Tennessee Valley Authority
For the period ended Jun 30, 2026. Filed Aug 4, 2026.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Jun 30, 2026 · Filed Aug 4, 2026
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Item 2. Results of Operations
Results of Operations
Sales of Electricity
Sales of electricity were 40,227 million and 39,751 million kilowatt hours ("kWh") for the three months ended June 30, 2026 and 2025, respectively. Sales of electricity were 121,771 million and 120,527 million kWh for the nine months ended June 30, 2026 and 2025, respectively. The total sales of electricity during the nine months ended June 30, 2026, included 60 thousand kWh of pre-commercial generation at CUG, of which 60 thousand kWh was recognized in the three months ended June 30, 2026. The total sales of electricity during the nine months ended June 30, 2025, included 94 thousand kWh of pre-commercial generation at the Johnsonville Aeroderivative Combustion Turbine ("CT") Facility ("Johnsonville Facility"), of which 35 thousand kWh was recognized in the three months ended June 30, 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.
| Degree Days | ||||||||
|---|---|---|---|---|---|---|---|---|
| Variation from Normal · Change from Prior Period | ||||||||
| 2026 | Normal | Percent Variation | 2025 | Normal | Percent Variation | Change | Percent Change | |
| Heating Degree Days | ||||||||
| Three Months Ended June 30 | 96 | 191 | (49.7)% | 144 | 191 | (24.6)% | (48) | (33.3)% |
| Nine Months Ended June 30 | 2,806 | 3,123 | (10.2)% | 2,888 | 3,123 | (7.5)% | (82) | (2.8)% |
| Cooling Degree Days | ||||||||
| Three Months Ended June 30 | 623 | 595 | 4.7% | 611 | 595 | 2.7% | 12 | 2.0% |
| Nine Months Ended June 30 | 741 | 666 | 11.3% | 712 | 666 | 6.9% | 29 | 4.1% |
Sales of electricity increased one percent for the three months ended June 30, 2026, as compared to the same period of the prior year. Sales volume increased primarily due to higher sales within the data processing, web hosting, and related services sector. Partially offsetting this increase was a 33 percent decrease in heating degree days.
Sales of electricity increased one percent for the nine months ended June 30, 2026, as compared to the same period of the prior year. Sales volume increased primarily due to higher sales within the data processing, web hosting, and related services sector.
Financial Results
The following table compares operating results for the three and nine months ended June 30, 2026 and 2025:
| Summary Consolidated Statements of Operations(in millions) | ||||||||
|---|---|---|---|---|---|---|---|---|
| Three Months Ended June 30 | Nine Months Ended June 30 | |||||||
| 2026 | 2025 | Change | Percent Change | 2026 | 2025 | Change | Percent Change | |
| Operating revenues | $3,442 | $3,306 | $136 | 4.1% | $10,037 | $9,758 | $279 | 2.9% |
| Operating expenses | 2,831 | 2,789 | 42 | 1.5% | 8,160 | 8,112 | 48 | 0.6% |
| Operating income | 611 | 517 | 94 | 18.2% | 1,877 | 1,646 | 231 | 14.0% |
| Other income, net | 34 | 29 | 5 | 17.2% | 89 | 58 | 31 | 53.4% |
| Other net periodic benefit cost | 22 | 27 | (5) | (18.5)% | 68 | 79 | (11) | (13.9)% |
| Interest expense | 316 | 307 | 9 | 2.9% | 933 | 880 | 53 | 6.0% |
| Net income | $307 | $212 | $95 | 44.8% | $965 | $745 | $220 | 29.5% |
Operating Revenues. Operating revenues for the three months ended June 30, 2026 and 2025, were $3.4 billion and $3.3 billion, respectively. Operating revenues for the nine months ended June 30, 2026 and 2025, were $10.0 billion and $9.8 billion, respectively. The following table compares TVA's operating revenues for the periods indicated:
| Operating Revenues by Customer Type(in millions) | ||||||||
|---|---|---|---|---|---|---|---|---|
| Three Months Ended June 30 | Nine Months Ended June 30 | |||||||
| 2026 | 2025 | Change | Percent Change | 2026 | 2025 | Change | Percent Change | |
| Operating revenues | ||||||||
| Local power company customers | $3,084 | $2,967 | $117 | 3.9% | $9,001 | $8,782 | $219 | 2.5% |
| Industries directly served | 273 | 259 | 14 | 5.4% | 776 | 734 | 42 | 5.7% |
| Federal agencies and other | 34 | 36 | (2) | (5.6)% | 102 | 100 | 2 | 2.0% |
| Revenue capitalized during pre-commercial plant operations(1) | (2) | (1) | (1) | 100.0% | (2) | (3) | 1 | (33.3)% |
| Other revenue | 53 | 45 | 8 | 17.8% | 160 | 145 | 15 | 10.3% |
| Total operating revenues | $3,442 | $3,306 | $136 | 4.1% | $10,037 | $9,758 | $279 | 2.9% |
Note
(1) Represents revenue capitalized during pre-commercial operations at CUG for the three and nine months ended June 30, 2026, and the Johnsonville Facility for the three and nine months ended June 30, 2025.
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 each accounted for eight percent of TVA's total operating revenues for both the nine months ended June 30, 2026, and the nine months ended June 30, 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 June 30, 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:
| Changes in Revenue Components(in millions) | ||||||
|---|---|---|---|---|---|---|
| Three Months Ended June 30 | Nine Months Ended June 30 | |||||
| 2026 | 2025 | Change | 2026 | 2025 | Change | |
| Base revenue | ||||||
| Energy revenue | $1,275 | $1,264 | $11 | $3,877 | $3,855 | $22 |
| Demand revenue | 1,028 | 1,009 | 19 | 3,131 | 3,034 | 97 |
| Grid access charge | 162 | 161 | 1 | 486 | 485 | 1 |
| Long-term partnership credits for LPCs | (54) | (53) | (1) | (167) | (164) | (3) |
| Other charges and credits(1) | (162) | (166) | 4 | (523) | (522) | (1) |
| Total base revenue | 2,249 | 2,215 | 34 | 6,804 | 6,688 | 116 |
| Fuel cost recovery | 1,141 | 1,045 | 96 | 3,068 | 2,924 | 144 |
| Off-system sales | 1 | 2 | (1) | 7 | 4 | 3 |
| Revenue capitalized during pre-commercial plant operations(2) | (2) | (1) | (1) | (2) | (3) | 1 |
| Revenue from sales of electricity | 3,389 | 3,261 | 128 | 9,877 | 9,613 | 264 |
| Other revenue | 53 | 45 | 8 | 160 | 145 | 15 |
| Total operating revenues | $3,442 | $3,306 | $136 | $10,037 | $9,758 | $279 |
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 CUG for the three and nine months ended June 30, 2026, and the Johnsonville Facility for the three and nine months ended June 30, 2025.
Operating revenues increased $136 million for the three months ended June 30, 2026, as compared to the same period of the prior year, primarily due to a $96 million increase in fuel cost recovery revenue driven by a $82 million increase attributable to higher fuel cost recovery rates, as well as a $14 million increase attributable to higher sales volume. In addition, there was a $34 million increase in base revenue. The $34 million increase in base revenue was driven by a $36 million increase attributable to higher sales volume, partially offset by a $2 million decrease attributable to lower effective base rates. Higher sales volume was driven by higher sales within the data processing, web hosting, and related services sector, which were partially offset by a decrease in heating degree days as compared to the same period of the prior year.
Operating revenues increased $279 million for the nine months ended June 30, 2026, as compared to the same period of the prior year, primarily due to a $144 million increase in fuel cost recovery revenue. The $144 million increase in fuel cost recovery revenue was driven by a $115 million increase attributable to higher fuel cost recovery rates as a result of higher natural gas prices as compared to the same period of the prior year and a $29 million increase attributable to higher sales volume. In addition, there was a $116 million increase in base revenue. The $116 million increase in base revenue was driven by a $103 million increase attributable to higher sales volume and a $13 million increase attributable to higher effective base rates. The higher sales volume was primarily due to higher sales within the data processing, web hosting, and related services sector.
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 nine months ended June 30, 2026 and 2025, consisted of the following:
| Operating Expenses(in millions) | ||||||||
|---|---|---|---|---|---|---|---|---|
| Three Months Ended June 30 | Nine Months Ended June 30 | |||||||
| 2026 | 2025 | Change | Percent Change | 2026 | 2025 | Change | Percent Change | |
| Operating expenses | ||||||||
| Fuel | $685 | $589 | $96 | 16.3% | $1,882 | $1,674 | $208 | 12.4% |
| Purchased power | 563 | 550 | 13 | 2.4% | 1,561 | 1,516 | 45 | 3.0% |
| Operating and maintenance | 964 | 922 | 42 | 4.6% | 2,695 | 2,771 | (76) | (2.7)% |
| Depreciation and amortization | 448 | 572 | (124) | (21.7)% | 1,530 | 1,691 | (161) | (9.5)% |
| Tax equivalents | 171 | 156 | 15 | 9.6% | 492 | 460 | 32 | 7.0% |
| Total operating expenses | $2,831 | $2,789 | $42 | 1.5% | $8,160 | $8,112 | $48 | 0.6% |
Three Months Ended June 30, 2026, Compared to Three Months Ended June 30, 2025
Fuel expense increased $96 million for the three months ended June 30, 2026, as compared to the same period of the prior year. This increase was primarily driven by an increase in fuel cost recovery of $73 million due to the recovery of unplanned fuel costs during the winter of 2026. Additionally, fuel expense increased $26 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 $3 million in effective fuel rates due to higher availability of nuclear generation as compared to the same period of the prior year.
Purchased power expense increased $13 million for the three months ended June 30, 2026, as compared to the same period of the prior year. This increase was primarily due to an increase in purchased power expense of $48 million due to the recovery of unplanned purchased power costs during the winter of 2026. Additionally, purchased power expense increased due to higher purchased power market prices compared to the same period of the prior year, resulting in a $29 million increase. Partially offsetting these increases was a decrease of $64 million due to higher levels of TVA generation as compared to the same period of the prior year.
Operating and maintenance expense increased $42 million for the three months ended June 30, 2026, as compared to the same period of the prior year. This increase was driven by a $16 million increase in payroll and benefit costs primarily for labor escalation and severance costs and an $18 million increase in technology costs associated with higher license and subscription costs and additional cloud asset amortization.
Depreciation and amortization expense decreased $124 million for the three months ended June 30, 2026, as compared to the same period of the prior year. This decrease was primarily driven by a $99 million decrease due to depreciable life assumption changes for CUF and KIF, and 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. Partially offsetting these decreases was an increase due to depreciation of additions to net completed plant.
Tax equivalents expense increased $15 million for the three months ended June 30, 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.
Nine Months Ended June 30, 2026, Compared to Nine Months Ended June 30, 2025
Fuel expense increased $208 million for the nine months ended June 30, 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 $129 million increase in fuel expense. Additionally, fuel expense increased $97 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 $18 million due to the deferral of significant expenses that were the result of higher than expected natural gas prices.
Purchased power expense increased $45 million for the nine months ended June 30, 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 $326 million increase. Partially offsetting this increase was a decrease of $261 million due to higher levels of TVA generation as compared to the same period of the prior year. Additionally, purchased power expense decreased $20 million due to the deferral of significant expenses that were the result of higher than expected market prices.
Operating and maintenance expense decreased $76 million for the nine months ended June 30, 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.
Depreciation and amortization expense decreased $161 million for the nine months ended June 30, 2026, as compared to the same period of the prior year. This decrease was primarily driven by a $132 million decrease due to depreciable life assumption changes for CUF and KIF, and a $105 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. Partially offsetting these decreases was an increase due to depreciation of additions to net completed plant.
Tax equivalents expense increased $32 million for the nine months ended June 30, 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.
| Total Power Supply by Generating SourceFor the three months ended June 30(millions of kWh) | ||||
|---|---|---|---|---|
| 2026 · 2025 | ||||
| Nuclear | 16,891 | 41% | 12,683 | 31% |
| Natural gas and/or oil-fired(1) | 9,705 | 24% | 9,301 | 23% |
| Coal-fired | 5,285 | 13% | 6,196 | 15% |
| Hydroelectric | 1,457 | 3% | 3,537 | 9% |
| Total TVA-operated generation facilities(2)(3) | 33,338 | 81% | 31,717 | 78% |
| Purchased power (natural gas and/or oil-fired)(4) | 3,531 | 9% | 4,067 | 10% |
| Purchased power (other renewables)(5) | 1,518 | 4% | 532 | 2% |
| Purchased power (coal-fired) | 1,263 | 3% | 1,617 | 4% |
| Purchased power (wind)(6) | 1,060 | 2% | 1,314 | 3% |
| Purchased power (hydroelectric) | 223 | 1% | 1,171 | 3% |
| Total purchased power(3) | 7,595 | 19% | 8,701 | 22% |
| Total power supply | 40,933 | 100% | 40,418 | 100% |
Notes
(1) The generation for the three months ended June 30, 2026, included 60 thousand kWh of pre-commercial generation at CUG. The generation for the three months ended June 30, 2025, included 35 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 June 30, 2026, and three months ended June 30, 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 1,081 million kWh and 1,484 million kWh for the three months ended June 30, 2026, and 2025, respectively.
(5) 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.
(6) At June 30, 2025, 1,314 megawatts ("MWs") previously classified as Purchased power (other renewables) has been reclassified to Purchased power (wind)
to conform to current year presentation.
| Total Power Supply by Generating SourceFor the nine months ended June 30(millions of kWh) | ||||
|---|---|---|---|---|
| 2026 · 2025 | ||||
| Nuclear | 50,663 | 41% | 38,584 | 31% |
| Natural gas and/or oil-fired(1) | 28,443 | 23% | 30,525 | 25% |
| Coal-fired | 17,163 | 14% | 17,814 | 15% |
| Hydroelectric | 6,987 | 5% | 10,783 | 9% |
| Total TVA-operated generation facilities(2)(3) | 103,256 | 83% | 97,706 | 80% |
| Purchased power (natural gas and/or oil-fired)(4) | 9,670 | 8% | 12,897 | 11% |
| Purchased power (coal-fired) | 3,476 | 3% | 3,978 | 3% |
| Purchased power (other renewables)(5) | 3,221 | 3% | 2,136 | 1% |
| Purchased power (wind)(6) | 3,061 | 2% | 3,077 | 3% |
| Purchased power (hydroelectric) | 1,279 | 1% | 2,884 | 2% |
| Total purchased power(3) | 20,707 | 17% | 24,972 | 20% |
| Total power supply | 123,963 | 100% | 122,678 | 100% |
Notes
(1) The generation for the nine months ended June 30, 2026, included 60 thousand kWh of pre-commercial generation at CUG. The generation for the nine months ended June 30, 2025, included 94 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 nine months ended June 30, 2026, and nine months ended June 30, 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 3,242 million kWh and 3,958 million kWh for the nine months ended June 30, 2026, and 2025, respectively.
(5) 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.
(6) At June 30, 2025, 3,077 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 2026, TVA expects to invest $146 million on its energy efficiency programs and anticipates approximately 406 gigawatt hours of net incremental energy efficiency savings. During the three and nine months ended June 30, 2026, TVA invested $42 million and $90 million on energy efficiency programs, respectively.
Interest Expense. Interest expense and interest rates for the three and nine months ended June 30, 2026, and the three and nine months ended June 30, 2025, were as follows:
| Interest Expense and Rates(in millions) | ||||||
|---|---|---|---|---|---|---|
| Three Months Ended June 30 | Nine Months Ended June 30 | |||||
| 2026 | 2025 | Percent Change | 2026 | 2025 | Percent Change | |
| Interest expense(1) | $316 | $307 | 2.9% | $933 | $880 | 6.0% |
| Average blended debt balance(2) | $24,021 | $22,775 | 5.5% | $23,670 | $22,270 | 6.3% |
| Average blended interest rate(3) | 5.09% | 5.11% | (0.4)% | 5.08% | 5.03% | 1.0% |
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 $9 million for the three months ended June 30, 2026, as compared to the same period of the prior year. This increase was primarily driven by a $5 million increase from higher average balances on short‐term debt and a $5 million increase in interest on other financing leases, primarily the new lease financing arrangement with Cumberland Combined Cycle Generation LLC ("CCCGL"). This increase was partially offset by a $1 million decrease in interest on short-term debt primarily due to lower average rates.
Total interest expense increased $53 million for the nine months ended June 30, 2026, as compared to the same period of the prior year. This increase was primarily driven by a $50 million increase from higher average balances and rates on long-term debt and a $7 million increase in interest from higher average balances on short-term debt. This increase was partially offset by a $4 million decrease in interest on short-term debt primarily due to lower average rates.
The text of this filing, as the company filed it with the SEC, without its images or exhibits. This is not investment advice.