Our current budget for our 30% ownership interest in Vogtle Units No. 3 and No. 4, is $7.5 billion, which includes capital costs and allowance for funds used during construction, our allocationis a range of the project-level contingency$8.3-8.35 billion and is based on a separate Oglethorpe-level contingency. As of December 31, 2020, our total investmentcommercial operation date in the additional Vogtle units was approximately $6.0 billion. The regulatory-approved in-service datessecond quarter of 2024 for Vogtle Unit No. 3 and4. Any schedule extension beyond June 2024 for Unit No. 4 are November 2021 and November 2022, respectively.

As part of its ongoing process, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnoversstart-up testing and related test results and workforce statistics. The project continuesengineering support.

On May 1, 2023, hot functional testing was completed at Unit No. 4. On July 20, 2023, Southern Nuclear announced that all Unit No. 4 inspections, tests, analyses, and acceptance criteria documentation had been submitted to face challenges including, but not limitedthe Nuclear Regulatory Commission, and, on July 28, 2023, the Nuclear Regulatory Commission published its 103(g) finding that the accepted criteria in the combined license for Unit No. 4 had been met, which allowed nuclear fuel to higher than expected absenteeism; overall constructionbe loaded and subcontractor labor productivity; system turnover andstart-up testing activities; and electrical equipment and commodity installation.

From November 2020 through January 2021, the number of active COVID-19 cases at the site increased significantly, consistent with a national rise in cases, which further impacted productivity and the pace of activity completion. Although still present, this spike in cases has since abated intoOn February and early March. The incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated by1, 2024, Georgia Power to be between $325announced that during start-up and $415 million (of which our 30% interest is $98 to $125 million) and is included in the project budget. As described previously, Georgia Power included estimated costs associated with near-term COVID-19 mitigation actions and related impacts on construction productivity in the additional project-level contingency established as of December 31, 2020. The continuing effects of the COVID-19 pandemic could further disrupt or delay construction,pre-operational testing supervisory, and support activities at Vogtle Units No. 3 and No. 4.

Meeting the projected in-service date for Unit No. 4 only, including financing costs.significantly depends on the progression of start-up and pre-operational testing, which may be impacted by equipment or other operational failures. As Unit No. 4 progresses

New challenges also may continue to arise as Unit No. 4 moves further into testing and start-up, including anywhich may result in required engineering changes or any remediation related thereto, ofto plant systems, structures or components (some of which are based on new technology that has only within the last fewseveral years began initial operation in the global nuclear industry at this scale), any of which may require additional labor and/or materials; or other issues could arise and further impact the projected schedule and estimated cost.

The ultimate outcome of these matters cannot be determined at this time; however, these risks could continue to impact the in-service dates and our cost of the additional units at Plantfor Vogtle Unit No. 4 which would increase the cost of electric service we provide to our members and, as a result, could affect their ability to perform their contractual obligations to us.

We own a 30% undivided interest in each of the Plant Hatch and Plant Vogtle each of which is a two-unit nuclear generating facility, and which collectivelyfacilities. Collectively, our interests in the five operating nuclear units at these facilities account for approximately 17%20% of our total gross generating capacity and 43%produced 35% of our energy generated during 2020. 2023. We also own a 30% interest in a sixth nuclear unit, Vogtle No. 4, which is expected to reach commercial operation in the second quarter of 2024.

Our ownership interests in these facilities expose us to various risks, including:

The Nuclear Regulatory Commission has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. If our nuclear facilities were found to be out of compliance with applicable requirements, the Nuclear Regulatory Commission may impose fines or shut down one or more units of these facilities until compliance is achieved. Revised safety requirements issued by the Nuclear Regulatory Commission have, in the past, necessitated substantial capital expenditures at other nuclear generating facilities.

Further, a major incident at a nuclear facility anywhere in the world could cause the Nuclear Regulatory Commission to limit or prohibit the operation or licensing of any domestic nuclear unit. While we have no reason to expect a serious incident at either of our nuclear plants, if an incident did occur, it could result in substantial cost to us.

We maintain an internal fund and an external trust fund to pay for the estimated cost of decommissioning our existing nuclear facilities. We continue to collect and deposit additional funds into these funds. The internal and external funds are invested in a diversified mix of equity and debt securities, the internal fund.performance of which is subject to market performance risks. If the values of the investments in the funds significantly decrease or the anticipated decommissioning costs significantly increase, it is possible that the decommissioning costs could exceed the funds available and we would have to collect additional revenue from our members to pay the unfunded costs.

We rely on the successful operation of our generation facilities to provide our members’ energy needs. The operation of our generating facilities may be adversely impacted by various factors, including:

We obtain our fuel supplies, including natural gas, coal and uranium, from a number of different suppliers. Any disruptions in our fuel supplies, including disruptions due to weather, environmental regulations, inadequate infrastructure, labor relations, workforce shortages, cyber security incident or other factors affecting our fuel suppliers, could result in us having insufficient levels of fuel supplies. For example,A number of commodities, including natural gas and coal, have recently been affected by broader supply chain challenges and commodity availability constraints. Natural gas supplies may be unavailable due to increased demand during periods of exceptionally cold weather and are also subject to disruption due to natural disasters and similar events or infrastructure failure. Further, a significant increase in liquefied natural gas (LNG) demand may constrain the supply of natural gas available to us. Over the past few years, we have also managed rail-related delays in connection with our coal supply. Additionally, there are only a few facilities that fabricate fuel for our nuclear units and if there was an interruption in production at one of those facilities, it could impact our ability to obtain fuel for our nuclear generating facilities on a timely basis. Natural gas supplies are also subject to disruption due to natural disasters and similar events, infrastructure failure or may be unavailable due to significantly increased demand caused by exceptionally cold weather. Any failure to maintain access to or an adequate inventory of fuel supplies could require us to operate other generating plants at a higher cost or require our members to purchase higher-cost energy from other sources and, as a result, affect our members’ ability to perform their contractual obligations to us.

Many of our generating facilities were constructed more than 3035 years ago and, even if maintained in accordance with good engineering practices, will require significant capital expenditures in order to maintain

We rely on access to external funding sources as a significant source of liquidity for capital expenditures and acquisitions not satisfied by cash flow generated from operations. Unlike most investor-owned utilities, electric cooperatives cannot issue equity securities and therefore rely almost entirely on debt financing.

Historically, we relied on federal loan programs guaranteed by the Rural Utilities Service, a branch of the U.S. Department of Agriculture, in order to meet a significant portion of our long-term financing needs, typically at a cost that was lower than traditional capital markets financing. However, the availability and magnitude of Rural Utilities Service funding levels are subject to the annual federal budget appropriations process, and therefore are subject to uncertainty because of budgetary and political pressures faced by Congress. If the amount of this funding available to us in the future is decreased or eliminated, we would seek alternative sources of debt financing in the traditional capital markets which would likely be at a higher cost.

Our access to both short-term and long-term capital market funding remains an important factor in our existing financing plans particularlyand will be an important factor in light of the significant amount of projectedconnection with any new capital investment.investments. We have entered into multiple credit agreements that provide significant short-term and medium-term liquidity and have successfully accessed the capital markets in the past to satisfy our long-term borrowing needs. We believe that we will be able to maintain sufficient access to the short-term and long-term capital markets based on our current credit ratings. However, our credit ratings reflect the views of the rating agencies, which could change at any point in the future. If one or more rating agencies downgrade us and potential investors take a similar view, our borrowing costs would likely increase and our potential pool of investors, funding sources and liquidity could decrease. In addition, if our credit ratings are lowered below investment grade, collateral calls may be triggered under certain agreements and contracts which would decrease our available liquidity.

Our borrowing costs are also affected by prevailing interest rates. If interest rates have increased at the time we issue fixed rate debt or reset the interest rates on our variable rate debt, our interest costs will increase and our financial condition and future results of operations could be adversely affected.

In addition, market disruptions could constrain, at least temporarily, lenders’ willingness or ability to perform their obligations under existing credit agreements and our ability to access additional sources of capital on favorable terms or at all. These disruptions include:

Further, an increasing number of lenders and investors are taking into account environmental, social and corporate governance criteria when making lending and investment decisions. Although we are not aware of any instances where our access to capital was limited due to these criteria, such considerations could potentially limit the number of lenders or investors who are willing to lend capital to us or other utility companies in the future.

If our ability to access capital becomes significantly constrained or more expensive for any of the reasons stated above or for any other reason, our ability to finance ongoing capital expenditures or future acquisitions could be limited and our financial condition and future results of operations could be adversely affected.

We are innearing the midstcompletion of a multi-year capital spending plan to fund our participation in the construction of Vogtle Units No. 3 and No. 4. Our current project budget for the additional Vogtle units is $7.5 billion,4 and our investment as of December 31, 20202023 was $6.0$8.2 billion. Since 2021, we have also acquired three natural gas resources and expect to acquire a fourth in the second quarter of 2024. We are also evaluating constructing additional generation assets to meet projected load growth in Georgia that would require significant additional capital expenditures. As we have financed generation assets in the past, we are relyingrely on external funding to finance this project.additional generation resources. As of December 31, 2020,2023, we had $10.6$12.1 billion of long-term debt outstanding, an increase of $6.4$7.9 billion since 2009, when construction of the new Vogtle units commenced. At the completion of the Vogtle expansion, we expect that the amount of our outstanding debt will be approximately $12.0$12.6 billion. In addition to the increase in absolute dollars, our debt has been increasing as a percentage of our total capitalization, which has constrained our equity ratio. Furthermore, our debt service payment obligations have increased, which has affected certain other financial metrics. Increased debt and the related impacts on our financial metrics could negatively impact our credit ratings. Any downgrade in our credit ratings would likely increase our borrowing costs and could decrease our access to the credit and capital markets.

In order to increase financial coverage during this period of generation expansion, our board of directors has approved budgets to achieve margins for interest ratios greater than the minimum 1.10 margins for interest ratio required under our first mortgage indenture. We have achieved the board-approved margins for interest ratio each year, and for 20212024 our board of directors again approved a margins for interest ratio of 1.14.

We are exposed to the risk of changing prices for fuels, including natural gas, coal and uranium. For 2020, ourOur primary fuel price exposure wasis to natural gas asand, for 2023, natural gas expenses constituted 68%64% of our total fuel costs for the year.costs. We have taken steps to manage this exposure by entering into natural gas swap arrangements designed to manage potential fluctuations in our power rates due to changes in the price of natural gas. We have also entered into fixed or capped price contracts for some of our coal requirements. The operator of our nuclear plants manages price and supply risk through use of long-term fixed or capped price contracts with multiple vendors of uranium ore mining, conversion and enrichment services. However, these arrangements do not cover all of our and our members’ risk exposure to increases in the prices of fuels. Further, changes in the utilization of different generation resources may subject us to greater fuel price volatility. Despite the continued low prices for domesticHistorically, natural gas prices natural gas prices have historically been more volatile than other fuel sources and stable pricing cannot be assured. Further,sources. Geopolitical events or conflicts, the availability of shale gas and potential regulations affecting its accessibility and transport, and increasing natural gas demand from LNG terminals along the Gulf Coast may have a materialsignificant impact on the cost and supply of natural gas. Increases in fuel prices could significantly increase the cost of electric service we provide to our members and affect their ability to perform their contractual obligations to us.

We depend primarily on revenue from our members under the wholesale power contracts to meet our financial obligations. Our members are our owners, and we do not control their operations or financial performance.

Under current Georgia law, our members generally have the exclusive right to provide retail electric service in their respective territories, subject to limited exceptions. Parties have unsuccessfully sought and will likely continue to seek to advance legislative proposals that will directly or indirectly affect the Georgia Territorial Act in order to allow increased retail competition in our members’ service territories which could affect our members’ financial performance. Further, our members must forecast their load growth and power supply needs.needs, including how to respond to the expected load growth in Georgia. If our members acquire more power supply resources than needed, whether from us or other suppliers, or fail to acquire sufficient resources, our members’ rates could increase excessively and affect their financial performance. Also, in times of weak economic conditions, sales by our members may not be sufficient to cover costs without rate increases, and our members may not collect all amounts billed to their consumers. Although each member has financial covenants to set rates to maintain certain margin levels and our members’ rates are not regulated by the Georgia Public Service Commission, pressure from their consumer members not to raise rates excessively could affect financial performance. Thus, we are exposed to the risk that one or more members could default in the performance of their obligations to us under the wholesale power contracts. Our ability to satisfy our financial obligations could be adversely affected if one or more of our members, particularly one of the larger members, defaulted on their payment obligations to us. Although the wholesale power contracts obligate non-defaulting members to pay the amount of

As with most electric utilities, we are subject to extensive federal, state and local environmental requirements which regulate, among other things, air pollutant emissions, wastewater discharges and the management of hazardous and solid wastes. Compliance with these requirements requires significant expenditures for the installation, maintenance and operation of pollution control equipment, monitoring systems and other equipment or facilities. Through 2020, we have spent approximately $1.1 billion on capital expenditures at our facilities or operating restrictions.

The EPA is expected to achieve and maintain compliance with Georgia’s “multi-pollutant rule” and Environmental Protection Agency's (EPA) Mercury and Air Toxics Standards (MATS), two air quality control regulations that have had a significant impact on our business to date. In addition, asfinalize several proposed rules over the course of December 31, 2020, we have spent approximately $242 million on capital expenditures related to coal ash handling, and expect to spend approximately $47 million more in the near future.

In April 2015, the EPA publishedissued a final rule to regulate coal combustion residuals from electric utilities as solid wastes. To comply with this rule, the ash ponds at Plants Wansley and Scherer ceased receiving new coal ash in early 2019We and Georgia Power has estimated closure activities for the ash ponds to be completed in 2026 and 2031, respectively. Currently, we and Georgia Power anticipate utilizing advanced engineering methods to close the existing ash ponds in place and have proposed such a planclosure plans for our co-owned coal ash ponds to the Georgia Environmental Protection Division. TheDivision (EPD). Georgia Power’s proposed closure plans are currently awaiting review. Ifhave been approved by the proposed plans are notGeorgia Public Service Commission but remain subject to EPD approval, and we cannot predict when they will be approved or statewhether either closure plan will require modifications. Costs associated with the closure of the ash ponds are reflected in the asset retirement obligations discussed below. If Georgia's requirements for coal ash disposal are subsequently revised and we andor the other co-owners of Plants Scherer and Wansleyproposed closure plans are instead required to construct lined coal ash disposal facilities,not approved, our estimated compliance costs wouldcould increase materially. In September 2015, the EPA also finalized a rule to revise the effluent limitations guidelines (ELG) that apply to certain wastewater discharges from nuclear and fossil fuel-fired steam electric power plants. ThisThe 2015 ELG rule was later revised in October 2020 for scrubber wastewater and bottom ash transport.2020. Then, in March 2023, EPA proposed a supplemental ELG rule that would increase the stringency of the current standards. We have already begun

Litigation relating to environmental issues, including claims of property damage, personal injury or common law nuisance caused by plant emissions, including greenhouse gases, wastewater discharges or solid waste disposal, including coal combustion residuals, is generally increasing throughout the U.S. Likewise, actions by private citizen groups to enforce environmental laws and regulations are also becoming increasingly prevalent.

We operate in a highly regulated industry that requires the continued operation of advanced information technology systems and network infrastructure, which are part of broader interconnected systems. Because our generation facilities,resources are part of the nation’s energy infrastructure, we are at an increased risk of cyberattack.

Cyber actors, including those associated with foreign governments, have attacked and threatened to perform necessary corporateattack energy infrastructure. Various regulators have increasingly stressed that these attacks, including ransomware attacks, and attacks targeting utility systems and other critical infrastructure, are increasing in sophistication, magnitude, and frequency. In particular, certain actors, such as nation-state and state-sponsored actors, can deploy significant resources and employ sophisticated methods to plan and carry out attacks. Risk of these attacks may escalate during periods of heightened geopolitical tensions, such as those caused by the war in Ukraine and conflicts in the Middle East.

Our generation assets and information technology systems, and those of our co-owned plants, could be directly or indirectly affected by deliberate or unintentional cyber incidents. If our technology systems were to be breached or otherwise fail, we may be unable to fulfill critical business functions, including the operation of our generation assets and to access funds from financial institutions and capital markets.These economic disruptions could also adversely affect our members’ customers’ ability to pay for electric service.effectively maintain certain internal controls over financial reporting. We and our third party vendors have been subject to attempts to gain unauthorized access to our respective technology systems and confidential data and attempts to disrupt our operations. To date, none of the attempts on our systems have been successful; however, we cannot guarantee that our security efforts will prevent, detect or limit future attempts to breach or compromise our technology and information systems.

Further, as discussed above, COVID-19 may continueour generation assets rely on an integrated transmission system to deliver power to our members, and a disruption of this transmission system could negatively impact our ability to do so. In order to reduce the construction schedulelikelihood and project costs for Vogtle Units No. 3severity of any cyber incident, we have comprehensive cyber security programs designed to protect and No. 4.preserve the confidentiality, integrity and availability of data and systems. Despite these protections, a major cyber incident could result in significant business disruption and expenses to repair security breaches or system damage and could lead to litigation, regulatory action, including fines, and an adverse effect on our reputation.

Our business model is to provide our members with wholesale electric power at the lowest possible cost. A key element of this model is that generating power at central station power plants achieves economies of scale and produces power at a competitive cost. Renewable energy, distributed generation or energy storage technologies currently exist or are in development, such as large-scale batteries, fuel cells, micro turbines, windmills and solar cells, some of which are capable of

We routinely execute transactions with counterparties in the energy and financial services industries. These transactions include credit facilities, facility construction, co-owner agreements, natural gas pipelines, contracts related to the market price and supply of natural gas and coal, and power sales and purchases. Many of these

In the context of facility construction, a counterparty’s failure to perform its contractual obligations under the applicable agreement could impact the project cost and schedule and potentially project completion.

Original bonds that you do not tender or we do not accept will, following the exchange offer, continue to be subject to the restrictions on transfer applicable to the original bonds. The restrictions on transfer of your original bonds arise because we issued the original bonds under exemptions from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws. In general, you may only offer or sell the original bonds if they are registered under the Securities Act and applicable state securities laws, or offered and sold under an exemption from these requirements. We do not plan to register the original bonds under the Securities Act. For further information regarding the consequences of tendering your original bonds in the exchange offer, see the discussion below under the caption "THE“THE EXCHANGE OFFER—Consequences of Failure to Exchange."”

Because we anticipate that most holders of original bonds will elect to exchange their original bonds, we expect that the liquidity of the market for any original bonds remaining after the completion of the exchange offer will be substantially limited. Any original bonds tendered and exchanged in the exchange offer will reduce the aggregate principal amount of the original bonds outstanding. Following the exchange offer, if you do not tender your original bonds, you generally will not have any further registration rights, and your original bonds will continue to be subject to certain transfer restrictions. Accordingly, the liquidity of the market for the original bonds could be adversely affected by the exchange offer.

The exchange bonds will be new securities for which there is no established trading market. We do not intend to apply for listing of the exchange bonds on any national securities exchange or to arrange for the exchange bonds to be quoted on any automated quotation system. As a result, we cannot provide any assurance as to:

Even if a trading market develops, the exchange bonds may trade at higher or lower prices than their principal amount or purchase price, depending on many factors, including:

If a market for the exchange bonds does not develop, purchasers may be unable to resell the exchange bonds for an extended period of time. Consequently, a holder of exchange bonds may not be able to liquidate its investment readily, and the exchange bonds may not be readily accepted as collateral for loans. In addition, market-making activities will be subject to restrictions of the Securities Act and the Securities Exchange Act of 1934.

In addition, if a large number of the holders of original bonds do not tender original bonds or tender original bonds improperly, the limited amount of exchange bonds that would be issued or outstanding after we complete this exchange offer would adversely affect the development of a market for the exchange bonds.

Delivery of the exchange bonds in exchange for the original bonds tendered and accepted for exchange pursuant to the exchange offer will be made only after timely receipt by the exchange agent of the following:

Therefore, holders of original bonds who would like to tender original bonds in exchange for exchange bonds should allow enough time for the original bonds to be delivered on time. We are not required to notify you of defects or irregularities in tenders of the original bonds for exchange. The original bonds that are not tendered or that are tendered but we do not accept for exchange will, following consummation of the exchange Offer, continue to be subject to the existing transfer restrictions under the Securities Act and, upon consummation of the exchange Offer, certain registration and other rights under the registration rights agreement will terminate. See "THE“THE EXCHANGE OFFER—Procedures for Tendering Original Bonds"Bonds” and "THE“THE EXCHANGE OFFER—Consequences of Failure to Exchange."”

Based on interpretations of the staff of the SEC contained in no-action letters to third parties, we believe that you may offer for resale, resell or otherwise transfer the exchange bonds without compliance with the registration and prospectus delivery requirements of the Securities Act. However, in some instances described in this prospectus under "PLAN“PLAN OF DISTRIBUTION,"” certain holders of exchange bonds will remain obligated to comply with the registration and prospectus delivery requirements of the Securities Act to transfer the exchange bonds. If a holder subject to the registration and prospectus delivery requirements of the Securities Act transfers any exchange bonds without delivering a prospectus meeting the requirements of the Securities Act or without an applicable exemption from registration under the Securities Act, that holder may incur liability under the Securities Act. We do not and will not assume or indemnify such a holder against this liability.

Any material differences between our actual results and the historical results contained in our annual, quarterly and current reports filed with the SEC could have a significant adverse impact on the market price of the exchange bonds, assuming a market for the exchange bonds develops. In the event that a market develops, prevailing interest rates may cause the exchange bonds to trade at higher or lower prices than their principal amount or purchase price. In addition, any downgrade of our credit ratings could have a significant adverse impact on the market price of the exchange bonds, assuming a market develops.

We will not receive any cash proceeds from the issuance of the exchange bonds pursuant to the exchange offer. In consideration for issuing the exchange bonds as contemplated in this prospectus, we will receive in exchange a like principal amount of original bonds. The original bonds surrendered in exchange for the exchange bonds will be retired and cancelled and cannot be reissued. Accordingly, the issuance of the exchange bonds will not result in any change in our capitalization.

The summary financial data below present selected historical information relating to our financial condition and resultsstatistical data. The financial data presented as of operations asthe end of and for each ofyear in the yearsthree-year period ended December 31, 2020, 2019 and 2018. Summary financial data for the years ended December 31, 2020, 2019 and 2018 that are presented below were2023, has been derived from our audited consolidated financial statements. You should read the information contained in this table together with our financial statements, the related notes to the financial statements and the discussion of this information in this prospectus.

We are a Georgia electric membership corporation (an EMC) incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 38 retail electric distribution cooperative members. Our principal business is providing wholesale electric power to our members. As with cooperatives generally, we operate on a not-for-profit basis. We are one of the largest electric cooperatives in the United States in terms of revenues, assets, kilowatt-hour sales to members and, through our members, consumers served. We are also the second largest power supplier in the state of Georgia. We have 299337 employees.

Our members are local consumer-owned distribution cooperatives that provide retail electric service on a not-for-profit basis. In general, our members' customer base consists of residential, commercial and industrial consumers within specific geographic areas. Our members serve approximately 2.02.1 million electric consumers (meters) representing approximately 4.34.5 million people. See "—"OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES."

Cooperatives like Oglethorpe are business organizations owned by their members, which are also either their wholesale or retail customers. As not-for-profit organizations, cooperatives are intended to provide services to their members at the lowest possible cost, in part by eliminating the need to produce profits or a return on equity. Cooperatives may make sales to non-members, the effect of which is generally to reduce costs to members. Today, cooperatives operate throughout the United States in such diverse areas as utilities, agriculture, irrigation, insurance and banking.

All cooperatives are based on similar business principles and legal foundations. Generally, an electric cooperative designs its rates to recover its cost-of-service and to collect a reasonable amount of revenues in excess of expenses, which constitutes margins. The margins increase patronage capital, which is the equity component of a cooperative's capitalization. These margins are considered capital contributions (that is, equity) from the members and are held for the accounts of the members and returned to them when the board of directors of the cooperative deems it prudent to do so. The timing and amount of any actual return of capital to the members depends on the financial goals of the cooperative and the cooperative's loan and security agreements. See "—First Mortgage Indenture."

We provide wholesale electric service to our members for more than halfa significant portion of their aggregate power requirements primarily from our fleet of generation assets but also with power purchased from other power suppliers.suppliers from time to time. In 2023, we supplied energy that accounted for approximately 68% of the retail energy requirements of our members. We provide this service pursuant to long-term, take-or-pay wholesale power contracts. The wholesale power contracts obligate our members jointly and severally to pay rates sufficient for us to recover all the costs of owning and operating our power supply business, including the payment of principal and interest on our indebtedness and to yield a minimum 1.10 margins for interest ratio under our first mortgage indenture. Our members satisfy all of their power requirements above their purchase obligations to us with purchases from other suppliers. See "—Our Members And Their Power Supply Resources"OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources."

As of December 31, 2023, our fleet of generating units total 7,8628,525 megawatts of summer planning reserve capacity, which includes 737733 megawatts of Smarr EMC assets that we manage but do not own. Our generation portfolio includes units powered by nuclear, gas, coal, oil and water. We also supply financial and management services to support Green Power EMC's purchase of energy from 320756 megawatts of renewable resources, including, low-impact hydroelectric, landfill gas, wood-waste biomass and solar facilities. See "—"– Relationship with Green Power EMC," "—Our Power Supply Resources,"OUR POWER SUPPLY RESOURCES," "—Our Members and Their Power Supply Resources"OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources" – and "—Properties"PROPERTIES – Generating Facilities."

In 2020,2023, two of our members, Jackson EMC and Cobb EMC, accounted for approximately 15% and 13%11% of our total revenues, respectively. Each of our other members accounted for less than 10% of our total revenues in 2020.

TheWe have a wholesale power contracts we havecontract with each member arethat is substantially similarsimilar. On November 15, 2023, we and extend througheach of our members extended the term of the contracts from December 31, 2050 to December 31, 2085, and each contract will continue thereafter until terminated by three years' written notice by us or the respective member. Under the wholesale power contracts, each member is unconditionally obligated, on an express "take-or-pay" basis, for a fixed percentage of the capacity costs of each of our generation resources and purchased power resources with a term greater than one year. Each wholesale power contract specifically provides that the member must make payments whether or not power is delivered and whether or not a resource is completed, delayed, terminated, operable, operating, retired, sold, leased, transferred or is otherwise unavailable. We are obligated to use our reasonable best efforts to operate, maintain and manage our resources in accordance with prudent utility practices.

We have assigned fixed percentage capacity cost responsibilities to our members for all of our generation and purchased power resources, although not all members participate in all resources. For any future generation or purchased power resource, we will assign fixed percentage capacity cost responsibilities only to members choosing to participate in that resource. The wholesale power contracts provide that each member is jointly and severally responsible for all costs and expenses of all existing generation and purchased power resources, as well as for future resources, whether or not that member has elected to participate in the resource, that are approved by 75% of the members of our board of directors, 75% of our members and members representing 75% of our patronage capital. In the event a member defaults on all or a portion of its payment obligation, the default amount is shared first among the participating members in each resource in which the defaulting member participates. If all these participating members default, each non-participating member is expressly obligated to pay a proportionate share of the default.

Under the wholesale power contracts, we are not obligated to provide all of our members' capacity and energy requirements. Individual members must satisfy all of their requirements above their purchase obligations from us from other suppliers, unless we and our members agree that we will supply additional capacity and associated energy, subject to the approval requirements described above. In 2020, we supplied energy that accounted for approximately 57% of the retail energy requirements of our members. See "—Our Members and Their Power Supply Resources"OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources."

Under the wholesale power contracts, each member must establish rates and conduct its business in a manner that will enable the member to pay (i) to us when due, all amounts payable by the member under its wholesale power contract and (ii) any and all other amounts payable from, or which might constitute a charge or a lien upon, the revenues and receipts derived from the member's electric system, including all operation and maintenance expenses and the principal of, premium, if any, and interest on all indebtedness related to the member's electric system.

The New Business Model Member Agreement that we have with our members requires member approval for us to undertake certain activities. The agreement does not limit our ability to own, manage, control and operate our resources or perform our functions under the wholesale power contracts.

We may not provide services unrelated to our resources or our functions under the wholesale power contracts if these services would require us to incur indebtedness, provide a guarantee or make any loan or investment, unless approved by 75% of the members of our board of directors, 75% of our members, and members representing 75% of

Each member is required 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. We are required to revise our rates as necessary so that the revenues derived from our rates, together with our revenues from all other sources, will be sufficient to pay all of the costs of our system, including the payment of principal and interest on our indebtedness, to provide for reasonable reserves and to meet all financial requirements.

Under the first mortgage indenture, we are required, subject to any necessary regulatory approval, to establish and collect rates which are reasonably expected, together with our other revenues, to yield a margins for interest ratio for each fiscal year equal to at least 1.10. The formulary rate is intended to provide for the collection of revenues which, together with revenues from all other sources, are equal to all costs and expenses we recorded, plus amounts necessary to achieve at least the minimum 1.10 margins for interest ratio. In the event we were to fall short of the minimum 1.10 margins for interest ratio at year end, the formulary rate is designed to recover the shortfall from our members in the following year without any additional action by our board of directors.

Under our loan agreements with each of the Rural Utilities Service and Department of Energy, changes to our rates resulting from adjustments in our annual budget are generally not subject to their approval. We must provide the Rural Utilities Service and Department of Energy with a notice of and opportunity to object to most changes to the formulary rate under the wholesale power contracts. See "– Relationship with Federal Lenders." Currently, our rates are not subject to the approval of any other federal or state agency or authority, including the Georgia Public Service Commission.

Our principal financial requirements are contained in the Indenture, dated as of March 1, 1997, from us to U.S. Bank Trust Company, National Association, as trustee (successor to SunTrust Bank)U.S. Bank National Association), as amended and supplemented, referred to herein as the first mortgage indenture. The first mortgage indenture constitutes a lien on substantially all of our owned tangible and certain of our intangible property, including property we acquire in the future. The mortgaged property includes our owned electric generating plants, the wholesale power contracts with our members and some of our contracts relating to the ownership, operation or maintenance of electric generation facilities owned by us.

Under our first mortgage indenture, we are required, subject to any necessary regulatory approval, to establish and collect rates which are reasonably expected, together with our other revenues, to yield a margins for interest ratio for each fiscal year equal to at least 1.10. The margins for interest ratio is determined by dividing margins for interest by total interest charges on debt secured under our first mortgage indenture. Margins for interest is the sum of:

Margins for interest takes into account any item of net margin, loss, gain or expenditure of any of our affiliates or subsidiaries only if we have received the net margins or gains as a dividend or other distribution from such affiliate or subsidiary or if we have made a payment with respect to the losses or expenditures. In addition, our margins include certain items that are excluded from the margins for interest ratio, such as non-cash capital credits allocation from Georgia Transmission Corporation.

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 the distribution, (i) an event of default exists under the first mortgage 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 at least 30% of our total long-term debt and equities. As of December 31, 2020,2023, our equity ratio was 9.1%9.4%.

As of December 31, 2020,2023, we had approximately $10.6$12.1 billion of secured indebtedness outstanding under the first mortgage indenture. From time to time, we may issue additional first mortgage obligations ranking equally and ratably with the existing first mortgage indenture obligations. The aggregate principal amount of obligations that may be issued under the first mortgage indenture is not limited; however, our ability to issue additional obligations under the first mortgage indenture is subject to certain requirements related to the certified value of certain of our tangible property, repayment of obligations outstanding under the first mortgage indenture and payments made under certain pledged contracts relating to property to be acquired.

Historically, federal loan programs administered by the Rural Utilities Service, an agency of the United States Department of Agriculture, have provided the principal source of financing for electric cooperatives. Loans guaranteed by the Rural Utilities Service and made by the Federal Financing Bank have been a major source of funding for us. However, Rural Utilities Service loan funds are subject to annual federal budget appropriations, and, due to budgetary and political pressures faced by Congress, the availability and magnitude of these loan funds cannot be assured. The budget for fiscal year 2021,2024, which began October 2020,2023, includes aan aggregate loan program level of $5.5 billion, the same as in recent years. The new Administration has not yet proposed a budget for fiscal year 2022.$6.5 billion. We cannot predict the amount or cost of Rural Utilities Service loans that may be available to us in the future.

We have a loan contract with the Rural Utilities Service. Under the loan contract, we may have to obtain approval from the Rural Utilities Service or provide the Rural Utilities Service with a notice and an opportunity to object before we take certain actions, including, without limitation,

As of December 31, 2020,2023, we had $2.4$2.7 billion of outstanding loans guaranteed by the Rural Utilities Service and secured under our first mortgage indenture.

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, we entered into a loan guarantee agreement with the Department of Energy in 2014, pursuant to which the Department of Energy agreed to guarantee over $3.0 billion of our obligations under a multi-advance term loan facility with the Federal Financing Bank. Proceeds of advances made under the facility have been used to reimburse us for a portion of certain costs of construction relating to two additional nuclear units at Plant Vogtle that are eligible for financing under the Title XVII loan guarantee program.

As of December 31, 2020, we hadWe have advanced $3.6 billion inall amounts available under the Department of Energy-guaranteed loans. In total, the Department of Energy-guaranteed2020, we began making principal payments on these loans will provide over $4.6and, at December 31, 2023, we had $4.2 billion of long-term financing at lower interest rates than our alternative sources of financings.outstanding. All advances received under this facility are secured under our first mortgage indenture.

Under the loan guarantee agreement, we may have to obtain approval from the Department of Energy or provide the Department of Energy with a notice and opportunity to object before we take certain actions, including, without limitation,

We and our 38 members are members of Georgia Transmission Corporation (An Electric Membership Corporation), which was formed in 1997 to own and operate the transmission business we previously owned. Georgia Transmission provides transmission services to its members for delivery of its members' power purchases from us and other power suppliers. Georgia Transmission also provides transmission services to third parties. We have entered into an agreement with Georgia Transmission to provide transmission services for third party transactions and for service to our own facilities.

Georgia Transmission has rights in the integrated transmission system, which consists of transmission facilities owned by Georgia Transmission, Georgia Power Company, the Municipal Electric Authority of Georgia and the City of Dalton, Georgia. Through agreements, common access to the combined facilities that compose the integrated transmission system enables the owners to use their combined resources to make deliveries to or for their respective consumers, to provide transmission service to third parties and to make off-system purchases and sales. The integrated transmission system was established in order to obtain the benefits of a coordinated development of the parties' transmission facilities and to make it unnecessary for any party to construct duplicative facilities.

We, Georgia Transmission and our 38 members are members of Georgia System Operations Corporation, which was formed in 1997 to own and operate the system operations business we previously owned. Georgia System Operations operates the system control center and currently provides Georgia Transmission and us with system operations services and administrative support services. We have contracted with Georgia System Operations to schedule and dispatch our resources. We also purchase from Georgia System Operations services that it purchases from Georgia Power under the Control Area Compact, which we co-signed with Georgia System Operations. See "—Our Members and Their Power Supply Resources"OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Members' Relationship with Georgia Transmission and Georgia System Operations." Georgia System Operations provides support services to us in the areas of accounts payable, payroll, auditing, human resources, campus services, telecommunications and information technology at cost.

As of December 31, 2020, we had approximately $11.5 million ofWe have made loans outstanding to Georgia System Operations primarily for the purpose of financing its capital expenditures. As of December 31, 2023, the balance of the loans outstanding was $10.3 million. Georgia System Operations has an additional $4.5 million that it can draw under one of its loans with us.

Georgia Transmission has contracted with Georgia System Operations to provide certain transmission system operation services including reliability monitoring, switching operations, and the real-time management of the transmission system.

Smarr EMC is a Georgia electric membership corporation owned by 35 of our 38 members. Smarr EMC owns two combustion turbine facilities with aggregate summer planning reserve capacity of 737733 megawatts. We provide operations, financial and management services forto Smarr EMC. See "—Our Members and Their Power Supply Resources"OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources."

Under current Georgia law, our members generally have the exclusive right to provide retail electric service in their respective territories. However, the Georgia Territorial Act permits limited competition among electric utilities

Some states have implemented varying forms of retail competition among power suppliers. No legislation related to retail competition has yet been enacted in Georgia which would amend the Georgia Territorial Act or otherwise affect the exclusive right of our members to supply power to their current service territories. However, parties have unsuccessfully sought and will likely continue to seek to advance legislative proposals that will directly or indirectly affect the Georgia Territorial Act in order to allow increased retail competition in our members' service territories. The Georgia Public Service Commission does not have the authority under Georgia law to order retail competition or amend the Georgia Territorial Act.

We routinely consider, along with our members, a wide array of potential actions to meet future power supply needs, maintain competitive rates, adapt to technological innovations, including distributed generation and energy storage technologies, and respond to the evolving competitive and regulatory landscape. We cannot predict at this time the outcome of various developments that may lead to increased competition in the electric utility industry or the effect of any developments on us or our members.

Many members are also providing or considering proposals to provide non-traditional products and services such as natural gas, telecommunications (including broadband) and other services. The Georgia Public Service Commission can authorize member affiliates to market natural gas but is required to condition any authorization on terms designed to ensure that cross-subsidizations do not occur between the electricity services of a member and the gas activities of its gas affiliates. Among other conditions, for members providing broadband services through an affiliate, the Georgia Public Service Commission must approve a cost allocation manualallocations designed to ensure that cross-subsidizations do not occur between the broadband services and the electric and/or gas services of a member or its affiliates.

Further, a member's power supply planning may include consideration of assignment of its rights and obligations under its wholesale power contract to another member or a third party. We have existing provisions for wholesale power contract assignment, as well as provisions for a member to withdraw and concurrently to assign its rights and obligations under its wholesale power contract. Assignments upon withdrawal require the assignee to have certain published credit ratings and to assume all of the withdrawing member's obligations under its wholesale power contract with us, and must be approved by our board of directors. Assignments without withdrawal are governed by the wholesale power contract and must be approved by both our board of directors and the Rural Utilities Service.

Our success depends on the people who are part of our company. We believe that in order to deliver superior performance and maximize the value of our members’ investment, we must attract and retain the most qualified workforce available. We further believe that a strong corporation requires initiative, commitment and talent from its employees and that exceptional results evolve from diversity, continuous improvement, personal development and the contributions of many

As an electric cooperative, we are also committed to being a positive influence in the communities we serve. To accomplish this goal, we support and encourage our associates to participate in a variety of initiatives and activities that help the communities where we and our members live and work.

We supply capacity and energy to our members for a portion of their requirements from a combination of our fleet of generating assets and power purchased from other suppliers.assets. In 2020,2023, we supplied approximately 57%68% of the retail energy requirements of our members. Our members purchased the remaining 43%32% from a variety of suppliers, including Green Power EMC (renewable resources), Smarr EMC (gas-fired resources), Georgia Energy Cooperative (gas-fired resource), Southeastern Power Administration (hydroelectric power), and several power marketers and other wholesale suppliers. For more detailed information on these other purchases, see "—Our Members and Their Power Supply Resources"OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources."

OurAs of December 31, 2023, our fleet of generating units total 7,8628,525 megawatts of summer planning reserve capacity, including 737733 megawatts of Smarr EMC assets, which we manage. Our generation portfolio includes interests in nuclear, coal, natural gas, oil and hydro units. Georgia Power, the Municipal Electric Authority of Georgia (MEAG) and the City of Dalton also have interests in nineseven of these units at Plants Hatch, Vogtle Wansley and Scherer. Georgia Power serves as operating agent for these nineseven units.

We currently have no material power purchase or sale agreements.

We have interchange, transmission and/or short-term capacity and energy purchase or sale agreements with a number of power marketers and other power suppliers. The agreements provide variously for the purchase and/or sale of capacity and energy and/or for the purchase of transmission service.

A recent filing atWe are a member of the FERC proposed a Southeast Energy Exchange Market (SEEM) that includeswhich began operating in 2022. SEEM, whose members include the traditional electric operating companies and many of the other electric service providers in the Southeast, including us. SEEM is an extension of the existing bilateral market wherein which participants would use an automated, intra-hour energy exchange to buy and sell power close tonear the time the energy is consumed, utilizing available unreserved transmission. If approved byOur participation in SEEM has had minimal impact on our business to date. On July 14, 2023, the FERC,U.S. Court of Appeals for the District of Columbia Circuit vacated certain Federal Electric Regulatory Commission orders related to SEEM is expectedand remanded the proceeding to begin service in early 2022.the Federal Electric Regulatory Commission. The ultimate outcome of this matter cannot be determined at this time.

We, Georgia Power, the Municipal Electric Authority of Georgia (MEAG), and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units under construction at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Our ownership interest and proportionate share of the cost to construct these units is 30%. Pursuant to this agreement, Georgia Power has designated Southern Nuclear Operating Company, Inc. as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services.

In 2008, Georgia Power, acting for itself and as agent for the Co-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (collectively, Westinghouse). Pursuant to the EPC Agreement, Westinghouse agreed to design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle.

Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement. In March 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Effective in July 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement (the Services Agreement), pursuant to which Westinghouse is providing facility design and engineering services, procurement and technical support and staff augmentation on a time and materials cost basis. The Services Agreement provides that it will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days’ written notice.

In October 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, pursuant to which Bechtel serves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel and is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel’s performance against cost and schedule targets. Each Co-owner is severally, and not

Our current budget for our 30% ownership interest inand proportionate share of the cost to construct Vogtle Units No. 3 and No. 4 is $7.530%, representing approximately 660 megawatts. As of December 31, 2023, our actual costs related to the new Vogtle units were approximately $8.2 billion, net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and approximately $384 million we received from Georgia Power in connection with cost-sharing provisions of the Global Amendments and settlement agreement described below.

Our current budget, which includes capital costs and allowance for funds used during construction, is a range of $8.3-8.35 billion and is based on a commercial operation date in the second quarter of 2024 for Unit No. 4 and Georgia Power continuing to pay 66% of our allocation30% share of the project-level contingency and a separate Oglethorpe-level contingency. Asremaining cost of December 31, 2020,construction pursuant to the settlement agreement described below. Any schedule extension beyond June 2024 for Unit No. 4 is expected to increase our total investment in the additional Vogtle units wascosts by approximately $6.0 billion.$20 million per month. We and some of our members have implemented various rate management programs to lessen the impact on rates whenrelated to the additional Vogtle Units No. 3 and No. 4 reach commercial operation. The Georgia Public Service Commission approved in-service dates for Vogtle Units No. 3 and No. 4 are November 2021 and November 2022, respectively.units.

As part of its ongoing process,processes, Southern Nuclear continues to evaluate cost and schedule forecasts for Unit No. 4 on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnoversstart-up testing and related test results and workforce statistics.

From November 2020 through January 2021, the number of active COVID-19 cases at the site increased significantly, consistent with a national rise in cases, which further impacted productivity and the pace of activity completion. Although still present, this spike in cases has since abated intoOn February and early March. The incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated by1, 2024, Georgia Power to be between $325announced that during start-up and $415 million (of which our 30% interest is $98 to $125 million) and is included in the project budget. As described previously, Georgia Power included estimated costs associated with near-term COVID-19 mitigation actions and related impacts on construction productivity in the additional project-level contingency established as of December 31, 2020. The continuing effects of the COVID-19 pandemic could further disrupt or delay construction,pre-operational testing supervisory, and support activities at Vogtle Units No. 3 and No. 4.

Meeting the pace of work package completion and system turnovers, and required construction remediation work.

New challenges also may continue to arise as Unit No. 4 moves further into testing and start-up, including anywhich may result in required engineering changes or any remediation related thereto, ofto plant systems, structures or components (some of which are based on new technology that has only within the last fewseveral years began initial operation in the global nuclear industry at this scale), any. These challenges may result in further schedule delays and/or cost increases.

With the receipt of which may require additional labor and/or materials; or other issues could arise and further impact the projected schedule and estimated cost.

The ultimate outcome of these matters cannot be determined at this time.

In November 2017, the Co-owners entered into an amendment to their joint ownership agreements for Vogtle Units No. 3 and No. 4 to provide for, among other conditions, additional Co-owner approval requirements. These joint ownership agreements, including the Co-owner approval requirements, were subsequently amended, effective August 31, 2018. As described below, certain provisions of the Joint Ownership Agreements were modified further onin September 26, 2018 by the Term Sheet that was memorialized onin February 18, 2019 when the Co-owners entered into certain amendments (the Global Amendments) to the Joint Ownership Agreements (as amended, the Joint Ownership Agreements).

As a result of an increase in the total project capital cost forecast and Georgia Power’s decision not to seek recovery of its allocation of the increase in the base capital costs and the increased construction budget in connection with Georgia Power’s 19th VCMnineteenth Vogtle construction monitoring report (VCM 19) in 2018, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4

In connection with the September 2018 vote to continue construction, Georgia Power entered into a binding term sheet with the other Co-owners and MEAG’s wholly-owned subsidiaries MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, and MEAG Power SPVP, LLC that mitigatedto mitigate certain financial exposure for the other Co-owners and offered to purchase production tax credits from each of the other Co-Owners, at that Co-owner’s option (the Term Sheet). OnIn February 18, 2019, the Co-owners entered into the Global Amendments to memorialize the provisions of the Term Sheet. Pursuant to the Global Amendments and consistent with the Term Sheet, the Joint Ownership Agreements provide that:

If the EAC iswas revised and exceedsexceeded the EAC in the nineteenth VCM report19 by more than $2.1 billion, each of the Co-owners, other than Georgia Power, will havehad a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power’s agreement to pay 100% of such Co-owner’s remaining share of construction costs actually incurred in excess of the EAC in the nineteenth VCM report19 plus $2.1 billion. In this event,

Pursuant to the Joint Ownership Agreements, as amended by the Global Amendments, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction, or can vote to suspend construction, if certain adverse events occur, including: (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement, the Bechtel

The ultimate outcome of these matters cannot be determined at this time.

We have loans from the Federal Financing Bank guaranteed by the Department of Energy to fundprovide funding for over $4.6 billion of the cost to construct our 30% undivided interest in Vogtle Units No. 3 and No. 4. These loans began amortizing in 2020 and, in December 2022, we made the last advance under these loans. As of December 31, 2020, we have borrowed $3.62023, $4.2 billion under these guaranteed loans.of the loans remained outstanding. For additional information regarding terms of the loan and loan guarantee agreement with the Department of Energy, including conditions for future advances, potential repayment over a five-year period, covenants and events of default, see Note 7a of Notes to Consolidated Financial Statements.

We have alsoAs of December 31, 2023, we had financed $2.3$3.2 billion of the capital costs of the Vogtle units through capital market debt issuances. Combined withWe anticipate financing the $4.6 billion loan guaranteed byremaining costs of the Vogtle units and amounts amortized under the Department of Energy, we have arranged financing for more than 92% of our $7.5 billion budget. We anticipate financing any project costs not guaranteed by the Department of EnergyEnergy-guaranteed loan in the capital markets. For additional information regarding the financing of Vogtle Units No. 3 and No. 4, see “MANAGEMENT'S DISCUSSION OF AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities—Department of Energy-Guaranteed Loans.”

Under the Bipartisan Budget Act of 2018, we qualify for nuclear production tax credits related to Vogtle Units No. 3 and No. 4. We expectBeginning with the commercial operation of Unit No. 3, we began to receive these tax credits in accordance with our 30% ownership interest in the Vogtle Units. We estimate that the nominal value of our allocation of production tax credits will be approximatelyup to $700 million and will be earned for eight years post commercial operation. Pursuant to the Global Amendments, Georgia Power agreed to purchase our allocation of production tax credits at varying purchase prices dependent upon the actual cost to complete construction of Vogtle Units No. 3 and No. 4 as compared to the EAC included in the nineteenth VCM report.19. Based on the current project budget, the purchase price would beis 98% of face value. Any purchases will be at our option and would occur after suchWe sold all production tax credits are earned.earned in 2023 to Georgia Power and received an aggregate amount of $21.7 million and used the proceeds to offset operating costs for Unit No. 3. We willexpect to continue to analyze various options to monetize these credits with one or more third parties, including Georgia Power. In order to maximize the value of theseselling earned production tax credits we do not anticipate entering into any agreement to sell these production tax credits until one or both of the Vogtle Units reach commercial operation. We expectGeorgia Power and will continue to use the proceeds received from the sale of production tax credits to offset operating costs following commercial operation of the new Vogtle Units. Any amountsAmounts received from these sales will not affect our project budget.

The ultimate outcome of these matters cannot be determined at this time.

On March 1, 2021,In August 2023, we entered intosigned a purchase and sale agreement with Southeast PowerGen,Mackinaw Power, LLC an affiliateto purchase Walton County Power, LLC, owner of the Carlyle Group Inc., to purchase EffinghamWalton County Power Plant. The Walton facility consists of three natural gas-fired combustion turbine electric generating units with a 511 megawatt natural gas combined cycle facilitynominal capacity of 465 megawatts located in Walton County, Georgia. ThisThe acquisition is subject to customary closing conditions including regulatory approvals, and is expected to close in the second quarter of 2021.2024.