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þ | ANNUAL REPORT PURSUANT TO SECTION 13, 15(d), OR 37 OF THE SECURITIES EXCHANGE ACT OF 1934 |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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A corporate agency of the United States created by an act of Congress | 62-0474417 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
400 W. Summit Hill Drive Knoxville, Tennessee | 37902 | |
(Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code
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• | Statements regarding strategic objectives; | ||
• | Projections regarding potential rate actions; | ||
• | Estimates of costs of certain retirement obligations; | ||
• | Estimates regarding power and energy forecasts; | ||
• | Expectations about the adequacy of TVA’s pension plans and nuclear decommissioning trust; | ||
• | Estimates regarding the reduction of total financing obligations; | ||
• | The impact of new accounting pronouncements and interpretations, including Statement of Financial Accounting Standards No. 158,“Employers Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R);” | ||
• | Estimates of amounts to be reclassified fromOther Comprehensive Income to earnings over the next year; | ||
• | TVA’s plans to continue using short-term debt to meet current obligations; and | ||
• | The anticipated cost and timetable for returning Browns Ferry Unit 1 to service. |
• | New laws, regulations, and administrative orders, especially those related to: |
– TVA’s protected service area, – The sole authority of the TVA Board to set power rates, – Various environmental and nuclear matters, – TVA’s management of the Tennessee River system, – TVA’s credit rating, and – TVA’s debt ceiling; |
• | Performance of TVA’s generation and transmission assets; | ||
• | Availability of fuel supplies; | ||
• | Compliance with existing environmental laws and regulations; | ||
• | Significant delays or cost overruns in construction of generation and transmission assets; | ||
• | Significant changes in demand for electricity; | ||
• | Legal and administrative proceedings; | ||
• | Weather conditions; | ||
• | Failure of transmission facilities; | ||
• | An accident at any nuclear facility, even one unaffiliated with TVA; | ||
• | Catastrophic events such as fires, earthquakes, floods, pandemics, wars, terrorist activities, and other similar events, especially if these events occur in or near TVA’s service area; | ||
• | Changes in the market price of commodities such as coal, uranium, natural gas, fuel oil, electricity, and emission allowances; | ||
• | Changes in the prices of equity securities, debt securities, and other investments; | ||
• | Changes in interest rates; | ||
• | Creditworthiness of TVA or its counterparties; | ||
• | Rising pension costs and health care expenses; | ||
• | Increases in TVA’s financial liability for decommissioning its nuclear facilities; | ||
• | Limitations on TVA’s ability to borrow money; | ||
• | Changes in economic environments; | ||
• | Ineffectiveness of TVA’s disclosure controls and procedures; | ||
• | Changes in accounting standards; | ||
• | The loss of TVA’s ability to use regulatory accounting; | ||
• | Loss of key personnel; | ||
• | Changes in technology; and | ||
• | Unforeseeable events. |
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• | TVA was created by an act of the U.S. Congress and is a wholly-owned corporate agency of the United States. | ||
• | TVA’s board of directors (the “TVA Board”) is appointed by the President with the advice and consent of the U.S. Senate. | ||
• | TVA holds its real properties as an agent for the United States. | ||
• | TVA is required to make payments to the U.S. Treasury as a repayment of and a return on the appropriation investment that the United States provided TVA for its power program (the “Appropriation Investment”). | ||
• | TVA is not authorized to issue equity securities such as common or preferred stock. Accordingly, TVA finances its operations primarily with cash flows from operations and proceeds from issuing debt. | ||
• | The TVA Board sets the rates TVA charges for power. In setting rates, the TVA Board must have due regard for the objective that power be sold at rates as low as are feasible. | ||
• | TVA is exempt from paying federal income taxes and state and local taxes but must pay certain states and counties an amount in lieu of taxes equal to five percent of TVA’s gross revenues from the sale of power during the preceding year excluding sales or deliveries to other federal agencies and exchange sales with other utilities, with a provision for minimum payments under certain circumstances. |
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(in millions)
2006 | 2005 | 2004 | ||||||||||
Alabama | $ | 1,268 | $ | 1,054 | $ | 1,033 | ||||||
Georgia | 228 | 186 | 182 | |||||||||
Kentucky | 909 | 832 | 731 | |||||||||
Mississippi | 826 | 674 | 658 | |||||||||
North Carolina | 47 | 39 | 38 | |||||||||
Tennessee | 5,764 | 4,820 | 4,734 | |||||||||
Virginia | 7 | 4 | 4 | |||||||||
9,049 | 7,609 | 7,380 | ||||||||||
Sale for resale | 13 | 95 | 59 | |||||||||
$ | 9,062 | $ | 7,704 | $ | 7,439 | |||||||
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(in millions)
2006 | 2005 | 2004 | ||||||||||
Municipalities and cooperatives | $ | 7,880 | $ | 6,561 | $ | 6,457 | ||||||
Industries directly served | 1,066 | 962 | 842 | |||||||||
Federal agencies and other | ||||||||||||
Federal agencies directly served | 103 | 86 | 81 | |||||||||
Exchange sales | 13 | 95 | 59 | |||||||||
Total | $ | 9,062 | $ | 7,704 | $ | 7,439 | ||||||
• | Contracts that require five years’ notice to terminate; | ||
• | Contracts that require 10 years’ notice to terminate; and | ||
• | Contracts that require 15 years’ notice to terminate. |
As of September 30, 2006
Number of | Sales to | Percentage of Total | ||||||||||
Distributor | Distributor | Operating Revenues | ||||||||||
Contract Arrangement | Customers | Customers in 2006 | in 2006 | |||||||||
(in millions) | ||||||||||||
15-Year Termination Notice | 5 | $ | 92 | 1.0 | % | |||||||
10-Year Termination Notice | 48 | 2,625 | 28.6 | % | ||||||||
5-Year Termination Notice * | 99 | 4,893 | 53.3 | % | ||||||||
Notice Given - - Less than 5 Years | ||||||||||||
Remaining* | 6 | 270 | 2.9 | % | ||||||||
158 | $ | 7,880 | 85.8 | % | ||||||||
* | Ordinarily the distributor customer and TVA have the same termination notice period; however, in contracts with six of the distributor customers with a five-year termination notice, TVA has a 10-year termination notice (which becomes a five-year termination notice if TVA loses its discretionary wholesale rate-setting authority). |
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As of September 30, 2006
TVA Sales to | ||||||||||||
Distributor | Percentage | |||||||||||
Date of Termination | Customer | of TVA Operating | ||||||||||
Distributor Customer | Location | of Power Contract | in 2006 | Revenues in 2006 | ||||||||
(in millions) | ||||||||||||
Monticello Electric Plant Board | Kentucky | November 2008 | $ | 6 | 0.1 | % | ||||||
Glasgow Electric Plant Board | Kentucky | November 2008 | 21 | 0.2 | % | |||||||
Warren Rural Electric Cooperative Corporation | Kentucky | April 2009 | 97 | 1.0 | % | |||||||
Paducah Power System | Kentucky | December 2009 | 39 | 0.4 | % | |||||||
Princeton Electric Plant Board | Kentucky | January 2010 | 6 | 0.1 | % | |||||||
Duck River Electric Membership Corporation | Tennessee | August 2010 | 101 | 1.1 | % | |||||||
Total | $ | 270 | 2.9 | % | ||||||||
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• | Operation, maintenance, and administration of its power system; | ||
• | Payments to states and counties in lieu of taxes; | ||
• | Debt service on outstanding indebtedness; | ||
• | Payments to the U.S. Treasury in repayment of and as a return on the Appropriation Investment in TVA’s power facilities; and | ||
• | Such additional margin as the TVA Board may consider desirable for investment in power system assets, retirement of outstanding indebtedness, additional reduction of the Appropriation Investment, and other purposes connected with TVA’s power business. |
1) | Fuel and purchased power costs; | ||
2) | Operating and maintenance costs; | ||
3) | Taxes; and | ||
4) | Debt service coverage. |
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As of September 30
(millions of kWh)
2006 | 2005 | 2004 | 2003 | 2002 | |||||||||||||||||||||||||||||||||||||||||
Coal-fired | 99,630 | 64 | % | 98,404 | 62 | % | 94,648 | 61 | % | 90,975 | 60 | % | 94,930 | 63 | % | ||||||||||||||||||||||||||||||
Nuclear | 45,313 | 29 | % | 45,156 | 28 | % | 46,003 | 30 | % | 43,167 | 29 | % | 45,179 | 30 | % | ||||||||||||||||||||||||||||||
Hydroelectric | 9,961 | 6 | % | 15,723 | 10 | % | 13,916 | 9 | % | 16,103 | 11 | % | 10,205 | 6 | % | ||||||||||||||||||||||||||||||
Combustion turbine and diesel generators | 613 | <1 | % | 595 | <1 | % | 278 | <1 | % | 817 | <1 | % | 1,190 | 1 | % | ||||||||||||||||||||||||||||||
Renewable resources | 19 | <1 | % | 18 | <1 | % | 18 | <1 | % | 15 | <1 | % | 18 | <1 | % | ||||||||||||||||||||||||||||||
Total | 155,536 | 100 | % | 159,896 | 100 | % | 154,863 | 100 | % | 151,077 | 100 | % | 151,522 | 100 | % | ||||||||||||||||||||||||||||||
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• | Tapoco, Inc.Four hydroelectric plants owned by Tapoco, Inc. (“Tapoco”), a subsidiary of Alcoa, Inc. (“Alcoa”), are operated in coordination with the TVA system. Under contractual arrangements with Tapoco which terminate on June 20, 2010, TVA purchases the electric power generated at these facilities and uses it to partially supply Alcoa’s energy needs. TVA’s arrangement with Tapoco provides 362 megawatts of winter net dependable capacity. | ||
• | Southeastern Power Administration.Under arrangements among TVA, the U.S. Army Corps of Engineers, and the Southeastern Power Administration (“SEPA”), eight hydroelectric plants of the U.S. Army Corps of Engineers on the Cumberland River system are operated in coordination with the TVA system. These arrangements provide for 405 megawatts of winter net dependable capacity as well as |
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• | Choctaw Generation, L.P.TVA has contracted with Choctaw Generation L.P. (“Choctaw”) for 440 megawatts of winter net dependable capacity from a lignite-fired generating plant in Chester, Mississippi. TVA’s contract with Choctaw expires on March 31, 2032. |
(in millions of kWh)
2006 | 2005 | 2004 | 2003 | 2002 | ||||
20,017 | 16,637 | 15,148 | 15,760 | 12,241 |
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As of September 30, 2006
Winter Net | Date First Unit | Date Last Unit | ||||||||||||||||
Number of | Dependable | Placed in | Placed in | |||||||||||||||
Source of Capacity | Location | Units | Capacity (MW)1 | Service | Service | |||||||||||||
Coal-Fired | ||||||||||||||||||
Allen | Tennessee | 3 | 750 | 1959 | 1959 | |||||||||||||
Bull Run | Tennessee | 1 | 889 | 1967 | 1967 | |||||||||||||
Colbert | Alabama | 5 | 1,201 | 1955 | 1965 | |||||||||||||
Cumberland | Tennessee | 2 | 2,524 | 1973 | 1973 | |||||||||||||
Gallatin | Tennessee | 4 | 988 | 1956 | 1959 | |||||||||||||
John Sevier | Tennessee | 4 | 712 | 1955 | 1957 | |||||||||||||
Johnsonville | Tennessee | 10 | 1,254 | 1951 | 1959 | |||||||||||||
Kingston | Tennessee | 9 | 1,448 | 1954 | 1955 | |||||||||||||
Paradise | Kentucky | 3 | 2,318 | 1963 | 1970 | |||||||||||||
Shawnee | Kentucky | 10 | 1,369 | 1953 | 1956 | |||||||||||||
Widows Creek | Alabama | 8 | 1,628 | 1952 | 1965 | |||||||||||||
Total Coal-Fired | 59 | 15,081 | ||||||||||||||||
Nuclear | ||||||||||||||||||
Browns Ferry | Alabama | 2 | 2,269 | 1974 | 1977 | |||||||||||||
Sequoyah | Tennessee | 2 | 2,333 | 1981 | 1982 | |||||||||||||
Watts Bar | Tennessee | 1 | 1,168 | 1996 | 1996 | |||||||||||||
Total Nuclear | 5 | 5,770 | ||||||||||||||||
Hydroelectric | ||||||||||||||||||
Conventional Plants | Alabama | 36 | 1,146 | 1925 | 1962 | |||||||||||||
Georgia | 2 | 32 | 1931 | 1956 | ||||||||||||||
Kentucky | 5 | 165 | 1944 | 1948 | ||||||||||||||
North Carolina | 8 | 536 | 1940 | 1956 | ||||||||||||||
Tennessee | 58 | 1,647 | 1912 | 1972 | ||||||||||||||
Pumped Storage | Tennessee | 4 | 1,618 | 1978 | 1979 | |||||||||||||
Total Hydroelectric | 113 | 5,144 | ||||||||||||||||
Combustion Turbine | ||||||||||||||||||
Allen | Tennessee | 20 | 575 | 1971 | 1972 | |||||||||||||
Colbert | Alabama | 8 | 486 | 1972 | 1972 | |||||||||||||
Gallatin | Tennessee | 8 | 730 | 1975 | 2000 | |||||||||||||
Johnsonville | Tennessee | 20 | 1,372 | 1975 | 2000 | |||||||||||||
Kemper | Mississippi | 4 | 374 | 2001 | 2001 | |||||||||||||
Lagoon Creek | Tennessee | 12 | 1,126 | 2002 | 2002 | |||||||||||||
Total Combustion Turbine | 72 | 4,663 | 2 | |||||||||||||||
Diesel Generator | ||||||||||||||||||
Meridian | Mississippi | 5 | 9 | 1998 | 1998 | |||||||||||||
Albertville | Alabama | 4 | 4 | 2000 | 2000 | |||||||||||||
Total Diesel Generators | 9 | 13 | ||||||||||||||||
Renewable Resources Owned by TVA | 5 | |||||||||||||||||
Total TVA-Owned Generation Facilities | 30,676 | |||||||||||||||||
Power Purchase Agreements | ||||||||||||||||||
Tapoco | 362 | |||||||||||||||||
SEPA | 405 | |||||||||||||||||
Choctaw | 440 | |||||||||||||||||
Other Power Purchase Agreements | 3,068 | |||||||||||||||||
Total Power Purchase Agreements | 4,275 | |||||||||||||||||
Total Winter Net Dependable Capacity | 34,951 | |||||||||||||||||
Notes | ||
(1) | Net dependable capacity is the net power output which can be obtained for a period adequate to satisfy the daily load patterns under expected conditions of operation with equipment in an average state of maintenance excluding any fluctuations in capacity that may occur due to planned outages, unplanned outages, and deratings. TVA currently estimates gas, combustion turbine, and diesel generator capacity at 95 degrees Fahrenheit for summer net dependable capacity and at 25 degrees Fahrenheit for winter net dependable capacity. For planning purposes, TVA estimated total summer net dependable capacity at September 30, 2006 to be approximately 33,653 megawatts, including hydroelectric capacity of approximately 5,458 megawatts, coal-fired capacity of approximately 14,709 megawatts, nuclear power capacity of approximately 5,611 megawatts, combustion turbine capacity of approximately 3,708 megawatts, diesel generator capacity of approximately 13 megawatts, capacity from renewable assets of approximately five megawatts, and capacity from power purchase agreements of approximately 4,149 megawatts. | |
(2) | As of September 30, 2006, 24 of TVA’s combustion turbine units were leased to private entities and leased back to TVA under long-term leases. |
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As of September 30, 2006
Installed | ||||||||||||||||||
Capacity | Net Capacity | Date of Expiration of | Date of Expiration of | |||||||||||||||
Nuclear Unit | Status | (Megawatts) | Factor for 2006 | Operating License | Construction License | |||||||||||||
Sequoyah Unit 1 | Operating | 1,221 | 88.9 | 2020 | – | |||||||||||||
Sequoyah Unit 2 | Operating | 1,221 | 98.0 | 2021 | – | |||||||||||||
Browns Ferry Unit 2 | Operating | 1,190 | 96.4 | 2034 | 3 | – | ||||||||||||
Browns Ferry Unit 3 | Operating | 1,190 | 84.7 | 2036 | 3 | – | ||||||||||||
Watts Bar Unit 1 | Operating | 1,270 | 84.0 | 2035 | – | |||||||||||||
Watts Bar Unit 2 | Deferred1 | – | – | – | 2010 | |||||||||||||
Bellefonte Unit 1 | Canceled2 | – | – | – | – | |||||||||||||
Bellefonte Unit 2 | Canceled2 | – | – | – | – | |||||||||||||
Browns Ferry Unit 1 | Recovery4 | 1,150 | – | 2033 | 3 | – |
Notes | ||
(1) | Per the Nuclear Regulatory Commission’s definition of deferred nuclear units. TVA is planning to perform a detailed scoping, estimating, and planning study at Watts Bar Nuclear Plant Unit 2 during 2007 and 2008 and has budgeted $30 million for the study. Watts Bar Unit 2 is a partially completed nuclear unit similar in design to the operating Watts Bar Unit 1. The purpose of the study is to provide accurate cost, schedule, and risk information to enable a more informed future decision regarding new base load generation. No decision has been made to actually complete Watts Bar Unit 2. | |
(2) | In September 2006, the Nuclear Regulatory Commission (“NRC”) approved TVA’s request to terminate the construction permits for unfinished Bellefonte Units 1 and 2. The TVA Board approved canceling the Bellefonte construction project in November 2005. Neither of these actions interferes in any way with TVA’s ability to use the site for future projects. | |
(3) | On May 3, 2006, the NRC approved TVA’s applications for 20-year license extensions for these units. (The expiration dates listed in the table reflect the extensions.) | |
(4) | Browns Ferry Unit 1 is expected to return to service in 2007 and is expected initially to provide additional generating capacity of approximately 1,150 megawatts and eventually to provide 1,280 megawatts of capacity. At September 30, 2006, the restart construction at Browns Ferry Unit 1 was approximately 94 percent complete. |
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(in millions of dollars)
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Coal | $ | 1,835 | $ | 1,495 | $ | 1,254 | $ | 1,242 | $ | 1,233 | ||||||||||
Natural Gas | 60 | 63 | 22 | 42 | 50 | |||||||||||||||
Fuel Oil | 46 | 28 | 17 | 40 | 14 | |||||||||||||||
Uranium | 71 | 44 | 16 | 42 | 38 | |||||||||||||||
Total | $ | 2,012 | $ | 1,630 | $ | 1,309 | $ | 1,366 | $ | 1,335 | ||||||||||
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(cents/kWh)
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Coal | 2.02 | 1.65 | 1.48 | 1.43 | 1.39 | |||||||||||||||
Natural gas and fuel oil | 10.65 | 11.44 | 9.01 | 7.61 | 4.65 | |||||||||||||||
Nuclear | 0.38 | 0.39 | 0.39 | 0.39 | 0.41 | |||||||||||||||
Aggregate fuel cost per kWh net thermal generation | 1.54 | 1.30 | 1.14 | 1.14 | 1.11 |
• | 37 percent from the Illinois Basin; | ||
• | 25 percent from the Powder River Basin in Wyoming; | ||
• | 19 percent from the Uinta Basin of Utah and Colorado; and | ||
• | 19 percent from the Appalachian Basin of Kentucky, Pennsylvania, Tennessee, Virginia, and West Virginia. |
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• | Approximately 17,000 circuit miles of transmission lines, including 2,400 miles of extra-high-voltage (500,000 volt) transmission lines; | ||
• | 537 substations, power switchyards, and switching stations; | ||
• | 1,045 individual interchange and customer connection points; and | ||
• | 260,000 right-of-way acres. |
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• | Simultaneous repeal, on the effective date of the restructuring legislation, of the fence and the anti-cherrypicking provision, | ||
• | A distributor customer option to gradually take up to a maximum of 30 percent of its power requirements from other suppliers with advance notice to TVA, | ||
• | New limitations on TVA retail sales in TVA’s current service area, | ||
• | Stranded cost recovery through 2007, | ||
• | FERC regulation to ensure that TVA charges others transmission service rates and imposes on others terms and conditions of service comparable to those TVA charges and imposes on itself, | ||
• | TVA to be subject to antitrust laws (with the exception of monetary damages and attorney’s fees), | ||
• | At individual distributor customer election, a reduction in TVA’s existing regulation of distributor customers, and | ||
• | New TVA generation to be limited to that needed to meet demand within the current TVA service area. |
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(in millions)
2006 | 2005 | 2004 | ||||||||||
Alabama | $ | 93 | $ | 89 | $ | 81 | ||||||
Georgia | 6 | 6 | 5 | |||||||||
Illinois | <1 | <1 | <1 | |||||||||
Kentucky | 33 | 30 | 27 | |||||||||
Mississippi | 20 | 20 | 19 | |||||||||
North Carolina | 2 | 2 | 2 | |||||||||
Tennessee | 221 | 218 | 203 | |||||||||
Virginia | <1 | <1 | <1 | |||||||||
$ | 376 | $ | 365 | $ | 338 | |||||||
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• | TVA could lose its protected service territory. |
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TVA’s service area is primarily defined by two provisions of law. |
– | The TVA Act provides that, subject to certain minor exceptions, neither TVA nor its distributor customers may be a source of power supply outside of TVA’s defined service area. This provision is often called the “fence” since it limits TVA’s sales activities to a specified service area. | ||
– | The Federal Power Act prevents FERC from ordering TVA to provide access to its transmission lines for the purpose of delivering power to customers within TVA’s defined service area. This provision is often called the “anti-cherrypicking provision” since it prevents competitors from “cherrypicking” TVA’s customers. |
• | The TVA Board could lose its sole authority to set rates for electricity. |
– | TVA might be unable to set rates at a level sufficient to generate adequate revenues to service its financial obligations, properly operate and maintain its power assets, and provide for reinvestment in its power program; and | ||
– | TVA might be subject to additional regulatory oversight that could impede TVA’s ability to manage its business. | ||
• | TVA could become subject to increased environmental regulation. |
• | TVA could become subject to increased regulation by the NRC. |
• | TVA could lose responsibility for managing the Tennessee River system. |
• | Congress could take actions that lead to a downgrade of TVA’s credit rating. |
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• | TVA’s debt ceiling could become more restrictive. |
• | Might have to invest a significant amount of resources to repair or replace the assets; | ||
• | Might be unable to operate the assets for a significant period of time; | ||
• | Might have to purchase replacement power on the open market; | ||
• | Might not be able to meet its contractual obligations to deliver power; and | ||
• | Might have to remediate collateral damage caused by a failure of the assets. |
• | Compliance with existing environmental laws and regulations may cost TVA more than it anticipates. | ||
• | At some of TVA’s older facilities, it may be uneconomical for TVA to install the necessary equipment to comply with existing environmental laws, which may cause TVA to shut down those facilities. | ||
• | TVA may be responsible for on-site liabilities associated with the environmental condition of facilities that it has acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. |
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• | TVA may be unable to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals or if TVA fails to obtain, maintain, or comply with any such approval, TVA may be unable to operate its facilities or may have to pay fines or penalties. |
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• | Commodity Price Risk.Prices of commodities critical to TVA’s operations, including coal, uranium, natural gas, fuel oil, emission allowances, and electricity, have been extremely volatile in recent years. If TVA fails to effectively manage its commodity price risk, customers may look for alternative power suppliers. | ||
• | Investment Price Risk.TVA is exposed to investment price risk in both its nuclear decommissioning trust and its pension fund. If the value of the investments held in the nuclear decommissioning trust or the pension fund decreases significantly, TVA could be required to make substantial unplanned contributions to these funds, which would negatively affect TVA’s cash flows, results of operations, and financial condition. | ||
• | Interest Rate Risk.Changes in interest rates could negatively affect TVA’s cash flows, results of operations, and financial condition by increasing the amount of interest that TVA pays on new Bonds that it issues, decreasing the return that TVA receives on its short-term investments, decreasing the value of the investments in TVA’s pension fund and nuclear decommissioning trust, and increasing the losses on the mark-to-market valuation of certain derivative transactions into which TVA has entered. | ||
• | Credit Risk.TVA is exposed to the risk that its counterparties will not be able to perform their contractual obligations. If TVA’s counterparties fail to perform their obligations, TVA’s cash flows, results of operations, and financial condition could be adversely affected. In addition, the failure of a counterparty to perform could make it difficult for TVA to perform its obligations, particularly if the counterparty is a supplier of electricity or fuel to TVA. |
• | A downgrade would increase TVA’s interest expense by increasing the interest rates that TVA pays on new debt securities that it issues. An increase in TVA’s interest expense would reduce the amount of cash available for other purposes, which could result in the need to increase borrowings, to reduce other expenses or capital investments, or to increase electricity rates. |
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• | A significant downgrade could result in TVA’s having to post collateral under certain physical and financial contracts that contain rating triggers. | ||
• | A downgrade below a contractual threshold would prevent TVA from borrowing under two credit facilities totaling $2.5 billion without the consent of the national bank that is the counterparty to the credit facilities. | ||
• | A downgrade could lower the price of TVA securities in the secondary market, thereby hurting investors who sell TVA securities after the downgrade and diminishing the attractiveness and marketability of TVA Bonds. |
• | Provisions of the pension and postretirement benefit plans; | ||
• | Changing employee demographics; | ||
• | Rates of increase in compensation levels; | ||
• | Rates of return on plan assets; | ||
• | Discount rates used in determining future benefit obligations; | ||
• | Rates of increase in health care costs; | ||
• | Levels of interest rates used to measure the required minimum funding levels of the plans; | ||
• | Future government regulation; and | ||
• | Contributions made to the plans. |
• | The value of the investments in the trust declines significantly; | ||
• | The laws or regulations regarding nuclear decommissioning change the decommissioning funding requirements; | ||
• | The assumed rate of return on plan assets, which is currently five percent, has been approved by the TVA Board; | ||
• | Changes in technology and experience related to decommissioning cause decommissioning cost estimates to increase significantly; or | ||
• | TVA is required to decommission a nuclear plant sooner than TVA anticipates. |
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• | Approximately 17,000 circuit miles of transmission lines, including 2,400 miles of extra-high-voltage (500,000 volt) transmission lines; | ||
• | 537 substations, power switchyards, and switching stations; | ||
• | 1,045 individual interchange and customer connection points; and | ||
• | 260,000 right-of-way acres. |
• | 11,000 miles of reservoir shoreline; | ||
• | 293,000 acres of reservoir land; | ||
• | 650,000 surface acres of water; and | ||
• | Over 100 public recreation areas. |
• | Under Section 31 of the TVA Act, TVA has authority to dispose of surplus real property at a public auction. | ||
• | Under Section 4(k) of the TVA Act, TVA can dispose of real property for certain specified purposes, including to provide replacement lands for certain entities whose lands were flooded or destroyed by dam or reservoir construction and to grant easements and rights-of-way upon which are located transmission or distribution lines. | ||
• | Under Section 15d(g) of the TVA Act, TVA can dispose of real property in connection with the construction of generating plants or other facilities under certain circumstances. | ||
• | Under 40 U.S.C. § 1314, TVA has authority to grant easements for rights-of-way or other purposes. |
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(in millions)
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Operating revenues | $ | 9,185 | $ | 7,794 | $ | 7,533 | $ | 6,953 | $ | 6,798 | ||||||||||
Operating expenses | (7,582 | )1 | (6,503 | )1 | (5,873 | )2 | (5,398 | ) | (5,323 | )3 | ||||||||||
Operating income | 1,603 | 1,291 | 1,660 | 1,555 | 1,475 | |||||||||||||||
Other income, net 4 | 65 | 52 | 43 | 32 | 19 | |||||||||||||||
Unrealized (loss)/gain on derivative contracts, net | (15 | ) | 3 | (7 | ) | (7 | ) | – | ||||||||||||
Interest expense, net4 | (1,215 | ) | (1,261 | ) | (1,310 | ) | (1,353 | ) | (1,431 | ) | ||||||||||
Cumulative effect of accounting changes | (109 | )5 | – | – | 217 | 6 | – | |||||||||||||
Total net income | $ | 329 | $ | 85 | $ | 386 | $ | 444 | $ | 63 | ||||||||||
Notes | ||
(1) | During 2006 and 2005, TVA recognized a total of $9 million and $24 million, respectively, in impairment losses related to its property, plant, and equipment. The losses included a $2 million and an $8 million write-down in 2006 and 2005, respectively, on one of two buildings in TVA’s Knoxville Office Complex based on TVA’s plans to sell or lease the East Tower of the Knoxville Office Complex. TVA also recognized a $7 million and a $16 million write-down in 2006 and 2005, respectively, of certainConstruction in Progress assets related to new pollution-control and other technologies that had not been proven effective and a re-evaluation of other projects due to funding limitations. | |
(2) | During 2004, TVA was notified by a supplier that it would not proceed with manufacturing of fuel cells to be installed in the partially completed Regenesys energy storage plant in Columbus, Mississippi. Accordingly, TVA recognized a net $20 million loss on the cancellation of the Regenesys project. See Note 1 —Project Cancellation. | |
(3) | Due to changes in the market forecast, TVA elected not to complete a gas-fired combined cycle plant in 2002. TVA recognized a $154 million loss related to the cancellation of this project. | |
(4) | Prior to 2006, TVA reported short-term investment interest income with interest expense. Interest income of $19 million, $6 million, $3 million, and $2 million for 2005, 2004, 2003, and 2002, respectively, has been reclassified fromInterest expense, net toOther Income. | |
(5) | During 2006, TVA adopted FIN No. 47, “Accounting for Conditional Asset Retirement Obligations – an interpretation of FASB Statement No. 143,” which resulted in a cumulative effect charge to income of $109 million and an increase in accumulated depreciation of $20 million. See Note 1 —Impact of New Accounting Standards and Interpretations. | |
(6) | The cumulative effects of $217 million are due to two accounting changes. Effective October 1, 2002, the TVA Board approved a change in the methodology for estimating unbilled revenue from electricity sales. The impact of this change resulted in an increase in accounts receivable of $412 million with a cumulative effect gain for the change in accounting for unbilled revenue. In addition, TVA adopted SFAS No. 143,“Accounting for Asset Retirement Obligations,”which resulted in a cumulative effect charge to income of $195 million and an increase in accumulated depreciation of $206 million. See Note 1 —Impact of New Accounting Standards and Interpretations. |
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(in millions)
2006 | 2005 | 2004 | 20031 | 2002 1 | ||||||||||||||||
Assets | �� | |||||||||||||||||||
Current assets2 | $ | 2,669 | $ | 2,176 | $ | 2,295 | $ | 2,238 | $ | 1,626 | ||||||||||
Property, plant, and equipment, net | 24,434 | 23,888 | 23,699 | 23,125 | 22,175 | |||||||||||||||
Investment funds | 972 | 858 | 744 | 638 | 510 | |||||||||||||||
Regulatory and other long-term assets | 6,445 | 7,551 | 7,451 | 7,027 | 6,522 | |||||||||||||||
Total assets | $ | 34,520 | $ | 34,473 | $ | 34,189 | $ | 33,028 | $ | 30,833 | ||||||||||
Liabilities and proprietary capital | ||||||||||||||||||||
Current liabilities2 | $ | 5,203 | $ | 6,724 | $ | 5,420 | $ | 5,8193 | $ | 4,755 | ||||||||||
Regulatory and other liabilities | 7,074 | 7,606 | 7,168 | 5,114 | 3,304 | |||||||||||||||
Long-term debt, net of discount | 19,544 | 17,751 | 19,337 | 20,201 | 21,358 | |||||||||||||||
Total liabilities | 31,821 | 32,081 | 31,925 | 31,134 | 29,417 | |||||||||||||||
Retained earnings | 1,565 | 1,244 | 1,162 | 783 | 349 | |||||||||||||||
Other proprietary capital | 1,134 | 1,148 | 1,102 | 1,111 | 1,067 | |||||||||||||||
Total proprietary capital | 2,699 | 2,392 | 2,264 | 1,894 | 1,416 | |||||||||||||||
Total liabilities and proprietary capital | $ | 34,520 | $ | 34,473 | $ | 34,189 | $ | 33,028 | $ | 30,833 | ||||||||||
Notes | ||
(1) | Prior to 2004, TVA presented 2 balance sheets – one for its power program and one for all programs. The 2003 and 2002 Balance Sheets presented above are for all programs which is consistent with the presentation for 2004, 2005, and 2006. | |
(2) | In 2006, TVA began to apply certain customer advances previously reported asCurrent liabilities as a reduction toAccounts receivable. The advances were $93 million in 2005, $91 million in 2004, $83 million in 2003, and $56 million in 2002 and reduced bothCurrent assets andCurrent liabilities by the same amount. | |
(3) | TVA reclassified $5 million related to discounted energy units from a long-term liability to a short-term liability in 2003. |
(in millions)
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Long-term debt, including current maturities | $ | 20,529 | $ | 20,444 | $ | 21,337 | $ | 22,537 | $ | 21,358 | ||||||||||
Other long-term obligations | ||||||||||||||||||||
Capital leases * | 128 | 150 | 138 | 151 | 162 | |||||||||||||||
Lease/leaseback commitments | 1,108 | 1,143 | 1,178 | 1,238 | 561 | |||||||||||||||
Energy prepayment obligations | 1,244 | 1,350 | 1,455 | 47 | – | |||||||||||||||
Total other financing obligations | 2,480 | 2,643 | 2,771 | 1,436 | 723 | |||||||||||||||
Discount notes | 2,376 | 2,469 | 1,924 | 2,080 | 3,492 | |||||||||||||||
Financial obligations | $ | 25,385 | $ | 25,556 | $ | 26,032 | $ | 26,053 | $ | 25,573 | ||||||||||
Note | ||
* | Included inNuclear fuel andCapital leases on the Balance Sheets. |
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For the years ended September 30
(in millions)
2006 | ||||
Net change in cash and cash equivalents | $ | (2 | ) | |
Energy prepayment | 105 | |||
Net cash (used in) provided by financing activities | 289 | |||
Total | $ | 392 | ||
As of September 30
(in millions)
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Financial Obligations | $ | 25,385 | $ | 25,556 | $ | 26,032 | $ | 26,053 | $ | 25,573 | ||||||||||
Less foreign currency valuations | (195 | ) | (52 | ) | (113 | ) | 35 | 220 | ||||||||||||
Plus discount on bonds | 178 | 227 | 102 | 223 | 185 | |||||||||||||||
Capital leases | (128 | ) | (150 | ) | (138 | ) | (151 | ) | (162 | ) | ||||||||||
Total | $ | 25,240 | $ | 25,581 | $ | 25,883 | $ | 26,160 | $ | 25,816 | ||||||||||
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For the years ended, or as of, September 30, as appropriate
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Sales of electricity(millions of kWh)1 | ||||||||||||||||||||
Municipalities and cooperatives | 143,343 | 136,640 | 133,161 | 130,769 | 128,600 | |||||||||||||||
Industries directly served | 30,987 | 30,872 | 29,344 | 27,756 | 26,478 | |||||||||||||||
Federal agencies and other | 2,040 | 3,986 | 3,353 | 3,009 | 3,579 | |||||||||||||||
Total sales | 176,370 | 171,498 | 165,858 | 161,534 | 158,657 | |||||||||||||||
Operating revenues(millions of dollars) 1 | ||||||||||||||||||||
Electric | ||||||||||||||||||||
Municipalities and cooperatives | $ | 7,880 | $ | 6,561 | $ | 6,457 | $ | 5,974 | $ | 5,856 | ||||||||||
Industries directly served | 1,066 | 962 | 842 | 781 | 732 | |||||||||||||||
Federal agencies and other | 116 | 181 | 140 | 120 | 120 | |||||||||||||||
Other | 123 | 90 | 94 | 78 | 90 | |||||||||||||||
Total revenues | $ | 9,185 | $ | 7,794 | $ | 7,533 | $ | 6,953 | $ | 6,798 | ||||||||||
Electric revenue per kWh (cents) | 5.14 | 4.49 | 4.49 | 4.26 | 4.23 | |||||||||||||||
Winter net dependable generating capacity (megawatts)2 | ||||||||||||||||||||
Coal-fired | 15,081 | 15,075 | 15,076 | 15,029 | 15,023 | |||||||||||||||
Nuclear units in service | 5,770 | 5,790 | 5,777 | 5,776 | 5,751 | |||||||||||||||
Hydroelectric | 5,144 | 5,104 | 4,981 | 5,022 | 4,924 | |||||||||||||||
Combustion turbine 3 and other 4 | 4,681 | 4,675 | 4,685 | 4,655 | 4,643 | |||||||||||||||
TVA facilities | 30,676 | 30,644 | 30,519 | 30,482 | 30,341 | |||||||||||||||
Power purchase agreements | 4,275 | 3,337 | 2,670 | 1,176 | 1,176 | |||||||||||||||
Total available capacity5 | 34,951 | 33,981 | 33,189 | 31,658 | 31,517 | |||||||||||||||
System peak load (megawatts)—summer | 32,008 | 31,924 | 29,966 | 28,530 | 29,052 | |||||||||||||||
System peak load (megawatts)—winter | 27,718 | 29,278 | 27,997 | 29,866 | 26,061 | |||||||||||||||
Percent gross generation by fuel source | ||||||||||||||||||||
Coal-fired | 64 | % | 62 | % | 61 | % | 60 | % | 63 | % | ||||||||||
Nuclear | 29 | % | 28 | % | 30 | % | 29 | % | 30 | % | ||||||||||
Hydroelectric | 6 | % | 10 | % | 9 | % | 11 | % | 6 | % | ||||||||||
Combustion turbine and other | <1 | % | <1 | % | <1 | % | <1 | % | 1 | % | ||||||||||
Fuel cost per kWh(cents) | ||||||||||||||||||||
Coal | 2.02 | 1.65 | 1.48 | 1.43 | 1.39 | |||||||||||||||
Natural gas and fuel oil | 10.65 | 11.44 | 9.01 | 7.61 | 4.65 | |||||||||||||||
Nuclear | 0.38 | 0.39 | 0.39 | 0.39 | 0.41 | |||||||||||||||
Aggregate fuel cost per kWh net thermal generation | 1.54 | 1.30 | 1.14 | 1.14 | 1.11 |
Notes | ||
(1) | Sales and revenues have been adjusted to include sales to other utilities and to exclude interdivisional sales. | |
(2) | See Item I, Business— Power Supply. | |
(3) | As of September 30, 2006, includes twenty-four 85-megawatt combustion turbine units subject to lease/leaseback arrangements. | |
(4) | See Item I, Business— Power Supplyfor a discussion of TVA’s diesel generators and renewable resources. | |
(5) | Total summer net dependable capacity at September 30, 2006, 2005, 2004, 2003, and 2002 was approximately 33,653 megawatts, 32,259 megawatts, 32,059 megawatts, 30,743 megawatts, and 30,477 megawatts, respectively. |
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Category | Performance Indicator | Description of Performance Indicator | ||
Financial | Delivered Cost of Power Excluding FCA * Costs | Measures the cost per megawatt-hour of power sold to customers excluding costs covered by the FCA | ||
Financial | FCA Costs | Measures costs covered by the FCA per megawatt-hour of power sold | ||
Financial | Productivity | Measures total TVA labor costs and contract labor costs | ||
Customer | Connection Point Interruptions | Measure interruptions of power caused by TVA’s transmission system | ||
Customer | Customer Satisfaction Survey | Measures the satisfaction of TVA’s customers with TVA in a variety of areas | ||
Customer | Economic Development | Measures job growth, the quality of jobs, and capital invested by economic development partners in the TVA service area | ||
Operations | Equivalent Availability Factor | Measures availability of generation | ||
Operations | Environmental Impact | Measures 23 environmental elements to assess the impact of TVA’s operations on air quality, water quality, land, waste production, and energy consumption | ||
People | Safe Workplace | Measures recordable injuries per hours worked |
Note | ||
* | FCA – Fuel Cost Adjustment |
• | On May 30, 2006, operators at Unit 1 of Watts Bar Nuclear Plant (“Watts Bar”) detected a problem involving the main turbine and took the reactor offline safely without further incident. The low-pressure turbine from Unit 2 at Watts Bar, which has never been put in service, was modified and used to repair the damaged turbine. The unit returned to service on June 25, 2006. Watts Bar Unit 1 was taken offline again on July 31, 2006, when the main generator shut down, and it returned to full power operation on August 4, 2006. Watts Bar Unit 1 has a net winter dependable capacity of approximately 1,168 megawatts. | ||
• | Bull Run Fossil Plant (“Bull Run”), which has a winter net dependable capacity of approximately 889 megawatts, was taken offline on July 25, 2006, due to a broken turbine stub shaft. The plant returned to service on August 5, 2006, following replacement of the stub shaft and associated repairs and inspection. |
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For the years ended September 30
2006 | 2005 | 2004 | ||||||||||
Cash provided by (used in): | ||||||||||||
Operating activities | $ | 2,014 | $ | 1,462 | $ | 3,290 | ||||||
Investing activities | (1,727 | ) | (1,188 | ) | (1,718 | ) | ||||||
Financing activities | (289 | ) | (255 | ) | (1,586 | ) | ||||||
Net (decrease) increase in cash and cash equivalents | $ | (2 | ) | $ | 19 | $ | (14 | ) | ||||
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• | In 2002, TVA monetized the call provisions on a $1 billion Bond issue by entering into a swaption agreement with a third party in exchange for $175 million. | ||
• | In 2003, TVA monetized the call provisions on a second Bond issue of $476 million by entering into a swaption agreement with a third party in exchange for $81 million. | ||
• | In 2005, TVA monetized the call provisions on two Bond issues ($42 million total par value) by entering into swaption agreements with a third party in exchange for $5 million. |
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• | An increase in cash provided by operating revenues of $1.4 billion resulting primarily due to higher average rates from rate actions effective in October 2005 and April 2006 and, to a lesser extent, by increased demand in 2006; | ||
• | Less cash paid for interest of $46 million in 2006; and | ||
• | A decrease in expenditures for nuclear refueling outages of $50 million due to the number and timing of outages during 2006. |
• | An increase in cash paid for fuel and purchased power of $734 million due to higher volume and increased market prices; | ||
• | An increase in payments in lieu of taxes of $11 million; | ||
• | An increase in cash outlays for routine and recurring operating costs of $44 million; and | ||
• | An increase in other deferred items of $55 million primarily due to $22 million of increased contributions to the TVA Retirement System and $15 million related to customer advances for construction. |
• | A larger increase in accounts receivable of $195 million due to increased sales of the prior year and higher rates in 2006; and | ||
• | A larger increase in inventories of $108 million due to higher priced coal and natural gas in ending inventory in 2006 and a higher volume of coal on hand at the end of 2006. |
• | A $125 million increase in accounts payable and accrued liabilities in 2006 compared to a $16 million decrease in 2005 primarily due to changes in the amount of collateral held by TVA of $88 million under terms of a swap agreement and higher costs for fuel and purchased power; and | ||
• | A $23 million increase in accrued interest in 2006 compared to a $22 million increase in 2005 due to timing of interest payments on Bonds issued relative to Bonds retired during 2006. |
• | Sales of short-term investments of $335 million in 2005 with no comparable sales in 2006; | ||
• | An increase in expenditures for the enrichment and fabrication of nuclear fuel of $136 million for the Sequoyah Unit 2 and Watts Bar Unit 1 reloads scheduled to be completed in the first quarter of 2007, and expenditures related to uranium, conversion, and enrichment for Browns Ferry Unit 1; | ||
• | An increase in expenditures for capital projects of $60 million was primarily due to increases in transmission construction projects related to reliability and load growth on the TVA system, including a substation and a 500-kv transmission line on the bulk transmission system, an increase in expenditures for nuclear projects of $17 million primarily for the Browns Ferry Unit 1 restart, and a corresponding increase in allowance for funds used during construction of $35 million; partially offset by decreases in clean air expenditures of $20 million related to project completions and a decrease in hydro expenditures of $26 million; and | ||
• | A decrease in proceeds received from the sale of certain receivables/loans of $45 million compared to the same period of 2005. |
• | A damage award in 2006 of $35 million in TVA’s breach of contract suit against the DOE; and |
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• | A smaller increase in collateral deposits in 2006 of $16 million as compared to 2005. See Note 1 —Summary of Significant Accounting Policies — Restricted Cash and Investments. |
• | A decrease in issuance of long-term debt of $518 million; | ||
• | Net issuances of short-term debt of $546 million in 2005 compared to net redemptions of short-term debt of $93 million in 2006; and | ||
• | An increase in payments to the U.S. Treasury of $2 million due to changes in interest rates. |
• | A decrease in redemptions of long-term debt of $1.1 billion in 2006 compared to 2005. |
• | Proceeds of $1.5 billion received in 2004 for energy prepayments with no comparable prepayment in 2005; | ||
• | Increased cash paid for fuel and purchased power of $521 million due to higher volume and increased market prices; | ||
• | An increase in expenditures for nuclear refueling outages of $36 million due to the number and timing of outages; | ||
• | An increase in other deferred items of $28 million primarily due to increased contributions to the TVA Retirement System; | ||
• | An increase in payments in lieu of taxes of $27 million; and | ||
• | Decreased cash provided from net income components of $199 million. |
• | An increase in cash provided by operating revenues of $251 million resulting primarily from increased sales volume; | ||
• | A decrease in cash outlays for interest of $47 million; and | ||
• | A decrease in cash outlays for operating and maintenance costs of $38 million primarily due to $33 million in severance and restructuring costs that were recognized in 2004. |
• | An increase in accounts receivable of $69 million in 2005 due to increased sales volume during the summer months of 2005; | ||
• | A larger payment of accrued interest of $17 million in 2005 than in 2004 due to the timing of interest payments on Bonds issued relative to Bonds retired; and | ||
• | An increase in inventories and other of $12 million in 2005 compared to a decrease in inventories and other of $10 million in 2004 primarily due to purchases of emission allowances and prepayment of insurance premiums for new programs in 2005. |
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• | Maturity of short-term investments of $335 million in 2005 compared to an increase in short-term investments of $68 million in 2004; | ||
• | A decrease in expenditures for capital projects of $213 million primarily due to decreases in clean air expenditures of $210 million partially offset by increases in expenditures for the Browns Ferry Unit 1 restart; | ||
• | Proceeds received in 2005 from the sale of certain power distributor customer loans receivable of $55 million (see Note 1 —Sale of Receivables/Loans); and | ||
• | Cash provided by net collections on loans and long-term receivables of $6 million in 2005 compared to $5 million in 2004, and net proceeds from investment activity of $1 million. |
• | An increase in expenditures for the enrichment and fabrication of nuclear fuel of $22 million as four nuclear units completed refueling outages in 2005; | ||
• | A payment of $15 million in 2004 from Regenesys Technologies Limited in connection with cancellation of the Regenesys project due to inability of manufacturer to supply materials; and | ||
• | An increase in restricted cash of $107 million resulting from collateral deposits in 2005 (see Note 1 —Restricted Cash and Investments). |
• | An increase in issuances of long-term debt of $878 million in 2005; | ||
• | Net issuances of short-term debt of $546 million in 2005 compared to net redemptions of short-term debt of $157 million in 2004; | ||
• | A decrease in payments to the U.S. Treasury of $2 million due to lower interest rates in 2005; and | ||
• | A decrease in lease payments of $26 million in 2005. |
• | An increase in redemptions of long-term debt of $117 million primarily due to the refinancing of callable debt at lower interest rates; | ||
• | A decrease in bond premium received of $97 million in 2005; | ||
• | A decrease in swap receivable monetization of $55 million in 2005; and | ||
• | An increase in net financing costs of $14 million in 2005 related to Bond transactions. |
As of September 30
Actual | Estimated Construction Expenditures | |||||||||||||||||||||||
2006 | 2007 | 2008 | 2009 | 2010 | 2011 | |||||||||||||||||||
Browns Ferry Unit 1 Restart | $ | 428 | $ | 76 | $ | – | $ | – | $ | – | $ | – | ||||||||||||
Clean Air Expenditures | 182 | 286 | 357 | 306 | 290 | 368 | ||||||||||||||||||
Transmission Expenditures2 | 232 | 203 | 231 | 319 | 312 | 278 | ||||||||||||||||||
Other Capital Expenditures3 | 406 | 487 | 611 | 510 | 560 | 534 | ||||||||||||||||||
Total Capital Projects Requirements 4 | $ | 1,248 | $ | 1,052 | $ | 1,199 | $ | 1,135 | $ | 1,162 | $ | 1,180 | ||||||||||||
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Notes | ||
(1) | This table shows only expenditures that are currently planned. TVA is updating its strategic plan. When completed, the strategic plan could indicate that it is desirable for TVA to acquire additional generation rather than depend on market purchases. Such new generation could require significant capital expenditures in order to meet the needs of TVA’s service area. The table does not include any projects to provide additional generation which may be identified in the strategic planning process. | |
(2) | Transmission Expenditures include reimbursable projects. | |
(3) | Other Capital Expenditures are primarily associated with short lead time construction expenditure projects aimed at the continued safe and reliable operation of generating assets. | |
(4) | Actual 2006 capital projects requirements excludes allowance for funds used during construction of $151 million. |
Payments Due in the Year Ending September 30
Total | 2007 | 2008 | 2009 | 2010 | 2011 | Thereafter | ||||||||||||||||||||||
Debt | $ | 22,888 | * | $ | 3,361 | $ | 90 | $ | 2,030 | $ | 63 | $ | 1,015 | $ | 16,329 | |||||||||||||
Interest payments relating to debt | 21,555 | 1,188 | 1,152 | 1,096 | 1,042 | 1,011 | 16,066 | |||||||||||||||||||||
Leases | ||||||||||||||||||||||||||||
Non-cancelable operating | 135 | 45 | 41 | 26 | 12 | 4 | 7 | |||||||||||||||||||||
Capital | 272 | 63 | 59 | 57 | 57 | 30 | 6 | |||||||||||||||||||||
Power purchase obligations | 4,354 | 205 | 146 | 148 | 152 | 154 | 3,549 | |||||||||||||||||||||
Purchase obligations | ||||||||||||||||||||||||||||
Fuel purchase obligations | 3,015 | 1,083 | 509 | 496 | 400 | 249 | 278 | |||||||||||||||||||||
Other obligations | 327 | 199 | 111 | 5 | 3 | 2 | 7 | |||||||||||||||||||||
Payments on other financings | 1,557 | 85 | 89 | 85 | 89 | 95 | 1,114 | |||||||||||||||||||||
Payment to U.S. Treasury | 432 | 40 | 43 | 42 | 41 | 40 | 226 | |||||||||||||||||||||
Retirement plans | 90 | 90 | – | – | – | – | – | |||||||||||||||||||||
Total | $ | 54,625 | $ | 6,359 | $ | 2,240 | $ | 3,985 | $ | 1,859 | $ | 2,600 | $ | 37,582 | ||||||||||||||
Note | ||
* | Does not include noncash items of foreign currency valuation loss of $195 million and net discount on sale of bonds of $178 million. |
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Payments Due in the Year Ending September 30
Total | 2007 | 2008 | 2009 | 2010 | 2011 | Thereafter | |||||||||||||||||||||||||
Energy Prepayment Obligations | $ | 1,244 | $ | 106 | $ | 106 | $ | 105 | $ | 105 | $ | 105 | $ | 717 | |||||||||||||||||
For the years ended September 30
2006 | 2005 | 2004 | ||||||||||
Operating revenues | $ | 9,185 | $ | 7,794 | $ | 7,533 | ||||||
Operating expenses | (7,582 | ) | (6,503 | ) | (5,873 | ) | ||||||
Operating income | 1,603 | 1,291 | 1,660 | |||||||||
Other income | 67 | 56 | 44 | |||||||||
Other expense | (2 | ) | (4 | ) | (1 | ) | ||||||
Unrealized (loss)/gain on derivative contracts, net | (15 | ) | 3 | (7 | ) | |||||||
Interest expense, net | (1,215 | ) | (1,261 | ) | (1,310 | ) | ||||||
Income before cumulative effects of accounting changes | 438 | 85 | 386 | |||||||||
Cumulative effect of change in accounting for conditional asset retirement obligations | (109 | ) | – | – | ||||||||
Net income | $ | 329 | $ | 85 | $ | 386 | ||||||
Sales (millions of kWh) | 176,370 | 171,498 | 165,858 |
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For the years ended September 30
Sales of Electricity | Operating Revenues | |||||||||||||||||||||||
(millions of kWh) | (millions of dollars) | |||||||||||||||||||||||
Percent | Percent | |||||||||||||||||||||||
2006 | 2005 | Change | 2006 | 2005 | Change | |||||||||||||||||||
Sales of electricity and operating revenues | ||||||||||||||||||||||||
Municipalities and cooperatives | 143,343 | 136,640 | 4.9 | % | $ | 7,880 | $ | 6,561 | 20.1 | % | ||||||||||||||
Industries directly served | 30,987 | 30,872 | 0.4 | % | 1,066 | 962 | 10.8 | % | ||||||||||||||||
Federal agencies and other | 2,040 | 3,986 | (48.8 | %) | 116 | 181 | (35.9 | %) | ||||||||||||||||
Other revenue | — | — | — | 123 | 90 | 36.7 | % | |||||||||||||||||
Total sales of electricity and operating revenues | 176,370 | 171,498 | 2.8 | % | $ | 9,185 | $ | 7,794 | 17.8 | % | ||||||||||||||
• | A $1,319 million increase in revenue from municipalities and cooperatives reflecting increased sales of 4.9 percent and average rates rising 14.5 percent of which $822 million relates to the rate adjustments effective October 1, 2005, and April 1, 2006; | ||
• | A $104 million increase in revenue from industries attributable to sales increasing 0.4 percent and average rates rising 10.4 percent of which $41 million relates to the rate adjustments effective October 1, 2005, and April 1, 2006; and | ||
• | A $33 million increase in other revenue primarily due to increased transmission revenues from wheeling activity. |
• | An $82 million decrease in exchange power sales reflecting decreased sales of 90.3 percent and reduced generation of 2.7 percent which includes a 36.6 percent decrease in hydroelectric generation resulting from dry conditions in 2006; offset by | ||
• | A $17 million increase in revenues from federal agencies directly served due to increased sales of 4.9 percent and average rates rising 14.3 percent of which $10 million relate to the rate adjustments effective October 1, 2005, and April 1, 2006. |
• | A 6,703 million kilowatt-hour increase in sales to municipalities and cooperatives attributable to 4,707 million kilowatt-hours related to the unbilled estimate methodology used in 2005 (see Note 1 —Accounts Receivable) and a 1,996 kilowatt-hour increase in sales demand by municipalities and cooperatives during 2006; | ||
• | A 115 million kilowatt-hour increase in sales to directly served industries as a result of increased firm and Firm Power Interruptible demand of 48.3 percent and 93.6 percent, respectively, offset by decreased Economy Surplus Power/Variable Priced Interruptible and Preferred Interruptible Power/Firm Power Interruptible demand of 29.2 percent and 32.3 percent respectively; and | ||
• | An 85 million kilowatt-hour increase in sales to federal agencies primarily due to increased demand of 34.5 percent for other miscellaneous products. |
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For the years ended September 30
Percent | ||||||||||||
2006 | 2005 | Change | ||||||||||
Operating expenses | ||||||||||||
Fuel and purchased power | $ | 3,333 | $ | 2,601 | 28.1 | % | ||||||
Operating and maintenance | 2,372 | 2,359 | <1 | % | ||||||||
Depreciation, amortization and accretion | 1,492 | 1,154 | 29.3 | % | ||||||||
Payments in lieu of taxes | 376 | 365 | 3.0 | % | ||||||||
Loss on asset impairment/project cancellation | 9 | 24 | (62.5 | %) | ||||||||
Total operating expenses | $ | 7,582 | $ | 6,503 | 16.6 | % | ||||||
• | A $377 million increase in fuel expense attributable to higher aggregate fuel cost per kilowatt-hour net thermal generation of 19.0 percent and increased generation of 1.2 percent, 3.0 percent, and 0.3 percent at the coal-fired, combustion turbine, and nuclear plants, respectively, in part because of lower hydroelectric generation; | ||
• | A $355 million increase in purchased power expense reflecting increased average purchase price of 16.3 percent and higher volume acquired of 27.7 percent to accommodate for decreased hydroelectric generation and for slightly lower asset availability in 2006 than planned; and | ||
• | An $11 million increase in payments in lieu of taxes due to increased gross revenues of 3.1 percent from the sale of power (excluding sales or deliveries to other federal agencies and exchange sales with other utilities) during 2005 as compared to 2004. See Item 1, Business —Payments in Lieu of Taxes. |
• | A $45 million net gain on the mark-to-market valuation adjustment of an interest rate swap contract; | ||
• | A $108 million net gain on the mark-to-market valuation adjustment of swaption contracts; and | ||
• | A $6 million unrealized net loss related to the mark-to-market valuation of sulfur dioxide emissions allowance call options during the first quarter of 2005 not present in 2006. |
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For the years ended September 30
Percent | ||||||||||||
2006 | 2005 | Change | ||||||||||
Interest expense | ||||||||||||
Interest on debt | $ | 1,357 | $ | 1,356 | (0.0 | %) | ||||||
Amortization of debt discount, issue, and reacquisition costs, net | 21 | 21 | 0.0 | % | ||||||||
Allowance for funds used during construction | (163 | ) | (116 | ) | 40.5 | % | ||||||
Net interest expense | $ | 1,215 | $ | 1,261 | (3.6 | %) | ||||||
(percent) | ||||||||||||
Percent | ||||||||||||
2006 | 2005 | Change | ||||||||||
Interest rates (average) | ||||||||||||
Long-term | 6.17 | 6.25 | (1.3 | %) | ||||||||
Discount notes | 4.47 | 2.70 | 65.6 | % | ||||||||
Blended | 6.02 | 5.93 | 1.5 | % |
• | A decrease in the average long-term interest rate from 6.25 percent in 2005 to 6.17 percent in 2006; | ||
• | A decrease of $407 million in the average balance of long-term outstanding debt in 2006; | ||
• | A decrease of $75 million in the average balance of discount notes outstanding in 2006; and | ||
• | A $47 million increase in AFUDC due to a higher level of construction work-in-progress in 2006. |
For the years ended September 30
Sales of Electricity | Operating Revenues | |||||||||||||||||||||||
(millions of kWh) | (millions of dollars) | |||||||||||||||||||||||
Percent | Percent | |||||||||||||||||||||||
2005 | 2004 | Change | 2005 | 2004 | Change | |||||||||||||||||||
Sales of electricity and operating revenue | ||||||||||||||||||||||||
Municipalities and cooperatives | 136,640 | 133,161 | 2.6 | % | $ | 6,561 | $ | 6,457 | 1.6 | % | ||||||||||||||
Industries directly served | 30,872 | 29,344 | 5.2 | % | 962 | 842 | 14.3 | % | ||||||||||||||||
Federal agencies and other | 3,986 | 3,353 | 18.9 | % | 181 | 140 | 29.3 | % | ||||||||||||||||
Other revenue | — | — | — | 90 | 94 | (4.3 | %) | |||||||||||||||||
Total sales of electricity and operating revenue | 171,498 | 165,858 | 3.4 | % | $ | 7,794 | $ | 7,533 | 3.5 | % | ||||||||||||||
• | A $104 million increase in revenues from municipalities and cooperatives due to increased sales of 2.6 percent although average rates decreased 1.0 percent; |
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• | A $120 million increase in revenues from industries directly served reflecting increased sales of 5.2 percent and average rates rising 8.6 percent; | ||
• | A $5 million increase in revenues from federal agencies directly served as a result of increased sales of 2.0 percent and average rates rising 4.1 percent; and | ||
• | A $36 million increase in revenues from exchange power sales (included inFederal Agencies and Other) attributable to increased total generation of 3.3 percent reflecting favorable market conditions. Favorable market conditions relate to electricity demands both inside and outside the TVA service area in addition to advantageous market rates. |
• | A 3,479 million kilowatt-hour increase in sales to municipalities and cooperatives primarily as a result of increased demand due to warmer summer weather reflecting higher combined degree days of 0.7 percent. During 2005, there were 325, or 18.6 percent, more cooling degree days offset by 291, or 9.0 percent, less heating degree days; | ||
• | A 1,528 million kilowatt-hour increase in sales to industries directly served largely attributable to increased demand of 19.1 percent from one of TVA’s largest industrial consumers of power; | ||
• | A 34 million kilowatt-hour increase in sales to federal agencies directly served as a result of increased demand of 3.4 percent by firm-based customers; and | ||
• | A 599 million kilowatt-hour increase in exchange power sales (included inFederal agencies and other) due to increased total generation of 3.3 percent reflecting favorable market conditions. |
For the years ended September 30
Percent | ||||||||||||
2005 | 2004 | Change | ||||||||||
Operating expenses | ||||||||||||
Fuel and purchased power | $ | 2,601 | $ | 2,081 | 25.0 | % | ||||||
Operating and maintenance | 2,359 | 2,319 | 1.7 | % | ||||||||
Depreciation, amortization, and accretion | 1,154 | 1,115 | 3.5 | % | ||||||||
Payments in lieu of taxes | 365 | 338 | 8.0 | % | ||||||||
Loss on asset impairment/project cancellation | 24 | 20 | 20.0 | % | ||||||||
Total operating expenses | $ | 6,503 | $ | 5,873 | 10.7 | % | ||||||
• | A $269 million increase in fuel expense attributable to higher aggregate fuel cost per kilowatt-hour, net thermal generation of 14.1 percent, increased fuel handling costs of $8 million, and increased generation of 4.0 percent and 114.0 percent at coal-fired and combustion turbine plants, respectively; | ||
• | A $251 million increase in purchased power expense as a result of the average purchase price increasing 43.6 percent and higher volume acquired of 6.2 percent; | ||
• | A $77 million increase in pension and post retirement expense due primarily to increased interest cost coupled with increased amortization of actuarial loss (see Note 12); | ||
• | A $29 million increase in depreciation expense attributable to capital projects placed in service; | ||
• | A $9 million increase in amortization expense related to the amortization of the capital lease recognized for the blended low enriched uranium program (see Note 1 —Blended Low Enriched Uranium Program); and | ||
• | A $24 million impairment loss related to the $16 million write-down of certain assets related to a new technology that had not been proven effective and a $8 million loss equal to the difference in the book value and market price of the East Tower of the Knoxville Office Complex (see Note 1 —Impairment of Assetsand Note 6 —Asset Impairment). |
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• | A $9 million net loss on the mark-to-market valuation adjustment of an interest rate swap contract; | ||
• | A $71 million net loss on the mark-to-market valuation adjustment of swaption contracts; and | ||
• | A $12 million unrealized net loss related to the mark-to-market valuation of sulfur dioxide emission allowance call options. |
For the years ended September 30
Percent | ||||||||||||
2005 | 2004 | Change | ||||||||||
Interest expense | ||||||||||||
Interest on debt | $ | 1,356 | $ | 1,385 | (2.1 | %) | ||||||
Amortization of debt discount, issue, and reacquisition costs, net | 21 | 24 | (12.5 | %) | ||||||||
Allowance for funds used during construction | (116 | ) | (99 | ) | 17.2 | % | ||||||
Net interest expense | $ | 1,261 | $ | 1,310 | (3.7 | %) | ||||||
(percent) | ||||||||||||
Percent | ||||||||||||
2005 | 2004 | Change | ||||||||||
Interest rates (average) | ||||||||||||
Long-term | 6.25 | 6.36 | (1.7 | %) | ||||||||
Discount notes | 2.70 | 1.14 | 136.8 | % | ||||||||
Blended | 5.93 | 6.12 | (3.1 | %) |
• | A decrease in the average long-term interest rate from 6.36 percent to 6.25 percent; | ||
• | A reduction of approximately $1,089 million in the average balance of long-term debt outstanding; and | ||
• | A $17 million increase in AFUDC due to a higher level of construction work-in-progress in 2005. |
• | An increase in the average discount note interest rate from 1.14 percent to 2.70 percent; and | ||
• | An increase of $995 million in the average balance of discount notes outstanding. |
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• | Timing – In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant’s retirement must be estimated. At a multiple unit site, the expiration of the unit with the latest to expire operating license is typically used for this purpose, or an assumption could be made that the plant will be relicensed and operate for some time beyond the original license term. Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in SAFSTOR status — a status authorized by applicable regulations which allows for a nuclear facility to be maintained and monitored in a condition that allows the radioactivity to decay, after which the facility is decommissioned. Afterwards, it is dismantled. While the impact of these assumptions cannot be determined with precision, assuming either license extension or use of SAFSTOR status can significantly decrease the present value of these obligations. | ||
• | Technology and Regulation – Because of the age of the nuclear plants in the United States, there is limited experience with actual decommissioning of large nuclear facilities. Changes in technology and experience as well as changes in regulations regarding nuclear decommissioning could cause cost |
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estimates to change significantly. The impact of these potential changes is not presently determinable. TVA’s cost studies assume current technology and regulations. | |||
• | Discount Rate – TVA’s decommissioning fund uses a blended rate of 5.65 percent to calculate the present value of the weighted estimated cash flows required to satisfy TVA’s decommissioning obligation. | ||
• | Investment Rate of Return – TVA assumes that its decommissioning fund will achieve a rate of return that is five percent greater than the rate of inflation. | ||
• | Cost Escalation Factors – TVA’s decommissioning estimates include an assumption that decommissioning costs will escalate over present cost levels by 4 percent annually. |
• | Interest and discount rates used in determining the future benefit obligations; | ||
• | Projected health care cost trend rates; | ||
• | Expected long-term rate of return on plan assets; and | ||
• | Rate of increase in future compensation levels. |
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Impact on 2006 | ||||||||||||
Change in | Impact on 2007 | Projected Benefit | ||||||||||
Actuarial Assumption | Assumption | Pension Cost | Obligation | |||||||||
(Increase in millions) | ||||||||||||
Discount rate | (0.25 | %) | $ | 18 | $ | 248 | ||||||
Rate of return on plan assets | (0.25 | %) | $ | 16 | NA | |||||||
Rate of compensation | 0.25 | % | $ | 12 | $ | 67 |
Impact on 2006 | ||||||||||||
Impact on 2007 | Projected | |||||||||||
Change in | Postretirement | Postretirement | ||||||||||
Actuarial Assumption | Assumption | Benefit Cost | Benefit Obligation | |||||||||
(Increase in millions) | ||||||||||||
Discount rate | (0.25 | %) | $ | 1 | $ | 14 | ||||||
Health care cost trend | 0.25 | % | $ | 1 | $ | 15 |
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September 30, | ||||||||||||||||
2006 | Average | High | Low | |||||||||||||
Electricity1 | $ | 45 | $ | 75 | $ | 124 | $ | 19 | ||||||||
Natural Gas2 | 34 | 26 | 61 | 3 | ||||||||||||
SO2 Emission Allowances3 | 21 | 20 | 59 | 3 | ||||||||||||
NOx Emission Allowances4 | 1 | 5 | 10 | 1 |
Notes | ||
1 | TVA’s VaR calculations for electricity are based on its on-peak electricity portfolio, which includes electricity forwards and option contracts. | |
2 | TVA’s VaR calculations for natural gas are based on TVA’s natural gas portfolio, which includes natural gas forwards, futures, and options on futures contracts. | |
3 | TVA’s VaR calculations for SO2 emission allowances are based on TVA’s portfolio of SO2 emission allowances. | |
4 | TVA’s VaR calculations for NOx emission allowances are based on TVA’s portfolio of NOx emissions allowances. |
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As of September 30
Trade Accounts Receivable1 | ||||
Municipalities and Cooperative Distributor Customers | ||||
Investment Grade | $ | 845 | ||
Internally Rated — Investment Grade | 433 | |||
Industries and Federal Agencies Directly Served | ||||
Investment Grade | 37 | |||
Non-investment Grade | (1 | ) | ||
Internally Rated — Investment Grade | 4 | |||
Internally Rated — Non-investment Grade | 10 | |||
Exchange Power Arrangements | ||||
Investment Grade | 4 | |||
Non-investment Grade | – | |||
Internally Rated — Investment Grade | 1 | |||
Internally Rated — Non-investment Grade | 1 | |||
Subtotal | 1,334 | |||
Other Accounts Receivable | ||||
Miscellaneous Accounts | 35 | |||
Provision for Uncollectible Accounts | (10 | ) | ||
Subtotal | 25 | |||
Total | $ | 1,359 | ||
(1) | Includes unbilled power receivables of $1,031 million. |
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• | A downgrade would increase TVA’s interest expense by increasing the interest rates that TVA pays on debt securities that it issues. An increase in TVA’s interest expense would reduce the amount of cash available for other purposes, which could result in the need to increase borrowings, to reduce other expenses or capital investments, or to increase electricity rates. | ||
• | A significant downgrade could result in TVA’s having to post collateral under certain physical and financial contracts that contain rating triggers. | ||
• | A downgrade below a contractual threshold would prevent TVA from borrowing under two credit facilities totaling $2.5 billion without the consent of the national bank that is the counterparty to the credit facilities. | ||
• | A downgrade could lower the price of TVA securities in the secondary market, thereby hurting investors who sell TVA securities after the downgrade and diminishing the attractiveness and marketability of TVA Bonds. |
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For the years ended September 30
(in millions)
2006 | 2005 | 2004 | ||||||||||
Operating revenues | ||||||||||||
Sales of electricity | ||||||||||||
Municipalities and cooperatives | $ | 7,880 | $ | 6,561 | $ | 6,457 | ||||||
Industries directly served | 1,066 | 962 | 842 | |||||||||
Federal agencies and other | 116 | 181 | 140 | |||||||||
Other revenue | 123 | 90 | 94 | |||||||||
Total operating revenues | 9,185 | 7,794 | 7,533 | |||||||||
Operating expenses | ||||||||||||
Fuel and purchased power | 3,333 | 2,601 | 2,081 | |||||||||
Operating and maintenance | 2,372 | 2,359 | 2,319 | |||||||||
Depreciation, amortization and accretion (Note 1 and Note 2) | 1,492 | 1,154 | 1,115 | |||||||||
Tax-equivalents | 376 | 365 | 338 | |||||||||
Loss on asset impairment/project cancellation | 9 | 24 | 20 | |||||||||
Total operating expenses | 7,582 | 6,503 | 5,873 | |||||||||
Operating income | 1,603 | 1,291 | 1,660 | |||||||||
Other income | 67 | 56 | 44 | |||||||||
Other expense | (2 | ) | (4 | ) | (1 | ) | ||||||
Unrealized (loss)/gain on derivative contracts, net | (15 | ) | 3 | (7 | ) | |||||||
Interest expense | ||||||||||||
Interest on debt | 1,357 | 1,356 | 1,385 | |||||||||
Amortization of debt discount, issue, and reacquisition costs, net | 21 | 21 | 24 | |||||||||
Allowance for funds used during construction | (163 | ) | (116 | ) | (99 | ) | ||||||
Net interest expense | 1,215 | 1,261 | 1,310 | |||||||||
Income before cumulative effects of accounting changes | 438 | 85 | 386 | |||||||||
Cumulative effect of change in accounting for conditional asset retirement obligations | (109 | ) | — | — | ||||||||
Net income | $ | 329 | $ | 85 | $ | 386 | ||||||
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At September 30
(in millions)
2006 | 2005 | |||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 536 | $ | 538 | ||||
Restricted cash and investments | 198 | 107 | ||||||
Accounts receivable, net | 1,359 | 1,052 | ||||||
Inventories and other | 576 | 479 | ||||||
Total current assets | 2,669 | 2,176 | ||||||
Property, plant, and equipment(Note 3) | ||||||||
Completed plant | 35,652 | 35,215 | ||||||
Less accumulated depreciation | (15,331 | ) | (14,407 | ) | ||||
Net completed plant | 20,321 | 20,808 | ||||||
Construction in progress | 3,539 | 2,643 | ||||||
Nuclear fuel and capital leases | 574 | 437 | ||||||
Total property, plant, and equipment, net | 24,434 | 23,888 | ||||||
Investment funds | 972 | 858 | ||||||
Regulatory and other long-term assets | ||||||||
Deferred nuclear generating units | 3,521 | 3,912 | ||||||
Other regulatory assets (Note 5) | 1,809 | 2,367 | ||||||
Subtotal | 5,330 | 6,279 | ||||||
Other long-term assets | 1,115 | 1,272 | ||||||
Total deferred charges and other assets | 6,445 | 7,551 | ||||||
Total assets | $ | 34,520 | $ | 34,473 | ||||
LIABILITIES AND PROPRIETARY CAPITAL | ||||||||
Current liabilities | ||||||||
Accounts payable | $ | 890 | $ | 740 | ||||
Accrued liabilities | 211 | 194 | ||||||
Collateral funds held | 195 | 107 | ||||||
Accrued interest | 403 | 380 | ||||||
Current portion of lease/leaseback obligations | 37 | 35 | ||||||
Current portion of energy prepayment obligations | 106 | 106 | ||||||
Short-term debt, net | 2,376 | 2,469 | ||||||
Current maturities of long-term debt (Note 9) | 985 | 2,693 | ||||||
Total current liabilities | 5,203 | 6,724 | ||||||
Other liabilities | ||||||||
Other liabilities | 2,305 | 2,500 | ||||||
Regulatory liabilities (Note 5) | 575 | 897 | ||||||
Asset retirement obligations | 1,985 | 1,857 | ||||||
Lease/leaseback obligations | 1,071 | 1,108 | ||||||
Energy prepayment obligations | 1,138 | 1,244 | ||||||
Total other liabilities | 7,074 | 7,606 | ||||||
Long-term debt, net(Note 9) | 19,544 | 17,751 | ||||||
Total liabilities | 31,821 | 32,081 | ||||||
Commitments and contingencies(Note 13) | ||||||||
Proprietary capital | ||||||||
Appropriation investment | 4,763 | 4,783 | ||||||
Retained earnings | 1,565 | 1,244 | ||||||
Accumulated other comprehensive income | 43 | 27 | ||||||
Accumulated net expense of stewardship programs | (3,672 | ) | (3,662 | ) | ||||
Total proprietary capital | 2,699 | 2,392 | ||||||
Total liabilities and proprietary capital | $ | 34,520 | $ | 34,473 | ||||
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For the years ended September 30
(in millions)
2006 | 2005 | 2004 | ||||||||||
Cash flows from operating activities | ||||||||||||
Net income | $ | 329 | $ | 85 | $ | 386 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities | ||||||||||||
Depreciation, amortization, and accretion | 1,513 | 1,175 | 1,140 | |||||||||
Refueling amortization | 89 | 105 | 100 | |||||||||
Amortization of deferred nuclear refueling costs | 128 | 131 | 132 | |||||||||
Loss on project cancellations/asset impairment | 9 | 24 | 20 | |||||||||
Cumulative effect of change in accounting principle | 109 | — | — | |||||||||
Net realized and unrealized mark-to-market and hedging transactions | 15 | (3 | ) | 7 | ||||||||
Non-cash retirement benefit expense | 302 | 289 | 207 | |||||||||
Prepayment credits applied to revenue | (105 | ) | (105 | ) | (96 | ) | ||||||
Other, net | (7 | ) | 7 | 13 | ||||||||
Changes in current assets and liabilities | ||||||||||||
Accounts receivable, net | (214 | ) | (19 | ) | 50 | |||||||
Inventories and other | (120 | ) | (12 | ) | 10 | |||||||
Accounts payable and accrued liabilities | 125 | (16 | ) | (65 | ) | |||||||
Accrued interest | 23 | (22 | ) | (5 | ) | |||||||
Proceeds from energy prepayments | — | — | 1,504 | |||||||||
Deferred nuclear refueling outage costs | (72 | ) | (122 | ) | (86 | ) | ||||||
Other, net | (110 | ) | (55 | ) | (27 | ) | ||||||
Net cash provided by operating activities | 2,014 | 1,462 | 3,290 | |||||||||
Cash flows from investing activities | ||||||||||||
Construction expenditures | (1,399 | ) | (1,339 | ) | (1,552 | ) | ||||||
Proceeds from project cancellation settlement (Note 1) | — | — | 15 | |||||||||
Nuclear fuel expenditures | (277 | ) | (141 | ) | (119 | ) | ||||||
Change in restricted cash and investments | (91 | ) | (107 | ) | ||||||||
Short-term investments, net | — | 335 | (68 | ) | ||||||||
Loans and other receivables | ||||||||||||
Advances | (17 | ) | (12 | ) | (17 | ) | ||||||
Repayments | 13 | 18 | 22 | |||||||||
Proceeds from sale of receivables/loans (Note 1) | 11 | 56 | — | |||||||||
Proceeds from settlement of litigation related to capital expenditures | 35 | — | — | |||||||||
Other, net | (2 | ) | 2 | 1 | ||||||||
Net cash used in investing activities | (1,727 | ) | (1,188 | ) | (1,718 | ) | ||||||
Cash flows from financing activities | ||||||||||||
Long-term debt | ||||||||||||
Issues | 1,132 | 1,650 | 772 | |||||||||
Redemptions and repurchases (Note 10) | (1,241 | ) | (2,368 | ) | (2,251 | ) | ||||||
Short-term (redemptions)/borrowings, net | (93 | ) | 546 | (157 | ) | |||||||
Proceeds from call monetizations | — | 5 | — | |||||||||
Bond premium received | — | — | 97 | |||||||||
Proceeds from swap receivable monetization | — | — | 55 | |||||||||
Payments on lease/leaseback financing | (28 | ) | (29 | ) | (32 | ) | ||||||
Payments on equipment financing | (6 | ) | (6 | ) | (29 | ) | ||||||
Financing costs, net | (14 | ) | (17 | ) | (3 | ) | ||||||
Payments to U.S. Treasury | (38 | ) | (36 | ) | (38 | ) | ||||||
Other | (1 | ) | — | — | ||||||||
Net cash used in financing activities | (289 | ) | (255 | ) | (1,586 | ) | ||||||
Net change in cash and cash equivalents | (2 | ) | 19 | (14 | ) | |||||||
Cash and cash equivalents at beginning of period | 538 | 519 | 533 | |||||||||
Cash and cash equivalents at end of period | $ | 536 | $ | 538 | $ | 519 | ||||||
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For the years ended September 30
(in millions)
Accumulated | ||||||||||||||||||||||||
Accumulated | Net Expense | |||||||||||||||||||||||
Other | of | |||||||||||||||||||||||
Appropriation | Retained | Comprehensive | Stewardship | Comprehensive | ||||||||||||||||||||
Investment | Earnings | Income (Loss) | Programs | Total | Income | |||||||||||||||||||
Balance at September 30, 2003 | $ | 4,823 | $ | 783 | $ | (74 | ) | $ | (3,638 | ) | $ | 1,894 | $ | — | ||||||||||
Net income (loss) | — | 397 | — | (11 | ) | 386 | 386 | |||||||||||||||||
Return on appropriated investment | — | (18 | ) | — | — | (18 | ) | — | ||||||||||||||||
Accumulated other comprehensive income (Note 7) | — | — | 22 | — | 22 | 22 | ||||||||||||||||||
Return of appropriated investment | (20 | ) | — | — | — | (20 | ) | — | ||||||||||||||||
Balance at September 30, 2004 | 4,803 | 1,162 | (52 | ) | (3,649 | ) | 2,264 | 408 | ||||||||||||||||
Net income (loss) | — | 98 | — | (13 | ) | 85 | 85 | |||||||||||||||||
Return on appropriated investment | — | (16 | ) | — | — | (16 | ) | — | ||||||||||||||||
Accumulated other comprehensive income (Note 7) | — | 79 | — | 79 | 79 | |||||||||||||||||||
Return of appropriated investment | (20 | ) | — | — | — | (20 | ) | — | ||||||||||||||||
Balance at September 30, 2005 | 4,783 | 1,244 | 27 | (3,662 | ) | 2,392 | $ | 164 | ||||||||||||||||
Net income (loss) | — | 339 | — | (10 | ) | 329 | 329 | |||||||||||||||||
Return on appropriated investment | — | (18 | ) | — | — | (18 | ) | — | ||||||||||||||||
Accumulated other comprehensive income (Note 7) | — | — | 16 | — | 16 | 16 | ||||||||||||||||||
Return of appropriated investment | (20 | ) | — | — | — | (20 | ) | — | ||||||||||||||||
Balance at September 30, 2006 | $ | 4,763 | $ | 1,565 | $ | 43 | $ | (3,672 | ) | $ | 2,699 | $345 | ||||||||||||
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(Dollars in millions except where noted)
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As of September 30
2006 | 2005 | |||||||
Power receivables billed | $ | 303 | $ | 286 | ||||
Power receivables unbilled | 1,031 | 731 | ||||||
Total power receivables | 1,334 | 1,017 | ||||||
Other receivables | 35 | 42 | ||||||
Allowance for uncollectible accounts | (10 | ) | (7 | ) | ||||
Net accounts receivable | $ | 1,359 | $ | 1,052 | ||||
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As of September 30
2006 | 2005 | 2004 | ||||||||||
Asset Class | ||||||||||||
Nuclear | 3.00 | 3.40 | 3.37 | |||||||||
Coal-Fired | 3.53 | 3.53 | 3.51 | |||||||||
Hydroelectric | 1.79 | 1.78 | 1.72 | |||||||||
Combustion turbine/diesel generators | 4.54 | 4.55 | 4.41 | |||||||||
Transmission | 2.57 | 2.52 | 2.53 | |||||||||
Other | 5.45 | 5.60 | 6.05 |
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As of September 30
2006 | 2005 | |||||||
Loans and long-term receivables, net | $ | 102 | $ | 93 | ||||
Intangible asset related to pension prior service cost | 280 | 312 | ||||||
Valuation of currency swaps | 246 | 76 | ||||||
Valuation of commodity contracts | 487 | 791 | ||||||
$ | 1,115 | $ | 1,272 | |||||
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For the years ended September 30
2006 | 2005 | 2004 | ||||||||||
Reported income before cumulative effect of change in accounting principle | $ | 438 | $ | 85 | $ | 386 | ||||||
FIN 47 pro forma earnings effects | (7 | ) | (7 | ) | (7 | ) | ||||||
Proforma income before cumulative effect of change in accounting principle | $ | 431 | $ | 78 | $ | 379 | ||||||
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As of September 30
Completed | Construction in | Fuel | ||||||||||
Plant, Net | Progress | Investment | ||||||||||
Browns Ferry * | $ | 1,952 | $ | 1,993 | $ | 229 | ||||||
Sequoyah | 1,648 | 32 | 118 | |||||||||
Watts Bar | 5,317 | 191 | 62 | |||||||||
Raw materials | — | — | 82 | |||||||||
Total Nuclear Production | $ | 8,917 | $ | 2,216 | $ | 491 | ||||||
Notes | ||
* | Browns Ferry Unit 1, a unit in recovery, is discussed below. |
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As of September 30
Operating License | ||||
Nuclear Unit | Expiration Date | |||
Browns Ferry Unit 1 | 2033 | |||
Browns Ferry Unit 2 | 2034 | |||
Browns Ferry Unit 3 | 2036 |
As of September 30
2006 | 2005 | |||||||||||||||||||||||
Accumulated | Accumulated | |||||||||||||||||||||||
Cost | Depreciation | Net | Cost | Depreciation | Net | |||||||||||||||||||
Fossil | $ | 10,567 | $ | 5,249 | $ | 5,318 | $ | 10,164 | $ | 4,912 | $ | 5,252 | ||||||||||||
Combustion turbine | 1,168 | 500 | 668 | 1,176 | 447 | 729 | ||||||||||||||||||
Nuclear | 15,437 | 6,520 | 8,917 | 15,517 | 6,128 | 9,389 | ||||||||||||||||||
Transmission | 4,360 | 1,607 | 2,753 | 4,227 | 1,512 | 2,715 | ||||||||||||||||||
Hydroelectric | 1,879 | 683 | 1,196 | 1,861 | 648 | 1,213 | ||||||||||||||||||
Other electrical plant | 1,235 | 428 | 807 | 1,264 | 426 | 838 | ||||||||||||||||||
Subtotal | 34,646 | 14,987 | 19,659 | 34,209 | 14,073 | 20,136 | ||||||||||||||||||
Multipurpose dams | 962 | 336 | 626 | 962 | 326 | 636 | ||||||||||||||||||
Other stewardship | 44 | 8 | 36 | 44 | 8 | 36 | ||||||||||||||||||
Subtotal | 1,006 | 344 | 662 | 1,006 | 334 | 672 | ||||||||||||||||||
Total | $ | 35,652 | $ | 15,331 | $ | 20,321 | $ | 35,215 | $ | 14,407 | $ | 20,808 | ||||||||||||
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As of September 30
Fair Market | Estimated | |||||||||||||||||||
Pro-Forma | Value of | Future | ||||||||||||||||||
Pro-Forma | September 30, | September | Investment | Liability at | ||||||||||||||||
October 1, 2004 | 2005 | 30, 2006 | Funds at Sept | Sept 30, | ||||||||||||||||
FIN 47 ARO Category | Obligation | Obligation | Obligation | 30, 2006 | 2006 | |||||||||||||||
Fossil Plants | $ | 106 | $ | 111 | $ | 117 | $ | — | $ | 449 | ||||||||||
Office and Other Facilities | 2 | 2 | 2 | — | 42 | |||||||||||||||
Hydroelectric Plants | 5 | 5 | 5 | — | 32 | |||||||||||||||
Transmission Facilities | 8 | 9 | 8 | — | 21 | |||||||||||||||
Total | $ | 121 | $ | 127 | $ | 132 | $ | — | $ | 544 | ||||||||||
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As of September 30
2006 | 2005 | |||||||
Balance at beginning of year | $ | 1,857 | $ | 1,782 | ||||
Liabilities settled | — | — | ||||||
Accretion expense | 100 | 100 | ||||||
Recognition of conditional asset retirement obligations | 132 | — | ||||||
Revisions in estimated cash flows | (104 | ) | (25 | ) | ||||
Balance at end of year | $ | 1,985 | $ | 1,857 | ||||
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As of September 30
2006 | 2005 | |||||||
Regulatory Assets: | ||||||||
Minimum pension liability | $ | 914 | $ | 1,158 | ||||
Nuclear decommissioning costs | 474 | 716 | ||||||
Reacquisition costs | 232 | 264 | ||||||
Deferred purchased power costs | 6 | — | ||||||
Deferred outage costs | 85 | 103 | ||||||
Capital leases | 76 | 84 | ||||||
Unrealized losses on purchased power contracts | 22 | 42 | ||||||
Subtotal | 1,809 | 2,367 | ||||||
Deferred nuclear generating units | 3,521 | 3,912 | ||||||
Total | $ | 5,330 | $ | 6,279 | ||||
Regulatory Liabilities: | ||||||||
Unrealized gain on coal purchase contracts | $ | 487 | $ | 791 | ||||
Capital lease liability | 88 | 106 | ||||||
Total | $ | 575 | $ | 897 | ||||
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As of September 30
Power | Stewardship | |||||||||||
Program | Program | Total | ||||||||||
Congressional appropriations and transfers of property from other federal agencies (net) | $ | 1,443 | $ | 9,622 | $ | 11,065 | ||||||
Program expenditures | (5,221 | ) | (5,221 | ) | ||||||||
Less repayments to the U.S. Treasury | (1,035 | ) | (46 | ) | (1,081 | ) | ||||||
Total | $ | 408 | $ | 4,355 | $ | 4,763 | ||||||
As of September 30
Accumulated other comprehensive loss, October 1, 2003 | $ | (74 | ) | |
Changes in fair value: | ||||
Inflation | 4 | |||
Foreign currency swaps | 18 | |||
Accumulated other comprehensive loss, September 30, 2004 | (52 | ) | ||
Changes in fair value: | ||||
Inflation | 4 | |||
Foreign currency swaps | 75 | |||
Accumulated other comprehensive income, September 30, 2005 | 27 | |||
Changes in fair value: | ||||
Inflation | (11 | ) | ||
Foreign currency swaps | 27 | |||
Accumulated other comprehensive income, September 30, 2006 | $ | 43 | ||
Note: | Foreign currency swap changes are shown net of reclassifications fromOther comprehensive income to earnings. |
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As of September 30
2006 | 2006 Balance Sheet | 2005 | 2005 Balance Sheet | 2006 Notional | Year of | ||||||||||||||||
Balance | Presentation | Balance | Presentation | Amount | Expiration | ||||||||||||||||
Inflation swap | $ | 22 | Other long-term assets | $ | 17 | Other long-term assets | $300 million | 2007 | |||||||||||||
Interest rate swap | (131 | ) | Other liabilities | (158 | ) | Other liabilities | $476 million | 2044 | |||||||||||||
Currency swaps: | |||||||||||||||||||||
Deutschemark | — | (69 | ) | Other long-term assets | DM1.5 billion | 2006 | |||||||||||||||
Sterling | 47 | Other long-term assets | 20 | Other long-term assets | £200 million | 2021 | |||||||||||||||
Sterling | 133 | Other long-term assets | 89 | Other long-term assets | £250 million | 2032 | |||||||||||||||
Sterling | 66 | Other long-term assets | 36 | Other long-term assets | £150 million | 2043 | |||||||||||||||
Swaptions: | |||||||||||||||||||||
$1 billion notional | (296 | ) | Other liabilities | (314 | ) | Other liabilities | $1 billion | 2042 | |||||||||||||
$28 million notional | (3 | ) | Other liabilities | (4 | ) | Other liabilities | $28 million | 2022 | |||||||||||||
$14 million notional | (2 | ) | Other liabilities | (2 | ) | Other liabilities | $14 million | 2022 | |||||||||||||
Coal contracts with volume options | 487 | Other long-term assets | 791 | Other long-term assets | 115 million tons | 2017 | |||||||||||||||
Purchase power option contracts | (22 | ) | Other liabilities | (42 | ) | Other liabilities | 500 MW | 2007 |
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As of September 30, 2006
Derivative | ||||||||||
Hedging | Purpose of Hedge | Type of Hedge– | Accounting for Derivative | Accounting for the | ||||||
Instrument | Hedged Item | Transaction | Cash Flow (CF) | Hedging Instrument | Hedged Item | |||||
Inflation Swap | Variable-principal debt | To fix the debt’s variable cash flows to a fixed flow | CF | Cumulative unrealized gains and losses are recorded inOther comprehensive income | No adjustment is made to the basis of the hedged item. | |||||
Currency Swaps | Anticipated payment denominated in a foreign currency | To protect against changes in cash flows caused by changes in foreign-currency exchange rates | CF | Cumulative unrealized gains and losses are recorded inOther comprehensive income and reclassified to earnings to the extent they are offset by cumulative gains and losses on the hedged transaction. | No adjustment is made to the basis of the hedged item. |
As of September 30, 2006
Derivative Type | Purpose of Derivative | Accounting for Derivative Instrument | ||
Coal Contracts with Volume Options | To protect against fluctuations in market prices of the item to be purchased | Gains and losses are recorded as regulatory assets or liabilities until settlement at which time they are recognized in fuel and purchased power expense. | ||
Purchase Power Option Contracts | To protect against fluctuations in market prices of the item to be purchased | Gains and losses are recorded as regulatory assets or liabilities until settlement at which time they are recognized in fuel and purchased power expense. | ||
Interest Rate Swap | To fix short-term debt variable rate to a fixed rate | Gains and losses are recorded in earnings as unrealized gains/losses on derivative contracts. | ||
Swaptions | To protect against decreases in value of the embedded call | Gains and losses are recorded in earnings as unrealized gains/losses on derivative contracts. | ||
Futures and Options on Futures | To protect against fluctuations in the price of the item to be purchased | Realized gains and losses are recorded in earnings as purchased power expense; unrealized gains and losses are recorded as a regulatory asset/liability. |
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• | In 2002, TVA monetized the call provisions on a $1 billion Bond issue by entering into a swaption agreement with a third party in exchange for $175 million (the “2002 Swaption”). | ||
• | In 2003, TVA monetized the call provisions on a second Bond issue of $476 million by entering into a swaption agreement with a third party in exchange for $81 million (the “2003 Swaption”). | ||
• | In 2005, TVA monetized the call provisions on two electronotes® issues ($42 million total par value) by entering into swaption agreements with a third party in exchange for $5 million (the “2005 Swaptions”). |
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As of September 30
2006 | 2005 | |||||||||||||||
Notional | Notional | |||||||||||||||
Amount | Contract | Amount | Contract | |||||||||||||
(in mmBtu) | Value | (in mmBtu) | Value | |||||||||||||
Futures contracts | ||||||||||||||||
Financial positions, beginning of period, net | 880,000 | $ | 9 | – | $ | – | ||||||||||
Purchased | 18,160,000 | 146 | 4,370,000 | 33 | ||||||||||||
Settled | (14,750,000 | ) | (97 | ) | (3,490,000 | ) | (27 | ) | ||||||||
Realized (losses)/gains | – | (23 | ) | – | 3 | |||||||||||
Net positions-long | 4,290,000 | 35 | 880,000 | 9 | ||||||||||||
Swap Futures | ||||||||||||||||
Financial positions, beginning of period, net | – | – | – | – | ||||||||||||
Fixed Portion | 1,977,500 | 12 | – | – | ||||||||||||
Floating Portion — realized | (155,000 | ) | (1 | ) | – | – | ||||||||||
Realized (losses) | – | – | – | – | ||||||||||||
Net positions-long | 1,822,500 | 11 | – | – | ||||||||||||
Options contracts | ||||||||||||||||
Financial positions, beginning of period, net | 240,000 | – | – | – | ||||||||||||
Calls Purchased | – | – | 580,000 | 1 | ||||||||||||
Calls and puts sold | – | – | 980,000 | (1 | ) | |||||||||||
Positions closed or expired | (240,000 | ) | – | (1,320,000 | ) | – | ||||||||||
Net positions-long | – | – | 240,000 | – | ||||||||||||
Holding gains (losses) | ||||||||||||||||
Unrealized gain at beginning of period, net | – | 1 | – | – | ||||||||||||
Unrealized(loss)/gain for the period | – | (7 | ) | – | 1 | |||||||||||
Unrealized (losses)/gains at end of period, net | – | (6 | ) | – | 1 | |||||||||||
Financial positions at end of period, net | 6,112,500 | $ | 40 | 1,120,000 | $ | 10 | ||||||||||
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Principal Amount | ||||||||
2006 | 2005 | |||||||
Redemptions/Maturities: | ||||||||
electronotes® | ||||||||
First quarter | $ | 152 | $ | 3 | ||||
Second quarter | 3 | 75 | ||||||
Third quarter | 4 | 101 | ||||||
Fourth quarter | 4 | 3 | ||||||
2000E QUINTS | 100 | |||||||
1998D PARRS | 86 | |||||||
1995 Series A | 2,000 | |||||||
1996 Series C | 1,000 | – | ||||||
2003 Series B | 28 | * | – | |||||
2005 Series A | 64 | * | – | |||||
Total | $ | 1,255 | $ | 2,368 | ||||
Issues | ||||||||
electronotes® | ||||||||
First quarter | $ | 49 | $ | – | ||||
Second quarter | 19 | 25 | ||||||
Third quarter | 37 | 105 | ||||||
Fourth quarter | 27 | 20 | ||||||
2006 Series A | 1,000 | – | ||||||
2005 Series A | – | 500 | ||||||
2005 Series B | – | 1,000 | ||||||
Total | $ | 1,132 | $ | 1,650 | ||||
Inflation indexed bond accretion | $ | 15 | $ | 11 |
Note | ||
* | Includes $13 million gain on redemption — See Note 10. |
As of September 30
Call/(Put) | Coupon | 2006 | 2005 Par | |||||||||||||||||
CUSIP or Other Identifier | Maturity | Date | Rate | Par Amount | Amount | |||||||||||||||
Discount Notes (net of discount) | $ | 2,376 | $ | 2,469 | ||||||||||||||||
Current maturities of long-term debt: | ||||||||||||||||||||
88059TAE1 | 06/15/2021 | 10/02/2005 | 6.350 | % | — | 28 | ||||||||||||||
88059TAJ0 | 08/15/2021 | 10/02/2005 | 6.100 | % | — | 23 | ||||||||||||||
88059TAZ4 | 05/15/2017 | 10/02/2005 | 6.000 | % | — | 40 | ||||||||||||||
88059TCM1 | 10/15/2023 | 10/02/2005 | 5.625 | % | — | 15 | ||||||||||||||
88059TCG4 | 08/15/2018 | 10/02/2005 | 5.500 | % | — | 44 | ||||||||||||||
880591CK6 | 04/01/2036 | (04/03/2006 | ) | 5.980 | % | — | 121 | |||||||||||||
880591CM2 | 09/18/2006 | 7.125 | % | — | 922 | |||||||||||||||
880591CS9 | 04/01/2036 | (04/03/2006 | ) | 5.880 | % | — | 1,500 | |||||||||||||
880591CQ3 | 01/15/2007 | 6.643 | % | 385 | – | |||||||||||||||
880591DS8 | 12/15/2016 | (12/15/2006 | ) | 4.875 | % | 600 | – | |||||||||||||
Current maturities of long-term debt | 985 | 2,693 | ||||||||||||||||||
Total short-term debt, net | $ | 3,361 | $ | 5,162 | ||||||||||||||||
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Call/(Put) | Coupon | 2006 | 2005 Par | |||||||||||||||||
CUSIP or Other Identifier | Maturity | Date | Rate | Par Amount | Amount | |||||||||||||||
880591CQ3 | 01/15/2007 | 6.643 | % | $ | – | $ | 370 | |||||||||||||
880591DS8 | 12/15/2016 | (12/15/2006 | ) | 4.875 | % | – | 600 | |||||||||||||
Maturing in 2007 | – | 970 | ||||||||||||||||||
88059TBQ3 | 01/15/2008 | 01/15/2004 | 3.050 | % | 10 | 10 | ||||||||||||||
88059TBS9 | 01/15/2008 | 01/15/2004 | 3.300 | % | 40 | 40 | ||||||||||||||
88059TCB5 | 05/15/2008 | 05/15/2004 | 2.450 | % | 40 | 41 | ||||||||||||||
Maturing in 2008 | 90 | 91 | ||||||||||||||||||
880591DB5 | 11/13/2008 | 5.375 | % | 2,000 | 2,000 | |||||||||||||||
88059TCW9 | 03/15/2009 | 03/15/2005 | 3.200 | % | 30 | 31 | ||||||||||||||
Maturing in 2009 | 2,030 | 2,031 | ||||||||||||||||||
88059TDP3 | 04/15/2010 | 04/15/2007 | 5.125 | % | 21 | – | ||||||||||||||
88059TDD0 | 06/15/2010 | 06/15/2006 | 4.125 | % | 42 | 42 | ||||||||||||||
Maturing in 2010 | 63 | 42 | ||||||||||||||||||
880591DN9 | 01/18/2011 | 5.625 | % | 1,000 | 1,000 | |||||||||||||||
88059TDQ1 | 05/15/2011 | 05/15/2007 | 5.250 | % | 6 | – | ||||||||||||||
88059TDR9 | 06/15/2011 | 06/15/2007 | 5.250 | % | 9 | – | ||||||||||||||
Maturing in 2011 | 1,015 | 1,000 | ||||||||||||||||||
880591DL3 | 05/23/2012 | 7.140 | % | 29 | 29 | |||||||||||||||
880591DT6 | 05/23/2012 | 6.790 | % | 1,486 | 1,486 | |||||||||||||||
88059TBH3 | 09/15/2012 | 09/15/2004 | 4.375 | % | 10 | 10 | ||||||||||||||
Maturing in 2012 | 1,525 | 1,525 | ||||||||||||||||||
880591CW0 | 03/15/2013 | 6.000 | % | 1,359 | 1,359 | |||||||||||||||
88059TBR1 | 01/15/2013 | 01/15/2005 | 4.375 | % | 14 | 14 | ||||||||||||||
88059TBW0 | 03/15/2013 | 03/15/2005 | 4.000 | % | 23 | 23 | ||||||||||||||
88059TBX8 | 03/15/2013 | 03/15/2004 | 4.250 | % | 13 | 13 | ||||||||||||||
88059TCD1 | 06/15/2013 | 06/15/2004 | 3.500 | % | 12 | 12 | ||||||||||||||
880591DW9 | 08/01/2013 | 4.750 | % | 990 | 990 | |||||||||||||||
88059TCF6 | 07/15/2013 | 07/15/2005 | 4.350 | % | 17 | 18 | ||||||||||||||
88059TDS7 | 07/15/2013 | 07/15/2008 | 5.625 | % | 9 | – | ||||||||||||||
Maturing in 2013 | 2,437 | 2,429 | ||||||||||||||||||
88059TCL3 | 10/15/2013 | 10/15/2005 | 4.500 | % | 12 | 12 | ||||||||||||||
88059TCQ2 | 12/15/2013 | 12/15/2005 | 4.700 | % | 8 | 8 | ||||||||||||||
88059TBJ9 | 10/15/2014 | 10/15/2004 | 4.600 | % | 22 | 22 | ||||||||||||||
88059TBN0 | 12/15/2014 | 12/15/2004 | 5.000 | % | 54 | 55 | ||||||||||||||
88059TBY6 | 04/15/2015 | 04/15/2005 | 4.600 | % | 20 | 20 | ||||||||||||||
88059TDB4 | 04/15/2015 | 04/15/2007 | 5.000 | % | 50 | 50 | ||||||||||||||
880591DY5 | 06/15/2015 | 4.375 | % | 1,000 | 1,000 | |||||||||||||||
88059TDE8 | 07/15/2015 | 07/15/2007 | 4.500 | % | 7 | 7 | ||||||||||||||
88059TCH2 | 08/15/2015 | 08/15/2005 | 5.125 | % | 34 | 35 | ||||||||||||||
88050TBK6 | 10/15/2015 | 10/15/2005 | 5.050 | % | 19 | 19 | ||||||||||||||
88059TDH1 | 10/15/2015 | 10/15/2007 | 5.000 | % | 28 | – | ||||||||||||||
88059TBL4 | 11/15/2015 | 11/15/2005 | 4.800 | % | 27 | 27 | ||||||||||||||
88059TCR0 | 12/15/2015 | 12/15/2005 | 4.875 | % | 11 | 11 | ||||||||||||||
88059TDK4 | 12/15/2015 | 12/15/2006 | 5.375 | % | 10 | – | ||||||||||||||
88059TBU4 | 02/15/2016 | 02/15/2006 | 4.550 | % | 9 | 9 | ||||||||||||||
88059TCV1 | 02/15/2016 | 02/15/2006 | 4.500 | % | 3 | 3 | ||||||||||||||
88059TDN8 | 03/15/2016 | 03/15/2008 | 5.375 | % | 8 | – | ||||||||||||||
88059TCC3 | 06/15/2016 | 06/15/2006 | 3.875 | % | 4 | 4 | ||||||||||||||
88059TDT5 | 08/15/2016 | 08/15/2007 | 5.625 | % | 4 | |||||||||||||||
88059TCJ8 | 09/15/2016 | 09/15/2006 | 4.950 | % | 11 | 11 | ||||||||||||||
88059TDU2 | 09/15/2016 | 09/15/2007 | 5.375 | % | 14 | – | ||||||||||||||
88059TCS8 | 01/15/2017 | 01/15/2007 | 5.000 | % | 29 | 29 | ||||||||||||||
880591CU4 | 12/15/2017 | 6.250 | % | 750 | 750 | |||||||||||||||
88059TCA7 | 05/15/2018 | 05/15/2004 | 4.750 | % | 24 | 24 | ||||||||||||||
88059TCE9 | 07/15/2018 | 07/15/2004 | 4.700 | % | 35 | 36 | ||||||||||||||
88059TCN9 | 11/15/2018 | 11/15/2006 | 5.125 | % | 18 | 19 | ||||||||||||||
88059TCT6 | 01/15/2019 | 01/15/2005 | 5.000 | % | 28 | 28 | ||||||||||||||
88059TCX7 | 03/15/2019 | 03/15/2007 | 4.500 | % | 13 | 13 | ||||||||||||||
88059TDF5 | 08/15/2020 | 08/15/2008 | 5.000 | % | 10 | 10 | ||||||||||||||
88059TDG3 | 09/15/2020 | 09/15/2008 | 4.800 | % | 3 | 3 | ||||||||||||||
88059TDJ7 | 11/15/2020 | 11/15/2008 | 5.500 | % | 11 | – |
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Call/(Put) | Coupon | 2006 | 2005 Par | |||||||||||||||||
CUSIP or Other Identifier | Maturity | Date | Rate | Par Amount | Amount | |||||||||||||||
88059TDL2 | 01/18/2021 | 01/15/2009 | 5.125 | % | $ | 5 | $ | – | ||||||||||||
880591DC3 | 06/07/2021 | 5.805 | % | 374 | 352 | |||||||||||||||
88859TAN1 | 12/15/2021 | 12/15/2005 | 6.000 | % | 25 | 25 | ||||||||||||||
88059TAR2 | 01/15/2022 | 01/15/2006 | 6.125 | % | 28 | 28 | ||||||||||||||
88059TAX9 | 04/15/2022 | 04/15/2006 | 6.125 | % | 14 | 14 | ||||||||||||||
88059TBE0 | 08/15/2022 | 08/15/2006 | 5.500 | % | 28 | 29 | ||||||||||||||
88059TBM2 | 11/15/2022 | 11/15/2006 | 5.000 | % | 11 | 11 | ||||||||||||||
88059TBP5 | 12/15/2022 | 12/15/2006 | 5.000 | % | 20 | 20 | ||||||||||||||
88059TBT7 | 01/15/2023 | 01/15/2007 | 5.000 | % | 11 | 12 | ||||||||||||||
88059TBV2 | 02/15/2023 | 02/15/2007 | 5.000 | % | 17 | 18 | ||||||||||||||
88059TBZ3 | 05/15/2023 | 05/15/2004 | 5.125 | % | 15 | 15 | ||||||||||||||
88059TCK5 | 10/15/2023 | 10/15/2007 | 5.200 | % | 14 | 14 | ||||||||||||||
88059TCP4 | 11/15/2023 | 11/15/2004 | 5.250 | % | 12 | 12 | ||||||||||||||
88059TCU3 | 02/15/2024 | 02/15/2008 | 5.125 | % | 9 | 9 | ||||||||||||||
88059TCY5 | 04/15/2024 | 04/15/2005 | 5.375 | % | 14 | 15 | ||||||||||||||
88059TCZ2 | 02/15/2025 | 02/15/2006 | 5.000 | % | 18 | 19 | ||||||||||||||
88059TDA6 | 03/15/2025 | 03/15/2009 | 5.000 | % | 6 | 6 | ||||||||||||||
88059TDC2 | 05/15/2025 | 05/15/2009 | 5.125 | % | 14 | 14 | ||||||||||||||
880591CJ9 | 11/01/2025 | 6.750 | % | 1,350 | 1,350 | |||||||||||||||
88059TDM0 | 02/15/2026 | 02/15/2010 | 5.500 | % | 7 | – | ||||||||||||||
880591300 2 | 06/01/2028 | 5.490 | % | 466 | 466 | |||||||||||||||
880591409 2 | 05/01/2029 | 5.618 | % | 410 | 410 | |||||||||||||||
880591DM1 | 05/01/2030 | 7.125 | % | 1,000 | 1,000 | |||||||||||||||
880591DP4 | 07/07/2032 | 6.587 | % | 468 | 441 | |||||||||||||||
880591DV1 | 07/15/2033 | 4.700 | % | 472 | 500 | |||||||||||||||
880591DX7 | 06/15/2035 | 4.650 | % | 436 | 500 | |||||||||||||||
880591CK6 | 04/01/2036 | 5.980 | % | 121 | – | |||||||||||||||
880591CS9 | 04/01/2036 | 5.880 | % | 1,500 | – | |||||||||||||||
880591CP5 | 01/15/2038 | 6.150 | % | 1,000 | 1,000 | |||||||||||||||
880591BL5 | 04/15/2042 | 04/15/2012 | 8.250 | % | 1,000 | 1,000 | ||||||||||||||
880591DU3 | 06/07/2043 | 4.962 | % | 281 | 265 | |||||||||||||||
880591CF7 | 07/15/2045 | 07/15/2020 | 6.235 | % | 140 | 140 | ||||||||||||||
880591DZ2 | 04/01/2056 | 5.375 | % | 1,000 | – | |||||||||||||||
Maturing 2014-2056 | 12,562 | 9,890 | ||||||||||||||||||
Subtotal | 19,722 | 17,978 | ||||||||||||||||||
Unamortized discounts, premiums, and other | (178 | ) | (227 | ) | ||||||||||||||||
Total long-term debt, net | $ | 19,544 | $ | 17,751 | ||||||||||||||||
Notes | ||
(1) | The above table includes net translation losses from currency transactions of $195 million and $52 million at September 30, 2006, and 2005, respectively. | |
(2) | TVA PARRS, CUSIP numbers 880591300 and 880591409, may be redeemed under certain conditions. See Note 9 —Put and Call Options. |
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As of September 30
2006 | 2005 | |||||||||||||||
Carrying | Fair | Carrying | Fair | |||||||||||||
Amount | Value | Amount | Value | |||||||||||||
Cash and cash equivalents | $ | 536 | $ | 536 | $ | 538 | $ | 538 | ||||||||
Restricted cash and investments | 198 | 198 | 107 | 107 | ||||||||||||
Investment funds | 972 | 972 | 858 | 858 | ||||||||||||
Loans and other long-term receivables | 102 | 102 | 93 | 93 | ||||||||||||
Short-term debt, net of discount | 2,376 | 2,376 | 2,469 | 2,469 | ||||||||||||
Long-term debt (including current portion), net of discount | 20,529 | 22,037 | 20,444 | 22,552 | ||||||||||||
Other financing obligations | 1,108 | 1,108 | 1,143 | 1,143 |
As of September 30
2006 | 2005 | |||||||
Securities held as trading | $ | 966 | $ | 853 | ||||
Other | 6 | 5 | ||||||
Total investment funds | $ | 972 | $ | 858 | ||||
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Pension Benefits | Other Postretirement Benefits | ||||||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||||||
Change in benefit obligation | |||||||||||||||||
Benefit obligation at beginning of year | $ | 8,433 | $ | 7,754 | $ | 544 | $ | 447 | |||||||||
Service cost | 127 | 117 | 9 | 6 | |||||||||||||
Interest cost | 440 | 428 | 29 | 25 | |||||||||||||
Plan participants’ contributions | 35 | 41 | 64 | 63 | |||||||||||||
Amendments, including special events | – | – | – | – | |||||||||||||
Actuarial loss | 3 | 489 | (108 | ) | 91 | ||||||||||||
Net transfers from variable fund/401(k) plan | 9 | 24 | – | – | |||||||||||||
Expenses paid | (4 | ) | (4 | ) | – | – | |||||||||||
Benefits paid | (443 | ) | (416 | ) | (87 | ) | (88 | ) | |||||||||
Benefit obligation at end of year | $ | 8,600 | $ | 8,433 | $ | 451 | $ | 544 | |||||||||
Change in plan assets | |||||||||||||||||
Fair value of plan assets at beginning of year | $ | 7,015 | $ | 6,415 | $ | – | $ | – | |||||||||
Adjustment to reconcile to system asset value | – | – | – | – | |||||||||||||
Actual return on plan assets | 641 | 902 | – | – | |||||||||||||
Plan participants’ contributions | 35 | 41 | 64 | 63 | |||||||||||||
Net transfers from variable fund/401(k) plan | 9 | 24 | – | – | |||||||||||||
Employer contributions | 75 | 53 | 23 | 25 | |||||||||||||
Expenses paid | (4 | ) | (4 | ) | – | – | |||||||||||
Benefits paid | (443 | ) | (416 | ) | (87 | ) | (88 | ) | |||||||||
Fair value of plan assets at end of year | $ | 7,328 | $ | 7,015 | $ | – | $ | – | |||||||||
Funded status | $ | (1,272 | ) | $ | (1,418 | ) | $ | (451 | ) | $ | (544 | ) | |||||
Unrecognized net actuarial loss | 1,275 | 1,554 | 113 | 237 | |||||||||||||
Unrecognized prior service cost | 275 | 311 | 39 | 44 | |||||||||||||
Unrecognized transition obligations | – | – | – | – | |||||||||||||
Prepaid (accrued) benefit cost | $ | 278 | $ | 447 | $ | (299 | ) | $ | (263 | ) | |||||||
Amount recognized on balance sheet | |||||||||||||||||
Prepaid benefit cost | $ | – | $ | – | $ | – | $ | – | |||||||||
Accrued benefit liability | (903 | ) | (1,010 | ) | (299 | ) | (263 | ) | |||||||||
Other long-term asset | 275 | 311 | – | – | |||||||||||||
Accumulated other comprehensive income reclassified to regulatory assets | 906 | 1,146 | – | – | |||||||||||||
Net amount recognized | $ | 278 | $ | 447 | $ | (299 | ) | $ | (263 | ) | |||||||
Weighted average assumptions as of September 30 | 2006 | 2005 | 2006 | 2005 | |||||||||||||
Discount rate | 5.90 | % | 5.38 | % | 5.90 | % | 5.38 | % | |||||||||
Expected return on plan assets | 8.75 | % | 8.25 | % | NA | NA | |||||||||||
Rate of compensation increase | 3.3% – 10.1 | % | 3.3% – 10.1 | % | NA | NA | |||||||||||
Initial health care trend rate | NA | NA | 8.50 | % | 9.00 | % | |||||||||||
Ultimate health care trend rate | NA | NA | 5.00 | % | 5.00 | % | |||||||||||
Ultimate trend rate is reached in year beginning | NA | NA | 2013 | 2013 |
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Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||||
2006 | 2005 | 2004 | 2006 | 2005 | 2004 | ||||||||||||||||||||
Components of net periodic benefit cost | |||||||||||||||||||||||||
Service cost | $ | 127 | $ | 117 | $ | 112 | $ | 9 | $ | 6 | $ | 5 | |||||||||||||
Interest cost | 440 | 429 | 406 | 28 | 25 | 18 | |||||||||||||||||||
Expected return on plan assets | (490 | ) | (457 | ) | (464 | ) | NA | NA | NA | ||||||||||||||||
Amortization of prior service cost | 36 | 36 | 36 | 5 | 5 | 5 | |||||||||||||||||||
Amortization of transition obligation | – | – | – | – | – | – | |||||||||||||||||||
Recognized net actuarial loss | 131 | 118 | 88 | 16 | 10 | 1 | |||||||||||||||||||
Net periodic benefit cost | 244 | 243 | 178 | 58 | 46 | 29 | |||||||||||||||||||
Special events | – | – | – | – | – | 7 | |||||||||||||||||||
Total benefits cost | $ | 244 | $ | 243 | $ | 178 | $ | 58 | $ | 46 | $ | 36 | |||||||||||||
Weighted average assumptions used to determine expense | |||||||||||||||||||||||||
Discount rate | 5.38 | % | 5.81 | % | 6.00 | % | 5.38 | % | 5.81 | % | 6.00 | % | |||||||||||||
Expected return on plan assets | 8.25 | % | 8.25 | % | 8.50 | % | NA | NA | NA | ||||||||||||||||
Rate of compensation increase | 3.3%-10.1 | % | 3.3%-10.1 | % | 3.3%-10.1 | % | NA | NA | NA | ||||||||||||||||
Initial health care trend rate | NA | NA | NA | 9.00 | % | 9.0 | % | 8.50 | % | ||||||||||||||||
Ultimate health care trend rate | NA | NA | NA | 5.00 | % | 5.00 | % | 5.00 | % | ||||||||||||||||
Ultimate trend rate is reached in year beginning | NA | NA | NA | 2013 | 2012 | 2010 |
1% Increase | 1% Decrease | |||||||
Effect on total of service and interest cost components | 4 | (5 | ) | |||||
Effect on end-of-year accumulated postretirement benefit obligation | 61 | (65 | ) |
Pension | Other | |||||||
2007 | $ | 534,125 | $ | 21,715 | ||||
2008 | $ | 544,053 | $ | 24,016 | ||||
2009 | $ | 559,152 | $ | 26,116 | ||||
2010 | $ | 572,454 | $ | 28,073 | ||||
2011 | $ | 584,788 | $ | 30,140 | ||||
2012-2016 | $ | 3,160,924 | $ | 159,368 |
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Payments Due in the Year Ending September 30
2007 | 2008 | 2009 | 2010 | 2011 | Thereafter | Total | ||||||||||||||||||||||
Debt | $ | 3,361 | $ | 90 | $ | 2,030 | $ | 63 | $ | 1,015 | $ | 16,329 | $ | 22,888 | * | |||||||||||||
Leases | ||||||||||||||||||||||||||||
Non-Cancelable Operating | 45 | 41 | 26 | 12 | 4 | 7 | 135 | |||||||||||||||||||||
Capital | 63 | 59 | 57 | 57 | 30 | 6 | 272 | |||||||||||||||||||||
Power purchase obligations | 205 | 146 | 148 | 152 | 154 | 3,549 | 4,354 | |||||||||||||||||||||
Purchase Obligations | ||||||||||||||||||||||||||||
Fuel purchase obligations | 1083 | 509 | 496 | 400 | 249 | 278 | 3,015 | |||||||||||||||||||||
Other obligations | 199 | 111 | 5 | 3 | 2 | 7 | 327 | |||||||||||||||||||||
Total | $ | 4,956 | $ | 956 | $ | 2,762 | $ | 687 | $ | 1,454 | $ | 20,176 | $ | 30,991 | ||||||||||||||
* | Does not include noncash items of foreign currency valuation loss of $195 million and net discount on sale of bonds of $178 million. |
Payments Due in the Year Ending September 30
2007 | 2008 | 2009 | 2010 | 2011 | Thereafter | Total | ||||||||||||||||||||||
Energy Prepayment Obligations | $ | 106 | $ | 106 | $ | 105 | $ | 105 | $ | 105 | $ | 717 | $ | 1,244 | ||||||||||||||
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• | depreciation accruals and other charges representing the amortization of capital expenditures; and | ||
• | the net proceeds from any disposition of power facilities; |
• | the reduction of its capital obligations (including Bonds and the Appropriation Investment); or | ||
• | investment in power assets. |
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• | The Clean Air Act (“CAA”) and the Clean Air Interstate Rule (“CAIR”) and Clean Air Mercury Rule (“CAMR”) | ||
• | The Clean Water Act and regulations under Sections 316a and 316b | ||
• | The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) |
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Related Party Transactions | ||||||||||||
For the years ended, or as of September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Sales of electricity services | $ | 181 | $ | 168 | $ | 153 | ||||||
Other revenues | 24 | 15 | 16 | |||||||||
Other expenses | 226 | 222 | 202 | |||||||||
Receivables at September 30 | 21 | 26 | 18 | |||||||||
Payables at September 30 | 123 | 131 | 203 | |||||||||
Return on appropriation investment (Note 7) | 18 | 16 | 18 | |||||||||
Repayment of appropriation investment (Note 7) | 20 | 20 | 20 |
2006 | ||||||||||||||||||||
(in millions) | First | Second | Third | Fourth | Total | |||||||||||||||
Operating revenues | $ | 2,052 | $ | 2,048 | $ | 2,250 | $ | 2,835 | $ | 9,185 | ||||||||||
Operating expenses | 1,827 | 1,766 | 1,874 | 2,115 | 7,582 | |||||||||||||||
Operating income | 225 | 282 | 376 | 720 | 1,603 | |||||||||||||||
Income before cumulative effect of accounting changes | (53 | ) | 14 | 162 | 315 | 438 | ||||||||||||||
Cumulative effect of accounting changes | – | – | – | (109 | ) | (109 | ) | |||||||||||||
Net (loss)/income | $ | (53 | ) | $ | 14 | $ | 162 | $ | 206 | $ | 329 |
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2005 | ||||||||||||||||||||
(in millions) | First | Second | Third | Fourth | Total | |||||||||||||||
Operating revenues | $ | 1,834 | $ | 1,839 | $ | 1,881 | $ | 2,240 | $ | 7,794 | ||||||||||
Operating expenses | 1,435 | 1,562 | 1,553 | 1,953 | 6,503 | |||||||||||||||
Operating income | 399 | 277 | 328 | 287 | 1,291 | |||||||||||||||
Net income (loss) | $ | 90 | $ | (24 | ) | $ | (15 | ) | $ | 34 | $ | 85 |
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Knoxville, Tennessee
December 14, 2006
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Directors | Age | Year Appointed | Year Term Expires | |||||||||
William B. Sansom, Chairman | 65 | 2006 | 2009 | |||||||||
Bishop William Graves | 70 | 2006 | 2007 | |||||||||
Susan Richardson Williams | 61 | 2006 | 2007 | |||||||||
Skila S. Harris | 56 | 1999 | 2008 | |||||||||
Donald R. DePriest | 67 | 2006 | 2009 | |||||||||
Howard A. Thrailkill | 67 | 2006 | 2010 | |||||||||
William W. Baxter | 53 | 2001 | 2011 | |||||||||
Dennis C. Bottorff | 62 | 2006 | 2011 | |||||||||
Robert M. Duncan | 55 | 2006 | 2011 |
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Employment | ||||||||||
Executive Officers | Title | Age | Commenced | |||||||
Tom D. Kilgore | President and Chief Executive Officer | 58 | 2005 | |||||||
John M. Hoskins | Interim Chief Financial Officer & Executive Vice President, Financial Services | 51 | 1978 | |||||||
William S. Orser | Interim Chief Operating Officer | 62 | 2006 | |||||||
Maureen H. Dunn | Executive Vice President and General Counsel | 57 | 1978 | |||||||
John E. Long, Jr. | Chief Administrative Officer and Executive Vice President, Administrative Services | 54 | 1980 | |||||||
Kenneth R. Breeden | Executive Vice President, Customer Resources | 58 | 2004 | |||||||
Terry Boston | Executive Vice President, Power System Operations | 56 | 1972 | |||||||
Karl Singer | Chief Nuclear Officer and Executive Vice President, TVA Nuclear | 50 | 1993 | |||||||
Kathryn Jackson | Executive Vice President, River System Operations and Environment and the Environmental Executive | 49 | 1991 | |||||||
Joseph Bynum | Executive Vice President, Fossil Power Group | 59 | 1972 | |||||||
Ashok S. Bhatnagar | Senior Vice President, Nuclear Operations | 50 | 1999 | |||||||
Peyton T. Hairston, Jr. | Senior Vice President, Communications | 51 | 1993 | |||||||
Janet C. Herrin | Senior Vice President, River Operations | 52 | 1978 | |||||||
Preston Swafford | Senior Vice President, Nuclear Support | 46 | 2006 | |||||||
Tammy W. Wilson | Interim Senior Vice President and Treasurer | 38 | 1990 | |||||||
Edwin E. Freeman | Vice President, Fossil Operations | 47 | 1994 | |||||||
Randy Trusley | Vice President and Controller | 50 | 1978 |
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• | Corporate Governance Committee | ||
• | Finance, Strategy and Rates Committee | ||
• | Operations, Environment and Safety Committee | ||
• | Human Resources Committee | ||
• | Community Relations Committee. |
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Director Compensation | ||||||||
Total | ||||||||
Annual Stipend | Director Compensation1 | |||||||
Name | ($) | ($) | ||||||
William W. Baxter | 45,000 | 61,737 | 2 | |||||
Dennis C. Bottorff | 46,000 | 21,581 | ||||||
Donald R. DePriest | 46,000 | 21,581 | ||||||
Robert M. Duncan | 46,000 | 21,581 | ||||||
Bishop William Graves3 | 45,000 | – | ||||||
Skila S. Harris | 46,000 | 59,500 | 4 | |||||
William B. Sansom | 50,000 | 23,336 | ||||||
Howard A. Thrailkill | 46,000 | 21,277 | ||||||
Susan Richardson Williams | 46,000 | 21,606 |
Notes | ||
(1) | Total Director Compensation excludes expense reimbursement. | |
(2) | Mr. Baxter served as Chairman of the TVA Board in a full-time capacity prior to its restructuring and received a salary at the rate of $149,200 per year until January 8, 2006. He received a salary at the rate of $152,000 per year from January 9, 2006, through March 30, 2006, at which time he began serving as a director in a part-time capacity and receiving a stipend at a rate of $45,000 annually. | |
(3) | Bishop Graves was not sworn in as a director until October 10, 2006. | |
(4) | Ms. Harris served as a director of the TVA Board in a full-time capacity prior to its restructuring and received a salary at the rate of $140,300 per year until January 8, 2006. She received a salary at the rate of $143,000 per year from January 9, 2006, through March 30, 2006, at which time she began serving as a director in a part-time capacity and receiving a stipend at a rate of $45,000 annually. On May 18, 2006, she was selected to chair the Human Resources Committee and began receiving a stipend of $46,000 annually. |
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Expiration of | Earliest | Estimated | ||||||||||
Current | Period of | Eligibility | Monthly Annuity3 | |||||||||
Name | Appointment | Creditable Service1 | Date2 | ($) | ||||||||
William W. Baxter | 5/18/2011 | 9 yrs., 5 mos. | 7/31/2015 | 1,099 | ||||||||
Dennis C. Bottorff | 5/18/2011 | 5 yrs., 1 mo. | 5/18/2011 | 194 | ||||||||
Donald R. DePriest | 5/18/2009 | 3 yrs., 1 mo. | – | 5 | – | 5 | ||||||
Robert M. Duncan | 5/18/2011 | 5 yrs., 1 mo. | 4/13/2013 | 194 | ||||||||
Bishop William Graves | 5/18/2007 | – | – | |||||||||
Skila S. Harris | 5/18/2008 | 15 yrs., 8 mos.4 | 5/18/2008 | 1,401 | ||||||||
William B. Sansom | 5/18/2009 | 3 yrs., 1 mo. | – | 5 | – | 5 | ||||||
Howard A. Thrailkill | 5/18/2010 | 4 yrs., 1 mo. | – | 5 | – | 5 | ||||||
Susan Richardson Williams | 5/18/2007 | 1 yr., 1 mo. | – | 5 | – | 5 |
Notes | ||
(1) | Assumes each director will continue to serve through the expiration of his or her respective current term without reappointment. | |
(2) | Earliest date each director will become eligible to receive an unreduced retirement benefit. Directors may be eligible for a reduced benefit at an earlier date. | |
(3) | Assumes there will be no change in the amount shown in the “Annual Stipend” column in the Director Compensation Table in 2006 and all subsequent years. In the case of Ms. Harris and Mr. Baxter, the highest average of salary during three consecutive plan years is based on the salaries received while serving as full-time directors. | |
(4) | Includes seven years and two months of prior federal service. | |
(5) | The director will not meet mandatory vesting requirements prior to the expiration of his or her term and will not be eligible to receive a retirement benefit under the FERS Basic Benefit Plan. |
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Annual Compensation | Long-Term Compensation | |||||||||||||||||||||||
Payouts | ||||||||||||||||||||||||
Other Annual | All Other | |||||||||||||||||||||||
Salary | Bonus1 | Compensation 2 | LTIP Payouts3 | Compensation4 | ||||||||||||||||||||
Name and Principal Position | Year | ($) | ($) | ($) | ($) | ($) | ||||||||||||||||||
Tom D. Kilgore President and Chief Executive Officer | 2006 | 140,000 | 334,152 | 5 | 511,984 | 293,709 | 6 | 306,300 | 7 | |||||||||||||||
Karl W. Singer Chief Nuclear Officer and Executive Vice President, TVA Nuclear | 2006 | 140,000 | 283,382 | 426,723 | 8 | 216,893 | 206,300 | 9 | ||||||||||||||||
Ashok S. Bhatnagar Senior Vice President, Nuclear Operations | 2006 | 140,000 | 210,007 | 321,470 | 10 | 140,641 | 153,705 | 11 | ||||||||||||||||
Joseph R. Bynum Executive Vice President, Fossil Power Group | 2006 | 140,000 | 154,540 | 275,066 | 124,713 | 150,269 | 12 | |||||||||||||||||
Michael E. Rescoe13 Chief Financial Officer and Executive Vice President, Financial Services | 2006 | 140,000 | 195,075 | 5 | 286,109 | 100,021 | 6 | 6,300 | 14 |
Notes | ||
(1) | Represents actual amount awarded under the EAIP except as noted otherwise. Under the EAIP, incentive opportunities (represented as a percentage of each participant’s base compensation) are established for each position based on opportunities provided for comparable positions in the energy services industry. Actual incentive awards are tied to the achievement of predefined corporate and business unit performance goals established each fiscal year and identified in TVA’s Winning Performance Balanced Scorecards. Payments pursuant to the EAIP are made during the first quarter of the succeeding fiscal year for performance in the year indicated. | |
(2) | Represents additional annual compensation paid in quarterly payments unless otherwise noted. | |
(3) | Represents actual amount awarded under the ELTIP except as noted otherwise. Under the ELTIP, incentive opportunities (represented as a percentage of each participant’s base compensation) are established for each position based on opportunities provided for comparable positions in the energy services industry. Actual incentive awards are tied to the achievement of predefined corporate performance goal(s). Payments pursuant to the ELTIP are made during the first quarter of the fiscal year following the end of the performance cycle. | |
(4) | Represents annual deferred compensation credits provided under Long-Term Deferred Compensation Plan (“LTDCP”) agreements and/or employer matching contributions to the TVA Retirement System’s 401(k) plan. Agreements administered under the LTDCP are designed to provide retention incentives to executives to encourage them to remain with TVA and to provide, in combination with ELTIP incentive awards, a competitive level of total direct compensation. Under the agreements, credits are made to an account in an executive’s name (typically on an annual basis) for a predetermined length of time (typically five years) after which the executive becomes vested in the balance of the account, including interest and/or return on investment, and receives a distribution in accordance with an earlier deferral election. | |
(5) | Represents the estimated amount to be awarded under the EAIP but not yet paid. | |
(6) | Represents the estimated amount to be awarded under the ELTIP but not yet paid. | |
(7) | Includes a $300,000 annual deferred compensation credit provided under a LTDCP agreement and $6,300 in employer matching contributions to the TVA Retirement System’s 401(k) plan based on Mr. Kilgore’s elective contribution. | |
(8) | Includes $341,323 in additional annual compensation paid in quarterly installments, $5,400 in vehicle allowance payments (paid at the rate of $450 every two weeks beginning April 2006), and an approved $80,000 in deferred compensation awarded for achievement of major milestone objectives established in conjunction with the Browns Ferry Unit 1 recovery project but not yet paid. | |
(9) | Includes a $200,000 annual deferred compensation credit provided under a LTDCP agreement and $6,300 in employer matching contributions to the TVA Retirement System’s 401(k) plan based on Mr. Singer’s elective contribution. | |
(10) | Includes $276,070 in additional annual compensation paid in quarterly installments, $5,400 in vehicle allowance payments (paid at the rate of $450 every two weeks beginning April 2006), and an approved $40,000 in deferred compensation awarded for achievement of major milestone objectives established in conjunction with the Browns Ferry Unit 1 recovery project but not yet paid. | |
(11) | Includes a $150,000 annual deferred compensation credit provided under a LTDCP agreement and $3,705 in employer matching contributions to the TVA Retirement System’s 401(k) plan based on Mr. Bhatnagar’s elective contribution. | |
(12) | Includes a $150,000 annual deferred compensation credit provided under a LTDCP agreement and $269 in employer matching contributions to the TVA Retirement System’s 401(k) plan based on Mr. Bynum’s elective contribution. | |
(13) | Mr. Rescoe left TVA effective November 13, 2006. | |
(14) | Represents $6,300 in employer matching contributions to the TVA Retirement System’s 401(k) plan based on Mr. Rescoe’s elective contribution. |
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Estimated Future Payouts Under Non Stock | ||||||||||||||||
Price Based Plan2 | ||||||||||||||||
Performance or Other | ||||||||||||||||
Period Until Maturation | Threshold | Target | Maximum | |||||||||||||
Name | Payout1 | ($) | ($) | ($) | ||||||||||||
Tom D. Kilgore | 3 Years | 292,500 | 390,000 | 487,500 | ||||||||||||
Karl W. Singer | 3 Years | 216,000 | 288,000 | 360,000 | ||||||||||||
Ashok S. Bhatnagar | 3 Years | 140,063 | 186,750 | 233,438 | ||||||||||||
Joseph R. Bynum | 3 Years | 124,200 | 165,600 | 207,000 | ||||||||||||
Michael E. Rescoe | 3 Years | 99,610 | 132,813 | 166,016 |
Notes | ||
(1) | While originally designed to cover three-year performance cycles, the plan has been administered as an annual incentive. | |
(2) | The awards were or are to be paid in cash in the first quarter of 2007 and are reported under the column titled “LTIP Payouts” in the Summary Compensation Table. |
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Estimated Monthly Retirement Benefit1 | ||||
Name | ($) | |||
Tom D. Kilgore | 345 | 2 | ||
Karl W. Singer | 1,671 | 3 | ||
Ashok S. Bhatnagar | 958 | 3 | ||
Michael E. Rescoe | 0 | 4 |
Notes | ||
(1) | These estimates represent the maximum benefit and are not reduced for any survivor options available under the plan. Except for Mr. Rescoe, the estimates are based on the following assumption: the annual salary amounts reported in the Summary Compensation Table are used for fiscal year 2006 and all subsequent years. | |
(2) | Represents the estimated monthly retirement benefit payable at the earliest date Mr. Kilgore will be eligible to receive an immediate benefit (March 3, 2010). This estimated benefit reflects a monthly pension benefit only. Mr. Kilgore will not be eligible to receive a supplemental benefit at the earliest date he becomes eligible to receive an immediate pension benefit since he will not have the required 10 years of creditable service. | |
(3) | Represents the estimated monthly retirement benefit at age 55 for Mr. Singer and Mr. Bhatnagar, which includes the combined monthly pension benefit and the monthly supplemental benefit. | |
(4) | Mr. Rescoe left TVA in November 2006 and did not have the minimum five years of creditable service required to become vested and receive a retirement benefit under the CBBS or to receive a supplemental benefit. |
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Years of Creditable Service | ||||||||||||||||||||
Remuneration1 | 5 | 10 | 15 | 20 | 24 and >2 | |||||||||||||||
($) | ($) | ($) | ($) | ($) | ($) | |||||||||||||||
150,000 | 18,750 | 37,500 | 56,250 | 75,000 | 90,000 | |||||||||||||||
200,000 | 25,000 | 50,000 | 75,000 | 100,000 | 120,000 | |||||||||||||||
300,000 | 37,500 | 75,000 | 112,500 | 150,000 | 180,000 | |||||||||||||||
400,000 | 50,000 | 100,000 | 150,000 | 200,000 | 240,000 | |||||||||||||||
500,000 | 62,500 | 125,000 | 187,500 | 250,000 | 300,000 | |||||||||||||||
600,000 | 75,000 | 150,000 | 225,000 | 300,000 | 360,000 | |||||||||||||||
700,000 | 87,500 | 175,000 | 262,500 | 350,000 | 420,000 | |||||||||||||||
800,000 | 100,000 | 200,000 | 300,000 | 400,000 | 480,000 | |||||||||||||||
900,000 | 112,500 | 225,000 | 337,500 | 450,000 | 540,000 | |||||||||||||||
1,000,000 | 125,000 | 250,000 | 375,000 | 500,000 | 600,000 | |||||||||||||||
1,100,000 | 137,500 | 275,000 | 412,500 | 550,000 | 680,000 | |||||||||||||||
1,200,000 | 150,000 | 300,000 | 450,000 | 600,000 | 720,000 |
Notes | ||
(1) | Represents the highest average of compensation during any three consecutive SERP years (for benefit calculation purposes, compensation includes the combined amounts reported under the columns titled“Salary”and“Bonus,”and additional annual compensation which is reported under the column titled“Other Annual Compensation”in the Summary Compensation Table). | |
(2) | Maximum benefit received at 24 years – no increase in benefits beyond 24 years of service. |
Remuneration | Creditable1 | |||||||
Named Officer | ($) | Service | ||||||
Tom D. Kilgore | 984,152 | 2 | <2 | |||||
Karl W. Singer | 737,806 | 3 | 14 | |||||
Ashok S. Bhatnagar | 587,350 | 7 | ||||||
Joseph R. Bynum | 607,997 | 24 | ||||||
Michael E. Rescoe4 | NA | NA |
Notes | ||
(1) | Limited to 24 years when determining supplemental benefits available under TVA’s SERP. | |
(2) | Mr. Kilgore will be granted three additional years of creditable service for pre-TVA employment following five years of actual TVA service. In the event his employment is terminated during the first five years (other than for cause), the five year vesting requirement will be waived and he will receive credit for eight years of service. In addition, the Prior Employer Offset will be waived and the Qualified Plan Offset will be calculated based on the actual pension benefit he will receive as a participant in TVA’s CBBS. | |
(3) | TVA has agreed to grant Mr. Singer up to six additional years of creditable service at the rate of one year’s service for each year of TVA service, beginning August 17, 2006 (age 50), and continuing through August 17, 2011 (age 55). | |
(4) | Mr. Rescoe left TVA in November 2006 and did not have the minimum five years of creditable service required to become vested and receive a retirement benefit under TVA’s SERP. |
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2006 | 2005 | |||||||
Audit Fees(1) | $ | 1,110,742 | $ | 948,393 | ||||
Audit-Related Fees(2) | 273,368 | 514,706 | ||||||
All Other Fees (3) | 14,000 | – | ||||||
Total | $ | 1,398,110 | $ | 1,463,099 | ||||
Notes | ||
1. | Audit fees consist of professional services rendered for the audit of TVA’s annual financial statements, the review of the interim financial statements included in TVA’s quarterly reports, and fees for Bond offering comfort letters. | |
2. | Audit-related fees are fees for services which are usually performed by the auditor and consist primarily of accounting assistance on proposed transactions and accounting standards, accounting assistance related to reviewing internal control over financial reporting, and assistance in preparing for TVA’s initial Form 10-K filing. | |
3. | All other fees relate to in-house training of TVA personnel. |
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(1) | Financial Statements. The following documents are provided in Item 8 herein. | ||
Statements of Income Balance Sheets Statements of Cash Flow Statements of Changes in Proprietary Capital Notes to Financial Statements Report of Independent Registered Public Accounting Firm (PricewaterhouseCoopers LLP) | |||
(2) | Financial Statement Schedules. | ||
Schedules not included are omitted because they are not required or because the required information is provided in the financial statements, including the notes thereto. |
Additions | ||||||||||||||||
Balance at | charged to | Balance at | ||||||||||||||
Description | beginning of year | expense | Deductions | end of year | ||||||||||||
For the year ended September 30, 2006 Allowance for doubtful accounts | ||||||||||||||||
Receivables | $ | 7 | $ | 4 | $ | – | $ | 11 | ||||||||
Loans | 15 | 1 | (1 | ) | 15 | |||||||||||
Inventories | 36 | 13 | (11 | ) | 38 | |||||||||||
Total allowances deducted from assets | $ | 58 | $ | 18 | $ | (12 | ) | $ | 64 | |||||||
For the year ended September 30, 2005 Allowance for doubtful accounts | ||||||||||||||||
Receivables | $ | 8 | $ | – | $ | (1 | ) | $ | 7 | |||||||
Loans | 14 | 1 | – | 15 | ||||||||||||
Inventories | 36 | 15 | (15 | ) | 36 | |||||||||||
Total allowances deducted from assets | $ | 58 | $ | 16 | $ | (16 | ) | $ | 58 | |||||||
For the year ended September 30, 2004 Allowance for doubtful accounts | ||||||||||||||||
Receivables | $ | 8 | $ | – | $ | – | $ | 8 | ||||||||
Loans | 14 | – | – | 14 | ||||||||||||
Inventories | 33 | 11 | (8 | ) | 36 | |||||||||||
Total allowances deducted from assets | $ | 55 | $ | 11 | $ | (8 | ) | $ | 58 | |||||||
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3.1 | Tennessee Valley Authority Act of 1933,as amended, 16 U.S.C. §§ 831-831ee (2000 & Supp. IV 2004) | |
3.2 | By-laws of Tennessee Valley Authority Adopted by the TVA Board of Directors on May 18, 2006 | |
4.1 | Basic Tennessee Valley Authority Power Bond Resolution Adopted by the TVA Board of Directors on October 6, 1960, as amended on September 28, 1976, October 17, 1989, and March 25, 1992 | |
10.1 | $1,250,000,000 Fall Maturity Credit Agreement Dated as of May 17, 2006, as Amended, Among TVA, Bank of America, N.A., as Administrative Agent, Bank of America, N.A., as a Lender, and the Other Lenders Party Thereto | |
10.2 | $1,250,000,000 Spring Maturity Credit Agreement Dated as of May 17, 2006, Among TVA, Bank of America, N.A., as Administrative Agent, Bank of America, N.A., as a Lender, and the Other Lenders Party Thereto | |
10.3 | TVA Discount Notes Selling Group Agreement | |
10.4 | Electronotes® Selling Agent Agreement Dated as of June 1, 2006, Among TVA, LaSalle Financial Services, Inc., A.G. Edwards & Sons, Inc., Citigroup Global Markets Inc., Edward D. Jones & Co., L.P., First Tennessee Bank National Association, J.J.B. Hilliard, W.L. Lyons, Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley & Co. Incorporated, and Wachovia Securities, LLC | |
10.5 | Commitment Agreement Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA Dated as of November 19, 2003 | |
10.6 | Power Contract Supplement No. 95 Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA Dated as of November 19, 2003 | |
10.7 | Void Walk Away Agreement Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA dated as of November 20, 2003 | |
10.8 | Power Contract Supplement No. 96 Among Memphis Light, Gas and Water Division, the City of Memphis, Tennessee, and TVA dated as of November 20, 2003 | |
10.9 | Overview of TVA’s September 26, 2003, Lease and Leaseback of Control, Monitoring, and Data Analysis Network with Respect to TVA’s Transmission System in Tennessee, Kentucky, Georgia, and Mississippi | |
10.10* | Participation Agreement Dated as of September 22, 2003, Among (1) TVA, (2) NVG Network I Statutory Trust, (3) Wells Fargo Delaware Trust Company, Not in Its Individual Capacity, Except to the Extent Expressly Provided in the Participation Agreement, But as Owner Trustee, (4) Wachovia Mortgage Corporation, (5) Wilmington Trust Company, Not in Its Individual Capacity, Except to the Extent Expressly Provided in the Participation Agreement, But as Lease Indenture Trustee, and (6) Wilmington Trust Company, Not in Its Individual Capacity, Except to the Extent Expressly Provided in the Participation Agreement, But as Pass Through Trustee | |
10.11* | Network Lease Agreement Dated as of September 26, 2003, Between NVG Network I Statutory Trust, as Owner Lessor, and TVA, as Lessee | |
10.12* | Head Lease Agreement Dated as of September 26, 2003, Between TVA, as Head Lessor, and NVG Network I Statutory Trust, as Head Lessee | |
10.13* | Leasehold Security Agreement Dated as of September 26, 2003, Made by NVG Network I Statutory Trust to TVA | |
10.14 | Description of Compensation of TVA’s Directors and Named Executive Officers | |
10.15† | Tennessee Valley Authority Supplemental Executive Retirement Plan, Effective as of October 1, 1995 | |
10.16† | Tennessee Valley Authority Executive Annual Incentive Plan, Effective in Fiscal Year 1999 |
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10.17† | Tennessee Valley Authority Executive Long-Term Incentive Plan, Effective in Fiscal Year 1999 | |
10.18† | Tennessee Valley Authority Long Term Deferred Compensation Plan | |
10.19† | Employment Contract Between TVA and Tom D. Kilgore Dated as of January 19, 2005 | |
10.20† | Employment Contract Between TVA and Michal E. Rescoe Dated as of April 21, 2004 | |
10.21† | First Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as of September 28, 2004 | |
10.22† | Second Deferral Agreement Between TVA and Ashok S. Bhatnagar Dated as of September 28, 2004 | |
10.23† | Deferral Agreement Between TVA and Joseph R. Bynum Dated as of March 3, 2004 | |
10.24† | Deferral Agreement Between TVA and Tom D. Kilgore Dated as of March 29, 2005 | |
10.25† | First Deferral Agreement Between TVA and Karl W. Singer Dated as of May 7, 2004 | |
10.26† | Second Deferral Agreement Between TVA and Karl W. Singer Dated as of May 7, 2004 | |
14 | Disclosure and Financial Ethics Code | |
31.1 | Rule 13a-14(a)/15d-14(a) Certification Executed by the Chief Executive Officer | |
31.2 | Rule 13a-14(a)/15d-14(a) Certification Executed by the Chief Financial Officer | |
32.1 | Section 1350 Certification Executed by the Chief Executive Officer | |
32.2 | Section 1350 Certification Executed by the Chief Financial Officer |
† | Management contract or compensatory arrangement. | |
* | Certain schedules and exhibits have been omitted. The Tennessee Valley Authority hereby undertakes to furnish supplementally copies of any of the omitted schedules and exhibits upon request by the Securities and Exchange Commission. |
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Date: December 15, 2006 | TENNESSEE VALLEY AUTHORITY (Registrant) | |||||
By: | /s/ Tom D. Kilgore | |||||
Tom D. Kilgore | ||||||
President and Chief Executive Officer | ||||||
(Principal Executive Officer) |
Signature | Title | Date | ||
/s/ Tom D. Kilgore | President and Chief Executive Officer (Principal Executive Officer) | December 15, 2006 | ||
/s/ John M. Hoskins | Interim Chief Financial Officer & Executive Vice President, Financial Services (Principal Financial Officer) | December 15, 2006 | ||
/s/ Randy Trusley | Vice President and Controller (Principal Accounting Officer) | December 15, 2006 | ||
/s/ William B. Sansom | Chairman and Director | December 15, 2006 | ||
/s/ Dennis C. Bottorff | Director | December 15, 2006 | ||
/s/ Donald R. DePriest | Director | December 15, 2006 | ||
/s/ Robert M. Duncan | Director | December 15, 2006 | ||
/s/ Bishop William Graves | Director | December 15, 2006 | ||
/s/ Skila S. Harris | Director | December 15, 2006 | ||
/s/ Howard A. Thrailkill | Director | December 15, 2006 | ||
/s/ Susan Richardson Williams | Director | December 15, 2006 |
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