Old Dominion Electric Cooperative
11/10/2026 | Press release | Distributed by Public on 11/10/2026 13:15
Quarterly Report for Quarter Ending September 30, 2026 (Form 10-Q)
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.
Critical Accounting Policies
As of September 30, 2026, there have been no significant changes in our critical accounting policies as disclosed in our 2025 Annual Report on Form 10-K. These policies include the accounting for regulated operations, deferred energy, margin stabilization, accounting for asset retirement and environmental obligations, and accounting for derivatives and hedging.
Basis of Presentation
The accompanying financial statements reflect the consolidated accounts of ODEC and TEC. See "Note 1-General" in Notes to Condensed Consolidated Financial Statements in Part 1, Item 1.
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 purchases. We also supply the transmission services necessary to deliver this power to our member distribution cooperatives.
Our results from operations for the three and nine months ended September 30, 2026, as compared to the same periods in 2025, were primarily impacted by increases in total revenues from sales to our member distribution cooperatives and purchased power expense. Our results from operations for the nine months ended September 30, 2026, as compared to the same period in 2025, were also impacted by the increase in fuel expense. In January and February of 2026, the PJM region experienced periods of extreme cold weather, which increased our member distribution cooperatives' customers' requirements for power and our purchased power and fuel expenses. Additionally, during the third quarter of 2026, the PJM region experienced periods of unseasonably hot and humid weather, which increased our member distribution cooperatives' customers' requirements for power.
•
Total revenues from sales to our member distribution cooperatives, which is comprised of sales to our member distribution cooperatives - formula rate and sales to our member distribution cooperatives - market-based rates, increased 35.0% and 29.8%, for the three and nine months ended September 30, 2026, as compared to the same periods in 2025, respectively.
•
Total revenues from sales to our member distribution cooperatives - formula rate increased 20.2% and 13.2%, respectively, primarily due to the increase in formula rate energy revenues. Formula rate energy revenues increased 30.6% and 24.4%, respectively, due to changes in our total energy rate and the increase in energy sales in MWh.
•
Total revenues from sales to our member distribution cooperatives - market-based rates increased 143.6% and 167.2%, respectively, primarily due to load growth related to increased member distribution cooperative sales to data centers.
•
Purchased power expense, which includes the cost of purchased energy and capacity, increased 75.3% and 47.4%, for the three and nine months ended September 30, 2026, respectively, primarily as a result of the increase in the cost of purchased energy.
•
Purchased energy costs increased 77.3% and 51.8%, respectively, due to increases in the average cost and volume of purchased energy.
•
The average cost of purchased energy increased 13.6% and 22.3%, respectively.
•
The volume of purchased energy increased 56.1% and 24.1%, respectively.
•
Fuel expense increased 28.6% for the nine months ended September 30, 2026, due to the 38.7% increase in the average cost of fuel partially offset by the 7.3% decrease in generation from our owned facilities.
Factors Affecting Results
For a comprehensive discussion of factors affecting results, see "Management's Discussion and Analysis of Financial Condition and Results of Operations-Factors Affecting Results" in Item 7 in our 2025 Annual Report on Form 10-K.
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:
•
all of our costs and expenses;
•
20% of our total interest charges (margin requirement); and
•
additional equity contributions approved by our board of directors.
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.
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.
As detailed in the table below, we utilized Margin Stabilization to reduce revenues for the three and nine months ended September 30, 2026 and 2025.
|
Three Months |
Nine Months |
|||||||||||||||
|
2026 |
2025 |
2026 |
2025 |
|||||||||||||
|
(in thousands) |
||||||||||||||||
|
Margin Stabilization adjustment |
$ |
3,060 |
$ |
13,184 |
$ |
11,051 |
$ |
18,051 |
||||||||
For further discussion of Margin Stabilization, see "Management's Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies-Margin Stabilization" in Item 7 in our 2025 Annual Report on Form 10-K.
Weather
Weather affects the demand for electricity. Relatively higher or lower temperatures tend to increase the demand for energy to use air conditioning and heating systems, respectively. Mild weather generally reduces the demand for energy because heating and air conditioning systems are operated less. Weather also plays a role in the price of energy through its effects on the market price for fuel, particularly natural gas.
Heating and cooling degree days are measurement tools used to quantify the need to utilize heating or cooling, respectively, for a building. Heating degree days are calculated as the number of degrees below 60 degrees in a single day. Cooling degree days are calculated as the number of degrees above 65 degrees in a single day. In a single calendar day, it is possible to have multiple heating degree and cooling degree days.
The heating and cooling degree days for the three and nine months ended September 30, 2026 and 2025, were as follows:
|
Three Months |
Nine Months |
|||||||||||||||||||||||
|
2026 |
2025 |
Change |
2026 |
2025 |
Change |
|||||||||||||||||||
|
Heating degree days |
- |
- |
- |
% |
2,080 |
2,130 |
(2.3 |
)% |
||||||||||||||||
|
Cooling degree days |
1,102 |
872 |
26.4 |
1,402 |
1,252 |
12.0 |
||||||||||||||||||
Power Supply Resources
We provide power to our members through a combination of our interests in Wildcat Point, a natural gas-fired combined cycle generation facility; North Anna, a nuclear power station; Clover, a coal-fired generation facility; two natural gas-fired combustion turbine facilities (Louisa and Marsh Run); diesel-fired distributed generation facilities; and physically-delivered forward power purchase contracts and spot market energy purchases. Our energy supply resources for the three and nine months ended September 30, 2026 and 2025, were as follows:
|
Three Months |
Nine Months |
|||||||||||||||||
|
2026 |
2025 |
2026 |
2025 |
|||||||||||||||
|
(in MWh and percentages) |
||||||||||||||||||
|
Generated: |
||||||||||||||||||
|
Wildcat Point |
734,968 |
16.0 |
% |
1,057,171 |
26.0 |
% |
1,983,881 |
15.0 |
% |
2,467,055 |
20.5 |
% |
||||||
|
North Anna |
413,696 |
9.0 |
420,354 |
10.3 |
1,392,613 |
10.5 |
1,300,368 |
10.8 |
||||||||||
|
Clover |
176,406 |
3.8 |
251,646 |
6.2 |
547,775 |
4.2 |
553,031 |
4.6 |
||||||||||
|
Louisa |
219,134 |
4.8 |
253,067 |
6.2 |
575,837 |
4.4 |
517,373 |
4.3 |
||||||||||
|
Marsh Run |
199,192 |
4.3 |
255,358 |
6.3 |
561,043 |
4.3 |
620,277 |
5.2 |
||||||||||
|
Distributed Generation |
736 |
- |
840 |
- |
2,135 |
- |
2,789 |
- |
||||||||||
|
Total Generated |
1,744,132 |
37.9 |
2,238,436 |
55.0 |
5,063,284 |
38.4 |
5,460,893 |
45.4 |
||||||||||
|
Purchased: |
||||||||||||||||||
|
Other than renewable: |
||||||||||||||||||
|
Long-term and short-term |
1,438,275 |
31.3 |
1,049,960 |
25.8 |
4,069,837 |
30.8 |
3,446,180 |
28.7 |
||||||||||
|
Spot market (1) |
1,254,626 |
27.3 |
668,324 |
16.5 |
3,408,634 |
25.8 |
2,513,083 |
20.9 |
||||||||||
|
Total Other than renewable |
2,692,901 |
58.6 |
1,718,284 |
42.3 |
7,478,471 |
56.6 |
5,959,263 |
49.6 |
||||||||||
|
Renewable (2) |
160,901 |
3.5 |
110,167 |
2.7 |
659,915 |
5.0 |
599,928 |
5.0 |
||||||||||
|
Total Purchased |
2,853,802 |
62.1 |
1,828,451 |
45.0 |
8,138,386 |
61.6 |
6,559,191 |
54.6 |
||||||||||
|
Total Available Energy |
4,597,934 |
100.0 |
% |
4,066,887 |
100.0 |
% |
13,201,670 |
100.0 |
% |
12,020,084 |
100.0 |
% |
||||||
(1)
Includes purchases for formula rate and market-based rates sales.
(2)
Related to our contracts from renewable facilities from which we obtain renewable energy credits. We may sell these renewable energy credits to our member distribution cooperatives and non-members.
Generating Facilities
Our operating expenses, and consequently our rates charged to our member distribution cooperatives, are significantly affected by the operations of our generating facilities, which 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. For further discussion of PJM, see "Business-Power Supply Resources-PJM" in Item 1 in our 2025 Annual Report on Form 10-K.
Operational Availability
The operational availability of our owned generating resources for the three and nine months ended September 30, 2026 and 2025, was as follows:
|
Three Months |
Nine Months |
|||||||||||||||
|
2026 |
2025 |
2026 |
2025 |
|||||||||||||
|
Wildcat Point |
93.6 |
% |
99.1 |
% |
87.5 |
% |
89.9 |
% |
||||||||
|
North Anna |
86.4 |
86.9 |
95.4 |
89.3 |
||||||||||||
|
Clover |
66.4 |
82.8 |
62.4 |
63.4 |
||||||||||||
|
Louisa |
99.8 |
99.2 |
97.2 |
98.2 |
||||||||||||
|
Marsh Run |
99.9 |
100.0 |
91.1 |
92.4 |
||||||||||||
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 three and nine months ended September 30, 2026 and 2025, as a percentage of maximum dependable capacity rating of the respective facility, was as follows:
|
Three Months |
Nine Months |
|||||||||||||||
|
2026 |
2025 |
2026 |
2025 |
|||||||||||||
|
Wildcat Point |
33.8 |
% |
48.5 |
% |
30.8 |
% |
38.2 |
% |
||||||||
|
North Anna |
85.3 |
86.8 |
96.9 |
90.4 |
||||||||||||
|
Clover |
20.4 |
26.9 |
21.0 |
19.9 |
||||||||||||
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 three and nine months ended September 30, 2026 and 2025, were as follows:
|
Three Months |
Nine Months |
|||||||||||||||
|
2026 |
2025 |
2026 |
2025 |
|||||||||||||
|
(in thousands) |
||||||||||||||||
|
Operating revenues: |
||||||||||||||||
|
Member distribution cooperatives: |
||||||||||||||||
|
Formula rate |
$ |
335,326 |
$ |
278,878 |
$ |
933,961 |
$ |
824,811 |
||||||||
|
Market-based rates |
92,233 |
37,865 |
265,676 |
99,447 |
||||||||||||
|
Total Member distribution cooperatives |
427,559 |
316,743 |
1,199,637 |
924,258 |
||||||||||||
|
Non-members (1) |
32,020 |
30,919 |
58,247 |
47,939 |
||||||||||||
|
Total Operating revenues |
$ |
459,579 |
$ |
347,662 |
$ |
1,257,884 |
$ |
972,197 |
||||||||
|
Energy sales to: |
(in MWh) |
|||||||||||||||
|
Member distribution cooperatives - formula rate |
3,577,225 |
3,361,616 |
10,389,091 |
10,117,885 |
||||||||||||
|
Member distribution cooperatives - market-based rates |
867,804 |
545,381 |
2,354,143 |
1,398,680 |
||||||||||||
|
Non-members |
124,373 |
146,205 |
405,596 |
448,488 |
||||||||||||
|
Total Energy sales |
4,569,402 |
4,053,202 |
13,148,830 |
11,965,053 |
||||||||||||
(1)
Includes renewable energy credit sales of $17.8 million and $22.1 million for the three and nine months ended September 30, 2026, respectively, and $22.5 million and $24.2 million for the three and nine months ended September 30, 2025, respectively.
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 three and nine months ended September 30, 2026 and 2025, were as follows:
|
Three Months |
Nine Months |
|||||||||||||||
|
2026 |
2025 |
2026 |
2025 |
|||||||||||||
|
(in thousands) |
||||||||||||||||
|
Member distribution cooperatives: |
||||||||||||||||
|
Formula rate: |
||||||||||||||||
|
Energy revenues |
$ |
197,584 |
$ |
151,268 |
$ |
522,337 |
$ |
419,753 |
||||||||
|
Renewable energy credits |
81 |
122 |
541 |
431 |
||||||||||||
|
Demand revenues |
137,661 |
127,488 |
411,083 |
404,627 |
||||||||||||
|
Total Formula rate revenues |
$ |
335,326 |
$ |
278,878 |
$ |
933,961 |
$ |
824,811 |
||||||||
|
Energy sales to: |
(in MWh) |
|||||||||||||||
|
Member distribution cooperatives - formula rate |
3,577,225 |
3,361,616 |
10,389,091 |
10,117,885 |
||||||||||||
|
Average cost to member distribution cooperatives: |
(per MWh) |
|||||||||||||||
|
Formula rate energy cost |
$ |
55.23 |
$ |
45.00 |
$ |
50.28 |
$ |
41.49 |
||||||||
|
Formula rate total cost |
$ |
93.74 |
$ |
82.96 |
$ |
89.90 |
$ |
81.52 |
||||||||
For the three and nine months ended September 30, 2026, total formula rate revenues increased $56.4 million, or 20.2%, and $109.2 million, or 13.2%, as compared to the same periods in 2025, respectively, primarily due to the increase in formula rate energy revenues. Formula rate energy revenues increased $46.3 million, or 30.6%, and $102.6 million, or 24.4%, respectively, due to changes in our total energy rate and the increase in energy sales in MWh. In January and February of 2026, the PJM region experienced periods of extreme cold weather, which increased our member distribution cooperatives' customers' requirements for power. Additionally, during the third quarter of 2026, the PJM region experienced periods of unseasonably hot and humid weather, which increased our member distribution cooperatives' customers' requirements for power.
The following table summarizes the changes to our total energy rate since 2025 to address the differences in our realized as well as projected energy costs:
|
Date |
% Change |
|||
|
January 1, 2025 |
(6.4 |
) |
||
|
June 1, 2025 |
16.4 |
|||
|
January 1, 2026 |
(1.1 |
) |
||
|
May 1, 2026 |
24.1 |
|||
Market-based Rates
Our operating revenues from sales to member distribution cooperatives - market-based rates for the three and nine months ended September 30, 2026 and 2025, were as follows:
|
Three Months |
Nine Months |
|||||||||||||||
|
2026 |
2025 |
2026 |
2025 |
|||||||||||||
|
(in thousands) |
||||||||||||||||
|
Member distribution cooperatives: |
||||||||||||||||
|
Market-based rates: |
||||||||||||||||
|
Energy revenues |
$ |
78,483 |
$ |
29,119 |
$ |
226,049 |
$ |
82,025 |
||||||||
|
Demand revenues |
13,750 |
8,746 |
39,627 |
17,422 |
||||||||||||
|
Total Market-based rates revenues |
$ |
92,233 |
$ |
37,865 |
$ |
265,676 |
$ |
99,447 |
||||||||
|
Energy sales to: |
(in MWh) |
|||||||||||||||
|
Member distribution cooperatives - market-based rates |
867,804 |
545,381 |
2,354,143 |
1,398,680 |
||||||||||||
For the three and nine months ended September 30, 2026, total market-based rates revenues increased $54.4 million, or 143.6%, and $166.2 million, or 167.2%, as compared to the same periods in 2025, respectively, primarily due to load growth related to increased member distribution cooperatives sales to data centers.
Operating Expenses
The following is a summary of the components of our operating expenses for the three and nine months ended September 30, 2026 and 2025:
|
Three Months |
Nine Months |
|||||||||||||||
|
2026 |
2025 |
2026 |
2025 |
|||||||||||||
|
(in thousands) |
||||||||||||||||
|
Fuel |
$ |
60,548 |
$ |
70,561 |
$ |
267,078 |
$ |
207,671 |
||||||||
|
Purchased power |
215,333 |
122,851 |
581,094 |
394,317 |
||||||||||||
|
Transmission |
61,096 |
54,026 |
184,214 |
166,557 |
||||||||||||
|
Deferred energy |
27,331 |
19,389 |
(39,210 |
) |
(38,871 |
) |
||||||||||
|
Operations and maintenance |
37,842 |
25,530 |
91,297 |
77,171 |
||||||||||||
|
Administrative and general |
14,901 |
14,362 |
45,372 |
42,242 |
||||||||||||
|
Depreciation and amortization |
17,478 |
17,780 |
52,368 |
53,232 |
||||||||||||
|
Amortization of regulatory asset/(liability), net |
15,406 |
(13,063 |
) |
20,273 |
(12,337 |
) |
||||||||||
|
Accretion of asset retirement obligations |
1,793 |
1,730 |
5,378 |
5,188 |
||||||||||||
|
Taxes, other than income taxes |
2,299 |
2,099 |
6,862 |
6,674 |
||||||||||||
|
Total operating expenses |
$ |
454,027 |
$ |
315,265 |
$ |
1,214,726 |
$ |
901,844 |
||||||||
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.
Total operating expenses increased $138.8 million, or 44.0%, and $312.9 million, or 34.7%, for the three and nine months ended September 30, 2026, as compared to the same periods in 2025, respectively. The increase for the three and nine months ended September 30, 2026, was primarily as a result of the increase in purchased power expense and the change in amortization of regulatory asset/(liability), net expense. Additionally, total operating expenses increased for the nine months ended September 30, 2026, as compared to the same period in 2025, as a result of the increase in fuel expense. In January and February of 2026, the PJM region experienced periods of extreme cold weather, which increased our purchased power and fuel expenses.
•
Purchased power expense, which includes the cost of purchased energy and capacity, increased $92.5 million, or 75.3%, and $186.8 million, or 47.4%, for the three and nine months ended September 30, 2026, respectively, primarily as a result of the increase in the cost of purchased energy.
•
Purchased energy costs increased $85.6 million, or 77.3%, and $183.4 million, or 51.8%, respectively, due to increases in the average cost and volume of purchased energy.
•
The average cost of purchased energy increased 13.6% and 22.3%, respectively.
•
The volume of purchased energy increased 56.1% and 24.1%, respectively.
•
Amortization of regulatory asset/(liability), net expense changed $28.5 million and $32.6 million, respectively, due to changes in the nuclear decommissioning trust. See "Other Items-Investment (expense)/income, net" below.
•
Fuel expense increased $59.4 million, or 28.6%, for the nine months ended September 30, 2026, due to the 38.7% increase in the average cost of fuel partially offset by the 7.3% decrease in generation from our owned facilities.
Other Items
Investment (expense)/income, net
Investment (expense)/income, net changed $28.7 million and $32.1 million, for the three and nine months ended September 30, 2026, respectively, primarily due to the change in investments in the nuclear decommissioning trust. During the third quarter of 2026, the change in investments in the nuclear decommissioning trust resulted in a realized gain and during the third quarter of 2025, 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 the realized gain and the realized loss through amortization of regulatory asset/(liability), net expense, resulting in no impact on net margin attributable to ODEC on the condensed consolidated statements of revenues, expenses, and patronage capital.
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 three and nine months ended September 30, 2026 and 2025, were as follows:
|
Three Months |
Nine Months |
|||||||||||||||
|
2026 |
2025 |
2026 |
2025 |
|||||||||||||
|
(in thousands) |
||||||||||||||||
|
Interest on long-term debt |
$ |
(13,721 |
) |
$ |
(10,984 |
) |
$ |
(41,148 |
) |
$ |
(32,941 |
) |
||||
|
Interest on revolving credit facility |
(130 |
) |
(816 |
) |
(809 |
) |
(2,673 |
) |
||||||||
|
Other interest |
(637 |
) |
(910 |
) |
(1,881 |
) |
(3,288 |
) |
||||||||
|
Total interest charges |
(14,488 |
) |
(12,710 |
) |
(43,838 |
) |
(38,902 |
) |
||||||||
|
Allowance for borrowed funds used during construction |
1,219 |
852 |
3,461 |
2,332 |
||||||||||||
|
Interest charges, net |
$ |
(13,269 |
) |
$ |
(11,858 |
) |
$ |
(40,377 |
) |
$ |
(36,570 |
) |
||||
Net Margin Attributable to ODEC
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, was relatively flat for the three and nine months ended September 30, 2026, as compared to the same periods in 2025. For both 2026 and 2025, our board of directors approved that an additional equity contribution of $27.5 million would be collected ratably through rates charged to our member distribution cooperatives.
For the three and nine months ended September 30, 2026, we recorded an additional equity contribution of $6.9 million and $20.6 million, respectively, and for the three and nine months ended September 30, 2025, we recorded an additional equity contribution of $6.9 million and $20.6 million, respectively.
Financial Condition
The principal changes in our financial condition from December 31, 2025 to September 30, 2026 were caused by the increases in regulatory liabilities, regulatory assets, nuclear decommissioning trust, and other liabilities, and the decrease in deferred energy.
•
Regulatory liabilities increased $37.4 million primarily due to the deferral of realized gains on changes in investments in the nuclear decommissioning trust, the change in the unrealized gain on the nuclear decommissioning trust, and the increase in the accrual for the zero-emission nuclear power production tax credit.
•
Regulatory assets increased $33.2 million primarily due to the change in the net unrealized losses on derivative instruments.
•
Nuclear decommissioning trust increased $28.8 million primarily due to realized and unrealized gains and losses, net as well as earnings on securities owned in the nuclear decommissioning trust.
•
Other liabilities increased $26.1 million primarily due to the decrease in the fair value of our natural gas hedges.
•
Deferred energy decreased $39.2 million due to the under-collection of our energy costs in 2026. Deferred energy was an over-collection of $59.0 million as of December 31, 2025, and an over-collection of $19.8 million as of September 30, 2026.
Liquidity and Capital Resources
Sources
Cash generated by our operations, periodic borrowings under our revolving credit facility, and occasional issuances of long-term debt provide our sources of liquidity and capital.
Operations
For the first nine months of 2026 and 2025, our operating activities provided cash flows of $68.2 million and $92.1 million, respectively.
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 this credit agreement mature on December 7, 2028, unless earlier terminated in accordance with the agreement. As of September 30, 2026, and December 31, 2025, we did not have any borrowings or letters of credit outstanding under this facility.
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.
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 September 30, 2026, had a balance of $369.4 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.
Old Dominion Electric Cooperative published this content on November 10, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on November 10, 2026 at 19:15 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]