Oglethorpe Power Corporation
11/12/2026 | Press release | Distributed by Public on 11/12/2026 14:42
Quarterly Report for Quarter Ending September 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 Nine Months Ended September 30, 2026 and 2025
Net Margin
Our net margin for the three-month and nine-month periods ended September 30, 2026 were $19.9 million and $84.2 million, respectively, compared to $1.9 million and $65.2 million, respectively, for the same periods of 2025. Through September 30, 2026, we collected approximately 151.7% of our targeted net margin of $55.5 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 $38.0 million and $37.1 million as of September 30, 2026 and September 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 nine-month periods ended September 30, 2026 and 2025 were as follows:
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
||||||||||||||||||||||||||||||||||
| (dollars in thousands) | |||||||||||||||||||||||||||||||||||
| 2026 | 2025 | % Change | 2026 | 2025 | % Change | ||||||||||||||||||||||||||||||
| Capacity revenues | $ | 397,847 | $ | 373,386 | 6.6 | % | $ | 1,215,486 | $ | 1,209,682 | 0.5 | % | |||||||||||||||||||||||
| Energy revenues | 268,425 | 220,862 | 21.5 | % | 731,944 | 654,557 | 11.8 | % | |||||||||||||||||||||||||||
| Total | $ | 666,272 | $ | 594,248 | 12.1 | % | $ | 1,947,430 | $ | 1,864,239 | 4.5 | % | |||||||||||||||||||||||
|
MWh Sales to members(1)
|
10,507,469 | 9,450,715 | 11.2 | % | 25,887,737 | 24,955,477 | 3.7 | % | |||||||||||||||||||||||||||
| Cents/kWh | 6.34 | 6.29 | 0.8 | % | 7.52 | 7.47 | 0.7 | % | |||||||||||||||||||||||||||
| Member energy requirements supplied | 72 | % | 71 | % | 1.4 | % | 70 | % | 71 | % | (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 three-month and nine-month periods ended September 30, 2026 compared to the same periods in 2025, primarily due to the recovery of higher fuel costs and an increase in megawatt-hours sold to members. 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 three-month period ended September 30, 2026 compared to the same period in 2025 primarily due to a decrease in refund liability recognized during the third quarter in 2026 compared to the same period in 2025. Capacity revenues from members were relatively unchanged for the nine-month period ended September 30, 2026 compared to the same period in 2025.
Sales to non-members. Sales to non-members during the three-month and nine-month periods ended September 30, 2026 and 2025 were as follows:
|
Three Months Ended September 30, |
Nine Months Ended September 30, |
||||||||||||||||||||||||||||||||||
| (dollars in thousands) | |||||||||||||||||||||||||||||||||||
| 2026 | 2025 | % Change | 2026 | 2025 | % Change | ||||||||||||||||||||||||||||||
| Energy revenues | $ | 27,922 | $ | 37,213 | (25.0) | % | $ | 73,290 | $ | 78,546 | (6.7) | % | |||||||||||||||||||||||
| Total | $ | 27,922 | $ | 37,213 | (25.0) | % | $ | 73,290 | $ | 78,546 | (6.7) | % | |||||||||||||||||||||||
| MWh Sales to non-members | 475,502 | 762,970 | (37.7) | % | 1,042,218 | 1,691,014 | (38.4) | % | |||||||||||||||||||||||||||
| Cents/kWh | 5.87 | 4.88 | 20.3 | % | 7.03 | 4.64 | 51.5 | % | |||||||||||||||||||||||||||
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 and nine-month periods ended September 30, 2026 as compared to the same periods in 2025 primarily due to a decrease in megawatt-hours sold to non-members offset by the recovery of higher fuel costs.
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 | 2026 | 2025 | % Change | 2026 | 2025 | % Change | 2026 | 2025 | % Change | ||||||||||||||||||||||||||||||||||||||||||||
| Coal | $ | 48,909 | $ | 31,169 | 56.9% | 1,329,131 | 836,938 | 58.8% | 3.68 | 3.72 | (1.1)% | ||||||||||||||||||||||||||||||||||||||||||
| Nuclear | 28,951 | 30,604 | (5.4)% | 3,969,697 | 3,878,065 | 2.4% | 0.73 | 0.79 | (7.6)% | ||||||||||||||||||||||||||||||||||||||||||||
|
Gas:(2)
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||
| Combined Cycle | 133,946 | 111,866 | 19.7% | 4,743,670 | 4,496,624 | 5.5% | 2.82 | 2.49 | 13.3% | ||||||||||||||||||||||||||||||||||||||||||||
| Combustion Turbine | 57,357 | 51,120 | 12.2% | 1,260,874 | 1,264,931 | (0.3)% | 4.55 | 4.04 | 12.6% | ||||||||||||||||||||||||||||||||||||||||||||
| $ | 269,163 | $ | 224,759 | 19.8% | 11,303,372 | 10,476,558 | 7.9% | 2.38 | 2.15 | 10.7% | |||||||||||||||||||||||||||||||||||||||||||
| 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 | 2026 | 2025 | % Change | 2026 | 2025 | % Change | 2026 | 2025 | % Change | ||||||||||||||||||||||||||||||||||||||||||||
| Coal | $ | 107,073 | $ | 109,505 | (2.2)% | 2,839,969 | 2,834,223 | 0.2% | 3.77 | 3.86 | (2.3)% | ||||||||||||||||||||||||||||||||||||||||||
| Nuclear | 81,639 | 88,176 | (7.4)% | 11,189,894 | 11,178,200 | 0.1% | 0.73 | 0.79 | (7.6)% | ||||||||||||||||||||||||||||||||||||||||||||
|
Gas:(2)
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||
| Combined Cycle | 423,818 | 359,974 | 17.7% | 11,482,734 | 11,197,721 | 2.5% | 3.69 | 3.21 | 15.0% | ||||||||||||||||||||||||||||||||||||||||||||
| Combustion Turbine | 115,298 | 96,589 | 19.4% | 2,230,181 | 2,144,956 | 4.0% | 5.17 | 4.50 | 14.9% | ||||||||||||||||||||||||||||||||||||||||||||
| $ | 727,828 | $ | 654,244 | 11.2% | 27,742,778 | 27,355,100 | 1.4% | 2.62 | 2.39 | 9.6% | |||||||||||||||||||||||||||||||||||||||||||
(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 nine-month period ended September 30, 2026 compared to the same period in 2025 primarily as a result of an increase in the average cost of fuel. 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. Total fuel costs increased for the three-month period ended September 30, 2026 compared to the same period in 2025 primarily as a result of an increase in the average cost of fuel and an increase in generation for members. The increase in generation was primarily attributable to higher output from our coal-fired generating units compared to the same period in 2025.
In August 2026, our member system hit a new summer peak demand of approximately 10,786 megawatts, exceeding our members' prior summer peak of 10,424 megawatts in July 2025. We measure our members' peaks at the members' delivery points, which is net of system losses, so this new summer peak did not exceed our all-time peak of 10,810 megawatts set in December 2022. However, in August 2026, the system peak hour demand measured at our generating resources reached 11,123 megawatts, exceeding the 11,032 megawatts of demand measured at our generating resources in December 2022, although system losses from the generation resources to the members' delivery points were slightly higher in August 2026 compared to December 2022.
Production Expenses
Production costs decreased for the nine-month period ended September 30, 2026 as compared to the same period 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 remained relatively unchanged for the three-month period ended September 30, 2026 as compared to the same period in 2025. 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 nine-month periods ended September 30, 2026 as compared to the same periods in 2025.
Interest Charges
Net interest charges remained relatively unchanged for the three-month and nine-month periods ended September 30, 2026 as compared to the same periods in 2025. The allowance for debt funds used during construction increased for the three-month and nine-month periods ended September 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 September 30, 2026
Assets
Cash used for property additions for the nine-month period ended September 30, 2026 totaled $904.3 million. Of this amount, $668.3 million related to construction work in progress during the nine-month period ended September 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 $87.8 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 nine-month period ended September 30, 2026.
Long-term investments decreased $0.6 million for the nine-month period ended September 30, 2026, primarily due to $49.9 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, $39.1 million redemption of coal ash investments to fund settlement of asset retirement obligations, and redemption of $24.8 million to fund major maintenance outages expenses. Offsetting these decreases was a $113.2 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.
Other investments, at cost, decreased $26.7 million during the nine-month period ended September 30, 2026, primarily due to a reclassification of $28.4 million in long-term investments to current. These investments are scheduled to mature in 2027 and will be used to pay Rocky Mountain Leasing Corporation's lease liabilities in 2027. See Note 4 in our 2025 Form 10-K for additional information regarding this lease termination.
Inventories increased $38.7 million during the nine-month period ended September 30, 2026, primarily due to an increase of $34.0 million in material and supplies at our electric generating facilities and an increase in fuel inventories of $4.7 million.
Receivables increased $37.2 million during the nine-month period ended September 30, 2026, primarily due to a $19.3 million increase in receivables from Georgia Power and an increase of $17.4 million in receivables from related parties.
Prepayments and other current assets increased $19.1 million during the nine-month period ended September 30, 2026, primarily due to a reclassification of $28.4 million in long-term investments to current offset by a $12.3 million decrease in the fair value of our natural gas hedges.
Equity and Liabilities
Obligation under Rocky Mountain transactions decreased $26.7 million for the nine-month period ended September 30, 2026, primarily as a result of a reclassification of $28.4 million in long-term lease liabilities, payable by our subsidiary, to other current liabilities.
Long-term debt and long-term debt and finance leases due within one year increased $496.0 million for the nine-month period ended September 30, 2026. This increase was primarily the result of (i) $302.2 million in advances under Rural Utilities Service's Empowering Rural America (New ERA) loan program in July 2026, (ii) a reclassification of $300.0 million of commercial paper to long-term debt that was refinanced through proceeds under a $650.0 million term loan credit agreement with five lenders, including Bank of America, N.A., as administrative agent, in October 2026, (iii) $267.4 million in advances under Rural Utilities Service-guaranteed loans, (iv) reclassification of $145.4 million of commercial paper to long-term debt that was refinanced through proceeds under a $200.0 million term loan credit agreement with CoBank, ACB as administrative
agent, in October 2026 and (v) a $40.9 million advance under a CFC term loan. Offsetting these increases was $568.5 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 for general and environmental improvements at our other generating facilities, increased $51.7 million during the nine-month period ended September 30, 2026. This increase was primarily as a result of borrowings of $956.3 million, offset by repayments of $459.2 million, the reclassification of $300.0 million of commercial paper to long-term debt that was refinanced through proceeds under our $650.0 million term loan credit agreement with Bank of America, as administrative agent, in October 2026, and the reclassification of $145.4 million of commercial paper to long-term debt that was refinanced through proceeds under our $200.0 million term loan credit agreement with CoBank, as administrative agent, in October 2026.
Accounts payable decreased $21.4 million during the nine-month period ended September 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 and a $49.1 million decrease in Georgia Power payables offset by a $42.0 million increase in trade payables, a $38.0 million refund liability recognized during 2026 and a $11.9 million increase in payables for natural gas purchases and related transportation.
Other current liabilities increased $77.3 million for the nine-month period ended September 30, 2026, primarily as a result of a $34.2 million increase in accrued liabilities principally for property additions for our new generation projects, reclassification of $28.4 million in long-term lease liabilities payable by our subsidiary to current and a $21.5 million increase in natural gas hedges payables to third parties, offset by an $8.0 million decrease in accrued property taxes.
Asset retirement obligations increased $26.4 million for the nine-month period ended September 30, 2026, primarily due to $44.2 million in accretion expense and a $9.7 million increase in cash flows estimates for nuclear asset retirement obligations, offset by $27.5 million in settlements of asset retirement obligations. See Note N of Notes to Unaudited Consolidated Financial Statements for a discussion of our asset retirement obligations.
Regulatory liabilities increased $39.1 million for the nine-month period ended September 30, 2026 primarily due to a $60.4 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 $40.2 million increase in the liability for collections of future major maintenance outage costs. Offsetting these increases, was a $48.0 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 September 30, 2026, we had incurred costs of approximately $893.9 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 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 September 30, 2026, we had incurred costs of approximately $85.0 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.
Battery Storage Resources
We and our members have approved the development and construction of three 25-megawatt, utility-scale battery storage resources. We estimate that the total cost of these battery storage resources will be approximately $240 million, before the application of any grant proceeds. The commercial operation dates for these resources are currently expected to be in 2029 and 2030. Oglethorpe and Georgia Transmission Corporation, through the Georgia Environmental Finance Authority, were awarded a grant under the Department of Energy's Grid Resilience and Innovation Partnerships (GRIP) Program. Oglethorpe intends to use its portion of the grant proceeds, approximately $81 million, to support the development of these battery storage resources. We are currently working through the GRIP Program funding process and receipt of any grant proceeds remains subject to meeting program requirements. If these grant funds become unavailable for this project, we and our members will reassess whether or not to continue with this project.
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 130 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 $400 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
In September 2026, we and our members approved participation in the extended power uprate project at Plant Hatch Units No. 1 and No. 2. The project includes planned equipment replacements and modifications to increase generating capacity. In connection with these activities, we revised our estimates of certain retirement costs associated with existing plant equipment. See Note N of Notes to Unaudited Consolidated Financial Statements for additional information regarding the associated asset retirement obligation adjustment.
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 September 2026, EPA issued a final, partial repeal of greenhouse gas (GHG) standards for power plants. The final rule repeals the carbon capture and storage/sequestration (CCS)-based standards for fossil fuel-fired power plants, including existing coal and new baseload natural gas units (i.e., units operating above a 40% capacity factor). Once the final rule is effective on November 16, 2026, existing coal units will no longer be 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) install 90% CCS by January 1, 2032, to operate beyond January 1, 2039. Additionally, new baseload gas units will no longer be required by January 1, 2032, to either install 90% CCS or limit operations to a 40% capacity factor. The final rule is being challenged in the U.S. Court of Appeals for the D.C. Circuit. On the same day as the final, partial repeal rule, EPA issued a supplemental proposed rule to rescind the basis for regulating GHG emissions from the power sector under Section 111 of the Clean Air Act. If finalized, the rule would repeal all remaining GHG emissions standards for fossil fuel-fired electric generating units, including the efficiency-based standards for new intermediate and baseload gas turbines.
We continue to monitor EPA's actions related to GHG emissions; however, the ultimate impact is unknown at this time and subject to the outcome of ongoing and future litigation and any future EPA and Georgia regulatory actions.
Liquidity
On October 2, 2026, we amended our syndicated line of credit facility among eleven lenders, including National Rural Utilities Cooperative Finance Corporation (CFC), as administrative agent, to increase the aggregate commitment to $1.35 billion from
$1.275 billion. The amendment extended the maturity date of $1.15 billion of commitments under the facility to October 2, 2031. The remaining $200 million of commitments mature on May 23, 2029.
Also on October 2, 2026, we amended our JPMorgan Chase Bank, N.A., line of credit to reduce the commitment to $150 million from $200 million and extend its maturity date to October 2, 2030. In addition, in October 2026, we entered into two term loan credit facilities with aggregate commitments of $850 million and maturities in October 2028 and borrowed $500 million under these credit facilities. One of these facilities is a $650 million two-year term loan credit facility with Bank of America, as administrative agent, and has an available draw period that extends through October 2027. The other is a $200 million two-year term loan credit facility with CoBank, as administrative agent. Following the amendments to our existing credit facilities and the addition of two new credit facilities, we have $2.6 billion of committed credit arrangements, representing an increase of $875 million, or approximately 50%, from $1.725 billion at the end of second quarter 2026.
At September 30, 2026, we had $977 million of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $255 million in cash and cash equivalents and $722 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 September 30, 2026
|
Expiration Date |
|||||||||||||||||||||
| (dollars in millions) | |||||||||||||||||||||||
| Unsecured Facilities: | |||||||||||||||||||||||
|
Syndicated Line among 11 banks led by CFC'(1)
|
$ | 1,275 | $ | 315 | May 2029 | ||||||||||||||||||
|
CFC Line of Credit(2)
|
110 | 110 | December 2028 | ||||||||||||||||||||
|
JPMorgan Chase Line of Credit(3)
|
200 | 198 | March 2027 | ||||||||||||||||||||
| Secured Facilities: | |||||||||||||||||||||||
|
CFC Term Loan(2)
|
250 | 99 | 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, 2026. In October 2026, this facility was increased to $1.35 billion with an expiration date of May 2029 for $200 million and October 2031 for $1.15 billion.
(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. Additionally, $41 million has been drawn under this facility and cannot be redrawn once repaid. Therefore, we reflect $99 million as the amount available under the term loan facility. Amounts borrowed under the $250 million term loan are secured under our first mortgage indenture, with a maturity no later than December 31, 2043.
(3)At September 30, 2026, $2.5 million of this facility was used for letters of credit issued to provide performance assurance to third parties. In October 2026, the authorized amount under this facility was decreased to $150 million and the expiration date was extended to October 2030.
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 September 30, 2026, our $1.0 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, and
•costs related to capital expenditures for existing generating facilities.
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. The Rural Utilities Service has conditionally committed a $3.3 billion loan to finance the Smarr Combined Cycle project that is subject to satisfaction of the conditions to closing and borrowing. See "- Financing Activities - Rural Utilities Service-Guaranteed Loans" for more information about our Rural Utilities Service loans and applications. 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 and, pending this long-term financing, expect to use commercial paper to provide interim funding for that purpose.
In October 2026, we used $445 million of the $500 million in proceeds under our two-year term loan credit facilities to repay commercial paper that had provided interim financing for a portion of the costs of the Smarr Combined Cycle and Talbot Unit No. 7 projects and capital expenditures on existing generating facilities. We intend to use the remaining $55 million of proceeds borrowed under these facilities for capital expenditures on existing generating facilities. We also intend to use the remaining $350 million available to be borrowed under one of the facilities for a portion of the costs of the Smarr Combined Cycle and Talbot Unit No. 7 projects. The term loan credit facilities provide interim financing for these costs until long-term financing is arranged.
Our unsecured committed lines of credit permit the issuance of up to $810 million in letters of credit on our behalf, of which $623 million remained available at September 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 additional intermediate or long-term financing is obtained.
Our credit facilities contain financial covenants that require us to maintain minimum levels of patronage capital. At September 30, 2026, the highest required minimum level was $900 million and our actual patronage capital balance was $1.4 billion. Following the amendments to our existing credit facilities and the two additional facilities, our minimum required patronage capital covenant increased to $1.025 billion. Our credit agreements also contain a covenant that limits our unsecured indebtedness, as defined in the credit agreements, to $4 billion. At September 30, 2026, we had $1.0 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 September 30, 2026, we had four members participating in the program and a balance of $42.3 million remaining to be applied against future power bills.
Financing Activities
First Mortgage Indenture. At September 30, 2026, 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 2025 Form 10-K for further discussion of our first mortgage indenture.
Rural Utilities Service-Guaranteed Loans. A summary of our Rural Utilities Service-Guaranteed Loans as of September 30, 2026 is provided in the table below:
| Rural Utilities Service-Guaranteed Loans | |||||||||||||||||||||||
|
Amount Approved / Pending Approval |
Amount Advanced September 30, 2026
|
Approved/Pending Amount Remaining September 30, 2026
|
|||||||||||||||||||||
| (dollars in millions) | |||||||||||||||||||||||
| Active Loans: | |||||||||||||||||||||||
|
General and Environmental Improvements1, 2
|
$ | 630.3 | $ | 543.2 | $ | 87.1 | |||||||||||||||||
|
General and Environmental Improvements3, 4
|
755.2 | 467.6 | 287.6 | ||||||||||||||||||||
| 1,385.5 | 1,010.8 | 374.7 | |||||||||||||||||||||
| Committed Loans: | |||||||||||||||||||||||
|
General and Environmental Improvements5
|
112.6 | - | 112.6 | ||||||||||||||||||||
|
General and Environmental Improvements6
|
486.7 | - | 486.7 | ||||||||||||||||||||
|
Smarr Combined Cycle Project7,8
|
3,324.3 | - | 3,324.3 | ||||||||||||||||||||
| 3,923.6 | - | 3,923.6 | |||||||||||||||||||||
| Pending Loans: | |||||||||||||||||||||||
|
Talbot Unit No. 7 Combustion Turbine Project9
|
415.0 | - | 415.0 | ||||||||||||||||||||
| 415.0 | - | 415.0 | |||||||||||||||||||||
| Completed Loans in 2026: | |||||||||||||||||||||||
| Walton Acquisition | 80.1 | 80.1 | - | ||||||||||||||||||||
|
New ERA Wansley Debt Refinancing10
|
331.5 | 302.2 | - | ||||||||||||||||||||
| 411.6 | 382.3 | - | |||||||||||||||||||||
| Total Active, Committed, Pending & Completed Loans | $ | 6,135.7 | $ | 1,393.1 | $ | 4,713.3 | |||||||||||||||||
(1) We are able to advance under this loan through September 30, 2028.
(2) We advanced an additional $6.6 million available under this loan in October 2026.
(3) We are able to advance under this loan through May 30, 2028.
(4) We advanced an additional $18.4 million available under this loan in October 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 by 2027.
(6) This loan was conditionally approved by the Rural Utilities Service in July 2026 and we expect to close and advance on this loan by 2027.
(7) This loan was conditionally approved by the Rural Utilities Service in August 2026 and we expect to close and advance on this loan by 2028.
(8) 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.
(9) Loan application in the amount of $415.0 million was submitted to the Rural Utilities Service in February 2026. In November 2026, we applied for an additional $35.9 million based on an updated project budget for the Talbot Unit No. 7 project.
(10) The New ERA loan is a direct loan from the Rural Utilities Service. Although the Rural Utilities Service approved $331.5 million, we are only eligible to advance the associated Wansley deferral amount of $302.2 million, a difference of $29.3 million.
As of September 30, 2026, we had $3.0 billion of debt outstanding under various Rural Utilities Service-guaranteed loans. 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 used 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.
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 November 12, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on November 12, 2026 at 20:42 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]