Oglethorpe Power Corporation

08/13/2026 | Press release | Distributed by Public on 08/13/2026 12:08

Quarterly Report for Quarter Ending June 30, 2026 (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 2025 Form 10-K.
Results of Operations
For the Three and Six Months Ended June 30, 2026 and 2025
Net Margin
Our net margin for the three-month and six-month periods ended June 30, 2026 were $16.2 million and $64.4 million, respectively, compared to $20.3 million and $63.3 million, respectively, for the same periods of 2025. Through June 30, 2026, we collected approximately 115% of our targeted net margin of $55.8 million for the year ending December 31, 2026. 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 2026 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 $22.0 million and $6.3 million as of June 30, 2026 and June 30, 2025, 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 2025 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 six-month periods ended June 30, 2026 and 2025 were as follows:
Three Months Ended
June 30, 		Six Months Ended
June 30,
(dollars in thousands)
2026 2025 % Change 2026 2025 % Change
Capacity revenues $ 395,398 $ 422,959 (6.5) % $ 817,639 $ 836,296 (2.2) %
Energy revenues 178,759 178,731 - % 463,519 433,695 6.9 %
Total $ 574,157 $ 601,690 (4.6) % $ 1,281,158 $ 1,269,991 0.9 %
MWh Sales to members(1)
8,388,348 8,086,872 3.7 % 15,380,268 15,504,762 (0.8) %
Cents/kWh 6.84 7.44 (8.0) % 8.33 8.19 1.7 %
Member energy requirements supplied 75 % 74 % 1.4 % 69 % 70 % (1.4) %
(1) Includes energy supplied to members for resale at wholesale and energy we supplied to our own facilities. Excludes test energy supplied to members. Revenues and costs associated with test energy were capitalized.
Energy revenues from members increased for the six-month period ended June 30, 2026 compared to the same period in 2025, primarily due to the recovery of higher fuel costs offset by a decrease in megawatt-hours sold to members. Energy revenues from members was relatively unchanged for the three-month period ended June 30, 2026 compared to the same period in 2025. For a discussion of fuel costs, which are the primary costs recovered by energy revenues, see "-Operating Expenses." Capacity revenues from members decreased slightly for the six-month period ended June 30, 2026 compared to the same period in 2025. Capacity revenues from members decreased for the three-month period ended June 30, 2026 compared to the same period in 2025 primarily due to the increase in refund liability recognized during the second quarter in 2026 compared to the same period in 2025.
Sales to non-members. Sales to non-members during the three-month and six-month periods ended June 30, 2026 and 2025 were as follows:
Three Months Ended
June 30, 		Six Months Ended
June 30,
(dollars in thousands)
2026 2025 % Change 2026 2025 % Change
Energy revenues 15,313 32,058 (52.2) % 45,368 41,333 9.8 %
Total $ 15,313 $ 32,058 (52.2) % $ 45,368 $ 41,333 9.8 %
MWh Sales to non-members 347,057 751,313 (53.8) % 566,716 928,044 (38.9) %
Cents/kWh 4.41 4.27 3.3 % 8.01 4.45 80.0 %
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 decreased for the three-month period ended June 30, 2026 compared to the same period in 2025 primarily due to a decrease in megawatt-hours sold to non-members and recovery of lower fuel costs. Energy revenues from non-members increased for the six-month period ended June 30, 2026 compared to the same period in 2025 primarily due to recovery of higher fuel costs offset by a decrease 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 June 30, Three Months Ended June 30, Three Months Ended June 30,
Fuel Source 2026 2025 % Change 2026 2025 % Change 2026 2025 % Change
Coal $ 26,822 $ 34,923 (23.2)% 689,435 799,502 (13.8)% 3.89 4.37 (11.0)%
Nuclear 27,770 29,954 (7.3)% 3,789,758 3,780,694 0.2% 0.73 0.79 (7.6)%
Gas:(2)
Combined Cycle 89,480 90,914 (1.6)% 3,746,968 3,731,235 0.4% 2.39 2.44 (2.0)%
Combustion Turbine 29,202 31,047 (5.9)% 781,162 775,755 0.7% 3.74 4.00 (6.5)%
$ 173,274 $ 186,838 (7.3)% 9,007,323 9,087,186 (0.9)% 1.92 2.06 (6.8)%
Cost
Generation(1)
Cents per kWh
(dollars in thousands) (MWh)
Six Months Ended June 30, Six Months Ended June 30, Six Months Ended June 30,
Fuel Source 2026 2025 % Change 2026 2025 % Change 2026 2025 % Change
Coal $ 58,163 $ 78,336 (25.8)% 1,510,838 1,997,285 (24.4)% 3.85 3.92 (1.8)%
Nuclear 52,688 57,572 (8.5)% 7,220,197 7,300,135 (1.1)% 0.73 0.79 (7.6)%
Gas:(2)
Combined Cycle 289,872 248,108 16.8% 6,739,064 6,701,097 0.6% 4.30 3.70 16.2%
Combustion Turbine 57,942 45,469 27.4% 969,307 880,025 10.1% 5.98 5.17 15.7%
$ 458,665 $ 429,485 6.8% 16,439,406 16,878,542 (2.6)% 2.79 2.54 9.8%
(1) Includes energy supplied to members for resale at wholesale and energy we supplied to our own facilities. Excludes test energy supplied to members. Revenues and costs associated with test energy were capitalized.
(2) Realized gains and losses on natural gas swaps are included in fuel expense.
Total fuel costs increased for the six-month period ended June 30, 2026 compared to the same period in 2025 as a result of an increase in the average cost of fuel offset by a decrease in generation for members. The increase in average fuel cost was primarily driven by significantly elevated natural gas prices during winter storm events from mid-January 2026 through mid-February 2026. The decrease in generation was primarily attributable to lower output from our coal-fired generating units compared to the same period in 2025, reflecting reduced dispatch during the six-month period ended June 30, 2026 compared to the same period in 2025 when natural gas costs were comparatively lower except during the winter storm events period. Total fuel costs decreased for the three-month period ended June 30, 2026 compared to the same period in 2025 primarily as a result of a decrease in generation for members and a decrease in the average cost of fuel. The decrease in generation was primarily attributable to lower output from our coal-fired generating units compared to the same period in 2025, reflecting reduced dispatch during the three-month period ended June 30, 2026 compared to the same period in 2025 when natural gas costs were comparatively lower.
Production Expenses
Production costs decreased for three-month and six-month periods ended June 30, 2026 as compared to the same periods in 2025 primarily as a result of lower fixed major maintenance outage costs associated with our natural gas-fired facilities offset by the deferral of net margins associated with BC Smith. Production costs can vary due to the number and extent of maintenance outages in a given year.
Depreciation and Amortization
Depreciation and amortization increased slightly for the three-month and six-month periods ended June 30, 2026 as compared to the same periods in 2025.
Interest Charges
Net interest charges remained relatively unchanged for the three-month and six-month periods ended June 30, 2026 as compared to the same periods in 2025. The allowance for debt funds used during construction increased for the three-month and six-month periods ended June 30, 2026 primarily due to capitalization of interest related to construction of Smarr Combined Cycle project as compared to the same periods in 2025.
Financial Condition
Balance Sheet Analysis as of June 30, 2026
Assets
Cash used for property additions for the six-month period ended June 30, 2026 totaled $623.7 million. Of this amount, $490.4 million related to construction work in progress during the six-month period ended June 30, 2026, primarily due to construction at our two new natural gas-fired generation resources as well as additions and replacements at our existing electric generating facilities. An additional $63.1 million was for nuclear fuel purchases.
The increase in the nuclear decommissioning trust fund was primarily due to the increase in the fair market value of investments due to continued appreciation in the stock market during the six-month period ended June 30, 2026.
Long-term investments decreased $6.9 million for the six-month period ended June 30, 2026, primarily due to a $39.1 million redemption of coal ash investments to fund settlement of asset retirement obligations, $33.3 million redeemed to fund expenses associated with our revenue deferral rate management plan, which was designed primarily to assist our members in managing the rate impacts associated with the new Vogtle units, and redemption of $18.1 million to fund major maintenance outages expenses. Offsetting these decreases was a $83.6 million increase in funds invested, including reinvestment of earnings. See Notes F and J of Notes to Unaudited Consolidated Financial Statements for a discussion of our member rate management programs and regulatory liabilities.
Inventories increased $35.4 million during the six-month period ended June 30, 2026 primarily due to an increase of $26.2 million in material and supplies at our electric generating facilities and an increase in fuel inventories of $9.2 million due to decreased generation at our coal-fired units and the associated decrease in coal burn.
Regulatory assets increased $13.3 million largely as a result of a $15.2 million increase in our asset associated with unrealized losses on our natural gas contracts and a $13.8 million increase in our deferral of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. Offsetting these increases was a $10.5 million decrease in our regulatory asset for the accelerated depreciation associated with the early retirement of Plant Wansley, which occurred in 2022, and an $8.9 million decrease in the deferral associated with coal ash pond asset retirement obligations.
Equity and Liabilities
Long-term debt and long-term debt and finance leases due within one year increased $26.5 million for the six-month period ended June 30, 2026 and was primarily the result of reclassification of $302.2 million of commercial paper to long-term debt that was refinanced through proceeds under Rural Utilities Service's Empowering Rural America (New ERA) loan program in July 2026, $175.7 million in advances under Rural Utilities Service-guaranteed loans and the reclassification of $39.1 million of commercial paper to long-term debt that was refinanced through proceeds under the CFC term loan in August 2026. Offsetting these increases was $497.6 million in debt service payments. See Note L of Notes to Unaudited Consolidated Financial Statements for additional information regarding long-term debt.
Short-term borrowings, which primarily provide interim financing for the new Smarr Combined Cycle and Talbot Unit No. 7 projects and the deferral of effects on net margin for Washington County Power Plant, BC Smith, Walton County and Baconton, increased $273.3 million during the six-month period ended June 30, 2026. This increase was primarily as a result of borrowings of $722.5 million, offset by the reclassification of $302.2 million of commercial paper to long-term debt that was refinanced through proceeds under the Rural Utilities Service's New ERA loan program in July 2026, repayments of $107.9 million and the reclassification of $39.1 million of commercial paper to long-term debt that was refinanced through proceeds under the CFC term loan in August 2026 for commercial paper that had been issued to finance operating costs for four of our electric generating facilities that were deferred or are currently being deferred by our members.
Accounts payable decreased $118.3 million during the six-month period ended June 30, 2026, primarily due to applying $70.6 million in credits to our members' bills in the first quarter of 2026 for a board-approved reduction in 2025 revenue in excess of the requirement to meet the 2025 targeted net margin, a $50.2 million decrease in Georgia Power payables and a $27.1 million decrease in trade payables offset by a $22.0 million refund liability recognized during the second quarter of 2026.
Other current liabilities decreased $12.7 million for the six-month period ended June 30, 2026, primarily as a result of a $27.3 million decrease in accrued property taxes offset by a $14.6 million increase in accrued liabilities principally for property additions for our new generation projects.
Regulatory liabilities increased $61.3 million for the six-month period ended June 30, 2026 primarily due to an $83.7 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 net $23.3 million increase in the liability for collections of future major maintenance outage costs. Offsetting these increases, was a $31.9 million decrease in the liability for our revenue deferral rate management plan, which is associated with the Vogtle Units No. 3 and No. 4, and a $10.6 million decrease in the liability associated with unrealized gains on our natural gas contracts. See Notes F and 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
Smarr Combined Cycle Generation Facility
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. As of June 30, 2026, we had incurred costs of approximately $662.0 million with respect to this project. For additional information regarding this project, see Note 14 in our 2025 Form 10-K.
Talbot Combustion Turbine Unit No. 7
We and our members have also approved the development and construction of an approximately 240-megawatt combustion turbine unit to be constructed at our Talbot Energy Facility in Talbot County, Georgia. Our current budget for this project, which includes capital costs, allowance for funds used during construction and a contingency amount, is approximately $440 million. The projected commercial operation date for this unit is 2029. As of June 30, 2026, we had incurred costs of approximately $68.5 million with respect to this project. For additional information regarding this project, see Note 15 in our 2025 Form 10-K.
We intend to finance the Smarr and Talbot projects on an intermediate-term basis through our commercial paper program as well as through intermediate-term capital markets debt issuances or bank financings. We are pursuing Rural Utilities Service financing as our primary source of long-term financing for the Smarr Combined Cycle and Talbot Unit No. 7 projects, subject to program availability, and we expect to issue first mortgage bonds for any costs not financed by the Rural Utilities Service.
Additional Approved Resources
We and our members have also approved the development and construction of several additional projects. One project is an approximately 713-megawatt, one-unit combined cycle generation facility. Our preliminary cost estimate for this project is approximately $2.3 billion to $2.7 billion and the projected commercial operation date is 2033. We are evaluating additional natural gas transportation options in connection with this resource. A second project is to modify one of our existing natural gas facilities by constructing an additional 209-megawatt combustion turbine unit to modernize and replace one or more older units. Our preliminary cost estimate for this modification is approximately $525 million to $625 million and the projected commercial operation date is 2032. We and our members are also proceeding with over 100 megawatts of capacity upgrades to some of our existing generation resources that will be phased in through 2031 and have an aggregate budget of approximately $200 million.
We and our members may also consider additional generation and capacity upgrades beyond these resources in the future. See "RISK FACTORS" for a discussion of certain risks associated with these new generation projects in our 2025 Form 10-K.
Plant Hatch
On June 12, 2026, the Nuclear Regulatory Commission approved Southern Nuclear Operating Company, Inc.'s subsequent license renewal application for Plant Hatch Units No. 1 and No. 2, renewing both units' operating licenses for an additional 20 years (through years 2054 and 2058 for Units No. 1 and No. 2, respectively).
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 2025 Form 10-K.
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. Certain compliance deadlines related to CCR management units were then extended in February 2026. On April 13, 2026, EPA proposed to amend the 2024 CCR regulations by modifying certain legacy surface impoundment and CCR management unit provisions; establishing compliance pathways that allow for site-specific considerations for closure requirements, among other things; and adopting new provision for beneficial use. 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.
Liquidity
At June 30, 2026, we had $767 million of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $122 million in cash and cash equivalents and $645 million 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 June 30, 2026
Expiration
Date
(dollars in millions)
Unsecured Facilities:
Syndicated Line among 11 banks led by CFC'(1)
$ 1,275 $ 198 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 June 30, 2026.
(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 June 30, 2026, $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 $1.3 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 June 30, 2026, our $1.1 billion 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,
•the interim refinancing of first mortgage bonds in an amount approximately equal to the regulatory assets established in connection with the retirement of Plant Wansley, pending receipt of proceeds from the Rural Utilities Service's zero-interest New ERA loan,
•costs related to capital expenditures for existing generating facilities, and
•net costs, after off-system sales revenues, associated with recently acquired generation facilities (BC Smith, Baconton, Washington County, and Walton County) prior to recovery through member rates.
In July 2026, we received $302.2 million of long-term financing through the Rural Utilities Service's zero-interest New ERA loan to refinance debt approximately equal to the regulatory assets established in connection with the retirement of Plant Wansley, the proceeds of which were used to repay the related commercial paper borrowings. In August 2026, we borrowed $41 million under the CFC Term Loan facility, to provide long-term financing for a portion of the net costs, after off-system sales revenues, associated with recently acquired generation facilities that were incurred prior to recovery through member rates. We used the proceeds from this loan advance to repay the related commercial paper borrowings.
We are pursuing Rural Utilities Service financing as our primary source of long-term financing for the Smarr Combined Cycle and Talbot Unit No. 7 projects as well as for capital expenditures for existing generating facilities, subject to program availability. 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. We intend to use long-term bank financing secured under our first mortgage indenture for the remaining net costs associated with recently acquired generation facilities that are incurred prior to recovery through member rates. We intend to seek intermediate-term financing through new unsecured bank loans and through first mortgage bond issuances in the capital markets to fund, prior to arranging long-term financing, a portion of the costs of the Smarr Combined Cycle and Talbot Unit No. 7 projects, and for capital expenditures on existing generating facilities.
Our unsecured committed lines of credit permit the issuance of up to $810 million in letters of credit on our behalf, of which $505 million remained available at June 30, 2026. This letter of credit issuance capacity includes up to $500 million under our $1.3 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 June 30, 2026, 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 June 30, 2026, we had $1.1 billion 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 June 30, 2026, we had five members participating in the program and a balance of $58.8 million remaining to be applied against future power bills.
Financing Activities
First Mortgage Indenture. At June 30, 2026, we had $12.6 billion of long-term debt outstanding, consisting of $12.2 billion 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, $0.3 billion of commercial paper that we reclassified to long-term debt in connection with our receipt of New ERA loan proceeds from the Rural Utilities Service on July 8, 2026 and $39.1 million of commercial paper that we reclassified to long-term debt in connection with our receipt of CFC term loan proceeds on August 10, 2026. On July 8, 2026, our long-term debt outstanding balance, under our first mortgage indenture increased from $12.2 billion to $12.5 billion due to our $0.3 billion advance under the Rural Utilities Service's New ERA loan.
See "Item 1-BUSINESS-OGLETHORPE POWER CORPORATION-First Mortgage Indenture" in our 2025 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 June 30, 2026 is provided in the table below:
Current Rural Utilities Service-Guaranteed Loans
Amount
Approved
Amount Advanced June 30, 2026
Amount Remaining June 30, 2026
(dollars in millions)
General and Environmental Improvements1, 2
$ 630.3 $ 510.3 $ 120.0
General and Environmental Improvements3, 4
755.2 408.8 346.4
General and Environmental Improvements5
112.6 - 112.6
Walton Acquisition 80.1 80.1 -
New ERA Wansley Debt Refinancing6
331.5 - 331.5
Total $ 1,909.7 $ 999.2 $ 910.5
(1) We are able to advance under this loan through September 30, 2026.
(2) We advanced an additional $32.9 million available under this loan in July 2026.
(3) We are able to advance under this loan through May 30, 2028.
(4) We advanced an additional $58.8 million available under this loan in July 2026.
(5) This loan was conditionally approved by the Rural Utilities Service in February 2026 and we expect to close and advance on this loan in 2027.
(6) The New ERA loan is a direct loan from the Rural Utilities Service. We advanced $302.2 million available under this loan in July 2026.
As of June 30, 2026, we had $2.9 billion of debt outstanding under various Rural Utilities Service-guaranteed loans.
Subsequent to June 30, 2026, the Rural Utilities Service conditionally approved two additional loans. In July 2026, the Rural Utilities Service conditionally approved a Rural Utilities Service-guaranteed loan for general and environmental improvements in the amount of $486.7 million that we expect to close on and advance by 2027. On August 6, 2026, the Rural Utilities Service conditionally approved a $3,324.3 million loan for our Smarr Combined Cycle project that we expect to close on and advance by 2028. The Smarr Combined Cycle loan is divided into a $1,861 million Rural Utilities Service direct loan and a $1,463 million Rural Utilities Service-guaranteed loan. We have also applied for an additional $415 million Rural Utilities Service-guaranteed loan to provide for long-term financing for our Talbot Unit No. 7 project. All loan applications are subject to review and approval by the Rural Utilities Service and, if conditionally committed, remain subject to standard loan closing conditions.
In December 2024, the Rural Utilities Service announced an award to us of a zero-interest loan of up to $331.5 million under its Empowering Rural America (New ERA) program established under the Inflation Reduction Act of 2022. On May 12, 2026, we and the Rural Utilities Service closed on this loan. We are obligated to use the loan proceeds to refinance an amount of debt approximately equal to the regulatory assets we established in connection with the retirement of the Wansley coal plant. On June 29, 2026, we issued commercial paper to redeem $297.8 million of outstanding taxable bonds and to pay approximately $4.4 million of prepayment premium related to the redemption. The redemption amount was approximately equal to the regulatory assets we established in connection with the retirement of the Wansley coal plant. On July 8, 2026, we received $302.2 million in loan proceeds from the Rural Utilities Service that we used to repay on July 9, 2026 the commercial paper that had been issued to refinance the existing debt. This refinancing resulted in interest expense savings that we will pass on to our members. In connection with our receipt of the loan proceeds, we reclassified, approximately $302.2 million of commercial paper to long-term debt as of June 30, 2026.
All of the amounts outstanding under Rural Utilities Service-guaranteed or direct loans are secured ratably with all other debt under our first mortgage indenture.
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 2025 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.
Oglethorpe Power Corporation published this content on August 13, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on August 13, 2026 at 18:09 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]