Registrant's telephone number, including area code: (770) 270-7600 Securities registered pursuant to Section 12(b) of the Act: Securities registered pursuant to Section 12(g) of the Act: None ☐ INFORMATION hazards; In 2023. 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. 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, On March 22, 2019, we and the Department of Energy executed an amended and restated loan guarantee agreement that added $1.6 billion to the loan guarantee. In connection with the increase of the loan guarantee, we entered into additional loan documents with the Federal Financing Bank to increase the aggregate amount available under the term loan facility. Proceeds of advances made under co-signed with Georgia System Operations. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES " 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. its affiliates. 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 members purchased the remaining 32% from a variety of suppliers, including Green Power EMC (renewable resources), Smarr EMC (gas-fired resources), 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 – Member Power Supply Resources." of all amounts owed to Bechtel under the Bechtel Agreement. costs. maintaining an average times interest earned ratio and an average debt service coverage ratio of not less than 1.25 and an operating times interest earned ratio and an operating debt service coverage ratio of not less than 1.10, in each case for the two highest out of every three successive years. and other power supply resources owned by the members. approximately 10 megawatts. full compliance with every applicable requirement. Plant Scherer. Paris Climate Agreement's goals. In In If Georgia's requirements for coal ash disposal are subsequently revised or the proposed closure plans are not approved, our estimated compliance costs could increase materially. claims relating to operations and/or emissions, including actions by citizens to enforce environmental regulations and claims for personal injury due to such operations and/or emissions. Likewise, actions by private citizen groups to enforce environmental laws and regulations are becoming increasingly prevalent. We cannot predict the outcome of current or future actions, our responsibility for a share of any damages awarded, or any impact on facility operations. We do not believe, however, that current actions will have a material adverse effect on our financial operations. Southern Nuclear has notified the Nuclear Regulatory Commission of its intent to seek to renew Plant Hatch Units No. 1 and No. 2 licenses for an additional 20 years, through 2054 and 2058, respectively. For information concerning nuclear insurance, see Note 10 of Notes to Consolidated Financial Statements. For information regarding the Nuclear Regulatory Commission's regulation relating to decommissioning of nuclear facilities and regarding the Department of Energy's assessments pursuant to the Energy Policy Act for decontamination and decommissioning of nuclear fuel enrichment facilities, see Note 1 of Notes to Consolidated Financial Statements. be available from Unit No. 4. $4.6 billion in loans from the Federal Financing Bank and a related loan guarantee from the Department of Vogtle Unit No. 4. obligations at our operating and retired coal plants are approximately $600 million to $800 million (in year of expenditure dollars), approximately $50 million of which had been spent as of December 31, 2023. We continue to review the ultimate cost of these rules on our co-owned coal facilities which may be affected by any revised rules or litigation challenging those rules and cannot be determined at this time. reputational harm. were to be breached or otherwise fail, we may be unable to fulfill critical business functions, including the operation of our generation assets and our ability to 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. If a defaulting counterparty is in poor financial condition, we may not be able to recover damages for any breach of contract. Regardless of our financial condition, (Mark One) ý☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 20172023ORoOR ☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934For the Transition Period FromtoCommission File No. 000-53908
Georgia 58-1211925 Georgia58-1211925(State or other jurisdiction of
incorporation or organization)(I.R.S. employer
identification no.)
30084-5336Tucker, Georgia30084-5336(Address of principal executive offices) (Zip Code) None None o ☐ No ý ☒ ý☒ Noo☐ o ☐No ý☒ electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý☒ No o Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ýLarge accelerated filer ☐ Accelerated filer ☐ ý(Do not check if asmaller reporting company)☒Smaller reporting company Emerging growth company ☐ o☐o☐Noý☒2017ITEM Page PART I PART II PART III PART IV iSTATEMENTSthe heading "RISK FACTORS" and in other sections of this annual report. In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this annual report may not occur.in particular,such as the construction of two additional nuclear unitsUnit No. 4 at Plant Vogtle;•decisions made byVogtle, the Georgia Public Service Commission in closure of coal ash ponds and any future generation projects we undertake;processor legislative responses to climate change initiatives or efforts to reduce greenhouse gas emissions, including carbon dioxide;the two additional units at Plant Vogtle;a decision by more than 10% of the co-owners of the additional Vogtle units notproceedcomply with the construction of the additional Vogtle units upon the occurrence of certain material adverse events;receive advances undermeet the U.S. Department of Energyapplicable loan guarantee agreement foror grant conditions and requirements; nuclear units at Plant Vogtle;the Department of Energy'sits decision to require such repayment;the continued availability of funding from the Rural Utilities Service;•increasing debt caused by significant capital expenditures;•unanticipated changes in capital expenditures, operating expenses and liquidity needs;•actions by credit rating agencies;•commercial banking and financial market conditions;•the impact of regulatory or legislative responses to climate change initiatives or efforts to reduce greenhouse gas emissions, including carbon dioxide;•costs associated with achieving and maintaining compliance with applicable environmental laws and regulations, including those related to air emissions, water and coal combustion byproducts;•legislative and regulatory compliance standards and our ability to comply with any applicable standards, including mandatory reliabilityii
unanticipated variation in demand for electricity or load forecasts resulting from changes in population and business growth (and declines), consumer consumption, energy conservation and efficiency efforts and the general economy;standards, and potential penalties for non-compliance;•risks and regulatory requirements related to the ownership and construction of nuclear facilities;•adequate funding of our nuclear decommissioning trust funds including investment performance and projected decommissioning costs;•continued efficient operation of our generation facilities by us and third-parties;•the availability of an adequate and economical supply of fuel, water and other materials;•reliance on third-parties to efficiently manage, distribute and deliver generated electricity;•acts of sabotage, wars or terrorist activities, including cyber attacks;•changes in technology available to and utilized by us, our competitors, or residential or commercial consumers in our members' service territories, including from the development and deployment of distributed generation and energy storage technologies;•the inability of counterparties to meet their obligations to us, including failure to perform under agreements;•litigation or legal and administrative proceedings and settlements;•our members' ability to perform their obligations to us;•our members' ability to offer their retail, commercial and industrial customers competitive rates;•changes to protections granted by the Georgia Territorial Act that subject our members to increased competition;•significant changes in critical accounting policies material to us; andhazards.278337 employees.1.92.1 million electric consumers (meters) representing approximately 4.14.5 million people. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES."www.opc.com.www.opc.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are made available on this website as soon as reasonably practicable after this material is filed with the Securities and Exchange Commission. Information contained on our website is not incorporated by reference into and should not be considered to be part of this annual report on Form 10-K. See "– First Mortgage Indenture."nearly two-thirdsa 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 –Member– Member Power Supply Resources." Our7,8438,525 megawatts of summer planning reserve capacity, which includes 728733 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 756 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–Member– Member Power Supply ResourcesResources" –Smarr EMC" and"PROPERTIES and "PROPERTIES – Generating Facilities."2017,2023, two of our members, Jackson EMC and Cobb EMC, accounted for 14.7%approximately 15% and 14.3%11% of our total revenues, respectively. Each of our other members accounted for less than 10% of our total revenues in 2017. Thecontracts 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.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 approved 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. For resources so approved in which less thanIn the event a member defaults on all members participate, costs areor a portion of its payment obligation, the default amount is shared first among the participating members and ifin 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.In 2017, we supplied energy that accounted for approximately 63% of the retail energy requirements of our members. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES –Member– Member Power Supply Resources." and purchased power resources. The monthly charges for capacity and other non-energy charges are based on our annual budget. These capacity and other non-energy charges may be adjusted by our board of directors, if necessary, during the year through an adjustment to the annual budget. Energy charges reflect the pass-through of actual energy costs, including fuel costs, variable operations and maintenance costs and purchased energy costs. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Summary of Cooperative Operations –Rate Regulation."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.2017,2023, our equity ratio was 9.8%9.4%.2017,2023, we had approximately $8.2$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.Congress has authorized the Rural Utilities Service to charge a fee to cover the cost of loan guarantees for baseload generation, if requested by a borrower. The Rural Utilities Service must establish a process to implement this authorization prior to making it available to borrowers. The President's budget for fiscal year 2019,2024, which beginsbegan October 2018, proposes a2023, includes an aggregate loan program level of $5.5 billion, the same as the current program level. Although Congress has historically rejected proposals to dramatically curtail or redirect the Rural Utilities Service loan program, there can be no assurance that it will continue to do so. Because of these factors, we$6.5 billion. We cannot predict the amount or cost of Rural Utilities Service loans that may be available to us in the future.2017,2023, we had $2.5$2.7 billion of outstanding loans guaranteed by the Rural Utilities Service and secured under our first mortgage indenture.the facility will bethese facilities have been used to reimburse us for a portionover $4.6 billion 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. Aggregate borrowingsloan guarantee program.facility may not exceed $3.1 billionDepartment of eligible project costs,Energy-guaranteed loans. In 2020, we began making principal payments on these loans and, as ofat December 31, 2017,2023, we had borrowed $1.7$4.2 billion under this loan. Advances may not occur after December 31, 2020.outstanding. All advances received under this facility are secured under our first mortgage indenture. Following bankruptcy of Westinghouse in March 2017, the loan guarantee agreement was amended to restrict advances pending the satisfaction of certain conditions, including the Department of Energy'sapproval of the Bechtel Agreement and a further amendment to the loan guarantee agreement to incorporate provisions relating to the Bechtel Agreement and other replacement agreements. While not assured, we expect to satisfy these conditions in the second quarter of 2018. Under this 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,significant dispositions of system assets, including In September 2017,Department of Energy issued a conditional commitment to us for $1.6 billion of additional guaranteed funding under the loan guarantee agreement. This additional funding is subject to an amendment and restatementterms of the loan guarantee agreement, and satisfaction of certain other conditions. The conditional commitment expires on June 30, 2018, subject to any extension approved by the Department of Energy. While not assured, we expect to close on this additional loan in the second quarter of 2018. For additional information regarding the current status of the loan guarantee agreement, including conditions to future advances and potential repayment over a five-year period, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION –Financial Condition-Financing Requirements – Department of Energy –Guaranteed Loan" andNOTENote 7a of Notes to Consolidated Financial Statements. For additional information on Vogtle Units No. 3 and No. 4, see "– OUR POWER SUPPLY RESOURCES –Future– Future Power Resources ––Members'– 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.currently have approximately $13.1 million ofmade 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 $4.0$4.5 million that it can be drawndraw under one of its loans with us.the development and construction of Vogtle Units No. 3 and No. 4. For further information regarding the agreements between Georgia Power and us, see "PROPERTIES – Fuel Supply," "– Co-Owners of Plants –Georgia Power Company" and "– The Plant Agreements." Georgia Power supplies services to us and Georgia System Operations to support the scheduling and dispatch of our resources, including off-system transactions. Georgia Power and our members are competitors in the State of Georgia for electric service to any new customer that has a choice of supplier under the Georgia Territorial Electric Service Act, which was enacted in 1973, commonly known as the Georgia Territorial Act (see "– Competition"). For further information regarding our members' relationships with Georgia Power, see "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Service Area and Competition.728733 megawatts. We provide operations, financial and management services forto Smarr EMC. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources."towith Green Power EMCpower supply cooperativeGeorgia electric membership corporation specializing in the purchase of renewable energy for its members. Green Power EMC currently purchases energy from 756 megawatts of renewable energy resources. By 2025, the capacity is expected to increase by at least 80 megawatts, bringing the total capacity to more than 836 megawatts. We supply financial and management services to Green Power EMC. SeeFor more information on the renewable resources of Green Power EMC, see "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources –Green Power EMC."Since 1973, however,However, the Georgia Territorial Act has permittedpermits limited competition among electric utilities located in Georgia for sales of electricity to certain large commercial or industrial customers. The owner of any new facility may receive electric service from the power supplier of its choice if the facility is located outside of municipal limits and has a connected load upon initial full operation of 900 kilowatts or more. Georgia is projected to experience significant load growth over the next several years. Our members are actively engaged in competition with other retail electric suppliers for thesea significant amount of new commercial and industrial loads. While the competition for 900-kilowattThe number of commercial and industrial loads represents onlyserved by our members continues to increase annually. This limited competition in Georgia, this competition has given our members the opportunity to develop resources and strategies to operate in a more competitive market. We routinely consider, along with our members, a wide arraynot only on the relative greenhouse gas emissions from a supplier's sources but also onand the nature of the regulation. Some of our generation sources emit greenhouse gases but we also have generation sources thatwhile others emit no greenhouse gases. Some ofnone. Comparatively, our competitors usemay rely on sources that emit proportionately more or less greenhouse gases while the sourcesthan we do. Further, many of some competitors emit less. Further,our members' third-party suppliers to our members are relyingalso rely on generation sources that emit greenhouse gases. The terms and conditions in the contracts with these third-party suppliers would determine the extent to which our members would be affected byany greenhouse gas regulation of the greenhouse gas emissions of these suppliers.suppliers affects our members. We believe our and our members' diverse portfolios of generation facilities, including the diversity of third-party suppliers, would mitigate any impactimpacts on our and our members' competitiveness resulting from any regulation. See "REGULATION – Environmental –Carbon Dioxide Emissions and Climate Change" and "RISK FACTORS." Depending on Among other conditions, for members providing broadband services through an affiliate, the natureGeorgia Public Service Commission must approve cost allocations designed to ensure that cross-subsidizations do not occur between the broadband services and the electric and/or gas services of the generation business in Georgia, there could be reasons for the members to separate their physical distribution business from their energy business,a member or otherwise restructure their current businesses to operate more effectively.–Results– Results of Operations – Factors Affecting Results." While changing weather patterns, whether resulting from greenhouse gas emissions or otherwise, could, under certain circumstances, alter seasonal weather patterns, predictions of future changes in weather patterns are inherently speculative, and we cannot make accurate conclusions about seasonality related to changes in weather patterns. Our energy revenues recover energy costs as they are incurred and also fluctuate month to month. Capacity revenues reflect the recovery ofare based upon budgeted expenditures and are generally recognized and billed to our fixed costs, which do not vary significantly from month to month; therefore, capacity charges are billed and capacity revenues are recognizedmembers in substantially equal monthly amounts.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 and if required, we reduce our capacity revenues and recognize a refund liability to our members. See Note 1e of Notes to Consolidated Financial Statements for information regarding revenue recognition.
Human Capitala combination of our fleet of generating assets and power purchased from other suppliers.assets. In 2017,2023, we supplied approximately 63%68% of the retail energy requirements of our members. Our7,8438,525 megawatts of summer planning reserve capacity, including 728733 megawatts of Smarr EMC assets, which we manage. ThisOur generation portfolio includes our interests in units fueled by nuclear, coal, natural gas, oil and water.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. Georgia Power also has an interest in the three units at Rocky Mountain, which we operate. In addition to our 3133 generating units, we operate and manage six gas-fired generating units on behalf of Smarr EMC.–Member– Member Power Supply Resources –Smarr EMC."purchase small amounts of energy from a "qualifying facility" under the Public Utility Regulatory Policies Act of 1978. Under a waiver order from the Federal Energy Regulatory Commission, we historically made all purchases the members would have otherwise been required to make under the Public Utility Regulatory Policies Actsupply financial and we were relieved of our obligation to sell certainmanagement services to "qualifying facilities" so long as the members make those sales. In 2017, our purchases from this qualifying facility provided less than 0.1% of the energy we supplied to our members. Under their wholesale power contracts, the members may now make such purchases instead of us. We managesupport Green Power EMC's purchase of energy from 119756 megawatts of renewable resources.resources, plus an additional 80 megawatts under contract to be constructed. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources – 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. Under the terms of the EPC Agreement, the Co-owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments. Toshiba Corporation guaranteed certain payment obligations of Westinghouse under the EPC Agreement (the Toshiba Guarantee),including any liability of Westinghouse for abandonment of work. Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement. On In March 29, 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. In connection with the bankruptcy filing, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreement with Westinghouse and WECTEC Staffing Services LLC to provide for a continuation of work at Vogtle Units No. 3 and No. 4. The Interim Assessment Agreement expired onEffective in July 27, 2017, upon the effective date of the Services Agreement discussed below. Subsequent to Westinghouse's bankruptcy filing, a number of subcontractors to Westinghouse alleged non-payment by Westinghouse for amounts owed for work performed on Vogtle Units No. 3 and No. 4. Georgia Power, acting for itself and as agent for the Co-owners, has taken actions to remove liens on the site filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against Westinghouse and the Co-owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and payment of other Westinghouse pre-petition accounts payable have been paid or accrued as of December 31, 2017. On June 9, 2017, Georgia Power and the other Co-owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (the Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee was $3.68 billion (the Guarantee Obligations), of which our proportionate share was $1.1 billion. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, the Co-owners, certain affiliates of the Municipal Electric Authority of Georgia, and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (the Settlement Agreement Amendment). The Settlement Agreement Amendment provided that Toshiba's remaining scheduled payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of the Co-owners and certain affiliates of the Municipal Electric Authority of Georgia against Westinghouse, and the Co-owners surrendered certain letters of credit securing a portion of Westinghouse's potential obligations under the EPC Agreement. Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement which was amended and restated on July 20, 2017 (the Services Agreement), forpursuant to which Westinghouse to transition construction management of Vogtle Units No. 3is providing facility design and No. 4 to Southern Nuclearengineering services, procurement and to provide ongoing design, engineering,technical support and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved Westinghouse's motion seeking authorization to (i) enter into the Services Agreement, (ii) assumestaff augmentation on a time and assign to the Co-owners certain project-related contracts, (iii) join the Co-owners as counterparties to certain assumed project-related contracts, and (iv) reject the EPC Agreement.materials cost basis. The Services Agreement and Westinghouse's rejection of the EPC Agreement, became effective upon approval by the Department of Energy on July 27, 2017. The Services Agreementprovides 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. Effective 23, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, wherebypursuant to which Bechtel will serveserves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement). Facility design and engineering remains the responsibility of Westinghouse under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel'sBechtel’s performance against cost and schedule targets. Each Co-owner is severally, and not jointly, liable for its proportionate share, based on its ownership interest, The Co-owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts related to work performed prior to the termination (including the applicable portionbase fee), certain termination-related costs and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including, certain Co-owner suspensions of work, certain breaches of the Bechtel Agreement by the Co-owners, Co-owner insolvency and certain other events. Pursuantcost to the loan guarantee agreement between us and the Department of Energy, we are required to obtain the Department of Energy's approval of the Bechtel Agreement prior to obtaining any further advances under the loan guarantee agreement. On November 2, 2017, the Co-owners entered into an amendment to their joint ownership agreements for Vogtle Units No. 3 and No. 4 (as amended, the Joint Ownership Agreements) to provide for, among other conditions, additional Co-owner approval requirements. Pursuant to the Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction if certain adverse events occur, including: (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia Public Service Commission or Georgia Power determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in Georgia Power's seventeenth Vogtle construction monitoring (VCM) report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Joint Ownership Agreements, the required approval of holders of ownership interests inconstruct Vogtle Units No. 3 and No. 4 is at least (i) 90% for a change30%, representing approximately 660 megawatts. As of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. On December 21, 2017, the Georgia Public Service Commission took a series of actions31, 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.issued its related order on January 11, 2018. Among other actions,July 2023, respectively, the Public Service Commission (i) accepted Georgia Power's recommendation that construction of Vogtle Units No. 3 and No. 4 be completed, with Southern Nuclear Operating Company, Inc. serving as construction manager and Bechtel as primary contractor and (ii) approved the revised schedule placing Unit No. 3 in service in November 2021 and Unit No. 4 in service in November 2022. In its January 11, 2018 order, the Public Service Commission stated if certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Public Service Commission reserve the right to reconsider the decision to continue construction. Parties have filed two petitions with the Fulton County Superior Court appealing the Georgia Public Service Commission's January 11, 2018 order. Georgia Power has stated that it believes these appeals have no merit; however, an adverse outcome in one or both of these appeals could have a material impact on our financial condition and results of operations. We expect Vogtle Units No. 3 and No. 4 to be placed in service by November 2021 and November 2022, respectively. Our project budget for the additional Vogtle units is $7.0 billion, which includes capital costs, allowance for funds used during construction and a contingency amount. This budget is net of the $1.1 billion of payments we received from Toshiba under the Guarantee Settlement Agreement. As of December 31, 2017, our total investment in the additional Vogtle units was approximately $2.9 billion, net of the payments received from Toshiba under the Guarantee Settlement Agreement. The payments from Toshiba were recorded as a reduction to the construction work in progress balance for the additional Vogtle units. In the event the Vogtle project is cancelled, our proportionate share of the Co-owners' cancellation costs are estimated to be approximately $230 million. If the project is cancelled, we would seek regulatory accounting treatment to amortize our investment in the Vogtle project over a long-term period which would require the approval of our board of directors and the Rural Utilities Service. We have a $3.1 billion federal loan guarantee from the Department of Energy, under which we have advanced $1.7 billion as of December 31, 2017. Pursuant to the terms of the loan guarantee agreement, no further advances are permitted pending satisfaction of certain conditions, including approval of the Bechtel Agreement and an amendment to the loan guarantee agreement to incorporate provisions relating to the Bechtel Agreement and other replacement agreements. While not assured, we expect to satisfy these conditions in the second quarter of 2018. On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to $1.6 billion of additional guaranteed funding under the loan guarantee agreement. This conditional commitment expires on June 30, 2018, subject to any extension approved by the Department of Energy. Final approval and issuance of the additional loan guarantee by the Department of Energy cannot be assured andsite is subject to an amendment and restatement of the loan guarantee agreement and satisfaction of certain other conditions. For additional information regarding conditions for future advances, potential repayment over a five-year period, covenants and events of default under the loan guarantee agreement with the Department of Energy, see Note 7 of Notes to Consolidated Financial Statements. We have also financed an additional $1.4 billion of the capital costs of the Vogtle units through capital market debt issuances. For additional information regarding the financing of Vogtle Units No.3 and No.4, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS –Financial Condition – Financing Activities – Department of Energy-Guaranteed Loan" and "Capital Requirements – Capital Expenditures." Under the Bipartisan Budget Act of 2018, we qualify for nuclear production tax credits related to Vogtle Units No. 3 and No. 4. We expect to receive these tax credits in accordance with our 30% ownership interest in the Vogtle Units and are analyzing various options to monetize these credits with a third party. We estimate that the nominal value of our allocation of production tax credits will be approximately $660 million and will be earned for eight years post commercial operation. As construction continues, risks remain that construction-related challenges, including management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly and installation of plant systems, structures and components, or other issues could further impact the projected schedule and cost. Aspects of the Westinghouse AP1000 design are based on new technologies and commercial operation of this design has yet to be tested. There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filedCommission’s operating reactor oversight process and approved or are pending before the Nuclear Regulatory Commission.must meet applicable technical and operational requirements contained in its operating license. Various design and other licensing-based compliance matters including the timely resolution of inspections, tests, analyses, and acceptance criteria and the related approvals by the Nuclear Regulatory Commission, may arise, which may result in additional license amendmentsamendment requests or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners."RISK FACTORS"“RISK FACTORS” for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units. From time to time,may assistand our members in investigatingare evaluating potential new power supply resources, after complianceto meet our members' anticipated power supply needs and are evaluating potential funding opportunities through the Rural Utilities Service Empowering Rural America program. Before acquiring or constructing any generation resource, we must comply with the terms of the New Business Model Member Agreement. See "OGLETHORPE POWER CORPORATION – New Business Model Member Agreement."1.92.1 million electric consumers (meters) representing approximately 4.14.5 million people. Our members serve a region covering approximately 38,000 square miles, which is approximately 65% of the land area in the State of Georgia, encompassing 151 of the State's 159 counties. Historically, our members' sales by customer class have been approximately two-thirds to residential consumers and slightly less than one-third to commercial and industrial consumers. Our members are the principal suppliers for the power needs of rural Georgia. While our members do not serve any major cities, portions of their service territories are in close proximity to urban areas and have experienced substantial growth over the years due to the expansion of urban areas, including metropolitan Atlanta, into suburban areas and the growth of suburban areas into neighboring rural areas. Each year we file an exhibit containing financial and statistical information for our 38 members for the most recent three year period with one of our quarterly reports onfirst or second quarter Form 10-Q.20152021 through 2017,2023, and also shows the amount of their energy requirements that we supplied. From 20152021 through 2017,2023, peak demand of the members and their energy requirements have fluctuated based on various factors, including milder weatherfactors. In August 2023, our member system hit a new summer peak demand of 10,088 megawatts. In December 2022, our member system hit its overall peak demand of 10,810(4)megawatts, eclipsing our members' prior peak of 10,018 megawatts achieved in 2015 and 2017. In 2016, the amount of energy we supplied to the members increased nearly 40%, primarily as a result of the use of Smith Energy Facility to meet the members' energy requirements, as well as an increase in total member requirements.Member Energy Requirements (MWh) 2023 10,088 41,370,456 28,289,147 2022 42,175,373 25,634,984 2021 9,284 39,701,458 24,727,600
Member Energy Requirements (MWh) Member Peak
Demand (MW) Supplied by Oglethorpe(3) Total(1) Total(2) 2017 8,716 37,880,696 23,813,679 2016 9,194 39,668,000 25,522,852 2015 8,964 38,323,141 18,371,558 We supplied none of Flint's energy requirements in 2015 but began supplying energy to Flint in 2016. Also includes energy we supplied to our own facilities.
(4)System peak hour demand measured at our generating resources was 11,077 megawatts and system peak hour demand measured at our members' delivery points was 10,810 megawatts.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. Since 1973, thehas allowedallows limited competition among electric utilities in Georgia by allowing the owner of any new facility located outside of municipal limits and having a connected load upon initial full operation of 900 kilowatts or greater to receive electric service from the retail supplier of its choice. Georgia is projected to experience significant load growth over the next several years. Our members, with our support, are actively engaged in competition with other retail electric suppliers for thesea significant amount of new commercial and industrial loads. The number of commercial and industrial loads served by our members continues to increase annually. While the competition for 900-kilowatt loads represents onlyThis limited competition in Georgia, this competition has given our members and us the opportunity to develop resources and strategies to operate in an increasingly competitive market.–Competition.– Competition."–Wholesale– Wholesale Power Contracts." The assets and revenues of our members are, however, pledged under their respective mortgages with the Rural Utilities Service or loan documents with other lenders. President's budget for fiscal year 2019,2024, which beginsbegan October 2018, proposes2023, includes a loan program level of $5.5 billion, the same as the current program level. Although Congress has historically rejected proposals to dramatically curtail or redirect the Rural Utilities Service loan program, there can be no assurance that it will continue to do so. Because of these factors, we$6.5 billion. We cannot predict the amount or cost of Rural Utilities Service loans that may be available to the members in the future. For additional information regarding the Rural Utilities Service, see "OGLETHORPE POWER CORPORATION – Relationship with Federal Lenders –Rural Utilities Service."see"OGLETHORPEsee "OGLETHORPE POWER CORPORATION – Relationship with Georgia System Operations Corporation."2017,2023, we supplied approximately 63%68% of the retail energy requirements of our members. Pursuant to the wholesale power contracts, we supply each member energy from our generation resources based on its fixed percentage capacity cost responsibility, which are take-or-pay obligations. See "OGLETHORPE POWER CORPORATION – Wholesale Power OurIn 2017,At January 1, 2024, the aggregate SEPA allocation of capacity to the members was 618570 megawatts plus associated energy. The availability of energy under these contracts is significantly affected by hydrologic conditions, including lengthy droughts. Each member must schedule its energy allocation, and each member, other than Flint EMC, has designated us to perform this function. Pursuant to a separate agreement, we schedule, through Georgia System Operations, 37 of our members' SEPA power deliveries. Further, each member may be required, if certain conditions are met, to contribute funds for capital improvements for U.S. Army Corps of Engineers projects from which its allocation is derived in order to retain the allocation.728733 megawatts. The 35 members participating in these two facilities purchase the output of those facilities pursuant to separate take-or-pay power purchase agreements that will continue until terminated by one year's written notice by Smarr EMC or the respective member.119756 megawatts of solar, low-impact hydroelectric, landfill gas and wood-waste biomass facilities, with an additional 80 megawatts under contract and solar facilities,under construction, with plans to purchase more in the future. Included in this total is energy purchased from Green Power Solar, a for-profit subsidiary of Green Power EMC, which has leased, with an option to purchase, 8 megawattstwelve solar facilities with a total of solar facilities.Georgia Energy Cooperative Fifteen of our members are members of Georgia Energy Cooperative, An Electric Membership Corporation, which owns a 100 megawatt gas turbine facility and also provides other services to its members.Thirty-oneAll members are parties to requirements contracts with third parties for some or all of their incremental power needs. The other members use a portfolio of short-term and long-term power purchase contracts tothat meet their incremental requirements. These requirements contracts and long-term power purchase contracts have remaining terms ranging from 52 to 2417 years. These other purchases include 156 megawatts from solar facilities under long-term contracts.and"OURand "OUR POWER SUPPLY RESOURCES – Future Power Resources." In addition to future power supply resources that we may construct or acquire for our members, the members will likely also continue to acquire future resources from other suppliers, including suppliers that may be owned by members.variousa wide range of federal, state and local environmental laws. Air emissions, solid waste disposal, effluent water discharges, and water usage are extensively controlled, closely monitored, and periodically reported. The manner in which various types of wastes can be stored, transported and disposed is also broadlycomprehensively regulated.stringent.prescriptive and stringent, and the Environmental Protection Agency, or EPA, intends to finalize a number of rules in 2024 that could impact our power plants. Although we have installed an extensive array of environmental control systems at our plants to ensure continued compliance with all existing applicable requirements, including systems to reduce emissions of sulfur dioxide, nitrogen oxides, mercury and other regulated air pollutants, at Plants Scherer and Wansley, new environmental regulatory requirements could be imposed. Such additional requirements, mayif adopted, could substantially increase the cost of electric service by requiring modifications in the design or operation of existing facilities.facilities and making new facilities more difficult to site and more expensive to build. Failure to comply with these requirements could result in us becoming subject to enforcement actions and the assessment of civil and criminal penalties andpenalties. In extreme cases of non-compliance, such enforcement actions could even include the complete shutdown of individual generating units not in compliance.units. Certain of our debt instruments also require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to comply with these requirements, it would constitute a default under those debt instruments. Although it is our intentwe intend to comply with all current and future regulations, we cannot provide assuranceguarantee that we will always be in compliance.standards.requirements and regulations. For further discussion of expected future capital expenditures to comply with environmental requirements and regulations, see"MANAGEMENT'Ssee "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS –Financial– Financial Condition –Capital Requirements –Capital Expenditures."concerns ofregulations adopted at the public, the scientific communityfederal and government officialsstate levels have resulted in legislation and regulation that has had and will continue to have a significant impact on the electric utility industry. The most significant environmental legislationregulations for us continuescontinue to be the air regulatory requirements imposed under the Clean Air Act, which regulatesAct. These requirements include stringent regulations for controlling emissions of sulfur dioxide, nitrogen oxides, particulate matter, mercury, greenhouse gases, and other air pollutants from affected electric utility units, including the coal-fired units at Plants Scherer and Wansley.units. The Environmental Protection Agency, or EPA has actively regulated emissions under the Clean Air Act and the following are the most significant ongoing Clean Air Act-related actionsAct regulatory requirements that affect or may affect our business. Regulatory Reform. Through a series of Executive Orders, the Trump Administration is requiring many federal agencies, including EPA, to review their regulations and make recommendations regarding the repeal, replacement or modification of certain regulations. Regulations that (i) adversely affect jobs, (ii) are outdated, unnecessary or ineffective, (iii) impose costs exceeding benefits or (iv) interfere with regulatory reform initiatives and policies are to be identifiedfurther action. Pursuant to an Executive Order entitled "Promoting Energy Independence and Economic Growth," EPA has undertaken a number of actions to reconsider and in some cases repeal existing regulations. Where appropriate, reference to such actions are made in the context of the specific regulatory programs discussed below. We cannot predict EPA's actions regarding these regulatory reforms or the effects from any litigation that may result from this extensive effort. National AmbientMeeting Air Quality Standards and Nonattainment Updates.Standards. common air pollutants: particulate matter, ground-level ozone, carbon monoxide, sulfur dioxide, nitrogen dioxide and lead. EPA will periodicallyis required to review the variousexisting NAAQS every five years to determine whether anya tightening of these standards shouldis necessary to protect public health. On February 6, 2024, EPA published a final rule that lowered the current annual particulate matter (PM2.5) standard from 12 parts per billion (ppb) down to 9 ppb but retained the existing 24-hour standards for certain particulate matter. This more stringent standard is likely to place additional geographic regions into nonattainment and could affect future siting decisions for new generation, as well as impose additional costs and potential operating restrictions. However, such regulatory determinations will not be made for several more stringent. In 2015, EPA lowered NAAQS for ground-level ozoneyears. We are reviewing the final rule, but at this time, it is too early to determine the extent to which, if any, EPA’s proposed tightening of the PM2.5 standard, if adopted, might have on Plant Scherer and Georgia submitted its proposed designations, recommending that only eight counties be designated nonattainment, with the remainder classified as attainment or unclassifiable. Nonattainment is defined as havingour gas-fired generating units.worse thanstandards, the NAAQS as defined in the Clean Air Act and amendments of 1990. Late in 2017, EPA concurred with Georgia's recommendations and plans to formally propose such designations for Georgia later this year. Oncenew finalized Georgia must revise its State Implementation Plan (SIP) to demonstrate attainment.Measures taken could affect sources located within the designated eight counties or sources in surrounding counties if those emissions are deemed to contribute to the nonattainment status of this new Atlanta ozone nonattainment area. In 2017, EPA redesignated to attainment all of the counties that were part of the 2008 eight-hour Atlanta ozone nonattainment area. EPA also took action in 2017 to designate nonattainment areas for other NAAQS, such as the 2010 one-hour SO2 NAAQS, where all counties in Georgia except Floyd County were designated as attainment/unclassifiable, and the nitrogen dioxide NAAQS, where EPA proposed no further changes to the standards. While our coal-fired plants have installed control systems for the current suite of NAAQS, the implementation of new orany future revised NAAQS could lead to additional complianceemissions reduction requirements. The costsCosts of any additional or upgraded pollution control equipment or operating restrictions that could be required because of new or revisedmore stringent NAAQS cannot be determined at this time. Cross State Air Pollution Rule. To address the interstate transport of ozone and fine particulate matter, EPA finalized the Cross State Air Pollution Rule (CSAPR) in 2011, imposing cap and trade programs for sulfur dioxide and nitrogen oxides emissions on fossil fuel-fired electric generating units located in twenty-eight states, including Georgia. EPA has adopted specific trading programs to address these emissions and Georgia is subject to three distinct CSAPR trading programs. Currently,time, neither can we believe that sufficient controls have been installeddetermine such impacts on our units, including the co-owned units at Plants Scherer and Wansley, such that compliance with the current CSAPR, including all allowance programs, can be maintained. Mercury and Air Toxics Standards and State Mercury Rule. In December 2011, EPA finalized its Mercury and Air Toxics Standards (MATS), which established maximum achievable control technology limits for certain hazardous air pollutants at coal and oil-fired electricor natural gas-fired generating units. For coal units, the rule sets stringent emission limits to control various hazardous air pollutants such as mercury, non-mercury metals and acid gases and work practice standards to control organics and dioxins. Our affected generating units, which include our co-owned units at Plants Wansley and Scherer, must comply with MATS. In 2015, the U.S. Supreme Court ruled that EPA must consider costs before finalizing MATS and remanded the rule back to EPA for further rulemaking consistent with its opinion. In 2016, EPA released a supplemental finding that it is appropriate and necessary to regulate hazardous air pollutants from coal and oil-fired electric generating units, and that MATS is reasonable. Cases challenging this determination are pending in the U.S. Circuit Courtcontrolsemission control systems currently installed at PlantsPlant Scherer and Wansleyour natural gas-fired generating units are generally sufficient to meet the air quality requirements described above. However, the regulation of air emissions has been and is expected to continue to be fluid and additional emissions reduction requirements could be imposed on major sources within Georgia, including at our power plants, to remedy any local and interstate transport air quality problems. Subsequent developments, including litigation and thenew implementation approaches selectedadopted by EPA and Georgia could require significant capital expenditures and increased operating expenses at certain of our generating facilities, particularly Plants Scherer and Wansley. Several of the Obama Administration's actions to limit carbon dioxide emissions have been curtailed by the Trump Administration. Some of the actions that could potentially have a direct effect on our operations are summarized below. 10.99.9 million shortmetric tons in 2017, as2023. Compared to 2005, our overall carbon dioxide emissions rate has declined by 43% through a combination of market factors, our commitment to running highly efficient units with lower carbon dioxide emissions rates and retirement of Plant Wansley in 2022. From coal alone, our carbon dioxide emissions in 2023 declined by 67% compared to 12.9 million short tons in 2016.2005. After the U.S. Supreme Court ruled in 2007 that certain greenhouse gases, including carbon dioxide, are pollutants which EPA has the authority to regulate under the Clean Air Act, EPA determined that regulation was needed. Beginning in 2009,On July 8, 2019, EPA issued a series of rules that apply the final Affordable Clean Air Act Prevention of Significant Deterioration and Title V permitting programsEnergy (ACE) rule to stationary source emissions of greenhouse gases. In 2015, EPA published a series of rules, known asrepeal the Clean Power Plan (CPP), which was one of the most significant regulatory actions to reduce greenhouse gas emissions. In the CPP, EPA established New Source Performance Standards (NSPS)and adopt a replacement rule for new, modified or reconstructed fossil fuel-fired electric generating units. For existing fossil fuel-fired electric generating units, EPA established guidelines for the states to follow in developing final NSPS for such units. Those guidelines became uniform national emission rates for existing units that states were required to incorporate into state rules and performance standards. A lynchpin of the CPP was EPA's interpretation that it could establish emissions guidelines beyond the fence line of regulated sources and require system-wide reductions inregulating carbon dioxide emissions from source owners and operators. In 2016, the U.S. Supreme Court stayed the CPP pending resolution of litigation challenging the CPP inexisting affected coal-fired electric generating units. On June 30, 2022, after the U.S. Court of Appeals for the DistrictD.C. Circuit vacated and remanded the ACE rule back to EPA, the U.S Supreme Court in West Virginia v. EPA reversed the D.C. Circuit ruling and, in so doing, limited EPA's authority to regulate greenhouse gas emissions as broadly as the Clean Power Plan. EPA has since initiated a rulemaking to replace the ACE rule.Columbia Circuit includingour coal and natural gas-fired generating units and have a significant impact on the U.S. power sector overall. EPA recently announced that it would not include existing gas turbines in the final rule. Instead, EPA indicated that it would address existing gas turbines in a future rulemaking. The ultimate impact of the proposed rules, and a future rule related to existing gas turbines, will depend on the final rules adopted by EPA and the results of any appeallitigation challenging the rules and cannot be determined at this time. EPA is expected to release final rules, excluding existing gas turbines, in spring 2024.Supreme Court. That litigation has been delayedParis Climate Agreement, to which President Biden recommitted the United States effective February 2021. The United States subsequently announced a nationally determined contribution under the agreement for reducing domestic carbon dioxide emissions by EPA, pending reconsideration50-52% below 2005 economy-wide levels by 2030. In order to meet this target, analyses have indicated that the power sector would have to reduce carbon dioxide emissions by about 80% below 2005 levels by 2030. These nationally determined contributions could lead to a wide range of legislative and regulatory actions to help achieve the CPP rule.October 2017,addition, President Biden continues to direct federal agencies to address climate change, environmental justice, and other environmental issues. As a result, as discussed above, EPA proposed a rule to repeal the CPP, in large part on the revised interpretation that emission guidelines for affected existing sources are limited to the steps source owners and operators can take at the regulated source. In December 2017, EPA also issued an Advance Notice of Proposed Rulemaking seeking information on the steps existing sources could take that would be consistent withadditional regulatory actions to require more stringent control requirements to reduce carbon dioxide and other emissions under its existing legal authority. At this revised interpretation. EPA may take other actions in the future to address the emissions of greenhouse gases from our units. For example, EPA may seek to revisit and perhaps reconsider its NSPS for new and modified fossil fuel-fired electric generating units. Wetime, we cannot predict the outcome of any legislative or regulatory changes agency actions, including but not limited toor the withdrawal or revisionresult of guidance, or executive orders related to climate change, nor can we predict the outcome or effect of possiblepotential litigation resulting fromchallenging any of these actions. In November 2015, the Paris Agreement was adopted at the United Nations 21st International Climate Change Conference. It established a non-binding universal framework for addressing greenhouse gas emissions based on nationally determined commitments as well as a process for increasing those commitments going forward. On June 1, 2017, President Trump announced that the U.S. would cease all participation in the 2015 Paris Agreement, stating that the accord would undermine the U.S. economy and put it at a permanent disadvantage. We are unable to determine the ultimate impact of this action on our operations or costs.Steam Electric Power Generating Effluent Limitations Guidelinespublishedestablished a comprehensive regulatory program to manage the disposal of coal combustion residuals (CCR) rule to regulate CCRs from electric utilitiescoal-fired power plants as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act.Act (RCRA). The 2015 CCR rule containssets forth requirements for structural integrity assessments, groundwater monitoring, location siting, composite lining, inactive units, closure and post closure, beneficial use recycling, design and operating criteria, recordkeeping, notification, and internet posting for new and existing CCR landfills, CCR surface impoundments and lateral expansions of CCR disposal facilities. In March 20182022 and 2023, the EPA publishedissued a number of proposed ruledeterminations on requests for extensions of time to updateclose ash ponds. The proposed determinations could affect the 2015 CCR rule. A final ruleGeorgia Environmental Protection Division's (EPD) review of the proposed closure plans for the coal ash ponds at Plants Wansley and Scherer. EPA's proposed determinations subsequently were challenged in the U.S. Court of Appeals for the D.C. Circuit in April 2022, and a decision is expected later in 2018. the near future. We are currently reviewing those proposed determinations to better understand how they may impact our closure plans. However, the ultimate impact of EPA's actions is unknown at this time and subject to the outcome of the litigation and any future EPA and Georgia regulatory actions.applyapplies to certain wastewater discharges from fossil fuel-fired steam electric power plants, including our co-owned Plants WansleyScherer and Scherer. Wansley. Since adopting the CCR and ELG rules, EPA has adopted revisions to the compliance deadlines and substantive requirements of the two rules. However, on March 29, 2023, EPA issued a proposed supplemental ELG rule for steam electric generating units that, if finalized, generally would increase the stringency of the current standards. The ultimate impact of the proposed rule will depend on the final rule adopted by EPA and the results of any litigation challenging the rule and cannot be determined at this time. EPA is expected to release a final ELG rule in spring 2024.postponedextended the ELG compliance deadlines set forth in the 2015 ELG rule to meet discharge limitations for scrubber wastewater and bottom ash transport water from affected coal-fired units, including Plants Scherer and Wansley to November 1, 2020. On November 22, 2019, EPA issued a proposed rule to moderate the discharge limitations on these two wastestreams and subsequently published a final ELG reconsideration rule on October 13, 2020.The ELG rule extends the applicability date for scrubber waste water and bottom ash transport water to December 31, 2025, and allows for various subcategories based on planned future operations, including the rule's voluntary incentives program, low utilization, and early retirement of affected units. Units participating in any of the subcategories were required to submit a notice of planned participation.compliance dates relatedregulatory requirements, and the notices reserved the right to transfer subcategories if circumstances change.effluent limitations guidelines. rule that are currently in the U.S. Court of Appeals for the Fourth Circuit. However, the litigation is being held in abeyance as EPA undertakes the supplemental rulemaking mentioned above. A final rule could affect our compliance approach. However, the impact and ultimate outcome of the ELG rule cannot be determined at this time. and in response to EPA's CCR rulemaking, the Georgia Environmental Protection Division added specific provisions forEPD adopted new requirements to regulate CCR wastes to its existing solid waste management rules.wastes. These new rules containincorporated EPA's CCR rule requirements as well as furtherstate-only requirements for managing CCR wastes in Georgia. The additionalThese state requirements were implemented and are administeredenforced through a state permit system. Citizen groups retain the authoritysystem that was approved by EPA in December 2019. Once CCR permits are issued by Georgia EPD, federal citizen suits under RCRA to enforce federal CCR requirements. At this point,requirements incorporated in the state permit are generally no longer allowed and permit challenges will be handled through EPD's existing administrative process. Georgia's existing CCR regulations are not anticipated to have a material impact on our compliance obligations under the federal CCR rule. However, we cannot predict the impact of any future changes to theGeorgia's CCR regulations including potential legislation or the effluent limitations guidelines.litigation.2015,2019, Georgia Power announced that it is preparing a scheduleceased sending CCR to close existingthe ash ponds at all of its Georgia coal-fired facilities, including at our co-owned Plants Scherer and Wansley. In 2016,Similarly, Georgia Power further announcedhas installed a new wastewater treatment system that it would cease sendingwill receive and manage the non-CCR wastestreams at Scherer. As a result, these new closure deadlines have not impacted our operations. Although no litigation related to CCR to all of its ash ponds inregulations is now pending, we cannot predict whether there will be any future lawsuits on the requirements for closing these impoundments or remedying any impacts the impoundments may be having on groundwater.within three years. It also announced that it wouldPower applied for CCR permits to close the ash ponds at Plants Scherer and Wansley in place using advanced engineering methodsmethods. However, in March 2022, Georgia Power notified the Georgia Public Service Commission of a revised closure proposal for Plant Wansley. Georgia Power’s modified closure plan at PlantsPlant Wansley recommends closure by removing the ash from the coal ash pond for several site-specific reasons, including available capacity at an existing on-site landfill due to the retirement of Plant Wansley in August 2022, beneficial use of the coal ash, and Scherer, among other locations. The initialmanaging construction and operational risks of its current closure in place design. Georgia Power’s proposed closure plans and any future revisions are subject to the approval of the Georgia Public Service Commission and EPD. Costs associated with the closure of ash ponds are reflected in the asset retirement obligations discussed below and we routinely update our asset retirement obligations to reflect any future changes in compliance requirements or cost projections. Georgia Power filed with the Georgia Environmental Protection Division estimatedestimates closing activities to be completed in 20262032 for Plantboth Plants Wansley and 2031Scherer.Plant Scherer.extensions of time to close ash ponds. The proposed determinations include the agency’s rationale and current position on closure standards, groundwaterestimatedestimates for capital expenditures for the settlement of related asset retirement obligations are approximately $173 million for the closure and post-closure of existing coal ash ponds. See Note 1 of Notes to Consolidated Financial Statements. In addition, preliminary estimates suggest that our capital expendituresat Plant Scherer to comply with the applicable CCR rulerequirements and effluent discharge limitations guidelines willare estimated to be approximately $273$230 million for conversion to dry ash handling, landfill construction, and wastewater treatment. This estimate includes $170 million that has already been spent. Additionally, our current estimated expenditures for the settlement of related asset retirement obligations at our operating and retired coal plants are approximately $600 million to $800 million (in year of expenditure dollars) for the closure and post-closure of existing coal ash ponds and the dry coal ash and gypsum storage areas. Approximately $50 million of this amount has already been incurred. See Note 1 of Notes to Consolidated Financial Statements. More definitive cost estimates will continue to be developed as the processprocesses of rule evaluation, compliance approach and design and construction implementation proceeds.proceed. The ultimate impacts associated with the federal and state CCR rules and the federal effluent discharge limitations, guidelines, any changes EPA may make to those rules,revised regulation or legislation at the state or federal level and any related litigation challenging such rules, or future legislation cannot be determined at this time. In 2008, the Georgia legislature adopted a comprehensive State Water Plan that lays out statewide policies, management practices and guidance for regional water planning in Georgia. In 2011, the Georgia Environmental Protection Division adopted regional water plans that were developed pursuant to the State Water Plan. Regional plans include resource assessments, estimates of current and future water needs and management practices. Updated draft regional water plans have been developed and were issued for public notice and comment in 2017. Georgia will consider the information contained in regional water plans (including any updated plans) when making water use permitting decisions under existing state law. The state water planning process may lead to new or revised regulations for water users in the future. Because power generation is generally dependent on water usage, the regional water plans and any future regulations or other enforceable requirements developed in connection with the State Water Plan may have substantial effects on the operations of our facilities or future facilities that we construct or acquire. The impacts of future regulations or revisions to regional water plans on our facilities or future facilities cannot be determined at this time.rule.rule and followed that proposal with a supplemental proposed rule in June 2018. The first step replacesreplaced the 2015 regulations that defined waters of the U.S. with those that were in effect prior to the 2015 rule. In the second step, EPA states that it will pursueproposed a formal rulemaking to substantively re-evaluaterule in December 2018 replacing the 2015 definition with a revised definition that clarifies and narrows the scope of federal authority under the Clean Water Act. A final rule incorporating the proposed rules was issued on January 23, 2020. The EPA and may substantially revise that rule. WeArmy Corps of Engineers subsequently revised the definition of waters of the U.S. in January 2023. However, in May 2023, the U.S. Supreme Court narrowed the definition of waters of the U.S., leading EPA and Army Corps of Engineers to issue a final rule on August 29, 2023, amending its definition to conform to the U.S. Supreme Court's decision. While there is minimal direct impact to our operations as a result of the current rule, we cannot determine the ultimate impact of the 2015 rule, any change to that rule or any litigation challenging thatvarious iterations of the rule or any replacement rule at this time.to the regulations implementing these environmental statutes. We do not believe that our compliance obligations with these statutesstatutory and regulationsregulatory requirements will have a material impact on our financial condition or resultsoperation of operations.our facilities. Changes to any of these laws, however, could affect many areas of our operations. Although compliance with new environmental legislation could have a significant impact on those operations, such impacts cannot be fully determined at this time and would depend in part on the final legislation and the development of implementing regulations.position,condition or results of operations or cash flows.causeeven force the complete shutdown of individual generating units not in compliance with these regulations.regulations in some cases. Any additional federal or state environmental restrictions imposed on our operations could result in significant additional compliance costs, including capital expenditures. Such costs could affect future unit retirement and replacement decisions and may result in significant increases in the cost of electric service. The cost impact of future legislation, regulation, judicial interpretations of existing laws or regulations, or international obligations will depend upon the specific requirements thereof and cannot be determined at this time.each unit of PlantsPlant Hatch Units No. 1 and VogtleNo. 2 expire in 2034 and 2038, respectively, and for Plant Vogtle Units No. 1, No. 2, No. 3 and No. 4 expire in 2047, 2049, 2062 and 2049,2063, respectively.–Future– Future Power Resources –Plant Vogtle Units No. 3 and No. 4." Existing2026.2026, and we are currently in the process of relicensing the project. Consistent with Federal Energy Regulatory Commission regulations, we submitted a draft license application for stakeholder review in November 2023 and anticipate making a timely application for a new license for the Rocky Mountain project in 2024. See "PROPERTIES –Generating– Generating Facilities" and "–" – The Plant Agreements –Rocky Mountain" for additional information. Uponmaycould either take over the project or relicense the project to us. Additionally, the Federal Energy Regulatory Commission may relicense the project either to the original licensee or toCommission's grant of a new licensee. In the event of takeover or relicensinglicense to another, the original licensee is tous could be compensated in accordance with the provisions of the Federal Power Act, such compensation to reflect the net investment of the licensee in the project, not in excess of the fair value of the property taken, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property taken. The Federal Energy Regulatory Commission may grant relicenses subject to certain requirements that could result in additional costs. If the Federal Energy Regulatory Commission does not act on the new license application prior to the expiration of the existing license, the commission is required to issue annual licenses, under the same terms and conditions of the existing license, until a new license is issued. We anticipate making a timely application for a new license for the Rocky Mountain project.the most significantmaterial risks, in management'smanagement’s view, that may affect our business and financial condition or the value of our debt securities. This discussion is not exhaustive, and there may be other risks that we face which are not described below. The risks described below, as well as additional risks and uncertainties presently unknown to us or currently not deemed significant,material, could negatively affect our business operations, financial condition and future results of operations. development and construction of Vogtle Units No. 3 and No. 4 could have a material impact on our financial condition and results of operations.Further, no nuclear plants have reached commercial operation using advanced designs, such as the Westinghouse AP1000 design, and therefore estimating the total cost of construction and the related schedule is inherently uncertain. We also rely on Georgia Power and Southern Nuclear as our agents for the oversight of the construction of the additional units at Plant Vogtle and do not exercise direct control over the construction process. Our current project budget for the additional Vogtle Units, which includes capital costs, allowance for funds used during construction and a contingency amount, is $7.0 billion and we expect Vogtle Units No. 3 and No. 4 to be placed in service by November 2021 and November 2022, respectively. Our $7.0 billion budget is net of payments we received from Toshiba under the Guarantee Settlement Agreement. Certain events have materially delayed the original commercial operation dates and increased the original project budget. The most significant of these relate to Westinghouse's filing for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code and its subsequent rejection of the substantially fixed price EPC Agreement. On January 11, 2018, the Georgia Public Service Commission entered an order regarding a series of actions related to Vogtle Units No. 3 and No. 4 that the Public Service Commission approved on December 21, 2017. Among other actions, the Public Service Commission (i) accepted Georgia Power's recommendation that construction of Vogtle Units No. 3 and No. 4 be completed, with Southern Nuclear serving as construction manager and Bechtel as primary contractor and (ii) approved the revised schedule placing Unit No. 3 in service in November 2021 and Unit No. 4 in service in November 2022. In its January 11, 2018 order, the Public Service Commission stated if certain assumptions upon which Georgia Power's recommendations were based do not materialize, both the Public Service Commission and Georgia Power reserve the right to reconsider the decision to continue construction. Parties have filed two petitions in Fulton County Superior Court for judicial review of the Public Service Commission's January 11, 2018 order. Georgia Power has stated that it believes these appeals have no merit; however, an adverse outcome in one or both of these appeals could have a material impact on our financial condition and results of operations. As construction continues, we remain subject to construction risks and no longer have the benefit of the substantially fixed price EPC Agreement which means that we and the other Co-owners are responsible for all construction costs based on our ownership percentages. Factors that could lead to further cost increases and schedule delays or even the inability to complete this project include:•performance by Georgia Power as agent for the Co-owners and performance by Southern Nuclear as construction manager;•performance by Bechtel under the Bechtel Agreement as well as subcontractor and supplier performance, including compliance with the design specifications approved and quality standards set forth by the Nuclear Regulatory Commission;•changes in labor costs and productivity;•performance by Westinghouse under the Services Agreement;•loss of access to intellectual property rights necessary to construct or operate the project;•shortages and/or inconsistent quality of equipment, materials and labor;•increases in our cost of debt financing as a result of changes in market interest rates or as a result of construction schedule delays;•unforeseen engineering or design problems;•erosion of public and policymaker support;•liens on the project;•contract disputes;•permits, approvals and other regulatory matters;•unanticipated increases in the costs of materials;•changes in project design or scope;•impacts of new and existing laws and regulations, including environmental laws and regulations;•adverse weather conditions; and•work stoppages. On November 2, 2017, the Co-owners amended the Joint Ownership Agreements to provide that holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction upon the occurrence of certain adverse events. As we are a 30% owner in the Vogtle project, we, along with Georgia Power and the Municipal Electricity Authority of Georgia, will all need to determine to move forward with the Vogtle project upon the occurrence of any of those adverse events. In the event the Co-owners determine not to proceed with the project following such an event, our proportionate share of the Co-owners' cancellation costs are estimated to be approximately $230 million. As of December 31, 2017,2023, our total investment in the additional Vogtle units was approximately $2.9$8.2 billion. Vogtle Unit No. 3 entered commercial operation July 31, 2023.net of payments we received from Toshiba under the Guarantee Settlement Agreement. If the projectand is cancelled, we would seek regulatory accounting treatment to amortize our investmentbased on a commercial operation date in the Vogtle project oversecond quarter of 2024 for Unit No. 4. Any schedule extension beyond June 2024 for Unit No. 4 is expected to increase our costs by approximately $20 million per month.long-term period which would require the approval of our board of directors and the Rural Utilities Service. As construction continues, risks remain that construction-related challenges, including management of contractors, subcontractors and vendors, labor productivity and availability, fabrication, delivery, assembly and installation of plant systems, structures and components, or other issues could further impact the projected schedule and cost. Aspects of the Westinghouse AP1000 design are based on new technologies and commercial operation of this design has yetregular basis to be tested. There have also been technical and procedural challenges to the construction and licensing of these units and additional challenges at the federal and state level may arise. Processes are in place that are designed to assure compliance with the requirements specifiedincorporate current information available, particularly in the Westinghouse Design Control Documentareas of start-up testing and the combined constructionrelated test results and operating licenses, including inspections byengineering support.and the Nuclear Regulatory Commissionannounced that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission. Various design and other licensing-based compliance matters, including the timely resolution ofall Unit No. 4 inspections, tests, analyses, and acceptance criteria bydocumentation had been submitted to the 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 be loaded and start-up testing to begin. Fuel load was completed on August 19, 2023. On October 6, 2023, Georgia Power announced that during start-up and pre-operational testing for Unit No. 4, Southern Nuclear had identified a motor fault in one of four reactor coolant pumps, which was replaced. With Unit No. 3’s four reactor coolant pumps operating as designed, Southern Nuclear has stated that it believes that the motor fault on the single Unit No. 4 reactor coolant pump is an isolated event. However, any findings on the root cause of the motor fault on the affected pump could require engineering changes or remediation related to the other Unit No. 3 and Unit No. 4 reactor coolant pumps.construction proceeds,Unit No. 4 moves further into testing and start-up, which may result in additional license amendmentsrequired engineering changes or require other resolution. If any license amendment requestsremediation related to plant systems, structures or other licensing-based compliance issuescomponents (some of which are not resolved in a timely manner, there may be further delaysbased on new technology that only within the last several years began initial operation in the project schedule that couldglobal nuclear industry at this scale). These challenges may result in increased costsfurther schedule delays and/or cost increases. Further delays into the summer months of 2024 could also require that our members acquire replacement power, potentially at a higher cost, for the power anticipated to the Co-owners.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.a loanEnergyEnergy.up to $3.1$4.6 billion of eligible project costs through 2020. Ascosts. Based on our current budget for Vogtle Units No. 3 and No. 4, we anticipate seeking $750 to $800 million of December 31, 2017, we had advanced $1.7 billion under this loan. Access to the committed funds under this loan requires us to meet certain conditions related to our business and the Vogtle project and also requires certain third parties related to the Vogtle project to comply with certain laws. We are currently unable to make advances from the remaining $1.4 billion of committed funds under our loan guarantee agreement with the Department of Energy and will not be able to make additional advances until we enter into an amendment to the loan guarantee agreement. While not assured, we expect to satisfy these conditions in the second quarter of 2018. Prolonged inability to accesslong-term funding pursuant to the Department of Energy loan guarantee agreement may constrain our liquidity and lead us to finance certain expenditures through alternative resources, likely at a higher interest rate. In addition, the occurrence of certain adverse events would give the Department of Energy discretion to require that we repay all amounts outstanding under the loan guarantee agreement over a five-year period. In the event that we are unable to draw the full amount of this loan or are required to repay amounts outstanding over a five year period, we expect that we would finance those project expenditures in the capital markets which would likely be at a higher cost. We have received a conditional commitment from thethrough 2024, including approximately $400 to $500 million to refinance Department of Energy for approximately $1.6 billionEnergy-guaranteed loans that mature before the in-service date of additional loan guarantees for eligible project costs. This conditional commitment expires on June 30, 2018, subject to any extension approved by the Department of Energy. Final approval and issuance of the additional loan guarantee by the Department of Energy cannot be assured and is subject to negotiation of definitive agreements, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of other conditions. See Note 7a of Notes to Consolidated Financial Statements for additional information about the loan guarantee agreement and related conditions.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 couldwould 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.lenders'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:economic downturns or recessions;
negative events in the energy industry, such as the bankruptcy of an unrelated energy company or the occurrence of a significant natural disaster;•terrorist attacksongoing capital expenditures or future acquisitions could be limited and our financial condition and future results of operations could be adversely affected.Ourparticularly in relation to the additional units under construction at Plant Vogtle, are projected tomay be significant and will continue to increase our debt, which is constraininghas constrained certain of our financial metrics and may also adversely affect our credit ratings, which would likely increase our borrowing costs and could decrease our access to capital. In order to meetenergy needs of our members, we are in 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 $7.0 billion,4 and our investment as of December 31, 20172023 was $2.9 billion, net$8.2 billion. Since 2021, we have also acquired three natural gas resources and expect to acquire a fourth in the second quarter of payments received from Toshiba under the Guarantee Settlement Agreement.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, 2017,2023, we had $8.2$12.1 billion of long-term debt outstanding, an increase of $3.9$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 $11.5$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. Beginning in 2009, inathis 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 20182024 our board of directors again approved a margins for interest ratio of 1.14.futurenew or stricter environmental laws and regulations, including those designed to address air and water quality, greenhouse gas emissions, including carbon dioxide,coal combustion residuals and other matters, may result in significant increases in compliance costs or operational restrictions.facilities. Through 2017, we have spent approximately $1.1 billion on capital expenditures at our facilities or operating restrictions.achieve and maintain compliance with Georgia's "multi-pollutant rule" and EPA's MATS, two air quality control regulations that have had a significant impact on our business to date. In addition, we spent approximately $80 million in 2017 on capital expenditures related to coal ash handling and effluent limitation guidelines, and expect to spend approximately $196 million infinalize several proposed rules over the near future. Although the current administration has relaxed certain federal regulations, potential future legislation or regulations,course of 2024, including those relating tofor greenhouse gas emissions, including carbon dioxide, or renewable or clean energy may create new requirements and operational hurdles.emissions. More stringent or new standards maycould require us to modify the design or operation of existing facilities and could result in significant increases in the cost of electricity or decreases in the amount of energy (due to operational constraints) providedwe provide to our members. Two examples of current and potential regulations are discussed below. The EPA has determined that carbon dioxide and other greenhouse gases are regulated pollutants underthe Clean Air Act. As a result of this determination, in October 2015 the EPA published final rules regarding emissions of carbon dioxide from certain fossil fuel-fired electric generating units. One of the rules, referred to as the "Clean Power Plan," established guidelines for states to develop plans to limit emissions of carbon dioxide from certain existing fossil fuel-fired electric generating units. The guidelines and standards set forth in the Clean Power Plan could impose future operational restrictions and substantial costs on our coal-fired units. In February 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan pending the resolution of litigation challenging the rule. In October 2017, the EPA proposed a rule to rescind the Clean Power Plan and the related guidelines and in December 2017, EPA published an advance notice of proposed rulemaking regarding a replacement rule for the Clean Power Plan. It is likely that any action by the EPA to rescind all or part of the Clean Power Plan will be challenged. If the Clean Power Plan is not ultimately rescinded and survives litigation challenging the rule, we anticipate that some of the policy approaches it sets forth could have significant negative consequences for the economy and electric system in Georgia and the nation. In the event that the Clean Power Plan is rescinded, we expect that efforts to limit the emissions of greenhouse gases, including carbon dioxide, will continue. The timing, cost and effect of any future laws or regulations attempting to reduce greenhouse gas emissions are uncertain; however, certain laws or regulations could impose substantial costs on our business and operational restrictions on certain of our generating facilities, particularly our coal-fired units.publishedissued a final rule to regulate coal combustion residuals from electric utilities as solid wastes. We and Georgia Power has announced thathave proposed closure plans for our co-owned coal ash ponds at eachto the Georgia EPD. Georgia Power’s proposed closure plans have been approved by the Georgia Public Service Commission but remain subject to EPD approval, and we cannot predict when they will be approved or whether either closure plan will require modifications. Costs associated with the closure of its Georgia coal-fired facilities, including our co-owned facilities, will cease receiving new coal ash by early 2019 and that closure activities for the ash ponds at Plants Wansley and Scherer are initiallyreflected in the asset retirement obligations discussed below. If Georgia's requirements for coal ash disposal are subsequently revised or the proposed closure plans are not approved, our estimated 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 continue to review the ultimate cost of this rule on our co-owned coal facilities.compliance costs could increase materially. In September 2015, the EPA also finalized a rule to revise the effluent limitations guidelinesELG that apply to certain wastewater discharges from nuclear and fossil fuel-fired steam electric power plants. The 2015 ELG rule was later revised in October 2020. Then, in March 2023, EPA proposed a supplemental ELG rule that would increase the stringency of the current standards. We estimate our total cost for compliance withare investing in facility upgrades to meet the coal combustion residuals rule and effluent limitations guidelines, and estimate our total capital cost for compliance at Plant Scherer to be approximately $273$230 million of capital costs plus an additional $173which $170 million had been spent as of costs associated withDecember 31, 2023. Expenditures for the settlement of related asset retirement obligation liabilities."BUSINESS –REGULATION – “BUSINESS —REGULATION—Environmental."We own”participating in the constructionsubject to risk of nuclear facilitiesfailure, loss of access or cybersecurity breaches which give risecould affect our ability to environmental, regulatory, financialoperate and other risks. We own a 30% undivided interest in Plant Hatch and Plant Vogtle, each of which is a two-unit nuclear generating facility, and which collectively account for approximately 18% of our generating capacity and 42% of our energy generated during 2017. Our ownershipinterests in these facilities expose us to various risks, including:•potential liabilities relating to harmful effects on the environmentlitigation, regulatory action and human health and safety resulting from the operation of these facilities and the on-site storage, handling and disposal of radioactive materials, including spent nuclear fuel;•uncertainties with respect to the technological and financial aspects of and the ability to maintain and anticipate adequate capital reserves for decommissioning these facilities at the end of their operational lives;•significant capital expenditures relating to maintenance, operation, security and repair of these facilities, including repairs or modifications required by the Nuclear Regulatory Commission;•potential liabilities arising out of nuclear incidents caused by natural disasters, terrorist attacks, cyber security attacks or otherwise, including the payment of retrospective insurance premiums, whether at our own plants or the plants of other nuclear owners; and•uncertainties with respect to the off-site storage and disposal of spent nuclear fuel in the event that on-site storage is not sufficient. 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 are collecting for and maintain an internal fund and an external trust fund to pay for the estimated cost of decommissioning our existing nuclear facilities. If the values of the investments in the funds significantly decrease or the anticipated decommissioning costs significantly increase, it is possible that decommissioning costs and liabilities could exceed the amount of these funds and we would have to collect additional revenue from our members to pay the excess costs. In addition to our ownership of existing nuclear units, we are participating with the other Co-owners of Plant Vogtle in the construction of two additional nuclear units at the Plant Vogtle site. See "BUSINESS –OUR POWER SUPPLY RESOURCES – Future Power Resources –Plant Vogtle Units No. 3 and No. 4."We could be adversely affected if we or third parties operating certain of our co-owned facilities are unable to continue to operate our facilities in a successful manner. The operation of our generating facilities may be adversely impacted by various factors, including:•the risk of equipment and information technology failure or operator error;•operating limitations that may be imposed by environmental or other regulatory requirements;•physical or cyber attacks against us or key suppliers or service providers;•interruptions in fuel, water or material supplies;•transmission constraints or disruptions;•compliance with electric reliability organizations' mandatory reliability and record keeping standards, including mandatory cyber security standards;•the ability to maintain a qualified workforce;•an environmental event, such as a spill or release;•labor disputes; or•catastrophic events such as fires, earthquakes, floods, droughts, hurricanes, explosions, pandemic health events such as influenzas or similar occurrences.orand those of our co-owned plants, could be directly or indirectly affected by deliberate or unintentional cyber incidents. If our technology systemsintrusion,incident, we have comprehensive cyber security programs designed to protect and 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. A severe drought could reduce the availability of water and restrict or prevent the operation of certain generating facilities. Other negative events such as those discussed above could also interrupt or limit electric generation or increase the cost of operating our facilities, which could have the effect of increasing the cost of electric service we provide to our members and affect their ability to perform their contractual obligations to us. Further, a significant percentage of our energy is generated at co-owned facilities that are operated by Georgia Power and Southern Nuclear. We rely on these third parties for the continued operation of these facilities to avoid potential interruptions in service from these facilities. If these third parties are unable to operate these facilities, the cost of electric service we provide to our members, or the cost of replacement electric service, may increase. See "BUSINESS –OGLETHORPE POWER CORPORATION – Relationship with Georgia Power Company" and "PROPERTIES – Co-Owners of Plants" and "– Plant Agreements" for discussions of our relationship with Georgia Power and our co-owned facilities.Changes in fuel prices could have an adverse effect on our cost of electric service. We are exposed to the risk of changing prices for fuels, including natural gas, coal and uranium. 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 recent depression in domestic natural gas prices, natural gas prices have historically been more volatile than other fuel sources and stable pricing cannot be assured. Further, the availability of shale gas and potential regulations affecting its accessibility may have a material 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 may not be able to obtain an adequate supply of fuel, which could limit our ability to operate our facilities. 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 or other factors affecting our fuel suppliers, could result in us having insufficient levels of fuel supplies. For example, 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 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.ChangesDistributedRenewable 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, that may besome of which are capable of producing or storing electric power at costs that are comparable with, or lower than, our cost of generating power. Incentives for renewable energy generation to facilitate the transition to lower-carbon energy sources included in the Inflation Reduction Act could accelerate the adoption and deployment of such technologies. If these technologies were to develop sufficient economies of scale and be broadly adopted in our members'members’ service territories, it could adversely affect our ability to recover the fixed costs related to and the value of our generating facilities and significantly increase the cost of electric service we provide to our members and affect their ability to perform their contractual obligations to us.The operational life of some of our generating facilities exposes us to potential costs to continue to meet efficiency, reliability and environmental compliance standards. Many of our generating facilities were constructed more than 30 years ago and, even if maintained in accordance with good engineering practices, will require significant capital expenditures in order to maintain efficient and reliable operation. Potential operational issues associated with the age of the plants may lead to unscheduled outages, a generating facility being out of service for an extended period of time, or other service-related interruptions. Further, maintaining compliance with applicable efficiency, reliability and environmental standards may require significant capital expenditures or operating reductions at certain of our facilities and we may determine to reduce or cease operations at those facilities in order to avoid such capital expenditures or to meet such standards. These expenditures and service interruptions could have the effect of increasing the cost of electric service we provide to our members and, as a result, could affect our members' ability to perform their contractual obligations to us. natural gas, power sales and purchases and co-owner agreements.purchases. Many of these transactions expose us to the risk that our counterparty may fail to perform its contractual obligations.our counterparties'a counterparty’s failure to perform theirits contractual obligations under the applicable agreementsagreement could impact the project cost and schedule and potentially project completion.We cannot predict the outcome of any current or future legal proceedings related to our business activities. From time to time we are subject to litigation from various parties. Our business, financial condition, and results of operations may be materially affected by adverse results of certain litigation. Unfavorable resolution of legal proceedings in which we are involved or other future legal proceedings could require significant expenditures that may increase the cost of electric service we provide to our members and, as a result, affect our members' ability to perform their contractual obligations to us.Our ability to meet our financial obligations could be adversely affected if our members fail 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 growthand power supply needs. 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 any payment default pursuant to a pro rata step-up formula, there can be no guarantee that the non-defaulting members would be able to fulfill this obligation.investors'investors’ ability to trade our debt securities may be limited by the absence of an active trading market and there is no assurance that any trading market will develop or continue to remain active.
Unit No. 1 Unit No. 2 Unit No. 1 Unit No. 2 Unit No. 1 Unit No. 2 Combustion Turbine Unit No. 1 Unit No. 2 Units No. 1-4 Units No. 5-6 Unit No. 1 Unit No. 2 Unit Plant Hatch Unit No. 1 Unit No. 2 Plant Vogtle Unit No. 1 Unit No. 2 Plant Wansley Unit No. 1 Unit No. 2 Combustion Turbine(4) Plant Scherer Unit No. 1 Unit No. 2 Rocky Mountain(5) Unit No. 1 Unit No. 2 Unit No. 3 Doyle(5) Talbot(5) Chattahoochee Hawk Road(5) Hartwell(5) Smith Unit No. 1 Unit No. 2 TOTAL supply. Co-Owners of Plants Oglethorpe Georgia Power MEAG Dalton Total among Georgia Power, MEAG, 2. equal to the percentage of its undivided interest which is owned or leased in such plant or unit. Georgia Power is required to furnish budgets for operating costs, fuel plans and scheduled maintenance plans. In the case of Scherer Units No. 1 and No. 2, the participants have limited rights to disapprove such budgets proposed by Georgia Power and to substitute alternative budgets. The Ownership Agreements and Operating Agreements provide that, should a participant fail to make any payment when due, among other things, such nonpaying participant's rights to output of capacity and energy would be suspended. STATEMENTS OF REVENUES AND EXPENSES DATA Operating revenues: Sales to Members Sales to non-Members Total operating revenues Operating expenses: Fuel Production Depreciation and amortization Purchased power Accretion Deferral of Hawk Road and Smith Energy Facilities effect on net margin Total operating expenses Operating margin Other income, net Net interest charges Net margin BALANCE SHEET DATA Electric plant, net: In service Nuclear fuel, at amortized cost Construction work in progress Total electric plant Total assets Capitalization: Long-term debt Obligations under capital leases Obligations under Rocky Mountain transactions Patronage capital and membership fees Accumulated other comprehensive (gain) loss Subtotal Less: long-term debt and capital leases due within one year Less: unamortized debt issuance costs Less: unamortized bond discounts on long-term debt Total capitalization Cash paid for property additions OTHER DATA Energy supply (megawatt-hours): Generated Purchased Available for sale Member revenues per kWh sold Despite increased interest rates in 2023, strategic financing and refinancing of capital investments with long-term debt through the Department of Energy and Rural Utilities Service loan guarantee programs, taxable and tax-exempt capital markets offerings enabled us to borrow long-term debt at relatively low rates and our weighted average interest cost on long-term debt was 3.89% per annum at December 31, 2023. We will continue to actively manage our debt portfolio and utilize advantageous borrowing programs available to us as our ability to borrow at lower costs ultimately benefits our members and their customers as interest savings are reflected in our pass-through rate structure. cost-protections agreed to under the Global Amendments, retained our 30% interest in the additional Vogtle units and achieved additional cost-protections by which Georgia Power will pay 66% of our 30% share of incremental construction costs that exceed $19.2 billion. commitments. related estimates and assumptions with the audit committee of our board of directors. participate. Variable costs are passed through to our members state agency or authority, including the Georgia Public Service Commission. acquisition. arrangements, which account for approximately a in 2022 than in 2021. 2021. generation from the other nuclear plants. Vogtle Unit No. 4. Capacity revenues Energy revenues Total kWh Sales Cents/kWh Member energy requirements supplied Capacity revenues Fuel Source Coal Nuclear Natural Gas: Combined Cycle Combustion Turbine Financial Condition outstanding. See "– relationship with the Department of Energy and Rural Utilities Service. 2023. Unsecured Facilities: Syndicated Line among 13 banks led by CFC CFC Line of Credit(2) December 2018 JPMorgan Chase Line of Credit October 2018 Secured Facilities: CFC Term Loan(2) and backing up commercial paper. As of December 31, 2023, the amount of certified bondable additions and retired or defeased first mortgage indenture obligations available for the issuance of additional first mortgage indenture obligations was approximately $3.1 billion. In addition, as of December 31, 2023, we had over $780 million of property additions and certified progress payments under qualified engineering, procurement and construction contracts that, once certified in accordance with the first mortgage indenture, will be available for the issuance of additional first mortgage indenture obligations. outstanding. All of the debt advanced under the loan guarantee agreement is secured ratably with all other debt under our first mortgage indenture. For additional information regarding total of approximately $486 million in principal on these loans by April 2024. We plan to refinance a portion of the principal repaid before the in-service date of Vogtle Unit No. 4 by issuing first mortgage bonds before the end of 2024. 2022. In 2023, we borrowed $70.3 million under various Rural Utilities Service-guaranteed loans for general and environmental improvements. Capital Expenditures(1) (dollars in millions) Future Generation(2) Existing Generation(3) Environmental Compliance(4) Nuclear Fuel(5) General Plant Total Contractual Obligations (dollars in millions) Long-Term Debt: Principal(1) Interest(2) Capital Leases(3) Operating Leases Rocky Mtn.Lease Transaction(4) Chattahoochee O&M Agmts. Asset Retirement Obligations(5) Purchase Commitments(6) Total Credit Rating Risk Long-term ratings: Senior secured rating Rating outlook Short-term rating: Commercial paper rating specified levels, could result in increased interest rates. Also, borrowing rates, letter of credit fees and commitment fees in two of our repricing in February 2025. and 2.5% of our total debt classified as intermediate-term fixed rate. The remaining 91.2% of our debt was classified as long-term fixed rate. our various projects. Notes to Consolidated Financial Statements. these funds would be approximately $19.1 million. 2025, respectively. Consolidated Balance Sheets, at December 31, Consolidated Statements of Patronage Capital and Membership Fees Operating revenues: Sales to Members Sales to non-Members Total operating revenues Operating expenses: Fuel Production Depreciation and amortization Purchased power Accretion Deferral of Hawk Road and Smith Energy Facilities effect on net margin Total operating expenses Operating margin Other income: Investment income Amortization of deferred gains Allowance for equity funds used during construction Other Total other income Interest charges: Interest expense Allowance for debt funds used during construction Amortization of debt discount and expense Net interest charges Net margin The accompanying notes are an integral part of these consolidated financial statements. Net Margin Other comprehensive margin: Unrealized loss on available-for-sale securities Amounts reclassified to regulatory assets Total comprehensive margin The accompanying notes are an integral part of these consolidated financial statements. Assets Electric plant: In service Less: Accumulated provision for depreciation Nuclear fuel, at amortized cost Construction work in progress Total electric plant Investments and funds: Nuclear decommissioning trust fund Investment in associated companies Long-term investments Restricted investments Other Total investments and funds Current assets: Cash and cash equivalents Restricted short-term investments Receivables Inventories, at average cost Prepayments and other current assets Total current assets Deferred charges and other assets: Regulatory assets Prepayments to Georgia Power Company Other Total deferred charges Total assets The accompanying notes are an integral part of these consolidated financial statements. Equity and Liabilities Capitalization: Patronage capital and membership fees Accumulated other comprehensive deficit Long-term debt Obligations under capital leases Other Total capitalization Current liabilities: Long-term debt and capital leases due within one year Short-term borrowings Accounts payable Accrued interest Member power bill prepayments, current Other current liabilities Total current liabilities Deferred credits and other liabilities: Asset retirement obligations Member power bill prepayments, non-current Contract retainage Regulatory liabilities Other Total deferred credits and other liabilities Total equity and liabilities Commitments and Contingencies (Notes 1, 7, 10, 11 and 12) The accompanying notes are an integral part of these consolidated financial statements. Secured Long-term debt: First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.84% to 8.43% (average rate of 4.02% at December 31, 2017) due in quarterly installments through 2043 First mortgage notes payable to the Federal Financing Bank at interest rates varying from 2.51% to 3.87% (average rate of 3.36% at December 31, 2017) due in quarterly installments through 2044 First mortgage notes payable to National Rural Utilities Cooperative Finance Corporation at interest rates varying from 4.55% to 4.90% (average rate of 4.69% at December 31, 2017) due in quarterly installments through 2020 First mortgage bonds payable: • Series 2006 • Series 2007 • Series 2009A • Series 2009B • Series 2009 • Series 2010A • Series 2011A • Series 2012A • Series 2014A • Series 2016A First mortgage notes issued in connection with the sale of pollution control revenue bonds through the Development Authorities of Appling, Burke, Heard and Monroe Counties, Georgia: • Series 2003A Burke, Heard, Monroe and 2003B Burke • Series 2004 Burke and Monroe • Series 2005 Burke and Monroe • Series 2008A through 2008C Burke • Series 2008E Burke • Series 2009A Heard and Monroe, and 2009B Monroe • Series 2010A Burke and Monroe, and 2010B Burke • Series 2013A Appling, Burke and Monroe • Series 2017A Burke, Heard, Monroe and 2017B Burke • Series 2017C, D Burke • Series 2017E, F Burke CoBank, ACB notes payable: • Transmission first mortgage notes payable: variable, paid in full January 2017 • Transmission first mortgage notes payable: variable, paid in full January 2017 Total Secured Long-term debt Obligations under capital leases Obligation under Rocky Mountain transactions Patronage capital and membership fees Accumulated other comprehensive (deficit) Subtotal Less: long-term debt and capital leases due within one year Less: unamortized debt issuance costs Less: unamortized bond discounts on long-term debt Total capitalization The accompanying notes are an integral part of these consolidated financial statements. Cash flows from operating activities: Net margin Adjustments to reconcile net margin to net cash provided by operating activities: Depreciation and amortization, including nuclear fuel Accretion cost Amortization of deferred gains Allowance for equity funds used during construction Deferred outage costs Deferral of Hawk Road and Smith Energy Facilities effect on net margin (Gain) loss on sale of investments Regulatory deferral of costs associated with nuclear decommissioning Other Change in operating assets and liabilities: Receivables Inventories Prepayments and other current assets Accounts payable Accrued interest Accrued and withheld taxes Other current liabilities Member power bill prepayments Total adjustments Net cash provided by operating activities Cash flows from investing activities: Property additions Guarantee settlement proceeds Activity in nuclear decommissioning trust fund – Purchases – Proceeds Increase in restricted investments Decrease (increase) in restricted short-term investments Activity in other long-term investments – Purchases – Proceeds Other Net cash used in investing activities Cash flows from financing activities: Long-term debt proceeds Long-term debt payments Increase (decrease) in short-term borrowings, net Other Net cash (used in) provided by financing activities Net increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period Supplemental cash flow information: Cash paid for – Interest (net of amounts capitalized) Supplemental disclosure of non-cash investing and financing activities: Change in asset retirement obligations Change in accrued property additions Interest paid-in-kind The accompanying notes are an integral part of these consolidated financial statements. Balance at December 31, 2014 Components of comprehensive margin in 2015 Net margin Unrealized loss on available-for-sale securities Total comprehensive margin Balance at December 31, 2015 Components of comprehensive margin in 2016 Net margin Unrealized loss on available-for-sale securities Total comprehensive margin Balance at December 31, 2016 Components of comprehensive margin in 2017 Net margin Amounts reclassified to regulatory assets Total comprehensive margin Balance at December 31, 2017 1. Summary of significant accounting policies: generation resources. each fiscal year. For the years members were as follows: Jackson EMC Cobb EMC Sawnee EMC $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. receivables that arose from contracts with members or non-members. Balance at December 31, 2016 Liabilities settled Accretion Change in cash flow estimates Balance at December 31, 2017 Balance at December 31, 2015 Liabilities settled Accretion Change in cash flow estimates Balance at December 31, 2016 Nuclear Decommissioning. the estimated costs of decommissioning co-owned nuclear facilities 2015 site study Expected start date of decommissioning Estimated costs based on site study in 2015 dollars: Radiated structures Spent fuel management Non-radiated structures Total estimated site study costs 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. funds in 2023 and 2022, respectively. a diversified mix of approximately External Trust Funds: Equity Debt Other Total Internal Funds: Equity Debt Total External Trust Funds: Equity Debt Other Total Internal Funds: Equity Debt Total Steam production Nuclear production Hydro production Other production Transmission General In 2023, depreciation expense increased by $42,595,000 compared to 2022 primarily due to Plant Vogtle Unit No. 3 achieving commercial operation in July 2023. In 2021, the composite depreciation rate for Plant Wansley was increased in anticipation of the plant’s retirement in 2022. In addition to the depreciation expense recognized in 2022 and 2021, $165,013,000 and $204,891,000, respectively, of Plant Wansley’s depreciation expense was deferred. Subsequent to the retirement of Plant Wansley, we amortized $25,900,000 and $8,120,000 of deferred depreciation expense in 2023 and 2022, respectively. See Note 1q for information regarding regulatory assets and liabilities. l. Cash and cash equivalents At December 31, 2022, we had restricted investments totaling $74,031,000, all of which were classified as current. During the three-month period ended March 31, 2023, we utilized all of our restricted investments for scheduled Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. No restricted investments were held at December 31, 2023. other deferred charges. For a discussion regarding regulatory assets, see Note 1q. Other deferred charges primarily represent the fair value of our natural gas contracts that will settle after the next twelve months and other long-term prepayments. 1q. will be applied in the future to reduce revenues required to be recovered from members. Regulatory Assets: Premium and loss on reacquired debt(a) Amortization on capital leases(b) Outage costs(c) Asset Retirement Obligations – Ashpond and other(k) Depreciation expense(d) Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(e) Interest rate options cost(f) Deferral of effects on net margin – Smith Energy Facility(g) Other regulatory assets(l) Total Regulatory Assets Regulatory Liabilities: Accumulated retirement costs for other obligations(h) Deferral of effects on net margin – Hawk Road Energy Facility(g) Major maintenance reserve(i) Amortization on capital leases(b) Deferred debt service adder(j) Asset retirement obligations – Nuclear(k) Other regulatory liabilities(l) Total Regulatory Liabilities Net regulatory assets Capital credits from associated companies (Note 4) Net revenue from Georgia Transmission and Georgia System Operations for shared Administrative and General costs Miscellaneous other Total t. credit losses. financial instruments are those whose fair value is based on significant unobservable inputs. Nuclear decommissioning trust funds: Domestic equity International equity trust Corporate bonds and debt US Treasury securities Mortgage backed securities Domestic mutual funds Municipal bonds Federal agency securities Other Long-term investments: International equity trust Corporate bonds and debt US Treasury securities Mortgage backed securities Dometic mutual funds Federal agency securities Other Natural gas swaps Nuclear decommissioning trust funds: Domestic equity International equity trust Corporate bonds and debt US Treasury securities Mortgage backed securities Municipal bonds Federal agency securities Other Long-term investments: International equity trust Corporate bonds and debt US Treasury securities Mortgage backed securities Domestic mutual funds Federal agency securities Other Natural gas swaps Long-term debt The estimated fair value of long-term debt is classified as Level 2 and is natural gas. Our risk management and compliance committee provides general oversight over all Realized gains and losses on natural gas swaps are included in fuel expense within our consolidated statements of revenues and expenses and, therefore, net margins within our consolidated statements of cash flows. Year 2018 2019 2020 2021 2022 Total The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at December 31, Assets Natural gas swaps Natural gas swaps Liabilities Natural gas swaps Natural gas swaps The following table presents the realized gains and (losses) on derivative instruments recognized in margin for the years ended December 31, Consolidated 2017 2016 2015 Natural Gas Swaps Natural Gas Swaps Total The following table presents the unrealized Natural Gas Swaps Natural Gas Swaps Interest Rate Options Total 2017 Equity Debt Other Total 2016 Equity Debt Other Total The contractual maturities of debt securities, Due within one year Due after one year through five years Due after five years through ten years Due after ten years Total The following table summarizes the realized gains and losses and proceeds from sales of securities for the years ended December 31, Gross realized gains Gross realized losses Proceeds from sales Investment in associated companies National Rural Utilities Cooperative Finance Corporation (CFC) CT Parts, LLC Georgia Transmission Corporation Georgia System Operations Corporation Other Total The CFC investments consist of capital term certificates required in connection with our membership in CFC and a voluntary investment in CFC member capital securities. Accordingly, there is no market for these 2028. $13,901,000. interest in Rocky Mountain to the owner trust, the owner trust has several options it can elect, including: Statutory federal income tax rate Patronage exclusion AMT credit monetization Other Effective income tax rate The components of our net deferred tax assets and liabilities as of December 31, Deferred tax assets Net operating losses Tax credits (alternative minimum tax and other) Accounting for Rocky Mountain transactions Other assets Deferred tax assets Less: Valuation allowance Net deferred tax assets Deferred tax liabilities Depreciation Accounting for Rocky Mountain transactions Other liabilities Deferred tax liabilities Net deferred tax liabilities Less: Patronage exclusion Net deferred taxes Expiration Date 2018 2019 2020 patronage exclusion. Year Ending December 31, 2018 2019 2020 2021 2022 2023-2031 Total minimum lease payments Less: Amount representing interest Present value of net minimum lease payments Less: Current portion Long-term balance bonds. FFB FMBs PCBs(1) CFC Capital Leases Total The weighted average interest rate on our long-term debt at December 31, The weighted average interest rate on our short-term borrowings at December 31, 2023 and 2022 was 5.72% and 4.84%, respectively. FFB FMBs PCBs CFC CoBank We use the effective interest rate method to amortize debt issuance costs and debt discounts as well as the straight-line method when the results approximate those of the effective interest rate method. Unamortized debt issuance costs and debt discounts are being amortized to expense over the life of the respective debt issues. Department of Energy agreed to guarantee our obligations under be re-borrowed. If we receive proceeds from an event of condemnation relating to Vogtle Units No. 3 and No. 4, such proceeds must be applied to immediately prepay outstanding borrowings under the Facility. plants and the BC Smith acquisition. 6.20% first mortgage bonds, Series 2023A, for the purpose of providing long-term financing for expenditures related to the construction of Vogtle Units No. 3 and No. 4. In conjunction with the issuance of the bonds, we repaid $390,612,000 of outstanding commercial paper. The are scheduled to mature in 2045. Our payment obligations related to these bonds are secured under our first mortgage indenture. Plant In-service(1) Owned property Vogtle Units No. 1 & No. 2 Vogtle Units No. 3 & No. 4 Hatch Units No. 1 & No. 2 Wansley Units No. 1 & No. 2 Scherer Unit No. 1 Doyle(Combustion Turbine - 100% ownership) Rocky Mountain Units No. 1, No. 2 & No. 3 Hartwell(Combustion Turbine - 100% ownership) Hawk Road(Combustion Turbine - 100% ownership) Talbot(Combustion Turbine - 100% ownership) Chattahoochee(Combined cycle - 100% ownership) Smith(Combined cycle - 100% ownership) Wansley(Combustion Turbine – 30% ownership) Transmission plant Other Property under capital lease: Scherer Unit No. 2(Fossil – 60% leasehold) Total in-service Construction work in progress Vogtle Units No. 3 & No. 4(2) Environmental and other generation improvements Other Total construction work in progress expenses. costs. November 1, 2028. up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted. We started purchasing this coverage in April 2023. $55 million. The maximum aggregate that NEIL will pay for all claims resulting from cyber acts and cyber events in any 12-month period is $3.2 billion each, plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. 2018 2019 2020 Thereafter To supply a portion of the fuel requirements to our co-owned generating units, Georgia Power, on our behalf for coal and Southern Nuclear on our behalf for nuclear fuel, $70,699,000. 2018 2019 2020 2021 2022 Thereafter 12. Contingencies and Regulatory Matters: 2017 Operating revenues Operating margin Net margin 2016 Operating revenues Operating margin Net margin served by the member. After the nominating committee nominates a candidate for a director position, the candidate must be elected by a majority vote of all of our member representatives, voting on an unweighted, one-member, one-vote basis. If the nominated candidate fails to receive a majority of the vote, the nominating committee must nominate another candidate and the member representatives will vote on Mr. Smith co-founded and served as the Executive Director of the Committee of Chief Risk Officers. From 1997 to 2002, Mr. Smith held multiple positions at Mirant Corporation, most recently as Vice President and Global Risk Officer. From 1994 to 1997, he was Manager of Planning and Evaluation for Vastar Resources and prior to that he worked at ARCO in various positions from 1983 to 1994. Mr. Smith has a Bachelor's degree in Business Law and a Masters of Business Administration in Finance from Louisiana State University. Mr. Smith is on the board of directors for Ms. Higgins is a member of the Rotary Club of Atlanta, the International Women’s Forum and Leadership Atlanta. She serves on the board of directors for Voices for Georgia’s Children and represents Oglethorpe on the Metro Atlanta Chamber board of advisors. She also serves on the advisory board of FM Global, one of our property insurers, and the CFO Forum Atlanta. She has volunteered as a mentor with Pathbuilders, a development program for high potential women, since 2017. Georgia State University. Management. Association in 2017 and 2018. directors since March 2016, and his present term will expire in March Commerce. directors. Corporation since May 2002. He is also the Secretary of Georgia Energy Cooperative. South Jenkins Volunteer Fire Department. Horace Weathersby. Mr. For a discussion regarding our cybersecurity risk oversight, see "CYBERSECURITY". goals achieved. executive officers is consistent with the coverage we provide to our employees generally. performance objectives that are used to determine performance pay amounts. He and our vice president, human resources present these goals to the compensation committee. The compensation committee then reviews and approves the goals and presents them to the board of directors for final approval. procedures and reducing workplace hazards for both our employees and contractors. oversight involvement, understanding of the project status and project issues, and timeliness and usefulness of project communications to our members and our board of directors. Our president and chief executive officer will assign a score based on his assessment of the overall effectiveness of our management of the project and submit the score to the construction committee of our board of directors for approval. Other components measure construction progress at the Vogtle project as well as construction projects that we directly oversee, and we measure completion in a timely manner and within project budget. Total Michael L. Smith Michael W. Price Elizabeth B. Higgins William F. Ussery James D. Messersmith Our employment agreement with Mr. Smith extends through December 31, be payable to Mr. Smith in the circumstances described above is 2023. Summary Compensation Table For an explanation of the criteria and formula used to determine the awards listed above, please refer to "– Compensation Discussion and Analysis – The following table sets forth contributions for the fiscal year ended December 31, 2023. committee is charged with monitoring compliance with this policy and making recommendations to the board of directors regarding this policy. Certain actions or relationships that might give rise to a conflict of interest are reviewed and approved by our board of directors. Financial Statements (Included under "Financial Statements and Supplementary Data") Consolidated Balance Sheets, As of December 31, Financial Statement Schedules None applicable. Exhibits marked with an asterisk (*) are hereby incorporated by reference to exhibits previously filed by the Registrant as indicated in parentheses following the description of the exhibit.which are in commercial operation.Facilities Type of
FuelPercentage
InterestOur Share of
Nameplate
Capacity
(megawatts)Commercial
Operation
DateLicense
Expiration
DatePlant Hatch (near Baxley, Ga.) Unit No. 1 Nuclear 30 269.9 1975 2034 Unit No. 2 Nuclear 30 268.8 1979 2038 Plant Vogtle (near Waynesboro, Ga.) Unit No. 1 Nuclear 30 348.0 1987 2047 Unit No. 2 Nuclear 30 348.0 1989 2049 Unit No. 3 Nuclear 30 363.3 2023 2062 Plant Scherer (near Forsyth, Ga.) Unit No. 1 Coal 60 490.8 1982 N/A (1) Unit No. 2 Coal 60 490.8 1984 N/A (1) Rocky Mountain (near Rome, Ga.) Pumped Storage Hydro 74.61 632.5 1995 2026 (2) Doyle (near Monroe, Ga.) Gas 100 325.0 2000 N/A (1) Talbot (near Columbus, Ga.) Units No. 1-4 Gas 100 412.0 2002 N/A (1) Units No. 5-6 Gas-Oil 100 206.0 2003 N/A (1) Chattahoochee (near Carrollton, Ga.) Gas 100 468.0 2003 N/A (1) BC Smith (near Savannah, Ga) Gas 100 597.0 2003 N/A (1) Washington County (near Sandersville, Ga) Unit No. 2 Gas 100 198.9 2003 N/A (1) Unit No. 3 Gas 100 198.9 2003 N/A (1) Hawk Road (near Franklin, Ga.) Gas 100 500.0 2001 N/A (1) Hartwell (near Hartwell, Ga.) Gas-Oil 100 300.0 1994 N/A (1) Baconton (near Baconton, Ga.) Unit 500 Gas-Oil 100 58.9 2000 N/A (1) TA Smith (near Dalton, Ga.) Unit No. 1 Gas 100 630.0 2002 N/A (1) Unit No. 2 Gas 100 620.0 2002 N/A (1) Facilities Type of
Fuel Percentage
Interest Our Share of
Nameplate
Capacity
(MW) Commercial
Operation Date License
Expiration Date Plant Hatch (near Baxley, Ga.) Nuclear 30 269.9 1975 2034 Nuclear 30 268.8 1979 2038
Plant Vogtle (near Waynesboro, Ga.)
Nuclear 30 348.0 1987 2047 Nuclear 30 348.0 1989 2049
Plant Wansley (near Carrollton, Ga.)
Coal 30 259.5 1976 N/A (1) Coal 30 259.5 1978 N/A (1) Oil 30 14.8 1980 N/A (1)
Plant Scherer (near Forsyth, Ga.)
Coal 60 490.8 1982 N/A (1) Coal 60 490.8 1984 N/A (1)
Rocky Mountain (near Rome, Ga.)
Pumped Storage Hydro
74.61
632.5
1995
2026
Doyle (near Monroe, Ga.)
Gas
100
325.0
2000
N/A
(1)
Talbot (near Columbus, Ga.)
Gas 100 412.0 2002 N/A (1) Gas-Oil 100 206.0 2003 N/A (1)
Chattahoochee (near Carrollton, Ga.)
Gas
100
468.0
2003
N/A
(1)
Hawk Road (near Franklin, Ga.)
Gas
100
500.0
2001
N/A
(1)
Hartwell (near Hartwell, Ga.)
Gas-Oil
100
300.0
1994
N/A
(1)
Smith (near Dalton, Ga.)
Gas 100 630.0 2002 N/A (1) Gas 100 620.0 2002 N/A (1)
(2)We intend to submit an application to extend this license in 2024.facilities:Unit 2023 2022 2021 2023 2022 2021 Plant Hatch Unit No. 1 262.2 97 % 90 % 93 % 98 % 91 % 94 % Unit No. 2 264.3 87 97 90 88 98 90 Plant Vogtle Unit No. 1 344.5 90 99 92 92 101 94 Unit No. 2 344.7 92 91 100 94 93 103 335.1 0 Plant Scherer Unit No. 1 515.0 98 78 95 45 38 26 Unit No. 2 515.0 94 93 85 15 15 18 Unit No. 1 272.3 97 91 77 17 16 14 Unit No. 2 272.3 90 96 75 17 20 18 Unit No. 3 272.3 89 76 76 14 10 11 273.1 80 84 81 2 4 2 679.2 76 75 77 8 10 5 Chattahoochee 484.5 90 67 94 82 59 73 500.0 90 77 89 56 55 72 326.0 93 100 1 0 486.9 67 63 65 11 16 10 6 305.5 66 73 79 6 9 6 44.5 75 15 TA Smith Unit No. 1 647.3 94 92 94 75 68 69 Unit No. 2 647.3 93 94 92 77 71 69 TOTAL 7,792.0 Summer
Planning
Reserve
Capacity(1) Equivalent
Availability(2) Capacity Factor(3) (Megawatts) 2017 2016 2015 2017 2016 2015 262.2 95 % 90 % 98 % 95 % 91 % 99 % 264.3 92 98 89 93 98 90
344.5 92 100 90 93 102 91 344.7 95 94 99 97 95 100
261.6 95 96 81 9 11 3 261.6 95 79 97 4 5 2 0 41 39 61 0 0 0
515.0 71 99 82 23 55 55 515.0 96 85 97 52 48 60
272.3 97 25 88 18 6 18 272.3 77 97 95 16 24 18 272.3 78 99 74 17 16 10
341.0
55
69
82
1
4
1
682.3
77
77
76
5
11 ��
6
458.0
91
83
89
82
74
69
486.9
83
69
74
10
18
7
301.1
80
57
81
3
1
1
630.0 86 89 79 57 60 45 630.0 86 90 83 59 56 30 7,115.1 20182024 capacity reserve planning.that a unit wasis available to generate if called upon, adjusted for periods when the unit is derated from its rated capacity. For 2015 and beyond, the plants operated by us and Siemens exclude periods when units are derated due to events classified under NERC guidelines as "Outside Management Control."The Wansley combustion turbine is used primarily for emergency service and is rarely operated except for testing.(5)Hartwell,Baconton, primarily operate as peaking plants, which results in low capacity factors. Due to low gas and market prices relative to the costsee"MANAGEMENT'Ssee "MANAGEMENT'S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS –Results– Results of Operations –Operating Expenses." Coal for Plant Wansley is purchased in spot market transactions. As of February 28, 2018, we had a 44-day coal supply at Plant Wansley based on continuous operation. Plant Wansley burns bituminous coal purchased primarily from coal mines in the Illinois Basin. Coal for Scherer Units No. 1 and No. 2 is purchased under term contracts and in spot market transactions. As of February 28, 2018,29, 2024, our coal stockpile at Plant Scherer contained a 39-day45-day supply based on continuous operation. Plant Scherer burns sub-bituminous coal purchased from coal mines in the Powder River Basin in Wyoming.separately dispatch Plant Wansley andour interest in Plant Scherer, but use Georgia Power as our agent for fuel procurement. We currently lease approximately 1,200 rail cars713 railcars to transport coal. Over the past few years, we have managed rail-related delays in connection with our coal to these two facilities. We are assessing our future railcar needs and evaluating our leasing options. long-term firm and short-term firm and non-firm contracts. See "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK – Commodity Price Risk." Wansley and Scherer Units No. 1 and No. 2 are co-owned by Georgia Power, the Municipal Electric Authority of Georgia,MEAG, the City of Dalton and us, and Rocky Mountain is co-owned by Georgia Power and us. Each co-owner owns or leases undivided interests in the amounts shown in the following table, which excludes the Plant Wansley combustion turbine.table. We are the operating agent for Rocky Mountain. Georgia Power is the operating agent for each of the other plants.Nuclear Coal-Fired Pumped
StoragePlant Hatch Plant Scherer Units
No. 1 & No. 2Rocky Mountain Total % % % % Oglethorpe 30.0 539 30.0 1,059 60.0 982 74.6 633 3,213 Georgia Power 50.1 900 45.7 1,614 8.4 137 25.4 215 2,866 MEAG 17.7 318 22.7 802 30.2 494 — — 1,614 Dalton 2.2 39 1.6 56 1.4 23 — — 118 Total 100.0 1,796 100.0 3,531 100.0 1,636 100.0 848 7,811 Nuclear Coal-Fired Pumped Storage
Plant Hatch
Plant Vogtle
Plant Wansley Plant Scherer Units No. 1 & No. 2
Rocky Mountain
Total % MW(1) % MW(1) % MW(1) % MW(1) % MW(1) MW(1) 30.0 539 30.0 696 30.0 519 60.0 982 74.6 633 3,369 50.1 900 45.7 1,060 53.5 926 8.4 137 25.4 215 3,238 17.7 318 22.7 527 15.1 261 30.2 494 – – 1,600 2.2 39 1.6 37 1.4 24 1.4 23 – – 123 100.0 1,796 100.0 2,320 100.0 1,730 100.0 1,636 100.0 848 8,330 the Municipal Electric Authority of GeorgiaMEAG and two municipalities. Georgia Power is the largest supplier of electric energy in the State of Georgia. See"BUSINESSSee "BUSINESS – OGLETHORPE POWER Power, is a state-chartered, municipal joint-action agency that provides capacity and energy to its membership of 49 municipal electric utilities, including 48 cities and one county in the State of Georgia. MEAG Power has wholesale take-or-pay power sales contracts with each of its 49 participants that extend to June 2054. The participants are located in 39 of Georgia's 159 counties and collectively serve approximately 311,000 electric consumers (meters). MEAG Power is Georgia's third largest power supplier behind Georgia Power and us. It presently serves more than 65,000 residential, commercial and industrial electric customers. Wansley, Vogtle and Scherer Wansley, Vogtle and Scherer are contained in a number of contracts between Georgia Power and us and, in some instances, MEAG Power and the City of Dalton. We are a party to fourthree Purchase and Ownership Participation Agreements (Ownership Agreements) under which we acquired from Georgia Power a 30% undivided interest in each of Plants Hatch Wansley and Vogtle Units No. 1 and No. 2, a 60% undivided interest in Scherer Units No. 1 and No. 2 and a 30% undivided interest in those facilities at Plant Scherer intended to be used in common by Scherer Units No. 1, No. 2, No. 3 and No. 4 (the Scherer Common Facilities). We have also entered into fourthree Operating Agreements (Operating Agreements) relating to the operation and maintenance of Plants Hatch, Wansley, Vogtle Units No. 1 and No. 2 and Scherer, respectively. The Ownership AgreementsAgreement and Operating AgreementsAgreement relating to PlantsPlant Hatch and Wansley areis a two-party agreementsagreement between Georgia Power and us. The Ownership Agreements and Operating Agreements relating to Plants Vogtle Units No. 1 and No. 2 and Scherer are agreements Power, the City of Dalton and us. The parties to each Ownership Agreement and Operating Agreement are referred to as "participants" with respect to each such agreement. Wansley and Scherer Units No. 1 and No. 2 and the facilities used in common at Plant Scherer. Each Operating Agreement gives Georgia Power, as agent, sole authority and responsibility for the management, control, maintenance and operation of the plant to which it relates. Each Operating Agreement also provides for the use of power and energy from the plant and the sharing of the costs of the plant by the participants in accordance with their respective interests in the plant. In performing its responsibilities under the Ownership and Operating Agreements, Georgia Power is required to comply with prudent utility practices. Georgia Power's liabilities with respect to its duties under the Ownership and Operating Agreements are limited by the terms of these agreements.and Wansley ownership and operating agreements allowagreement allows each co-owner (i) to dispatch separately its respective ownership interest in conjunction with contracting separately for long-term coal purchases procured by Georgia Power and (ii) to procure separately long-term coal purchases. We separately dispatch our ownership share of Scherer Units No. 1 and No. 2 and of Plant Wansley.and for Plant Wansley, each party is responsible for its fuel costs and for variable operating costs in proportion to the net energy output for its ownership interest, and is responsible for a percentage of fixed operating costsPlant Wansley is in the process of being extended until 2041. The co-owners anticipate extending the term prior to expiration. The Operating Agreement for Scherer Units No. 1 and No. 2 will remain in effect with respectexpires on January 31, 2026 and automatically renews for additional two year terms subject to Scherer Units No. 1 and No. 2 until 2022 and 2024, respectively.notice of termination provisions. Upon termination of each Operating Agreement, following any extension agreed to by the parties, Georgia Power will retain such powers as are necessary in connection with the disposition of the property of the applicable plant, and the rights and obligations of the parties shall continue with respect to actions and expenses taken or incurred in connection with such disposition. In conjunction with the development of additional units at Plant Vogtle, we, Georgia Power, MEAG Power and the City of Dalton entered into amendments to the Operating Agreement for Plant Vogtle and the Nuclear Managing Board Agreement, and entered into an Ownership Agreement that governs participation in Vogtle Units No. 3 and No. 4. Pursuant to this ownership agreement, Georgia Power has designated Southern Nuclear as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services. See "BUSINESS – OUR POWER SUPPLY RESOURCES –Future Power Resources –Plant Vogtle Units No. 3 and No. 4" for a discussion of recent amendments to our ownership agreements related to Vogtle Units No. 3 and No. 4.of Notes to Consolidated Financial Statements.Patronage Capital Litigation In 2014, two lawsuits were filed in the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission, and certain of our member distribution cooperatives. The plaintiffs, current and former consumer-members of those member distribution cooperatives, challenged the defendants' patronage capital distribution practices, claiming, among other things, the defendants failed to retire patronage capitalon an alleged required, regular schedule and, therefore, had inappropriately retained patronage capital owed to current and former consumer-members. In May 2016, the Superior Court issued a final order dismissing all of the plaintiffs' claims against us, Georgia Transmission, and the defendant member distribution cooperatives in both cases with prejudice. The plaintiffs in both cases appealed the Superior Court's decision to the Georgia Court of Appeals. On June 9, 2017, the Georgia Court of Appeals upheld the Superior Court's decision to dismiss on all counts both of these cases. The plaintiffs did not further appeal these dismissals to the Georgia Supreme Court and the appeal period has since expired, ending this litigation.our selected historical financial and statistical data. The financial data presented as of the end of and for each year in the five-yearthree-year period ended December 31, 2017,2023, has been derived from our consolidated audited financial statements. This data should be read in conjunction with"MANAGEMENT'Swith "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" and the"FINANCIALthe "FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA."(dollars in thousands) 2023 2022 2021 STATEMENTS OF REVENUES AND EXPENSES DATA Operating revenues: Sales to members $ 1,681,566 $ 1,974,683 $ 1,557,109 Sales to non-members 58,619 155,454 47,754 Operating expenses $ 1,463,119 $ 1,936,086 $ 1,410,482 Other income, net $ 81,049 $ 72,244 $ 71,254 Net interest charges $ 292,325 $ 204,591 $ 207,854 Net margin $ 65,790 $ 61,704 $ 57,781 BALANCE SHEET DATA Assets: Total electric plant $ 12,680,395 $ 12,490,108 $ 11,757,327 Total assets $ 16,524,851 $ 16,489,370 $ 15,707,026 Capitalization: Patronage capital and membership fees $ 1,257,917 $ 1,192,127 $ 1,130,423 Long-term debt and obligations under finance leases 12,149,489 12,001,694 10,983,930 Obligation under Rocky Mountain transactions 29,862 27,945 26,151 Other 5,152 2,256 1,550 Total long-term debt and equities $ 13,442,420 $ 13,224,022 $ 12,142,054 Less: Long-term debt and finance leases due within one year 384,426 322,102 281,238 Less: Unamortized debt issuance costs and bond discounts 120,560 114,142 111,909 Total capitalization $ 12,937,434 $ 12,787,778 $ 11,748,907 OTHER DATA 28,289,147 25,634,984 24,727,585 Member revenues per kWh sold 5.94 ¢ 7.70 ¢ 6.30 ¢ 9.4 % 9.0 % 9.3 % 1.14 1.14 1.14 (dollars in thousands) 2017 2016 2015 2014 2013 $ 1,433,830 $ 1,506,807 $ 1,219,052 $ 1,314,869 $ 1,166,618 366 424 130,773 93,294 78,758 1,434,196 1,507,231 1,349,825 1,408,163 1,245,376 473,184 513,258 441,738 515,729 442,425 401,374 434,306 457,264 428,801 369,730 224,098 217,534 168,920 166,247 158,375 59,996 54,108 56,925 71,799 56,084 36,674 32,361 26,108 24,616 22,900 – – (58,588 ) (58,426 ) (35,662 ) 1,195,326 1,251,567 1,092,367 1,148,766 1,013,852 238,870 255,664 257,458 259,397 231,524 64,985 56,903 52,030 46,371 43,433 (252,578 ) (262,222 ) (261,147 ) (259,133 ) (233,477 ) $ 51,277 $ 50,345 $ 48,341 $ 46,635 $ 41,480 $ 4,584,075 $ 4,671,500 $ 4,670,310 $ 4,582,551 $ 4,434,728 358,562 377,653 373,145 369,529 341,012 2,935,868 �� 3,228,214 2,868,669 2,374,392 2,212,224 $ 7,878,505 $ 8,277,367 $ 7,912,124 $ 7,326,472 $ 6,987,964 $ 10,928,139 $ 10,701,113 $ 10,059,783 $ 9,448,820 $ 9,048,453 $ 8,232,703 $ 8,304,523 $ 7,575,027 $ 7,256,995 $ 6,954,293 94,358 98,531 100,456 121,731 140,212 20,051 18,765 17,561 16,434 15,379 911,087 859,810 809,465 761,124 714,489 – (370 ) 58 468 (549 ) 9,258,199 9,281,259 8,502,567 8,156,752 7,823,824 (216,694 ) (316,861 ) (189,840 ) (160,754 ) (152,153 ) (87,802 ) (93,133 ) (93,651 ) (97,423 ) (46,759 ) (7,811 ) (8,128 ) (4,337 ) (4,516 ) (3,103 ) $ 8,945,892 $ 8,863,137 $ 8,214,739 $ 7,894,059 $ 7,621,809 $ 1,019,695 $ 613,019 $ 495,426 $ 534,171 $ 628,216 24,028,841 25,918,782 22,408,932 21,699,553 20,648,325 143,546 49,945 142,150 400,699 198,272 24,172,387 25,968,727 22,551,082 22,100,252 20,846,597 6.02¢ 5.90¢ 6.64¢ 6.52¢ 6.29¢ primarily derived from sales to our members pursuant to take-or-pay wholesale power contracts. In November 2023, we and each of our members extended the term of our wholesale power contracts that extend through 2050.from 2050 to 2085 which gives us greater flexibility to plan for and finance our resources. These contracts obligate our members jointly and severally to pay all of our costs and expenses associated with owning and operating our power supply business. To that end, our rate structure provides for a pass-through of actual energy costs. Charges for fixed costs, including capacity, other non-energy charges, debt service obligations and the margin required to meet our budgeted margins for interest ratio are carefully managed throughout the year to ensure that we collect sufficient capacity-related revenues. Our rate structure provides us with the ability to manage our revenues to assure full recovery of our costs and has enabled us consistently to meet our financial obligations since our formation in 1974.2017remainhad another successful year in 2023 and continue to be well positioned, both financially and operationally, to fulfill our obligations to our members, bondholders and creditors. Once again in 2017, ourOur revenues were more than sufficient to recover all of our costs and to satisfy all of our debt service obligations and financial covenants. Specifically, we recorded a net margin of $51.3$65.8 million in 2017,2023, which achieved the 1.14 margins for interest ratio approved by our board of directors and exceeded the 1.10 margins for interest ratio required to meet the rate covenant under our first mortgage indenture. Since 2009, we have targeted higher margins than necessary to meet our margins for interest ratio covenant of 1.10. We believe this is prudent due to significant capital expenditures and increased debt to fund those capital expenditures, most notably related to the construction of Vogtle Units No. 3 and No. 4. We have achieved our targeted margins in each of these years and, as a result, our patronage capital has increased significantly, from $535.8 million at December 31, 2008 to $911.1 million at December 31, 2017. For 2018,2024, we are again targeting a margins for interest ratio of 1.14, effectively increasing our annual margins by 40% over the minimum required level. We anticipate that we will continue to target a 1.14 margins for interest ratio through the remainder of the Vogtle construction period.capacityresources through the construction of Vogtle Units No. 3 and No. 4 and the acquisition of multiple natural gas-fired generation resources and the upgrading of our generation facilities, our total assets and total debt have more than doubled to $10.9 billion atsignificantly increased over the past several years. At December 31, 2017 from $5.02023, our total assets were $16.5 billion at December 31, 2008. Similarly, ourand total long-term debt including capital leases, has increased to $8.2 billion from $3.6 billion during the same period.was $12.1 billion. During the remainder of the Vogtle construction period, we expect that our assets and long-term debt and patronage capital will each continue to increase.UnitsUnit No. 3 also achieved commercial operation on July 31, 2023 which was reflected in rates starting in August. For the year ended December 31, 2023, our operating revenues were $1.7 billion, and No. 4 Wewe sold over 29.7 million megawatt hours compared to $2.1 billion in revenues and 27.3 million megawatt hours for the other Co-ownersyear ended December 31, 2022. Our cost-plus formulary rate structure ensures recovery of Plant Vogtle successfully navigatedcosts on a very challenging year with regardsmonthly basis and we remain focused on delivering cost-effective, reliable power to the development and construction of Vogtle Units No. 3 and No. 4. The year began with significant uncertainty regarding the financial viability of Westinghouse and is parent company, Toshiba. Then, in March 2017, Westinghouse filed for bankruptcy protection and this uncertainty spread to the future of Vogtle Units No. 3 and No. 4. Throughout the remainder of 2017, we actively engaged with Georgia Power, as our agent, and the other Co-owners to vigorously pursue our contractual remedies against Westinghouse and Toshiba and actively engaged with our members to evaluate our options regarding the additional Vogtle units. Following a comprehensive schedule, cost-to-complete and cancellation assessment of the Vogtle units, we, along with the other Co-owners, recommended proceeding with the project. In August 2017, Georgia Power included this recommendationrather than on maximizing revenues. Our continued investment in its construction monitoring report to the Georgia Public Service Commission. In a December 21, 2017 decision, the Georgia Public Service Commission approved the continuation of Vogtle Units No. 3 and No. 4. The Westinghouse bankruptcy led to significant changes in the parties managing the construction of the Vogtle units. Southern Nuclear is now construction manager, Bechtel is the primary contractor and Westinghouse is providing design services under a new Services Agreement. Over recent months, this new team has achieved increased productivity measures at the project site compared to the prior contractors, and weare optimistic that this improved performance will continue. Importantly, Toshiba honored its parent guarantee of Westinghouse's EPC Agreement and paid the Co-owners the entire $3.68 billion due under the Guarantee Settlement Agreement in late 2017. Our proportionate share of these payments was $1.1 billion which we are utilizing to cover our costs related to the Vogtle project. We expectresources, including Vogtle Units No. 3 and No. 4, is intended to provide long-term cost-effective and reliable power that is less sensitive to market volatility.placed in service by November 2021 and November 2022, respectively. Our project budget for the additional Vogtle units is $7.0 billion, which includes capital costs, allowance for funds used during construction and a contingency amount. This budget is net of the $1.1 billion of payments we received from Toshiba.primary focus area. As of December 31, 2017,2023, our total investment in the additional Vogtle units was approximately $2.9 billion, net$8.2 billion. Our current budget, which includes capital costs and allowance for funds used during construction, is a range of $8.3-8.35 billion.payments received from Toshiba.have a $3.1 billion federal loan guarantee fromare pleased with the Departmentinitial commercial operation of Energy, under which we have advanced $1.7 billion as of December 31, 2017. Our ability to request further advances under this loan is on hold pending an amendmentUnit No. 3 and look forward to the loan guarantee agreement. In September 2017, the Departmentcommercial operation of Energy issued a conditional commitment to us for up to $1.6 billion in additional guaranteed loans under the loan guarantee agreement. Although not assured, we expect to amend and restate the loan guarantee agreement in the second quarter of 2018 which will allow us to resume advances under the original $3.1 billion loan guarantee and serve as the primary definitive agreement for the additional $1.6 billion commitment. We expect that these Department of Energy-guaranteed loans will provide an aggregate amount of nearly $4.7 billion of long-term financing at lower interest rates than our alternative sources of financings. We anticipate the net present value of the savings from these loans will be over $500 million, which will reduce the long-term costs of these units. Separately, as a result of the Bipartisan Budget Act of 2018, we qualify for nuclear production tax credits related toUnit No. 4. Upon completion, Vogtle Units No. 3 and No. 4. We are reviewing various options to monetize these tax credits. We estimate that the nominal value of these tax credits will be approximately $660 million which we will receive over time after the units begin operating. We are grateful to the supporters of these tax credits, as the credits will reduce our members' costs related to the operation of the new Vogtle units and benefit the electric consumers they serve. Upon completion, these units4 will have an aggregate generating capacity of approximately 2,200 megawatts and our 30% undivided interest will entitle us to approximately 660 megawatts of carbon-free, baseload generating capacity. Once complete, weWe expect Vogtle Units No. 3 and No. 4our interest in these units to be valuable assets for us and our members over the next 60 to 80 years and to contribute to our diverse pool of generation resources. For additional information regarding Vogtle Units No. 3 and No. 4 and related financing activities, see "BUSINESS“BUSINESS – OUR POWER SUPPLY RESOURCES – Future Power Resources – " "MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION –” “– Financial Condition – Financing Activities – Department of Energy-Guaranteed Loan"Loans” and "– “– Capital Requirements – Capital Expenditures"” and Note 7a of Notes to Consolidated Financial Statements. Onestanding is our strong liquidity position.standing. This liquidity is comprised of a diversified, cost-effective mix of cash (including short-term investments), committed lines of credit and commercial paper. Our primary source of liquidity is a $1.2 billion unsecured credit facility that extends through March 2020December 2024 and which supports our $1.0 billion commercial paper program. We currently anticipate renewing this credit facility in the second quarter of 2024. Additionally, we have three other bank credit facilities which provide another $400$600 million available through additional secured and unsecuredin credit facilities.Department of Energy andthe Rural Utilities Service federal loan programsprogram and the taxable and tax-exempt capital markets. We expect to continue utilizing each of these sources of capital to meet our long-term financing needs in the coming years. With We also have $4.2 billion outstanding pursuant to borrowings under the Department of Energy loan program to finance the construction of the new Vogtle Units.current sourcesmembers are evaluating new incentives available to us to further diversify our generation portfolio through the addition of committed short-termnew battery storage and long-termrenewable generation resources. In October 2023, we, together with the Georgia Environmental Finance Authority, Georgia Transmission and Georgia System Operations, were selected for a $250 million grant under the Department of Energy’s GRIP Program. As part of the grant application, we applied for an aggregate of 75 megawatts of utility-scale battery storage which is estimated to utilize approximately $80 million of the total award. Receipt of any grant proceeds remains subject to meeting program requirements and customary closing conditions. We are also evaluating additional new funding we anticipate that we will have sufficient liquidity to complete Vogtle Units No. 3 and No. 4.opportunities through the Rural Utilities Service Empowering Rural America program.Asset Management Oneprimarykey focus areas continues to be ensuring that our owned and operated generation facilities perform in the most efficient and cost-effective manner possible. Our Operational Excellence program strives to achieve safety, reliability and compliance in a cost effective manner. Many of the generation facilities we operate rank in the top quartile of similar plants in one or more key performance indicators, including start reliability, peak season availability and forced outages. Achieving operational excellence results in the most reliable, efficient and lowest cost power supply for our members; therefore, effective asset management will always be one of our top priorities.Environmental Regulations A key component in effective asset management is maintaining compliance with all applicable environmental laws and regulatory standards. Although the short-term pressures we face from environmental legislationWe own electric generation facilities powered by nuclear, natural gas, coal and regulations have decreased since the beginning of 2017, environmental regulations continue to presenthydro resources which presents substantial challenges tofor us and our members.members to comply with existing environmental regulations. Based on the President’s executive orders and on statements and proposed rules from federal administrative agencies, we expect several existing environmental regulations to become more stringent. As an electric cooperative that operates on a not-for-profit basis, our compliance costs are ultimately borne by our members'members’ electricity consumers.have been oneby approximately 80% below 2005 levels by 2030. To that end, the EPA released a new rule in 2023 to address carbon dioxide emissions from existing coal and natural gas-fired power plants although it recently announced that it would address existing natural gas-fired plants in a future rulemaking. We believe that some of the most prominent areas for environmental regulations overassumptions in the past several years. Sinceproposed rule, particularly regarding natural gas, hydrogen availability, carbon capture and sequestration and the beginningpace of 2017, the Trump administration has taken a number of actionstechnological advancements, continue to reduce or rescind a number of federal environmental regulations, including those related to greenhouse gas emissions. Most notably, in October 2017, the EPA proposed a rule to rescind the Clean Power Plan. We are encouraged bybe unrealistic. At this action and have previously stated our belief that the Clean Power Plan is significantly flawed and could have significant negative consequences for the economy and electric systems of Georgia and nationwide. Even if the Clean Power Plan is ultimately rescinded, we anticipate that efforts to reduce greenhouse gas emissions, in particular carbon dioxide, will continue. Althoughtime, we cannot predict the formoutcome or timingpotential cost of any legislative or regulatory changes on us or our members, but such laws or regulations, wecosts could be significant.members'members’ needs. Further, our members continue to pursue potential renewable generation opportunities and invest where they deem appropriate in order to further diversify their power supply resources to meet the demands of their member consumers and prepare for potential future limitations on greenhouse gas emissions.2018 We20244.14.5 million people they serve andserve. We believe we are well positioned to do so. As discussed above, there are certain risks and challenges that we must continue to address, most notably related to Vogtle Units No. 3load growth in Georgia and No. 4.anticipated environmental regulation. However, as we manage our risks, we intend to keep doing what we have done so successfully for the last 4450 years, including, among other things:diversityand diverse portfolio of generating resources, including nuclear, natural gas, coal and hydro and continuing the reliable, efficient and cost-effective operation of these resources;2017,2023, our regulatory assets and regulatory liabilities totaled $585.1 million$1.1 billion and $251.6$706.3 million, respectively. While we do not currently foresee any events such as competition or other factors that would make it not probable that we will recover these costs from our members as future revenues through rates under our wholesale power contracts, if such an event were to occur, we could no longer apply the provisions of accounting for regulated operations, which would require us to eliminate all regulatory assets and regulatory liabilities that had been recognized as a charge or credit to our statement of revenues and expenses and begin recognizing assets and liabilities in a manner similar to other businesses in general. In addition, we would be required to determine any impairment to other assets, including plants, and write-down those assets, if impaired, to their fair values.2017,2023, our nuclear decommissioning and coal ash related asset retirement obligation totaled $548.6obligations were $929.8 million whichand $464.0 million, respectively. Our asset retirement obligations represent an estimate of the present value of anticipated retirement costs. For additional detail regarding our asset retirement obligations, see Note 1h of Notes to Consolidated Financial Statements. These obligations represented approximately 75%95% of our total asset retirement obligations. Our remaining asset retirement obligations relate to non-nuclear retirement obligations such as those related to our shareresults.costs. In addition, these estimates are dependent on subjective factors, including the selection of cost escalation and discount rates, which we consider to be a critical assumption.assumptions. Our current estimates are based upon studies that were performed in 2015.2020 and 2021. For ratemaking purposes, we record decommissioning costs over the expected service life of each unit. The impact on measurements of asset retirement obligations using different assumptions in the future may be significant.New Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (FASB) issued "Revenue from Contracts with Customers" (Topic 606). The new revenue standard requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expectsentitledcritical estimates, in exchange forparticular those goods and services. The standard is effective for us for the annual reporting period beginning after December 15, 2017 using eithercoal ash ponds. Cost studies are periodically performed to provide site-specific "base year" estimates that determine the nature and timing of planned decommissioning costs. These cost studies are based on relevant information available at the time they are performed; however, estimates of the following transition methods: (i) a full retrospective approach reflectingamount and timing of future cash flows for extended periods are by nature highly uncertain and may vary significantly from actual costs. Critical assumptions include coal ash pond closure strategy, including water treatment requirements, and the applicationvolume of coal ash in the standardponds. In addition, these estimates are dependent on other subjective factors, such as estimates of costs to perform the decommissioning and post-closure activities, timing of expenditures, and the selection of cost escalation and discount rates. Our current estimates are based upon studies that were performed in each prior reporting period with2023. For ratemaking purposes, we are applying regulated operations accounting to the optiondecommissioning costs and currently expect to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes additional footnote disclosures). We have completed our evaluation of the new revenue standard and adopted the amendments within the new standard effective January 1, 2018. There was no cumulative impact upon adoption.recover ash pond closure costs over approximately 13 years. The adoption of this standard is not expected to have a material impact on an annual basis, to our revenue recognition based on our existing contracts with customers. Our evaluation process included, but was not limited to, identifyingcontracts withinasset retirement obligations using different assumptions in the scope of Topic 606, reviewing and documenting our accounting for these contracts and assessing the applicability of the variable consideration guidance. The vast majority of our revenue is derived from substantially identical wholesale power contracts that we have with each of our 38 members. We expect the pattern of revenue recognition pursuant to our wholesale power contracts will remain unchanged on an annual basis under the new revenue standard. Historically, our Board has approved budget adjustments, typically at year end butfuture may be made throughout the year, that affect our annual revenue requirement. As a result, at the end of each reporting period we will determine whether the variable consideration cumulatively received from our Members exceeds the consideration to which we expect to be entitled on an annual basis. We will recognize a refund liability for the consideration which we expect to refund to our Members, if such excess consideration received would result in a significant reversal in the cumulative revenues recognized. In January 2016, the FASB issued "Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities." The amendments in this update address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The new standard is effective for us for annual reporting periods beginning after December 15, 2017, and interim periods therein. Certain provisions within this update can be adopted early. Certain provisions within this update should be applied by means of a cumulative effect adjustment to the balance sheet of the fiscal year of adoption and certain provisions should be applied prospectively. One of the provisions in this standard requires our equity investments, except those accounted for under the equity method of accounting or those that result in consolidation of our subsidiary, to be measured at fair value with changes in fair value recognized in net income. None of the other provisions in this standard will have any impact to our consolidated financial statements. Effective December 31, 2017, we adopted regulatory accounting treatment with respect to unrealized gains and/or losses on our equity investments. Upon applying regulatory accounting treatment, unrealized gains on our equity investments will be recorded as a regulatory liability and, conversely, unrealized losses on our equity investments will be recorded as a regulatory asset, at the end of each reporting period. As of December 31, 2017, we recorded $0.6 million of unrealized losses on our equity investments as a regulatory asset. Effective January 1, 2018, we adopted the amendments within this standard. The adoption of this standard will have no impact to our consolidated financial statements due to our regulatory accounting treatment for unrealized gains and/or losses on our equity investments. In February 2016, the FASB issued "Leases (Topic 842)." The new leases standard requires a dual approach for lessee accounting under which a lessee would account for leases as finance leases or operating leases. Both finance leases and operating leases will result in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee would recognize interest expense and amortization of the ROU asset and for operating leases the lessee would recognize a straight-line total lease expense. The new lease standard does not substantially change lessor accounting. The new leases standard is effective for us on a modified retrospective approach for annual reporting periods beginning after December 15, 2018, and interim periods therein. Early adoption is permitted. We are currently evaluating the future impact of this standard on our consolidated financial statements. In June 2016, the FASB issued "Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments." The amendments in this update replace the current incurred loss impairment methodology with a methodology that reflects expected credit losses. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2019, and interim periods therein. The amendments in this update can be adopted earlier as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are currently evaluating the future impact of this standard on our consolidated financial statements. In August 2016, the FASB issued "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments." The amendments in this standard provide specific guidance on eight cash flow classification issues relating to how certain cash receipts and cash payments are presented and classified in the statement of cash flows, thereby reducing the current and potential future diversity in practice. The new standard is effective for us for annual reporting periods beginning after December 15, 2017, and interim periodstherein. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. The amendments should be applied using a retrospective transition method to each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. As permitted, on October 1, 2017, we early adopted these amendments and applied their provisions retrospectively. The adoption of this standard had no impact on our consolidated financial statements as the amendments did not change how we present and classify the eight identified cash flow classification issues within our consolidated statement of cash flows. In November 2016, the FASB issued "Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)." The amendments in this standard require the statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statement of cash flows. The new standard is effective for us on a retrospective basis for annual reporting periods beginning after December 15, 2017, and interim periods therein. Early adoption is permitted, including adoption in an interim period. As permitted, on October 1, 2017, we early adopted these amendments and applied their provisions retrospectively. The adoption of this standard had no impact on our consolidated financial statements as we did not have any restricted cash balances in 2017 and 2016.We supplyOur primary source of revenue is the sale of capacity and energy to our members for a portion of their energy requirements which is our primary source of revenues.requirements. We may also sell capacity and energy to non-members. Capacity revenues are the revenues we receive for providing electric service whether or not our generation and purchased power resources are dispatched to produce electricity. Energy revenues are the revenues we receive by selling electricity whichthat we generate or purchase. and purchased power resources. Each member has contractually agreed to pay us for the electric capacity assigned to it based on its individual fixed percentage capacity cost responsibility.We do not provide our members with all of their energy requirements; however, our energyEnergy sales to our members fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in the service territories of our members, operating costs, availability of electric generation resources and our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights and byrights. In addition, as we do not provide our members with all of their energy requirements, energy sales may also fluctuate based on our members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers.participate, and variable as energy charges based on the amount of energy supplied to each member.2018.2024. As our capital requirements continue to evolve, our board will continue to evaluate the level of margin coverage and may choose to change the targeted margins for interest ratio in the future, although not below 1.10.2017,2023, we had $911.1 million$1.3 billion in patronage capital and membership fees. Our equity ratio, calculated pursuant to our first mortgage indenture as patronage capital and membership fees divided by total capitalization and long-term debt due within one year, was 9.8%9.4% and 9.3%9.0% at December 31, 20172023 and December 31, 2016,2022, respectively.Lenders – Rural Utilities Service.Lenders." Currently, our rates are not subject to the approval of any other federal or We haveplants, allowing usplants. See Note 13 of Notes to serve the power needs of our members in a reliable, efficient and low-cost manner. The types of generation assets we own include several natural gas-fired simple cycle combustion turbines, two combined cycle natural gas-fired plants, a plant that burns bituminous coal, a plant that burns sub-bituminous coal, two nuclear plants and a pumped storage hydroelectric plant. Until the beginning of 2016, two of our facilities were not generally used to serve member load. Smith, a 1,250-megawatt combined cycle natural gas-fired plant we acquired in 2011, was used prior to 2016 extensivelyConsolidated Financial Statements for off-system sales. Additionally, one of our simple cycle natural gas-fired plants, Hawk Road, was utilized solely to serve seven of our members or for off-system sales until the beginning of 2016. These two facilities were acquired on favorable terms with the knowledge that our members generally would not require the energy generation until 2016. Duringadditional information regarding this time, the effect on net margin of the revenues and expenses at Smith and Hawk Road were deferred, and when we began dispatching these units to serve member load in 2016, we began recovering the net effect of these deferrals from our members. Starting in 2016, we began dispatching Smith exclusively to serve member load, and therefore member kilowatt-hour sales increased significantly, non-member sales substantially ended, and the average cost of energy sold to members decreased significantly. When we began dispatching Smith to serve member load, we experienced an increase in overall generation from Smith since member energy requirements have been a more consistent source of demand than general market demand. Additionally, in 2016, we began charging members to recover both the current fixed costs and the previously deferred net costs of Smith which, along with the increased generation from Smith, resulted in significantly increased sales revenues from members. This included higher energy charges due to a greater number of kilowatt-hours of energy that we generated and sold to members from Smith as well as increased member capacity revenues from Smith to recover fixed operating costs, depreciation and interest on the initial acquisition costs, as well as the amortization of previously deferred fixed costs of Smith. Although these capacity revenues increased, the increase in kilowatt-hours of energy sold to members was greater than the increase in total cost of the additional member sales from Smith, so the average cost of energy we sold to our members was significantly lower in 2017 and 2016 compared with 2015.Our members' energy demandThis is a function of weather, economic activity, residential use patterns and the relative cost and availability of our members' third party supplysignificant portionthird of the energy they purchase. Sincepass through allgenerated and sold to members was higher than in 2022 and 2021, and led to higher utilization of our combined cycle generating facilities and our coal facilities compared to the prior two years. While the amount of energy we sold to our members was higher, our members’ overall energy demand was lower in 2023 compared to 2022 primarily due to 2023 being a mild weather year. December 2022 still holds the overall peak when we experienced extremely cold weather during the Christmas holiday weekend.members, including fuelserve non-member sales, and we plan to continue doing so through 2025. In 2023, we saw reduced market demand for these off-system sales compared with 2022; therefore, we generated and sold fewer megawatt-hours of off-system energy from BC Smith compared with 2022.which is one of our most significant operating costs,cost, and this greatly impacts the cost of our energy sales to our members as well as our member sales (in dollars) is significantly affected by fuel prices. The price of natural gas is the most significant variable in our cost of fuel and also affects how we dispatch our generation resources. SinceIn 2023, natural gas prices have remained relatively lowdecreased significantly compared with 2022 due to market alleviation on supply and demand pressures. This decrease in natural gas prices led to more generation and sales to our members and lower fuel cost compared to 2022. The commercial operation of Vogtle Unit No. 3, which began in July 2023, also contributed to the last threeincrease in megawatt-hour sales to the members in 2023. In 2022, natural gas prices were significantly higher compared with each of the previous years due to market pressures on supply and demand. Coupled with the amountincrease in member sales (in megawatt-hours), the increased natural gas prices in 2022 resulted in higher cost of coal-fired generation we soldfuel and member sales (in dollars). In 2022, due to the increase in natural gas prices, our coal units were also more economical resulting in more coal generated energy to sell to our members has decreased each year from 2015 through 2017.kilowatt hourkilowatt-hour generated is also affected by how efficiently our natural gas facilities burn the gas. Compared to our combustion turbine units, our combined cycle units our combustion turbines are lessmore efficient and thus burn moreless gas per kilowatt hour of electricity generated. Consequently, our combustion turbines are dispatched less frequentlyturbine units have a higher dispatch cost than our combined cycle units and are typically used to generate energy only during periods of higher electricity demand, such as on hot summer days or colder winter days. In 2016, we dispatched our combustion turbinesAnd although 2023 had milder weather overall, more frequently due toextreme weather days in 2023 resulted in significantly higher and more frequent incidences of peak demand driven by a relatively hot summer. Therefore, the generation from our combustion turbinescombined cycle units compared to 2022 and 2021 and this also contributed to higher member sales (in megawatt-hours) in 2016 was significantly higher2023, than in both 20172022 and 2015. In 2017, because we dispatched these higher-heat-rate peaking units less frequently, our average fuel cost per kilowatt hour generated was lower in 2017 than in 2016.toor 24-month cycle and these refueling outages, which typically last several weeks, resulted in fluctuations in nuclear plant availability and generation in each of the last three years. These shutdowns and outages significantly reduced generation at the affected plants, reduced kilowatt-hour sales to and energy revenues from our members during the periods that the plants were not generating power. Our energy sales to our members also fluctuate In 2023, generation from period to period based on weather. SummerVogtle Unit No. 3 offset the decrease in 2016 was relatively hot and as a result, member demand and energy requirements, and therefore, energy sales to our members were higher in 2016 compared with 2017 and 2015. The higher 2016 energy sales also contributed to higher fuel costs and, consequently, higher operating expenses in 2016 than in 2017 or 2015.under construction at Plant Vogtle and the BC Smith, Washington County, and Baconton acquisitions, which we have primarily financed with debt. These financings have increased our overall debt which has increased our interest expense and our allowance for debt funds used during construction. Additionally, since our margin is calculated as a percentage of our secured interest expense, our net margin has alsogenerally increased. As discussed under "– Financial Condition – Capital Resources – Capital Expenditures," we expect significant capital expenditures to continue through the completion of the additional units at Plant Vogtle.2017, 20162023, 2022 and 20152021 was $51.3$65.8 million, $50.3$61.7 million and $48.3$57.8 million, respectively. These amounts produced a margins for interest ratio of 1.14 in each of 2017, 20162023, 2022 and 2015.2021. For additional information on our margin requirement, see "– Summary of Cooperative Operations – Rate Regulation."Members.members. We generate revenues principally from the sale of electric capacity and energy to our members. Capacity revenues are the revenues we receive for electric service whether or not our generation and purchased power resources are dispatched to produce electricity, andelectricity. These revenues are designed to recover the fixed costs associated with our business, including fixed production expenses, depreciation and amortization expenses and interest charges, plus a targeted margin. Energy revenues are earned by sellingthe sales of electricity to our members, which involves generatinggenerated or purchasing electricitypurchased for our members. Energy revenues recover the variable costs of our business, including fuel, purchased energy and variable operation and maintenance expense.(in thousands) 2023 vs. 2022 2022 vs. 2021 2023 2022 2021 % Change % Change Capacity revenues $ 1,082,368 $ 984,036 $ 946,662 10.0 % 3.9 % Energy revenues 599,198 990,647 610,447 (39.5) % 62.3 % Total $ 1,681,566 $ 1,974,683 $ 1,557,109 (14.8) % 26.8 % 28,289,147 25,634,984 24,727,585 10.4 % 3.7 % Cents/kWh 5.94 7.70 6.30 (22.8) % 22.3 % Member energy requirements supplied 68 % 58 % 62 % 17.2 % (6.5) % (in thousands) 2017 vs. 2016 2016 vs. 2015 2017 2016 2015 % Change % Change $ 862,511 $ 896,412 $ 772,069 (3.8 )% 16.1 % 571,319 610,395 446,983 (6.4 )% 36.6 % $ 1,433,830 $ 1,506,807 $ 1,219,052 (4.8 )% 23.6 % 23,813,679 25,522,852 18,371,558 (6.7 )% 38.9 % 6.02 5.90 6.64 2.0 % (11.1 )% 63 % 64 % 48 % (1.6 )% 33.3 % declined 3.8%increased in 2017 as2023 compared to 20162022 primarily due to Plant Vogtle Unit No. 3 being placed in service on July 31, 2023 and the related recovery of net interest and depreciation expense. The increase in capacity revenues in 2022 compared to 2021 was due primarily to the recovery of higher fixed production maintenance costs. For a discussion of production costs and depreciation expense, see "– Operating Expenses."(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 kWh Sales to non-members 1,415,042 1,690,454 1,039,957 Cents/kWh 4.14 9.19 4.59 Cost Generation Cents per kWh (dollars in thousands) (kWh in thousands) Fuel Source 2023 2022 2021 2023 vs.
2022
%
Change2022 vs.
2021
%
Change2023 2022 2021 2023 vs.
2022
%
Change2022 vs.
2021
%
Change2023 2022 2021 2023 vs.
2022
%
Change2022 vs.
2021
%
ChangeCoal $ 124,638 $ 107,207 $ 86,289 16.3 % 24.2 % 3,166,368 2,856,494 2,559,235 10.8 % 11.6 % 3.94 3.75 3.37 4.9 % 11.3 % Nuclear 84,192 73,871 77,366 14.0 % (4.5) % 11,122,301 10,206,060 10,171,948 9.0 % 0.3 % 0.76 0.72 0.76 4.6 % (4.8) % Natural Gas: Combined Cycle 323,614 704,809 387,069 (54.1) % 82.1 % 14,804,306 13,100,271 12,722,401 13.0 % 3.0 % 2.19 5.38 3.04 (59.4) % 76.8 % Combustion Turbine 46,350 159,202 48,272 (70.9) % 229.8 % 1,382,989 1,824,570 1,026,430 (24.2) % 77.8 % 3.35 8.73 4.70 (61.6) % 85.5 % $ 578,794 $ 1,045,089 $ 598,996 (44.6) % 74.5 % 30,475,964 27,987,395 26,480,014 8.9 % 5.7 % 1.90 3.73 2.26 (49.1) % 65.1 % fixed production costs and the recoveryaverage cost of such costs. For a discussion of production costs, see "– Operating Expenses." Beginningfuel. The decrease in 2016, we began dispatching Smith and Hawk Roadaverage fuel cost was primarily due to serve member load. Consequently, capacity revenues increased 16.1%lower average natural gas prices in 20162023. The overall increase in generation in 2023 compared to 20152022 was due in part to an increase in sales to our members as a result of the recoverycommercial operation of fixed costs at these plants. Prior to 2016,Vogtle Unit No. 3 and our members did not require theobtaining more of their energy generationrequirements from Smith and Hawk Road and the effects of the revenues and expenses from these resources on net margin were deferred. The 6.4% decrease in energy revenues from members in 2017 compared to 2016 was primarilyus rather than their third party suppliers due to a decrease in generation for member salesrelative energy prices. In 2023 and a decrease2022, we included $20.9 million and $115.0 million of net losses and net gains recognized, respectively, in total fuel costs. Slightly offsettingexpense for the decrease wassettlement of natural gas financial contracts we utilize to manage our exposure to fluctuations in market prices. Total fuel expense increased in 2022 compared to 2021 primarily as a result of an increase in revenues related to purchased power energy. Energy revenues increased in 2016 compared to 2015 primarily due tothe average cost of fuel and an increase in generation for membermembers and non-members. The increase in average fuel cost was primarily due to higher average natural gas prices in 2022. The overall increase in generation in 2022 compared to 2021 was largely due to increases in sales to our members as a result of Smithweather events and Hawk Road being utilized by our members. The average energy revenue per kilowatt-hour from sales to members decreased 11.1% in 2016 compared to 2015. Our members' ability to schedule these additional natural gas-fired facilities, which provided an economical source of energy due to low natural gas prices, significantly increased our kilowatt-hour sales to our members and allowed us to provide a larger percentage of our member's load requirements in 2016. Slightly offsetting the increase was a decrease in revenues related to purchased power energy. For a discussion of fuel costs and purchased power costs, see "– Operating Expenses." Sales to Non-members. Prior to 2016, sales to non-members consisted primarilyfrom BC Smith which we acquired in July 2021.2016 and 2017 as we began scheduling Smith for our members and opportunities for sales to non-members were greatly reduced.Operating Expenses Our operating expensesa given year. Production costs decreased 4.5%11.8% in 20172023 compared to 20162022 and increased 14.6%14.1% in 20162022 compared to 2015.2021. The decrease in 20172023 was due to less costly planned major maintenance outages during 2023 compared to 20162022. The increase in 2022 was due to more costly planned major maintenance outages and the result of deferring BC Smith's effects on net margin during 2022 compared to 2021.lower fuel and production costs. The increase in 2016 compared to 2015 was primarily due to an increase in fuel costs, depreciation, and the end of deferral of the effect of Smith and Hawk Road on net margins in 2015. The following table summarizes our kilowatt-hour generation and fuel costs by generating source. Cost Generation Cents per kWh (dollars in thousands) (kWh in thousands) 2017 2016 2015 2017 vs.
2016
%
Change 2016 vs.
2015
%
Change 2017 2016 2015 2017 vs.
2016
%
Change 2016 vs.
2015
%
Change 2017 2016 2015 2017 vs.
2016
%
Change 2016 vs.
2015
%
Change $ 103,007 $ 141,773 $ 142,113 (27.3% ) (0.2% ) 3,605,093 4,800,836 5,013,312 (24.9% ) (4.2% ) 2.86 2.95 2.83 (3.1% ) 4.2% 90,520 83,751 78,762 8.1% 6.3% 10,110,190 10,344,201 10,151,539 (2.3% ) 1.9% 0.90 0.81 0.78 11.1% 3.8% 239,472 221,851 182,818 7.9% 21.4% 9,823,035 8,916,272 6,890,245 10.2% 29.4% 2.44 2.49 2.65 (2.0% ) (6.0% ) 40,185 65,883 38,045 (39.0% ) 73.2% 966,548 1,743,795 789,041 (44.6% ) 121.0% 4.16 3.78 4.82 10.1% (21.6% ) $ 473,184 $ 513,258 $ 441,738 (7.8% ) 16.2% 24,504,866 25,805,104 22,844,137 (5.0% ) 13.0% 1.93 1.99 1.93 (3.0% ) 3.1% Total fuel costs decreased in 2017 compared to 2016higher interest income as a result of a 7.8% decreasehigher interest rates in generation2023 compared to 2022. Total other income was relatively unchanged in 2022 compared to 2021.a shiftNo. 4 construction expenditures and plant acquisitions. Allowance for debt funds used during construction decreased in generation2023 due to the relatively more economical natural gas-fired combined cycle units. The decrease and shiftPlant Vogtle Unit No. 3 being placed in generation were due in part to more moderate weather in 2017, in particular the summer months, and an extended major maintenance outage at Scherer Unit 1.service on July 31, 2023. As a result of these factors, generation at ournet interest charges increased 42.9% in 2023. Net interest charges were relatively more expensive combustion turbine and coal-fired plants decreased by 44.6% and 24.9%, respectfully. Partially offsettingflat in 2022 as the decreaseincreased interest expense, which was an 8.1% increase in nuclear fuel costs largely due to spent fuel storage costs incurred during 2017. Total fuel costs increased in 2016 compared to 2015 primarily asborrowings for Plant Vogtle construction expenditures, was offset by a result of a 39%corresponding increase in generation at our natural gas-fired plants. The effect of increased generation on fuel cost was partially moderated by lower average natural gas pricesallowance for debt funds used during the first half of 2016. A combination of the lower natural gas prices and the ability of our members to schedule Smith and Hawk Road in 2016 were the primary contributors to the increase in total generation. Also contributing to increased fuel costs in 2016 was a $7.1 million reduction in fuel expense in 2015 associated with the recovery of spent nuclear fuel storage costs from the U.S. Department of Energy. The exclusion of the credit would have resulted in (i) 2015 nuclear fuel costs of $85.8 million, a 2.4% decrease in 2016 compared to 2015 and (ii) a 4.2% decrease in the average cost per kilowatt-hour generation in 2016 compared to 2015. Changes in total fuel costs are also impacted by the amount of realized gains and losses incurred for natural gas financial hedging contracts utilized for managing our exposure to fluctuations in market prices of natural gas. During 2017, we realized a net gain of $2.1 million. In 2016 and 2015, we realized net losses of $17.3 million and $19.9 million, respectively. Production costs decreased 7.6% in 2017 compared to 2016 and 5.0% in 2016 compared to 2015. The decrease in 2017 was primarily due to a decline in planned major maintenance costs at Hartwell and lower fixed maintenance costs at Smith. The decrease in 2016 was primarily due to higher planned major maintenance costs at Smith and Hawk Road in 2015 than 2016. Depreciation expense increased slightly in 2017 and 28.8% in 2016 compared to 2015. The increase in depreciation expense in 2016 compared to 2015 was primarily due to the adoption of new depreciation rates for our co-owned nuclear and coal-fired plants. The new depreciation rates were higher than the previous rates largely as a result of capital additions for environmental controls and costs associated with interim retirements. Also contributing to the 2016 increase was the completion in 2015 of the amortization of a deferred liability related to the Hawk Road acquisition, the start of the amortization of the deferred asset related to the effect of Smith on net margins, and an increase in depreciation associated with certain asset retirement obligations. The deferral of the Hawk Road and Smith effect on net margin ceased as of December 31, 2015. The deferred amounts are being amortized, which began in 2016, over the remaining lives of the plants. The amortization is recorded as a component of depreciation and amortization expense.Other Income Investment income increased 8.6% in 2017 compared to 2016 and 27.8% in 2016 compared to 2015. The increase in 2017 was due to higher investment balances and an increase in the investment income associated with nuclear decommissioning. The increase in 2016 was primarily related to an increase in investment income associated with nuclear decommissioning. We use the accounting provision for regulated operations for our nuclear decommissioning transactions, and record a regulatory asset or liability to reflect the difference in the timing of recognition of decommissioning expenses for financial statement purposes compared to the expense recovered for ratemaking purposes. As a result of this treatment, nuclear decommissioning related investment income increased $1.9 million in 2017 and $9.1 million in 2016, which equaled the increase in nuclear decommissioning expense for the periods. The increase in nuclear decommissioning expense was driven by an increase in cash flow estimates made pursuant to nuclear decommissioning studies completed in late 2015.Interest Charges The increases in interest expense in 2017 and 2016 as compared to the respective prior years were primarily due to increased debt issued to finance the construction of Vogtle Units No. 3 and No. 4. We expect interest on long-term debt to continue to increase in future years as we issue additional debt to finance the construction of Vogtle Units No. 3 and No. 4.2017,2023, we achieved a 1.14 margins for interest ratio which produced a net margin of $51.3$65.8 million. This net margin increased our total patronage capital (our equity) and membership fees to $911.1 million$1.3 billion at December 31, 2017.2023. Our 20182024 budget again targets a 1.14 margins for interest ratio.increased from 9.3%was 9.4% at December 31, 2016 to 9.8%2023 and 9.0% at December 31, 2017.2022. We anticipate that our equity ratio will remain around its current level during the remainder of the Vogtle construction period; however, the absolute level of patronage capital will continue to increase.2017,2023 with $1.6$1.7 billion of unrestricted available liquidity, including $397.7$490.6 million of cash and cash equivalents. We issued commercial paper throughout the year to provide interim financing for the Plant Vogtle construction, the Washington County and Baconton acquisitions and for other purposes at a very low cost.general purposes. The average cost of funds on the $190.6$607.9 million of commercial paper outstanding at December 31, 20172023 was 1.58%5.7%. Our total assetsslightly to $10.9by approximately $4.8 billion at December 31, 2017 from $10.7 billion at December 31, 2016. For the past several years, our total assets have shown significant increases due to increases in construction work in progress in connection with the additional nuclear units under construction at Plant Vogtle. However, total assets increased only slightly in 2017 due to a corresponding decrease in construction work in progress, following our receipt of guaranty settlement payments from Toshiba, totaling approximately $1.1 billion, during the fourth quarter of 2017.primarily due to Plant Vogtle Unit No. 3 being placed in service on July 31, 2023. The receipt of the guaranty settlement payments also reduced our investment to-date on the project, from $3.9 billion at September 30, 2017 to $2.9 billion at December 31, 2017. Property additions during 2017 totaled $1.0 billion. Theseother capital additions include costs related to the construction of the new Vogtle units, environmental control facilities being installed at Plants Scherer and Wansley,Baconton acquisition, normal additions and replacements to existing generation facilities and purchases of nuclear fuel. There was a net decrease For the past several years, our total assets have significantly increased primarily due to the additional nuclear units under construction at Plant Vogtle.long-term debtthe fair market value of investments due to the recovery in the stock market in 2023.capital leases of $76short-term investments decreased by $104.1 million at December 31, 20172023 compared to December 31, 2016.2022. The decrease was due to the utilization of remaining funds on deposit with the Rural Utilities Service in$8.2$12.1 billion of long-term debt outstanding at December 31, 20172023 was 4.17%3.89%. In 2014, we obtained a loan See "– isare guaranteed by the Department of Energy that provides funding for $3.1 billionto fund a portion of theour cost to construct our 30% undivided interest in the two new nuclear units at Plant Vogtle. We are currently restricted from receiving further advances under this loan pending the completionAs of certain conditions whichDecember 31, 2023, we expect to occur in the second quarter of 2018. In September 2017, the Department of Energy issued a conditional commitment to us for $1.6had $4.2 billion of additional guaranteed funding under the loan guarantee agreement. This additional funding is subject to an amendment and restatement of the Loan Guaranty Agreement and satisfaction of certain other conditions. The conditional commitment expires on June 30, 2018, subject to any extension approved by the Department of Energy. While not assured, we expect to close on this loan in the second quarter of 2018. See "–Financing Activities" and Note 7 in Notes to Consolidated Financial Statements for additional information regarding the status of this loan.markets, and ifmarkets. If the Rural Utilities Service loan program were to be curtailed or eliminated, in the future, we believe we are well positioned to continue to access capital market financings.Lenders."TableLenders" for further discussion of Contents See"– Capital Requirements – Capital Expenditures" for more detailed information regarding our estimated capital expenditures. See "–Financing Activities" for more detailed information regarding our financing plans.2017,2023, we had $1.6$1.7 billion of unrestricted available liquidity to meet short-term cash needs and liquidity requirements, consisting of $397.7$490.6 million of cash and cash equivalents and $1.2$1.20 billion of unused and available committed credit arrangements.$471.3$194.5 million in 2017,2023, and averaged $339.6$433.8 million per year for the three-year period 20152021 through 2017. We monitor our anticipated liquidity needs to ensure that our credit facility portfolio appropriately covers our anticipated needs. We anticipate renewing the three credit facilities that are set to expire in 2018 as detailed in the table below.2017,2023, we had $1.6$1.8 billion of committed credit arrangements in place and $1.2$1.20 billion available under these facilities. The four separate facilitiescredit facilities. These are reflected in the table below:Committed Credit Facilities (dollars in millions) Authorized
AmountAvailable
12/31/2023Expiration
DateUnsecured Facilities: Syndicated Line among 12 banks led by CFC $ 1,210 $ 599 (1) December 2024 110 110 December 2028 JPMorgan Chase Line of Credit 350 347 (3) October 2024 Secured Facilities: 250 140 December 2028 Committed Credit Facilities (dollars in millions) Authorize
Amount Available
12/31/2017 Expiration
Date $ 1,210 $ 884 (1) March 2020
110
110
150
34
(3)
250 140 December 2018 OfThis facility is dedicated to support outstanding commercial paper and the portion of this facility that was unavailable at 12/31/17, $190.6 million was dedicated to supportrepresents outstanding commercial paper and $135.5 million related to letters of credit issued to support variable rate demand bonds.Of the portionthat was unavailable at 12/31/17, $113.7 million related toused for letters of credit issued to support variable rate demand bonds and $2.2 million related to letters of credit issued to post collateralprovide performance assurance to third parties.to support up to $1.0 billion of commercial paper and to issueissuing letters of credit to third parties.anyour committed backup lines of credit, thereby providing 100% dedicated support for any commercial paper outstanding. Under Due to this requirement, any commercial paper we issue will reduce the availability under the $1.2 billion syndicated line of credit. At December 31, 2023, we had issued commercial paper primarily to provide interim funding for:we havepermit the abilityissuance of up to issue$960 million in letters of credit totaling $760.0 million in the aggregate,on our behalf, of which $508.6$957 million remained available at December 31, 2017. However, amounts related to issued letters2023. This letter of credit reduce the amount that would otherwise be available to draw for working capital needs. Also, due to the requirement to have 100% dedicated backup for any commercial paper outstanding, any amounts drawnissuance capacity includes $500 million under our committed credit facilities for working capital or related to issued letters$1.2 billion syndicated line of credit, will reduce the amount of commercial paper that we can issue. The majority of$350 million under our outstanding lettersJPMorgan Chase line of credit, are for the purpose of providing credit enhancement on variable rate demand bonds. We generally issue commercial paper to provide interim financing of our expenses related to the construction of Vogtle Units No. 3 and No. 4 which we repay with the proceeds from long-term funding sources. Due to issues stemming from the bankruptcy of Westinghouse, we were restricted from borrowing$110 million under our DepartmentCFC line of Energy-guaranteed loan for mostcredit. TwoThree of our line of credit facilities contain similar financial covenants that require us to maintain minimum patronage capital levels. Currently, we are required to maintain minimum patronage capital of $675$750 million. As of December 31, 2017,2023, our patronage capital balance was $911.1 million.$1.3 billion. These agreements contain an additional covenant that limits our secured indebtedness and our unsecured indebtedness, both as defined in the credit agreements, to $12$14 billion and $4 billion, respectively. At December 31, 2017,2023, we had $8.2$12.1 billion of secured indebtedness outstanding and $190.6$607.9 million of unsecured indebtedness outstanding.2017,2023, we had 15seven members participating in the program and a balance of $209.5$78.5 million remaining to be applied against future power bills. In addition to unrestricted available liquidity, at December 31, 2017 we had $883.0 million of restricted liquidity in connection with deposits made into a Rural Utilities Service Cushion of Credit Account. Deposits into the Cushion of Credit Account are voluntary and earn a rate of interest of 5% per annum. The funds in the account, including interest thereon, can only be applied to debt service on Rural Utilities Service-guaranteed Federal Financing Bank notes. From time to time, we may deposit additional funds into the Cushion of Credit Account.2017,2023, we had only one financial agreement in place containing a liquidity covenant. This covenant is in connection with the Rocky Mountain lease transaction and requires us to maintain minimum liquidity of $50 million at all times during the term of the lease. We had sufficient liquidity to meet this covenant in 20172023 and expect to have sufficient liquidity to meet this covenant in 2018.2024. For a discussion of the Rocky Mountain lease transaction, see Note 4 of Notes to Consolidated Financial Statements.2017,2023, we had $8.2$12.1 billion of outstanding debt secured equally and ratably under our first mortgage indenture, a decreasean increase of $71.8 million$0.2 billion from December 31, 2016.2022. 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.Loan. In 2014, we entered into a loan guarantee agreement withLoans. We have loans from the Federal Financing Bank guaranteed by the Department of Energy that we expect will fund $3.1to provide funding for over $4.6 billion of the cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4. The loan is being funded byBy the Federal Financing Bank and is backed by a federal loan guarantee provided byend of 2022, we had fully advanced the $4.6 billion available under the Department of Energy. AtEnergy-guaranteed loans, and as of December 31, 2017, we had borrowed $1.72023, $4.2 billion including capitalized interest, under this loan and we had the capacity to fund an additional $918 million under the facility based on the amount of eligible project costs already incurred. Our last advance under this loanthese loans was in December 2016. Following the bankruptcy of Westinghouse in March 2017, the loan guarantee agreement was amended to restrict advances pending the satisfaction of certain conditions, including the Department of Energy's approval of the Bechtel Agreement and a further amendment to the loan guarantee agreement to incorporate provisions related to the Bechtel Agreement and other replacement agreements. While not assured, we expect to satisfy these conditions in the second quarter of 2018. In September 2017, the Department of Energy issued a conditional commitment to us for $1.6 billion of additional guaranteed funding under the loan guarantee agreement. This additional funding is subject to an amendment and restatement of the loan guarantee agreement, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of certain other conditions and final approval and issuance of the additional loan guarantee cannot be assured. The conditional commitment expires on June 30, 2018, subject to any extension approved by the Department of Energy. We expect to close on this facility in the second quarter of 2018. If closed, our aggregate Department of Energy loan financing for the Vogtle expansion project will increase to nearly $4.7 billion.this loan,these loans, see Note 77a of Notes to Consolidated Financial Statements. At December 31, 2017,had fundedhave raised $3.2 billion of debt in the aggregate approximately $3.1 billion of our Vogtle project cost. In additioncapital markets and expect to raise long-term financing for the Department of Energy funding, we have issued $1.4 billion of first mortgage bonds to finance the portion of the Vogtle expansion that willremaining amounts not be funded by the Department of Energy. Depending onEnergy-guaranteed loans in the final Vogtle project cost andcapital markets.final amount advanced under therelated promissory notes, we began principal repayments of our Department of Energy-guaranteed loan, there may beloans in February 2020. As of December 31, 2023, we had repaid $455.1 million under these loans and we expect to repay a need for additional capital market financing. We currently have As of December 31, 2023, we had one approved Rural Utilities Service-guaranteed loan totaling $630.3 million to fund general and environmental improvements that had $182.3 million remaining to be advanced. When advanced, the debt will be secured ratably under our first mortgage indenture. In September 2023, we received a conditional loan commitment for a new Rural Utilities Service-guaranteed loan totaling $755.2 million that we expect to begin advancing in late 2024. In February 2024, we received two approvedadditional conditional commitments for new Rural Utilities Service-guaranteed loans totaling $678$87.9 million that areand $17.5 million, respectively, for the Washington County andvarious stages of being drawn down, with $481 million remaining to be advanced. The two loans include a $448 million loan that we closed in January 2018 to fund general and environmental improvements.late 2024. As of December 31, 2017,2023, we had $2.5$2.7 billion of debt outstanding under various Rural Utilities Service-guaranteed loans, a decrease of $124.4$95.4 million from December 31, 2016.October 2017, the Development Authorities of Burke, Heard and Monroe Counties in GeorgiaDecember 2023, we issued on our behalf, $122.6$400 million of variable rate pollution control revenue bonds.6.20% first mortgage bonds, Series 2023A, to provide long-term financing for expenditures related to the construction of Vogtle Units No. 3 and No. 4. The bonds were directly purchased by a bankare due to mature in December 2053 and the proceeds were used to repay outstanding commercial paper that we issued in January 2017 in connection with the redemption of a like amount of our remaining auction rate pollution control revenue bonds. In December 2017, the Development Authority of Burke County, Georgia issued, on our behalf, $399.8 million of variable rate pollution control revenue bonds, which were directly purchased by two banks and the proceeds were used to defease various series of pollution control revenue bonds issued in 2008 that became callable on January 1, 2018. On February 1, 2018, the bank held bonds were remarketed to investors, with $200 million of the bonds converted to a fixed rate mode and the remaining $199.8 million converted to term rate modes. All the pollution control revenue bonds are secured ratably with all other debt under our first mortgage indenture.20182024 through 2020.2026. Actual expenditures may vary from the estimates listed in the table because of factors such as changes in business conditions, design changes and rework required by regulatory bodies, delays in obtaining necessary regulatory approvals, construction delays, changing environmental requirements, and changes in cost of capital, equipment, material and labor.(dollars in millions) 2024 2025 2026 Total $ 212 $ 1 $ 1 $ 214 431 391 204 1,026 14 19 31 64 133 121 140 394 General Plant 10 6 3 19 Total $ 800 $ 538 $ 379 $ 1,717 2018 2019 2020 Total $ 918 $ 1,007 $ 810 $ 2,735 134 111 113 358 114 43 30 187 79 69 78 226 10 10 9 29 $ 1,255 $ 1,240 $ 1,040 $ 3,535 Units No. 3 andUnit No. 4, excluding initial nuclear fuel, core.and our Walton acquisition. Forecasted Vogtle Unit No. 4's expenditures are based on an assumed in-service datesdate of November 2020 for Vogtle Unit No. 3 and November 2021 for Vogtle Unit No. 4.PlantsPlant Scherer, and Wansley, including to comply with coal ash regulations.onfor existing nuclear units and initial nuclear fuel core for Vogtle UnitsUnit No. 3 and No.4.4. In additionthe amounts reflectedmeet projected load growth that are not included in the table above, we have budgeted approximately $1.3 billion to complete construction of Vogtle Units No. 3 and No. 4 beyond the years shown in the table. Forabove. If our members approve one or more new generation resources, our projected capital expenditures could increase significantly.thisthe Vogtle project, see "BUSINESS – OUR POWER SUPPLY RESOURCES – Future Power Resources – Plant Vogtle Units No. 3 and No. 4" and "–Financing Activities."PlantsPlant Scherer and Wansley choose to comply with any future legislation or regulations, both capital expenditures and operating expenditures may be impacted. As required by the wholesale power contracts, we expect to be able to recover from our members all capital and operating expenditures made in complying with current and future environmental regulations.–Environmental.– Environmental." Contractual Obligations. The table below reflects, as of December 31, 2017, our contractual obligations for the periods indicated. 2018 2019-
2020 2021-
2022 Beyond
2022 Total $ 210 $ 891 $ 379 $ 6,866 $ 8,346 306 572 604 4,042 5,524 22 30 23 93 168 5 4 – – 9 – – – 36 36 19 3 – – 22 11 18 46 2,912 2,987 138 189 163 816 1,306 $ 711 $ 1,707 $ 1,215 $ 14,765 $ 18,838 (1)Includes principal amounts that would be due if the credit support facilities for the Series 2009 and Series 2010 pollution control bonds were drawn upon and became payable in accordance with their terms, such as would occur if the credit facility providing the support were not renewed or extended at its expiration date. These amounts equal $18.7 million in 2018, $37.4 million in 2019, $170.9 million in 2020 and $18.7 million in 2021. We anticipate extending these credit facilities before their expirations. The nominal maturities of the Series 2009 and Series 2010 pollution control bonds range from 2030 through 2038.(2)Includes interest expense related to variable rate debt. Future variable rates are based on projected LIBOR and SIFMA interest rate curves as of February 2018.(3)Amounts represent total rental payment obligations, not amortization of debt underlying the leases.(4)We have entered into an Equity Funding Agreement for a third party to fund this obligation.(5)A substantial portion of this amount relates to the decommissioning of nuclear facilities.(6)Includes commitments for the procurement of coal, nuclear fuel and natural gas related transportation agreements. Contracts for coal and nuclear fuel procurement, in most cases, contain provision for price escalations, minimum purchase levels and other financial commitments.Inflation As with utilities generally, inflation has the effect of increasing the cost of our operations and construction program. Operating and construction costs have been less affected by inflation over the last few years because rates of inflation have been relatively low. Our Ratings S&P Moody'sFitchMoody's FitchBBB+ A-Baa1 Baa1A-BBBBBB+ A-Baa2 Baa2N/R(2)BBBStable NegativeStable StableStablePositiveA-2 A-2P-2 P-2F2
unsecured; however, pricing of our $1.2 billion syndicated line of credit is determined based on our unsecured or issuer ratings.unsecured.(2)N/R indicates no rating assigned for this category.2017,2023, our maximum potential collateral requirements were as follows:a total of $54$50 million at a senior secured level of BBB-/Baa3,a total of $83$80 million at a senior secured level of BB+/Ba1 or below, anda total of $0.3 million at a senior unsecured or issuer level of BBB-/Baa3,•a total of approximately $60$53 million at a senior unsecured or issuer rating level of BB+/Ba1 or below.ourcredit agreements and pollution control bond agreements contain provisions based on our ratings that, upon a credit rating downgrade belowlinelines of credit agreements are based on credit ratings and could increase if our ratings are lowered. None of these covenants and provisions, however, would result in acceleration of any debt due to credit rating downgrades.Off-Balance Sheet Arrangements We do not currently have any material off-balance sheet arrangements. and external relations. The risk management and compliance committee has implemented comprehensive risk management policies to manage and monitor credit, market price, and other corporate risks. These policies also specify controls and authorization levels related to various risk management activities. The committee frequently meets to review corporate exposures, risk management strategies, hedge positions, and compliance matters. The audit committee of our board of directors receives regular reports on corporate exposures, risk management and compliance activities and the actions of the risk management and compliance committee. For further discussion of our board of director's oversight of risk management and compliance, see "DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE – Board of Directors' Role in Risk Oversight." At December 31, 2017, we wererelatedrelating to a portion of our $959debt. We categorize our debt as variable rate, which is debt that is subject to a change in interest rates within the next year, intermediate-term fixed rate debt, which is debt that is not subject to a change in interest rates within the next year, but is subject to a change in interest rates within the next five years, or long-term fixed rate debt, which is debt that is not subject to a change in interest rates within the next five years. At December 31, 2023, we had $799.3 million of variable rate debt, which includes $190.6$312.8 million of intermediate-term fixed rate debt, and the remainder of our debt was long-term fixed rate debt. Our $799.3 million of variable rate debt at December 31, 2023, included $607.9 million of commercial paper outstanding (which typically has maturities of between 1 and 90 days) and $768 million of pollution control bond debt (including variable rate demand bonds subject to repricing weekly and indexed variable rate bonds). On February 1, 2018, we converted the interest rate mode on $399.8$191.4 million of pollution control bonds from a(indexed variable rate mode intobonds, which are subject to repricing weekly). Our $312.8 million of intermediate-term fixed interest rate modes, including both fixeddebt at December 31, 2023 consisted of term rate debt subject to maturityremarketing and fixed for a term of five or seven years. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition –Financing Activities –Bond Financings."2017,2023, the weighted average interest rate on thisour variable rate debt excluding the $399.8 million in pollution control bonds that was subsequently converted to fixed rates, was 1.85%5.5%. If, during 2018,2023, interest rates on this debt changed a hypothetical 100 basis points on the respective repricing dates and remained at that level for the remainder of the year, annual interest expense would change by approximately $6$7.7 million.2017, excluding the $399.8 million in pollution control bonds that was subsequently converted to fixed rates,2023, we had 6.63%6.3% of our total debt, including commercial paper, in aclassified as variable rate mode.significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures particularlyand planned debt refinancings, such as for the constructionremaining issuance of long-term debt related to Vogtle Units No. 3 and No. 4, and for recent and upcoming acquisitions, as well as the short-term debt we are using for interim financing of this project.Equity Price RiskCommission (see Note 1 of Notes to Consolidated Financial Statements).Commission. We also maintain an internal reserve for decommissioning (included in "Long-term investments" on the balanceTable For further discussion on our nuclear decommissioning trust funds, see Note 1 of Contents20172023 would result in a loss of value to the funds of approximately $34$81.7 million. For further discussion onnuclearcoal ash pond retirement obligations and for major maintenance expenses. We invest a portion of our coal ash decommissioning trustand major maintenance accounts in fixed income funds see Note 1that are subject to changes in market value. A 10% decrease in the market value of Notes to Consolidated Financial Statements.Coal1,501982 megawatts of coal-fired nameplate capacity at Plants Scherer and Wansley.Plant Scherer. We purchase coal under term contracts and in spot-market transactions. Some of our coal contracts provide volume flexibility and most have fixed or capped prices. Our existing contracts willand stockpile are expected to provide fixed prices for up to 87%100% and 60% of our remaining 2018 forecasted coal requirements at Plants Scherer. We currently do not have any fixed price contracts for Plant Wansley2024 and will utilize the spot market to meet its coal requirements.eighteleven gas fired generation facilities totaling 4,170over 5,200 megawatts of nameplate capacity. See "PROPERTIES – Generating Facilities" and "BUSINESS – OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources –Smarr EMC."approximately 1819 of our members have elected to participate in our natural gas hedging program. This program layers in fixed prices for a portion of our forecasted natural gas requirements over a rolling time horizon of up to five and a half years. Natural gas swap arrangements are used for hedging20172023 was a net liabilityasset of approximately $6.3$13.4 million, which represents the net amount we would have paidreceived if the swaps had been terminated as of that date. As of December 31, 2017,2023, approximately 35%27% of our 20182024 total system forecasted natural gas requirements were hedged under swap arrangements. A hypothetical 10% decline in the market price of natural gas would have resulted in a decrease of approximately $23.2$27.4 million to the fair value of our natural gas swap agreements. Additional members may elect to participate in our natural gas hedging program, and participating members may choose to discontinue their active participation in this program at any time.pricevalue of equity securitiesinvestments we hold, and commodity prices have not changed materially from the previous reporting period.Page Page6020172023 and 2016 and Accumulated Other Comprehensive (Deficit) Margin, , For the Years Ended December 31, 2017, 2016,2023, 2022, and 20152017, 20162023, 2022 and 2015
2021(dollars in thousands) 2023 2022 2021 Operating revenues: Sales to members $ 1,681,566 $ 1,974,683 $ 1,557,109 Sales to non-members 58,619 155,454 47,754 Total operating revenues 1,740,185 2,130,137 1,604,863 Operating expenses: Fuel $ 578,794 $ 1,045,089 $ 598,996 Production 413,312 468,754 410,708 Depreciation and amortization 330,449 283,774 275,346 Purchased power 74,657 82,516 69,346 Accretion 65,907 55,953 56,086 Total operating expenses $ 1,463,119 $ 1,936,086 $ 1,410,482 Operating margin $ 277,066 $ 194,051 $ 194,381 Other income: Investment income $ 70,252 $ 57,564 $ 45,932 Amortization of deferred gains 1,789 1,789 1,789 Allowance for equity funds used during construction 750 700 385 Other 8,258 12,191 23,148 Total other income $ 81,049 $ 72,244 $ 71,254 Interest charges: Interest expense $ 515,862 $ 455,474 $ 417,722 Allowance for debt funds used during construction (234,090) (262,573) (221,463) Amortization of debt discount and expense 10,553 11,690 11,595 Net interest charges $ 292,325 $ 204,591 $ 207,854 Net margin $ 65,790 $ 61,704 $ 57,781 (dollars in thousands) 2017 2016 2015 $ 1,433,830 $ 1,506,807 $ 1,219,052 366 424 130,773
1,434,196
1,507,231
1,349,825
473,184 513,258 441,738 401,374 434,306 457,264 224,098 217,534 168,920 59,996 54,108 56,925 36,674 32,361 26,108 – – (58,588 ) 1,195,326 1,251,567 1,092,367 238,870 255,664 257,458
56,122 51,656 40,424 1,788 1,788 1,788 784 788 675 6,291 2,671 9,143 64,985 56,903 52,030
374,345 366,892 354,269 (134,319 ) (116,634 ) (108,667 ) 12,552 11,964 15,545 252,578 262,222 261,147
$
51,277
$
50,345
$
48,341
62STATEMENTS OF COMPREHENSIVE MARGINFor the years ended BALANCE SHEETS2017, 20162023 and 20152022(dollars in thousands) 2023 2022 Assets Electric plant: In service $ 14,112,098 $ 9,266,627 Right-of-use assets--finance leases 302,732 302,732 Less: Accumulated provision for depreciation (5,418,738) (5,183,589) Electric plant in service, net 8,996,092 4,385,770 Nuclear fuel, at amortized cost 389,662 388,303 Construction work in progress 3,294,641 7,716,035 Total electric plant 12,680,395 12,490,108 Investments and funds: Nuclear decommissioning trust fund 641,239 540,716 Investment in associated companies 82,133 78,937 Long-term investments 690,732 669,479 Other 35,585 32,561 Total investments and funds 1,449,689 1,321,693 Current assets: Cash and cash equivalents 490,592 595,381 Restricted cash and short-term investments — 104,431 Short-term investments 143,931 61,702 Receivables 201,784 220,015 Inventories, at weighted average cost 337,045 297,951 Prepayments and other current assets 18,335 51,409 Total current assets 1,191,687 1,330,889 Deferred charges and other assets: Regulatory assets 1,131,489 1,212,305 Prepayments to Georgia Power Company 13,722 20,873 Other 57,869 113,502 Total deferred charges 1,203,080 1,346,680 Total assets $ 16,524,851 $ 16,489,370 (dollars in thousands) 2017 2016 2015
$
51,277
$
50,345
$
48,341 – (428 ) (410 ) 370 – –
$
51,647
$
49,917
$
47,931
6320172023 and 2016
2022(dollars in thousands) 2023 2022 Equity and Liabilities Capitalization: Patronage capital and membership fees $ 1,257,917 $ 1,192,127 Long-term debt 11,600,917 11,512,513 Obligations under finance leases 43,586 52,937 Obligation under Rocky Mountain transactions 29,862 27,945 Other 5,152 2,256 Total capitalization 12,937,434 12,787,778 Current liabilities: Long-term debt and finance leases due within one year 384,426 322,102 Short-term borrowings 607,885 655,650 Accounts payable 117,272 203,705 Accrued interest 106,355 105,452 Member power bill prepayments, current 31,406 54,443 Other current liabilities 111,109 153,941 Total current liabilities 1,358,453 1,495,293 Deferred credits and other liabilities: Asset retirement obligations 1,458,937 1,343,743 Member power bill prepayments, non-current 47,133 53,877 Regulatory liabilities 706,320 792,190 Other 16,574 16,489 Total deferred credits and other liabilities 2,228,964 2,206,299 Total equity and liabilities $ 16,524,851 $ 16,489,370 Commitments and Contingencies (Notes 1, 7, 10, 11 and 12) (dollars in thousands) 2017 2016
$ 8,886,407 $ 8,786,839 (4,302,332 ) (4,115,339 ) 4,584,075 4,671,500
358,562
377,653 2,935,868 3,228,214 7,878,505 8,277,367
445,055 386,029 74,981 72,783 140,622 99,874 653,585 221,122 22,562 20,730 1,336,805 800,538
397,695 366,290 229,324 247,006 156,781 155,042 266,219 259,831 18,884 32,919 1,068,903 1,061,088
585,084 545,387 45,575 3,948 13,267 12,785 643,926 562,120 $ 10,928,139 $ 10,701,113
64BALANCE SHEETS
STATEMENTS OF CAPITALIZATION20172023 and 2016
2022(dollars in thousands) 2023 2022 Secured Long-term debt: First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.03% to 8.21% (average rate of 3.38% at December 31, 2023) due in quarterly installments through 2048 $ 2,663,385 $ 2,758,753 First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.44% to 4.01% (average rate of 2.94% at December 31, 2023) due in quarterly installments through 2044 4,177,967 4,325,395 First mortgage bonds payable: 300,000 300,000 500,000 500,000 400,000 400,000 1,010 2,021 450,000 450,000 300,000 300,000 250,000 250,000 250,000 250,000 250,000 250,000 500,000 500,000 450,000 450,000 500,000 500,000 400,000 — First mortgage notes issued in connection with the sale of pollution control revenue bonds through the Development Authorities of Appling, Burke and Monroe Counties, Georgia: 212,760 212,760 91,645 91,645 200,000 200,000 100,000 100,000 99,785 99,785 Total Secured Long-term debt $ 12,096,552 $ 11,940,359 Obligations under finance leases 52,937 61,335 Obligation under Rocky Mountain transactions 29,862 27,945 Other 5,152 2,256 Patronage capital and membership fees 1,257,917 1,192,127 Subtotal $ 13,442,420 $ 13,224,022 Less: long-term debt and finance leases due within one year (384,426) (322,102) Less: unamortized debt issuance costs (97,850) (96,588) Less: unamortized bond discounts on long-term debt (22,710) (17,554) Total capitalization $ 12,937,434 $ 12,787,778 (dollars in thousands) 2017 2016
$ 911,087 $ 859,810 – (370 )
7,927,562
7,892,836 87,192 92,096 20,051 18,765 8,945,892 8,863,137
216,694 316,861 190,626 102,168 212,868 73,801 79,510 93,634 6,171 176,988 55,136 59,979 761,005 823,431
734,997 698,051 203,615 48,115 – 40,008 251,649 197,748 30,981 30,623 1,221,242 1,014,545 $ 10,928,139 $ 10,701,113
65CAPITALIZATION
CASH FLOWS20172023, 2022 and 2016
2021(dollars in thousands) 2023 2022 2021 Cash flows from operating activities: Net margin $ 65,790 $ 61,704 $ 57,781 Adjustments to reconcile net margin to net cash provided by operating activities: Depreciation and amortization, including nuclear fuel $ 441,926 $ 451,899 $ 400,681 Accretion cost 65,907 55,953 56,086 Amortization of deferred gains (1,789) (1,789) (1,789) Allowance for equity funds used during construction (750) (700) (385) Deferred outage costs (32,390) (30,926) (30,746) (Gain) loss on sale of investments (6,954) 21,950 (13,516) Gain on sale of spare parts — — (15,734) Regulatory deferral of costs associated with nuclear decommissioning (21,449) (54,529) (19,318) Other (5,150) (712) (2,528) Change in operating assets and liabilities: Receivables 12,011 (68,550) (5,693) Inventories (38,562) (36,235) 23,232 Prepayments and other current assets (2,211) 25,031 577 Accounts payable (104,164) 7,008 31,790 Accrued interest 903 9,042 23,976 Accrued taxes 1,087 52,764 (36,301) Other current liabilities (65,795) 32,300 (14,292) Rate management program (billing credits applied) collections, net (56,612) 19,847 144,763 Other (57,281) 2,217 (38,078) Total adjustments $ 128,727 $ 484,570 $ 502,725 Net cash provided by operating activities $ 194,517 $ 546,274 $ 560,506 Cash flows from investing activities: Property additions $ (474,952) $ (1,156,383) $ (1,203,050) Plant acquisition (16,743) (86,826) (233,156) Activity in nuclear decommissioning trust fund – Purchases (535,027) (204,500) (675,153) – Proceeds 520,986 194,046 667,344 Proceeds from the sale of spare parts — — 18,500 Decrease in restricted investments 74,031 246,022 167,535 Activity in other long-term investments – Purchases (262,712) (185,092) (433,532) – Proceeds 199,200 107,082 246,256 Other 13,782 4,040 14,843 Net cash used in investing activities $ (481,435) $ (1,081,611) $ (1,430,413) Cash flows from financing activities: Long-term debt proceeds $ 506,272 $ 1,414,925 $ 757,032 Long-term debt payments (358,477) (397,162) (468,577) (Decrease) increase in short-term borrowings, net (47,765) (440,321) 712,473 Other 51,699 2,526 44,618 Net cash provided by financing activities 151,729 579,968 1,045,546 Net (decrease) increase in cash, cash equivalents and restricted cash $ (135,189) $ 44,631 $ 175,639 Cash, cash equivalents and restricted cash at beginning of period 625,781 581,150 405,511 Cash, cash equivalents and restricted cash at end of period $ 490,592 $ 625,781 $ 581,150 Supplemental cash flow information: Cash paid for – Interest (net of amounts capitalized) $ 278,952 $ 182,066 $ 170,605 Supplemental disclosure of non-cash investing and financing activities: Change in asset retirement obligations $ 63,803 $ 10,486 $ 107,677 Accrued property additions at end of period $ 39,854 $ 79,204 $ 65,686 (dollars in thousands) 2017 2016
$
2,456,864
$
2,581,281
1,735,586
1,678,442 2,411 3,347
First Mortgage Bonds, 5.534%, due 2031 through 2035 300,000 300,000
First Mortgage Bonds, 6.191%, due 2024 through 2031 500,000 500,000
First Mortgage Bonds, 6.10%, due 2019 350,000 350,000
First Mortgage Bonds, 5.95%, due 2039 400,000 400,000
Clean renewable energy bond, 1.81%, due 2024 7,072 8,083
First Mortgage Bonds, 5.375% due 2040 450,000 450,000
First Mortgage Bonds, 5.25% due 2050 300,000 300,000
First Mortgage Bonds, 4.20% due 2042 250,000 250,000
First Mortgage Bonds, 4.55% due 2044 250,000 250,000
First Mortgage Bonds, 4.25% due 2046 250,000 250,000
Auction rate bonds, fully redeemed January 2017 – 95,230
Auction rate bonds, fully redeemed January 2017 – 11,525
Auction rate bonds, fully redeemed January 2017 – 15,865
Fixed rate bonds, 5.30% to 5.70%, fully defeased December 2017 – 255,035
Fixed rate bonds, 7.00%, fully defeased December 2017 – 144,750
Weekly rate bonds, 1.65% to 1.75%, due 2030 through 2038 112,055 112,055
Weekly rate bonds, 1.70% to 1.72%, due 2036 through 2037 133,550 133,550
Term rate bonds, 2.40% through April 1, 2020, due 2038 through 2040 212,760 212,760
Indexed put bonds–weekly reset, 2.56% due 2040 through 2045 122,620 –
Indexed put bonds–monthly reset, 1.69% due 2041 through 2045 200,000 –
Indexed put bonds–weekly reset, 2.56% due 2041 through 2045 199,785 –
– 419 – 2,181 $ 8,232,703 $ 8,304,523 94,358 98,531 20,051 18,765 911,087 859,810 – (370 ) 9,258,199 9,281,259 (216,694 ) (316,861 ) (87,802 ) (93,133 ) (7,811 ) (8,128 ) $ 8,945,892 $ 8,863,137
66CASH FLOWS
PATRONAGE CAPITAL AND MEMBERSHIP FEES2017, 20162023, 2022 and 2015
2021(dollars in thousands) Balance at December 31, 2020 $ 1,072,642 Components of comprehensive margin in 2021: Net margin 57,781 Balance at December 31, 2021 $ 1,130,423 Components of comprehensive margin in 2022: Net margin 61,704 Balance at December 31, 2022 $ 1,192,127 Components of comprehensive margin in 2023: Net margin 65,790 Balance at December 31, 2023 $ 1,257,917 (dollars in thousands) 2017 2016 2015 $ 51,277 $ 50,345 $ 48,341 374,411 362,716 313,320 36,674 32,361 26,108 (1,788 ) (1,788 ) (1,788 ) (784 ) (788 ) (675 ) (40,644 ) (40,599 ) (40,803 ) – – (58,588 ) (18,614 ) 96 (34,464 ) (2,605 ) (20,440 ) 21,532 (9,240 ) (7,286 ) (8,353 ) (1,182 ) (24,578 ) (98 ) (6,388 ) 23,947 (28,403 ) 614 (2,172 ) (4,317 ) 129,187 (76,495 ) (37,155 ) (14,124 ) 34,804 (11 ) (1,531 ) 1,102 3,731 (8,646 ) (11,937 ) 2,805 (15,317 ) 6,155 20,994 420,023 275,098 173,835 471,300 325,443 222,176 (1,019,695 ) (613,019 ) (495,426 ) 1,104,000 – – (450,113 ) (395,506 ) (558,568 ) 442,989 389,011 553,654 (432,463 ) (86,432 ) (16,301 ) 17,682 6,198 (6,076 ) (108,704 ) (61,200 ) (89,263 ) 78,356 50,529 86,563 (43,056 ) 13,554 (13,068 ) (411,004 ) (696,865 ) (538,485 ) 544,503 790,385 423,637 (677,641 ) (114,702 ) (162,903 ) 88,458 (159,310 ) 27,109 15,789 8,301 4,113 (28,891 ) 524,674 291,956 31,405 153,252 (24,353 ) 366,290 213,038 237,391 $ 397,695 $ 366,290 $ 213,038 $ 251,186 $ 212,574 $ 240,817 $ 2,414 $ 63,011 $ 144,161 $ (28,457 ) $ (50,775 ) $ 119,775 $ 57,144 $ 47,814 $ 36,021
67 OF PATRONAGE CAPITAL AND MEMBERSHIP FEES ANDACCUMULATED OTHER COMPREHENSIVE (DEFICIT) MARGIN2017, 20162023, 2022 and 2015
2021 (dollars in thousands) Patronage
Capital and
Membership
Fees Accumulated
Other
Comprehensive
(Deficit) Margin Total $ 761,124 $ 468 $ 761,592
48,341 – 48,341 – (410 ) (410 ) 47,931
$
809,465
$
58
$
809,523
50,345 – 50,345 – (428 ) (428 ) 49,917
$
859,810
$
(370
)
$
859,440
51,277 – 51,277 – 370 370 51,647
$
911,087
$
–
$
911,087 The accompanying notes are an integral part of these consolidated financial statements.NOTES TO CONSOLIDATED FINANCIAL STATEMENTSFor the years ended December 31, 2017, 2016 and 20157,1157,792 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns 728733 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 119756 megawatts of capacity, including 86724 megawatts sourced by solar energy. Georgia Power Company is a co-owner and the operating agent of our nuclear and coal-fired generating units. Our members in turn distribute energy on a retail basis to approximately 4.1 million people.20172023 and 20162022 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2017.2023. 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. Certain fair value hierarchy disclosures have been revised to conform to the current period classification. Securities previously classified as "US Treasury and government agency securities" under Level 1 in the fair value hierarchy totaling $37,884,000 as of December 31, 2016 in the fair value table of Note 2 are now presented under Level 2 as "Mortgage backed securities" and "Federal agency securities." These changes do not impact the investment portfolio or the fair value of the assets that are recorded in the financial statements.generation.2017, 20162023, 2022 and 2015,2021, we achieved a margins for interest ratio of 1.14.OperatingRevenue recognition Electricity 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.whenby 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 provided. Operating revenues from sales to members consist primarilysatisfied over time as the customer simultaneously receives and consumes the benefit of electricity sales pursuant to long-term wholesale power contracts which we maintain with eachthese services. Both performance obligations are provided directly by us and not through a third party.members. These wholesale power contracts obligate each membermembers is obligated to pay us for capacity and energy furnishedwe furnish under its wholesale power contract in accordance with rates we establish. Capacity revenues recoverWe 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.chargedrecognized 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. CapacityNon-member capacity revenues are billed and recognized in accordance with the terms of the associated contract.an annual budget and, notwithstanding budget adjustmentsour avoided cost of borrowing. For additional information regarding our member prepayment program, see Note 1p.meetdeliver energy as energy is delivered to the applicable meter points. We determine the standard selling price for energy we deliver to our targeted margin, are recorded in approximately equal amounts throughoutmembers based upon the year. Energy revenues recover variable costs such as fuel, incurred to generate or purchase electricitythat energy. Fuel expense is the primary variable cost. Energy revenue recognized equals the actual variablerecordedrequired 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 energyrevenue 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 energyfixed costs incurred. Priorand targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to 2016, operatingdetermine 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 salesnon-members.non-members consisted primarily of energy sales at Smith.(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 2017, 20162023, 2022 or 2015:2021:2023 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 % (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 2017 2016 2015 14.7 % 14.3 % 9.7 % 14.3 % 13.7 % 13.1 % n/a 10.5 % 10.4 % certaininterest 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. The Vogtle program allows for the recovery of financing costs associated with the construction of Vogtle Units No. 3 and No. 4 on a current basis. Under this program, amounts billed to participating members in 2017, 20162023, 2022 and 20152021 were $11,000,000, $16,096,000$9,261,000, $14,796,000 and $7,630,000,$15,693,000, respectively. The cumulative amount billed since inception of the program totaled $54,087,000. Prior$135,693,000.2016, members also subscribed torecover future expense on a current basis from our members. In general, the Smith program which allowed for additional collections over a five-year period with those amounts then applied to billings over the accelerated recoverysubsequent 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 deferredthe 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 costs related to Smith. The Smith program ceased as of December 31, 2015 when the plant became available for scheduling to our members. The amountbilling credits and amounts billed to participating members underduring 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 2015 was $17,745,000the 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 $58,922,000.electricitycapacity 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. Member receivablesReceivables from contracts with our members at December 31, 20172023, 2022 and 20162021 were $126,211,000$170,901,000, $187,401,000 and $136,552,000,$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.Uncollectible amounts, ifOur 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.are identified on a specific basis and charged to expense in the period the amounts are determined to be uncollectible.2017, 20162023, 2022 and 20152021 amounted to $90,520,000, $83,751,000,$84,192,000, $73,871,000, and $78,762,000,$77,366,000, respectively. On December 14, 2014,Court of Federal Claims issued a judgmentgovernment in favor of Georgia Power, as agent for the co-owners, to recover spent nuclear fuel storage costs at Plants Hatch and Vogtle Units No. 1 and No. 2 covering the period of 2005 through 2010. Our ownership share of the $36,474,000 total award was $10,949,000, which was received in April 2015. The effects of the award were recorded during the first quarter of 2015 and resulted in a $7,320,000 reduction in total operating expenses, including reductions to fuel expense and production costs, as well as a $3,629,000 reduction to plant in service. On October 10, 2017, Georgia Power, as agent for the co-owners filed a separate claim2014 (as amended) seeking damages for spent nuclear fuel storage costs at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 covering athe 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.In addition,On August 13, 2020, Georgia Power previously filed a separate claimamended complaints in each of the lawsuits against the U.S. government in the Court of Federal Claims for damages from January 1, 2018 to cover periodsDecember 31, 2019.2013 which was subsequently amended and extended through December 31, 2014.2019 are approximately $84,000,000. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts werehave been recognized in the consolidated financial statements as of December 31, 20172023 or December 31, 2022 for this claim.these claims. The final outcome of these matters cannot be determined at this time.FacilitiesWe expect that facilities at both plants can be expanded to accommodate spent fuel through the expected life of each plant.facilities.facilities and coal ash ponds. In addition, we have retirement obligations related to coal ash ponds, 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.20152020, 2021 and 2016,2023, respectively.Asset Retirement Obligationsasset retirement obligations included in the consolidated balance sheets for the years 20172023 and 2016.(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 (dollars in thousands) Nuclear Coal Ash
Pond Other Total $ 517,565 $ 156,465 $ 24,021 $ 698,051 (17 ) (943 ) (1,185 ) (2,145 ) 31,026 4,629 1,019 36,674 – 1,604 813 2,417 $ 548,574 $ 161,755 $ 24,668 $ 734,997 (dollars in thousands) Nuclear Coal Ash
Pond Other Total $ 488,458 $ 93,622 $ 20,150 $ 602,230 – (553 ) (707 ) (1,260 ) 29,107 2,215 1,039 32,361 – 61,181 3,539 64,720 $ 517,565 $ 156,465 $ 24,021 $ 698,051 The estimated costsOur most recent assessment of decommissioning are based on the most current study performednuclear asset obligation for Plant Hatch and Plant Vogtle Units No. 1 and No. 2, which occurred in 2015. In projecting future costs, the escalation rate for labor, materials and equipment was assumed to be 2.5%. The increase2021 resulted in a slight decrease in the cash flow estimatesobligation 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 2015 was primarily attributableMarch 2023, we recognized a new nuclear asset retirement obligation for Plant Vogtle Unit No. 3 totaling $62,841,000. We expect to security costs, waste disposal costs and inflation, among other factors.record an asset retirement obligation of approximately $65,000,000 for Plant Vogtle Unit No. 4 in the first quarter of 2024. Our portion ofwerefor which we have recorded asset retirement obligations as of December 31, 2023 are as follows:(dollars in thousands) 2021 site study Hatch
Unit No. 1Hatch
Unit No. 2Vogtle
Unit No. 1Vogtle
Unit No. 2Expected 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
Unit No. 3Expected 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 (dollars in thousands) Hatch
Unit No. 1 Hatch
Unit No. 2 Vogtle
Unit No. 1 Vogtle
Unit No. 2 2034 2038 2047 2049 $ 193,000 $ 213,000 $ 178,000 $ 195,000 49,000 47,000 49,000 47,000 16,000 22,000 26,000 33,000 $ 258,000 $ 282,000 $ 253,000 $ 275,000 Ash Pond. On April 17, 2015 the Environmental Protection Agency published its final coalCombustion Residuals. Coal combustion residuals (CCR) rule which regulates CCRs as non-hazardous materials under Subtitle Dare 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 Resource Conservation and Recovery Act. The rule took effect on October 19, 2015. Our most current assessment of the final CCR rulecoal ash pond asset retirement obligation resulted in a $1,604,000 change$321,000 increase and a $16,301,000 increase in cash flow estimates for coal ash pond decommissioning.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 rule.regulations. The 2017 and 2016 increases2022 increase in cash flow estimates werewas primarily attributeddue to an increase inthe Georgia Public Service Commission's approval of Georgia Power's request to revise the closure cost estimates.of the Plant Wansley coal ash pond from in-place to removal. Additional adjustments to the asset retirement obligations are expected periodically as we continuedue to assesspotential changes in estimates and assumptions.impactfunds 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.rule, including potential changes, onassociated decommissioning fund are recorded directly to the regulatory asset in accordance with our estimates and assumptions. Other.ratemaking treatment.In 2017As a result of nuclear fuel load for Plant Vogtle Units No. 3 and 2016, no additional amounts wereNo. 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 which are classified as available-for-sale, 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.sheet. In both 2017sheets. We contributed $10,000,000 and 2016, we contributed $4,750,000$8,350,000 into the internal funds.20172023 and December 31, 2016.2022. The funds arewere invested in60%71% equity and 40%29% fixed income securities for both 2017in 2023 and 2016.2023 External Trust Funds: (dollars in thousands) Cost
12/31/2022Purchases 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 2017 12.31.16
Cost Purchases Net
Proceeds(1) Unrealized
Gain(Loss) 12.31.17
Fair Value $ 200,595 $ 61,406 $ (44,607 ) $ 76,221 $ 293,615 148,011 388,609 (384,199 ) 170 $ 152,591 351 98 (1,600 ) – $ (1,151 ) $ 348,957 $ 450,113 $ (430,406 ) $ 76,391 $ 445,055 12.31.16
Cost Purchases Net
Proceeds(1) Unrealized
Gain(Loss) 12.31.17
Fair Value $ 38,798 $ – $ 4,900 $ 11,669 $ 55,367 26,207 73,153 (65,820 ) – $ 33,540 $ 65,005 $ 73,153 $ (60,920 ) $ 11,669 $ 88,907 and dividends, contributions and fees of $31,939,680.2023 Internal Funds: (dollars in thousands) Cost
12/31/2022Purchases Unrealized
Gain(Loss)Fair Value
12/31/2023Equity $ 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 2016 12.31.15
Cost Purchases Net
Proceeds(2) Unrealized
Gain(Loss) 12.31.16
Fair Value $ 198,265 $ 46,865 $ (43,395 ) $ 38,749 $ 240,484 144,187 347,383 (343,040 ) (1,675 ) $ 146,855 187 1,258 (2,754 ) (1 ) $ (1,310 ) $ 342,639 $ 395,506 $ (389,189 ) $ 37,073 $ 386,029 12.31.15
Cost Purchases Net
Proceeds(2) Unrealized
Gain(Loss) 12.31.16
Fair Value $ 33,513 $ – $ 5,285 $ 7,263 $ 46,061 25,539 42,783 (42,115 ) (211 ) $ 25,996 $ 59,052 $ 42,783 $ (36,830 ) $ 7,052 $ 72,057
$13,542,000.(2)and dividends, contributions and fees of $12,270,144.2022 External Trust Funds: (dollars in thousands) Cost
12/31/2021Purchases Unrealized
Gain(Loss)Fair Value
12/31/2022Equity $ 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 2022 Internal Funds: (dollars in thousands) Cost
12/31/2021Purchases Unrealized
Gain(Loss)Fair Value
12/31/2022Equity $ 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 6.4%6.2% in the last ten years and 6.3%6.0% since inception in 1990. Based on current funding and cost study estimates, we expect the current balances and anticipated investment earningsstandardprescribed depreciation rates as well as site specific rates determined through depreciation studies as approved by the Rural Utilities Service. The 2017 and 2016 depreciation rates for steam, nuclear and nuclearother production in the table below reflect revised rates from depreciation rate studies completed in 2015.2020 or 2021. Site specific depreciation studies are performed every five years. Annual weighted average depreciation rates in effect in 2017, 20162023, 2022, and 20152021 were as follows:Remaining Useful Life Range in
years*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% Range of
Useful Life in
years* 2017 2016 2015 49-65 2.91 % 2.84 % 1.93 % 37-60 1.96 % 1.96 % 1.55 % 50 2.00 % 2.00 % 2.00 % 27-33 2.58 % 2.55 % 2.38 % 36 2.75 % 2.75 % 2.75 % 3-50 2.00-33.33 % 2.00-33.33 % 2.00-33.33 %
expiration date of the applicable operating license approved by the NRC.CalculatedBased on estimated retirement dates as of 2023. Actual retirement dates may be different. Remaining useful lives for nuclear production are based on the composite depreciation rates in effect for 2017.2017, 20162023, 2022 and 20152021 was $218,027,000, $211,282,000,$321,047,000, $278,452,000, and $180,866,000,$269,280,000, respectively.ended 2017, 20162023, 2022 and 2015,2021, the allowance for funds used during construction rates were 4.45%4.18%, 4.61%4.03% and 4.73%3.90%, respectively.plus cost of removal, less salvage of such property, is charged to the accumulated provision for depreciation. Cost of removal, less salvage, is charged to a regulatory liability, accumulated retirement costs for other assets. Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are charged to expense, including certain major maintenance costs at our natural gas-fired plants.consistconsisted of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds on deposit earn interest at a rate of 5% per annum. At December 31, 2017 and 2016, we had restricted investments totaling $882,909,000 and $468,179,000, respectively, of which $653,585,000 and $221,122,000, respectively,Account that were classified as long-term. The funds on deposit with the Rural Utilities Service in the Cushion of Credit Account are held by the U.S. Treasury, acting through the Federal Financing Bank.Classification Twelve months ended December 31, 2023 December 31, 2022 (dollars in thousands) Cash and cash equivalents $ 490,592 $ 595,381 Restricted cash included in restricted cash and short-term investments — 30,400 Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows $ 490,592 $ 625,781 20172023 and December 31, 2016,2022, fossil fuels inventories were $54,050,000$74,149,000 and $57,289,000,$64,386,000, respectively. Inventories for spare parts at 20172023 and 20162022 were $212,169,000$262,896,000 and $202,542,000,$233,565,000, respectively. Other deferredprimarilyand other assets represent advance depositsregulatory assets, long-term prepayments to Georgia Power Company related to the Vogtle construction project and progress payments for equipment associated with future nuclear refueling outages.January 2023,December 2028, with the majority of the balance scheduled to be credited by the end of 2019. During 2016,2025.connection with the Vogtle Units No. 3Note 1h and No. 4 construction project, we were accruing long-term contract retainage amounts for substantial and mechanical milestones. As a result of a settlement agreement entered into by Georgia Power Company and the Co-owners and Toshibaregulatory liabilities in June 2017, these contract retainage amounts were reversed. For more information regarding the Vogtle construction project, see Note 8.members, whichmembers. These contracts extend through December 31, 2050.2085. Regulatory liabilities represent certain items of(dollars in thousands) 2023 2022 Regulatory Assets: Premium and loss on reacquired debt(a) $ 25,476 $ 29,494 Amortization on financing leases(b) 28,780 31,908 Outage costs(c) 30,040 29,317 Asset retirement obligations – Ashpond and other(l) 343,523 353,212 Asset retirement obligations – Nuclear(l) — 32,192 Depreciation expense - Plant Vogtle(d) 34,125 35,549 Depreciation expense - Plant Wansley(e) 335,884 361,784 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f) 55,159 54,701 Interest rate options cost(g) 137,463 136,827 Deferral of effects on net margin – TA Smith Energy Facility(h) 130,786 136,730 Other regulatory assets(o) 10,253 10,591 Total Regulatory Assets $ 1,131,489 $ 1,212,305 Regulatory Liabilities: Accumulated retirement costs for other obligations(i) $ 25,992 $ 35,580 Deferral of effects on net margin – Hawk Road Energy Facility(h) 16,020 16,636 Deferral of effects on net margin – BC Smith Energy Facility(p) 546 14,825 Major maintenance reserve(j) 120,547 74,584 Amortization on financing leases(b) 2,658 5,557 Deferred debt service adder(k) 170,466 154,514 Asset retirement obligations – Nuclear(l) 47,217 — Revenue deferral plan(m) 308,507 357,460 Natural gas hedges(n) 13,445 131,804 Other regulatory liabilities(o) 922 1,230 Total Regulatory Liabilities $ 706,320 $ 792,190 Net regulatory assets $ 425,169 $ 420,115 (dollars in thousands) 2017 2016 $ 52,989 $ 55,084 33,846 32,274 40,525 39,986 68,289 33,747 42,667 44,091 48,702 43,444 112,102 107,394 166,454 172,399 19,510 16,968 585,084 545,387
$ 12,813 $ 9,829 19,553 20,163 47,087 28,379 20,055 23,084 95,695 86,082 53,571 11,766 2,875 18,445 251,649 197,748 $ 333,435 $ 347,639 2620 years.andversus financial statement purposes related to capitalfinance lease payments and the aggregate of the amortization of the asset and interest on the obligation.4860 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 or 24-month operating cycles of each unit.to Vogtle Units No. 3costs, including interest and No. 4 training and interest related carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units.(f)net loss associated with the change in fair value and expired cost ofpremiums paid to purchase interest rate options purchasedused to hedge interest rates on certain borrowings, related tocarrying costs and other incidentals associated with construction of Vogtle Units No.3No. 3 and No.4 construction.No. 4. Amortization will commencecommenced in February 2020 and will be amortized through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project.(g)(h)(i)(j)(k)thedecommissioning costs of decommissioning and ashpond remediation for financial statement purposes versus ratemaking purposes, as well as the deferral of unrealized gains and losses of funds set aside for ratemaking purposes.(l)3230 years and the amortization periods of other regulatory liabilities range up to 93 years.ownowned facilities. For 2017, 2016,2023, 2022, and 2015,2021, we incurred expenses from Georgia Transmission of $28,410,000, $27,399,000,$41,426,000, $40,774,000 and $28,172,000,$39,677,000, respectively.SystemsSystem Operations. Georgia SystemsSystem Operations operates the system control center and currently provides us system operations services and administrative support services. For 2017, 2016,2023, 2022, and 2015,2021, we incurred expenses from Georgia SystemsSystem Operations of $25,597,000, $23,994,000,$30,109,000, $27,416,000, and $22,616,000,$26,936,000, respectively. The components ofwithinincreased due to the Consolidated Statementrecognition of Revenues and Expenses were as follows: (dollars in thousands) 2017 2016 2015 $ 1,531 $ 1,679 $ 1,859
6,816
6,553
6,278
(2,056
)
(5,561
)
1,006 $ 6,291 $ 2,671 $ 9,143 NewRecently issued or adopted accounting pronouncementsMay 2014,November 2023, the Financial Accounting Standards Board (FASB) issued "Revenue from Contracts with Customers"“Segment Reporting (Topic 606). The new revenue standard requires that an entity recognize revenue280): Improvements to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard is effective for us for the annual reporting period beginning after December 15, 2017 using either of the following transition methods: (i) a full retrospective approach reflecting the application ofthe standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes additional footnote disclosures). We have completed our evaluation of the new revenue standard and adopted the amendments within the new standard effective January 1, 2018. There was no cumulative impact upon adoption. The adoption of this standard is not expected to have a material impact, on an annual basis, to our revenue recognition based on our existing contracts with customers. Our evaluation process included, but was not limited to, identifying contracts within the scope of Topic 606, reviewing and documenting our accounting for these contracts and assessing the applicability of the variable consideration guidance. The vast majority of our revenue is derived from substantially identical wholesale power contracts that we have with each of our 38 members. We expect the pattern of revenue recognition pursuant to our wholesale power contracts will remain unchanged on an annual basis under the new revenue standard. Historically, our Board has approved budget adjustments, typically at year end but may be made throughout the year, that affect our annual revenue requirement. As a result, at the end of each reporting period we will determine whether the variable consideration cumulatively received from our Members exceeds the consideration to which we expect to be entitled on an annual basis. We will recognize a refund liability for the consideration which we expect to refund to our Members, if such excess consideration received would result in a significant reversal in the cumulative revenues recognized. In January 2016, the FASB issued "Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities."Reportable Segment Disclosures.” The amendments in this update address certain aspectsare intended to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant expenses. The amendments in this update require disclosures to include significant segment expenses that are regularly provided to the chief operating decision maker (CODM), a description of recognition, measurement, presentation,other segment items by reportable segment, and disclosureany additional measures of financial instruments.a segment's profit or loss used by the CODM when deciding how to allocate resources. The amendments in this update are also applicable to entities with only one reportable segment. The amendments in this update also require all annual disclosures currently required by Topic 280 to be included in interim periods. The new standard is effective for us for annual reporting periods beginning after December 15, 2017,2023 and interim periods therein. Certain provisions within this update can be adopted early. Certain provisions within this update should be applied by meansfiscal years beginning after December 15, 2024. Early adoption is permitted and requires retrospective application to all prior periods presented in the financial statements. We are currently evaluating the future impact of a cumulative effect adjustment to the balance sheet of the fiscal year of adoption and certain provisions should be applied prospectively. One of the provisions in this standard requires our equity investments, except those accounted for under the equity method of accounting or those that result in consolidation of our subsidiary, to be measured at fair value with changes in fair value recognized in net income. None of the other provisions in this standard will have any impact toon our consolidated financial statements. Effective31, 2017, we adopted regulatory accounting treatment with respect to unrealized gains and/or losses on our equity investments. Upon applying regulatory accounting treatment, unrealized gains on our equity investments will be recorded as a regulatory liability and, conversely, unrealized losses on our equity investments will be recorded as a regulatory asset, at the end of each reporting period. As of December 31, 2017, we recorded $618,000 of unrealized losses on our equity investments as a regulatory asset. On January 1, 2018, we adopted the amendments within this standard. The adoption of this standard will have no impact to our consolidated financial statements due to our regulatory accounting treatment for unrealized gains and/or losses on our equity investments. In February 2016,2023, the FASB issued "Leasesamended "Income Taxes (Topic 842)740): Improvements to Income Tax Disclosures”." The new leases standardamendments in this update requires a dual approach for lessee accounting under which a lessee would account for leases as finance leases or operating leases. Both finance leasesadditional disclosures related to the rate reconciliation, income taxes paid and operating leases will resultother amendments intended to improve effectiveness and comparability. The amendments in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee would recognize interest expense and amortization of the ROU asset and for operating leases the lessee would recognize a straight-line total lease expense. The new lease standard does not substantially change lessor accounting. The new leases standard isthis update are effective for us on a modified retrospective approach for annual reporting periods beginning after December 15, 2018,2024. Early adoption is permitted and interim periods therein. Early adoptionshould be applied on a prospective basis. Retrospective application is permitted. We are currently evaluating the future impact of this standard on our consolidated financial statements. In June 2016,statements, however, we do not anticipate the FASB issued "Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments." The amendments in this update replace the current incurred loss impairment methodology with a methodology that reflects expected credit losses. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2019, and interim periods therein. The amendments in this update canimpact will beadopted earlierfiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are currently evaluating the future impactcost basis of this standard on our consolidatedthese financial statements. In August 2016, the FASB issued "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receiptsassets is remote and Cash Payments." The amendments in this standard provide specific guidance on eight cash flow classification issues relating to how certain cash receipts and cash payments are presented and classified in the statement of cash flows, thereby reducing the current and potential future diversity in practice. The new standard is effectivewe have not recognized an allowance for us for annual reporting periods beginning after December 15, 2017, and interim periods therein. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. The amendments should be applied using a retrospective transition method to each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. As permitted, on October 1, 2017, we early adopted these amendments and applied their provisions retrospectively. The adoption of this standard had no impact on our consolidated financial statements as the amendments did not change how we present and classify the eight identified cash flow classification issues within our consolidated statement of cash flows. In November 2016, the FASB issued "Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)." The amendments in this standard require the statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statement of cash flows. The new standard is effective for us on a retrospective basis for annual reporting periods beginning after December 15, 2017, and interim periods therein. Early adoption is permitted, including adoption in an interim period. As permitted, on October 1, 2017, we early adopted these amendments and applied their provisions retrospectively. The adoption of this standard had no impact on our consolidated financial statements as we did not have any restricted cash balances in 2017 and 2016. None of our assets or liabilities measured at fair value on a recurring basis were categorized as Level 3 at December 31, 2017 or December 31, 2016. Fair Value Measurements at Reporting Date Using December 31, 2017 Quoted Prices in
Active Markets for
Identical Assets
(Level 1) Significant Other
Observable Inputs
(Level 2) (dollars in thousands) $ 142,419 $ 142,419 $ – $ 88,820 – 88,820 $ 66,317 – 66,317 $ 38,791 38,791 – $ 49,379 – 49,379 $ 47,833 47,833 – $ 92 – 92 $ 3,725 – 3,725 $ 7,679 7,679 – $ 20,071 – 20,071 $ 16,215 – 16,215 $ 6,670 6,670 – $ 7,267 – 7,267 $ 87,011 87,011 – $ 259 – 259 $ 3,129 3,129 – $ 6,328 – 6,328 Fair Value Measurements at Reporting Date Using December 31, 2023 Quoted Prices in
Active Markets for
Identical Assets
(Level 1)Significant Other
Observable Inputs
(Level 2)Significant
Unobservable Inputs
(Level 3)(dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 234,979 $ 234,979 $ — $ — International equity trust $ 134,911 — 134,911 — Corporate bonds and debt $ 67,986 — 67,900 86 US Treasury securities $ 43,917 43,917 — — Mortgage backed securities $ 58,763 — 58,763 — Domestic mutual funds $ 85,481 85,481 — — Municipal bonds $ 303 — 303 — Federal agency securities $ 7,256 — 7,256 — Non-US Gov't bonds & private placements $ 2,717 — 2,717 — International mutual funds $ 2,012 — 2,012 — Other $ 2,914 2,914 — — Long-term investments: International equity trust $ 43,202 — 43,202 — Corporate bonds and debt $ 14,151 — 14,151 — US Treasury securities $ 17,243 17,243 — — Mortgage backed securities $ 15,024 — 15,024 — Domestic mutual funds $ 378,387 378,387 — — Treasury STRIPS $ 220,765 — 220,765 — Non-US Gov't bonds & private placements $ 1,568 — 1,568 — Other $ 392 392 — — Short-term investments: Treasury STRIPS $ 143,931 — 143,931 — Natural gas swaps $ 13,445 — 13,445 — Fair Value Measurements at Reporting Date Using December 31, 2016 Quoted Prices in
Active Markets for
Identical Assets
(Level 1) Significant Other
Observable
Inputs
(Level 2) (dollars in thousands) Fair Value Measurements at Reporting Date Using Fair Value Measurements at Reporting Date Using December 31, 2022 December 31, 2022 Quoted Prices in
Active Markets for
Identical Assets
(Level 1)Significant Other
Observable
Inputs
(Level 2)Significant
Unobservable
Inputs
(Level 3)(dollars in thousands) (dollars in thousands) $ 170,408 $ 170,408 $ – $ 66,861 – 66,861 $ 60,019 – 60,019 $ 34,119 34,119 – $ 41,914 – 41,914 $ 943 – 943 $ 7,102 – 7,102 $ 4,663 4,663 – Domestic equity Domestic equity $ 15,946 – 15,946 $ 11,853 – 11,853 $ 5,909 5,909 – $ 6,844 – 6,844 $ 57,932 57,932 – $ 1,085 – 1,085 Non-US Gov't bonds & private placements International mutual funds International mutual funds $ 653 653 $ 305 305 – Long-term investments: International equity trust International equity trust International equity trust Corporate bonds and debt US Treasury securities Mortgage backed securities Domestic mutual funds Treasury STRIPS Non-US Gov't bonds & private placements Other Short-term investments: Treasury STRIPS Short-term investments: Treasury STRIPS $ 61,702 61,702 $ (15,090 ) – (15,090 ) assetmortgage backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of observable inputs. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are no unfunded commitments for the international equity trust and redemption may occur daily with a three-day3-day redemption notice period.20172023 and 20162022 were as follows (in thousands):2023 2022 (in thousands) Carrying
ValueFair
ValueCarrying
ValueFair
ValueLong-term debt $ 12,096,552 $ 10,638,749 $ 11,940,359 $ 10,194,954 2017 2016 Carrying
Value Fair
Value Carrying
Value Fair
Value $ 8,232,703 $ 9,155,942 $ 8,304,523 $ 9,043,029 estimated based on observed or quoted market prices for the same or similar issues, or based on current rates offered to us for debt of similar maturities. The primary sources of our long-term debt consist of first mortgage bonds, pollution control revenue bonds and long-term debt issued by the Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. We also have small amounts of long-term debt provided by National Rural Utilities Cooperative Finance Corporation (CFC). The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from a third party data reporting service, and are based on secondary market trading of our debt. Valuations for debt issued by the Federal Financing Bank are based on U.S.2017 and 20162023 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. The rates on the CFC debt are fixed and the valuation is based on rate quotes provided by CFC. As discussed in Note 1m, restricted investments consist of funds on deposit with the Rural Utilities ServiceCushionmarket price of Credit Account. The carrying amount approximates fair value because of the liquid nature of the deposits with the U.S. Treasury.3. Derivative instruments:risk management and compliance activities, including but not limited to, commodity trading, investment portfolio managementand interest rate risk management. We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas.derivative activities. We do not apply hedge accounting for any of these derivatives,to derivative transactions, but instead apply regulatoryregulated operations accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps are reflected as regulatory assets or liabilities, as appropriate. hedging arrangements. Credit risk is the potential loss resulting from a counterparty's nonperformance under an agreement. We have established policies and procedures to manage credit risk through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and certain other contractual provisions.20172023 all of the counterparties with transaction amounts outstanding under our hedgingderivative programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade.hedgederivative counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement). Gas hedges.20172023 and 2016,2022, the estimated fair valuevalues of our natural gas contracts were a net liabilityassets of $6,328,000$13,445,000 and a net asset of $15,090,000,$131,804,000, respectively.2017 and 2016, neither we nor any counterparties2023, none of our counterparties were required to post credit support or collateral under theunder our natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements were triggered onAs of December 31, 2017 due to2022, one of our credit rating being downgraded below investment grade, we would have beencounterparties was required to post letterscredit collateral totaling $30,400,000 under our natural gas swap agreements. Such posted collateral was classified as restricted cash and included in the Restricted cash and short-term investments line item within our consolidated balance sheets.20172023 that is expected to settle or mature each year:Year Natural Gas
Swaps
(MMBTUs)(in millions) 2024 32.4 2025 25.1 2026 20.9 2027 10.3 2028 — Total 88.7 Natural Gas
Swaps
(MMBTUs) (in millions) 27.1 18.9 16.1 13.1 7.9 83.1 Interest rate options. In fourth quarter of 2011, we purchased seventeen LIBOR swaptions at a cost of $100,000,000 with a total notional amount of approximately $2,200,000,000 to hedge the interest rates on a portion of the debt that we expected to incur through March 2017 to finance the two additional nuclear units at Plant Vogtle. The last of these options, having a notional value of $80,169,000, expired without value at March 31, 2017. In accordance with rate-making treatment, we deferred the premiums paid to purchase these swaptions and related carrying costs, and will continue to defer other incidentals. The deferral will continue and costs will be amortized and collected in rates from February 2020 through February 2044, corresponding with the life of the associated debt that we hedged with the swaptions.20172023 and 2016. We do not apply hedge accounting to these derivative instruments.Consolidated Balance Sheet
LocationFair Value 2023 2022 (dollars in thousands) Assets Natural gas swaps Other current assets $ — $ 35,285 Natural gas swaps Other deferred charges $ 25,459 $ 99,725 Liabilities Natural gas swaps Other current liabilities $ 10,370 $ 3,206 Natural gas swaps Other deferred credits $ 1,644 $ — Balance Sheet
Location Fair Value 2017 2016 (dollars in thousands)
Other current assets $ 412 13,833 Other deferred charges $ – 3,289
Other current liabilities $ 1,575 $ 54 Other deferred credits $ 5,165 $ 1,977 2017, 20162023, 2022 and 2015.Consolidated
Statement of
Revenues and
Expenses Location2023 2022 2021 (dollars in thousands) Natural gas swaps gains Fuel $ 2,001 $ 121,626 $ 31,440 Natural gas swaps losses Fuel (22,924) (6,587) (1,431) Total $ (20,923) $ 115,039 $ 30,009
Statement of
Revenues and
Expenses Location (dollars in thousands) Fuel $ 3,818 $ 2,445 $ 206 Fuel (1,677 ) (19,697 ) (20,102 ) $ 2,141 $ (17,252 ) $ (19,896 ) gains(gains) and (losses)losses on derivative instruments deferred on the consolidated balance sheetsheets at December 31, 20172023 and 2016.Consolidated Balance
Sheet Location2023 2022 (dollars in thousands) Natural gas swaps Regulatory liability $ 13,445 $ 131,804 Total $ 13,445 $ 131,804 Consolidated Balance
Sheet Location 2017 2016 (dollars in thousands) Regulatory asset $ (6,328 ) $ (62 ) Regulatory liability – 15,152 Regulatory asset – (5,788 ) $ (6,328 ) $ 9,302 classified as available-for-sale and are carriedrecorded at market value. Prior to October 1, 2017, unrealized gains and losses of investment securities related to nuclear decommissioning were deferred pursuant to regulated operations accounting, while those for all other investment securities were added to or deducted from accumulated other comprehensive (deficit) margin. Duringfair value in the fourth quarter of 2017, we began applyingaccompanying consolidated balance sheets. We apply regulated operations accounting to the unrealized gains and losses of all investment securities. All realized and unrealized gains and losses are determined using the specific identification method. Approximately 75%(dollars in thousands) Gross Unrealized 2023 Cost Gains Losses Fair Value Equity $ 344,669 $ 246,795 $ (5,549) $ 585,915 Debt 908,316 3,938 (25,181) 887,073 Other 2,889 61 (36) 2,914 Total $ 1,255,874 $ 250,794 $ (30,766) $ 1,475,902 (dollars in thousands) Gross Unrealized 2022 Cost Gains Losses Fair Value Equity $ 323,907 $ 159,445 $ (8,949) $ 474,403 Debt 833,035 372 (46,369) 787,038 Other 10,445 20 (9) 10,456 Total $ 1,167,387 $ 159,837 $ (55,327) $ 1,271,897 gross$25,181,000 of unrealized losses wererelates to securities that have been in effectunrealized loss positions for less than one year. (dollars in thousands) Gross Unrealized Cost Gains Losses Fair Value $ 246,549 $ 91,954 $ (4,064 ) $ 334,439 240,878 1,814 (2,262 ) 240,430 10,807 1 – 10,808 $ 498,234 $ 93,769 $ (6,326 ) $ 585,677 (dollars in thousands) Gross Unrealized Cost Gains Losses Fair Value $ 237,317 $ 51,054 $ (5,041 ) $ 283,330 201,492 1,167 (3,423 ) 199,236 3,339 – (2 ) 3,337 $ 442,148 $ 52,221 $ (8,466 ) $ 485,903 All of the available-for-sale investments are recorded at fair value in the accompanying consolidated balance sheets, therefore the carrying value equals the fair value. available-for-sale, which are included in the estimated fair value table above, at December 31, 20172023 and 20162022 are as follows:(dollars in thousands) 2023 2022 Cost Fair Value Cost Fair Value Due within one year $ 486,602 $ 477,726 $ 367,199 $ 353,180 Due after one year through five years 267,690 260,193 293,523 275,073 Due after five years through ten years 47,804 47,416 66,255 62,576 Due after ten years 106,220 101,738 106,058 96,209 Total $ 908,316 $ 887,073 $ 833,035 $ 787,038 (dollars in thousands) 2017 2016 Cost Fair Value Cost Fair Value $ 54,785 $ 54,143 $ 8,292 $ 8,268 53,050 52,834 52,452 52,054 51,367 51,600 65,657 64,971 81,676 81,853 75,091 73,943 $ 240,878 $ 240,430 $ 201,492 $ 199,236 2017, 20162023, 2022 and 2015:(dollars in thousands) 2023 2022 2021 Gross realized gains $ 15,518 $ 10,029 $ 33,501 Gross realized losses (8,564) (31,979) (19,985) Proceeds from sales 720,186 301,128 913,600 (dollars in thousands) 2017 2016 2015 $ 35,523 $ 19,934 $ 53,453 (16,909 ) (20,030 ) (18,989 ) 521,345 439,540 640,217 20172023 and 2016:(dollars in thousands) 2023 2022 National Rural Utilities Cooperative Finance Corporation (CFC) $ 24,068 $ 24,081 CT Parts, LLC 6,568 6,574 Georgia Transmission Corporation 40,806 38,287 Georgia System Operations Corporation 6,500 7,750 Other 4,191 2,245 Total $ 82,133 $ 78,937 (dollars in thousands) 2017 2016 $ 24,056 $ 24,049 10,243 10,250 28,690 27,285 8,500 7,500 3,492 3,699 $ 74,981 $ 72,783 investments.investments and they are valued at cost. The investment in Georgia Transmission represents capital credits.credits valued at cost. The investment in Georgia System Operations represents loan advances. Repayments of these advances are due by December 2022.$47,882,000.2023 2022 2021 Statutory federal income tax rate 21.0 % 21.0 % 21.0 % Patronage exclusion (21.0) % (21.0) % (21.0) % Effective income tax rate 0.0 % 0.0 % 0.0 % 2017 2016 2015 35.0 % 35.0 % 35.0% (34.1 %) (34.7 %) (34.7%) (2.2 %) 0.0 % 0.0% (0.9 %) (0.3 %) (0.3%) (2.2 %) 0.0 % 0.0% The tax benefit reflected in the effective income tax rate reconciliation relates to the approximate $1,117,000 current tax benefit realized in 2017 as a result of monetizing the remaining balance of alternative minimum tax credits. This benefit is as a result of a refundable credit, and since it is applied after considering the patronage dividend deduction, it is not allocated to our members, but instead is a source of cash to the taxpayer applied against its normal operating expenses. The benefit is shown as a component of production operating expenses on the statement of revenues and expenses.20172023 and 20162022 were as follows: (dollars in thousands) 2017 2016 $ 19,668 $ 29,724 – 599 231,268 349,127 75,013 109,793 325,949 489,243 (19,668 ) (29,724 ) $ 306,281 $ 459,519
$ 271,652 $ 435,570 114,514 170,402 78,407 123,121 464,573 729,093 158,292 269,574 (158,292 ) (269,574 ) $ – $ – (dollars in thousands) 2023 2022 Deferred tax assets Net operating losses $ 109,447 $ 115,080 Obligation related to asset retirements 375,530 345,879 Advance payments 176,956 183,833 Other regulatory liabilities 23,652 18,687 Other assets 30,085 30,373 Deferred tax assets 715,670 693,852 Less: Valuation allowance — — Net deferred tax assets $ 715,670 $ 693,852 Deferred tax liabilities Fixed assets and intangibles $ (154,219) $ (140,095) Right-of-use assets-finance leases (77,923) (77,923) Other regulatory asset (373,802) (343,230) Other liabilities (15,679) (15,352) Deferred tax liabilities (621,623) (576,600) Net deferred tax assets (liabilities) $ 94,047 $ 117,252 Less: Patronage exclusion (94,047) (117,252) Net deferred taxes $ — $ — 2017,2023, we have federal tax net operating loss carryforwards and alternative minimum tax credits as follows: (dollars in thousands) Alternative
Minimum
Tax Credits NOLs $ – $ 61,533 – 10,516 – 4,362 $ – $ 76,411 The net operating loss expiration dates start in the year 2018 and end in the year 2020.of $425,203,000 which may be carried forward indefinitely. Due to the tax basis method for allocating patronage dividends, and as shown bywe will utilize this loss to offset any future federal taxable income prior to member allocation per the above valuation allowance, itbylaws. There is not more likely than not thatno net impact to the deferred tax asset related toafter the net operating losses will be realized. On December 18, 2015, the Protecting Americans from Tax Hikes (PATH) Act was signed into law. The PATH Act allowed us to accelerate and monetize AMT credits in lieu of bonus depreciation through the tax year ended December 31, 2019. The remaining credit of $599,000 will be claimed on the tax return filed for the tax year ended December 31, 2017. On December 22, 2017, following its passage by the United States Congress, the President signed into law Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, or the Act. The Act will make significant changes to U.S. federal income tax laws. The Act reduces the federal tax rate for corporations from 35% to 21% effective January 1, 2018 and changes or applies limitations to certain tax deductions. As of December 31, 2017, we have not completed our accounting for the tax effects upon enactment of the Act; however we have been able to make a reasonable estimate of the effects on our existing deferred tax balances. We have remeasured the deferred tax assets and liabilities to reflect the applicable tax rate expected to be in effect when the timing differences reverse, which is 21%. No net impact to the results of operations was recorded as a result of this remeasurment, however the impact to the components of the net deferred tax assets and liabilities is reflected in the above table. We continue to analyze the impact of this tax reform legislation which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts, however we do not believe it will have a material impact on the company's results of operation or cash flows.20142020 and forward. State jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state jurisdictions include 20142020 and forward. We have no liabilities recorded for uncertain tax positions.Capital leases: In 1985,Leases:sold and subsequently leased back from four purchasers theirhave a relatively small portfolio of leases with the most significant being our 60% undivided ownership interest in Scherer Unit No. 2. The gain2 and railcar leases for the transportation of coal. We also have various other leases of minimal value.the sale is being amortizedshort-term leases, leases having an initial term of 12 months or less, for any class of underlying asset. We recognize lease expense for short-term leases on a straight-line basis over the termslease term. Lease expense recognized for our short-term leases during 2023 and 2022 was insignificant.theour Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the lease,leases, we can elect at our sole discretion to:lessors The minimum lease payments under the capital leases together with the present value of the net minimum lease payments as of December 31, 2017 are as follows: (dollars in
thousands) $ 22,424 14,949 14,949 14,949 7,474 92,905
167,650
(73,292
)
94,358
(7,166
)
$
87,192 The Scherer No. 2 lease is reported as a capital lease. For rate-making purposes, however, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the capital leaseright-of-use asset and the interest on the capitalfinance lease obligation is recognized as a regulatory asset. CapitalFinance lease amortization is recorded in depreciation and amortization expense.Classification 2023 2022 (dollars in thousands) Right-of-use assets - Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (278,586) (272,876) Total finance lease assets $ 24,146 $ 29,856 Lease liabilities - Finance leases Obligations under finance leases $ 43,586 $ 52,937 Long-term debt and finance leases due within one year 9,351 8,398 Total finance lease liabilities $ 52,937 $ 61,335 Classification 2023 2022 (dollars in thousands) Right-of-use assets - Operating leases Electric plant in service, net $ 6,587 $ 3,326 Total operating lease assets $ 6,587 $ 3,326 Lease liabilities - Operating leases Capitalization - Other $ 5,152 $ 2,256 Other current liabilities 1,529 1,164 Total operating lease liabilities $ 6,681 $ 3,420 2023 2022 (dollars in thousands) Lease Cost Classification Finance lease cost: Amortization of leased assets Depreciation and amortization $ 8,398 $ 7,542 Interest on lease liabilities Interest expense $ 6,551 $ 7,408 Operating lease cost $ 1,441 $ 995 Total lease cost $ 16,390 $ 15,945 December 31, 2023 December 31, 2022 Lease Term and Discount Rate Weighted-average remaining lease term (in years): Finance leases 5.26 5.94 Operating leases 5.77 6.44 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 6.37 % 5.52 % 2023 2022 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 6,551 $ 7,408 Operating cash flows from operating leases $ 1,410 $ 1,009 Financing cash flows from finance leases $ 8,398 $ 7,541 Right-of-use assets obtained in exchange for new operating lease liabilities $ 4,503 $ 1,954 (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2024 $ 14,949 $ 1,913 $ 16,862 2025 14,949 1,703 16,652 2026 14,949 1,412 16,361 2027 14,949 1,134 16,083 2028 3,052 1,026 4,078 Thereafter 7,633 795 8,428 Total lease payments $ 70,481 $ 7,983 $ 78,464 Less: imputed interest (17,544) (1,302) (18,846) Present value of lease liabilities $ 52,937 $ 6,681 $ 59,618 2023 2022 (dollars in thousands) Lease income $6,776 $6,539 , and first mortgage notes issued in conjunction with the sale by public authorities of pollution control revenue bonds (PCBs) and first mortgage notes payable to CFC.(PCRBs). Substantially all of our owned tangible and certain of our intangible assets are pledged under our first mortgage indenture as collateral for the Federal Financing Bank notes, the first mortgage bonds, and the first mortgage notes issued in conjunction with the sale of pollution control revenue bonds, and the CFC first mortgage notes.capitalfinance lease obligations through 20222028 are as follows:(dollars in thousands) 2024 2025 2026 2027 2028 FFB $ 311,565 $ 284,714 $ 265,177 $ 242,177 $ 283,089 FMBs 63,510 62,500 62,500 62,500 62,500 PCRBs — — — — — $ 375,075 $ 347,214 $ 327,677 $ 304,677 $ 345,589 Finance Leases 9,351 10,413 11,595 12,912 2,153 Total $ 384,426 $ 357,627 $ 339,272 $ 317,589 $ 347,742 (dollars in thousands) 2018 2019 2020 2021 2022 $ 188,857 $ 157,105 $ 172,189 $ 177,383 $ 180,754 1,010 351,010 1,010 1,010 1,010 18,677 37,352 170,902 18,676 – 984 1,035 391 – – $ 209,528 $ 546,502 $ 344,492 $ 197,069 $ 181,764 7,166 5,462 6,082 6,722 7,541 $ 216,694 $ 551,964 $ 350,574 $ 203,791 $ 189,305 (1)In addition to regularly scheduled principal payments on the bonds, this includes amounts that would be due if the standby letters of credit supporting the Series 2009 and Series 2010 bonds were drawn upon and became payable in accordance with their terms, such as would occur if the credit facility the letters of credit were issued under was not renewed or extended at its expiration date. These amounts equal $18.7 million in 2018, $37.4 million in 2019, $170.9 million in 2020 and $18.7 million in 2021. We anticipate extending these credit facilities before their expiration. The nominal maturities of the Series 2009 and Series 2010 pollution control bonds range from 2030 through 2038.20172023 and 20162022 was 4.17%3.89% and 4.34%3.78%, respectively.20172023 and 2016December 31, 2022 are as follows:2023 2022 Principal Unamortized Debt
Issuance Costs
and
Debt DiscountsPrincipal Unamortized Debt
Issuance Costs
and
Debt Discounts(dollars in thousands) FFB $ 6,841,352 $ 51,083 $ 7,084,148 $ 52,690 FMBs 4,551,010 60,987 4,152,021 52,480 PCRBs 704,190 8,490 704,190 8,972 $ 12,096,552 $ 120,560 $ 11,940,359 $ 114,142 2017 2016 Principal Unamortized Debt
Issuance Costs
and
Debt Discounts Principal Unamortized Debt
Issuance Costs
and
Debt Discounts (dollars in thousands) $ 4,192,450 $ 51,593 $ 4,259,723 $ 55,754 3,057,072 34,673 3,058,083 36,717 980,770 9,347 980,770 8,789 2,411 – 3,347 – – – 2,600 – $ 8,232,703 $ 95,613 $ 8,304,523 $ 101,260 (the Title XVII Loan Guarantee Program), we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 (as amended, the Loan Guarantee Agreement) pursuant to which thethea Note Purchase Agreement, dated as of February 20, 2014 (the Original Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank in the aggregate amount of $3,057,069,461 (the Original FFB Notes and together with the Original Note Purchase Agreement, the Original FFB Credit Facility Documents). TheCredit FacilityNote and together with the Additional Note Purchase Agreement, the Additional FFB Documents). multi-advance term loan facility (the Facility), under which we may make long-term loan borrowings through the Federal Financing Bank. Proceedsborrowed a total of advances made$4,633,028,088. We received our final advance under the Facility will be used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3in December 2022. Interest is payable quarterly in arrears and No. 4 that are eligible for financingprincipal payments on all advances under the Title XVII Loan Guarantee Program. AggregateFFB Notes began in February 2020. As of December 31, 2023, we have repaid $455,060,646 of principal on the FFB Notes and the aggregate Department of Energy-guaranteed borrowings outstanding, including capitalized interest, totaled $4,177,967,442. The final maturity date is February 20, 2044. We may voluntarily prepay outstanding borrowings under the FacilityFacility. Under the FFB Documents, any prepayment will be subject to a make-whole premium or discount, as applicable. Any amounts prepaid may not exceed $3,057,069,461, of which $335,471,604 is designated for capitalized interest.the Department of Energyit is required to make any payments to the Federal Financing Bank under theits guarantee. Our payment obligations to the Federal Financing Bank under the FFB Notes and reimbursement obligations to the Department of Energy under its guarantee, but not our covenants to the Department of Energy under the Loan Guarantee Agreement, are secured equally and ratably with all of our other notes and obligations issued under our first mortgage indenture. The final maturity date for each advance is February 20, 2044. Interest is payable quarterly in arrears and principal payments will begin on February 20, 2020. Under both FFB Notes, the interest rates during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%. At December 31, 2017, aggregate Department of Energy-guaranteed borrowings totaled $1,735,586,000, including capitalized interest. Pursuant to the amended terms of the Loan Guarantee Agreement, we are restricted from receiving further advances until certain conditions are met, including Department of Energy approval of the Bechtel Agreement (as defined in Note 8) and the Department of Energy and we enter into an amendment to the Loan Guarantee Agreement to incorporate provisions relating to the Bechtel Agreement and other replacement agreements. While not assured, we expect to satisfy these conditions in the second quarter of 2018. When these conditions are satisfied, advances may be requested under the Facility on a quarterly basis through December 31, 2020. In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, including certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of updated project-related information, our continued ownership of our interest in Vogtle Units No. 3 and No. 4 free and clear of any liens except those permitted under the Loan Guarantee Agreement, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act, as amended, and certification from the Department of Energy's consulting engineer that proceeds of the advance are used to reimburse eligible project costs. Under the Loan Guarantee Agreement, upon the occurrence ofEnergy may require usEnergy's option we will be required to prepayrepay the outstanding principal amount of all guaranteed borrowings under the Facility over a period of five years, with level(ii)(iii) termination of the Services Agreement as defined in Note 8 or rejection of the Services Agreement in bankruptcy, if Georgia Power does not maintain access to certain related intellectual property rights, (iii) a decision(iv) termination of the Services Agreement by us notWestinghouse or termination of the Bechtel Agreement by Bechtel Power Corporation, (v) delivery of certain notices by the Co-owners to continuethe Department of Energy of their intent to cancel construction of Vogtle Units No. 3 and No. 4 (iv)coupled with termination by the Co-owners of the Services Agreement or the Bechtel Agreement, (vi) failure of the Co-owners to enter into a replacement contract with respect to the Services Agreement or the Bechtel Agreement following the Co-owners' termination of such agreement with the intent to replace it, (vii) the Department of Energy's takeover of construction of Vogtle Units No. 3 and No. 4 under certain conditions, (viii) the occurrence of any Project Adverse Event that results in a cancellation of the Vogtle Units No. 3 and No. 4 project or the cessation or deferral of construction beyond the periods permitted under the Loan Guarantee Agreement, (ix) loss of or failure to receive necessary regulatory approvals under certain circumstances, (v)(x) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (vi)(xi) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve consecutive months, (vii)(xii) change of control of Oglethorpe and (viii)(xiii) certain events of loss or condemnation. We may also voluntarily prepay outstanding borrowings under the Facility. Under the FFB Credit Facility Documents, any prepayment will be subject to a make-whole premium or discount, as applicable. On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to approximately $1,620,000,000 of additional guaranteed funding under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any extension approved by the Department of Energy. Final approval and issuance of this additional loan guarantee by the Department of Energy cannot be assured and is subject to negotiation of definitive agreements, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of other conditions.2017,2023, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $22,098,000$70,272,000 for long-term financing of general and environmental improvements at existing plants.January 2018,February 2024, we received an additional $2,636,000$6,067,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants.Pollution Control Revenue Bonds: On October 12, 2017, the Development Authority of Burke County (Georgia), the Development Authority of Heard County (Georgia) and the Development Authority of Monroe County (Georgia) issued, on our behalf, $122,620,000 (Series 2017A Burke, Heard and Monroe and 2017B Burke) in aggregate principal amount of tax-exempt pollution control revenue bonds to refinance costs associated with certain of our pollution control facilities. The bonds were directly purchased by a bank and the proceeds were used to repay outstanding commercial paper issued to redeem certain auction rate pollution control revenue bonds in January 2017. Each series of bonds bears interest at an indexed variable rate until October 3, 2022, the initial mandatory tender date. Bonds that are not remarketed by the initial mandatory tender date will be returned to the holders thereof and will be subject to mandatory redemption on October 2, 2023. These pollution control revenue bonds are scheduled to mature in 2040 through 2045. Our payment obligations related to these bonds are secured under our first mortgage indenture. On December 28, 2017, the Development Authority of Burke County (Georgia) issued, on our behalf, $399,785,000 (Series 2017C, D, E, F Burke) in aggregate principal amount of tax-exempt pollution control revenue bonds to refinance costs associated with certain of our pollution control facilities. The bonds were directly purchased by two banks and the proceeds defeased our obligations under $399,785,000 of pollution control revenue bonds issued in 2008 that were callable on or after January 1, 2018. Those 2008 bonds were fully redeemed on their call date. Each series of the 2017 bonds bore interest at an indexed variable rate until February 1, 2018 when we converted the bonds into fixed interest rate modes. We converted the (i) $200,000,000 Series 2017C and Series 2017D bonds to a fixed rate of 4.125% per annum to maturity with an optional call at par on February 1, 2028, (ii) $100,000,000 Series 2017E bonds to a fixed term rate of 3.25% per annum to the mandatory tender date of February 3, 2025 and (iii) $99,785,000 Series 2017F bonds to a fixed term rate of 3.00% per annum to the mandatory tender date of February 1, 2023. The Series 2017C, D, E, F bonds are scheduled to mature in 2041 through 2045. Our payment obligations related to these bonds are secured under our first mortgage indenture.
Credit Facilities:d)2017,2023, we had a total of $1,610,000,000$1,810,000,000 of committed credit arrangements comprised of four separate facilities with maturity dates that range from October 20182024 to March 2020.December 2028. These credit facilities are for general working capital purposes, issuing letters of credit and backing up outstanding commercial paper. Under our unsecured committed lines of credit that we had in place at December 31, 2017,2023, we had the ability to issue letters of credit totaling $760,000,000$960,000,000 in the aggregate, of which $509,000,000$957,000,000 remained available. At December 31, 2017,2023, we had 1) $251,000,000(i) $2,504,000 under these lines of credit in the form of issued letters of credit supporting variable rate demand bonds and collateral postings to third parties, and 2) $191,000,000(ii) $611,000,000 dedicated under one of these lines of credit to support a like amountface value of commercial paper that was outstanding.
d)First Mortgage Bonds:TableContentsweighted averagebonds are due to mature December 2053 and are secured under our first mortgage indenture.on short-term borrowings at December 31, 2017modes until February 1, 2028 and December 31, 2016 was 1.58% and 0.93%, respectively.20172023 and 20162022 is as follows:2023 2022 (dollars in thousands) Plant Investment Accumulated
DepreciationInvestment Accumulated
DepreciationOwned property $ 3,035,806 $ (1,948,158) $ 3,024,112 $ (1,916,942) 4,771,526 (43,418) 58,189 (8,627) 1,019,809 (559,001) 991,852 (533,771) 24,710 (27,152) 20,312 (15,337) 1,372,241 (660,580) 1,378,904 (636,799) 148,902 (127,378) 145,780 (124,306) 618,955 (308,827) 616,278 (296,624) 233,662 (131,434) 232,532 (125,092) 272,416 (79,985) 269,837 (74,685) 308,837 (167,033) 301,869 (162,137) 343,531 (168,292) 324,310 (171,272) 352,005 (126,886) 339,189 (121,318) 689,198 (228,997) 686,517 (208,142) 171,034 (92,498) 170,432 (88,585) 32,987 (16,379) — — Transmission plant 122,452 (65,784) 107,992 (64,785) Other 101,061 (60,710) 106,424 (65,922) Property under finance lease: 795,698 (606,226) 794,830 (569,245) Total in-service $ 14,414,830 $ (5,418,738) $ 9,569,359 $ (5,183,589) Construction work in progress Vogtle Unit No. 4 $ 3,128,720 $ 7,583,291 Environmental and other
generation improvements165,921 132,744 Total construction work in progress $ 3,294,641 $ 7,716,035 2017 2016 (dollars in thousands) Investment Accumulated
Depreciation Investment Accumulated
Depreciation
(Nuclear – 30% ownership) $ 2,916,852 $ (1,751,558 ) $ 2,885,559 $ (1,712,642 )
(Nuclear – 30% ownership) 36,745 (2,514 ) 36,163 (1,567 )
(Nuclear – 30% ownership) 824,890 (420,000 ) 809,971 (407,400 )
(Fossil – 30% ownership) 587,436 (236,155 ) 577,781 (190,974 )
(Fossil – 60% ownership) 1,102,085 (399,774 ) 1,083,772 (368,948 ) 136,351 (106,370 ) 135,849 (102,642 )
(Hydro – 75% ownership) 609,048 (246,758 ) 607,742 (234,765 ) 225,808 (104,269 ) 227,878 (104,342 ) 251,671 (73,998 ) 250,595 (69,984 ) 292,250 (128,344 ) 290,790 (119,874 ) 313,587 (133,378 ) 313,693 (123,946 ) 642,732 (170,366 ) 614,453 (176,701 ) 3,887 (3,552 ) 3,582 (3,569 ) 92,929 (55,502 ) 92,085 (53,251 ) 92,179 (54,927 ) 99,644 (61,356 )
757,957 (414,867 ) 757,282 (383,378 )
$
8,886,407
$
(4,302,332
)
$
8,786,839
$
(4,115,339
)
$ 2,721,949 $ 3,069,476 212,476 158,181 1,443 557
$
2,935,868
$
3,228,214 �� 20172023 of $290,725,000 and 2016December 31, 2022 of $197,000,000.The 2017 amount is net of a $1,104,000,000 credit recorded as a result of payments received from Toshiba under the Guarantee Settlement Agreement as describedNote 8b.service on July 31, 2023.Statementconsolidated statements of Revenuesrevenues and Expenses. 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. Under the terms of the EPC Agreement, the Co-owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments. Toshiba Corporation guaranteed certain payment obligations of Westinghouse under the EPC Agreement (the Toshiba Guarantee), including any liability of Westinghouse for abandonment of work. On In March 29, 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. In connection with the bankruptcy filing, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreement with Westinghouse and WECTEC Staffing Services LLC to provide for a continuation of work at Vogtle Units No. 3 and No. 4. The Interim Assessment Agreement expired onEffective in July 27, 2017, upon the effective date of the Services Agreement discussed below. Subsequent to Westinghouse's bankruptcy filing, a number of subcontractors to Westinghouse alleged non-payment by Westinghouse for amounts owed for work performed on Vogtle Units No. 3 and No. 4. Georgia Power, acting for itself and as agent for the Co-owners, has taken actions to remove liens on the site filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against Westinghouse and the Co-owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and payment of other Westinghouse pre-petition accounts payable have been paid or accrued as of December 31, 2017. On June 9, 2017, Georgia Power and the other Co-owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (the Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee was $3,680,000,000 (the Guarantee Obligations), of which our proportionate share was $1,104,000,000. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, the Co-owners, certain affiliates of the Municipal Electric Authority of Georgia, and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (the Settlement Agreement Amendment). The Settlement Agreement Amendment provided that Toshiba's remaining scheduled payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of the Co-owners and certain affiliates of the Municipal Electric Authority of Georgia against Westinghouse, and the Co-owners surrendered certain letters of credit securing a portion of Westinghouse's potential obligations under the EPC Agreement. Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement which was amended and restated on July 20, 2017 (the Services Agreement), forpursuant to which Westinghouse to transition construction management of Vogtle Units No. 3is providing facility design and No. 4 to Southern Nuclearengineering services, procurement and to provide ongoing design, engineering,technical support and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved Westinghouse's motion seeking authorization to (i) enter into the Services Agreement, (ii) assumestaff augmentation on a time and assign to the Co-owners certain project-related contracts, (iii) join the Co-owners as counterparties to certain assumed project-related contracts, and (iv) reject the EPC Agreement.materials cost basis. The Services Agreement and Westinghouse's rejection of the EPC Agreement, became effective upon approval by the Department of Energy on July 27, 2017. The Services Agreementprovides 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. Effective 23, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, wherebypursuant to which Bechtel will serveserves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement). Facility design and engineering remains the responsibility of Westinghouse under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel'sBechtel’s performance against cost and schedule targets. Each Co-owner is severally, and not jointly, liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Co-owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts
On July 31, 2023, Georgia Power placed Unit No. 3 in service.related to work performed prior to the termination (including the applicable portionbase fee), certain termination-related costs and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including, certain Co-owner suspensions of work, certain breaches of the Bechtel Agreement by the Co-owners, Co-owner insolvency and certain other events. Pursuantcost to the loan guarantee agreement between us and the Department of Energy, we are required to obtain the Department of Energy's approval of the Bechtel Agreement and further amend the loan guarantee agreement to incorporate provisions relating to the Bechtel Agreement and other replacement agreements prior to receiving any further advances. On November 2, 2017, the Co-owners entered into an amendment to their joint ownership agreements for Vogtle Units No. 3 and No. 4 (as amended, the Joint Ownership Agreements) to provide for, among other conditions, additional Co-owner approval requirements. Pursuant to the Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction if certain adverse events occur, including: (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia Public Service Commission or Georgia Power determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in Georgia Power's seventeenth Vogtle construction monitoring (VCM) report of more than $1,000,000,000 or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Joint Ownership Agreements, the required approval of holders of ownership interests inconstruct Vogtle Units No. 3 and No. 4 is at least (i) 90% for a change30%, representing approximately 660 megawatts. As of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. On December 21, 2017, the Georgia Public Service Commission took a series of actions31, 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.issued its related order on January 11, 2018. Among other actions,July 2023, respectively, the Public Service Commission (i) accepted Georgia Power's recommendation that construction of Vogtle Units No. 3 and No. 4 be completed, with Southern Nuclear Operating Company, Inc. serving as construction manager and Bechtel as primary contractor and (ii) approved the revised schedule placing Unit No. 3 in service in November 2021 and Unit No. 4 in service in November 2022. In its January 11, 2018 order, the Public Service Commission stated if certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Public Service Commission reserve the rightsite is subject to reconsider the decision to continue construction. Parties have filed two petitions with the Fulton County Superior Court appealing the Georgia Public Service Commission's January 11, 2018 order. Georgia Power has stated that it believes these appeals have no merit; however, an adverse outcome in one or both of these appeals could have a material impact on our financial condition and results of operations. We expect Vogtle Units No. 3 and No. 4 to be placed in service by November 2021 and November 2022, respectively. Our project budget for the additional Vogtle units is $7 billion, which includes capital costs, allowance for funds used during construction and a contingency amount. This budget is net of the $1,104,000,000 of payments we received from Toshiba under the Guarantee Settlement Agreement. As of December 31, 2017, our total investment in the additional Vogtle units was $2,938,000,000, net of the payments received from Toshiba under the Guarantee Settlement Agreement. The payments from Toshiba were recorded as a reduction to the construction work in progress balance for the additional Vogtle units. In the event the Vogtle project is cancelled, our proportionate share of the Co-owners' cancellation costs are estimated to be approximately $230,000,000. If the project is cancelled, we would seek regulatory accounting treatment to amortize our investment in the Vogtle project over a long-term period which would require the approval of our board of directors and the Rural Utilities Service. As construction continues, risks remain that construction-related challenges, including management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly and installation of plant systems, structuresand components, or other issues could further impact the projected schedule and cost. Aspects of the Westinghouse AP1000 design are based on new technologies and commercial operation of this design has yet to be tested. There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filedCommission’s operating reactor oversight process and approved or are pending before the Nuclear Regulatory Commission.must meet applicable technical and operational requirements contained in its operating license. Various design and other licensing-based compliance matters including the timely resolution of inspections, tests, analyses, and acceptance criteria and the related approvals by the Nuclear Regulatory Commission, may arise, which may result in additional license amendmentsamendment requests or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners.$1,436,000, $1,371,000$2,143,000, $2,017,000 and $1,310,000$1,811,000 in 2017, 20162023, 2022 and 2015,2021, respectively.Prior to 2016, the effective rate of the employer retirement contribution was 8%. Our contributions to the employer retirement contribution feature of the 401(k) plan were approximately $3,791,000, $3,678,000$5,655,000, $5,098,000 and $2,611,000$4,527,000 in 2017, 20162023, 2022 and 2015,2021, respectively.$13,400,000,000.$16.2 billion. This amount is covered by private insurance and a mandatory program of deferred premiums that could be assessed against all owners of nuclear power reactors. Such private insurance provided by American Nuclear Insurers (ANI), is carried by Georgia Power for the benefit of all the co-owners of Plants Hatch and Vogtle. Agreements of indemnity have been entered into by and between each of the co-owners and the NRC. In the event of a nuclear incident involving any commercial nuclear facility in the country involving total public liability in excess of $450,000,000$450 million, a licensee of a nuclear power plant could be assessed a deferred premium of up to $127,000,000$166 million per incident for each licensed reactor operated by it, but not more than $19,000,000$25 million per reactor per incident to be paid in a calendar year. On the basis of our ownership interest in foursix nuclear reactors, we could be assessed a maximum of $153,000,000$299 million per incident, but not more than $23,000,000$44 million in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five5 years, and exclude any applicable state premium taxes. The next scheduled adjustment is due no later than September 10, 2018.$1,500,000,000$1.5 billion for members' operating nuclear generating facilities. Additionally, there is coverage through NEIL for decontamination, excess property insurance, and premature decommissioning coverage up to $1,250,000,000$1.25 billion for nuclear losses in excess of the $1,500,000,000 primary coverage. On April 1, 2014, NEIL introduced a new excess non-nuclear policyand policies providing coverage up to $750,000,000$750 million for non-nuclear losses in excess of the $1,500,000,000$1.5 billion primary coverage.3 and No. 4. This policy provides $2,750,000,000the Vogtle owners up to $2.75 billion in limits for accidental property damage occurring during construction.portion of the current maximum annual assessment for Georgia Power that would be payable by Oglethorpe based on ownership share, is limited to approximately $40,000,000.subject(subject to normal policy limits.limits). The maximum aggregate however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3,200,000,000$3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.a. Operating leases As of December 31, 2017, our estimated minimum rentalfor our railcar leases for use at our coal-fired facilities over the next five yearsto meet fuel, transportation, maintenance and thereafter are as follows: (dollars in thousands) $ 5,277 2,923 583 – These railcar leasing costs are added to the cost of the fossil inventories and are recognized in fuel expense. Rental expenses totaled $4,919,000, $4,456,000 and $4,849,000 in 2017, 2016 and 2015, respectively. We are assessing our future railcar needs and evaluating our leasing options.b. Fuel and Georgia Power, on our behalf for coal, have entered into various long-term commitments for the procurement of coal and nuclear fuel. The contracts in most cases contain provision for price escalations, minimum and maximum purchase levels and other financial commitments. The value of the coal commitments is based on maximum coal prices and minimum volumes as provided in the contracts and does not include taxes, transportation, government impositions or railcar costs. For further discussion of total nuclear fuel expense, see Note 1g. On April 11, 2014, we signed a precedent agreementTranscontinental Gas Pipeline Company, LLC (Transco) for additionalvarious counterparties to provide firm natural gas transportation to our Smith facility.natural gas-fired facilities. The newvalue of these agreements is based on fixed rates as provided in the contracts and does not include variable costs.gas pipeline by Transco was placed into servicegas-fired facilities. In most cases, these agreements include provisions for price escalation and performance bonuses and, if applicable, are included in August 2017. Total fixed chargesthe values; timing of expenditures is based on current operational assumptions. Certain agreements contain significant cancellation for convenience penalties and, therefore, amounts in the table below include total estimated expenditures over the 25-year base term willlife of the agreement. If these agreements were terminated by us in 2024 for convenience, our cancellation obligation would be approximately $942,500,000.2017,2023, our estimated minimum long-term commitments are as follows:(dollars in thousands) Coal Nuclear Fuel Gas
TransportationMaintenance
AgreementsAsset
Retirement
ObligationsFinance and Operating Leases 2024 $ 33,810 $ 95,520 $ 66,186 $ 57,749 $ 51,378 $ 16,862 2025 15,938 36,000 67,368 43,025 39,673 16,652 2026 9,362 32,250 69,578 15,736 45,923 16,361 2027 — 28,800 73,075 3,237 59,885 16,083 2028 — 28,500 68,971 46,964 71,267 4,078 Thereafter — 45,660 835,212 269,196 5,065,526 8,428 (dollars in thousands) Coal Nuclear Fuel Gas
Transportation $ 14,809 $ 56,500 $ 66,905 7,526 32,500 60,854 4,598 25,300 57,530 – 30,900 57,481 – 26,300 48,515 – 39,600 776,587 aremay also become subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide, for certain new and modified facilities. In general, these and other types of environmental requirements are becoming increasingly stringent. dioxide.Classification (dollars in thousands) Recognized identifiable assets acquired and liabilities assumed: Electric plant in service, net $ 16,450 Other current assets 323 Other current liabilities (30) Total identifiable net assets $ 16,743 20172023 and 20162022 is as follows:First
QuarterSecond
QuarterThird
QuarterFourth
Quarter(dollars in thousands) 2023 Operating revenues $ 389,453 $ 389,389 $ 500,776 $ 460,567 Operating margin 57,006 49,987 92,317 77,756 Net margin 24,410 18,414 27,127 (4,161) 2022 Operating revenues $ 420,442 $ 533,128 $ 704,265 $ 472,302 Operating margin 57,845 54,269 64,553 17,384 Net margin 21,980 18,167 32,097 (10,540) First
Quarter Second
Quarter Third
Quarter Fourth
Quarter (dollars in thousands) $ 354,170 $ 367,119 $ 385,906 $ 327,001 69,330 69,222 68,770 31,548 21,454 21,426 20,805 (12,408 )
$ 348,161 $ 379,343 $ 431,013 $ 348,714 71,093 74,148 70,929 39,494 20,598 23,277 18,630 (12,160 ) The negative net margins in the fourth quarter of 2017 and 2016 were due to reductions to revenue requirements in order to achieve the targeted margins for interest ratio of 1.14.20172023 and 2016, and2022, the related consolidated statements of revenues and expenses, comprehensive margin, patronage capital and membership fees and accumulated other comprehensive margin (deficit) and cash flows for each of the three years in the period ended December 31, 2017,2023, and the related notes (collectively referred to as the "consolidated“consolidated financial statements"statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2023, in conformity with U.S. generally accepted accounting principles.Company'sCompany’s management. Our responsibility is to express an opinion on the Company'sCompany’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.Company'sCompany’s internal control over financial reporting. Accordingly, we express no such opinion.
the projected timing of when the assets will be retired and ultimately be decommissioned, the amount of estimated future dismantling and removal of radiated portions of the plant from service and spent fuel management costs, the factors used to reflect how the costs will escalate with inflation and the appropriate credit adjusted, risk free rate./s/ Ernst & Young LLPCompany'sCompany’s auditor since 2010.29, 201825, 202420172023 in providing a reasonable level of assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods in SEC rules and forms, including a reasonable level of assurance that information we are required to disclose in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.ourthis evaluation, under the framework in Internal Control – Integrated Framework (2013 framework) issued by Committee of Sponsoring Organizations, our management concluded that our internal control over financial reporting was effective as of December 31, 20172023 in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.2017,2023, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. None.
During the fiscal quarter ended December 31, 2023, none of our directors or “officers,” as defined in Rule 16a-1(f) under the Securities Exchange Act of 1934, adopted or terminated any “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as those terms are defined in Item 408 of Regulation S-K. As noted on the cover page of this annual report, we are a membership corporation and have no authorized or outstanding equity securities although we do have outstanding debt securities.must eachmay only be filled by a director of one of our members.that.the new candidate. Should that candidate also fail to receive a majority vote, this nomination and election process would be repeated until a nominated candidate is elected by a majority of the members.Name Age Position Executive Officers: NameAgePosition Executive Officers:Michael L. Smith 64 58President and Chief Executive Officer MichaelElizabeth B. Higgins55 Executive Vice President and Chief Financial Officer David W. PriceSorrick60 57Executive Vice President and Chief Operating Officer Elizabeth B. Higgins49Executive Vice President and Chief Financial OfficerWilliam F. Ussery 59 53Executive Vice President, Member and External RelationsAnnalisa M. Bloodworth 45 39Senior Vice President and General Counsel Lori K. Holt 62 56Senior Vice President, Fuels & Co-owned Assets James A. MessersmithJeffrey R. Swartz61 63Senior Vice President, Plant Operations Keith D. RussellHeather Teilhet48 56Senior Vice President, Capital Projects and Technical ServicesExternal AffairsJami G. Reusch 61 55Vice President, Human Resources Heather Teilhet42Vice President, Governmental Affairs
Directors:Bobby C. Smith, Jr.64Chairman and At-Large DirectorMarshall S. Millwood 74 Chairman and Member Group Director (Group 3) James I. White 6878Vice-Chairman and At-Large DirectorJimmy G. Bailey69At-Large DirectorGeorge L. Weaver70Member Group Director (Group 1) James I. WhiteJimmy G. Bailey75 At-Large Director Horace H. Weathersby III 7264At-Large Director George L. Weaver 76 Member Group Director (Group 1) Danny L. Nichols 59 53Member Group Director (Group 2) Sammy G. Simonton 82 76Member Group Director (Group 2) Randy Crenshaw 71 65Member Group Director (Group 3) M. Anthony Ham66Member Group Director (Group 3)Fred A. McWhorter 77 71Member Group Director (Group 4) Jeffrey W. Murphy 60 54Member Group Director (Group 4) Ernest A. "Chip" Jakins III 54 48Member Group Director (Group 5) Wm. Ronald Duffey 82 76Outside Director hashave entered into an employment contract with us that provides for minimum annual base salary and performance pay. See "EXECUTIVE COMPENSATION – Compensation Discussion and Analysis – Employment Agreements" for further discussion of these agreements.both the SERC Reliability Corporation and Association of Edison Illuminating Companies. Mr. Smith is also on the board of directors of the Georgia Chamber of Commerce, the Georgia Energy and Industrial Construction Consortium and for ACES Power Marketing.Michael W. Price is our Executive Vice President and Chief Operating Officer and has served in that office since February 1, 2000. In October 2008, Mr. Price's title changed from Chief Operating Officer to his current title. Mr. Price was employed by Georgia System Operations from January 1999 to January 2000, first as Senior Vice President and then as Chief Operating Officer. He served as Vice President of System Planning and Construction of Georgia Transmission from May 1997 to December 1998. He served as a manager of system control of Georgia System Operations from January to May 1997. From 1986 to 1997, Mr. Price was employed by Oglethorpe in the areas of control room operations, system planning, construction and engineering, and energy management systems. Prior to joining Oglethorpe, he was a field test engineer with the Tennessee Valley Authority from 1983 to 1986. Mr. Price has a Bachelor of Science degree in Electrical Engineering from Auburn University. Mr. Price is on the board of directors for SERC Reliability Corporation and ACES Power Marketing. and External Relations and has served in that office since October 2005. In October 2008, Mr. Ussery's title changed from Senior Vice President, Member and External Relations to his current title.Executive Vice President, Member and External Relations. In January 2020, Mr. Ussery’s title changed to Executive Vice President, Member Relations. Mr. Ussery previously served as Vice President and Assistant Chief Operating Officer of Oglethorpe from November 2003 to October 2005. Prior to joining Oglethorpe in 2001, Mr. Ussery held several key positions, including Chief Operating Officer, Vice President of Engineering and System Engineer at Sawnee Electric Membership Corporation. Mr. Ussery holds a Bachelor of Science degree in Electrical Engineering from Auburn University and an associate degree in Science from Middle Georgia College. Since March 2007, Mr. Ussery has served as a board member of the Council on Alcohol and Drugs, Inc. and previously served as its Chairman of the Board.presentlyLeadership Atlanta. She serves onas Treasurer for the Corporate Leadership Councilboard of the Fernbank Natural History Museumdirectors of Murphy-Harpst Children's Home, and is a Past-President of the Emory University School of Law Alumni Board.and has served in that capacity since January 2017.from 2017 to 2023. Ms. Holt joined us in 2009 as Vice President of Fuels and Energy. From 2002 to 2009, Ms. Holt was Managing Director of Business Development for ACES. Prior to joining ACES, she was involved with power plant development for Panda Power Funds. Ms. Holt graduated from the University of Louisville with a Bachelor of Science in Business Administration degree.James A. Messersmith2007.September 2022. Prior to joining us, Mr. Messersmith joined us in 1991 as the Assistant Plant Manager at Rocky Mountain andSwartz was promotedVice President for Power Operations for New Fortress Energy from 2021 to Plant Manager in 1994. In 2001, Mr. Messersmith2022. Prior to that, he was promoted again to the position of DirectorVice President of Plant Generation Operations for Duke Energy Florida, LLC from 2012 to 2021 and began working for other subsidiaries of Duke Energy Corporation in 2002 he became our Vice President, Plant Operations, a position he held until 2007.2001. Mr. Messersmith started his career in facility operationsSwartz graduated from the United States Naval Academy with Public Service Indiana and continued his career at St. Johns River Power Park in Jacksonville, FL prior to joining us. Mr. Messersmith holds a Bachelor of Science in Mechanical Engineering degree and is a veteran of the U.S. Navy with engineering experience in Accounting from the University of Southern Indiana and a Master in Business Administration from the University of Evansville.Keith D. Russellnuclear power.Capital Projects and Technical ServicesExternal Affairs and has served in that capacity since 2009.January 2020. Ms. Teilhet joined us in January 2017 as Vice President of Governmental Affairs. Prior to joining us, Mr. Russell spent 26 years with Southern Company Generation,Ms. Teilhet served as Vice President of Government Relations for Georgia Electric Membership Corporation from 2010 to 2016, where she represented Georgia's 41 electric cooperatives before the Georgia General Assembly, the U.S. Congress and certain regulatory agencies. Prior to joining Georgia EMC, she served as a business unitsenior staff member for Georgia Governor Sonny PerdueMaster of BusinessMasters in Public Administration degree and a Bachelor of Science degree in Mechanical Engineering from University of Alabama Birmingham.has aholds several Senior Professional certificates in Human Resources certification.Heather H. Teilhet is our Vice President, Governmental Affairs and has served in that capacity since January 2017. Prior to joining us, Ms. Teilhet served as Vice President of Government Relations for Georgia Electric Membership Corporation from 2010 to 2016, where she represented Georgia's 41 electric cooperatives before the Georgia General Assembly, the U.S. Congress and certain regulatory agencies. Prior to joining Georgia EMC, she served as a senior staff member for Georgia Governor Sonny Perdue and as a staff member for Georgia Governor Roy Barnes. Ms. Teilhet graduated from the University of Georgia and holds a Masters in Public Administration from Georgia State University.2019.2025. Mr. Bailey is a member of the compensation committee and the construction project committee. Mr. Bailey is a director of the Diverse Power Incorporated, an EMC.EMC, and served as the Chairman of Diverse Power board from 2018 to 2020. Mr. Bailey has owned and operated a construction contracting business since 1970.from 1970 to 2018. He also servesserved as Chairman of Kudzu Networks Inc., a subsidiary of Diverse Power, and iswas President of the Georgia Directors Association.2019.2025. He is a member of the compensationaudit committee. Mr. Crenshaw is President and Chief Executive Officer of Irwin Electric Membership Corporation and Middle Georgia Electric Membership Corporation. Mr. Crenshaw also serves on the board of directors for Georgia Electric Membership Corporation, where he is the Secretary-Treasurer and on the executive committee, and the Georgia Cooperative Council, where he serves as Chairman. He is also on the board of directors for Green Power EMC, Smarr EMC and GRESCO Utility Supply, IncInc. He is the former President and Chief Executive Officer of Middle Georgia Electric Membership Corporation and is a former member of the Georgia SystemsSystem Operations board of directors and former chairman of the Georgia Cooperative Council board of directors. He is also pastthe former President of the Irwin/Ocilla Chamber of Commerce and a member of the Irwin Development Board.2021.2027. He is the chairman of the audit committee and served as special liaison between senior management and the board during the search for a successor president and chief executive officer from June to November 2013. Mr. Duffey is the retired Chairman of the Board of Directors of Peachtree National Bank in Peachtree City, Georgia, a wholly owned subsidiary of Synovus Financial Corp. Prior to his employment in 1985 with Peachtree National Bank, Mr. Duffey served as Executive Vice President and a member of the board of directors for First National Bank in Newnan, Georgia. He holds a Bachelor of Business Administration degree from Georgia State College with a concentration in finance and has completed banking courses at the School of Banking of the South, Louisiana State University, the American Bankers Association School of Bank Investments, and The Stonier Graduate School of Banking, Rutgers University. Mr. Duffey is Vicethe immediate past Chair of the board of directors of Piedmont Healthcare, where he is also servesserved on the Executive Committee, Executive Performance and Compensation Committee and Governance, Nominating Committee and Nominatingwas past Chair of the Audit Committee. Mr. Duffey is also a former member of the board of directors of the Georgia Chamber of Commerce.M. Anthony Ham is a member group director (group 3). Mr. Ham has served on ourCommerce board of directors since March 2004, and his present term will expire in March 2020. He is a member of the compensation committee. Mr. Ham operates Tony Ham Elite Property Services. In December 2008, Mr. Ham left his position as the Clerk of the Superior and Juvenile Court in Brantley County, Georgia after 20 years of service. He has served as a director of Okefenoke Rural Electric Membership Corporation since 1994 and was appointed Secretary and Treasurer in 2007.2020.2026. Mr. Jakins is a memberchairman of the construction projectcompensation committee and also serves on the compensationconstruction project committee. Mr. Jakins is currently the President and Chief Executive Officer of Jacksonauditcompensation committee, for Georgia Electric Membership Corporation where he is a member of the Executive Committee and Workers Compensation Fund ExecutiveEconomic Development Committee, and for Green Power EMC. He is also a member of the Georgia Chamber of Commerce.2019.2025. He is a member of the compensation committee and the construction project committee. Mr. McWhorter serves as Chairman of the Rayle Electric Membership Corporation board of directors. Mr. McWhorter also serves on the board of directors for Georgia Electric Cooperative. He is the owner of F.A. McWhorter Poultry Farms.Vice-ChairmanChairman of the Board and an at-large director.a member group director (group 3). Mr. Millwood has served on our board of directors since March 2003, and his present term will expire in March 2021. He is the chairman of the compensation committee.2026. He has been the owner and operator of Marjomil Inc., a poultry and cattle farm in Forsyth County, Georgia, since 1998. He is a director of Sawnee Electric Membership Corporation.2021.2027. He is a member of the audit committee. Mr. Murphy has been the President and Chief Executive Officer of Hart Electric Membership2020.2026. Mr. Nichols is the chairman of the construction project committee and also serves on the compensation committee. Mr. Nichols is the General ManagerPresident/Chief Executive Officer of Colquitt Electric Membership Corporation.2021.2027. He is a member of the compensationaudit committee. Mr. Simonton is a director of Walton Electric Membership Corporation. Mr. Simonton is currently the owner of Simonton Farms and has previous business affiliations with Meridian Homes, Moreland Altobelli Associates, Inc. and the Georgia Department of Transportation.Bobby C. Smith, Jr. the Chairman of the Board and an at-large director. Mr. SmithWeathersby has served on our board of directors since May 2008, acting as Chairman since September 2015,2022, and his present term will expire in March 2020. Mr. Smith is a farmer.2026. He is a member of the board of directorscompensation committee and the construction committee. Mr. Weathersby is a director of Planters Electric Membership Corporation. HeCorporation where he has served since 2006 and currently serves as Chairman. Mr. Weathersby is the owner of Millen Peanut Company and Horace Weathersby Farms. Mr. Weathersby is also serves on the boarda director of directors for Georgia Electric Membership Corporation, Jenkins County Commission and is Chairman of the Board of the Screven County Development Authority and a member of the Sylvania Lions Club.2019.2025. He is a member of the audit committee. Mr. Weaver has been employed by Central Georgia Electric Membership Corporation since 1970 and is currently serving as President and Chief Executive Officer. Mr. Weaver is currently a director of Southeastern DataMeridian Cooperative and is a former director of Federated Rural Electric Insurance Corporation.2020.2026. He is a member of the audit committee. Mr. White has served as a director of Snapping Shoals Electric Membership Corporation since 1995. Mr. White is the owner and president of Realty South Inc. and the owner of T.K. White Real Estate Co. and is a member of the Metro South Association of Realtors and Georgia Association of Realtors. Mr. White is also a member of the Henry County Chamber of Commerce and was involved with the Henry County Development Authority for over 20 years. He was previously vice president at the First National Bank in Crestview, Florida.TheAs of the date of this annual report, the members of the audit committee are currently Ronald Duffey, Randy Crenshaw, Jeffrey Murphy, Sam Simonton, George Weaver and James White. Mr. Duffey is the chairman of the audit committee. The board of directors has determined that Mr. Duffey qualifies as an independent audit committee financial expert.Currently,As of the date of this annual report, the members of the compensation committee are Marshall Millwood, Randy Crenshaw, Anthony Ham, Chip Jakins, Jimmy Bailey, Fred McWhorter, Danny Nichols and Sammy Simonton.MillwoodJakins is the chairman of the compensation committee.TheAs of the date of this annual report, the members of the construction project committee are currently Danny Nichols, Jimmy Bailey, Chip Jakins, Fred McWhorter and Fred McWhorter.Horace Weathersby. Mr. Nichols is the chairman of the construction project committee.i)(i) significant compliance issues, ii)(ii) significant audits/examinations by governmental or other regulatory agencies, and iii)(iii) significant regulatory proceedings. The risk management and compliance committee, comprised of our chief executive officer, chief operating officer, chief20172023 for our executive officers should be comprised of the following three primary components:upperformance pay equal to 15%30% or 20%35% of his or her base salary, as a performance bonus based on position, multiplied by the achievementpercentage of corporate goals. Certain executive officers have an individual performance component to their performance pay.2017,2023, we contributed an additional amount equal to 11% of an executive officer's pay per period. See "– Nonqualified Deferred Compensation" below for additional information regarding our contributions to our executive officers' retirement plans.theany employment agreements with our executive officers' employment agreementsofficers on an annual basis and makes an affirmative decision whether each should be extended. Our president and chief executive officer reports the executive officers' salaries and determination whether to extend the employment agreements, if applicable, to the compensation committee and board of directors annually.remainslevels remain competitive, we review standardized surveys to compare our total compensation program against other companies in the utility industry of a similar size. We do not benchmark against such data; rather we utilize these surveys to gain a general understanding of current compensation practices and better understand and compare the components of our compensation program. The surveys we review are generally available and we have not hired a compensation consultant to provide us with information on executive compensation data. Executive compensation levels at other companies do not drive our compensation decisions,decisions. For our employees overall and we do not target a specific market percentile for our executive officerofficers, we review market compensation levels as a reference point in our overall compensation review process.2017,2023, our performance measures were divided into the following categories: i)(i) safety, ii)(ii) operations, iii)(iii) construction and project management, iv)(iv) corporate compliance, v)(v) financial and vi)(vi) quality. Targeted performance measures in these categories are designed to help us accomplish our corporate goals which will benefit our members, employees and promote responsible environmental stewardship. For example, in 2017, we added a new safety goal to enhance our lockout-tagout procedures. We also review and refine these goals annually and make adjustments as necessary to ensure that we are consistently stretching our expectations and performance. Although some performance measures may stay the same, the applicable threshold may become more difficult. The following provides an overview of the purposes of each category of our corporate goals:OneOur safety performance goal is measured by comparinggoals focused on the incident rate in our work environment against the national incident rate compiled by the U.S. Department of Labor's Bureau of Labor Statistics. The other three goals focus onserious injuries and fatalities, safety training and meetings, and enhancing our safety program and procedures.whichthat minimizes long-term maintenance and replacement energy costs. Certain operational goals take into account performance standards as required by contracts related to the facility operations. Our achieving operational excellence at the corporate level results in the most reliable, efficient and lowest cost power supply for our members. the construction of Vogtle Units No. 3 and No. 4. One of the goals measures how well we are managing the project in our role as a Co-owner. Performance is based on our participation on the Project Management Board, the degree and effectiveness ofsuccessperformance based on meeting applicablesuccessful project deadlines. In 2017, we revised our goals related to our compliance with the electric reliability standards. Certain performance pay is based entirely on the achievement of corporate goals and other executive officers' performance pay is based 75% on the achievement of corporate goals and 25% on individual performance. For executive officers whose performance pay is based entirely on corporate goal achievement, we multiply 20% of his or her base salary by the corporate goal achievement percentage to determine his or her performance bonus. For executive officers whose performance pay is based on corporate goals and individual performance, we multiply 15% of his or her base salary by the corporate goal achievement percentage and multiply 5% of his or her base salary by an individual performance ranking that ranges from 0% to 200%.20172023 Corporate Goals20172023 performance pay were the following:Performance
Category/ DescriptionPerformance Measure Threshold Maximum 2023
ResultWeight Weighted
Goal
AchievedSafety Incident Rate Serious Injuries and Fatalities 0 0 0 3.0 % 3.00 % Safety Training and Meetings 100.0 % 100.0 % 100.0 % 1.0 % 1.00 % Safety Observation Program 216/120 360/240 452/412 2.5 % 2.50 % Hazard Reduction Program 75.0 % 100.0 % 100.0 % 0.5 % 0.50 % Oglethorpe Managed Successful Starts 97.2 % 100.0 % 99.9 % 4.0 % 3.90 % Fleet Successful Dispatch 90.0 % 97.5 % 100.0 % 2.0 % 2.00 % Peak Season Availability 55.6 % 99.9 % 87.9 % 21.0 % 18.46 % Co-Owned Fleet Coal Fleet Peak Season Equivalent Forced Outage Rate 6.0 % 3.0 % 0.7 % 0.65 % 0.65 % Coal Fleet Annual Equivalent Unplanned Unavailability Factor 5.8 % 3.3 % 2.5 % 0.35 % 0.35 % Nuclear Fleet Capability Factor 90.7 % 92.7 % 91.7 % 2.0 % 1.03 % Construction and Project Management Vogtle Units No. 3 and No. 4 Oglethorpe Performance 0.0 % 100.0 % 100.0 % 7.0 % 7.00 % Project Milestones Meet applicable deadlines 50.0 % 3.0 % 1.50 % Oglethorpe Managed Projects Status of Projects Meet applicable deadlines & budgets 100.0 % 6.0 % 6.00 % Corporate Compliance Environmental Final Notices of Violation and Letters of Non-Compliance 1 (if fine is ≤ $5,000) or 2 0 1 4.0 % 3.00 % Reportable Spills 1 0 0 4.0 % 4.00 % Mandatory Electric Reliability Standards Non-Critical Infrastructure Protection Compliance 1+ (if minimal penalty) 0 0 3.0 % 3.00 % Critical Infrastructure Protection Compliance 1+ (if minimal penalty) 0 0 3.0 % 3.00 % Financial Cost Saving Current Year / Long-Term Savings $ 0 $ 50,000,000 $ 516,461,000 14.0 % 14.00 % Additional Cost Savings $ 0 $ 50,000,000 $ 455,753,497 0-5.0% 5.00 % Internal Control over Financial Reporting Significant Deficiency or Material Weakness 0 0 1 2.0 % — % Control Deficiency 2 1 0 2.0 % 2.00 % Quality Board Satisfaction Board of Directors Survey 80.0 % 100.0 % 95.0 % 15.0 % 14.25 % Total 100.0 % 96.14 % Performance
Category/ Description Performance Measure Threshold Maximum 2017 Result Weight Weighted
Goal
Achieved Safety Incident Rate Lost Work Time Cases 1+ (if not OSHA) 0 1 3.0 % 1.50 % Safety Program(1) Training and Meetings 33.3 % 100.0% 100.0 % 1.0 % 1.00 % Safety Observations 175 300 >300 3.0 % 3.00 % Procedures Lockout-Tagout Enhancement Meet applicable deadlines 100.0 % 3.0 % 3.00 %
Operations(2)
Oglethorpe Managed Successful Starts 96.9 % 100.0% 99.0 % 4.0 % 2.97 % Fleet Successful Dispatch 92.5 % 97.5% 96.5 % 3.0 % 1.98 % Peak Season Availability 66.5 % 99.69% 88.5 % 19.0 % 16.81 % Smith Gas Availability 0.0 % 100.0% 65.9 % 1.0 % 0.66 % Co-Owned Fleet Coal Fleet Peak Season Equivalent Forced Outage Rate 5.25 % 3.25% 1.2 % 1.33 % 1.33 % Coal Fleet Annual Equivalent Unplanned Unavailability Factor 6.0 % 4.0% 4.4 % 0.67 % 0.61 % Nuclear Fleet Capability Factor 91.7 % 92.1% 93.5 % 2.0 % 2.00 %
Construction and Project Management
Vogtle Units No. 3 and No. 4 Oglethorpe Performance 0.0 % 100.0% 100.0 % 6.0 % 6.00 % Status of Project Meet applicable deadlines 0.0 % 2.0 % 0.00 % Oglethorpe Managed Projects Status of Projects Meet applicable deadlines 87.5 % 4.0 % 3.50 %
Corporate Compliance
Environmental Final Notices of Violation and Letters of Non-Compliance 1 (if fine is £
$5,000) or 2 0 2 4.0 % 2.00 % Reportable Spills 1 0 0 4.0 % 4.00 % Mandatory Electric Reliability Standards Non-Critical Infrastructure Protection Compliance 1+ (if minimal penalty) 0 0 3.0 % 3.00 % Critical Infrastructure Protection Compliance 1+ (if minimal penalty) 0 0 3.0 % 3.00 %
Financial
Cost Saving Current Year / Long-Term Savings $0 $35,000,000 $ 77,998,267 14.0 % 14.00 % Internal Control over Financial Reporting Significant Deficiency or Material Weakness 0 0 0 2.0 % 2.00 % Control Deficiency 2 1 0 2.0 % 2.00 %
Quality
Board Satisfaction Board of Directors Survey 80.0 % 100.0% 95.7 % 15.0 % 14.40 % 100.0 % 88.71 % have beenare aggregated for purposes of the table.results based on all of the generating units within the category.88.71%96.14% of our corporate goals for 2017.2023. As a result, Mr. Smith, Mr. Price, Ms. Higgins and Mr. UsserySorrick received performance pay in an amount equal to 88.71%96.14% of 20%35% of his or her base salary and Mr. Ussery and Ms. Bloodworth received performance pay in an amount equal to 96.14% of 30% of his or her base salary. Mr. Messersmith received an amount equal to 88.71% of 15% of his base salary plus 115% of 5% of his base salary. Set forth below is a2017:Executive Officer Performance Pay* Michael L. Smith $ 342,394 Elizabeth B. Higgins 196,174 David W. Sorrick 183,724 William F. Ussery 127,799 Annalisa M. Bloodworth 130,654 Executive Officer Performance Pay* $ 126,330 75,936 76,468 59,436 58,602 2017.2023. Actual compensation earned in 20172023 is reported in the Summary Compensation Table below.Mr. Price, Ms. Higgins, Mr. Sorrick, Mr. Ussery and Mr. Ussery.Ms. Bloodworth. We negotiated each of these employment agreements on an arms-length basis, and the compensation committee determined that the terms of each agreement are reasonable and necessary to ensure that these executive officers' goals are aligned with our members' interests and that each performs his or her respective role while acting in our members' best interests. We review these agreements on an annual basis. We do not have an employment agreement with Mr. Messersmith.2020.2026. Mr. Smith's agreement will automatically renew pursuant to the corresponding provision of the agreement for successive one-year periods unless either party provides written notice not to renew the agreement twenty-four months before the expiration of any extended term. Each year, our board of directors makes an affirmative determination as to whether to provide such notice and no such notice has been provided. Mr. Smith's minimum annual base salary under his agreement is $630,000,$956,970, and is subject to review and adjustment by our board of directors. Mr. Smith is eligible for an annual bonus and to participate in incentive compensation plans generally available to similarly situated employees and for an annual bonus determined by our board of directors at its sole discretion. Mr. Smith is also entitled to an automobile or an automobile allowance during the term of the agreement. Mr. Smith's employment agreement contains severance pay provisions.Mr. Price, Ms. Higgins, Mr. Sorrick, Mr. Ussery and Mr. Ussery.Ms. Bloodworth. The current term of each agreementMs. Higgins', Mr. Sorrick's, Mr. Ussery's and Ms. Bloodworth's agreements extends through December 31, 20192026 and will automatically renew for successive one-year periods unless either party provides written notice not to renew the agreement twelvetwenty-four months before the expiration of any extended term. Each year, our president and chief executive officer makes an affirmative determination as to whether to provide such notice, and no such notices have been provided.$414,000 for Mr. Price, $417,100$555,000 for Ms. Higgins, and $324,400$520,000 for Mr. Ussery.Sorrick, $422,000 for Mr. Ussery and $405,000 for Ms. Bloodworth. Salaries are subject to review and possible adjustment as determined by the president and chief executive officer. Each executive is also eligible for an annual bonus and to participate in incentive compensation plans generally available to similarly situated employees and for an annual bonus determined by usthe president and chief executive officer at ourhis sole discretion. The employment agreements with Mr. Price, Ms. Higgins, andMr. Sorrick, Mr. Ussery and Ms. Bloodworth contain severance pay provisions.isare entitled to severance payments and benefits in the event they are terminated not for cause or they resign for good reason.$1,572,912. The compensation committee also$2,277,646.Mr. Smith, Mr. Price, Ms. Higgins, andMr. Sorrick, Mr. Ussery and Ms. Bloodworth would receive upon the occurrence of a severance event. The compensation committeeevent and determined that it was appropriate for these executive officers to receive severance compensation equal to one year's compensation,a maximum of two years of his or her then current base salary, plus benefits as described below, because such agreements provide a measure of stability for both us and the executive officers. In addition, like our president and chief executive officer, these executive officers are not compensated using options or other forms of equity compensation that lead to significant wealth accumulation. Therefore, the compensation committeeour president and chief executive officer believes such severance compensation is necessary to address competitive concerns and offset any potential risk our executive officers face in the course of their employment.Mr. Price, Ms. Higgins, andMr. Sorrick, Mr. Ussery and Ms. Bloodworth will each be entitled to a lump-sum severance payment if we terminate the executive without cause or if the executive resigns after a demotion or material reduction of his or her position or responsibilities, a reduction of his or her base salary, or a relocation of his or her principal office by more than 50 miles. The severance payment will equal one year of the executive'sexecutive officer's then current base salary through the rest of the term of the agreement (with a minimum of one year's pay and a maximum of two years' pay), payable within 30 days of termination, subject to the provisions of Internal Revenue Code Section 409A. In addition, the executive will be entitled to six monthsone year of outplacement services and an amount equal to the executive's cost for medical and dental continuation coverage under COBRA for six months.one year. Severance is payable only if the executive signs a form releasing all claims against us. The maximum severance that would be payable to Mr. Price, Ms. Higgins, andMr. Sorrick, Mr. Ussery and Ms. Bloodworth in the circumstances described above is $473,556, $477,600,$1,312,814, $1,216,914, $988,248 and $366,506,$1,037,478, respectively.20172023 for filing with the SEC.Randy CrenshawM. Anthony HamMarshall S. MillwoodSammy G. Simonton Mr. Crenshaw, Mr. Ham, Mr. Jakins, Mr. Nichols and Mr. SimontonWeathersby served as members of our compensation committee in 2017. Mr. Crenshaw isduring all or a directorportion of ours and the President and Chief Executive Officer of Irwin Electric Membership Corporation and Middle Georgia Electric Membership Corporation. Irwin and Middle Georgia are members of ours and each has a wholesale power contract with us. Irwin's revenues of $8.8 million to us in 2017 under its wholesale power contract accounted for approximately 0.6% of our total revenues. Middle Georgia's revenues of $5.7 million to us in 2017 under its wholesale power contract accounted for approximately 0.4% of our total revenues.$210.4$262.7 million to us in 20172023 under its wholesale power contract accounted for approximately 14.7%15.1% of our total revenues.General ManagerPresident and Chief Executive Officer of Colquitt Electric Membership Corporation. Colquitt is a member of ours and has a wholesale power contract with us. Colquitt's revenues of $44.5$42.8 million to us in 20172023 under its wholesale power contract accounted for approximately 3.1%2.5% of our total revenues.2017, 20162023, 2022 and 2015.Name and Principal Position Year Salary Bonus Non-Equity
Incentive Plan
CompensationTotal Michael L. Smith 2023 $ 1,007,450 $ — $ 342,394 $ 196,817 $ 1,546,661 President and 2022 947,475 — 178,379 186,873 1,312,727 Chief Executive Officer 2021 890,140 — 166,176 177,508 1,233,824 Elizabeth B. Higgins 2023 578,333 — 196,174 118,561 893,068 Executive Vice President and 2022 549,167 — 103,452 113,797 766,416 Chief Financial Officer 2021 517,333 — 96,013 108,579 721,925 2023 541,667 — 183,724 110,200 835,591 Executive Vice President and 2022 484,168 — 88,851 110,233 683,252 Chief Operating Officer William F. Ussery 2023 439,583 — 127,799 93,720 661,102 Executive Vice President, 2022 417,833 — 78,661 97,440 593,934 Member Relations 2021 395,000 — 73,302 83,332 551,634 Annalisa M. Bloodworth 2023 438,333 — 130,654 107,364 676,351 Senior Vice President, 2022 390,750 — 75,492 95,858 562,100 and General Counsel Name and Principal Position Year Salary Bonus Non-Equity
Incentive Plan
Compensation All Other
Compensation(1) Total Michael L. Smith 2017 $ 708,026 $ – $ 126,330 $ 144,420 $ 978,776 President and 2016 683,550 – 129,103 136,677 949,330 Chief Executive Officer 2015 656,250 – 113,050 86,864 856,164
Michael W. Price
2017
425,667
–
75,936
109,838
611,441
Executive Vice President and 2016 411,667 – 77,691 93,704 580,567 Chief Operating Officer 2015 397,500 – 68,360 59,478 525,338
Elizabeth B. Higgins
2017
428,683
–
76,468
91,103
596,254
Executive Vice President and 2016 414,750 – 78,273 79,465 569,914 Chief Financial Officer 2015 400,333 – 68,873 61,701 530,907
William F. Ussery
2017
333,233
–
59,436
73,508
466,177
Executive Vice President, 2016 322,833 – 60,877 78,308 462,018 Member and External Relations 2015 313,333 – 53,833 48,547 415,713
James A. Messersmith
2017
305,546
–
58,602
66,242
430,390
Senior Vice President, Plant Operations
Figures for 20172023 consist of matching contributions and contributions we made by Oglethorpe under the 401(k) Retirement Savings Plan on behalf of each Mr. Smith, Mr. Price, Ms. Higgins, Mr. Ussery, and Ms. Bloodworth of $43,500 and $43,956 for Mr. Messersmith of $36,000, $36,000, $36,000, $36,000, and $36,000, respectively;Sorrick; contributions by Oglethorpe to a nonqualified deferred compensation plan on behalf of Mr. Smith, Mr. Price, Ms. Higgins, Mr. Ussery, Ms. Bloodworth and Mr. Messersmith,Sorrick, respectively of $89,880, $43,033, $40,642, $25,087$133,793, $60,242, $36,363, $35,990 and $20,446;$52,560; car allowances; paid time off, executive health benefits; customary holiday gifts and service awards.2017.Estimated Future
Payouts
Under Non-Equity
Incentive Plan AwardsGrant Date Threshold Maximum Michael L. Smith N/A $ 98,052 $ 356,141 Elizabeth B. Higgins N/A $ 56,178 $ 204,050 David W. Sorrick N/A $ 52,613 $ 191,100 William F. Ussery N/A $ 36,598 $ 132,930 Annalisa M. Bloodworth N/A $ 37,416 $ 135,900 Estimated Future
Payouts
Under Non-Equity
Incentive Plan Awards Grant Date Name Threshold Maximum Michael L. Smith N/A $ 31,059 $ 142,408
Michael W. Price
N/A
$
18,669
$
85,600
Elizabeth B. Higgins
N/A
$
18,800
$
86,200
William F. Ussery
N/A
$
14,613
$
67,000
James A. Messersmith
N/A
$
22,361
$
76,879
20172023 Corporate Goals."270,000330,000 as indexed).20172023 along with aggregate earnings for the same period.Name Executive
Contributions
in Last FYAggregate
Withdrawals/
Distributions
in Last FYAggregate
Balance at
Last FYEMichael L. Smith $ 42,000 $ 133,793 $ 233,164 $ — $ 1,681,187 Elizabeth B. Higgins $ 12,480 $ 60,242 $ 212,562 $ — $ 1,096,498 David W. Sorrick $ 8,016 $ 52,560 $ 3,144 $ — $ 63,720 William F. Ussery $ 3,000 $ 36,363 $ 71,031 $ — $ 468,614 Annalisa M. Bloodworth $ 7,200 $ 35,990 $ 34,258 $ — $ 227,614 Name Executive
Contributions
in Last FY Registrant
Contributions
in Last FY(1) Aggregate
Earnings
in Last FY(2) Aggregate
Withdrawals/
Distributions
in Last FY Aggregate
Balance at
Last FYE Michael L. Smith $ 25,000 $ 89,880 $ 49,391 $ – $ 399,817 Michael W. Price $ 6,066 $ 43,033 $ 39,496 – $ 303,248 Elizabeth B. Higgins $ 12,284 $ 40,642 $ 55,842 – $ 335,422 William F. Ussery – $ 25,087 $ 20,572 – $ 141,145 James A. Messersmith – $ 20,446 $ 12,134 – $ 81,905 2017.2017,2023, we had 277337 employees, including full-time, part-time, temporary and seasonal workers (excluding our president and chief executive officer), who were all located in the United States. We then calculated the annual total compensation for each of these employees for the fiscal year ended December 31, 20172023 in the same manner in which we calculated our president and chief executive officer's total annual compensation presented in the "Summary Compensation Table." Employee compensation includes salary, performance pay and benefits.20172023 was $138,937.$169,500. As set forth in the Summary Compensation Table, our president and chief executive officer's annual total compensation for 20172023 was $978,776.$1,546,661. The ratio of our president and chief executive officer's annual total compensation to our median employee's annual total compensation for the fiscal year ended December 31, 20172023 was 7.04:9.12:1.2017.Name Total Fees
Earned or Paid
in CashMember Directors Jimmy G. Bailey $ 18,200 Randy Crenshaw $ 17,160 Ernest A. "Chip" Jakins III $ 14,560 Fred A. McWhorter $ 20,280 Marshall S. Millwood, Chairman $ 20,020 Jeffrey W. Murphy $ 17,290 Danny L. Nichols $ 16,900 Sammy G. Simonton $ 20,670 Horace H. Weathersby III $ 17,440 George L. Weaver $ 20,730 James I. White, Vice-Chairman $ 26,600 Outside Director Wm. Ronald Duffey $ 38,830 Name Total Fees
Earned or Paid
in Cash Member Directors Jimmy G. Bailey $ 22,100 Randy Crenshaw $ 19,900 M. Anthony Ham $ 20,100 Ernest A. "Chip" Jakins III $ 20,100 Fred A. McWhorter $ 21,600 Marshall S. Millwood, Vice-Chairman $ 21,600 Jeffrey W. Murphy $ 21,200 Danny L. Nichols $ 21,000 Bobby C. Smith, Jr., Chairman $ 27,080 Sammy G. Simonton $ 21,600 George L. Weaver $ 23,000 James I. White $ 23,600 Outside Director Wm. Ronald Duffey $ 39,600 During 2017,In 2023, we paid our member directors a fee of $1,200$1,560 per board meeting and $800$1,040 per day for attending committee meetings, other meetings, or other official business approved by the chairman of the board of directors. Member directors arewere paid $600$780 per day for attending the annual meeting of members and member advisory board meetings and $300$390 per day for participation by video conference for a meeting of the advisory board. OurWe paid our outside director was paid a fee of $5,500 per board meeting for four meetings a year and a fee of $1,000 per board meeting for the remaining other board meetings held during the year. Our outside director was also paid $1,000 per day for attending committee meetings, annual meetings of the members or other official business. In addition, we reimburse all directors for out-of-pocket expenses incurred in attending a meeting. All directors, areincluding the outside director, were paid $100$130 per dayhour, or for each fraction thereof, up to a daily cap of $780, when participating in meetings by conference call. The chairman of the board of directors is paid an additional 20% of his director's fee per board meeting for time involved in preparing for the meetings. The audit committee financial expert is paid an additional $400 per audit committee meeting for the time involved in fulfilling that role. If more than one meeting is held the same day, only one day's per diem is paid. Neither our outside director nor member directors receive any perquisites or other personal benefits from us. We will also pay any fees charged for such training. Directors may choose one external training course per year to attend.Corporation and Middle Georgia Electric Membership Corporation. Irwin and Middle Georgia are membersis a member of ours and each has a wholesale power contract with us. Irwin's revenues of $8.8$9.1 million to us in 20172023 under its wholesale power contract accounted for approximately 0.6%0.5% of our total revenues. Middle Georgia's revenues of $5.7 million to us in 2017 under its wholesale power contract accounted for approximately 0.4% of our total revenues.$210.4$262.7 million to us in 20172023 under its wholesale power contract accounted for approximately 14.7%15.1% of our total revenues.$21.3$23.9 million to us in 20172023 under its wholesale power contract accounted for approximately 1.5%1.4% of our total revenues.General ManagerPresident and Chief Executive Officer of Colquitt Electric Membership Corporation. Colquitt is a member of ours and has a wholesale power contract with us. Colquitt's revenues of $44.5$42.8 million to us in 20172023 under its wholesale power contract accounted for approximately 3.1%2.5% of our total revenues.$42.0$65.5 million to us in 20172023 under its wholesale power contract accounted for approximately 2.9%3.8% of our total revenues.theour members own and manage us. Our bylaws set forth specific requirements regarding the composition of our board of directors. See "DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE – Our Board of Directors – Structure of Our Board of Directors" for a detailed discussion of the specific requirements contained in our bylaws regarding the composition of our board of directors.2017.2023. Although we do not have any securities listed on the NASDAQ Stock Market, we have used its independence criteria in making this determination in accordance with applicable SEC rules.20172023 and 2016,2022, fees for services provided by our independent registered public accounting firm, Ernst & Young LLP were as follows:2023 2022 (dollars in thousands) $ 656 $ 706 95 162 — — — 2 Total $ 751 $ 870 2017 2016 (dollars in thousands) Audit Fees(1) $ 513 $ 498 Audit-Related Fees(2) 67 57 Tax Fees(3) 41 26 All Other Fees(4) 2 2 Total $ 623 $ 583 relatespreviously related to a subscription toof an on-lineonline accounting research tool.and investigative tool, now a free service.20172023 were pre-approved in accordance with the pre-approval policy and procedures adopted by the audit committee. The policy requires that requests for all services must be submitted to the audit committee for specific pre-approval and cannot commence until such approval has been granted. Normally, pre-approval is provided at regularly scheduled meetings.Page Page(1) (1)6020172023 and 2016(2) (2)(3) Exhibits (3)ExhibitsNumber Description *3.1(a) – Restated Articles of Incorporation of Oglethorpe, dated as of July 26, 1988. (Filed as Exhibit 3.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 1988, File No. 33-7591.) *3.1(b) – *3.2 – *4.1 – *4.2.1(a) – *4.2.1(b) – *4.2.1(c) – *4.2.1(d) – *4.2.1(e) – *4.2.1(f) – *4.2.1(g) – *4.2.1(h) – *4.2.1(i) – –*4.2.1(j) – –*4.2.1(k) – –*4.2.1(l) – –*4.2.1(m) – –*4.2.1(n) – –*4.2.1(o) – –*4.2.1(p) – –*4.2.1(q) – –*4.2.1(r) – –*4.2.1(s) – –*4.2.1(t) – –*4.2.1(u) – –*4.2.1(v) – –*4.2.1(w) – –*4.2.1(x) – –*4.2.1(y) – –*4.2.1(z) – –*4.2.1(aa) – –*4.2.1(bb) – –*4.2.1(cc) – –*4.2.1(dd) – –*4.2.1(ee) – –*4.2.1(ff) – –*4.2.1(gg) – –*4.2.1(hh) – –*4.2.1(ii) – –*4.2.1(jj) – –*4.2.1(kk) – –*4.2.1(ll) – –*4.2.1(mm) – –*4.2.1(nn) – –*4.2.1(oo) – –*4.2.1(pp) – –*4.2.1(qq) – –*4.2.1(rr) – –*4.2.1(ss) – –*4.2.1(tt) – –*4.2.1(uu) – –*4.2.1(vv) – –*4.2.1(ww) – –*4.2.1(xx) – –*4.2.1(yy) – –*4.2.1 (zz) – –*4.2.1 (bbb) – –*4.2.1 (ccc) – –*4.2.1 (ddd) – –*4.2.1 (eee) – –*4.2.1(fff) – –*4.2.1(ggg) – –*4.2.1(hhh) – –*4.2.1(iii) – –*4.2.1(jjj) – –*4.2.1(kkk) – –*4.2.1(lll) – –*4.2.1(mmm) – –*4.2.1(nnn) – –*4.2.1(ooo) – –*4.2.1(ppp) – –*4.2.1(qqq) – –*4.2.1(rrr) – –*4.2.1(sss) – –*4.2.1(ttt) – –*4.2.1(uuu) – –*4.2.1(vvv) – –*4.2.1(www) – –*4.2.1(xxx) – –*4.2.1(yyy) – –*4.2.1(zzz) – –*4.2.1(aaaa) – *4.2.1(bbbb) – *4.2.1(cccc) – *4.2.1(dddd) – *4.2.1(eeee) – *4.2.1(ffff) – *4.2.1(gggg) – *4.2.1(hhhh) – *4.2.1(iiii) – *4.2.1(jjjj) – *4.2.2 – –*4.3 – –– –Loan Agreement, dated as of December 1, 2009, between the Development Authority of Monroe County and Oglethorpe relating to the Development Authority of Monroe County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Scherer Project), Series 2009A, and five other substantially identical (Variable Rate Bonds) loan agreements.4.4.2(1)–Note, dated December 10, 2009, from Oglethorpe to U.S. Bank National Association, as trustee, acting pursuant to a Trust Indenture, dated as of December 1, 2009, between the Development Authority of Monroe County and U.S. Bank National Association relating to the Development Authority of Monroe County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Scherer Project), Series 2009A, and five other substantially identical notes.4.4.3(1)–Trust Indenture, dated as of December 1, 2009, between the Development Authority of Monroe County and U.S. Bank National Association, as trustee, relating to the Development Authority of Monroe County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Scherer Project), Series 2009A, and five other substantially identical indentures.4.5.1(1)–Loan Agreement, dated as of April 1, 2013, between the Development Authority of Appling County and Oglethorpe relating to the Development Authority of Appling County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Hatch Project), Series 2013A, and two other substantially identical (Term Rate Bonds) loan agreements. 4.5.2– –Note, dated April 23, 2013, from Oglethorpe to U.S. Bank National Association, as trustee, acting pursuant to a Trust Indenture, dated as of April 1, 2013, between the Development Authority of Appling County and U.S. Bank National Association relating to the Development Authority of Appling County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Hatch Project), Series 2013A, and two other substantially identical notes. 4.5.3– –Trust Indenture, dated as of April 1, 2013, between the Development Authority of Appling County and U.S. Bank National Association, as trustee, relating to the Development Authority of Appling County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Hatch Project), Series 2013A, and two other substantially identical indentures. 4.6.1– –Loan Agreement, dated as of October 1, 2017, between the Development Authority of Burke County and Oglethorpe relating to the Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2017A, and threetwo other substantially identical (Indexed Put Rate Bonds) loan agreements.4.6.2– –Note, dated October 12, 2017, from Oglethorpe to U.S. Bank National Association, as trustee, acting pursuant to a Trust Indenture, dated as of October 1, 2017, between the Development Authority of Burke County and U.S. Bank National Association relating to the Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2017A, and threetwo other substantially identical notes.4.6.3– –Trust Indenture, dated as of October 1, 2017, between the Development Authority of Burke County and U.S. Bank National Association, as trustee, relating to the Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2017A, and threetwo other substantially identical indentures.4.6.4– –Bondholder's Agreement, dated as of October 1, 2017, by and between Oglethorpe and RBC Municipal Products, LLC, relating to the Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2017A, and threetwo other substantially identical bondholder's agreements.4.7.1– –Loan Agreement, dated as of December 1, 2017, between the Development Authority of Burke County and Oglethorpe relating to the Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2017C, and threetwo other substantially identical (Fixed Rate and Term Rate Bonds) loan agreements.4.7.2– –Note, dated December 28, 2017, from Oglethorpe to U.S. Bank National Association, as trustee, acting pursuant to a Trust Indenture, dated as of December 1, 2017, between the Development Authority of Burke County and U.S. Bank National Association relating to the Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2017C, and threetwo other substantially identical notes.4.7.3– –Trust Indenture, dated as of December 1, 2017, between the Development Authority of Burke County and U.S. Bank National Association, as trustee, relating to the Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2017C, and threetwo other substantially identical indentures.4.8.1– –Term Loan Agreement, dated as of August 1, 2009, between Oglethorpe and National Rural Utilities Cooperative Finance Corporation, relating to the Series 2009C Note.4.8.2(1)–First Amendment to Term Loan Agreement, dated as of December 20, 2013, by and between Oglethorpe and National Rural Utilities Cooperative Finance Corporation, relating to the Series 2009C Note.4.8.3(1)–Series 2009C CFC Note, dated August 11, 2009, in the original principal amount of $250,000,000, from Oglethorpe to National Rural Utilities Cooperative Finance Corporation.4.9.1(1)–Bond Purchase Agreement, dated as of December 30, 2009, between Oglethorpe and CoBank, ACB, relating to Oglethorpe Power Corporation (An Electric Membership Corporation) First Mortgage Bond, Series 2009 CoBank (Clean Renewable Energy Bond). 4.9.2– –Oglethorpe Power Corporation (An Electric Membership Corporation) First Mortgage Bond, Series 2009 CoBank (Clean Renewable Energy Bond), dated December 30, 2009, from Oglethorpe to CoBank, ACB, in the original principal amount of $16,165,400. * 4.10.14.8.1– –* 4.10.24.8.2– –* 4.10.34.8.3– –* 4.10.44.8.4– –*4.8.5 – *4.8.6 – * 4.10.4(a)4.8.6(a)– –* 4.10.4(b)4.8.6(b)– –* 4.10.4(c)4.8.6(c)– –* 4.10.4(d)4.8.6(d)– –* 4.10.54.8.6(e)– –*4.8.6(f) – *4.8.6(g) – *4.8.7 – * 4.10.64.8.8– –*4.8.9 – *10.1.1(a) – –Participation Agreement No. 2 among Oglethorpe as Lessee, Wilmington Trust Company as Owner Trustee, The First National Bank of Atlanta as Indenture Trustee, Columbia Bank for Cooperatives as Loan Participant and Ford Motor Credit Company as Owner Participant, dated December 30, 1985, together with a schedule identifying three other substantially identical Participation Agreements. (Filed as Exhibit 10.1.1(b) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.1(b) – –Supplemental Participation Agreement No. 2. (Filed as Exhibit 10.1.1(a) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.1(c) – –Supplemental Participation Agreement No. 1, dated as of June 30, 1987, among Oglethorpe as Lessee, IBM Credit Financing Corporation as Owner Participant, Wilmington Trust Company and The Citizens and Southern National Bank as Owner Trustee, The First National Bank of Atlanta, as Indenture Trustee, and Columbia Bank for Cooperatives, as Loan Participant. (Filed as Exhibit 10.1.1(c) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.) *10.1.1(d) – –*10.1.2 – –General Warranty Deed and Bill of Sale No. 2 between Oglethorpe, Grantor, and Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Grantee, together with a schedule identifying three substantially identical General Warranty Deeds and Bills of Sale. (Filed as Exhibit 10.1.2 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.3 – –*10.1.4(a) – –Lease Agreement No. 2, dated December 30, 1985, between Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Lessor, and Oglethorpe, Lessee, with a schedule identifying three other substantially identical Lease Agreements. (Filed as Exhibit 4.5(b) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.4(b) – –First Supplement to Lease Agreement No. 2 (included as Exhibit B to the Supplemental Participation Agreement No. 2 listed as Exhibit 10.1.1(b)). *10.1.4(c) – –First Supplement to Lease Agreement No. 1, dated as of June 30, 1987, between The Citizens and Southern National Bank as Owner Trustee under Trust Agreement No. 1 with IBM Credit Financing Corporation, as Lessor, and Oglethorpe, as Lessee. (Filed as Exhibit 4.5(c) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.) *10.1.4(d) – –*10.1.5(a) – –Supporting Assets Lease No. 2, dated December 30, 1985, between Oglethorpe, Lessor, and Wilmington Trust Company and William J. Wade, as Owner Trustees, under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Lessee, together with a schedule identifying three substantially identical Supporting Assets Leases. (Filed as Exhibit 10.1.3 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.5(b) – –First Amendment to Supporting Assets Lease No. 2, dated as of November 19, 1987, together with a schedule identifying three substantially identical First Amendments to Supporting Assets Leases. (Filed as Exhibit 10.1.3(a) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.) *10.1.5(c) – –*10.1.6(a) – –Supporting Assets Sublease No. 2, dated December 30, 1985, between Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Sublessor, and Oglethorpe, Sublessee, together with a schedule identifying three substantially identical Supporting Assets Subleases. (Filed as Exhibit 10.1.4 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.6(b) – –First Amendment to Supporting Assets Sublease No. 2, dated as of November 19, 1987, together with a schedule identifying three substantially identical First Amendments to Supporting Assets Subleases. (Filed as Exhibit 10.1.4(a) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.) *10.1.6(c) – –*10.1.7(a) – –Tax Indemnification Agreement No. 2, dated December 30, 1985, between Ford Motor Credit Company, Owner Participant, and Oglethorpe, Lessee, together with a schedule identifying three substantially identical Tax Indemnification Agreements. (Filed as Exhibit 10.1.5 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.7(b) – –*10.1.8 – –Assignment of Interest in Ownership Agreement and Operating Agreement No. 2, dated December 30, 1985, between Oglethorpe, Assignor, and Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Assignee, together with a schedule identifying three substantially identical Assignments of Interest in Ownership Agreement and Operating Agreement. (Filed as Exhibit 10.1.6 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.9(a) – –Consent, Amendment and Assumption No. 2, dated December 30, 1985, among Georgia Power Company and Oglethorpe and Municipal Electric Authority of Georgia and City of Dalton, Georgia and Gulf Power Company and Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, together with a schedule identifying three substantially identical Consents, Amendments and Assumptions. (Filed as Exhibit 10.1.9 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.9(b) – –Amendment to Consent, Amendment and Assumption No. 2, dated as of August 16, 1993, among Oglethorpe, Georgia Power Company, Municipal Electric Authority of Georgia, City of Dalton, Georgia, Gulf Power Company, Jacksonville Electric Authority, Florida Power & Light Company and Wilmington Trust Company and NationsBank of Georgia, N.A., as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, together with a schedule identifying three substantially identical Amendments to Consents, Amendments and Assumptions. (Filed as Exhibit 10.1.9(a) to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.) *10.2.1(a) – –Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of May 15, 1980. (Filed as Exhibit 10.6.1 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.2.1(b) – –Amendment to Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of December 30, 1985. (Filed as Exhibit 10.1.8 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.2.1(c) – –Amendment Number Two to the Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of July 1, 1986. (Filed as Exhibit 10.6.1(a) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.) *10.2.1(d) – –Amendment Number Three to the Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of August 1, 1988. (Filed as Exhibit 10.6.1(b) to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.) *10.2.1(e) – –Amendment Number Four to the Plant Robert W. Scherer Units Number One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of December 31, 1990. (Filed as Exhibit 10.6.1(c) to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.) *10.2.2(a) – –Plant Robert W. Scherer Units Numbers One and Two Operating Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of May 15, 1980. (Filed as Exhibit 10.6.2 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.2.2(b) – –Amendment to Plant Robert W. Scherer Units Numbers One and Two Operating Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of December 30, 1985. (Filed as Exhibit 10.1.7 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.2.2(c) – –Amendment Number Two to the Plant Robert W. Scherer Units Numbers One and Two Operating Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of December 31, 1990. (Filed as Exhibit 10.6.2(a) to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.) *10.2.2(d) – *10.2.3 – –Plant Scherer Managing Board Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia, City of Dalton, Georgia, Gulf Power Company, Florida Power & Light Company and Jacksonville Electric Authority, dated as of December 31, 1990. (Filed as Exhibit 10.6.3 to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.) *10.3.1(a) – –Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of August 27, 1976. (Filed as Exhibit 10.7.1 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.3.1(b) – –Amendment Number One, dated January 18, 1977, to the Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia. (Filed as Exhibit 10.7.3 to the Registrant's Form 10-K for the fiscal year ended December 31, 1986, File No. 33-7591.) *10.3.1(c) – –Amendment Number Two, dated February 24, 1977, to the Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia. (Filed as Exhibit 10.7.4 to the Registrant's Form 10-K for the fiscal year ended December 31, 1986, File No. 33-7591.) *10.3.2 – –*10.3.2(a) – –* 10.4.2(a)10.3.2(b)– –Plant Hal Wansley Operating *10.4.2(b)–Amendment2 to Plant Hal Wansley OperatingAlvin W. Vogtle Additional Units Ownership Participation Agreement, dated as of January 15, 1995,February 20, 2014, by and among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia. (Filed as Exhibit 10.5.2(a)10.3.2(b) to the Registrant's Form 10-K for the fiscal year ended December 31, 2013, File No. 000-53908.)*10.3.2(c) – *10.3.2(d) – *10.3.2(e) – *10.3.3 – * 10.4.2(c)10.3.3(a)– –Second * 10.4.310.3.3(b)– –*10.3.4 – Plant Hal Wansley Combustion Turbine*10.3.4(a) – – – – *10.3.6(c) – *10.3.7 – * 10.5.110.4.1– –Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement between Georgia Power Company and Oglethorpe, dated as of January 6, 1975. (Filed as Exhibit 10.9.1 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) * 10.5.210.4.2– –Edwin I. Hatch Nuclear Plant Operating Agreement between Georgia Power Company and Oglethorpe, dated as of January 6, 1975. (Filed as Exhibit 10.9.2 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) * 10.6.110.5.1– –Rocky Mountain Pumped Storage Hydroelectric Project Ownership Participation Agreement, dated as of November 18, 1988, by and between Oglethorpe and Georgia Power Company. (Filed as Exhibit 10.22.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 1988, File No. 33-7591.) * 10.6.210.5.2– –Rocky Mountain Pumped Storage Hydroelectric Project Operating Agreement, dated as of November 18, 1988, by and between Oglethorpe and Georgia Power Company. (Filed as Exhibit 10.22.2 to the Registrant's Form 10-K for the fiscal year ended December 31, 1988, File No. 33-7591.) * 10.7.110.6.1(a)– –* 10.7.210.6.1(b)– –* 10.7.310.6.1(c)– –*10.6.2 – *10.9 – Supplemental Agreement by and among Oglethorpe, Tri-County Electric Membership Corporation and Georgia Power Company, dated as of November 12, 1990, together with a schedule identifying 37 other substantially identical Supplemental Agreements. (Filed as Exhibit 10.30 to the Registrant's Form 8-K, filed January 4, 1991, File No. 33-7591.) *10.10.1(a) – *10.10.1(b) – *10.10.2 – *10.10.3 – *10.11 – *10.12(a) – *10.12(b) – – – – – – 14.1 – Code of Conduct, available on our website, www.opc.com. 31.1 – 31.2 – 32.1 – 32.2 – *99.1 – 101 – XBRL Interactive Data File. 104 – Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101). 29th25th day of March, 2018.OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)By: By:
/s/ MICHAEL L. SMITHMICHAEL L. SMITH President and Chief Executive Officer Signature Title Date SignatureTitleDate/s/ MICHAEL L. SMITH MICHAEL L. SMITHPresident and Chief Executive Officer (Principal Executive Officer) March 29, 201825, 2024
MICHAEL L. SMITH/s/ ELIZABETH B. HIGGINS ELIZABETH B. HIGGINS
Executive Vice President and Chief Financial Officer (Principal Financial Officer)
March 29, 201825, 2024
ELIZABETH B. HIGGINS/s/ G. KENNETH WARREN, JR. G. KENNETH WARREN, JR.
Vice President, Controller (Principal Accounting Officer)
March 29, 201825, 2024
G. KENNETH WARREN, JR./s/ JIMMY G. BAILEY Director March 25, 2024 JIMMY G. BAILEY DirectorMarch 29, 2018/s/ RANDY CRENSHAW RANDY CRENSHAWDirector Director
March 29, 201825, 2024
RANDY CRENSHAW/s/ WM. RONALD DUFFEY Director March 25, 2024 WM. RONALD DUFFEY DirectorMarch 29, 2018/s/ M. ANTHONY HAMM. ANTHONY HAMDirectorMarch 29, 2018
/s/ ERNEST A. JAKINS IIIDirector March 25, 2024 ERNEST A. JAKINS III /s/ FRED MCWHORTER Director March 25, 2024 FRED MCWHORTER March 29, 2018Signature Title Date SignatureTitleDate/s/ FRED MCWHORTERFRED MCWHORTERDirectorMarch 29, 2018
/s/ MARSHALL S. MILLWOODDirector March 25, 2024 MARSHALL S. MILLWOOD DirectorMarch 29, 2018/s/ JEFFREY W. MURPHY Director March 25, 2024 JEFFREY W. MURPHY DirectorMarch 29, 2018/s/ DANNY L. NICHOLS Director March 25, 2024 DANNY L. NICHOLS DirectorMarch 29, 2018/s/ SAMMY G. SIMONTON Director March 25, 2024 SAMMY G. SIMONTON /s/ HORACE H. WEATHERSBY III Director
March 29, 201825, 2024/s/ BOBBY C. SMITH, JR.BOBBY C. SMITH, JR.HORACE H. WEATHERSBY IIIDirectorMarch 29, 2018/s/ GEORGE L. WEAVER Director March 25, 2024 GEORGE L. WEAVER DirectorMarch 29, 2018/s/ JAMES I. WHITE Director March 25, 2024 JAMES I. WHITE DirectorMarch 29, 2018