Annual Report for Fiscal Year Ending December 31, 2025 (Form 10-K)

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

Caution Regarding Forward-looking Statements

Management's Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements regarding matters that could have an impact on our business, financial condition, and future operations. These statements, based on our expectations and estimates, are not guarantees of future performance and are subject to risks, uncertainties, and other factors. These risks, uncertainties, and other factors include, but are not limited to: general business conditions; demand for energy; change in load requirements; federal and state legislative and regulatory actions, and legal and administrative proceedings; changes in and compliance with environmental laws and regulations; general credit and capital market conditions; weather conditions; the cost and availability of commodities used in our industry; disruption due to cybersecurity threats or incidents; and unanticipated changes in operating expenses and capital expenditures. Our actual results may vary materially from those discussed in the forward-looking statements as a result of these and other factors. Any forward-looking statement speaks only as of the date on which the statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which the statement is made even if new information becomes available or other events occur in the future.

Overview

We are a not-for-profit power supply cooperative owned entirely by our eleven Class A member distribution cooperatives and a Class B member, TEC. We supply our member distribution cooperatives' energy and demand requirements through a portfolio of resources including generating facilities, long-term and short-term physically-delivered forward power purchase contracts, and spot market energy purchases. We also supply the transmission services necessary to deliver this power to our member distribution cooperatives.

Our results from operations for the year ended December 31, 2025, as compared to 2024, were primarily impacted by the increase in total revenues from sales to our member distribution cooperatives, increases in purchased power expense, fuel expense, and transmission expense, the decrease in deferred energy expense, and an additional equity contribution.

Basis of Presentation

The accompanying financial statements reflect the consolidated accounts of ODEC and TEC. See "Note 1-Summary of Significant Accounting Policies-General" in Item 8.

Critical Accounting Policies and Estimates

The preparation of our financial statements in conformity with generally accepted accounting principles requires that our management make estimates and assumptions that affect the amounts reported in our financial statements. We base these estimates and assumptions on information available as of the date of the financial statements. We consider the following accounting policies to be critical accounting policies due to the estimation involved in each.

Accounting for Regulated Operations

We are a rate-regulated entity and, as a result, are subject to the accounting requirements of Accounting for Regulated Operations. In accordance with Accounting for Regulated Operations, certain of our revenues and expenses can be deferred at the discretion of our board of directors, which has budgetary and rate setting authority, if it is probable that these amounts will be collected or returned through our formula rate in future periods. Regulatory assets represent costs that we expect to collect from our member distribution cooperatives based on rates approved by our board of directors in accordance with our formula rate. Regulatory liabilities represent probable future reductions in our revenues associated with amounts that we expect to return to our member distribution cooperatives based on rates approved by our board of directors in accordance with our formula rate. See "Factors Affecting Results-Formula Rate" below. Regulatory assets are generally included in deferred charges and other assets, and regulatory liabilities are generally included in deferred credits and other liabilities. Deferred energy, which can be either a regulatory asset or regulatory liability, is included in current assets or current liabilities, respectively. We recognize regulatory assets and liabilities as expenses or as a reduction in expenses, respectively, concurrent with their collection or return through rates.

Deferred Energy

In accordance with Accounting for Regulated Operations, we use the deferral method of accounting to recognize differences between our energy revenues collected from our member distribution cooperatives and our energy expenses. Deferred energy on our Consolidated Statements of Revenues, Expenses, and Patronage Capital represents the difference between energy revenues, which are based upon energy rates approved by our board of directors, and energy expenses, which are based upon actual energy costs incurred. The deferred energy balance on our Consolidated Balance Sheet represents the net accumulation of any under- or over-collection of

energy costs. Under-collected energy costs appear as an asset and will be collected from our member distribution cooperatives in subsequent periods through our formula rate. Conversely, over-collected energy costs appear as a liability and will be returned to our member distribution cooperatives in subsequent periods through our formula rate.

In January and February of 2026, the PJM region experienced extremely cold weather, which increased our member distribution cooperatives' customers' requirements for power as well as increased our purchased power and fuel expenses. As a result, our deferred energy balance changed from an over-collection of energy costs to an under-collection of energy costs. We currently anticipate that our deferred energy balance as of February 28, 2026, will be an under-collection of energy costs of approximately $100 million. To address the under-collection of energy costs, our board of directors approved an increase of 24.1% to our total energy rate, effective May 1, 2026.

Margin Stabilization

Margin Stabilization allows us to review our actual demand-related costs of service and demand revenues and adjust revenues from our member distribution cooperatives to meet our financial coverage requirements and accumulate additional equity as approved by our board of directors. Our formula rate allows us to collect and return amounts utilizing Margin Stabilization. We record all adjustments, whether increases or decreases, in the year affected and allocate any adjustments to our member distribution cooperatives based on power sales during that year. We collect these increases from our member distribution cooperatives, or offset decreases against amounts owed by our member distribution cooperatives to us, generally in the succeeding calendar year. We adjust operating revenues and accounts receivable-members or accounts payable-members, as appropriate, to reflect these adjustments. These adjustments are treated as due, owed, incurred, and accrued for the year to which the adjustment relates. See "Factors Affecting Results-Formula Rate" below. The following table details the reduction in revenues utilizing Margin Stabilization for the past three years:

Accounting for Asset Retirement and Environmental Obligations

Accounting for Asset Retirement and Environmental Obligations requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value when incurred and capitalized as part of the related long-lived asset. In the absence of quoted market prices, we estimate the fair value of our asset retirement obligations using present value techniques, in which estimates of future cash flows associated with retirement activities are discounted using a credit-adjusted risk-free rate. Asset retirement obligations currently reported on our Consolidated Balance Sheet were measured during a period of historically low interest rates. The impact on measurements of new asset retirement obligations using different rates in the future may be significant. Our estimated liability could change significantly if actual costs vary from assumptions or if governmental regulations change significantly.

A significant portion of our asset retirement obligations relates to our share of the future costs to decommission North Anna. As of December 31, 2025 and 2024, our share of North Anna's nuclear decommissioning asset retirement obligation totaled $188.9 million, or 87.1%, of our total asset retirement obligations, and $183.2 million, or 87.3%, of our total asset retirement obligations, respectively. Periodically, a new decommissioning study for North Anna is performed by third-party experts. The third-party experts provide us with periodic site-specific "base year" cost studies in order to estimate the nature, cost, and timing of planned decommissioning activities for North Anna. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods are by nature highly uncertain and may vary significantly from actual results. In addition, these estimates are dependent on subjective factors, including the selection of cost escalation rates, which we consider to be a critical assumption. Our current estimate is based on a study that was performed in 2024 and adopted effective December 31, 2024. See "Note 3-Accounting for Asset Retirement and Environmental Obligations" in Item 8.

We determine cost escalation rates, which represent projected cost increases over time, due to both general inflation and increases in the cost of specific decommissioning activities. The following table details the weighted average cost escalation rates used by the study:

The weighted average cost escalation rate was applied if the cash flows increased as compared to the previous study. The original weighted average cost escalation rate was applied if the cash flows decreased as compared to the previous study. The use of alternative rates would have been material to the liabilities recognized. For example, had we increased the cost escalation rates by 0.5%, the amount recognized as of December 31, 2025, for our asset retirement obligations related to nuclear decommissioning would have been $47.5 million higher.

Accounting for Derivatives and Hedging

We primarily purchase power under both long-term and short-term physically-delivered forward contracts to supply power to our member distribution cooperatives. These forward purchase contracts meet the accounting definition of a derivative; however, a majority of these forward purchase derivative contracts qualify for the normal purchases/normal sales accounting exception under Accounting for Derivatives and Hedging. As a result, these contracts are not recorded at fair value. We record a liability and purchased power expense when the power under the physically-delivered forward contract is delivered. We also purchase natural gas futures generally for five years or less to hedge the price of natural gas for our facilities which utilize natural gas. These derivatives do not qualify for the normal purchases/normal sales accounting exception.

For all derivative contracts that do not qualify for the normal purchases/normal sales accounting exception, we defer all unrealized gains and losses on a net basis as a regulatory liability or regulatory asset, respectively, in accordance with Accounting for Regulated Operations. See "Accounting for Regulated Operations" above. These amounts are subsequently reclassified as purchased power or fuel expense on our Consolidated Statements of Revenues, Expenses, and Patronage Capital as the power or fuel is delivered and/or the contract settles.

Generally, derivatives are reported at fair value on our Consolidated Balance Sheet in other assets and other liabilities. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, we seek indicative price information from external sources, including broker quotes and industry publications. For individual contracts, the use of differing assumptions could have a material effect on the contract's estimated fair value.

Factors Affecting Results

Margins

We operate on a not-for-profit basis and, accordingly, seek to generate revenues sufficient to recover our cost of service and produce margins sufficient to establish reasonable reserves, meet financial coverage requirements, and accumulate additional equity approved by our board of directors. Revenues in excess of expenses in any year are designated as net margin attributable to ODEC on our Consolidated Statements of Revenues, Expenses, and Patronage Capital. We designate retained net margins attributable to ODEC on our Consolidated Balance Sheet as patronage capital, which we assign to each of our members on the basis of its class of membership and business with us.

Formula Rate

Our power sales are comprised of two power products - energy and demand. Energy is the physical electricity delivered through transmission and distribution facilities to customers. We must have sufficient committed energy available to us for delivery to our member distribution cooperatives to meet their maximum energy needs at any time, with limited exceptions. This committed available energy at any time is referred to as demand.

The rates we charge our member distribution cooperatives are regulated by FERC and FERC has granted us authority to charge our member distribution cooperatives utilizing both a formula rate and market-based rates. In accordance with our wholesale power contracts with our member distribution cooperatives, we sell power to them utilizing a formula rate. An exception in the formula rate allows our member distribution cooperatives to elect to utilize market-based rates for new and expanding loads that meet certain criteria.

The rates we charge our member distribution cooperatives under the formula rate are intended to permit collection of revenues which will equal the sum of:

The formula rate identifies the cost components that we can collect through rates, but not the actual amounts to be collected. With limited minor exceptions, we can change our rates periodically to match the costs we have incurred and we expect to incur without seeking FERC approval.

Energy costs, which are primarily variable costs, such as natural gas, nuclear, and coal fuel costs, and the energy costs under our power purchase contracts with third parties, are recovered through two separate rates, the base energy rate and the energy adjustment rate (collectively referred to as the total energy rate). The base energy rate is developed annually to collect energy costs as estimated in our budget including amounts in the deferred energy account from the prior year. As of January 1 of each year, the base energy rate is reset in accordance with our budget and the energy adjustment rate is reset to zero. We can revise the energy adjustment rate during the year if it becomes apparent that the total energy rate is over-collecting or under-collecting our actual and anticipated energy costs. Any revision to the energy adjustment rate requires board approval and that the resulting change to the total energy rate is at least 2%.

Demand costs, which are primarily fixed costs, such as capacity costs under power purchase contracts with third parties, transmission costs, administrative and general expenses, depreciation expense, interest expense, margin requirement, and additional equity contributions approved by our board of directors, are recovered through our demand rates. The formula rate allows us to change the actual demand rates we charge as our demand-related costs change, without FERC approval, with the exception of decommissioning cost, which is a fixed number in the formula rate that requires FERC approval prior to any adjustment. FERC approval is also needed to change account classifications currently in the formula or to add accounts not otherwise included in the current formula. Additionally, depreciation studies are required to be filed with FERC for its approval if they would result in a change in our depreciation rates. We collect our total demand costs through the following three separate rates:

As stated above, our margin requirement and additional equity contributions approved by our board of directors are recovered through our demand rates. We establish our demand rates to produce a net margin attributable to ODEC equal to 20% of our budgeted total interest charges, plus additional equity contributions approved by our board of directors. The formula rate permits us to adjust revenues from the member distribution

cooperatives to equal our actual total demand costs incurred, including a net margin attributable to ODEC equal to 20% of actual interest charges, plus additional equity contributions approved by our board of directors. We make these adjustments utilizing Margin Stabilization. See "Critical Accounting Policies and Estimates-Margin Stabilization" above.

We may revise our budget at any time to the extent that our current budget does not accurately reflect our costs and expenses or estimates of our sales of power. Increases or decreases in our budget automatically amend the energy and/or the demand components of our formula rate, as necessary. If at any time our board of directors determines that the formula does not recover all of our costs and expenses or determines a change in cost allocation methodology among our member distribution cooperatives is appropriate, it may adopt a new formula to meet those costs and expenses, subject to any necessary regulatory review and approval.

Indenture

In addition to the requirements of our formula rate, our Indenture obligates us to establish and collect rates for service to our member distribution cooperatives, which are reasonably expected to yield a margins for interest ratio for each fiscal year equal to at least 1.10, subject to any necessary regulatory or judicial approvals. The Indenture requires that these amounts, together with other moneys available to us, provide us moneys sufficient to remain in compliance with our obligations under the Indenture. We calculate the margins for interest ratio by dividing our margins for interest by our interest charges.

Margins for interest under the Indenture equal:

In calculating margins for interest under the Indenture, we factor in any item of net margin, loss, income, gain, earnings or profits of any of our affiliates or subsidiaries, only if we have received those amounts as a dividend or other distribution from the affiliate or subsidiary, or if we have made a contribution to, or payment under a guarantee or like agreement for an obligation of, the affiliate or subsidiary. Any amounts that we are required to refund in subsequent years do not reduce margins for interest as calculated under the Indenture for the year the refund is paid. The margins for interest ratio was 2.20, 1.27, and 1.27, for the years ended December 31, 2025, 2024, and 2023, respectively.

Interest charges under the Indenture equal our total interest charges (other than capitalized interest) related to (1) all obligations under the Indenture, (2) indebtedness secured by a lien equal or prior to the lien of the Indenture, and (3) obligations secured by liens created or assumed in connection with a tax-exempt financing for the acquisition or construction of property used by us, in each case including amortization of debt discount and expense or premium.

Recognition of Revenue

Our operating revenues reflect the actual demand-related costs we incurred plus the energy costs that we collected. Estimated demand-related costs are collected during the period through the demand components of our formula rate. In accordance with Margin Stabilization, these costs, as well as operating revenues, are adjusted at the end of each reporting period to reflect actual demand-related costs incurred during that period. See "Critical Accounting Policies and Estimates-Margin Stabilization" above. Estimated energy costs are collected during the period through the energy components of our formula rate. Operating revenues are not adjusted at the end of each reporting period to reflect actual energy costs incurred during that period. The difference between actual energy costs incurred and energy costs collected during each period is recorded as deferred energy expense, which may be a positive or negative number. See "Critical Accounting Policies and Estimates-Deferred Energy" above.

We bill energy to each of our member and non-member customers based on the total MWh delivered to them each month. We bill demand costs through three separate rates: a transmission service rate, an RTO capacity service rate, and a remaining owned capacity service rate. See "Formula Rate" above. The transmission service rate is billed to each of our member distribution cooperatives based on its contribution to the single zonal coincident peak (the hour of the month the need for energy is highest) for the prior year within each of the PJM transmission zones. The RTO capacity service rate is billed to each of our member distribution cooperatives based on its contribution to the average of the five hourly PJM coincident peaks in the prior year, subject to add-backs for participation in PJM demand response programs. The remaining owned capacity service rate is billed based on the average hourly demand in the prior 12-month period from September 1 to August 31.

Member Distribution Cooperatives' Requirements for Power

Changes in the number of customers and those customers' requirements for power significantly affect our member distribution cooperatives' requirements for power. Factors affecting our member distribution cooperatives' requirements for power include:

The heating and cooling degree days for the past three years were as follows:

For additional discussion of our member distribution cooperatives' customers, see "Members-Member Distribution Cooperatives-Service Territories and Customers" in Item 1.

Power Supply Resources

In an attempt to provide stable power costs to our member distribution cooperatives, we utilize a combination of our owned generating resources and purchases from the market. We also regularly evaluate options for future power sources, including additional owned generation and power purchase contracts.

Market forces influence the structure and price of new power supply contracts into which we enter. When we enter into long-term power purchase contracts or agree to purchase energy at a date in the future, we rely on models based on our judgment and assumptions of factors such as future demand for power and market prices of energy and the price of commodities, such as natural gas, used to generate electricity. Our actual results may vary from what our models predict, which may in turn impact our resulting costs to our members. Additionally, our models become less reliable the further into the future that the estimates are made. See "Risk Factors" in Item 1A.

In 2025, our generating facilities satisfied approximately 81.0% of our PJM capacity obligation and 44.7% of our energy requirements. We obtained the remainder of our PJM capacity obligation through the PJM RPM capacity auction process and purchased capacity contracts. Although we expect that capacity costs in PJM will increase, we expect that the corresponding generation capacity credits we receive from PJM will also increase. The energy requirements not met by our owned generating facilities were obtained from multiple suppliers under various long-term and short-term physically-delivered forward power purchase contracts and spot market purchases. See "Power Supply Resources" in Item 1 and "Properties" in Item 2.

PJM

PJM is an RTO that serves all of Delaware and Maryland, and most of Virginia, as well as other areas outside our member distribution cooperatives' service territories. We are a member of PJM and are therefore subject to the operations of PJM. PJM coordinates and establishes policies for the generation, purchase, and sale of capacity and energy in the control areas of its members, including all of the service territories of our member distribution cooperatives. As a result, our generating facilities are under dispatch direction of PJM.

PJM balances its members' power requirements with the power resources available to supply those requirements. Based on this evaluation of supply and demand, PJM schedules and directs the dispatch of available generating facilities throughout its region in a manner intended to meet the demand for energy in the most reliable and cost-effective manner. Thus, PJM directs the dispatch of these facilities even though it does not own them. When the most economical generating facility cannot be dispatched due to transmission constraints, PJM will direct the dispatch of more expensive generating facilities to meet power requirements. For these reasons, actions by PJM may materially affect our operating results. PJM compensates us for the capacity of our generating facilities made available without regard to whether our generating facilities are dispatched. See "Power Supply Resources-PJM" in Item 1.

We transmit power to our member distribution cooperatives through the transmission facilities subject to PJM operational control, including a limited amount of transmission facilities we own. We have agreements with PJM which provide us with access to transmission facilities under PJM's control as necessary to deliver energy to our member distribution cooperatives. See "Transmission" in Item 2.

Transmission owners within PJM have made significant investments in their transmission systems. Because transmission rates are established to recover the cost of investment plus a return on the investment, PJM's rates for network transmission services have increased significantly in recent years. Our transmission costs are impacted each year by billing determinants, which are based on our usage during either the peak hour

of the year or the peak hour of each month, depending upon the transmission zone. See "Results of Operations-Operating Expenses" below.

Generating Facilities

Our operating expenses, and consequently our rates to our member distribution cooperatives, are significantly affected by the operations of our generating facilities, which are under dispatch direction of PJM. See "PJM" above.

Operational Availability

The operational availability of our owned generating resources for the past three years was as follows:

The operational availability is impacted by planned maintenance outages as well as unplanned outages.

Capacity Factor

The output of Wildcat Point, North Anna, and Clover for the past three years as a percentage of maximum dependable capacity rating of each facility, was as follows:

Each unit at North Anna is scheduled for refueling approximately every 18 months. While only one unit is refueled at a time, this refueling schedule typically results in both units being off-line for refueling during the same calendar year once every three years. During 2025, both units at North Anna were off-line for refueling. During 2024 and 2023, one unit at North Anna was off-line for refueling.

There has been an increase in the capacity factor for Clover due to Virginia's withdrawal from RGGI at the end of 2023. See "Regulation-Environmental-Regional Greenhouse Gas Initiative ("RGGI")" in Item 1. Clover continues to be a reliable component of our power supply resources portfolio.

Changing Environmental Legislation and Regulation

We are subject to extensive federal and state regulation regarding environmental matters. This regulation is becoming increasingly stringent through amendments to federal and state statutes and the development of regulations authorized by existing law. Future federal and state legislation and regulations present the potential for even greater obligations to limit the impact on the environment from the operation of our generating and transmission facilities. The impact of these developments can have a material adverse effect on our results of operations, financial condition, or cash flows, depending on the final terms of new regulations and how those rules are implemented. See "Regulation-Environmental" in Item 1 and "Risk Factors" in Item 1A.

Taxable Status

We are a not-for-profit wholesale power supply cooperative and currently are exempt from federal income taxation under IRC Section 501(c)(12). In order to maintain our tax-exempt status, we must receive at least 85%

of our income from our members on an annual basis. We maintained our tax-exempt status as of December 31, 2025.

Zero-emission Nuclear Power Production Tax Credit

The Inflation Reduction Act of 2022 provides for the zero-emission nuclear power production tax credit for electricity produced at a qualified nuclear power facility, including North Anna, and sold to an unrelated third party beginning in 2024. In November 2025, we filed a claim for $24.3 million in zero-emission nuclear power production tax credit and elected direct pay reimbursement for tax year 2024 based on existing guidance. Additionally, we recorded $19.2 million in zero-emission nuclear power production tax credit for tax year 2025 for which we expect to seek direct pay reimbursement to be reflected on our 2025 tax return. We have established a receivable as well as a regulatory liability for $43.5 million. The ultimate zero-emission nuclear power production tax credit realized by us may vary significantly based on future IRS guidance.

Results of Operations

Operating Revenues

Our operating revenues are derived from sales of power and renewable energy credits to our member distribution cooperatives and non-members. ODEC sells excess purchased and generated energy not needed to meet the actual needs of our member distribution cooperatives to PJM, TEC, or other counterparties. Our financial statements represent the consolidated financial statements of ODEC and TEC and through the consolidation process, all intercompany balances and transactions have been eliminated and TEC's sales are reflected as non-member revenues. Our operating revenues and energy sales in MWh by type of purchaser for the past three years were as follows:

Member Distribution Cooperatives

The rates we charge our member distribution cooperatives are regulated by FERC and FERC has granted us authority to charge our member distribution cooperatives utilizing both a formula rate and market-based rates. In accordance with our wholesale power contracts with our member distribution cooperatives, we sell

power to them utilizing a formula rate. An exception in the formula rate allows our member distribution cooperatives to elect to utilize market-based rates for new and expanding loads that meet certain criteria.

Formula Rate

Our operating revenues from sales to member distribution cooperatives - formula rate for the past three years were as follows:

In 2025, total formula rate revenues increased $92.0 million, or 9.0%, as compared to 2024.

The following table summarizes the changes to our total energy rate since 2023, which were implemented to address the differences in our realized as well as projected energy costs. See "Factors Affecting Results-Formula Rate" above.

Market-based Rates

Our operating revenues from sales to member distribution cooperatives - market-based rates for the past three years were as follows:

In 2025, total revenues from sales to our member distribution cooperatives - market-based rates increased $104.3 million, or 210.8%, as compared to 2024, due to load growth related to increased member distribution cooperative sales to data centers.

Operating Expenses

The following is a summary of the components of our operating expenses for the past three years.

Our operating expenses are comprised of the costs that we incur to generate and purchase power to meet the needs of our member distribution cooperatives, and the costs associated with any sales of power to non-members. Our energy costs generally are variable and include fuel expense, the energy portion of our purchased power expense, and the variable portion of operations and maintenance expense. Our demand costs generally are fixed and include the capacity portion of our purchased power expense, transmission expense, the fixed portion of operations and maintenance expense, administrative and general expense, and depreciation and amortization expense. Additionally, all non-operating expenses and income items, including investment income, and interest charges, net, are components of our demand costs. See "Factors Affecting Results-Formula Rate" above.

In 2025, total operating expenses increased $166.8 million, or 15.6%, as compared to 2024, primarily as a result of increases in purchased power expense, fuel expense, and transmission expense, partially offset by the decrease in deferred energy expense and the amortization of regulatory asset/(liability), net.

Other Items

Investment (Expense)/Income, Net

In 2025, investment (expense)/income, net changed $26.1 million as compared to 2024, primarily due to a change in investments in the nuclear decommissioning trust during 2025, which resulted in a realized loss. As a rate-regulated entity, we account for certain revenues and expenses in accordance with Accounting for Regulated Operations, which allows certain of our revenues and expenses to be deferred. We deferred this realized loss through amortization of regulatory asset/(liability), net expense, resulting in no impact on net margin attributable to ODEC on the consolidated statements of revenues, expenses, and patronage capital. See "Critical Accounting Policies and Estimates-Accounting for Regulated Operations" above.

Interest Charges, Net

The primary factors affecting our interest charges, net are issuances of indebtedness, scheduled payments of principal on our indebtedness, interest charges related to our revolving credit facility (including fees), and interest paid to our member distribution cooperatives on prepayment balances, which is included in other interest. The major components of interest charges, net for the past three years were as follows:

Net Margin Attributable to ODEC

In 2025, net margin attributable to ODEC, which is a function of our total interest charges plus any additional equity contributions approved by our board of directors, increased $37.0 million as compared to 2024. Our board of directors approved an additional equity contribution of $38.5 million that was collected in 2025. Additional equity contributions are collected through rates charged to our member distribution cooperatives and are used to fund future capital expenditures. Our board of directors also approved an additional equity contribution of $27.5 million to be collected in 2026. See "Factors Affecting Results-Formula Rate" above.

Discussion of Results of Operations Comparing 2024 to 2023

For discussion of our financial results comparing 2024 to 2023, see "Results of Operations" in Item 7 of our 2024 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 18, 2025.

Financial Condition

The principal changes in our financial condition from December 31, 2024 to December 31, 2025, were caused by the increases in long-term debt, regulatory liabilities, nuclear decommissioning trust, accounts receivable, and accounts receivable-members, and decreases in revolving credit facility, accounts payable-members, and deferred energy.

Equity Ratio

Our equity ratio was 32.8% and 33.6%, as of December 31, 2025 and 2024, respectively. Equity ratio equals patronage capital divided by the sum of our long-term debt, borrowings outstanding under our revolving credit facility, long-term debt due within one year, and patronage capital.

Liquidity and Capital Resources

Sources

Cash generated by our operations, periodic borrowings under our revolving credit facility, and occasional issuances of long-term indebtedness provide our sources of liquidity and capital.

Operations

In 2025 and 2024, our operating activities provided cash flows of $85.3 million and $257.4 million, respectively. In 2023, our operating activities used cash flows of $16.3 million.

Revolving Credit Facility

We maintain a revolving credit facility to cover our short-term and medium-term funding needs that are not met by cash from operations or other available funds. The $400 million in aggregate commitments under the credit agreement mature on December 7, 2028, unless earlier terminated in accordance with the agreement. As of December 31, 2025, we did not have any borrowings outstanding under this facility. As of December 31, 2024, we had outstanding under this facility $65.0 million in borrowings at a blended interest rate of 5.61%. As of December 31, 2025 and 2024, we did not have any letters of credit outstanding under this facility.

The credit agreement contains customary conditions to borrowing or the issuance of a letter of credit, representations and warranties and covenants. The credit agreement obligates us to maintain a debt to capitalization ratio of no more than 0.85 to 1.00 and to maintain a margins for interest ratio of no less than 1.10 times interest charges (calculated in accordance with our Indenture as currently in effect). Obligations under the credit agreement may be accelerated following, among other things:

Financings

We fund the portion of our capital expenditures that we are not able to fund from operations through borrowings under our revolving credit facility and issuances of debt in the capital markets. These capital expenditures consist primarily of the costs related to the development, construction, acquisition, expansion, or improvement of our owned generating and transmission facilities. We continue to evaluate the issuance of additional long-term indebtedness to fund capital expenditures related to our existing generating and transmission facilities. Additionally, we are evaluating the need to construct new or expand existing generating facilities, which could result in the issuance of additional long-term indebtedness. We believe our cash from operations, funds available from our revolving credit facility, and issuances of additional long-term indebtedness, will be sufficient to meet our currently anticipated future operational and capital requirements.

On December 16, 2025, we issued $250 million of long-term debt in a private placement transaction. The issuance consisted of $250 million first mortgage bonds due 2052 under the Indenture and proceeds were used to pay amounts outstanding under our revolving credit facility and for other general corporate purposes.

Uses

Our uses of liquidity and capital relate to funding our working capital needs, investment activities, and financing activities. Substantially all of our investment activities relate to capital expenditures in connection with our generating facilities. Additionally, we have asset retirement obligations in the future that are significantly offset by the nuclear decommissioning trust, which as of December 31, 2025, had a balance of $340.6 million. Our future contingent obligations primarily relate to power purchase and natural gas contracts, and we have no off-balance sheet obligations. Some of our power purchase contracts obligate us to provide

credit support if our obligations issued under the Indenture are rated below specified thresholds by S&P and Moody's. We currently anticipate that cash from operations, borrowings under our revolving credit facility, and potential issuances of long-term indebtedness will be sufficient to meet our liquidity needs for the near term, including planned capital expenditures, asset retirement obligations, and our contingent obligations as described above.

Capital Expenditures

We regularly forecast our capital expenditures as part of our long-term business planning activities. We review these projections periodically in order to update our calculations to reflect changes in our future plans, projects currently under consideration, construction costs, market factors, and other items affecting our forecasts. Our actual capital expenditures could vary significantly from these projections. The table below summarizes our actual and projected capital expenditures on a cash flow basis, including capitalized interest, for 2023 through 2028:

Nearly all of our capital expenditures consist of additions to electric plant and equipment. Capital expenditures for North Anna include $41.8 million, $34.4 million, and $29.2 million, for 2026, 2027, and 2028, respectively, for costs related to license extension. Projected capital expenditures for transmission include costs related to transmission facility upgrades in accordance with PJM planning processes. Projected capital expenditures for combustion turbine facilities include costs related to uprate projects. Projected capital expenditures for Clover for 2026 include costs related to the project to rebuild the main generator for Unit 2. We intend to use our cash flow from operations, funds from our 2025 debt issuance, borrowings under our revolving credit facility, and, if needed, issuances of additional debt in the capital markets to fund all of our currently projected capital requirements through 2028.

Power Purchase and Natural Gas Agreements

Under the terms of most of our power purchase and natural gas agreements, we typically agree to provide collateral under certain circumstances and require comparable terms from our counterparties. The collateral we may be required to post with a counterparty, and vice versa, is normally a function of the collateral thresholds we negotiate with a counterparty relative to a range of credit ratings as well as the value of our transaction(s) under a contract with a respective counterparty. As of December 31, 2025, we were not required to post collateral with counterparties pursuant to the power purchase and natural gas agreements we have in place.

Typically, collateral thresholds under our contracts are zero once an entity is rated below investment grade by S&P or Moody's (i.e., "BBB-" or "Baa3," respectively). As of December 31, 2025, if our credit ratings had been below investment grade we estimate we would have been obligated to post between $25 million and $75 million of collateral with our counterparties. This calculation is based on power and natural gas prices on December 31, 2025, and delivered power and natural gas for which we had not yet paid. Depending on the difference between the price of power and natural gas under our agreements and the price of power and natural gas in the market at the time of the calculation, this amount could increase or decrease. S&P, Moody's, and Fitch currently rate our outstanding obligations issued under our Indenture at "A+," "A1," and "A+,"

respectively. Additionally, we have an issuer credit rating of "A+" from S&P, and an implied senior unsecured rating of "A+" from Fitch.

PJM requires that we provide collateral to support our obligations in connection with certain PJM transactions and as of December 31, 2025, we had posted collateral totaling $7.6 million. In accordance with its credit policy, PJM subjects each member of PJM to a credit evaluation. A material change in our financial condition, including the downgrading of our credit rating by any rating agency, could cause PJM to re-evaluate our creditworthiness and require that we provide additional collateral. As of December 31, 2025, if PJM had determined that we needed to provide additional collateral to support our obligations as a result of our creditworthiness, PJM could have asked us to provide up to approximately $26.5 million.