuclear decommissioning transactions such that collections and investment income (interest, dividends and realized gains and losses) of our nuclear decommissioning funds are compared to the associated decommissioning expenses with the difference deferred as regulatory asset or liability. As this difference is largely attributable to the timing of decommissioning fund earnings, the difference is recorded as an adjustment to investment income in our consolidated statements of revenues and expenses. Unrealized gains and losses of the decommissioning funds are recorded directly to the regulatory asset or liability for asset retirement obligations in accordance with our ratemaking treatment. Coal Combustion Residuals. Coal combustion residuals (CCR) are subject to Federal and State regulations. Our obligations associated with CCR are primarily for the closure of coal ash ponds. During 2023 and 2022, assessments of the coal ash pond asset retirement obligation resulted in a $321,000 increase and a $16,301,000 increase in cash flow estimates for coal ash decommissioning, respectively. Estimates are based on various assumptions including, but not limited to, closure and post-closure cost estimates, timing of expenditures, escalation factors, discount rates and methods for complying with the CCR regulations. The 2022 increase in cash flow estimates was primarily due to the Georgia Public Service Commission's approval of Georgia Power's request to revise the closure of the Plant Wansley coal ash pond from in-place to removal. Additional adjustments to the asset retirement obligations are expected periodically due to potential changes in estimates and assumptions. We have internally segregated the funds collected for coal ash pond and other CCR decommissioning costs, including earnings thereon. As of December 31, 2023 and December 31, 2022, the fund balances were $176,630,000 and $153,208,000, respectively. We apply the provision of regulated operations to coal ash pond and other CCR decommissioning transactions such that collections and investment income (interest, dividends and realized gains and losses) are compared to the associated decommissioning expenses with the difference deferred to or amortized from the regulatory asset. This difference is recorded to the associated expenses in our consolidated statements of revenues and expenses. Unrealized gains and losses of the associated decommissioning fund are recorded directly to the regulatory asset in accordance with our ratemaking treatment. Other Retirement Costs Accounting standards for asset retirement and environmental obligations do not apply to a retirement cost for which there is no legal obligation to retire the asset, and non-regulated entities are not allowed to accrue for such future retirement costs. We continue to recognize retirement costs for these other obligations in our depreciation rates under the accounting provisions for regulated operations. Accordingly, the accumulated retirement costs for other obligations are reflected as a regulatory liability in our balance sheets. For information regarding accumulated retirement costs for other obligations, see Note 1q. i. Nuclear decommissioning funds The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. The NRC definition of decommissioning does not include all costs that may be associated with decommissioning, such as spent fuel management and non-radiated structures. We have established external trust funds to comply with the NRC's regulations. Upon approval by the NRC, any funding in the external trust in excess of their requirements may be used for other decommissioning costs. As a result of nuclear fuel load for Plant Vogtle Units No. 3 and No. 4, in 2023 and 2022, we contributed $4,619,000 and $2,643,000, respectively, to the external trust funds. These funds are managed by unrelated third party investment managers with the discretion to buy, sell and invest pursuant to investment objectives and restrictions set forth in agreements entered into between us and the investment managers. We record the investment securities held in the nuclear decommissioning trust fund at fair value, as disclosed in Note 2. Because day-to-day investment decisions are made by third party investment managers, the ability to hold investments in unrealized loss positions is outside our control. In addition to the external trust funds, we maintain unrestricted investments internally designated for nuclear decommissioning. These internal funds are available to be utilized to fund the external trust funds, should additional funding be required, as well as other decommissioning costs outside the scope of the NRC funding regulations. The funds are included in long-term investments on our consolidated balance sheets. We contributed $10,000,000 and $8,350,000 into the internal funds in 2023 and 2022, respectively. The following table outlines the fair value of our nuclear decommissioning funds as of December 31, 2023 and December 31, 2022. The funds were invested in a diversified mix of approximately 71% equity and 29% fixed income securities in 2023 and 69% equity and 31% fixed income securities in 2022. 2023 External Trust Funds: (dollars in thousands) Cost Purchases Net Proceeds (1) Unrealized Gain(Loss) Fair Value 12/31/2023 Equity $ 228,936 $ 29,307 $ (9,180) $ 201,900 $ 450,963 Debt 192,986 485,705 (482,935) (4,751) 191,005 Other 91 20,015 (20,835) — (729) $ 422,013 $ 535,027 $ (512,950) $ 197,149 $ 641,239 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $22,078,000. 2023 Internal Funds: (dollars in thousands) Cost Purchases Net Proceeds (1) Unrealized Fair Value Equity $ 79,122 $ — $ 7,256 $ 39,134 $ 125,512 Debt 43,032 59,630 (53,342) (942) 48,378 $ 122,154 $ 59,630 $ (46,086) $ 38,192 $ 173,890 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $13,542,000. 2022 External Trust Funds: (dollars in thousands) Cost Purchases Net Proceeds (1) Unrealized Fair Value Equity $ 223,336 $ 9,255 $ (3,655) $ 131,572 $ 360,508 Debt 204,935 191,958 (203,907) (12,869) 180,117 Other (795) 3,287 (2,401) — 91 $ 427,476 $ 204,500 $ (209,963) $ 118,703 $ 540,716 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends and fees of $5,463,000. 2022 Internal Funds: (dollars in thousands) Cost Purchases Net Proceeds (1) Unrealized Fair Value Equity $ 68,914 $ — $ 10,005 $ 18,995 $ 97,914 Debt 46,856 76,207 (79,828) (2,741) 40,494 $ 115,770 $ 76,207 $ (69,823) $ 16,254 $ 138,408 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $6,384,000. Realized and unrealized gains and losses of the nuclear decommissioning funds that would be recorded in earnings by a non-regulated entity are directly deducted from or added to the regulatory asset or liability for asset retirement obligations in accordance with our rate-making treatment. The nuclear decommissioning trust fund has produced an average annualized return of approximately 6.2% in the last ten years and 6.0% since inception in 1990. j. Depreciation Depreciation is computed on additions when they are placed in service using the composite straight-line method. We use prescribed depreciation rates as well as site specific rates determined through depreciation studies as approved by the Rural Utilities Service. The depreciation rates for steam, nuclear and other production in the table below reflect revised rates from depreciation rate studies completed in 2020 or 2021. Site specific depreciation studies are performed every five years. Annual weighted average depreciation rates in effect in 2023, 2022, and 2021 were as follows: Remaining Useful Life Range in 2023 2022 2021 Steam production 19-21 3.05 % 13.77 % 14.47 % Nuclear production 11-59 1.87 % 2.17 % 2.18 % Hydro production 43 2.00 % 2.00 % 2.00 % Other production 16-30 2.73 % 2.68 % 2.60 % Transmission 11-59 2.75 % 2.75 % 2.75 % General 1-42 2.00-33.33% 2.00-33.33% 2.00-33.33% * Based on estimated retirement dates as of 2023. Actual retirement dates may be different. Remaining useful lives for nuclear production are based on the expiration date of the applicable operating license approved by the NRC. Depreciation expense for the years 2023, 2022 and 2021 was $321,047,000, $278,452,000, and $269,280,000, respectively. In 2023, depreciation expense increased by $42,595,000 compared to 2022 primarily due t |
