Tennessee Valley Authority

Results of Operations

Sales of Electricity

Sales of electricity were 42,745 million and 40,636 million kilowatt hours ("kWh") for the three months ended March 31, 2025 and 2024, respectively. Sales of electricity were 80,776 million and 77,971 million kWh for the six months ended March 31, 2025 and 2024, respectively. The total sales of electricity during the six months ended March 31, 2025 included 59 thousand kWh of pre-commercial generation at Johnsonville Aeroderivative CT Units 21-30, of which 49 thousand kWh was recognized in the three months ended March 31, 2025. The total sales of electricity during the six months ended March 31, 2024 included 137 thousand kWh of pre-commercial generation at Paradise CT Units 5-7, all of which was recognized in the three months ended December 31, 2023. TVA sells power at wholesale rates to local power company customers ("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 charts compare TVA's sales of electricity by customer type for the periods indicated:

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 five percent for the three months ended March 31, 2025, as compared to the same period of the prior year. The increased sales volume was primarily driven by increases within the data processing, hosting, and related services sector. In addition, there was an 11 percent increase in heating degree days as compared to the same period of the prior year.

Sales of electricity increased four percent for the six months ended March 31, 2025, as compared to the same period of the prior year. The increased sales volume was primarily driven by increases within the data processing, hosting, and related services sector. In addition, there was a 2 percent increase in heating degree days as compared to the same period of the prior year.

Financial Results

The following table compares operating results for the three and six months ended March 31, 2025 and 2024:

Operating Revenues. Operating revenues for the three months ended March 31, 2025 and 2024, were $3.5 billion and $3.2 billion, respectively. Operating revenues for the six months ended March 31, 2025 and 2024, were $6.5 billion and $5.9 billion, respectively. The following table compares TVA's operating revenues for the periods indicated:

Note

(1) Represents revenue capitalized during pre-commercial operations at Johnsonville Aeroderivative CT Units 21-30 in the six months ended March 31, 2025 and Paradise CT Units 5-7 in the six months ended March 31, 2024, all of which was recognized in the three months ended December 31, 2023.

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 seven percent and eight percent, respectively, of TVA's total operating revenues for both the six months ended March 31, 2025 and the six months ended March 31, 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 March 31, 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.

TVA is required to charge rates for power that will produce gross revenues sufficient to cover various costs as discussed in Part I, Item I, Business —Rates of the Annual Report. In August 2024, the TVA Board approved a 5.25 percent wholesale base rate increase (excluding fuel) effective October 1, 2024, primarily due to additional capacity needs and rising costs. This rate adjustment is estimated to produce an additional $495 million of revenue during 2025.

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 16 —Revenue.

(2) Represents revenue capitalized during pre-commercial operations at Johnsonville Aeroderivative CT Units 21-30 in the six months ended March 31, 2025 and Paradise CT Units 5-7 in the six months ended March 31, 2024, all of which was recognized in the three months ended December 31, 2023.

Operating revenues increased $378 million for the three months ended March 31, 2025, as compared to the same period of the prior year, primarily due to a $266 million increase in base revenue. The $266 million increase in base revenue was driven by a $161 million increase attributable to higher sales volume and a $105 million increase attributable to higher effective base rates. The higher sales volume was driven primarily by increases within the data processing, hosting, and related services sector and an increase in heating degree days. 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. In addition, there was a $120 million increase in fuel cost recovery revenue driven by a $71 million increase attributable to higher effective fuel rates and a $49 million increase attributable to higher sales volume. The higher 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 same period of the prior year.

Operating revenues increased $533 million for the six months ended March 31, 2025, as compared to the same

period of the prior year, primarily due to a $362 million increase in base revenue. The $362 million increase in base revenue was driven by a $202 million increase attributable to higher sales volume and a $160 million increase attributable to higher effective base rates. The higher sales volume was driven primarily by increases within the data processing, hosting, and related services sector and an increase in heating degree days. 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. In addition, there was a $167 million increase in fuel cost recovery revenue driven by a $103 million increase attributable to higher effective fuel rates and a $64 million increase attributable to higher sales volume. The higher 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 same period of 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 the three and six months ended March 31, 2025 and 2024, consisted of the following:

Three Months Ended March 31, 2025, Compared to Three Months Ended March 31, 2024

Fuel expense decreased $61 million for the three months ended March 31, 2025, as compared to the same period of the prior year. A decrease of $131 million was primarily due to the deferral of significant expenses that were the result of higher than expected coal and gas prices due to colder than average temperatures and less availability of nuclear generation compared to forecast. These deferrals will be recognized in expense as collected in customer rates in subsequent quarters. Additionally, fuel expense decreased $18 million due to less availability of nuclear generation as compared to the same period of the prior year. Partially offsetting these decreases was an increase of $88 million due primarily to using higher cost coal and natural gas generation due to less availability of nuclear generation as compared to the same period of the prior year.

Purchased power expense increased $200 million for the three months ended March 31, 2025, as compared to the same period of the prior year. This increase was primarily due to higher demand for energy with less availability of TVA nuclear generation, resulting in an increase of $276 million. Partially offsetting this increase was a $73 million decrease in purchased power expense from lower purchased power market prices compared to the same period of the prior year.

Operating and maintenance expense increased $55 million for the three months ended March 31, 2025, as compared to the same period of the prior year. This increase was primarily due to $71 million of increased payroll and benefit costs primarily due to severance costs associated with ETP efforts and labor escalation for cost of living increases. Partially offsetting these increases was an $11 million decrease in outage expense primarily due to the Sequoyah Nuclear Plant Unit 2 outage for the main generator capital project and an $8 million decrease in expenditures related to project contract labor primarily due to higher power operations performance activities and other natural gas project work in the prior year.

Depreciation and amortization expense increased $32 million for the three months ended March 31, 2025, as compared to the same period of the prior year. The increase was primarily driven by an increase in depreciation expense of $10 million related to the decision in April 2024 to retire Kingston and a $9 million increase in amortization expense of finance leases and amortization expense of decommissioning costs recovered in rates. Additionally, there was an increase due to depreciation of additions to net completed plant.

Tax equivalents expense increased $17 million for the three months ended March 31, 2025, as compared to the same period of the prior year. This change is 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.

Six Months Ended March 31, 2025, Compared to Six Months Ended March 31, 2024

Fuel expense decreased $52 million for the six months ended March 31, 2025, as compared to the same period of the prior year. A decrease of $165 million was primarily due to the deferral of significant expenses that were the result of higher than expected coal and gas prices due to colder than average temperatures and less availability of nuclear generation compared to forecast. These deferrals will be recognized in expense as collected in customer rates in subsequent quarters. Additionally, fuel expense decreased $26 million due to less availability of nuclear generation as compared to the same period of the prior year. Partially offsetting these decreases was an increase of $139 million due primarily to using higher cost coal and natural gas generation due to less availability of nuclear generation as compared to the same period of the prior year.

Purchased power expense increased $235 million for the six months ended March 31, 2025, as compared to the same period of the prior year. This increase was primarily due to higher demand for energy with less availability of TVA nuclear generation, resulting in an increase of $332 million. Partially offsetting this increase was a $93 million decrease in purchased power expense from lower purchased power market prices compared to the same period of the prior year.

Operating and maintenance expense increased $93 million for the six months ended March 31, 2025, as compared to the same period of the prior year. This increase was primarily due to $104 million of increased payroll and benefit costs primarily due to severance costs associated with ETP efforts, labor escalation for cost of living increases, and additional headcount as compared to the prior year. In addition, there was a $17 million increase in outage expense primarily due to the scope and timing of coal and natural gas outages during the six months ended March 31, 2025, as compared to the same period of the prior year and an increase in nuclear outage days. Partially offsetting these increases was a $23 million decrease in expenditures related to project contract labor primarily due to higher power operations performance activities and other natural gas project work in the prior year.

Depreciation and amortization expense increased $68 million for the six months ended March 31, 2025, as compared to the same period of the prior year. The increase was primarily driven by an increase of $25 million related to amortization expense of finance leases and amortization expense of decommissioning costs recovered in rates and an increase in depreciation expense of $20 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.

Tax equivalents expense increased $30 million for the six months ended March 31, 2025, as compared to the same period of the prior year. This change is 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.

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 the three months ended March 31, 2025 includes 49 thousand kWh of pre-commercial generation at Johnsonville Aeroderivative CT Units 21-30. The generation for the three months ended March 31, 2024 includes no 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 three months ended March 31, 2025, and 2024. See Part I, Item 1, Business —Power Supply and Load Management Resources —Hydroelectric Pumped-Storage in the Annual Report for a discussion of Raccoon Mountain Pumped-Storage Plant.

(4) Purchased power (natural gas and/or oil-fired) includes generation from Caledonia Combined Cycle Plant ("Caledonia CC"), which is currently a leased facility operated by TVA. Generation from Caledonia CC was 1,236 million kWh and 966 million kWh for the three months ended March 31, 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.

Notes

(1) The generation for the six months ended March 31, 2025 includes 59 thousand kWh of pre-commercial generation at Johnsonville Aeroderivative CT Units 21-30. The generation for the six months ended March 31, 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 six months ended March 31, 2025, and 2024. See Part I, Item 1, Business —Power Supply and Load Management Resources —Hydroelectric Pumped-Storage in the Annual Report for a discussion of Raccoon Mountain Pumped-Storage Plant.

(4) Purchased power (natural gas and/or oil-fired) includes generation from Caledonia Combined Cycle Plant ("Caledonia CC"), which is currently a leased facility operated by TVA. Generation from Caledonia CC was 2,724 million kWh and 1,876 million kWh for the six months ended March 31, 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 RECs in connection with certain purchased power transactions and sells some of these RECs to customers.

In addition to power supply sources included here, TVA offers energy efficiency programs that effectively reduce energy needs. In 2025, TVA expects to invest $99 million on its energy efficiency programs and anticipates approximately 304 gigawatt hours of net incremental energy efficiency savings.

Interest Expense. Interest expense and interest rates for the three and six months ended March 31, 2025, and the three and six months ended March 31, 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 variable interest entities ("VIEs"), and discount notes.

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

Total interest expense increased $27 million for the three months ended March 31, 2025, as compared to the same period of the prior year. This increase was primarily driven by a $13 million increase in interest on other financing leases, primarily the new lease financing arrangement with Johnsonville Aeroderivative Combustion Turbine Generation LLC ("JACTG"), a $10 million increase from higher average balances of long-term debt, and a $6 million increase from higher average rates on long-term debt. This increase was partially offset by a $2 million decrease in interest on short-term debt primarily due to lower rates.

Total interest expense increased $45 million for the six months ended March 31, 2025, as compared to the same period of the prior year. This increase was primarily driven by a $25 million increase in interest on other financing leases, primarily the new lease financing arrangement with JACTG, a $12 million increase from higher average rates on long-term debt, a $10 million increase from higher average balances of long-term debt, and a $2 million increase from higher average balances of short-term debt. This increase was partially offset by a $4 million decrease in interest on short-term debt primarily due to lower rates.