Oglethorpe Power Corporation

11/12/2025 | Press release | Distributed by Public on 11/12/2025 11:37

Quarterly Report for Quarter Ending September 30, 2025 (Form 10-Q)

Management's Discussion and Analysis of Financial Condition and Results of Operations
General
We are a Georgia electric membership corporation (an EMC) incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 38 retail electric distribution cooperative members. Our members are consumer-owned distribution cooperatives providing retail electric service in Georgia on a not-for-profit basis. Our principal business is providing wholesale electric power to our members, which we provide primarily from our generation assets and, to a lesser extent, from power purchased from other suppliers. As with cooperatives generally, we operate on a not-for-profit basis.
We have a substantially similar wholesale power contract with each member that extends to December 31, 2085, and each contract will continue thereafter until terminated by three years' written notice by us or the respective member. For additional information regarding our wholesale power contracts with our members, see "Item 1-BUSINESS-OGLETHORPE POWER CORPORATION-Wholesale Power Contracts" in our 2024 Form 10-K.
Results of Operations
For the Three and Nine Months Ended September 30, 2025 and 2024
Net Margin
Our net margin for the three-month and nine-month periods ended September 30, 2025 were $1.9 million and $65.2 million, compared to $10.6 million and $76.9 million for the same periods of 2024, respectively. Through September 30, 2025, we collected approximately 117% of our targeted net margin of $55.6 million for the year ending December 31, 2025. These collections are typical as our capacity revenues are generally recorded evenly throughout the year. We anticipate our board of directors will approve a budget adjustment by year end so that margins will achieve, but not exceed, the 2025 targeted margins for interest ratio of 1.10. As a result, we assessed our projected margin and annual revenue requirement to meet the targeted margins for interest ratio to determine if a refund liability should be recognized. As a result of this assessment, we recognized cumulative refund liabilities of $37.1 million and $41.8 million as of September 30, 2025 and September 30, 2024, respectively. For additional information regarding our net margin requirements and policy, see "Item 7-MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Summary of Cooperative Operations-Margins" in our 2024 Form 10-K.
Operating Revenues
Our operating revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members' service territories, operating costs, availability of electric generation resources, our decisions of whether to dispatch our owned, purchased or member-owned resources over which we have dispatch rights and our members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers, and sales to non-members.
Sales to 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. 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 the sales of electricity generated or purchased for our members. Energy revenues recover the variable costs of our business, including fuel, purchased energy and variable operation and maintenance expense.
The components of member revenues for the three-month and nine-month periods ended September 30, 2025 and 2024 were as follows:
Three Months Ended
September 30, 		Nine Months Ended
September 30,
(dollars in thousands) (dollars in thousands)
2025 2024 % Change 2025 2024 % Change
Capacity revenues $ 373,386 $ 362,852 2.9 % $ 1,209,682 $ 1,120,280 8.0 %
Energy revenues 220,862 152,645 44.7 % 654,557 492,854 32.8 %
Total $ 594,248 $ 515,497 15.3 % $ 1,864,239 $ 1,613,134 15.6 %
MWh Sales to members(1)
9,450,715 9,180,278 2.9 % 24,955,477 23,572,242 5.9 %
Cents/kWh 6.29 5.62 12.0 % 7.47 6.84 9.2 %
Member energy requirements supplied(1)
71 % 71 % 0.0 % 71 % 69 % 2.9 %
(1)Excludes test energy megawatt-hours from Plant Vogtle Unit No. 4 supplied to members during the nine-month period ended September 30, 2024. Any revenues and costs associated with test energy were capitalized.
Energy revenues from members increased for the three-month and nine-month periods ended September 30, 2025 compared to the same periods in 2024, primarily due to the increase in megawatt-hours sold to members and recovery of higher fuel costs. For a discussion of fuel costs, which are the primary costs recovered by energy revenues, see "-Operating Expenses." Capacity revenues from members increased for the nine-month period ended September 30, 2025 compared to the same period in 2024, primarily due to the recovery of increased fixed operating expenses, net interest expense and depreciation expense as a result of Plant Vogtle Unit No. 4 being placed in service on April 29, 2024. Capacity revenues from members increased slightly for the three-month period ended September 30, 2025 compared to the same period in 2024.
Sales to non-members.Sales to non-members during the three-month and nine-month periods ended September 30, 2025 and 2024 were as follows:
Three Months Ended
September 30, 		Nine Months Ended
September 30,
(dollars in thousands) (dollars in thousands)
2025 2024 % Change 2025 2024 % Change
Energy revenues $ 37,213 $ 25,173 47.8 % $ 78,546 $ 26,368 197.9 %
Capacity revenues - - N/M - 1,572 (100.0) %
Total $ 37,213 $ 25,173 47.8 % $ 78,546 $ 27,940 181.1 %
MWh Sales to non-members 762,970 707,330 7.9 % 1,691,014 760,831 122.3 %
Cents/kWh 4.88 3.56 37.1 % 4.64 3.67 26.4 %
N/M - Not meaningful
Energy revenues from non-members were primarily from the sale of the BC Smith Energy Facility's deferring members' output into the wholesale market. Energy revenues from non-members increased for the three-month and nine-month periods ended September 30, 2025 compared to the same periods in 2024 primarily due to an increase in megawatt-hours sold to non-members.
Operating Expenses
Fuel
The following table summarizes our fuel costs and megawatt-hour generation by generating source.
Cost
Generation(1)
Cents per kWh
(dollars in thousands) (MWh)
Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30,
Fuel Source 2025 2024 % Change 2025 2024 % Change 2025 2024 % Change
Coal $ 31,169 $ 35,160 (11.4)% 836,938 935,786 (10.6)% 3.72 3.76 (1.1)%
Nuclear 30,604 31,428 (2.6)% 3,878,065 3,679,964 5.4% 0.79 0.85 (7.1)%
Nuclear Fuel Credits(2)
- (37,300) N/M - - N/M N/M N/M N/M
Gas:(3)
Combined Cycle 111,866 86,417 29.4% 4,496,624 4,268,071 5.4% 2.49 2.02 23.3%
Combustion Turbine 51,120 36,877 38.6% 1,264,931 1,229,627 2.9% 4.04 3.00 34.7%
$ 224,759 $ 152,582 47.3% 10,476,558 10,113,448 3.6% 2.15 1.51 42.4%
Cost
Generation(1)
Cents per kWh
(dollars in thousands) (MWh)
Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30,
Fuel Source 2025 2024 % Change 2025 2024 % Change 2025 2024 % Change
Coal $ 109,505 $ 110,950 (1.3)% 2,834,223 2,768,633 2.4% 3.86 4.01 (3.7)%
Nuclear 88,176 87,001 1.4% 11,178,200 10,554,329 5.9% 0.79 0.82 (3.7)%
Nuclear Fuel Credits(2)
- (37,300) N/M - - N/M N/M N/M N/M
Gas:(3)
Combined Cycle 359,974 243,702 47.7% 11,197,721 9,810,906 14.1% 3.21 2.48 29.4%
Combustion Turbine 96,589 63,738 51.5% 2,144,956 1,823,543 17.6% 4.50 3.50 28.6%
$ 654,244 $ 468,091 39.8% 27,355,100 24,957,411 9.6% 2.39 1.88 27.1%
(1)Excludes test energy megawatt-hours generated at Plant Vogtle Unit No. 4 during the nine-month period ended September 30, 2024.
(2)Represents credits to fuel expense for settlements related to spent nuclear fuel storage costs. For additional information regarding spent nuclear fuel storage costs litigation, see Notes 1e and 1g in our 2024 Form 10-K.
(3)Realized gains and losses on natural gas swaps are included in fuel expense.
N/M - Not meaningful
Total fuel costs increased for the three-month and nine-month periods ended September 30, 2025 compared to the same periods in 2024 as a result of an increase in the average cost of fuel and an increase in generation for members. The increase in average fuel cost was primarily due to higher average natural gas prices during the three-month and nine-month periods ended September 30, 2025 compared to the same periods in 2024 as prices have increased due to supply and demand pressures. The increase in generation was primarily due to the output from BC Smith, which underwent a major maintenance outage during the comparable periods in 2024, and from Plant Vogtle Unit No. 4 being placed in service on April 29, 2024. Coal-fired generation increased for the nine-month period ended September 30, 2025 compared to the same period in 2024 primarily as a result of the higher average natural gas prices, which caused generation from the coal-fired units to be relatively more economical. Coal-fired generation decreased slightly for the three-month period ended September 30, 2025 compared to the same period in 2024 due to temporary constraints on our ability to obtain additional coal.
Based on meter readings, our member system hit a new summer peak demand of approximately 10,420 megawatts in July 2025, exceeding our members' prior summer peak of 10,092 megawatts in July 2024.
Production Expenses
Production costs increased for the three-month and nine-month periods ended September 30, 2025 as compared to the same periods in 2024 primarily as a result of $24.6 million and $70.2 million in production costs related to Plant Vogtle Units No. 3 and No. 4, net of $22.1 million and $66.9 million in credits recognized during the respective periods from the sale of nuclear production tax credits to Georgia Power and the deferral of net margins associated with BC Smith. The increase in production costs for the nine-month period ended September 30, 2025 was offset by $18.1 million in lower fixed major maintenance outage costs associated with our natural gas-fired facilities compared to the same period in 2024. Major maintenance outage costs associated with our natural gas-fired facilities was relatively unchanged for the three-month period ended September 30, 2025 as compared to the same period in 2024. Production costs can also vary due to the number and extent of maintenance outages in a given year.
Depreciation and Amortization
Depreciation and amortization increased for the nine-month period ended September 30, 2025 as compared to the same period in 2024 primarily as a result of Plant Vogtle Unit No. 4 being placed in service on April 29, 2024. Depreciation and amortization was relatively unchanged for the three-month period ended September 30, 2025 as compared to the same period in 2024.
Interest Charges
Net interest charges increased for the nine-month period ended September 30, 2025 as compared to the same period in 2024 as a result of lower capitalized interest expense due to Plant Vogtle Unit No. 4 being placed in service on April 29, 2024. Net interest charges was relatively unchanged for the three-month period ended September 30, 2025 as compared to the same period in 2024.
Financial Condition
Balance Sheet Analysis as of September 30, 2025
Assets
Cash used for property additions for the nine-month period ended September 30, 2025 totaled $569.6 million. Of this amount, construction work in progress increased $406.4 million during the nine-month period ended September 30, 2025, primarily due to additions and replacements at our existing electric generating facilities as well as construction at our two new natural gas-fired generation resources. An additional $95.2 million was for nuclear fuel purchases and $30.6 million was associated with construction expenditures for Vogtle Unit No. 4. The remainder was for expenditures related to normal additions and replacements to our existing generation facilities.
The $111.2 million increase in the nuclear decommissioning trust fund was primarily due to a $59.7 million increase in the fair value of investments due to continued appreciation in the stock market, $43.2 million in investment earnings and $8.3 million in contributions to our nuclear decommissioning trust fund during the nine-month periodended September 30, 2025.
Receivables decreased $15.8 million for the nine-month period ended September 30, 2025 primarily due to a $42.2 million decrease in Georgia Power receivables primarily related to spent nuclear fuel storage cost litigation. Largely offsetting this decrease was a $13.0 million increase in member receivables and a $8.7 million increase in other non-member receivables.
Inventories decreased $6.7 million during the nine-month period ended September 30, 2025 primarily due to a decrease in fuel inventories of $20.2 million due to increased generation at our coal-fired units and the associated increase in coal burn. Such decrease was offset by an increase of $13.5 million in material and supplies at our electric generating facilities.
Regulatory assets decreased $33.7 million largely as a result of a $16.0 million decrease in the deferral associated with coal ash pond asset retirement obligations and a $15.8 million decrease in our regulatory asset for the accelerated depreciation associated with the early retirement of Plant Wansley, which occurred in 2022.
Equity and Liabilities
Long-term debt and long-term debt and finance leases due within one year decreased $57.1 million. This was primarily the result of $276.1 million in debt service payments and reclassifying $254.5 million of commercial paper, which was classified as long-term debt at December 31, 2024 due to the refinancing of that commercial paper by the issuance of the Series 2025A green first mortgage bonds in January 2025, to short-term borrowings. Offsetting these decreases was the issuance of $350.0 million of our Series 2025A green first mortgage bonds and $124.3 million in advances under Rural Utilities Service-guaranteed loans. See Note L of Notes to Unaudited Consolidated Financial Statements for additional information regarding long-term debt.
At September 30, 2025, short-term borrowings, which primarily provide interim financing for costs related to the Walton County acquisition, the new Smarr Combined Cycle and Talbot Unit No. 7 projects and the deferral of effects on net margin for BC Smith and the Washington County Power Plant, increased $105.5 million during the nine-month period ended September 30, 2025, primarily as a result of borrowings of $117.8 million. At December 31, 2024, short-term borrowings were primarily related to interim financing for Vogtle Units No. 3 and No. 4 construction costs.
Accounts payable increased $15.9 million during the nine-month period ended September 30, 2025, primarily due to a $27.2 million increase in Georgia Power payables and a $6.7 million increase in payables for natural gas purchases and related transportation offset by a net decrease of $18.8 million in payables to our members by applying $55.9 million in credits to our members' bills in the first quarter of 2025 for a board-approved reduction in 2024 revenue in excess of the requirement to meet the 2024 targeted net margin, offset by a $37.1 million refund liability recognized during the third quarter of 2025.
Other current liabilities increased $109.5 million for the nine-month period ended September 30, 2025, primarily as a result of a $108.9 million increase in accrued liabilities principally for property additions for our new generation projects.
Regulatory liabilities increased $27.6 million for the nine-month period ended September 30, 2025 primarily due to a $121.3 million increase in deferred nuclear asset retirement obligations that was primarily driven by an increase in unrealized gains associated with our nuclear decommissioning investments, and a $11.3 million increase in the liability for collections of future debt service payments. Offsetting these increases was a $66.5 million decrease in the liability for our revenue deferral rate management plan, which is associated with the new Vogtle units, a $23.9 million decrease in the liability of retirement costs associated with long-lived assets for which there are no legal obligations to retire such assets, a $9.7 million decrease in the liability associated with unrealized gains on our natural gas contracts, and a net $4.4 million decrease in the liability for collections of future major maintenance outage costs. See Notes F and Note J of Notes to Unaudited Consolidated Financial Statements for a discussion of our member rate management programs and regulatory liabilities.
Capital Requirements and Liquidity and Sources of Capital
Future Power Resources
We and our members have approved the development and construction of an approximately 1,425-megawatt, two-unit combined cycle generation facility to be located on land we own adjacent to the Smarr Energy Facility in Monroe County, Georgia. Our current budget for this project, which includes capital costs, allowance for funds used during construction and a contingency amount, is $3.3 billion. The projected commercial operation date is 2029. In September 2025, we entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with TIC - The Industrial Company, a subsidiary of Kiewit Energy Group Inc., for the construction of the project. The EPC Agreement is a fixed price agreement with certain limited exceptions that includes performance guarantees and performance liquidated damages and a parent guaranty by Kiewit. We have separately entered into an agreement with GE Verona Operations, LLC for the purchase of the two combustion cycle units. As of September 30, 2025, we had incurred costs of approximately $202.3 million with respect to this project.
We intend to finance the Smarr project on a short-term basis through our commercial paper program and may pursue medium-term loans for intermediate financing. Our preferred source of long-term financing for this project is loans from the Federal Financing Bank guaranteed by the Rural Utilities Service, and we expect to issue first mortgage bonds for any costs not financed by the Rural Utilities Service.
See "RISK FACTORS" in our 2024 Form 10-K for a discussion of certain risks associated with the construction and financing of new generation projects.
For additional information regarding other on-going capital projects, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Financial Condition-Capital Requirements and Liquidity and Sources of Capital-Other Future Power Resources" in our quarterly report on Form 10-Q for the quarterly period ended March 31, 2025. We and our members may also continue to consider additional generation resources in the future.
Environmental Regulations
Federal and state laws and regulations regarding environmental matters affect operations at our facilities. For a discussion regarding potential effects on our business from environmental regulations, including potential capital requirements, see "Item 1-BUSINESS-REGULATION-Environmental," "Item 1A-RISK FACTORS" and "Item 7-MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Financial Condition-Capital Requirements-Capital Expenditures" in our 2024 Form 10-K.
In May 2024, the Environmental Protection Agency published a final rule under Clean Air Act sections 111(b) and 111(d) to limit greenhouse gas emissions from new gas turbines and existing coal plants, respectively. This final rule replaces the
Affordable Clean Energy Rule, which was vacated and remanded to EPA in 2021 by the U.S. Court of Appeals for the District of Columbia. As written, the final rule would likely adversely impact a portion of our coal and natural gas-fired generating units and have a significant impact on the U.S. power sector overall. Under the new rule, gas-fired turbines that operate above a 20% capacity factor are required to meet stringent carbon dioxide emissions standards, including adding carbon capture and sequestration (CCS) by January 1, 2032, for baseload units operating above a 40% capacity factor. Exiting coal plants are required to either 1) cease operations by January 1, 2032, with no additional restrictions; 2) co-fire with 40% natural gas by January 1, 2030, and operate to January 1, 2039; or 3) reduce carbon dioxide emissions by 90% using CCS by January 1, 2032, to operate beyond January 1, 2039. However, the Trump administration has issued executive orders, among which include withdrawing from the Paris Climate Agreement and revoking any attendant carbon dioxide emissions goals and commitments, and stated its intention to rescind, revise or replace some existing environmental regulations, which would include regulations for greenhouse gas emissions from power plants. On March 12, 2025, EPA announced that it would reconsider regulations to limit greenhouse gas emissions from power plants. Additionally, EPA's final rule is being challenged in the U.S. Court of Appeals for the District of Columbia. In February 2025, the court granted EPA's request that the court withhold issuing an opinion and hold the case in abeyance for 60 days while EPA determines how it wishes to proceed. On April 25, 2025, the U.S. Court of Appeals for the D.C. Circuit granted EPA's motion requesting a continuing abeyance of the litigation over the greenhouse gas rule EPA issued in 2024. EPA stated in its motion that it will issue a proposed reconsideration rule in spring 2025 and a final reconsideration rule by December 2025. On June 17, 2025, EPA published a proposed rule that included both a primary proposal to repeal all greenhouse gas standards for power plants, and an alternative proposal to repeal the standards for existing coal-fired plants and the CCS-based standards for new gas-fired combustion turbines, which would have required combustion turbines either to have CCS installed by 2032 or to limit operations to a 40% capacity factor or less beginning in 2032. Although we continue to evaluate the impact of EPA's greenhouse gas rule on our power plants, we cannot predict the outcome of any regulatory actions or the result of potential litigation challenging any of these actions.
In 2015, EPA established a comprehensive regulatory program to manage the disposal of coal combustion residuals (CCR) from coal-fired power plants as non-hazardous material under the Resource Conservation and Recovery Act (RCRA). The 2015 CCR rule sets 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. Since 2015, EPA has made subsequent revisions to CCR requirements and, beginning in 2022, EPA issued a number of proposed and final determinations on requests for extensions of time to close ash ponds, which could affect the Georgia Environmental Protection Division's (EPD) review of the proposed closure plans for the coal ash ponds at Plants Wansley and Scherer. In May 2024, EPA adopted new CCR regulations that expanded regulatory requirements to cover Legacy Surface Impoundments and CCR Management Units that were previously exempt. Then, on July 22, 2025, EPA proposed a rule modifying and extending certain compliance deadlines related to CCR management units. A final rule is expected in 2026. We continue to monitor EPA's actions related to CCR; however, the ultimate impact is unknown at this time and subject to the outcome of ongoing litigation and any future EPA and Georgia regulatory actions.
In May 2024, the EPA published a final supplemental effluent limitations guideline (ELG) rule, which generally increases the stringency of the wastewater discharge standards. Taken together, the ELG rule revisions are expected to increase capital and operating costs of affected units. However, because of the compliance strategy for Plant Scherer, we do not anticipate significant additional impacts related to more stringent requirements in the supplemental ELG rule. The 2024 supplemental ELG rule is being challenged in federal court. In February 2025, EPA requested, and the court granted, a 60-day abeyance to determine how EPA wishes to proceed with the litigation. Additionally, certain Trump administration executive orders direct EPA to develop and implement action plans that suspend, revise, or rescind certain environmental regulations. On March 12, 2025, EPA announced that it will reconsider the supplemental ELG rule. On October 2, 2025, EPA published a proposed rule extending certain compliance deadlines for the ELG rules that apply to coal-fired power plants. A final rule is expected in 2026. We continue to monitor EPA's actions related to ELG; however, the ultimate impact is unknown at this time and subject to the outcome of ongoing litigation and any future EPA regulatory changes.
Liquidity
At September 30, 2025, we had $1.8 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $311 million in cash and cash equivalents and $1.5 billion available under our $1.7 billion of committed credit arrangements, the details of which are reflected in the table below:
Committed Credit Facilities
Authorized
Amount
Available September 30, 2025
Expiration
Date
(dollars in millions)
Unsecured Facilities:
Syndicated Line among 12 banks led by CFC'(1)
$ 1,275 $ 1,023 May 2029
CFC Line of Credit(2)
110 110 December 2028
JPMorgan Chase Line of Credit(3)
200 197 March 2027
Secured Facilities:
CFC Term Loan(2)
250 140 December 2028
(1)This facility is dedicated to support outstanding commercial paper and the portion of this facility that was unavailable represents the face value of outstanding commercial paper at September 30, 2025.
(2)Any amounts drawn under the $110 million unsecured line of credit with CFC will reduce the amount that can be drawn under the $250 million secured term loan. Therefore, we reflect $140 million as the amount available under the term loan even though there are no amounts outstanding under that facility. Any amounts borrowed under the $250 million term loan would be secured under our first mortgage indenture, with a maturity no later than December 31, 2043.
(3)At September 30, 2025, $2.5 million of this facility was used for letters of credit issued to provide performance assurance to third parties.
A portion of our unrestricted available liquidity is allocated to support $40.5 million of weekly variable rate bonds that do not have external credit or liquidity support. The holders of these bonds may tender their bonds for purchase upon seven days' notice, and we are obligated to purchase any of these bonds which are tendered for purchase and not remarketed.
We have the flexibility to use the $1.275 billion syndicated line of credit for several purposes, including borrowing for general corporate purposes, issuing letters of credit and backing up commercial paper.
Under our commercial paper program, we are authorized to issue commercial paper in amounts that do not exceed the amount of our committed backup lines of credit, thereby providing 100% dedicated support for any commercial paper outstanding. Due to this requirement, any commercial paper we issue will reduce the availability under the $1.3 billion syndicated line of credit. At September 30, 2025, our $251.1 million of outstanding commercial paper was primarily used to provide interim funding for:
•costs related to the new Smarr Combined Cycle and Talbot Unit No. 7 projects,
•costs related to the Walton County Power Plant acquisition, and
•costs related to the deferral of effects on net margin of our recently acquired facilities: BC Smith, Baconton Power Plant, two units at the Washington County Power Plant and Walton County Power Plant.
Rural Utilities Service financing is our preferred source of long-term financing for the Walton County acquisition, and for the Smarr Combined Cycle and Talbot Unit No. 7 projects. We intend to issue first mortgage bonds to provide long-term financing for certain other costs, including any costs for the Smarr Combined Cycle and Talbot Unit No. 7 projects not financed by the Rural Utilities Service, and for the deferral of effects on net margin of our recently acquired facilities. We may also seek intermediate-term financing for the Smarr Combined Cycle project to finance a portion of the costs of this project prior to arranging long-term financing.
Our unsecured committed lines of credit permit the issuance of up to $810 million in letters of credit on our behalf, of which $807 million remained available at September 30, 2025. This letter of credit issuance capacity includes $500 million under our $1.275 billion syndicated line of credit, $200 million under our JPMorgan Chase line of credit, and $110 million under our CFC line of credit. Between projected cash on hand and the credit arrangements currently in place, we believe we have sufficient liquidity to cover normal operations and our interim financing needs, including interim financing for the new natural gas resources, until intermediate or long-term financing is obtained.
Three of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At September 30, 2025, the highest required minimum level was $900 million and our actual patronage capital balance was $1.4 billion. Two of these agreements contain an additional covenant that limits our unsecured indebtedness, as defined in the credit agreements, to $4 billion. At September 30, 2025, we had $251.1 million of unsecured indebtedness outstanding.
Under our power bill prepayment program, members can prepay their power bills from us at a discount for an agreed number of months in advance, after which point the funds are credited against the participating members' monthly power bills. At September 30, 2025, we had five members participating in the program and a balance of $68.1 million remaining to be applied against future power bills.
Financing Activities
First Mortgage Indenture.At September 30, 2025, we had $12.6 billion of long-term debt outstanding under our first mortgage indenture secured equally and ratably by a lien on substantially all of our owned tangible and certain of our intangible property, including property we acquire in the future. See "Item 1-BUSINESS-OGLETHORPE POWER CORPORATION-First Mortgage Indenture" in our 2024 Form 10-K for further discussion of our first mortgage indenture.
Rural Utilities Service-Guaranteed Loans.A summary of our current Rural Utilities Service-Guaranteed Loans as of September 30, 2025 is provided in the table below:
Current Rural Utilities Service-Guaranteed Loans
Amount
Approved
Amount Advanced September 30, 2025
Amount Remaining September 30, 2025
(dollars in millions)
General and Environmental Improvements1
$ 630.3 $ 469.6 $ 160.7
General and Environmental Improvements2
755.2 302.6 452.6
Total $ 1,385.5 $ 772.2 $ 613.3
(1)We are able to advance under this loan through September 30, 2026.
(2)We are able to advance under this loan through May 30, 2028.
In February 2025, we received a conditional commitment from the Rural Utilities Service for a guaranteed loan of $80.1 million for our acquisition of the Walton County Power Plant. We expect to close and advance on that loan by early 2026.
When advanced, the debt will be secured ratably under our first mortgage indenture. As of September 30, 2025, we had $2.8 billion of debt outstanding under various Rural Utilities Service-guaranteed loans.
Department of Energy-Guaranteed Loans. We have loans from the Federal Financing Bank guaranteed by the Department of Energy that provided funding for over $4.6 billion of the cost to construct our interest in Vogtle Units No. 3 and No. 4. We have fully advanced the $4.6 billion available under these loans. As of September 30, 2025, we had repaid $682.0 million and $4.0 billion remained outstanding. All of the debt advanced under the loan guarantee agreement is secured ratably with all other debt under our first mortgage indenture. For more information regarding the loan guarantee agreement, see Note L of Notes to Unaudited Consolidated Financial Statements.
For more detailed information regarding our financing plans, see "Item 7-MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Financial Condition-Financing Activities" in our 2024 Form 10-K.
Newly Adopted or Issued Accounting Standards
For a discussion of recently issued or adopted accounting pronouncements, see Note E of Notes to Unaudited Consolidated Financial Statements.
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