Tennessee Valley Authority

Results of Operations

Sales of Electricity

Sales of electricity were 41,966 million and 42,745 million kilowatt hours ("kWh") for the three months ended March 31, 2026 and 2025, respectively. Sales of electricity were 81,543 million and 80,776 million kWh for the six months ended March 31, 2026 and 2025, respectively. The total sales of electricity during the six months ended March 31, 2025 included 59 thousand kWh of pre-commercial generation at the Johnsonville Aeroderivative Combustion Turbine ("CT") Facility ("Johnsonville Facility"), of which 49 thousand kWh was recognized in the three months ended March 31, 2025. 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") 2025, 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 decreased two percent for the three months ended March 31, 2026, as compared to the same period of the prior year. For the three months ended March 31, 2026, weather conditions were milder as compared to the same period of the prior year, which resulted in an 11 percent decrease in heating degree days. Partially offsetting this decrease was an increase due to higher sales within the data processing, hosting, and related services sector.

Sales of electricity increased one percent for the six months ended March 31, 2026, as compared to the same period of the prior year. Sales volume increased primarily due to higher sales within the data processing, hosting, and related services sector.

Financial Results

The following table compares operating results for the three and six months ended March 31, 2026 and 2025:

Operating Revenues. Operating revenues for both the three months ended March 31, 2026 and the three months ended March 31, 2025, were $3.5 billion. Operating revenues for the six months ended March 31, 2026 and 2025, were $6.6 billion and $6.5 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 seven percent and eight percent, respectively, of TVA's total operating revenues for both the six months ended March 31, 2026 and the six months ended March 31, 2025.

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, 2026, 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.

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 the Johnsonville Facility for the three and six months ended March 31, 2025.

Operating revenues increased $14 million for the three months ended March 31, 2026, as compared to the same period of the prior year, primarily due to a $76 million increase in fuel cost recovery revenue driven by a $96 million increase attributable to higher fuel cost recovery rates, partially offset by a $20 million decrease attributable to lower sales volume. The higher fuel cost recovery rates were primarily due to higher natural gas prices as compared to the same period of the prior year. The increase in fuel cost recovery revenue was partially offset by a $70 million decrease in base revenue. The $70 million decrease in base revenue was driven by a $59 million decrease attributable to lower sales volume and an $11 million decrease attributable to lower effective base rates. Lower sales volume was driven by weather conditions that were milder as compared to the same period of the prior year which were partially offset by higher sales within the data processing, hosting, and related services sector.

Operating revenues increased $143 million for the six months ended March 31, 2026, as compared to the same period the prior year, primarily due to a $82 million increase in base revenue. The $82 million increase in base revenue was driven by a $67 million increase attributable to higher sales volume and a $15 million increase attributable to higher effective base rates. The higher sales volume was primarily due to higher sales within the data processing, hosting, and related services sector. In addition, there was a $48 million increase in fuel cost recovery revenue. The $48 million increase in fuel cost recovery revenue was driven by a $31 million increase attributable to higher fuel rates as a result of higher natural gas prices as compared to the same period of the prior year and a $17 million increase attributable to higher sales volume.

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, 2026 and 2025, consisted of the following:

Three Months Ended March 31, 2026, Compared to Three Months Ended March 31, 2025

Fuel expense increased $103 million for the three months ended March 31, 2026, as compared to the same period of the prior year. This increase was primarily due to an increase in effective fuel rates due to higher natural gas prices, resulting in a $115 million increase in fuel expense. Additionally, fuel expense increased $40 million due to higher levels of TVA generation as compared to the same period of the prior year. Partially offsetting these increases was a decrease of $52 million due to the deferral of significant expenses that were the result of higher than expected natural gas prices.

Purchased power expense increased $16 million for the three months ended March 31, 2026, as compared to the same period of the prior year. This increase was primarily due to higher purchased power market prices compared to the same period of the prior year, resulting in a $246 million increase. Partially offsetting this increase was a decrease of $196 million

due to higher levels of TVA generation as compared to the same period of the prior year. Additionally, purchased power expense decreased $34 million due to the deferral of significant expenses that were the result of higher than expected market prices.

Operating and maintenance expense decreased $62 million for the three months ended March 31, 2026, as compared to the same period of the prior year. This decrease was driven by a $48 million decrease in payroll and benefit costs primarily due to severance costs associated with the Enterprise Transformation Program ("ETP") efforts in the three months ended March 31, 2025, and a decrease in headcount as compared to the prior year.

Depreciation and amortization expense decreased $51 million for the three months ended March 31, 2026, as compared to the same period of the prior year. This decrease was primarily driven by a $45 million decrease in depreciation expense due to the December 2025 Browns Ferry SLR, which extended the useful life of the three nuclear units for an additional 20 years, and a $33 million decrease due to the depreciable life assumptions for the Cumberland and Kingston Fossil Plants. Partially offsetting these decreases was an increase due to depreciation of additions to net completed plant.

Tax equivalents expense increased $10 million for the three months ended March 31, 2026, 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 2025, which is used as the basis for calculating tax equivalent expense.

Six Months Ended March 31, 2026, Compared to Six Months Ended March 31, 2025

Fuel expense increased $112 million for the six months ended March 31, 2026, as compared to the same period of the prior year. This increase was primarily due to an increase in effective fuel rates due to higher natural gas prices, resulting in a $133 million increase in fuel expense. Additionally, fuel expense increased $70 million due to higher levels of TVA generation as compared to the same period of the prior year. Partially offsetting these increases was a decrease of $91 million due to the deferral of significant expenses that were the result of higher than expected natural gas prices.

Purchased power expense increased $32 million for the six months ended March 31, 2026, as compared to the same period of the prior year. This increase was primarily due to higher purchased power market prices compared to the same period of the prior year, resulting in a $299 million increase. Partially offsetting this increase was a decrease of $199 million due to higher levels of TVA generation as compared to the same period of the prior year. Additionally, purchased power expense decreased $68 million due to the deferral of significant expenses that were the result of higher than expected market prices.

Operating and maintenance expense decreased $118 million for the six months ended March 31, 2026, as compared to the same period of the prior year. This decrease was primarily due to IRA tax credits recorded in the three months ended December 31, 2025, which contributed $62 million to the overall decrease. These credits were recognized as a reduction in Operating and maintenance expense based on what the credits were intended to reimburse. See Note 1— Summary of Significant Accounting Policies — Government Grants. In addition, there was a $48 million decrease in payroll and benefit costs primarily due to severance costs associated with the ETP efforts in the six months ended March 31, 2025, and a decrease in headcount as compared to the prior year.

Depreciation and amortization expense decreased $37 million for the six months ended March 31, 2026, as compared to the same period of the prior year. This decrease was primarily driven by a $60 million decrease in depreciation expense due to the December 2025 Browns Ferry SLR, which extended the useful life of the three nuclear units for an additional 20 years, and a $33 million decrease due to the depreciable life assumptions for the Cumberland and Kingston Fossil Plants. Partially offsetting these decreases was an increase due to depreciation of additions to net completed plant.

Tax equivalents expense increased $17 million for the six months ended March 31, 2026, 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 2025, 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 included 49 thousand kWh of pre-commercial generation at the Johnsonville Facility.

(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, 2026, and three months ended March 31, 2025. See Part I, Item 1, Business —Power Supply and Load Management Resources —Hydroelectric Pumped-Storagein 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 1,141 million kWh and 1,486 million kWh for the three months ended March 31, 2026, and 2025, respectively.

(5) At March 31, 2025, 1,125 megawatts ("MWs") previously classified as Purchased power (other renewables) has been reclassified to Purchased power (wind)

to conform to current year presentation.

(6) Purchased power (other renewables) includes purchased power from the following renewable sources: solar, 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 included 59 thousand kWh of pre-commercial generation at the Johnsonville Facility.

(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, 2026, and six months ended March 31, 2025. 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 CC, which is currently a leased facility operated by TVA. Generation from Caledonia CC was 2,161 million kWh and 2,724 million kWh for the six months ended March 31, 2026, and 2025, respectively.

(5) At March 31, 2025, 2,149 MWs previously classified as Purchased power (other renewables) has been reclassified to Purchased power (wind)

to conform to current year presentation.

(6) Purchased power (other renewables) includes purchased power from the following renewable sources: solar, 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 2026, TVA expects to invest $133 million on its energy efficiency programs and anticipates approximately 400 gigawatt hours of net incremental energy efficiency savings. During the three and six months ended March 31, 2026, TVA invested $55 million and $82 million on energy efficiency programs, respectively.

Interest Expense. Interest expense and interest rates for the three and six months ended March 31, 2026, and the three and six months ended March 31, 2025, 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 VIEs, and discount notes.

Total interest expense increased $15 million for the three months ended March 31, 2026, as compared to the same period of the prior year. This increase was primarily driven by a $16 million increase from higher average balances and rates on long‐term debt and a $3 million increase in interest from higher average balances on short-term debt. This increase was partially offset by lower interest on short-term debt primarily due to lower rates.

Total interest expense increased $44 million for the six months ended March 31, 2026, as compared to the same period of the prior year. This increase was primarily driven by a $49 million increase from higher average balances and rates on long-term debt and a $2 million increase in interest from higher average balances on short-term debt. This increase was partially offset by lower interest on short-term debt primarily due to lower rates.