Tennessee Valley Authority

Results of Operations

Sales of Electricity

Sales of electricity were 167,612 million and 162,933 million kilowatt hours ("kWh") for 2025 and 2024, respectively. The total sales of electricity in 2025 included 99 thousand kWh of pre-commercial generation at Johnsonville Aeroderivative CT Units 21-30. The total sales of electricity in 2024 included 137 thousand kWh of pre-commercial generation at Paradise CTs 5-7. TVA sells power at wholesale rates to LPCs that then resell the power to their customers at retail rates. TVA also sells power to directly served customers, consisting primarily of federal agencies and customers with large or nonstandard loads. In addition, power exceeding TVA's system needs is sold under exchange power arrangements with certain other power systems.

The following chart compares TVA's sales of electricity by customer type for the years ended September 30, 2025 and 2024:

Sales of Electricity

For the years ended September 30

(millions of kWh)

The following charts show a breakdown of TVA's energy load:

Note

Information included in the charts above was derived from energy usage of directly served customers and customers served by LPCs during calendar year ("CY") 2024, and these graphs will continue to be updated on a CY basis.

Weather affects both the demand for TVA power and the price for that power. TVA uses degree days to measure the impact of weather on its power operations. Degree days measure the extent to which the TVA system 23-station average temperatures vary from 65 degrees Fahrenheit.

Sales of electricity increased approximately three percent for the year ended September 30, 2025, as compared to the prior year. The increased sales volume was primarily driven by higher sales to residential and small commercial and industrial customers as well as increases within the data processing, hosting, and related services sector.

Financial Results

The following table compares operating results for 2025 and 2024:

Operating Revenues. Operating revenues for the years ended September 30, 2025 and 2024, were $13.7 billion and $12.3 billion, respectively. The following table compares TVA's operating revenues for the periods indicated:

Note

TVA's two largest LPCs — Memphis Light, Gas and Water Division ("MLGW") and Nashville Electric Service ("NES") — have contracts with a five-year and a 20-year termination notice period, respectively. Sales to MLGW and NES accounted for nine percent and eight percent, respectively, of TVA's total operating revenues during both the years ended September 30, 2025 and 2024.

TVA's rate structure uses pricing signals to indicate seasons and hours of higher cost to serve its customers and to capture a portion of TVA's fixed costs in fixed charges. The structure includes three base revenue components: time of use demand charges, time of use energy charges, and a grid access charge ("GAC"). The demand charges are based upon the customer's peak monthly usage. The energy charges are based on time differentiated kWh used by the customer. Both of these components can be significantly impacted by weather. The GAC captures a portion of fixed costs and is offset by a corresponding reduction to the energy rates. The GAC also reduces the impact of weather variability to the overall rate structure.

TVA has a Partnership Agreement option that better aligns the length of LPC power contracts with TVA's long-term commitments. Under the partnership arrangement, the LPC power contracts automatically renew each year and have a 20-year termination notice. The partnership arrangements can be terminated under certain circumstances, including TVA’s failure to limit rate increases to no more than 10 percent during any consecutive five-fiscal-year period, as more specifically described in the agreements. Participating LPCs receive benefits including a 3.1 percent wholesale bill credit in exchange for their long-term commitment, which enables TVA to recover its long-term financial commitments over a commensurate period. As of September 30, 2025, 148 LPCs had signed the 20-year Partnership Agreement with TVA.

In addition to base revenues, the rate structure includes a separate fuel rate that includes the costs of natural gas, fuel oil, purchased power, coal, emission allowances, nuclear fuel, and other fuel-related commodities; realized gains and losses on derivatives purchased to hedge the costs of such commodities; and payments to states and counties in lieu of taxes ("tax equivalents") associated with the fuel cost adjustments. See Part I, Item 1, Business— Rates — Rate Methodology.

The changes in revenue components are summarized below:

Notes

(1) Includes economic development credits to promote growth in the Tennessee Valley, hydro preference credits for residential customers of LPCs, and demand response credits allowing TVA to reduce industrial customer usage in periods of peak demand to balance system demand. See Note 18 —Revenue.

(2) Represents revenue capitalized during pre-commercial operations at Johnsonville Aeroderivative CT Units 21-30 in 2025 and Paradise CT Units 5-7 in 2024.

Operating revenues increased $1.4 billion for the year ended September 30, 2025, as compared to the prior year, primarily due to a $690 million increase in base revenue. The $690 million increase in base revenue was driven by a $400 million increase attributable to higher effective base rates and a $290 million increase attributable to higher sales volume. The increase in effective base rates was primarily due to the TVA Board action to approve a 5.25 percent wholesale base rate increase effective October 1, 2024. The higher sales volume was driven primarily by higher sales to residential and small commercial and industrial customers as well as increases within the data processing, hosting, and related services sector. In addition, there was a $670 million increase in fuel cost recovery revenue driven by a $572 million increase attributable to higher effective fuel rates and a $98 million increase attributable to higher sales volume. The higher effective fuel rates were due primarily to using higher cost coal and natural gas generation due to less availability of nuclear generation as compared to the prior year.

See Sales of Electricity above for further discussion of the change in the volume of sales of electricity and Operating Expenses below for further discussion of the change in fuel expense.

Operating Expenses. Operating expense components as a percentage of total operating expenses for 2025 and 2024 consisted of the following:

The following table summarizes TVA's expenses for various fuels for the years indicated:

Notes

(1) Excludes effects of the fuel cost adjustment in the amounts of $18 million and $(4) million for the years ended September 30, 2025 and 2024, respectively.

(2) Fuel expense related to oil consumed for startup at coal-fired facilities was $32 million and $23 million for the years ended September 30, 2025 and 2024, respectively.

(3) Fuel expense related to oil consumed for generation at natural gas and/or oil-fired facilities was $6 million and $8 million for the years ended September 30, 2025 and 2024, respectively.

(4) Total cost per kWh is based on a weighted average.

Fuel expense increased $207 million for the year ended September 30, 2025, as compared to the prior year. An increase of $194 million was due primarily to higher effective fuel rates related to using higher cost coal and natural gas generation due to less availability of nuclear generation as compared to the prior year. Additionally, fuel expense increased $22 million due to the recovery of prior year deferrals of unplanned coal costs, and gas prices being lower than forecasted during the summer of 2025. Partially offsetting these increases was a decrease of $9 million due to more availability of hydro generation as compared to the prior year.

Purchased power expense increased $525 million for the year ended September 30, 2025, as compared to the prior year. This increase was primarily due to higher demand for energy and less availability of TVA nuclear generation, resulting in an increase of $305 million. Additionally, purchased power expense increased $173 million due to higher purchased power market prices as compared to the prior year. Finally, purchased power expense increased $47 million due to the recovery of prior year deferrals of unplanned purchased power costs, and gas and purchased power prices being lower than forecasted during the summer of 2025.

Operating and maintenance expense increased $76 million for the year ended September 30, 2025, as compared to the prior year. This increase was primarily due to $136 million of increased payroll and benefit costs primarily due to labor escalation for cost of living increases, severance costs associated with ETP efforts, and higher medical claims. Partially offsetting these increases was a $48 million decrease in outage expense primarily due to fewer nuclear refueling outages.

Depreciation and amortization expense increased $133 million for the year ended September 30, 2025, as compared to the prior year. The increase was primarily driven by an increase of $43 million related to amortization expense of decommissioning costs recovered in rates and amortization expense of finance leases and an increase in depreciation expense of $18 million related to the decision in April 2024 to retire Kingston. Additionally, there was an increase due to depreciation of additions to net completed plant. See Note 1 —Summary of Significant Accounting Policies — Property, Plant, and Equipment, and Depreciation — Depreciation.

Tax equivalents expense increased $76 million for the year ended September 30, 2025, as compared to the prior year. This change was primarily driven by an increase in TVA's revenue from sales of electricity in 2024, which is used as the basis for calculating tax equivalent expense. Additionally, tax equivalents expense increased due to an increase in the tax equivalents collected in the fuel cost recovery.

Generating Sources. The following tables show TVA's generation and purchased power by generating source as a percentage of all electrical power generated and purchased (based on kWh) for the periods indicated:

Notes

(1) The generation for 2024 includes 99 thousand kWh of pre-commercial generation at Johnsonville Aeroderivative CT Units 21-30. The generation for 2024 includes 137 thousand kWh of pre-commercial generation at Paradise CT Units 5-7.

(2) Generation from TVA-owned renewable resources (non-hydroelectric) is less than one percent for all periods shown and therefore is not represented in the table above.

(3) Raccoon Mountain Pumped-Storage Plant net generation is allocated against each TVA-operated generation facility and purchased power type for both the year ended September 30, 2025, and the year ended September 30, 2024. See Part I, Item 1, Business —Power Supply and Load Management Resources —Hydroelectric Pumped-Storagefor a discussion of Raccoon Mountain Pumped-Storage Plant.

(4) Purchased power (natural gas and/or oil-fired) includes generation from Caledonia CC, which is currently a leased facility operated by TVA. Generation from Caledonia Combined Cycle Plant ("Caledonia CC") was 5,464 million kWh and 4,798 million kWh for the years ended September 30, 2025 and 2024, respectively.

(5) Purchased power (other renewables) includes purchased power from the following renewable sources: solar, wind, biomass, and renewable cogeneration. TVA acquires Renewable Energy Certificates ("RECs") in connection with certain purchased power transactions and sells some of these RECs to customers.

(6) At September 30, 2024, 2,286 MWs previously classified as Purchased power (other renewables) has been reclassified to Purchased power (wind) to conform to current year presentation.

In addition to power supply sources included here, TVA offers energy efficiency programs that effectively reduce energy

needs. In 2025, TVA invested $94 million on its energy efficiency programs and effectively reduced 2025 energy needs by approximately 257 gigawatt hours of net incremental energy efficiency savings.

Interest Expense. Interest expense and interest rates for 2025 and 2024 were as follows:

Notes

(1) Includes amortization of debt discounts, issuance, and reacquisition costs, net.

(2) Includes average balances of long-term power bonds, debt of VIEs, and discount notes.

(3) Includes interest on long-term power bonds, debt of VIEs, and discount notes.

Total interest expense increased $130 million for the year ended September 30, 2025, as compared to the prior year. This increase was primarily driven by a $97 million increase from higher average balances and rates on long-term debt, and a $51 million increase in interest on other financing leases, primarily driven by the lease financing arrangement with Johnsonville Aeroderivative Combustion Turbine Generation LLC ("JACTG"). This increase was partially offset by an $18 million decrease in interest on short-term debt primarily due to lower average balances and rates.

Other Income, Net

Other income, net increased $21 million for the year ended September 30, 2025, as compared to the prior year. This increase was driven by increases in external services primarily due to additional transmission projects as a result of economic development and higher interest income on cash investments due to a higher balance of cash held during the year, partially offset by lower short-term rates earned on that cash.

Other Net Periodic Benefit Cost

Other net periodic benefit cost increased $7 million for the year ended September 30, 2025, as compared to the prior year. The increase is primarily due to the decreases in the discount rates used to measure net periodic benefit cost for the year ended September 30, 2025, as compared to the prior year. Other net periodic benefit cost is subject to significant economic assumptions, such as changes in the discount rate, COLA, and the rate of return on plan assets, that can materially impact TVA. See Note 21 —Benefit Plans.