This Annual Report on Form 10-K ("Annual Report") contains forward-looking statements relating to future events and future performance. All statements other than those that are purely historical may be forward-looking statements. In certain cases, forward-looking statements can be identified by the use of words such as “may,” “will,” “should,” “expect,” “anticipate,” “believe,” “intend,” “project,” “plan,” “predict,” “assume,” “forecast,” “estimate,” “objective,” “possible,” “probably,” “likely,” “potential,” "speculate," or other similar expressions.

Although the Tennessee Valley Authority ("TVA") believes that the assumptions underlying the forward-looking statements are reasonable, TVA does not guarantee the accuracy of these statements. Numerous factors could cause actual results to differ materially from those in the forward-looking statements. These factors include, among other things:

TVA does not own real property. TVA acquires real property in the name of the United States, and such legal title in real property is entrusted to TVA as the agent of the United States to accomplish the purpose of the Tennessee Valley Authority Act of 1933, as amended, 16 U.S.C. §§ 831-831ee (as amended, the “TVA Act”). TVA acquires personal property in the name of TVA. Accordingly, unless the context indicates the reference is to TVA’s personal property, any statement in this Annual Report referring to TVA property shall be read as referring to the real property of the United States which has been entrusted to TVA as its agent.

TVA's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports are available on TVA's web site, free of charge, as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission ("SEC"). TVA's web site is www.tva.gov. Information contained on TVA’s web site shall not be deemed to be incorporated into, or to be a part of, this ~~Quarterly~~Annual Report. TVA's SEC reports are also available to the public without charge from the web site maintained by the SEC at www.sec.gov.

The Tennessee Valley Authority ("TVA") is a corporate agency and instrumentality of the United States ("U.S.") that was created in 1933 by legislation enacted by the U.S. Congress in response to a request by President Franklin D. Roosevelt. TVA was created to, among other things, improve navigation on the Tennessee River, reduce the damage from destructive flood waters within the Tennessee River system and downstream on the lower Ohio and Mississippi Rivers, further the economic development of TVA’s service area in the southeastern United States, and sell the electricity generated at the facilities TVA operates.

Today, TVA operates the nation’s largest public power system and supplies power in most of Tennessee, northern Alabama, northeastern Mississippi, and southwestern Kentucky and in portions of northern Georgia, western North Carolina, and southwestern Virginia to a population of over nine million people. In ~~2012~~2013, the revenues generated from TVA’s electricity sales were $~~11.1~~10.8 billion and accounted for virtually all of TVA’s revenues.

TVA manages the Tennessee River, its tributaries, and certain shorelines to provide, among other things, year-round navigation, flood damage reduction, and affordable and reliable electricity. Consistent with these primary purposes, TVA also manages the river system to provide recreational opportunities, adequate water supply, improved water quality, natural resource protection, and economic development. TVA performs these management duties in cooperation with other federal and state agencies which have jurisdiction and authority over certain aspects of the river system. ~~The~~In addition, the TVA Board of Directors (the "TVA Board") ~~also~~ established ~~a council under~~two councils--the Regional Resource Stewardship Council ("RRSC") and the Regional Energy Resource Council--under the Federal Advisory Council Act to advise TVA on its energy resource activities and its stewardship ~~activities. TVA’s stewardship responsibilities are conducted within~~activities in the Tennessee watershed, whose boundaries are similar to, though not exactly the same as, the TVA service area. TVA’s management of the Tennessee River, its tributaries, and certain shorelines is sometimes referred to as TVA’s “stewardship” program in this Annual Report.Valley.

The area in which TVA sells power, its service area, is defined by the TVA Act. Under the TVA Act, subject to certain minor exceptions, TVA may not, without specific authorization from the U.S. Congress, enter into contracts that would have the effect of making it, or the ~~distributor customers~~local power company customer of TVA ("LPC") which distribute its power, a source of power supply outside the area for which TVA or its ~~distributor customers~~LPCs were the primary source of power supply on July 1, 1957. This provision is referred to as the “fence” because it bounds TVA’s sales activities, essentially limiting TVA to power sales within a defined service area.

TVA is primarily a wholesaler of power. It sells power to ~~distributor customers~~LPCs which then resell power to their customers at retail rates. TVA’s ~~distributor customers~~LPCs consist of (1) municipalities and other local government entities ~~(referred to collectively below as "municipalities"~~("municipalities") and (2) customer-owned

Revenues from ~~distributor customers~~LPCs accounted for 8586 percent of TVA’s total operating revenues in ~~2012~~2013. At September 30, ~~2012~~2013, TVA had wholesale power contracts with 155 ~~municipalities and cooperatives.~~LPCs. Each of these contracts requires ~~distributor customers~~the LPCs to purchase from TVA all of ~~their~~its electric power and energy consumed within the TVA service area.

The number of ~~distributor customers~~LPCs with the contract arrangements described above, the revenues derived from such arrangements in ~~2012~~2013, and the percentage of TVA’s ~~2012~~2013 total operating revenues represented by these revenues are summarized in the table below.

TVA’s two largest ~~distributor customers~~LPCs — Memphis Light, Gas and Water Division ("MLGW") and Nashville Electric Service ("NES") — have contracts with five-year and 10-year termination notice periods, respectively. Although no single customer accounted for 10 percent or more of TVA’s total operating revenues in ~~2012~~2013, sales to MLGW and NES accounted for nine percent and eight percent, respectively.

Revenues from directly served industrial customers accounted for 1311 percent of TVA’s total operating revenues in ~~2012~~2013. Contracts with these customers are subject to termination by the customer or TVA upon a minimum notice period that varies according to the customer’s contract demand and the period of time service has been provided.

The United States Enrichment Corporation ("USEC"), a subsidiary of USEC, Inc., iswas TVA’s largest directly served industrial customer. ~~Sales to~~On May 24, 2013, USEC ~~for~~announced the cessation of enrichment activities at its Paducah, Kentucky ~~facility~~site. TVA and USEC have subsequently completed agreements to extend power sales to facilitate the cessation of enrichment activities and to support non-enrichment activities at the site at a greatly reduced level. These sales arrangements may continue to be extended. Power sales to USEC represented three percent and five percent of ~~TVA’s~~TVA's total operating revenues in for the years ended September 30, 2013, and 2012,~~. TVA's power supply commitments to USEC end on May 31, 2013.~~ respectively.

In view of demand for electricity, ~~and~~ the level of competition, and other relevant factors, it is reasonable to assume that rates, set at levels that will recover ~~TVA’s~~TVA's costs, can be charged and collected from customers. Further, the TVA Board has the discretion to determine when costs will be recovered in rates. As a result of these factors, TVA records certain assets and liabilities that result from the self-regulated ratemaking process that could not otherwise be so recorded under accounting principles generally accepted in the United States. See Note 1 — Cost-Based Regulationand Note 7.

In setting rates to cover the costs set out in the TVA Act, TVA uses a wholesale rate structure that is comprised of a base rate and a fuel rate that is automatically determined by the operation of the fuel cost adjustment formula each month. In setting the base rates, TVA uses a debt-service coverage ("DSC") methodology to derive annual revenue requirements in a manner similar to that used by other public power entities that also use the DSC rate methodology. Under the DSC methodology, rates are calculated so that an entity will be able to cover its operating costs and to satisfy its obligations to pay principal and interest on debt. This ratemaking approach is particularly suitable for use by entities financed primarily, if not entirely, by debt capital, such as TVA.

~~TVA’s~~TVA's wholesale and retail rate structures include time-of-use ("TOU") and seasonal demand and energy ("SDE") rate structures. These rate structures provide price signals intended to incentivize ~~distributor~~LPCs and end-use customers to shift energy usage from high-cost generation periods to less expensive generation periods. The rates are intended to more closely align TVA's revenues with its costs.

~~Additionally, TVA’s rates include an adjustment to fund investment in equipment associated with TVA's clean air program. This adjustment was approved by~~On August 22, 2013, the TVA Board approved a five-year extension of the environmental adjustment (which commenced in ~~August 2003~~2004), which reflects the need to collect revenue for environmental expenditures to further TVA's environmental performance, as well as comply with new, more stringent air, water, and ~~is scheduled to terminate in September 2013.~~

Nuclear Reactor Licensing. On August 7, 2012, the NRC suspended final decisions on nuclear reactor licensing in response to a ruling by the the U.S. Court of Appeals for the District of Columbia Circuit ~~which~~("D.C. Circuit") that vacated the NRC's Waste Confidence Decision ("WCD") relating to the environmental impact of the long-term storage of nuclear waste. On September 6, 2012, in response to the ruling, the ~~Commission~~NRC directed the NRC staff to develop a generic Environmental Impact Statement ("EIS") to support an updated WCD rule, maintaining the option for the staff to conduct some analyses of waste confidence issues on a site-specific ~~basis.~~basis, if necessary. Licensing reviews and proceedings may currently continue, but final licenses will not be issued until the NRC completes its reassessment of the environmental impacts of the storage of nuclear waste. The delay of licensing decisions by the NRC could affect the unit currently under construction at Watts Bar Unit 2, the proposed construction atof Bellefonte Unit 1, and the renewal of the licenses for the two units at Sequoyah. All of the procedures and inspections that happen prior to licensing will continue as usual.

Operational Challenges. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations — ~~Key Initiatives~~Liquidity and Capital Resources — Liquidity Challenges —Related to Generation Resources, ~~and~~ ~~Regulatory Compliance~~.which discussion is incorporated herein by reference.

Other Nuclear Matters. See Fuel Supply — Nuclear Fuel below for a discussion of spent nuclear fuel and low-level

Conventional Hydroelectric Dams. TVA maintains 29 conventional hydroelectric dams with 109 generating units throughout the Tennessee River system and one pumped-storage facility for the production of electricity. At September 30, ~~2012~~2013, these units accounted for ~~5,447~~5,433 MW of summer net capability. The amount of electricity that TVA is able to generate from its hydroelectric plants depends on a number of factors, including the amount of precipitation and runoff, initial water levels, and the need for water for competing water management objectives. The amount of electricity generated also depends on the availability of TVA's hydroelectric generation plants. When these factors are unfavorable, TVA must increase its reliance on higher cost generation plants and purchased power. In addition, four hydroelectric dams owned by a third party on the Little Tennessee River and eight U.S. Army Corps of Engineers dams on the Cumberland River contribute to the TVA power system. See Weather and Seasonality.

Raccoon Mountain Pumped-Storage Plant. The four units at Raccoon Mountain were placed in service ~~between~~during 1978 and 1979. The units, with a total net summer capability of 1,616 MW, are utilized to balance the transmission system as well as generate power.

At September 30, ~~2012~~2013, TVA operated 98 combustion turbine power blocks, 87 simple-cycle units ~~87 of which were simple-cycle~~ and 11 ~~of which were combined-cycle.~~ combined-cycle power blocks. The 87 simple-cycle units provide a maximum of 5,388 MW of summer net capability. The 11 combined-cycle ~~units~~power blocks provide a maximum of 3,854 MW of summer net capability. Eighty of the simple-cycle units and one combined-cycle ~~unit~~power block are fueled by either natural gas or fuel oil. The remaining seven simple-cycle units as well as the 10 combined-cycle ~~units~~power blocks are fueled by natural gas only. Seventy-six of the simple-cycle units are capable of quick-start response allowing full generation capability in approximately 10 minutes. TVA uses simple-cycle units as peaking or backup units. See Item 2, Properties — Generating Properties for a discussion of lease arrangements into which TVA has entered in connection with certain of the combustion turbine units. Because of TVA's strategy of portfolio diversification and reducing air emissions, TVA may decide to make further strategic investments in natural gas-fired facilities in the future by purchase, construction, and/or lease.

In February 2013, TVA ~~has two~~sold its diesel ~~generator plants consisting~~generators located in Albertville, Alabama to the city of ~~nine~~ ~~units.~~Albertville. At September 30, ~~2012~~2013, TVA had one diesel generator plant consisting of five units, and these facilities accounted for 139 MW of summer net capability.

TVA acquires power from a variety of power producers through long-term and short-term power purchase agreements as well as through power spot market purchases. During ~~2012~~2013, TVA acquired approximately 1410 percent of the power that it purchased on the power spot market, ~~two~~approximately one percent through short-term power purchase agreements (agreements with a duration of one year or less but longer than the term of ~~spot market~~spot-market purchase), and approximately 8489 percent through long-term power purchase agreements (agreements with a duration of more than one year).

Under federal law, TVA is required to purchase energy from qualifying cogenerators and small power producers at TVA's avoided cost of self-generating or purchasing this energy from another source. AtAs of September 30, ~~2012~~2013, there were ~~eight~~six suppliers, with a combined capacity of ~~918~~913 MW, whose power ~~is purchased by~~ TVA purchases under this law.

AtAs of September 30, ~~2012~~2013, TVA was a party to ~~nine~~contracts with eight wind farms for the purchase of ~~renewable wind~~ energy. Energy is currently provided to TVA under ~~seven of the nine~~all contracts. The first began providing 300 MW (nameplate capacity) under a ~~twenty year~~twenty-year contract from a wind farm in Illinois in May 2010. TVA currently does not purchase the renewable attributes for this energy but has the opportunity to ~~attain~~obtain them in the future. The other ~~six~~seven contracts provide TVA with an additional ~~850~~1,215 MW (nameplate capacity) that include renewable attributes. These wind farms are located in Illinois, Kansas, and Iowa. ~~The remaining two 20-year wind contracts will provide up to an additional~~ ~~365~~ ~~MW (nameplate capacity) of renewable energy from wind farms located in Illinois and Kansas. These wind farms are under construction with expected deliveries beginning in 2013.~~ TVA may work with counterparties to renegotiate or even terminate existing arrangements based on its evaluation of the economics of the contracts given that bringing power from distant locations raises transmission issues and costs.

Watts Bar Unit 2. On August 1, 2007, the TVA Board approved the completion of Watts Bar Unit 2, which is expected to be completed in CY 2015 and to provide approximately 1,180 MW of summer net capability. The work on Watts Bar Unit 2 is continuing within the schedule and budget expectations approved by the TVA Board in April 2012. The current construction ~~permits expire~~permit expired in ~~2013 and an~~March 2013. An extension ~~request~~to the permit has been ~~submitted~~requested and, by regulation, work is allowed to proceed. An extended construction permit is expected to be received from the ~~NRC.~~NRC in the first quarter of 2014. The unit was approximately 80 percent complete at September 30, 2013.

For a discussion of legal proceedings related to Watts Bar Unit 2, see Note 20 — Legal Proceedings — Case Involving the NRC Waste Confidence Decision on Spent Nuclear Fuel Storage and Administrative Proceedings Regarding Watts Bar ~~Nuclear Plant~~ Unit 2.

Bellefonte ~~Units~~Unit 1 ~~and 2~~. The ~~TVA Board's approval~~incorporation of ~~the construction of~~Watts Bar Unit 2 lessons learned into the Bellefonte Nuclear Plant ("Bellefonte")Unit 1 ~~project in August 2011 provided that construction of~~completion estimate has revealed some similar problems and inaccuracies. TVA finalized a new estimate to complete Bellefonte Unit 1 will not begin until after initial fuel loading at Watts Bar Unit 2. Bellefonte Unit 1 was expected to be completed in 2020 and to provide approximately 1,260 MW of summer net capability. As a result of lessons learned during the ~~construction~~first quarter of ~~Watts Bar Unit 2 and other factors, such as~~2014 putting the ~~Fukushima events, TVA is analyzing the Bellefonte Unit 1 cost and schedule. It is expected that the~~total estimated cost of completion in the ~~project will increase~~range of $7.5 billion and ~~the completion date will change. In the event of significant changes TVA will seek action from the TVA Board. See~~ ~~Note 20~~ — ~~Legal Proceedings~~ ~~— Case Regarding Bellefonte Nuclear Plant Units 1 and 2~~. The construction permits for Bellefonte Units 1 and 2 currently extend until 2020 and 2014, respectively. Bellefonte's construction permits are currently in deferred plant status. TVA will provide notice to the NRC at least four months in advance of activating construction. Asset-preservation and equipment-maintenance activities for Units 1 and 2 are continuing$8.7 billion. Work at the site has been slowed to better allocate resources on nearer-term priorities as ~~well as Unit 1 engineering design work, detailed plant system physical reviews,~~both budget and ~~assessments. It is possible~~staffing levels for the project have been reduced in the 2014 budget. TVA believes that the ~~final licensing of this new unit could~~resulting budgeting and staffing levels should be ~~impacted by the NRC suspension of final decisions on nuclear reactor licensing that began August 7, 2012.~~

Other Nuclear Initiatives. In November 2012, the Department of Energy ("DOE") announced a grant award to Babcock & Wilcox ("B&W"), in conjunction with TVA ~~signed a letter of intent to begin evaluating a site~~ and ~~perform studies~~Bechtel, for small modular ~~reactor(s)~~reactor ("SMR") at its Clinch River site in Oak Ridge, Tennessee. TVA notified the NRC in August 2010 that it intends to submit a construction permit application. The SMR would have a scalable, modular design allowing utilities to add electricaldevelopment. See

Extended Power Uprate. TVA is undertaking an Extended Power Uprate ("EPU") project at Browns Ferry ~~which~~that is expected to increase the amount of electrical generation by increasing the amount of steam produced by the reactors. Additional fuel would be added to the reactors during each refueling outage to support the increased steam production. The NRC license for each reactor must be modified to allow reactor operation at the higher power level. TVA has submitted license amendment requests and is currently in discussions with the NRC on selected technical issues affecting EPU licensing. The result of these discussions may impact the amount of power level increase realized by the EPU. Completion of the licensing process will determine the final implementation schedule.

The Solar Solution Initiative ("SSI") is a pilot program that began in February 2012 and provides incentive payments for mid-sized (greater than 50 kW up to 1 MW) solar projects in TVA's RSO program if the projects use local certified installers in the Tennessee Valley region. SSI is a targeted incentive that aims to support the existing local solar industry, while also serving as a recruitment tool for new industry in the Tennessee Valley region, adding investment and jobs. Under this successful program,

Coal consumption at TVA’s coal-fired generating facilities during ~~2012~~2013 and ~~2011~~2012 ~~were~~was approximately 2932 million tons and 3629 million tons, respectively. At September 30, ~~2012~~2013, and ~~2011~~2012, TVA had 2829 days and 2928 days of system-wide coal supply at full burn rate, respectively, with net book values of ~~$402~~$374 million and ~~$404~~$402 million, respectively.

TVA utilizes both short-term and long-term (longer than one year) coal contracts. During ~~2012~~2013, long-term contracts made up 9788 percent of coal purchases and short-term contracts accounted for the remaining ~~three~~12 percent. TVA plans to continue using contracts of various lengths, terms, and coal quality to meet its expected consumption and inventory requirements. During ~~2012~~2013, TVA purchased coal by basin as follows:

Total system coal inventories were at or above target levels for most of ~~2012~~2013 due to lower than planned coal-fired generation. ~~During~~ ~~2012, seven percent of TVA’s~~The following table indicates the delivery methods TVA utilizes for its coal ~~supply was delivered by rail, 20 percent was delivered by barge, and 59 percent was delivered by a combination of barge and rail. The remainder was delivered by truck.~~supply:

During ~~2012~~2013, TVA purchased a significant amount of its natural gas requirements from a variety of suppliers under contracts with terms of ~~one year or less but managed its exposure~~up to ~~spot market volatility through its FTP.~~

~~2011, the~~The net book value of TVA’s natural gas in inventory was $7 million at September 30, 2013, and ~~the~~2012. The net book value of TVA’s fuel oil in inventory was $113 million and $99 million at September 30, 2013, and ~~$77 million,~~2012, respectively. At September 30, ~~2012~~2013, all but 17 of TVA’s combustion turbine units were dual-fuel capable, and TVA has fuel oil stored on each ~~site~~of these sites for its dual-fuel combustion turbines as a backup to natural gas.

Current Fuel Supply. Converting uranium to nuclear fuel generally involves four stages: the mining and milling of uranium ore to produce uranium concentrates; the conversion of uranium concentrates to uranium hexafluoride gas; the enrichment of uranium hexafluoride; and the fabrication of the enriched uranium hexafluoride into fuel assemblies. For its forward five-year ~~(2013-2017)~~(2014-2018) requirements, TVA currently has 100 percent of its uranium mining and milling, conversion services, enrichment services, and fabrication services requirements either in inventory or under contract. TVA anticipates being able to fill its needs beyond this period by normal contracting processes as market forecasts indicate that the fuel cycle components will be readily available.

TVA, the ~~U.S.~~ ~~Department of Energy ("DOE")~~,DOE, and certain nuclear fuel contractors have entered into agreements providing for surplus DOE highly enriched uranium (uranium that is too highly enriched for use in a nuclear power plant) to be blended with other uranium. The enriched uranium that results from this blending process, which is called blended low-enriched uranium ("BLEU"), is fabricated into fuel that can be used in a nuclear power plant. This blended nuclear fuel was first loaded in a Browns Ferry reactor in 2005 and is expected to continue to be used to reload the Browns Ferry reactors through at least 2016. BLEU fuel was loaded into Sequoyah Unit 2 three times but is not expected to be used in ~~CY 2008, CY 2009 and CY 2011.~~the Sequoyah reactors in the future.

Under the terms of an interagency agreement between the DOE and TVA, in exchange for supplying highly enriched uranium materials for processing into usable BLEU fuel for TVA, the DOE participates ~~to a degree~~ in the savings generated by TVA’s use of this blended nuclear fuel. See Note 1 — Blended Low-Enriched Uranium Program for a more detailed discussion of the BLEU project.

TVA owns all nuclear fuel held for its nuclear plants. At September 30, ~~2012~~2013, and ~~2011~~2012, the net book value of this nuclear fuel was ~~$1.2~~$1.3 billion and ~~$1.1~~$1.2 billion, respectively.

Mixed Oxide Nuclear Fuel. Under the DOE Surplus Plutonium Disposition ("SPD") Program, mixed oxide ("MOX") fuel would be fabricated with surplus plutonium and depleted uranium as a replacement for commercial uranium fuel. In February 2010, DOE and TVA entered into an interagency agreement to evaluate the potential use of ~~mixed oxide fuel~~MOX in reactors at Browns Ferry and Sequoyah. As part of the evaluation of MOX, TVA is participating as a cooperating ~~agency.~~ agency in DOE's development of a supplemental EIS that addresses the potential use of MOX fuel in the TVA reactors. TVA could make a decision in ~~2013~~2014 on whether to continue to pursue the use of MOX fuel.At the earliest, based on the expected production rate of MOX, TVA could start using a small number of MOX fuel assemblies in TVA reactors ~~in the 2018 timeframe.~~after 2020. TVA's three criteria for implementing MOX are that it must be environmentally and operationally safe; it must be economical compared to other

Low-Level Radioactive Waste. Low-level radioactive waste ("radwaste") results from the normal operation of nuclear electrical generation units and includes such materials as disposable protective clothing, mops, and filters. TVA ~~has certain types of radwaste processed and shipped to a disposal facility in Clive, Utah. In June 2011, TVA entered into a six year contract to send~~sends shipments of radwaste to ~~a new~~ burial ~~facility~~facilities in Clive, Utah and Andrews, ~~Texas~~. ~~The first shipment occurred in September 2012.~~Texas. TVA ~~also stores~~is capable of storing some radwaste at its own facilities ~~and is capable of storing radwaste at its facilities~~ for an extended period of ~~time.~~time, if necessary.

Spent Nuclear Fuel. Under the Nuclear Waste Policy Act of 1982, TVA (and other domestic nuclear utility licensees) entered into a contract with the DOE for the disposal of spent nuclear fuel. Payments to the DOE are based upon TVA’s nuclear generation and charged to nuclear fuel expense. Although the contracts called for the DOE to begin accepting spent nuclear fuel from the utilities by January 31, 1998, the DOE has yet to establish a permanent disposal site for spent nuclear fuel. TVA, like other nuclear utilities, stores spent nuclear fuel at its nuclear sites. TVA would have had sufficient space to continue to store spent nuclear fuel as originally scheduled in storage pools indefinitely had the DOE begun accepting spent nuclear ~~fuel.~~fuel at the agreed upon time. The DOE’s failure to do so in a timely manner required TVA to construct dry cask storage facilities at Sequoyah and Browns Ferry and to purchase special storage containers for the spent nuclear fuel. The Sequoyah and Browns Ferry dry cask storage facilities have been in use since 2004 and 2005, respectively, and are expected to provide storage capacity through 2026 at Sequoyah and 2018 at Browns Ferry. Watts Bar has sufficient storage capacity in its spent fuel pool to last until approximately 2015. In September 2010, the NRC announced its approval of final revisions to its ~~waste confidence findings and regulations~~WCD expressing the NRC’s confidence that spent nuclear fuel can be safely stored for at least 60 years beyond the licensed life of any reactor and that sufficient repository capacity will be available when necessary. On June 8, 2012, the ~~U.S. Court of Appeals for the District of Columbia~~D.C. Circuit vacated the NRC's WCD relating to the long-term storage of nuclear waste. On September 6, 2012, in response to that ruling, the NRC directed the NRC staff to develop a generic EIS to support an updated WCD rule within 24 months, maintaining the option for the staff to conduct some analyses of waste confidence issues on a site-specific basis. A draft rule and EIS addressing the decision of the D.C. Circuit were issued for public comment in September 2013. Licensing reviews and proceedings may continue, but final licenses will not be issued until the NRC completes its reassessment of the storage of nuclear waste. SeePower Supply — Nuclear Reactor Licensing.

Tritium-Related Services. TVA and the DOE are engaged in a long-term interagency agreement under which TVA will, at the DOE’s request, irradiate tritium producing burnable absorber rods to assist the DOE in producing tritium for the Department of Defense ("DOD"). This agreement, which ends in 2035, requires the DOE to reimburse TVA for the costs that TVA incurs in connection with providing irradiation services and to pay TVA an irradiation services fee at a specified rate per tritium-producing rod over the period when irradiation has occurred.

Weather affects both the demand for and the market prices of electricity. TVA uses degree days to measure the impact of weather on its power operations. Degree days measure the extent to which average temperatures in the five largest cities in TVA's service area vary from 65 degrees Fahrenheit. During ~~2012~~2013, TVA had ~~820,~~735, or 2428 percent, ~~fewer~~more heating degree days and ~~seven,~~354, or ~~0.3~~17 percent, fewer cooling degree days than in ~~2011~~2012.

Strategic guidance for carrying out many of TVA's essential stewardship responsibilities is provided in TVA's Natural Resource Plan ("NRP"),. The NRP, accepted in August 2011, ~~is designed to enhance~~serves as a 20-year guide for TVA's essential stewardship ~~of public recreation facilities,~~efforts in managing biological resources (plants, animals, and aquatic species); cultural resources (archaeological sites, historical sites, and artifacts); recreation; water ~~resources, wildlife and plants, and historic and cultural sites on TVA-managed~~resources; reservoir lands ~~by helping to~~planning; and public engagement. The plan will also guide TVA in achieving the objectives of its Environmental Policy for a more systematic and integrated approach to fulfilling its essential stewardship responsibilities. The NRP was developed with public input including participation from federal and state resource management ~~to better meet public stewardship objectives while responding to~~agencies and the ~~needs~~RRSC. Members of the ~~TVA region’s communities~~RRSC, established in March 2000, represent public and ~~residents. Implementation~~private

Section 37 of the Securities Exchange Act of 1934 (the "Exchange Act") requires TVA to file with the SEC such periodic, current, and supplementary information, documents, and reports as would be required pursuant to section 13 of the Exchange Act if TVA were an issuer of a security registered pursuant to section 12 of the Exchange Act. Section 37 of the Exchange Act exempts TVA from complying with section 10A(m)(3) of the Exchange Act, which requires each member of a listed issuer’s audit committee to be an independent member of the board of directors of the issuer. Since TVA is an agency and instrumentality of

TVA is subject to regulation by the EPA in a variety of areas, including air quality control, water quality control, and management and disposal of ~~hazardous~~solid and wastes. See Environmental Matters.

The Supremacy Clause of the U.S. Constitution prohibits states, without congressional consent, from regulating the manner in which the federal government conducts its activities. As a federal agency, TVA is exempt from regulation, control, and taxation by states except in certain areas ~~such as air and water quality~~ where Congress has ~~given the states limited powers~~clearly made TVA subject to ~~regulate federal activities.~~state regulation. See Environmental Matters.

TVA’s activities and records are also subject to review to varying degrees by other federal entities, including the Government Accountability Office and the Office of Management and Budget ("OMB"). There is also an Office of the Inspector General which reviews TVA’s activities and records.

National Ambient Air Quality Standards. The CAA requires the EPA to set ~~minimum~~ National Ambient Air Quality Standards ("NAAQS") for certain air ~~emissions and the~~pollutants. The EPA has done this for ozone, particulate matter ("PM"), sulfur dioxide ("SO₂"), ~~and~~ nitrogen dioxide ("NO₂")~~. The CAA established two types of NAAQS: (1) primary standards, which set limits to protect public health,~~, carbon monoxide, and (2) secondary standards, which set limits to protect public welfare. Most NAAQS require measurement over a defined period of time (typically one hour, eight hours, twenty-four hours, or one year) to determinelead. Over the ~~average concentration of the pollutant present in a defined geographic area.~~

New Source Review. The NSR provisions of the CAA require ~~persons~~that a permit be obtained prior to constructing new major air emission sources or making major modifications to existing air pollution ~~sources to obtain a permit prior to such construction or modifications.~~sources. Major modifications are non-routine physical or operational changes that increase the emissions from an air emission source above specified thresholds. ~~In order to proceed with a project, the facility must first obtain a permit which requires the identification~~The EPA and ~~implementation of~~ ~~Best Available Control Technology ("BACT")~~ for all regulated air pollutants emitted above the prescribed thresholds and an analysis of the ambient air quality impacts of the new construction or major modification. In 1999, the EPA announced plans toenvironmental groups have been actively ~~pursue~~pursuing NSR enforcement actions against electric utilities ~~for making changes to their coal-fired power plants without obtaining an~~since 1999, alleging that typical plant maintenance activities require NSR permit. Under section 114 of the CAA, the EPA has the authority to request from any person who owns or operates an emission source information and records about operation, maintenance, and emissions as well as other data relating to such source for the purpose of developing regulatory programs, determining if a violation occurred (such as the failure to comply with NSR), or carrying out other statutory responsibilities.permits. If violations are found to have occurred, the EPA or ~~possibly, other~~state enforcement authorities could require the installation of new pollution control equipment and could impose fines and penalties. ~~See Item 1, Business —~~ ~~Current Power Supply~~ — ~~Coal-Fired~~ ~~and~~ ~~Note 20~~ — ~~Legal Proceedings~~ — The Environmental Agreements — ~~John Sevier Fossil Plant Clean Air Act Permit,~~ — ~~Shawnee Fossil Plant Clean Air Act Permit,~~ ~~and~~

Cross State Air Pollution Rule. In July 2011, the EPA announced the final Cross State Air Pollution Rule ("CSAPR"). This rule ~~required by court order,~~ was to replace the existing Clean Air Interstate Rule ("CAIR"), effective January 1, 2012. CSAPR ~~will~~was to regulate SO₂ and NO_x emissions from upwind states that are negatively impacting ozone and fine particulate air quality in downwind states. ~~On October 6, 2011, the EPA proposed revisions to CSAPR which will allow slightly more ozone season NO~~_x ~~emissions in Mississippi, where TVA has purchased a combined-cycle natural gas plant. It also proposed to reduce the~~The rule would have required greater SO₂ and NO_xX ~~allowances allocated to coal-fired plants in Alabama, Kentucky,~~reductions than those achieved under CAIR. However, CSAPR was vacated by the D.C. Circuit and ~~Tennessee to match the more stringent requirements of the Environmental Agreements for the years 2013, 2018, and 2019.~~

Hazardous Air Pollutants from Industrial, Commercial, and Institutional Boilers.In March 2011, the EPA published a final rule to establish standards for hazardous air pollutants emitted from industrial, commercial, and institutional boilers and process heaters. The final rule will have minor impacts beginning in CYthe second quarter of 2014 for some of TVA’s startup and auxiliary ~~boilers. Most~~boilers at its plants. While all plant startup and auxiliary boilers are expected to be exempt from the emission standards due to their limited use, most boilers will ~~require~~be subject to scheduled ~~maintenance~~tuneups to ensure optimized combustion, and ~~a few may require the installation of controls. Concurrently with the issuance of the rule, the EPA announced reconsideration of several elements~~TVA will be required to follow work practice standards in the rule. Until the reconsideration process is completed, final specific requirements are too uncertain to predict. In May 2011, the EPA published a notice in the Federal Register delaying the effective dates of the boiler rule while it was in the process of reconsidering certain aspects of the rule. On January 9, 2012, the U.S. Court of Appealsorder for the ~~District of Columbia Circuit issued a decision vacating and remanding the EPA delay notice. In February 2012, the EPA provided a “no action assurance”~~boilers to the owners and/or operators of industrial boilers with respect to the notification deadlines in the boiler rule. Under the “no action assurance,” the EPA will exercise its discretion not to pursue enforcement for violations of the notification deadlines until either December 31, 2012, or the effective date of a final rule addressing the proposed reconsideration, whichever occurs earlier. The EPA expects to issue final standards by the end of 2012 pending OMB final review.be exempt from emission standards.

Mercury and Air Toxic Standards for Electric Utility Units. Effective April 16, 2012, the EPA promulgated a final rule on establishing standards for hazardous air pollutants emitted from steam electric utilities. The rule requires additional controls for hazardous air pollutants, including mercury, non-mercury metals, and acid gases, for some of TVA’s coal-fired units by ~~the April 2015-2016 timeframe. Boiler combustion systems require scheduled maintenance to ensure optimized combustion to minimize emissions of organic hazardous air pollutants.~~2015-2016. TVA may choose to idle or retire some units in lieu of investing in additional controls and may in some cases construct replacement generation. The ~~final rule moderated somewhat from the proposed rule, but it remains~~Mercury and Air Toxic Standards are the primary ~~driver~~drivers of additional ~~air quality~~emission controls for TVA's coal-fired plants over the next few years. ~~Legal challenges to~~The rule has been challenged in court, and the resolution of this ~~rule~~litigation could affect the compliance ~~dates.~~dates and/or other requirements.

The Environmental Agreements. The Environmental Agreements became effective in June 2011. These Agreements settled several outstanding legal challenges. In the agreements, TVA committed to (1) retire 18 coal-fired units by the end of 2017, (2) control, convert, or retire an additional 16 coal-fired units through June 20, 2019, (3) comply with annual, declining emission caps for SO₂ ~~and NO~~_x, (4) invest $290 million in certain TVA environmental projects, (5) provide $60 million split between Alabama, Kentucky, North Carolina, and Tennessee to fund environmental projects, and (6) pay civil penalties of $10 million. See Note 20—Legal Proceedings—Environmental ~~Agreements.~~

Acid Rain Program. Congress established the Acid Rain Program to achieve reductions in emissions of SO₂ and NO_x, the primary causes of acid rain. The program includes a cap-and-trade emission reduction program for SO₂ emissions from power plants. ~~By CY 2000,~~TVA continues to reduce SO₂and NO_X emissions from its coal-fired plants and the ~~program established a nationwide cap on power plant~~ SO₂ ~~emissions~~allowances allocated to TVA under the Acid Rain program are sufficient to cover the operation of ~~8.9 million tons per year. The program also contains requirements for power plants to reduce~~its coal-fired plants. In the TVA service area, the limitations imposed on NO_x emissions ~~through~~by either the ~~use of available~~

Regional Haze Program. In June 2005, the EPA issued the Clean Air Visibility Rule, amending its CY 1999 regional haze rule, which had established ~~time lines~~timelines for states to improve visibility in national parks and wilderness areas throughout the United States. Under the amended rule, certain types of older existing sources ~~may be~~are required to install best available retrofit technology. To comply with this requirement, certain utilities, including TVA, may have to install additional controls for particulate matter, SO₂, and NO_x ~~emissions.~~emissions or agree to lower emission limits at plants equipped with such controls. TVA does not anticipate that this program has the potential to impact any unit other than Colbert ~~Fossil Plant ("Colbert")~~Unit 5.5, which was idled in October 2013.

Opacity.Opacity, or visible emissions, measures the denseness (or color) of power plant plumes and has traditionally been used by states as a means of monitoring good maintenance and operation of particulate control equipment. Under some conditions, retrofitting a unit with additional equipment to better control SO₂ and NO_x emissions can adversely affect opacity performance, and TVA and other utilities are addressing this issue. The evaluation of a utility’s compliance with ~~state~~ opacity requirements is coming under increased scrutiny, especially compliance during periods of startup, shutdown, and malfunction. ~~SIPs~~State implementation plans ("SIPs") developed under the CAA typically exclude periods of startup, shutdowns, and ~~malfunctions.~~malfunctions, but the EPA has proposed a rule to eliminate such exclusions. The ~~EPA recently reversed its previous approval of Alabama's SIP~~proposed rule should be final in 2014, after which the states must modify their implementation plans by 2016. These new requirements could reduce flexibility and increase operational costs for ~~opacity, and this has been challenged in court.~~TVA’s coal-fired plants.

Legislation. Although ~~it is unlikely that~~ climate change legislation ~~will pass during~~has failed to progress in the ~~112th~~U.S. Congress ~~Congress may consider climate change and energy-related proposals. It~~in past years, there is ~~not unreasonable to anticipate~~continuing interest in legislation that ~~new EPA regulations or laws may set limits on~~could regulate GHG emissions ~~for the electric utility sector. Prospects for future proposals becoming law,~~or impose other energy-related restrictions and ~~the resulting potential impact on electric rates, are not clear at this time. However, if~~requirements. If legislation intended to limit GHG emission ~~reductions from electricity generating facilities~~or impose other energy policies were to become ~~mandatory, the~~law, such limitations would likely affect TVA’s coal-fired plants and could affect other fossil fuel-fired plants. The costs and impacts ~~are expected to~~or such regulation could be significant ~~especially~~ for ~~coal-fired plants.~~TVA. There is no way to predict the likelihood or form of such legislation at this time.

Regulation. ~~In April 2007, the U.S. Supreme Court issued~~The Obama administration has promulgated a ~~decision in~~ ~~Massachusetts v. EPA~~ ~~holding~~number of regulations that ~~GHG~~impose limitations upon emissions of GHGs, including CO₂~~, are “air pollutants” under the CAA and requiring the EPA~~ from power plants. The most important of these apply to ~~determine whether GHGs from~~major new motor vehicles pose a threat to health and welfare. On December 15, 2009, the EPA published its finding under the CAA that six identified GHGs contribute to air pollution that may endanger public health or welfare, which triggered the statutory requirement that the EPA regulate emissionssources of GHGs, ~~from motor vehicles. As~~including coal-fired and gas-fired power plants, and major modifications of ~~January 2011,~~existing plants. On October 15, 2013, the ~~CAA permitting programs for stationary sources must now also address GHGs.~~

The first phase of the Tailoring Rule became effective in January 2011, and applies only to sources that were already subject to PSD and/or Title V programs because of their emission levels of other regulated pollutants. Under the first phase,EPA proposed a ~~source will be subject to PSD requirements for GHGs if (1) the source is already subject to PSD requirements for another pollutant and (2) the source increases its~~ GHG ~~emissions by at least 75,000 tons per year on a CO~~₂e basis. Those sources may be required to conduct a BACT review for their GHG emissions. The EPA has issued guidance on the technologies or operations that would constitute BACT for GHGs. Pending the commercial demonstration of technologies such as carbon capture and sequestration, it is expected that the use of energy efficiency measures will constitute BACT. Additionally, under the first phase, any source that was required to have a Title V permit for a non-GHG pollutant is required to address GHG requirements, including monitoring, record keeping, and reporting requirements, when it applies for, renews, or revises its Title V permit.

Biomass CO₂Emissions. InOn July ~~2011,~~12, 2013, the D.C. Circuit vacated the EPA’s ~~final~~biomass deferral rule, holding that determined that GHG emissions from biomass combustion will not be counted toward emission thresholds for PSD and Title V permitting under the second phase of the EPA’s Tailoring Rule for a period of three years became effective. During this three-year interim period, the EPA ~~will examine how~~did not have the authority to ~~evaluate~~temporarily delay regulating biogenic CO₂ ~~emissions from biomass. The EPA released a companion document that provides guidance~~ for three years pending the ~~determination~~completion of ~~BACT in PSD proceedings involving~~its study to determine whether biogenic CO₂ emissions ~~from bioenergy facilities.~~contribute to increases in CO

Executive Orders. ~~In October 2009,~~On June 25, 2013, the President ~~Obama signed~~ ~~Executive Order ("EO")~~ ~~13514,~~released his Climate Action Plan, which ~~requires federal agencies~~includes a broad range of executive actions to ~~establish GHG emission reduction targets~~mitigate U.S. carbon emissions, manage climate change adaptation efforts, and ~~prepare inventories of GHG emissions including emissions of CO~~₂~~, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbon gases, and sulfur hexafluoride. The White House~~ ~~Council on Environmental Quality ("CEQ")~~ released final Federal Greenhouse Gas Accounting and Reporting Guidance in October 2010, which is the basis for these inventories. TVA submitted its first Strategic Sustainability Performance Plan to OMB in June 2010 and updated it per the Executive Order.lead international efforts.

International Accords. ~~The Kyoto Protocol was~~International agreements and protocols have not been adopted ~~in 1997~~ by the United ~~Nations to address global climate change by reducing emissions of CO~~₂States; accordingly, they would not become binding upon TVA unless and other GHGs. Although the United States has not adopted the Kyoto Protocol, the United States pledged to reduce its GHG emission in the range of 17 percent below CY 2005 levels by CY 2020 in connection with the 15^th ~~Conference of the Parties to the~~ ~~United Nations Framework Convention on Climate Change ("UNFCC"). In December 2011, decisions made by the 17~~^th Conference of the Parties included a promise to work toward a new global treaty by 2015 that will apply to all 195 UNFCC parties, effective starting in 2020. An act of the U.S. Congress is required to make UNFCC reductions enforceable. TVA is unable to predict whether any such climate-related legislation requiring such reductions in GHG emissions ultimately will becomeuntil they are enacted into law.

Litigation. In addition to legislative activity, climate change issues ~~are~~have been the subject of a number of lawsuits, including lawsuits against TVA. See Note 20—Legal Proceedings —— Case Arising out of Hurricane Katrina ~~and —~~ ~~Global Warming Cases, Southern District of New York~~.

Indirect Consequences of Regulation or Business Trends. Legal, technological, political, and scientific developments regarding climate change may create new opportunities and risks. The potential indirect consequences could include an increase or decrease in electricity demand, increased demand for generation from alternative energy sources, and subsequent impacts to business reputation and public opinion. See Power Supply.

~~impacts to business reputation and public opinion. See~~ ~~Future Power Supply.~~

Actions Taken by TVA to Reduce GHG Emissions. TVA has ~~taken significant voluntary steps to reduce~~reduced GHG emissions ~~including the following:~~

~~The U.S.~~Legislation has been proposed in Congress ~~has not passed~~in the past to establish a national renewable energy standard ("RES")~~. Further, it is unlikely Congress will adopt a law~~ that could require energy providers, including TVA, to rely more on renewable energy resources. Such legislation has not passed but could be reintroduced in the ~~near future that will require TVA to acquire a certain percentage of electric generation from a specified list of eligible renewable energy technologies.~~future.

~~In April 2011, the~~Cooling Water Intake Structures. The EPA has proposed a ~~new~~ rule ~~under §316(b) of the~~implementing Clean Water Act ~~designed~~§316(b) to ~~minimize~~reduce the ~~impacts to~~impingement of fish and ~~shellfish from~~ the ~~design~~entrainment of fish eggs and ~~operation of~~larvae by cooling water intake structures at existing ~~power~~ plants ~~and manufacturing facilities. The~~that withdraw more than two million gallons-per-day. As proposed, rule contains new requirements for reducing the mortality of aquatic organisms trapped against the surface of water intake screens or drawn through the screens into plant cooling water systems. Compliance with the rule is expected to require changes in the operation of cooling water intakes and modifications to their design. These changes could potentially result in significant increases in capital costs and operating and maintenance costs. All of the intakes at TVA’s existing coal and nuclear generating facilities are likelyimpingement impacts would have to be ~~subject to the new rule. Compliance is anticipated~~reduced by no later than 2020, and entrainment impacts would have to be ~~required within eight years of the effective date of the final rule. Because of the uncertainty~~reduced as soon as possible based on site-specific analyses. Issuance of the final rule ~~changes~~was extended to allow more time for the EPA to assess cost-benefits and complete consultation under the Endangered Species Act. The consultation under the Endangered Species Act could result in more stringent requirements for plants located on waters with protected species or their designated habitats.

Based upon a notice of data availability ("NODA"), the EPA is now considering identifying “model technologies” that would be designated as compliant with the impingement numeric limits. For TVA intakes, it is probable that installation of fish-friendly traveling screens and a fish return system will be required at most, if not all, coal-fired and nuclear plants. The EPA’s NODA presented no additional discussion of entrainment requirements beyond those initially proposed; thus, the need for entrainment controls is expected to remain a site-specific determination made by the ~~EPA, the future compliance costs are uncertain at this time. The EPA has recently committed to finalizing the new rule by June 27, 2013.~~state-designated NPDES permit writer.

Hydrothermal Discharges.The EPA and many states are ~~taking increased interest in~~beginning to focus regulatory attention on potential effects of hydrothermal discharges. ~~TVA is working with states and the EPA to demonstrate that the data collected in the vicinity of~~Many TVA plants ~~is sufficient~~have variances from thermal standards under § 316(a) of the Clean Water Act that may have to assess the impacts of thermal discharges on the aquatic environment and validate existing thermal limits. TVA expects to collect substantially more in-stream biological and temperature data than in the past to justify current thermal limits.be re-justified through new studies. Specific data requirements in the future will be determined based on negotiations between TVA and regulators.

~~The~~Steam-Electric Effluent Guidelines. On June 7, 2013, the EPA proposed revisions to the effluent guidelines for the steam electric power generating industry. The rule proposal focuses on stricter limitations on wastewater discharges from ash handling, air pollution control systems, and enhanced mercury air controls. Wastewater streams from air pollution control systems contain pollutants such as metals, total suspended solids, chlorides, and nutrients, which have typically been treated in settling ponds. The EPA identified four preferred alternatives which include numerical limits for each option. Depending on the stringency of the final rule, TVA likely would have to install additional wastewater treatment systems at its coal-fired plants, substantially increasing TVA’s water pollution control costs. The EPA is required to finalize the rulemaking by May 2014.

Groundwater Contamination. Environmental groups and state regulatory agencies are increasing their attention on groundwater contamination associated with coal combustion residuals ("CCRs") management activities such as ash ponds. Seven of TVA’s eleven coal-fired plants are in some level of state regulatory groundwater assessment. Three of those plants (Colbert, Gallatin Fossil Plant ("Gallatin"), and Shawnee) have investigations beyond monitoring and reporting. Four of the seven TVA coal-fired plants (Gallatin, Shawnee, Johnsonville, and Widows Creek) have either underground storage tank groundwater monitoring, or groundwater remediation monitoring with state regulatory involvement. As a result of these assessments and increased attention, TVA may have to change how it manages CCRs at some of its plants with associated

General Clean Water Act Requirements. As is the case in other industrial sectors, TVA and other utilities are also facing more stringent requirements related to the protection of wetlands, reductions in storm water impacts from construction activities, new water quality criteria for nutrients and other pollutants, new wastewater analytical methods, and regulation of herbicide discharges. In addition, other new environmental regulations related to mountain top mining of coal in the Appalachian region under the Clean Water Act may increase the cost of coal that TVA purchases for the Steam Electric Power Generating Category were last revised by the EPA in CY 1982. The EPA is currently conducting studies and surveys of wastewater discharges from the industry. Under a revised consent decree approved by the U.S. Court of Appeals for the District of Columbia Circuit, the EPA has agreed to sign a notice of proposed rulemaking by December 14, 2012, and to sign a decision taking final action by May 22, 2014. A future rule is expected to focus on wastewaters from ash handling and clean air control systems. The revised effluent guidelines are likely to require more restrictive discharge limitations through more advanced wastewater treatment, resulting in significant additional expenditures to meet the new requirements. In the interim, TVA is unable to predict whether state regulators may impose more stringent limits on a case-by-case basis under existing authority to exercise best professional judgment as ~~National Pollutant Discharge Elimination System ("NPDES")~~ ~~permits are renewed.~~its plants.

Liability for releases and cleanup of hazardous substances is ~~primarily regulated~~imposed under the federal Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), and other federal and parallel state statutes. In a manner similar to many other industries and power systems, TVA has generated or used hazardous substances over the years.

~~Non-TVA~~TVA Sites. ~~TVA is aware of alleged hazardous-substance releases at certain non-TVA areas for which it may have~~

~~Coal Combustion Wastes~~Non-TVA Sites. TVA is aware of alleged hazardous-substance releases at certain non-TVA areas for which it may have some liability. See Note 20 — Contingencies — Environmental Matters.

Coal Combustion Residuals.In May 2010, the EPA released the text of a proposed rule describing two possible regulatory options it is considering under ~~the~~ ~~Resource Conservation and Recovery Act ("RCRA")~~RCRA for the disposal of ~~coal combustion wastes ("CCWs")~~CCRs generated from the combustion of coal by electric utilities and independent power producers. Under one option, CCRs would be regulated as a solid or special waste. Under the other option, CCRs would be regulated as a hazardous waste. Under either option, the EPA would regulate the construction of impoundments and landfills, and seek to ensure both the physical and environmental integrity of disposal facilities. ~~CCWs~~CCRs include fly ash, bottom ash, boiler slag, and flue gas desulfurization materials. If ~~these materials are beneficially reused, they are referred to as~~ ~~coal combustion products ("CCP"). If these materials are destined for disposal, they are referred to as CCRs.~~

Kingston Ash Spill.See Note 9 for a discussion of the environmental issues associated with the Kingston ash spill.

SO₂Emissions.To reduce SO₂ emissions, TVA has installed scrubbers on 17 of its coal-fired units, and switched to lower-sulfur coals at 41 coal-fired units. In August 2011, the TVA Board approved adding scrubbers to ~~three units at Allen and~~ four units at Gallatin subject to completing appropriate environmental reviews. ~~In August 2012,~~After these reviews were completed, TVA’s Chief Executive Officer authorized proceeding with the ~~TVA Board canceled the scrubber projects at Allen, and TVA is currently re-evaluating its options for this plant.~~proposed projects.

NO_x Emissions. To reduce NO_x emissions, TVA installed SCRs on 21 coal-fired units, installed selective non-catalytic reduction systems on two coal-fired units (although TVA is no longer operating one of these systems because of technical challenges), installed High Energy Reagent Technology systems on seven coal-fired units, installed low-NO_x burners or low-NO_x combustion systems on 46 coal-fired units, optimized combustion on 12 coal-fired units, and began operating NO_x control equipment year round when units are operating (except during startup, shutdown, and maintenance periods) starting in October 2008. In addition, in August 2011, the TVA Board approved adding SCRs to four units at Gallatin subject to completing appropriate environmental reviews. After these reviews were completed, TVA's Chief Executive Officer authorized proceeding with the proposed projects.

Particulate Emissions.To reduce particulate emissions of air pollutants, TVA has equipped all of its coal-fired units with scrubbers, mechanical collectors, electrostatic precipitators, and/or ~~baghouses.~~bag houses.

Primarily ~~on account of~~due to the actions described above, emissions of NO_x and SO₂ on the TVA system have been reduced by 8890 percent below peak 1995 levels and by 9194 percent below 1977 levels, respectively. These controls also have provided a co-benefit of reducing hazardous air pollutants, including mercury, at some units. For CY 2012, TVA’s emission of CO₂ from its sources was 81 million tons, a 23 percent reduction from 2005 levels. This includes 426 tons from units rated at less than 25

There could be additional material costs if reductions of GHGs, including CO₂, are mandated by legislative, regulatory, or judicial actions and if more stringent emission reduction requirements for conventional pollutants are established. These costs cannot reasonably be predicted at this time because of the uncertainty of these actions. A number of emerging EPA regulations establishing more stringent air, water, and waste requirements could result in significant changes in the structure of the U.S. power industry, especially in the eastern half of the country.

TVA now anticipates spending approximately $~~2.3~~1.3 billion through ~~2018~~2022 to add controls to its coal-fired units, which is less than the previous projection of ~~$3.4~~$2.3 billion. This results from increasing reliance on cleaner energy resources and the idling/retirement of more coal-fired units which TVA otherwise would have had to ~~have been controlled. Also, the EPA's final mercury and air toxic standards were less restrictive than predicted.~~However, the addition of cleaner energy resources to the TVA system and the transmission upgrades that are necessary to accommodate unit idling/retirements have their own costs. TVA has added five gas-fired combined-cycle generating facilities to its fleet since 2007. These facilities provide cleaner capacity than other fossil fuel-fired options and help replace the capacity of idled or retired coal-fired units. Additional combined-cycle generating facilities may be added to TVA's fleet in the future as needed. See ~~Current Power Supply~~ — ~~Natural Gas and/or Oil-Fired~~ ~~for more information.~~

On September 30, ~~2012~~2013, TVA had ~~12,762~~12,612 employees, of whom ~~4,673~~4,613 were trades and labor employees. Under the TVA Act, TVA is required to pay trades and labor workers hired by TVA and certain of its contractors the rate of wages for work of a similar nature prevailing in the vicinity where the work is being performed. Neither the federal labor relations laws covering most private sector employers nor those covering most federal agencies apply to TVA. However, the TVA Board has a long-standing policy of acknowledging and dealing with recognized representatives of its employees, and that policy is reflected in long-term agreements to recognize the unions (or their successors) that represent TVA employees. Federal law prohibits TVA employees from engaging in strikes against TVA.

The risk factors described below, as well as the other information included in this Annual Report, should be carefully considered. Risks and uncertainties described in these risk factors could cause future results to differ materially from historical results as well as from the results anticipated in forward-looking statements. Although the risk factors described below are the ones that TVA considers significant, additional risk factors that are not presently known to TVA or that TVA presently does not consider significant may also impact ~~TVA~~'sTVA's business operations. Although the TVA Board has the authority to set ~~TVA~~'sTVA's own rates and may thus mitigate some risks by increasing rates, there may be instances in which TVA would be unable to partially or completely eliminate one or more of these risks through rate increases over a reasonable period of time or at all. Accordingly, the occurrence of any of the following could have a material adverse effect on ~~TVA~~'sTVA's cash flows, results of operations, and financial condition.

At September 30, ~~2012~~2013, TVA-operated generating assets consisted of 5046 active coal-fired units and ~~nine idled~~14 inactive coal-fired units, ~~six~~6 nuclear units, 109 conventional hydroelectric units, four pumped-storage units (all out of service at September 30, ~~2012 but one unit returning~~2013, although they are expected to ~~limited~~be returned to service ~~at October 24, 2012)~~later in 2014), 11 combined-cycle ~~units,~~power blocks, 87 simple-cycle units (with ~~six~~four units out of service), ~~nine~~5 diesel generator units, one wind energy site (out of service), and 16 solar sites. In addition, TVA has biomass cofiring potential at its coal-fired sites. See Item 1, Business — ~~Current~~ Power Supply — Net Capability for a chart that indicates the location, capability, and in-service dates for certain of these properties, which chart is incorporated by reference into this Item 2, Properties. AtAs of September 30, ~~2012~~2013, 24 of the simple-cycle ~~combustion turbine units and one of the combined-cycle~~ combustion turbine units were leased to private entities and leased back to TVA under long-term ~~leases (TVA~~leases. In addition, TVA is leasing the three Caledonia combined-cycle ~~units~~power blocks under a long-term ~~lease). In addition, since April 17, 2009,~~ ~~Seven States Southaven, LLC ("SSSL")~~ ~~has owned an undivided 90 percent interest in the three Southaven combined-cycle units, and~~lease. TVA ~~has entered into a lease with SSSL under which TVA leases SSSL’s undivided 90 percent interest in the facility and operates the entire facility through April 23, 2013. For additional details, see~~ ~~Note 13. TVA~~ is ~~also~~ in the process of constructing additional generating assets. For a discussion of these assets, see Item 1, Business — ~~Future Power Supply.~~—Cleaner Energy Initiatives.

At September 30, ~~2012~~2013, certain qualified technological equipment and other software related to TVA’s transmission system were leased to private entities and leased back to TVA under long-term leases.

In addition, the Basic Tennessee Valley Authority Power Bond Resolution adopted by the TVA Board on October 6, 1960, as amended on September 28, 1976, October 17, 1989, and March 25, 1992 (the "Basic Resolution"), prohibits TVA from mortgaging any part of its power properties and from disposing of all or any substantial portion of these properties unless TVA provides for a continuance of the interest, principal, and sinking fund payments due and to become due on all outstanding Bonds, or for the retirement of such Bonds.

From time to time, TVA is party to or otherwise involved in lawsuits, claims, proceedings, investigations, and other legal matters ("Legal Proceedings") that have arisen in the ordinary course of conducting TVA’s activities, as a result of catastrophic events or otherwise. While the outcome of the Legal Proceedings to which TVA is a party cannot be predicted with certainty, any adverse outcome to a Legal Proceeding involving TVA may have a material adverse effect on TVA’s cash flows, results of operations, and financial condition.

For a discussion of Legal Proceedings involving TVA, see Note 20 — Legal Proceedings, which discussion is incorporated by reference into this Item 3.

The following selected financial data for the years ~~2008~~2009 through ~~2012~~2013 should be read in conjunction with the audited financial statements and notes thereto (collectively, the ~~"Financial~~"Consolidated Financial Statements") presented in Item 8, Financial Statements and Supplementary Data. Certain reclassifications have been made to the ~~2008~~2009, ~~2009~~2010, and ~~2010~~2011 financial statement ~~presentation~~presentations to conform to the ~~2011~~2012 and ~~2012~~2013 ~~presentation.~~presentations.

TVA operates the nation's largest public power system. At September 30, ~~2012~~2013, TVA provided electricity to approximately 50 large industrial customers, six federal agency customers, and 155 ~~distributor~~local power company customers of TVA ("LPCs") that serve over nine million people in parts of seven southeastern states. TVA generates virtually all of its revenues from the sale of electricity, and in ~~2012~~2013 revenues from the sale of electricity totaled $~~11.1~~10.8 billion. As a wholly-owned agency and instrumentality of the United States, however, TVA differs from other electric utilities in a number of ways:

In 2011, ~~the~~ TVA ~~Board accepted the~~completed an Integrated Resource Plan ("IRP"), which ~~recommends~~recommended a ~~strategic~~planning direction ~~focusing on a diverse mix of electricity generation sources, including nuclear~~consistent with TVA's Environmental Policy and fully supports TVA's renewed vision. The IRP guides TVA in meeting its customers’ power ~~renewable~~needs while addressing the substantial challenges facing the electric utility industry. The recommended planning direction provides flexibility to make sound choices as economic and regulatory changes occur. Resource recommendations in the plan balance costs, energy efficiency, system reliability, and ~~natural gas, as well as traditional coal and hydroelectric power.~~environmental responsibility for TVA’s stakeholders. TVA is ~~increasing its low or no emission generation. TVA considers fuel mix in making decisions about generation, and is~~currently undertaking a refresh of the 2011 IRP with the new report expected to ~~rely on nuclear, natural gas-fired capacity, and energy efficiency as the primary means to meet future electricity needs.~~ be published in 2015.

Sales of electricity accounted for virtually all of TVA's operating revenues in ~~2012~~2013, ~~2011~~2012, and ~~2010~~2011. TVA sells power at wholesale rates to ~~distributor customers, consisting of municipalities and cooperatives~~LPCs that resell the power to their customers at retail rates. TVA also sells power to directly served customers, consisting primarily of federal agencies and customers with large or ~~unusual~~nonstandard loads. In addition, power that exceeds the needs of the TVA system is sold under exchange power arrangements with certain other power systems.

The following table compares TVA’s energy sales statistics for the ~~year~~years ended September 30, 2013, 2012, and 2011:

Sales of electricity decreased 3.3 billion kilowatt hours ("kWh") for the year ended September 30, 2013, compared to the year ended September 30, 2012, primarily due to a decrease in demand from industries directly served. The reduced demand was largely the result of a decrease in demand by TVA's largest directly served industrial customer, which began ceasing operations during the third quarter of 2013 (see 2013 Key Initiatives and Challenges — Customers/Counterparties Risk). Offsetting the decrease from industries directly served was an increase in sales to federal agencies and other due to an increase in off-system sales as TVA had excess generation available for resale.

Operating Revenues. Operating revenues for ~~2012~~2013, ~~2011~~2012, and ~~2010~~2011 consisted of the following:

Fuel expense decreased $246 million for the year ended September 30, 2012, as compared to the prior year. Overall favorable fuel rates, as a result of the change in the mix of generation resources, accounted for $235 million of the decrease. Coal-fired generation decreased 21 percent while natural gas-fired generation was 145 percent higher as compared to the prior year. This increase was primarily due to greater capacity as a result of the acquisition of the Magnolia Combined-Cycle Gas Plant ("Magnolia") and the completion of the John Sevier ~~CCF~~Combined Cycle Facility ("John Sevier CCF") and was also due to the increased use of natural gas-fired generation as a result of lower gas prices. The average Henry Hub natural gas spot price in 2012 was $2.73 per mmBtu, which was 34 percent lower than the average price for the prior year. Nuclear generation also helped offset the reduction in coal-fired generation as it increased 11 percent compared to the prior year due to fewer refueling outages. Lower sales of electricity led to a decrease in overall generation, which accounted for the remaining $11 million of the decrease in fuel expense.

Depreciation and amortization expense increased $147 million in 2012 over 2011 primarily due to additional depreciation of $308 million on certain idled coal-fired units and due to depreciation expense on net plant additions. These increases were partially offset by a $155 million decrease in amortization expense due to the treatment of certain regulatory assets as a result of the approval of Bellefonte Unit 1 in August 2011. See Note 1 — Property, Plant, and Equipment, and Depreciation.

Net interest expense decreased $47 million for the year ended September 30, 2013. This was primarily attributable to a decrease in interest expense of $78 million as a result of a decrease in the average interest rate of TVA's outstanding debt. This was partially offset by a $31 million increase primarily due to the amortization of debt reacquisition cost as a result of prior year refinancings and due to the financing of the John Sevier CCF. See Note 8.

The TVA Act authorizes TVA to issue Bonds in an amount not to exceed $30.0 billion outstanding at any time. At September 30, 2013, TVA had $24.8 billion of Bonds outstanding (not including noncash items of foreign currency exchange loss of $43 million and net discount on sale of Bonds of $85 million). Due to this limit on the amount of outstanding Bonds, TVA may

Issuance of Debt. TVA Bonds are not obligations of the United States, and the United States does not guarantee the payments of principal or interest on Bonds. ~~TVA had outstanding, along with~~Bonds consist of power bonds ~~the long-term debt of two variable interest entities as of~~ ~~September 30, 2012. TVA is required to consolidate the debt of these variable interest entities as the primary beneficiary of the entities. See~~ ~~Lease Financing~~ ~~below.~~and discount notes. Power bonds have maturities of between one and 50 years. ~~TVA also issues discount notes from time to time.~~ Discount notes have maturities of less than one year. Power bonds and discount notes have a first priority and equal claim of payment out of net power proceeds. Net power proceeds are defined as the remainder of TVA's gross power revenues after deducting the costs of operating, maintaining, and administering its power properties and payments to states and counties in lieu of taxes, but before deducting depreciation accruals or other charges representing the amortization of capital expenditures, plus the net proceeds from the sale or other disposition of any power facility or interest therein.

Power bonds and discount notes are both issued pursuant to section 15d of the TVA Act and pursuant to the Basic Tennessee Valley Authority Power Bond Resolution adopted by the TVA Board on October 6, 1960, as amended on September 28, 1976, October 17, 1989, and March 25, 1992 (the "Basic Resolution"). The TVA Act and the Basic Resolution each contain two bond tests: the rate test and the bondholder protection test.

The rate test for the one-year period ended September 30, ~~2012~~2013, was calculated after the end of ~~2012~~2013, and TVA met the test’s requirements.

TVA Bonds are traded in the public bond markets. TVA's Bonds are listed on the New York Stock Exchange ("NYSE") except for TVA's discount notes, the 2009 Series A and B power bonds, and the power bonds issued under TVA's ~~electronotes®~~electronotes^® program. TVA's Putable Automatic Rate Reset Securities are traded on the NYSE under the exchange symbols “TVC” and ~~“TVE”.~~“TVE.” Other NYSE-listed bonds are assigned various symbols by the exchange, which are noted on the NYSE's web site. TVA has also listed certain bonds on foreign exchanges from time to time, including the Luxembourg, Hong Kong, and Singapore Stock Exchanges. See Item 1A, Risk Factors for additional information regarding the market for TVA's Bonds.

Credit Facility Agreements. TVA and the U.S. Treasury, pursuant to the TVA Act, have entered into a memorandum of understanding under which the U.S. Treasury provides TVA with a $150 million credit facility. This credit facility was renewed for fiscal year 2014 and has a maturity date of September 30, ~~2013.~~2014. Access to this credit facility or other similar financing arrangements with the U.S. Treasury has been available to TVA since the 1960s. TVA plans to use the U.S. Treasury credit facility as a secondary source of liquidity. The interest rate on any borrowing under this facility is based on the average rate on

~~TVA also has~~The following table provides additional information regarding TVA's funding available in the form of three long-term revolving credit ~~facilities totaling $2.5 billion.~~

Lease ~~Financing~~Financings. On August 9, 2013, TVA entered into a $400 million leasing transaction whereby it agreed to lease for a term of approximately thirty-one years Southaven Combined Cycle Combustion Turbine Facility ("Southaven CCF") to Southaven Combined Cycle Generation, LLC ("SCCG"). The lease was funded through SCCG's issuance of $360 million of secured notes and $40 million of membership interests subject to mandatory redemption. On the same date, TVA agreed to lease the facility back from SCCG for a term of twenty years, at the end of which the head lease will terminate so long as TVA is not in default. TVA used the proceeds from the transaction primarily for the re-acquisition of the 90 percent undivided interest in the Southaven CCF held by Seven States Southaven, LLC ("SSSL"), a subsidiary of Seven States Power Corporation ("Seven States"). See Note 13 — Lease/Leasebacks.

TVA has determined that SCCG, JSCCG and Holdco are variable interest entities of which TVA is the primary beneficiary and, as such, TVA is required to account for the entities on a consolidated basis. See Note 8, Note 10 — Membership Interests of VIE Subject to Mandatory Redemption, and Note 12 — ~~Debt Outstanding~~ — Secured Debt of VIEs.

~~Watts Bar Nuclear Plant Unit 2. At its April 2012 meeting, TVA's Board approved a revised~~ ~~Estimate to Complete ("ETC")~~ for TVA's Watts Bar Unit 2. The ETC concluded that additional funding of $1.5 billion to $2.0 billion will be needed to complete Watts Bar Unit 2, putting the total estimated cost of completion in the range of $4.0 billion to $4.5 billion with estimated completion by December 2015. The new estimate also adds an allowance for addressing impacts associated with Fukushima events and other potential emergent risks.

TVA faces potentially large capital requirements to maintain its power system infrastructure and invest in new power assets, including generation assets using cleaner energy sources. As a result of the Federal Facilities Compliance Agreement with the Coal-Fired Units~~Environmental Protection Agency ("EPA")and~~ the agreement with Alabama, Kentucky, North Carolina, Tennessee, the Sierra Club, National Parks Conservation Association, and Our Children’s Earth Foundation (collectively, the “Environmental Agreements”)~~, TVA expects to retire 18 of its 59 coal-fired units.~~. Due to the age, lower capacity, and lower efficiency of TVA's older coal-fired units, it may not be economical to continue to operate some units in the future, particularly if new environmental laws or regulations become effective. ~~However, discontinuing~~The decision to idle or retire coal-fired units from its generation fleet will be influenced in part by the two environmental agreements reached in April 2011 (the "Environmental Agreements") (see Note 20 — Legal Proceedings — Environmental Agreements) and by the cost of adding emission control equipment to existing units.

Under the Environmental Agreements, TVA committed, among other things, to retire, on a phased schedule, 18 coal-fired units. As of September 30, 2013, TVA had already retired four coal-fired units with a summer net capability of 574 MW, and TVA idled an additional five coal-fired units with a summer net capability of 968 MW on October 1, 2013. See Item 1, Business — Power Supply — Coal-Fired for the schedule of future idling decisions.

In March 2013, TVA announced it is proceeding with a $1.1 billion emissions control project at Gallatin Fossil Plant. The project includes the dry installation of selective catalytic reduction ("SCR") systems, scrubbers, and baghouses at all four units of the 976 MW plant. The dry scrubbers and associated baghouses are expected to be completed in 2016, and the SCR systems are expected to be completed in 2017. TVA also plans to locate a Particulate Matter Continuous Emissions Monitor ("PM CEM") on the common stack for Shawnee Fossil Plant Units 6-10. TVA had been evaluating a particulate control option for Paradise Fossil Plant ("Paradise") Units 1 and 2 or a gas-fired replacement generation option to meet the requirements of the Mercury and Air Toxics Standard ("MATS"). At its November 14, 2013 meeting, the TVA Board canceled its August 2012 conditional budget authorization for a particulate control project and approved the construction of a natural gas facility at Paradise. Upon completion of the natural gas-fired facility at the Paradise site, Paradise coal-fired Units 1 and 2 will be retired. Paradise Unit 3, a coal-fired unit, would continue to be operated.

Nuclear Generation.~~TVA's nuclear fleet is facing some risk due to the cost and timing of newly required regulatory actions related to lessons learned from the Fukushima events. See~~ ~~Liquidity Challenges Related to Generation Resources —Nuclear Regulatory Commission Safety Improvement Orders.~~

~~In October 2012,~~Status of Other Generation Units. TVA had several hydroelectric and combustion turbine units removed from service as of September 30, 2013. All four units at Raccoon Mountain were out of service as of September 30, 2013, because of cracking in the ~~Institute of Nuclear Power Operations ("INPO")~~ ~~Accrediting Board of~~rotor poles and the ~~National Academy of Nuclear Training renewed accreditation for Browns Ferry’s training programs for chemistry technicians, radiation protection technicians, instrumentation~~rotor rims. These units are undergoing a maintenance overhaul and controls, electrical and mechanical maintenance. However, the INPO Board placed the engineering training program on probation. A recovery plan is being developed to get the engineering training program off of probation by April 2013. The cost of recovery is notare expected to ~~be material.~~return to service in 2014. TVA is dispatching generation from other TVA units and purchasing power, if needed, to compensate for the loss in generating capacity.

~~Hydrology Issues~~Effective May 1, 2012, four simple-cycle combustion turbine units at TVA’s Allen Fossil Plant ("Allen"), with a total net summer capability of 64 MW, were designated as temporarily unavailable for operation until repairs have been performed.

Kingston Fossil Plant. In December 2008, a containment dike surrounding a portion of a landfill for ash from the Kingston Fossil Plant ("Kingston") operations failed releasing approximately 5.4 million cubic yards of coal ash. Approximately 3.0 million cubic yards of ash were recovered from the adjacent Emory River from March 2009 to December 2010 and transported offsite for disposal. TVA finished recovering approximately 2.4 million cubic yards of ash from the adjacent Swan Pond Embayment in June 2013 and is currently placing that ash in an onsite ash landfill. Once the ash is stacked in place, a multi-layer cap will be ~~high enough~~constructed over the landfill, which is approximately 230 acres. Also, in June 2013, TVA began placing the first section of the multi-layer cap. The final cap is forecasted to contain the flood waters. A "probable maximum flood” is an extremely unlikely event, and TVA is taking actions with the aim of ensuring that flood waters would pass safely and not cause failure of these dams. Due to the possibility that several dams would heavily impact nuclear plant operations, TVA implemented interim dam modifications inbe completed by the first quarter of ~~2010 by installing engineered, interconnected, fabric-lined containers filled with compacted sand~~2015. An underground perimeter slurry wall is also being constructed to ~~protect four upstream dams from embankment overtopping. TVA is preparing~~stabilize the perimeter of the landfill to contain the ash in the event of an ~~Environmental Impact Statement~~earthquake. The wall construction was completed in ~~accordance with~~August 2013, and jet grout repairs are expected to continue into the ~~National Environmental Policy Act to identify permanent solutions to replace the sand-filled containers which were intended only for temporary use.~~third quarter of 2014.

~~could affect equipment at Watts Bar as well as at~~ ~~Sequoyah Nuclear Plant ("Sequoyah")~~. In ~~addition~~accordance with EPA approved plans, the long-term monitoring of the Emory River was initiated in the spring of 2013 and will continue for up to ~~the interim dam modifications described above, compensatory measures were also put into place at Watts Bar and Sequoyah. In June 2012, TVA committed to the NRC to make a series~~30 years. Results of near-term and longer-term improvements to reduce flooding concerns at Watts Bar and Sequoyah. The near-term improvements involve the construction of flood barriers around specific components or buildings at the plants. The longer-term solutions may involve permanent modifications to several upstream dams or other engineering solutions. Any specific improvementsthis monitoring will be ~~identified after~~used to evaluate the ~~completion of necessary environmental reviews discussed above. The costs associated with~~ecological resources in the ~~potential improvements to the plants~~river system and the ~~dams are still unknown but could be significant.~~

~~Blue Ridge Dam~~In December 2010, a leak was identified in the clay liner of the gypsum pond at Kingston. TVA submitted to the Tennessee Department of Environment and Conservation ("TDEC") a two-phase Corrective Action Plan to install a synthetic liner on the gypsum pond. Work on the first phase of the new gypsum storage facility was completed on October 21, 2011, and TDEC approval to place the facility back in operation was received on November 16, 2011. The plan for the second phase of the work has been incorporated into the overall Kingston CCR storage strategy, with the specific phase two work to be completed by January 2015, as part of the CCR conversion program.

~~When~~Coal Combustion Residual Facilities. As a result of the December 2008 ash spill at Kingston, TVA ~~acquired Blue Ridge Dam in 1939, there was known damage~~retained an independent third-party engineering firm to perform a multi-phased evaluation of the overall stability and safety of all existing embankments associated with TVA’s wet CCR facilities. The study showed that none of TVA’s other coal-fired plants presented risks similar to the ~~water inlet piping supplying~~conditions that existed at Kingston at the ~~hydroelectric turbine in the powerhouse on the downstream side~~time of the ~~dam.~~ ash spill, and that the ongoing remediation work being done at the plants should bring all of them within industry standards in terms of stability upon completion. Implementation of recommended actions is ongoing, including risk mitigation steps such as performance monitoring, designing and completing repairs, developing planning documents, obtaining permits, and generally implementing the lessons learned from the Kingston ash spill at TVA’s other CCR facilities.

~~The~~ Transmission Issues.~~U.S. Government Accountability Office~~ Since the announcement of the proposed integration of Entergy Corporation ("~~GAO"~~Entergy") ~~released~~into the Midcontinent Independent Transmission System Operator, Inc. ("MISO") market, TVA has been evaluating potential impacts to the reliability of its transmission system. TVA completed a ~~report~~detailed reliability assessment during the second quarter of 2013 which identified that significant transmission upgrades will be required if new coordinated planning and operational processes are not implemented.

On October 17, 2013, the North American Electric Reliability Corporation ("NERC") revisions to the Transmission Planning ("TPL") Reliability Standards were approved by the ~~chairman~~Federal Energy Regulatory Commission ("FERC"). The revisions increase requirements on contingency planning, constraints on load shedding, and transparency and interactions with stakeholders. In anticipation of this revision TVA began preliminary work in 2006, and is now evaluating this final version of the ~~U.S. Senate Committee on Environment and Public Works.~~ TPL, including costs to comply, which will be significant.

Adjustment to Nuclear Insurance Costs. The ~~GAO stated that TVA could benefit~~Price-Anderson Act provides a layered framework of protection to compensate for losses arising from a ~~consultant's study~~nuclear event in the United States. In addition to requiring all NRC nuclear plant licensees to purchase nuclear liability insurance, the Price-Anderson Act requires licensees to pay a specified total amount per unit for any nuclear event, including events at other licensees’ facilities, plus a five percent surcharge. The NRC adjusts this amount every five years to account for inflation. On July 12, 2013, the NRC increased this total amount to $127 million per unit for each event, effective September 10, 2013. The maximum amount that could be recovered per year per unit is $19 million. The prior amounts were a total assessment of $118 million per unit for each event with a maximum annual payment of $18 million per unit.

In November 2012, the Department of ~~leadership~~Energy ("DOE") announced a grant award to Babcock & Wilcox ("B&W"), in ~~energy efficiency improvements.~~conjunction with TVA ~~agreed~~and Bechtel, for small modular reactor ("SMR") development. TVA and B&W subsequently signed a contract in February 2013 establishing the process toward submittal and the NRC review of a license application. The B&W-designed SMR would have a scalable, modular design allowing utilities to add electrical generation capacity in increments of 360 MW. The proposed site for the reactor is TVA’s Clinch River site near the DOE’s Oak Ridge, Tennessee reservation. DOE will invest up to half of the total cost for design, certification, and licensing with the ~~GAO. Prior~~project's industry partners (including TVA) matching this investment by at least one-to-one.

United States Enrichment Corporation. In May 2012, TVA ~~had already commissioned~~extended its power contract with its largest directly served customer, United States Enrichment Corporation ("USEC"), a ~~study by an outside firm. The results~~subsidiary of USEC, Inc. On May 24, 2013, USEC announced the ~~study have been received~~cessation of enrichment activities at its Paducah, Kentucky site. TVA and ~~show that~~USEC subsequently completed agreements to extend power sales to facilitate the cessation of enrichment activities and to support non-enrichment activities at the site at a greatly reduced level. These sales arrangements may continue to be extended. Power sales to USEC represented three percent and five percent of TVA's ~~energy efficiency plans are within the achievable range of potential energy savings~~total operating revenues for the ~~region. Its findings are consistent with TVA's IRP, the agency's 20-year energy roadmap,~~years ended September 30, 2013, and ~~TVA's plans for energy efficiency and demand response programs. TVA will continue to analyze the details of the study and incorporate them into future energy efficiency and demand response planning.~~2012, respectively. See Note 14—Counterparty Credit Risk.

For ~~distributor customers,~~LPCs, the default wholesale rate structure is seasonal time-of-use ("TOU")~~, with an option~~. However, these customers have two additional wholesale options from which to ~~elect a SDE structure. The wholesale rate provisions originally specified~~elect: enhanced TOU and enhanced seasonal demand and energy ("SDE"). LPC elections as of October 1, 2013 were as follows: 144 were served under the ~~SDE option would expire in September 2012. In April 2012, the TVA Board approved an optional revised SDE structure and an optional~~ enhanced TOU structure, ~~that became available in October 2012,~~five remained served under the default seasonal TOU structure, and ~~142 of TVA's distributor customers elected to move to~~six were served under the enhanced ~~TOU~~SDE structure.

As of September 30, ~~2012,~~2013, TVA's qualified pension plan had assets of $~~$7.0~~7.2 billion compared with liabilities of $~~$11.9~~11.5 billion. The potential for the plan's funded status to quickly improve is limited because of the significant amount of benefits paid each year to plan beneficiaries. The plan currently has approximately 36,000 participants, of which approximately 23,000 are retirees or beneficiaries currently receiving benefits. Benefits of approximately ~~$600~~$622 million were paid to participants in ~~2012.~~2013.

Health Care. There is a risk of increased health care costs associated with the Affordable Care Act legislation. During 2013, 2012 and 2011, TVA changed its health care plans to include, among other things, extended coverage for children, removal of pre-existing condition provisions for minors, and expansion of certain preventative care ~~services.~~services in order to comply with the act. Although there have been some increase in TVA's health care costs, they have not been material to its operations. TVA plans to continue to monitor the changes required by this legislation and to review its health care plans to comply ~~with required changes~~ in a cost-effective ~~manner.~~manner with Affordable Care Act requirements and provisions that impact TVA's health care plans.

Physical Security. Non-Nuclear asset protection at TVA conforms to various federal regulations, industry best practices and Presidential directives. TVA utilizes a variety of technology solutions, security awareness activities and security personnel to prevent sabotage, vandalism and thefts. Any of these activities could negatively impact the ability of TVA to generate, transport and deliver power to its customers. TVA's Security and Emergency Management collaborates with the security departments at numerous utilities across the nation to determine the most effective protection strategies for non-nuclear assets.

Recent physical attacks at other utilities on transmission facilities across the country have heightened awareness. TVA is working with the Department of Homeland Security ("DHS"), FERC, Edison Electric Institute, Electric Power Research Institute, and other utilities to implement industry approved recommendations and standards.

TVA's consolidated financial statements are prepared in accordance with GAAP, which require management to make estimates, judgments, and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Each of these estimates varies in regard to the level of judgment involved and its potential impact on TVA's financial results. Estimates are deemed critical either when a different estimate could have reasonably been used, or where changes in the estimate are reasonably likely to occur from period to period, and such use or change also would materially impact TVA's financial condition, results of operations, or cash flows. TVA's critical accounting policies are also discussed in Note 1 of the Notes to Consolidated Financial Statements in this Annual Report.

Counterparty Performance Risk. In addition to being exposed to economic loss due to the nonperformance of TVA’s customers, TVA is exposed to economic loss because of the nonperformance of its other counterparties, including suppliers and counterparties to its derivative contracts. Where exposed to performance risk, TVA analyzes the counterparty’s financial condition prior to entering into an agreement and employs performance assurance measures, such as parent guarantees, letters of credit, cash deposits, or performance bonds, to mitigate the risk.

Credit of Suppliers. If one of TVA’s fuel or purchased power suppliers fails to perform under the terms of its contract with TVA, TVA might lose the money that it paid to the supplier under the contract and have to purchase replacement fuel or power on the spot market, perhaps at a significantly higher price than TVA was entitled to pay under the contract. In addition, TVA might not be able to acquire replacement fuel or power in a timely manner and thus might be unable to satisfy its own obligations to deliver power. TVA has a power purchase agreement with a supplier that expires on March 31, 2032. ~~The supplier’s senior secured~~TVA has determined that the supplier has the equivalent of a non-investment grade credit ~~ratings are currently CC by Standard & Poor’s and Caa1 with Moody’s.~~rating. As a result of the supplier’s credit ratings, the company has provided credit assurance to TVA under the terms of its agreement.

Credit of Derivative Counterparties. TVA has entered into derivative contracts for hedging purposes, and TVA’s NDT and qualified pension plan have entered into derivative contracts for investment purposes. If a counterparty to one of TVA’s hedging transactions defaults, TVA might incur substantial costs in connection with entering into a replacement hedging transaction. If a counterparty to the derivative contracts into which the NDT and the qualified pension plan have entered for investment purposes defaults, the value of the investment could decline significantly, or perhaps become worthless.

Quantitative and qualitative disclosures about market risk are reported in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations — Risk Management Activities, which discussion is incorporated into this Item 7A, Quantitative and Qualitative Disclosures About Market Risk.

The Tennessee Valley Authority ("TVA") is a corporate agency and instrumentality of the United States that was created in 1933 by legislation enacted by the United States ("U.S.") Congress in response to a request by President Franklin D. Roosevelt. TVA was created to, among other things, improve navigation on the Tennessee River, reduce the damage from destructive flood waters within the Tennessee River system and downstream on the lower Ohio and Mississippi Rivers, further the economic development of TVA's service area in the southeastern United States, and sell the electricity generated at the facilities TVA operates.

Today, TVA operates the nation's largest public power system and supplies power in most of Tennessee, northern Alabama, northeastern Mississippi, and southwestern Kentucky and in portions of northern Georgia, western North Carolina, and southwestern Virginia to a population of over nine million people.

The power program has historically been separate and distinct from the stewardship programs. It is required to be self-supporting from power revenues and proceeds from power financings, such as proceeds from the issuance of bonds, notes, or other evidences of indebtedness ("Bonds"). Although TVA does not currently receive congressional appropriations, it is required to make annual payments to the U.S. Treasury in repayment of and as a return on the government's appropriation investment in TVA's power facilities (the "Power Program Appropriation Investment"). In the 1998 Energy and Water Development Appropriations Act, Congress directed TVA to fund essential stewardship activities related to its management of the Tennessee River system and nonpower or stewardship properties with power revenues in the event that there were insufficient appropriations or other available funds to pay for such activities in any fiscal year. Congress has not provided any appropriations to TVA to fund such activities since 1999. Consequently, during 2000, TVA began paying for essential stewardship activities primarily with power revenues, with the remainder funded with user fees and other forms of revenues

Power rates are established by the TVA Board of Directors ("TVA Board") as authorized by the Tennessee Valley Authority Act of 1933, as amended, 16 U.S.C. §§ 831-831ee (as amended, the “TVA Act”). The TVA Act requires TVA to charge rates for power that will produce gross revenues sufficient to provide funds for operation, maintenance, and administration of its power system; payments to states and counties in lieu of taxes ("tax equivalents"); debt service on outstanding indebtedness; payments to the U.S. Treasury in repayment of and as a return on the Power Program Appropriation Investment; and such additional margin as the TVA Board may consider desirable for investment in power system assets, retirement of outstanding Bonds in advance of maturity, additional reduction of the Power Program Appropriation Investment, and other purposes connected with TVA's power business. In setting TVA's rates, the TVA Board is charged by the TVA Act to have due regard for the primary objectives of the TVA Act, including the objective that power shall be sold at rates as low as are feasible. Rates set by the TVA Board are not subject to review or approval by any state or other federal regulatory body.

TVA's fiscal year ends September 30. Years ~~(2012, 2011,~~(2013, 2012, etc.) refer to TVA's fiscal years unless they are preceded by “CY,” in which case the references are to calendar years.

Cash includes cash on hand and non-interest bearing cash and deposit accounts. All highly liquid investments with original maturities of three months or less are considered cash equivalents.

The allowance for uncollectible accounts reflects TVA's estimate of probable losses inherent in its accounts and loans receivable balances. TVA determines the allowance based on known accounts, historical experience, and other currently available information including events such as customer bankruptcy and/or a customer failing to fulfill payment arrangements after 90 days. It also reflects TVA's corporate credit department's assessment of the financial condition of customers and the credit quality of the receivables.

The allowance for uncollectible accounts was $71 million and $17 million at September 30, ~~2012~~2013, and ~~2011~~2012, respectively, for accounts receivable. Additionally, loans receivable of $~~191~~73 million and $7476 million at September 30, ~~2012~~2013, and ~~2011~~2012, respectively, are included in Other long-term assets and reported net of allowances for uncollectible accounts of $1210 million and $1112 million at September 30, ~~2012~~2013, and ~~2011~~2012., respectively.

From time to time TVA transfers fiber optic capacity on TVA’s network to telecommunications service carriers and TVA ~~distributor customers.~~local power company customers of TVA ("LPCs"). These transactions are structured as indefeasible rights of use ("IRUs"), which are the exclusive right to use a specified amount of fiber optic capacity for a specified term. TVA accounts for the consideration received on transfers of fiber optic capacity for cash and on all of the other elements deliverable under an IRU as revenue ratably over the term of the agreement. TVA does not recognize revenue on any contemporaneous exchanges of its fiber optic capacity for an IRU of fiber optic capacity of the counterparty to the exchange.

Certain Fuel, Materials, and Supplies. Coal, oil, limestone, tire-based fuel inventories, and materials and supplies inventories are valued using an average unit cost method. A new average cost is computed after each inventory purchase transaction, and inventory issuances are priced at the latest moving weighted average unit cost. Natural gas inventories are valued using an average cost method, and a new average cost is computed monthly.

Allowance for Inventory Obsolescence. TVA reviews material and supplies inventories by category and usage on a periodic basis. Each category is assigned a probability of becoming obsolete based on the type of material and historical usage data. Based on the estimated value of the inventory, TVA adjusts its allowance for inventory obsolescence.

Emission Allowances. TVA has emission allowances for sulfur dioxide ("SO₂")and nitrogen oxides ("NO_x") which are accounted for as inventory. The average cost of allowances used each month is charged to operating expense based on tons of SO₂ and NO_x emitted during the respective compliance periods. Allowances granted to TVA by the Environmental Protection Agency ("EPA") are recorded at zero cost.

Property, Plant, and Equipment. Additions to plant are recorded at cost, which includes direct and indirect costs and an allowance for funds used during construction ("AFUDC"). The cost of current repairs and minor replacements is charged to

Depreciation. TVA accounts for depreciation of its properties using the composite depreciation convention of accounting. Accordingly, the original cost of property retired, less salvage value, is charged to accumulated depreciation. Except as described below, depreciation is generally computed on a straight-line basis over the estimated service lives of the various classes of assets. Depreciation expense for the years ended September 30, 2013, 2012, and 2011 was $1.4 billion, $1.7 billion, and $1.4 billion, respectively. Depreciation expense expressed as a percentage of the average annual depreciable completed plant was 3.12 percent for 2013, 3.78 percent for 2012, and 3.21 percent for 2011~~, and~~ ~~2.92 percent~~ ~~for~~ ~~2010~~. Average depreciation rates by asset class are as follows:

In April 2011, TVA ~~determined depreciation rates based~~entered into two substantively similar agreements, one with the EPA and the other with Alabama, Kentucky, North Carolina, Tennessee, and three environmental advocacy groups (collectively, the "Environmental Agreements”). See Note 20 — Legal Proceedings — Environmental Agreements. Under the Environmental Agreements, TVA committed, among other things, to retire, on a ~~new depreciation study during the second quarter of~~ ~~2012. Implementation of the new study, exclusive of the impact of idling decisions discussed below, resulted in an $11 million~~ ~~decrease in depreciation expense during the year ended~~ ~~September 30, 2012~~.phased schedule, 18 coal-fired units.

Consistent with the Environmental Agreements, Units 1 and 2 at John Sevier Fossil Plant ("John Sevier") were retired on December 31, 2012 and Units 3 and 5 at Widows Creek Fossil Plant ("Widows Creek") were retired on July 31, 2013. In ~~an effort to address operational challenges~~addition on December 31, 2012, John Sevier Units 3 and ~~reduce costs, TVA announced the idling of several coal-fired units during 2012. Due to unanticipated operating challenges, however, TVA subsequently delayed the idle dates for certain of these units~~4 were idled, and ~~brought certain units back into service.~~ on October 1, 2013, Colbert Fossil Plant ("Colbert") Unit 5 and Johnsonville Fossil Plant ("Johnsonville") Units 5, 6, 9, and 10 were idled.

Depreciation rates are adjusted to reflect current assumptions so that the units will be fully depreciated by the applicable idle dates.

Capital Lease Agreements. Property, plant, and equipment also includes assets recorded under capital lease ~~agreements which~~agreements. These primarily consist of power production facilities, water treatment assets, and ~~office~~land of $42 million and power production facilities of $24 ~~and $~~9 million at September 30, ~~2012~~2013 and ~~2011~~2012, respectively, and fuel fabrication and blending facilities of $115 million and $1711 million at September 30, ~~2012~~2013 and ~~2011~~2012, respectively.

Allowance for Funds Used During Construction. AFUDC capitalized during the year ended September 30, ~~2012~~2013, was $~~171~~168 million, of which $23 million is reflected in the consolidated balance sheets as a regulatory asset, as compared ~~with~~to $~~126~~171 million capitalized during the year ended September 30, ~~2011~~2012. TVA capitalizes interest as AFUDC, based on the average interest rate of TVA’s outstanding debt. The allowance is applicable to construction in progress related to projects with (1) an expected total project cost of $1.0 billion or more, and (2) an estimated construction period of at least three years in duration. During 2012 and 2011, TVA also included certain nuclear fuel inventories in the calculation of the allowance. During 2012, the TVA Board approved a change in the AFUDC methodology which removed the inclusion of nuclear fuel from the AFUDC calculation effective October 1, 2012. The accumulated balance of costs, ~~for qualifying projects,~~ which is used to calculate AFUDC, averaged approximately $~~2.5~~3.1 billion for the year ended September 30, ~~2012~~2013. Subsequent to August 31, 2013, the accumulated balance of costs for Bellefonte Nuclear Plant ("Bellefonte") were removed from this calculation.

Software Costs. TVA capitalizes certain costs incurred in connection with developing or obtaining internal-use software. Capitalized software costs are included in Property, plant, and equipment on the consolidated balance sheets and are amortized primarily over five years. At September 30, ~~2012~~2013 and ~~2011~~2012, unamortized computer software costs totaled $265 million and $57

For the years ended ~~2012~~2013 and ~~2011~~2012, the changes in market value of the interest rate derivatives resulted in deferred unrealized ~~losses~~gains (losses) of $~~168~~524 million and $~~365~~(168) million, respectively. There were no realized gains or losses for the years ended ~~2012~~2013 and ~~2011~~2012. ~~The net deferred unrealized gains and losses on the 1992 D Swaption were assigned to the resulting interest rate swap upon the effective date of the exercise.~~

Commodity Derivatives. TVA enters into certain derivative contracts for coal and natural gas that require physical delivery of the contracted quantity of the commodity. TVA marks to market all such contracts. At September 30, ~~2012~~2013, and September 30, ~~2011~~2012, TVA's coal contract derivatives had net market values of $~~(267)~~(140) million and $~~239~~(267) million, respectively, which TVA deferred as regulatory assets or liabilities on a gross basis. At September 30, ~~2012~~2013, TVA's coal contract derivatives had terms of up to ~~six~~five years.

The total market value of natural gas derivative contracts was $(1) million at September 30, 2013, and was less than $(1) million at September 30, 2012~~, and~~ ~~September 30, 2011, was less than $1 million.~~. At September 30, ~~2012~~2013, natural gas derivative contracts had terms of up to ~~three~~two years.

Derivatives Under FTP. TVA has a FTP under which it ~~purchases~~may purchase and ~~sells~~sell futures, swaps, options, and combinations of these instruments (as long as they are standard in the industry) to hedge TVA’s exposure to (1) the price of natural gas, fuel oil, electricity, coal, emission allowances, nuclear fuel, and other commodities included in TVA’s fuel cost adjustment calculation, (2) the price of construction materials, and (3) contracts for goods priced in or indexed to foreign currencies. The combined transaction limit for the fuel cost adjustment and construction material transactions is $130 million (based on one-day value at risk). In addition, the maximum hedge volume for the construction material transactions is 75 percent of the underlying net notional volume of the material that TVA anticipates using in approved TVA projects, and the market value of all outstanding hedging transactions involving construction materials is limited to $100 million at the execution of any new transaction. The portfolio value at risk limit for the foreign currency transactions is $5 million and is separate and distinct from the $130 million transaction limit discussed above. TVA's policy prohibits trading financial instruments under the FTP for speculative purposes.

At September 30, 2013 and 2012, the risks hedged under the FTP were the economic risks associated with the prices of natural gas, fuel oil, and crude ~~oil,~~oil. At September 30, 2013 and ~~coal. Futures~~2012, TVA had no outstanding coal contract derivatives under the FTP. There were no futures contracts ~~and option~~or options contracts outstanding under the FTP ~~had remaining terms of less than~~at ~~one year~~September 30, 2013~~. Swap~~, and swap contracts under the FTP had remaining terms of ~~six~~five years or less.

Investment Fund Derivatives. Investment funds consist primarily of funds held in the NDT, ART, and SERP. All securities in the trusts are classified as trading. See Note 15 — Investments for a discussion of the trusts' objectives and the types of investments included in the various trusts. These trusts may invest in derivative instruments which may include swaps, futures, options, forwards, and other instruments. At September 30, ~~2012~~2013, and September 30, ~~2011~~2012, the fair value of derivative instruments in these trusts was not material to TVA's consolidated financial statements.

Collateral. TVA's interest rate swaps and its currency swaps contain contract provisions that require a party to post collateral (in a form such as cash or a letter of credit) when the party's liability balance under the agreement exceeds a certain threshold. At September 30, ~~2012~~2013, the aggregate fair value of all derivative instruments with credit-risk related contingent features that were in a liability position was $~~1.8~~1.2 billion. TVA's collateral obligations at September 30, ~~2012~~2013, under these arrangements, was $~~1.1~~0.8 billion, for which TVA had posted $~~1.1~~0.8 billion in letters of credit. These letters of credit reduce the available balance under the related credit facilities. TVA's assessment of the risk of its nonperformance includes a reduction in its exposure under the contract as a result of this posted collateral.

Credit of Customers. The majority of TVA's counterparty credit risk is associated with trade accounts receivable from delivered power sales to ~~municipal and cooperative distributor customers,~~LPCs, all located in the Tennessee Valley region. To a lesser extent, TVA is exposed to credit risk from directly served industries and federal agencies, and from exchange power arrangements with a small number of investor-owned regional utilities, related to either delivered power or the replacement of open positions of longer-term purchased power or fuel agreements. TVA had concentrations of accounts receivable from three customers that represented 27 percent of total outstanding accounts receivable at September 30, 2013, and 26 percent of total outstanding accounts receivable at September 30, 2012~~, and~~ ~~September 30, 2011~~. Power sales to TVA's largest directly served industrial customer represented ~~five~~three percent and ~~four~~five percent of TVA's total operating revenues for the years ended September 30, ~~2012~~2013 and ~~2011~~2012, respectively. ~~This customer's senior unsecured~~TVA has determined that this customer has the equivalent of a non-investment grade credit ~~ratings are currently CCC- by S&P and Caa2 by Moody's.~~rating. As a result of its credit ratings, this customer has provided credit assurance to TVA under the terms of its power contract. On May 24, 2013, the customer announced the cessation of enrichment activities at one of its sites. TVA and the customer subsequently completed agreements to extend power sales to facilitate the cessation of enrichment activities and to support non-enrichment activities at the site at a greatly reduced level. These sales may continue to be extended.

Credit of Derivative Counterparties. TVA has entered into derivative contracts for hedging purposes, and TVA's NDT fund and qualified defined benefit pension plan have entered into derivative contracts for investment purposes. If a counterparty to one of TVA's hedging transactions defaults, TVA might incur substantial costs in connection with entering into a replacement hedging transaction. If a counterparty to the derivative contracts into which the NDT fund and the pension plan have entered for investment purposes defaults, the value of the investment could decline significantly or perhaps become worthless. TVA has concentrations of credit risk from the banking and coal industries because multiple companies in these industries serve as counterparties to TVA in various derivative transactions. At September 30, ~~2012~~2013, all of TVA's currency swaps, interest rate swaps, and commodity derivatives under the FTP were with counterparties whose Moody's credit rating was Baa1 or higher. At September 30, ~~2012~~2013, all of TVA's coal contract derivatives were with counterparties whose Moody's credit rating, or TVA's

TVA currently utilizes two active futures commission merchants ("FCMs") to clear commodity contracts, including futures, options, and similar financial derivatives. These transactions are executed under the FTP by the FCMs on exchanges on behalf of TVA. TVA maintains margin cash accounts with the FCMs. See notes to the Mark-to-Market Values of TVA Derivatives table.

Credit of Suppliers. If one of TVA's fuel or purchased power suppliers fails to perform under the terms of its contract with TVA, TVA might lose the money that it paid to the supplier under the contract and have to purchase replacement fuel or power on the spot market, perhaps at a significantly higher price than TVA was entitled to pay under the contract. In addition, TVA might not be able to acquire replacement fuel or power in a timely manner and thus might be unable to satisfy its own obligations to deliver power. To help ensure a reliable supply of coal, TVA had coal contracts with 13 ~~different~~multiple suppliers at September 30, ~~2012~~2013. The contracted supply of coal is sourced from multiple geographic regions of the United States and is to be delivered via various transportation methods (for example, barge, rail, and truck). TVA purchases ~~all~~the majority of its natural gas requirements from a variety of suppliers under short-term contracts.

TVA has a power purchase agreement that expires on March 31, 2032, with a supplier of electricity for 440 megawatts ("MW") of summer net capability from a lignite-fired generating plant. ~~The supplier's senior secured credit ratings are currently CC by S&P and Caa1 by Moody's. As a result of its credit ratings,~~TVA has determined that the supplier has ~~provided~~the equivalent of a non-investment grade credit ~~assurance to TVA under the terms of its agreement.~~ rating.

At September 30, ~~2012~~2013, Investment funds were composed of $~~1.5~~1.7 billion of securities classified as trading and measured at fair value and $21 million of equity investments not required to be measured at fair value. Trading securities are held in the NDT, ART, and SERP. The NDT holds funds for the ultimate decommissioning of TVA's nuclear power plants. The ART holds funds for the costs related to the future closure and retirement of TVA's long-lived assets. TVA established a SERP for certain executives in critical positions to provide supplemental pension benefits tied to compensation that exceeds limits set by Internal Revenue Service ("IRS") rules applicable to the qualified defined benefit pension plan. The NDT, ART, and SERP are invested in securities generally designed to achieve a return in line with overall equity market performance.

Private partnership investments may include holdings of investments in private real estate, venture capital, buyout, mezzanine or subordinated debt, restructuring or distressed debt, and special situations through funds managed by third-party investment managers. Investments in private partnerships generally involve a three-to-four-year period where the investor contributes capital. This is followed by a period of distribution, typically over several years. The investment period is generally, at a minimum, ten years or longer. The NDT had unfunded commitments related to private partnerships of $~~150~~149 million at September 30, ~~2012~~2013. These investments have no redemption or limited redemption options and may also have imposed restrictions on the NDT’s ability to liquidate its investments. There are no readily available quoted exchange prices for these investments. The fair value of the investments is based on TVA’s ownership percentage of the fair value of the underlying investments as provided by the investment managers. These investments are typically valued on a quarterly basis. TVA’s private partnership investments are valued at net asset values ("NAV") as a practical expedient for fair value. TVA classifies its interest in these types of investments as Level 3 within the fair value hierarchy.

See Note 14 — Cash Flow Hedging Strategy for Currency Swaps and Derivatives Not Receiving Hedge Accounting Treatment for a discussion of the nature, purpose, and contingent features of TVA's currency and interest rate ~~derivatives.~~

Commodity Contract Derivatives. Most of these contracts are valued based on market approaches which utilize short- and mid-term market-quoted prices from an external industry brokerage service. A small number of these contracts are valued based on a pricing model using long-term price estimates from TVA's coal price forecast. To value the volume option component of applicable coal contracts, TVA uses a Black-Scholes pricing model which includes inputs from the forecast, contract-specific terms, and other market inputs. These contracts are classified as Level 3 valuations.

Commodity Derivatives Under FTP. These contracts are valued based on market approaches which utilize Chicago Mercantile Exchange ("CME") quoted prices and other observable inputs. Futures and options contracts settled on the CME are classified as Level 1 valuations. Swap contracts are valued using a pricing model based on CME inputs and are subject to nonperformance risk outside of the exit price. These contracts are classified as Level 2 valuations.

See Note 14 — Derivatives Not Receiving Hedge Accounting Treatment — Commodity Derivatives and Derivatives Under FTP for a discussion of the nature and purpose of coal contracts and derivatives under TVA's FTP.

Nonperformance risk for most of TVA's derivative instruments is an adjustment to the initial asset/liability fair value. TVA adjusts for nonperformance risk, both for TVA (for liabilities) and the counterparty (for assets), by applying credit valuation adjustments ("CVAs"). TVA determines an appropriate CVA for each applicable financial instrument based on the term of the instrument and TVA's or the counterparty's credit rating as obtained from Moody's. For companies that do not have an observable credit rating, TVA uses internal analysis to assign a comparable rating to the company. TVA discounts each

The following tables set forth by level, within the fair value hierarchy, TVA's financial assets and liabilities that were measured at fair value on a recurring basis at September 30, ~~2012~~2013, and September 30, ~~2011~~2012. Financial assets and liabilities have been classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TVA's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the determination of the fair value of the assets and liabilities and their classification in the fair value hierarchy levels.

There were no realized ~~or unrealized~~ gains or losses related to the instruments measured at fair value using significant unobservable inputs ~~that affected net income or other comprehensive income~~ during the year ended September 30, ~~2012~~2013. All unrealized gains and losses related to these instruments have been reflected as increases or decreases in regulatory assets and liabilities. See Note 7.

TVA uses the methods and assumptions described below to estimate the fair value of each significant class of financial instrument. The fair market value of the financial instruments held at September 30, ~~2012~~2013, and September 30, ~~2011~~2012, may not be representative of the actual gains or losses that will be recorded when these instruments mature or are called or presented for early redemption. The estimated values of TVA's financial instruments not recorded at fair value at September 30, ~~2012~~2013, and September 30, ~~2011~~2012, were as follows:

The 1959 amendment to the TVA Act also required TVA, beginning in 1961, to make annual payments to the U.S. Treasury from net power proceeds as a repayment of and as a return on the Power Program Appropriation Investment until an additional $1.0 billion of the Power Program Appropriation Investment has been repaid. Of this $1.0 billion amount, $3010 million remained unpaid at September 30, ~~2012~~2013. Once the $1.0 billion has been repaid, the TVA Act requires TVA to continue making payments to the U.S. Treasury as a return on the remaining Power Program Appropriation Investment. The remaining Power

TVA paid $20 million each year for ~~2012~~2013, ~~2011~~2012, and ~~2010~~2011 as a repayment of the Power Program Appropriation Investment. In addition, TVA paid the U.S. Treasury $7 million in ~~2012~~2013, $7 million in ~~2011~~2012, and $97 million in ~~2010~~2011 as a return on the Power Program Appropriation Investment. The amount of the return on the Power Program Appropriation Investment is based on the Power Program Appropriation Investment balance at the beginning of that year and the computed average interest rate payable by the U.S. Treasury on its total marketable public obligations at the same date. The interest rates payable by TVA on the Power Program Appropriation Investment were ~~2.33~~2.10 percent, ~~2.40~~2.33 percent, and ~~2.58~~2.40 percent for ~~2012~~2013, ~~2011~~2012, and ~~2010~~2011, respectively.

The items included in Accumulated other comprehensive income (loss) consist of market valuation adjustments for certain derivative instruments. See Note 1514.

TVA records exchange rate gains and losses on debt in net income and marks its currency swap assets and liabilities to market through other comprehensive income. TVA had unrealized gains of $9978 million and ~~losses of~~ $5099 million in ~~2012~~2013 and ~~2011~~2012, respectively, on the mark-to-market of currency swaps. TVA then reclassifies an amount out of accumulated other comprehensive income into net income, offsetting the gain/loss from recording the exchange gain/loss on the debt. The amounts reclassified from other comprehensive income into net income ~~were an increase~~resulted in increases to net income of $1 million and $35 million in 2013 and 2012, respectively, and a decrease to net income of $7 million in 2011~~, and a decrease to net income of $17 million~~ in ~~2010~~. These reclassifications, coupled with the recording of the exchange gain/loss on the debt, ~~resulted in a net effect~~did not have an impact on net income ofin ~~zero~~ ~~for~~ ~~2012~~2013, ~~2011~~2012, and ~~2010~~2011. ~~Due~~Based on forecasted foreign currency exchange rates, TVA expects to ~~the number~~reclassify approximately $53 million of ~~variables affecting the future gains/~~losses ~~on these instruments, TVA is unable to reasonably estimate the amount to be reclassified~~ from accumulated other comprehensive income to ~~net income~~interest expense within the next twelve months to offset amounts anticipated to be recorded in ~~future years.~~interest expense related to exchange gain on the debt.

Interest paid was $1.3 billion, $1.4 billion, and $1.4 billion in ~~each of~~2013, 2012, and 2011, ~~and~~ ~~2010~~.respectively. These amounts differ from interest expense due to the timing of payments and interest capitalized of $168 million in 2013, $171 million in 2012, and $126 million in 2011~~, and $79 million~~ in ~~2010~~ as a part of major capital expenditures.

Construction in progress and Nuclear Fuel expenditures included in Accounts payable and accrued liabilities at September 30, 2013, 2012, and 2011 were $270 million, $204 million, and $307 million, respectively, and are excluded from the Statements of Consolidated Cash Flows for the years ending 2013, 2012, and 2011 as non-cash investing activities. In November 2013, in accordance with the regulated operations property, plant and equipment accounting guidance, the TVA Board approved the treatment of all amounts currently included in Construction in progress related to Bellefonte as a regulatory asset. Bellefonte amounts included in Construction expenditures for 2013, 2012, and 2011 were $162 million, $212 million, and $199 million.

TVA sponsors a qualified defined benefit pension plan that covers most of its full-time employees, a qualified defined contribution plan that covers most of its full-time employees, two unfunded post-retirement health care plans that provide for non-vested contributions toward the cost of ~~certain~~eligible retirees' medical coverage, other postemployment benefits such as workers' compensation, and the SERP.

Defined Benefit Pension Plan. TVA sponsors a qualified defined benefit pension plan for most of its full-time annual employees that provides two benefit structures: the Original Benefit Structure and the Cash Balance Benefit Structure. Eligible employees initially hired on or after January 1, 1996, must participate in the Cash Balance Benefit Structure. A summary of the benefits provided by each structure is as follows:

The defined benefit pension plan is administered by a separate legal entity, Tennessee Valley Authority Retirement System ("TVARS"), which is governed by its own board of directors (the "TVARS Board"). Upon notification by the TVARS Board of athe minimum required and recommended contributions, TVA determines the level of contribution to make to TVARS for the ~~next~~upcoming fiscal ~~year, TVA determines whether~~year.

In CY 2014, the COLA benefit of CPI-U, capped at 5.0 percent, is to be ~~required by the rules and regulations of TVARS.~~restored.

Defined Contribution Plan. TVARS also administers a qualified defined contribution 401(k) plan to which TVA makes matching contributions of 25 cents on the dollar (up to 1.5 percent of annual pay) for members participating in the Original Benefit Structure and 75 cents on the dollar (up to 4.5 percent of annual pay) for members participating in the Cash Balance Benefit Structure. TVA made matching contributions of approximately $34 million to the plan during 2013, $34 million during 2012, and $31 million during 2011~~, and $27 million~~ ~~during~~ ~~2010~~.

Supplemental Executive Retirement Plan. TVA has established a SERP for certain executives in critical positions to provide supplemental pension benefits tied to compensation that exceeds limits imposed by IRS rules applicable to the qualified defined benefit pension plan. TVA has historically funded the annual calculated expense.

Other Post-Retirement Benefits. TVA sponsors two unfunded post-retirement benefit plans that provide for non-vested contributions toward the cost of certain eligible retirees’ medical coverage. The first plan covers only certain retirees and surviving dependents who do not qualify for TVARS benefits, including the ~~vested~~ supplemental pension benefit. The second plan is designed to place a limit on the out-of-pocket amount certain eligible retirees pay for medical coverage and provides a credit based on years of TVA service and monthly base pension amount, reduced by any TVARS supplemental pension benefits or any TVA contribution from the first plan, described above.

Other ~~Post-employment~~Post-Employment Benefits. TVA employees injured in work-related incidents are covered by the workers’ compensation program for federal employees administered through the Department of Labor by the Office of Workers’ Compensation Programs in accordance with the provisions of ~~the~~ FECA. FECA provides compensation and medical benefits to federal employees for permanent and temporary disability due to employment-related injury or disease.

Regulatory Accounting. TVA has classified all amounts related to unrecognized prior service costs, net actuarial gains or losses, and ~~subsequent changes in~~ the funded status as regulatory ~~assets.~~assets as such amounts are probable of collection in future rates.

Cost Method. TVA uses the projected unit credit cost method to determine the service cost and the projected benefit obligation for retirement, termination, and ancillary benefits. Under this method, a “projected accrued benefit” is calculated at the beginning of the year and at the end of the year for each benefit that may be payable in the future. The “projected accrued benefit” is based on the plan’s accrual formula and upon service at the beginning or end of the year, but it uses final average compensation, social security benefits, and other relevant factors projected to the age at which the employee is assumed to leave active service. The projected benefit obligation is the actuarial present value of the “projected accrued benefits” at the beginning of the year for employed participants and is the actuarial present value of all benefits for other participants. The service cost is the actuarial present value of the difference between the “projected accrued benefits” at the beginning and end of the year.

Amortization of Net Gain or Loss. TVA utilizes the corridor approach for gain/loss amortization. Differences between actuarial assumptions and actual plan results are deferred and amortized into periodic cost only when the accumulated

Asset Method. TVA recognizes the impact of asset performance on pension expense over a three-year phase-in period through a “market-related” value of assets calculation. Since the “market-related” value of assets recognizes investment gains and losses over a three-year period, the future value of assets will be impacted as previously deferred gains or losses are recognized. The “market-related” value is used in calculating expected return on plan assets and net gain or loss for pension cost determination.

The changes in plan obligations, assets, and funded status for the years ended September 30, ~~2012~~2013 and ~~2011~~2012, were as follows:

The pension actuarial gain above for 2013 primarily reflects the impact of the increase in the discount rate from 4.00 percent to 5.00 percent, which decreased the liability by approximately $1.4 billion. The actuarial gain is offset by the impact of including certain retiree benefits in the pension obligation which were not considered in prior periods, which increased the 2013 liability by $705 million. The pension actuarial loss ~~above~~ for 2012 primarily reflects the impact of the reduction in the discount rate from 4.50 percent to 4.00 percent, which increased the liability by approximately $683 million. ~~The pension actuarial loss for~~ ~~2011~~ ~~primarily reflects the impact of the reduction in the discount rate from~~ ~~5.00 percent~~ to ~~4.50 percent, which increased the liability by approximately $591 million~~.

Amounts related to these benefit plans recognized on TVA's consolidated balance sheets consist of regulatory assets that have not been recognized as components of net periodic benefit cost at September 30, ~~2012~~2013 and ~~2011~~2012, and the funded status of TVA’s benefit plans, which are included in Accounts payable and accrued liabilities and Post-retirement and post-employment benefit obligations:

The components of net periodic benefit cost and other amounts recognized as changes in regulatory assets for the years ended September 30, ~~2012~~2013, and ~~2011~~2012, were as follows:

Discount Rate. In selecting the assumed discount rate, TVA reviews market yields on high-quality corporate debt and long-term obligations of the U.S. Treasury and endeavors to match, through the use of a hypothetical bond portfolio, instrument maturities with the maturities of its pension obligations in accordance with the prevailing accounting standards. The selected bond portfolio is derived from a universe of high quality corporate bonds of Aa-rated quality or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan's projected benefit payments discounted at this rate with the market value of the bonds selected. Based on recent market trends, TVA ~~decreased~~increased its discount rate used to determine the pension benefit obligation and other post-retirement obligation from 4.00 percent at the end of 2012 for both obligations to 5.00 percent and 5.05 percent, respectively, at the end of 2013. TVA had decreased its discount rate from 4.50 percent at the end of 2011 to 4.00 percent at the end of 2012~~. TVA had decreased its~~ for both pension and other post-retirement obligations. The discount rate ~~from~~ ~~5.00 percent~~assumptions used to determine the obligations at year-end are used to determine the ~~end of~~ ~~2010~~ to ~~4.50 percent~~ atnet periodic benefit costs for the ~~end of~~ ~~2011~~.following year.

Rate of Return. In determining its expected long-term rate of return on pension plan assets, TVA uses a process that incorporates actual historical asset class returns and an assessment of expected future performance and takes into consideration external actuarial advice and asset class factors. Changes in the expected return rates are generally based on annual studies performed by third party professional investment consultants. Based on the results from annual studies for 2013, 2012 ~~2011,~~, and ~~2010,~~2011, TVA adjusted the expected return on plan assets rate used to develop the net periodic pension benefit cost for 2013, 2012 ~~2011,~~, and ~~2010~~2011 to 7.25 percent, ~~7.50~~7.25 percent, and ~~7.75~~7.50 percent, respectively. Asset allocations are periodically updated using the pension plan asset/liability studies, and are part of the determination of the estimates of long-term rates of return. The expected rate of return had been reduced ~~both~~ in ~~2010 and~~ 2011 based upon the annual ~~studies~~study performed and a change of investment allocation policies. Investment allocation changes in 2010 shifted a portion of equities to fixed income, and in September 2011, the TVARS Board approved a long-term investment plan which contains a dynamic de-risking strategy that allocates investments to assets that better match the liability, such as long duration fixed-income securities over time as funding status targets are met. In September ~~2012,~~2013, the TVARS Board approved a new initial asset allocation policy that includes additional asset class diversification and maintains the long-term expected return of 7.25 percent (see Plan Investments below). The actual rate of return for the years ended September 30, ~~2012~~2013 and ~~2011~~2012 were ~~16.81~~11.69 percent and ~~less than~~ ~~one~~16.81 percent, respectively.

Compensation Increases. Assumptions related to compensation increases are based on the results obtained from an actual company experience study performed during the most recent five years for plan participants. TVA obtained an updated study in ~~2008~~2013 and determined that future compensation would likely increase at rates between ~~3.30~~3.50 percent and ~~10.10~~13.00 percent per year, depending upon the employee's age. Based upon the current active participants, the average assumed compensation increase used to determine benefit obligations for ~~2012~~2013 and ~~2011~~2012 was ~~4.44~~5.72 percent and ~~4.43~~4.44 percent, respectively.

Mortality. Mortality assumptions are based on the results obtained from a recent actual company experience study performed which included retirees as well as other plan participants. TVA obtained an updated study in ~~2008 and, accordingly, adjusted the~~2013, determining an improvement in TVA's mortality rates from the 1983 Group Annuity Mortality Tables to the RP-2000 Mortality Tables. During 2010, TVA's experience was reexamined and it was determined that TVA’s mortality experience has continued to improve. As a result,experience. Accordingly, TVA adjusted the ~~mortality rates to~~projection period for the RP-2000 Mortality Tables for males and females projected to ~~2013~~2022 using scale AA at September 30, ~~2010. There were no changes~~2013. At September 30, 2012 and 2011, the projection period for the RP 2000 Mortality Tables for males and females was projected to ~~the mortality assumptions in~~ ~~2012~~.2013 using scale AA.

Health Care Cost Trends. TVA reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. As of September 30, ~~2012~~2013 and ~~2011~~2012, the medical care trend rates used to determine the post-retirement benefit obligations were ~~8.50~~8.00 percent and ~~8.00~~8.50 percent, respectively. TVA increased the rate in 2012 based upon exhibited annual increases in costs per covered life due primarily to changes in inflation, utilization, and recent healthcare ~~law~~ regulations. ~~This increase~~The rate is assumed to gradually decrease each successive year until it reaches a 5.00 percent annual increase in health care costs in the year beginning October 1, 2019, and beyond. The assumed ~~healthcare~~health care cost trend rate used to determine the post-retirement net periodic benefit cost was8.50 percent for 2013, 8.00 percent for 2012, ~~2011,~~ and ~~2010.~~8.00 percent for 2011.

Cost of Living Adjustment. ~~Thequalified defined benefit pension plan includes~~COLAs are an increase in the benefits for eligible retirees to help maintain the purchasing power of benefits as consumer prices increase. Eligible retirees may receive a COLA ~~that~~in January following any year in which the 12-month average CPI-U exceeded by as much as one percent the 12-month average of the CPI-U for the preceding year on the base pension portion of the monthly pension benefit. The minimum COLA is ~~generally indexed against~~one percent and the ~~CPI, subject to a floor and ceiling.~~maximum is five percent. The ~~CPI fell during 2009, and market-based measures of inflation expectations at the end of 2009 projected slow growth in the CPI through 2015. Additionally, the~~ COLA was temporarily reduced for a four-year period beginning January 1, 2010 for current retirees, and the eligibility for the COLA was changed to age 60 from attained age 55for employees retiring on or after January 1, 2010. The COLA assumption has been ~~2.5~~2.50 percent since ~~2009. Due~~2009; however, due to ~~stabilizing~~the Federal Reserve System’s long-term monetary policy and the market-based measure of inflation expectations that inflation will remain below two percent into 2015, TVA ~~determined~~adjusted the COLA assumption ~~should be held~~ at September 30, 2013 to 1.6 percent with an assumed gradual increase each successive year until it reaches 2.5 percent at ~~September 30, 2012~~.in 2019.

Sensitivity of Costs to Changes in Assumptions. The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions:

The qualified defined benefit pension plan (the "Plan"), which includes the Original Benefit Structure and the Cash Balance Benefit Structure, is the only plan that includes qualified plan assets. TVARS has a long-term investment plan which contains a dynamic de-risking strategy that allocates investments to assets that better match the liability, such as long duration fixed income securities, over time as funding status targets are met. In September ~~2012,~~2013, the TVARS Board approved a new initial asset allocation policy. The approved investment allocation policy has targets of 4847 percent equity including U.S., non-U.S., private, and ~~private~~low volatility global public equity investments, 2728 percent fixed income securities, 15 percent public real assets including Treasury Inflation-Protected Securities ("TIPS"), commodities, and Master Limited Partnerships ("MLPs"), and 10 percent private real assets. The qualified pension plan assets are invested inacross global public equity, ~~securities, debt securities, U.S. equities, international equities,~~private equity, cash, core fixed income, long-term core fixed income, investment grade credit, high yield fixed income, global TIPS, MLPs, and private real ~~estate, timber, investment-grade debt, high-yield debt, U.S. Treasury inflation-protected securities, currencies, and derivative instruments such as futures, options, swaps, and forwards.~~assets. The TVARS asset allocation policy includes permissible deviations from these target allocations. The TVARS Board can take action, as appropriate, to rebalance the system’s assets consistent with the asset allocation policy. At September 30, ~~2012~~2013 and ~~2011~~2012, the asset holdings of the system included the following:

The following table provides the fair value measurement amounts for assets held by TVARS at September 30, 2013:

The following table provides the fair value measurement amounts for assets held by TVARS at September 30, 2012:

Vendor-provided prices for the ~~Plan's~~Plan’s investments are subjected to automated tolerance checks by the trustee to identify and avoid, where possible, the use of inaccurate prices. Any questionable prices identified are reported to the vendor ~~which~~that provided the price. If the prices are validated, the primary pricing source is used. If not, a secondary source price that has passed the applicable tolerance check is used (or queried with the vendor if it is out of tolerance), resulting in either the use of a secondary price, where validated, or the last reported default price, as in the case of a missing price. For monthly valued accounts, where secondary price sources are available, an automated inter-source tolerance report identifies prices with an inter-vendor pricing variance of over two percent at an asset class level. For daily valued accounts, each security is assigned, where possible, an indicative major market index, against which daily price movements are automatically compared. Tolerance thresholds are established by asset class. Prices found to be outside of the applicable tolerance threshold are reported and queried with vendors as described above.

~~Equities~~.Equities. Investment securities, including common stock, ~~and~~ mutual funds, and MLPs, listed on either a national or foreign securities exchange or traded in the over-the-counter ~~national market system~~National Market System, are generally valued each business day at the official closing price (typically the last reported sale price) on the exchange on which the security is primarily traded. If there are no current day sales, the securities are valued at their last quoted bid price. Equities priced by an exchange in an active market are classified as Level 1. ~~Equities priced using unobservable inputs are classified as Level 3.~~

Preferred ~~Securities~~Securities.. Preferred securities are valued at their quoted market price (Level 1 inputs), or in such instances where quoted market prices are unavailable, the fair value is estimated based on yields currently available on comparable securities of issues with similar credit ratings (Level 2 inputs). ~~Certain~~Most preferred securities ~~priced used using unobservable inputs have been~~ classified as Level 3.2 have been priced by dealer quote. Others may have been evaluated using theoretical assumptions based on observable market data, such as yields on bonds from the same issuer or industry.

Corporate Debt ~~Securities~~Securities.. Corporate bonds are valued based upon recent bid prices or the average of recent bid and asked prices when available (Level 2 inputs) and, if not available, they are valued through matrix pricing models developed by sources considered by management to be reliable. Matrix pricing, which is a mathematical technique commonly used to price debt securities that are not actively traded, values debt securities without relying exclusively on quoted prices for the specific securities but rather by relying on the ~~securities'~~securities’ relationship to other benchmark quoted securities (Level 2 inputs). ~~Certain corporate debt securities priced using unobservable inputs have been classified as Level 3.~~

Residential Mortgage-Backed ~~Securities~~Securities.. Residential mortgage-backed securities consist of collateralized mortgage obligations ("CMOs") and U.S. pass-through security pools related to government-sponsored enterprises ("GSE"). CMO pricing is typically based on either a volatility-driven, multidimensional, ~~single cash flow~~single-cash-flow stream model or an option-adjusted spread model. These models incorporate available market data such as trade information, dealer quotes, market color, spreads, bids,

U.S. Treasury and Agency ~~Securities~~Securities.. For U.S. Treasury securities, fair values reflect the closing price reported in the active market in which the security is traded (Level 1 inputs). Agency securities are typically priced using evaluated pricing applications and models incorporating U.S. Treasury yield curves. Agency securities are classified as Level 2 because of the nature of their market-data-based pricing models.

Debt Securities Issued by Foreign Governments.These include foreign government bonds and foreign government inflation-linked securities. They are typically priced based on proprietary discounted cash flow models, incorporating option-adjusted spread features as appropriate. Debt securities issued by foreign governments are classified as Level 2 because of the nature of their market-data-based pricing models. ~~Debt securities issued by foreign governments priced using unobservable inputs are classified as Level 3.~~

Asset-Backed ~~Securities~~Securities.. Asset-backed securities are typically priced based on a single cash-flow stream model, which incorporates available market data such as trade information, dealer quotes, market color, spreads, bids, and offers. Because of the market-data-based nature of such pricing models, asset-backed securities are classified as Level 2. ~~Asset-backed securities priced using unobservable inputs are classified as Level 3.~~

Debt Securities Issued by State and Local ~~Governments~~Governments.. Debt securities issued by state and local governments are typically priced using market-data-based pricing models, and are therefore classified as Level 2. These pricing models incorporate market data such as quotes, trading levels, spread relationships, and yield curves, as applicable. ~~Debt securities issued by state and local governments priced using unobservable inputs are classified as Level 3.~~

Commercial Mortgage-Backed ~~Securities.~~ Securities.Commercial mortgage-backed securities are typically priced based on a ~~single cash flow~~single-cash-flow stream model, which incorporates available market data such as trade information, dealer quotes, market color, spreads, bids, and offers. Because of the market-data-based nature of such pricing models, commercial mortgage-backed securities are classified as Level 2.

Private Equity Funds.Private equity limited partnerships and other similar alternative investments are reported at fair value, which is derived by independent appraisals or investment management judgment. The inputs used by the General Partners in estimating the fair value of the limited partnerships include the original transaction prices, recent transactions in the same or similar instruments, completed or pending third-party transactions in the underlying investments or comparable issues, subsequent rounds of financing, recapitalizations, and other transactions across the capital structure, offerings in the equity or debt capital markets, and changes in financial ratios or cash flows. These investments may also be adjusted to reflect illiquidity and/or non-transferability, with the amount of such discounts estimated by the General Partners in the absence of market information. Due to the lack of observable inputs, the determination of the fair value by the General Partners may differ materially from the value ultimately realized by the Partnership.

The private equity funds have no investment withdrawal provisions prior to the termination of the partnerships. Partnerships generally continue 10 to 12 years after the inception of the fund. The partnerships are subject to three to fourone-

Private Real Estate ~~Funds.~~ Investments.The ~~Plan's~~Plan’s ownership in ~~the~~ private real estate investments consists of a pro rata share and not a direct ownership of the underlying investments. The fair values of the ~~Plan's~~Plan’s private real estate investments are estimated utilizing net asset values provided by the investment managers. The methodologies utilized by the investment managers to calculate their net asset values are summarized as follows:

Derivatives. The Plan invests in a variety of derivative instruments. The valuation methodologies for these instruments are as follows:

Futures.The Plan enters into ~~equity futures, foreign currency futures and interest rate~~ futures. The futures contracts are listed on either a national or foreign securities exchange and generally valued each business day at the official closing price (typically the last reported sales price) on the exchange on which the security is primarily traded. The pricing is performed by third-party vendors. Since futures are priced by an exchange in an active market, they are classified as Level 1.

Options.The Plan enters into ~~interest rate options, foreign currency options~~purchased and ~~fixed income~~written options. Options that are listed on either a national or foreign securities exchange are generally valued each business day at the official closing price (typically the last reported sales price) on the exchange on which the security is primarily traded. These options are classified as Level ~~1 and include both written and purchased options on Treasury note futures and Eurodollar futures.~~1. Options traded over the counter and not inon exchanges are priced by third-party vendors and are classified as Level 2. ~~This includes both written and purchased options on interest rate swaps.~~

Swaps.The Plan enters into various types of swaps. Credit default swaps are priced at market using models that consider cash flows, credit curves, recovery rates, and other factors. The pricing is performed by third-party vendors. Interest rate swap contracts are priced at market using forward rates derived from the swap curve, and the pricing is also performed by third-party vendors. Other swaps such as ~~currency~~equity index swaps and ~~total return~~variance swaps are priced by third-party vendors using market inputs such as spot rates, yield curves, and ~~yield curves. These~~volatility. The Plan’s swaps are generally classified as Level 2 ~~due to~~based on the observable ~~inputs which are incorporated into~~nature of their pricing ~~models.~~inputs.

Foreign ~~currency forwards~~Currency Forwards.The Plan enters into foreign currency forwards. All commitments are marked to market daily at the applicable translation rates, and any resulting unrealized gains or losses are recorded. Foreign currency forwards are priced by third-party vendors and are classified as Level ~~2 due to the market-based nature~~2.

Commingled ~~Funds~~Funds.. The Plan invests in commingled funds, which include collective trusts, unit investment trusts, and similar investment funds that predominantly hold debt and/or equity securities as underlying assets. The ~~Plan's~~Plan’s ownership

Institutional Mutual ~~Funds~~Funds.. Participation units of institutional mutual funds are stated at their quoted redemption values as reported by the investment managers based on their net asset values, which reflect the fair values of the underlying investments. These funds are traded at published net asset values in an active market (Level 1 inputs).

Cash Equivalents and Other Short-Term ~~Investments~~Investments.. Cash equivalents and other short-term investments represent securities with maturities of less than twelve months. Cash equivalents are highly liquid securities ~~with~~and consists of certificates of deposit and commercial paper. The carrying amounts of these instruments approximate their fair values and each are considered a ~~maturity of less than three months and 12 months respectively. These consist primarily~~Level 1 valuation classification. Other short-term investments consists of U.S. Treasury securities, residential mortgage-backed securities, ~~commercial paper,~~ corporate bonds, and asset-backed ~~securities and certificates of deposit.~~securities. U.S. Treasury securities are ~~priced based on~~valued using the closing price reported in the active market in which the security is traded and is considered a Level 1 ~~inputs as described above. The other types of cash equivalent~~valuation classification. Residential mortgage-backed securities and ~~other short-term investments,~~asset-backed securities are typically valued with pricing models using observable market data such as ~~described above,~~trade information, dealer quotes, market color, spreads, bids, and offers. Accordingly, these securities are ~~priced~~considered Level 2 classifications. Corporate bonds are valued based upon recent bid prices or the average of recent bid and asked prices, or are valued through matrix pricing models using ~~models that incorporate market-based inputs~~market information for similar benchmark quoted securities, and are ~~therefore classified as~~also considered Level 2.2 classifications.

Contributions. In ~~2012,~~2013, TVA made contributions of $86 million to the SERP and $4147 million to the other post-retirement benefit plans. TVA expects to contribute $6 million to the SERP and $3840 million to the other post-retirement benefit plans in ~~2013.~~2014. In 2009, TVA entered into an agreement with TVARS resulting in TVA ~~prefunding annual~~contributing $1.0 billion for 2010 and as an advance on contributions for 2011through 2013 ~~for a~~. In 2011, TVA made an additional discretionary contribution to TVARS. TVA plans to contribute $250 million to the defined pension plan in 2014.

Post-employment benefit cost estimates are revised to properly reflect changes in actuarial assumptions made at the end of each year. TVA utilizes a discount rate determined by reference to the U.S. Treasury Constant Maturities corresponding to calculated average durations of TVA’s future estimated post-employment claims payments. The use of a ~~1.65~~2.64 percent discount rate resulted in the recognition of approximately $52(8) million in expenses in ~~2012~~2013 and an unpaid benefit obligation of about $~~597~~535 million at September 30, ~~2012~~2013. The2013 current portion of the obligation is $49 million and is recorded in Accounts payable and accrued liabilities. The 2013 long-term portion of $486 million is recorded in Post-retirement and post-employment benefit obligations. TVA utilized discount rates of 1.65 percent and 1.92 percent in 2012 and 2011, respectively. The use of these discount rates resulted in expense and unpaid benefit obligations of $52 million and $597 million, respectively, for 2012 and expense and unpaid benefit obligations of $81 million and $596 million, respectively, for 2011. The 2012 current portion of the obligation is $53 million and is recorded in Accounts payable and accrued liabilities. The 2012long-term portion of $544 million is recorded in Post-retirement and post-employment benefit obligations. ~~TVA utilized~~The amounts in the current portion of the obligation represent the total unpaid losses and administrative fees for each year that are due one month following TVA’s fiscal year end.

The decrease in the unpaid benefit obligation and expense from 2012 to 2013 is due primarily to the increase in the discount ~~rates of~~rate from ~~1.92 percent~~ ~~and~~ ~~2.53~~1.65 percent in ~~2011~~2012 to 2.64 percent in 2013 resulting in a decrease of $45 million. Decreases in loss experiences and ~~2010, respectively. The use of these discount rates resulted~~other changes in ~~expense and~~demographic experiences also decreased the unpaid benefit ~~obligations of~~ ~~$81 million~~ ~~and~~ ~~$596 million, respectively, for~~ ~~2011~~obligation and expense ~~and unpaid benefit obligations of~~ ~~$141 million~~ ~~and~~ ~~$570 million, respectively, for~~ ~~2010~~.to a lesser degree.

At September 30, ~~2012~~2013, the amounts of contractual cash commitments maturing in each of the next five years and beyond are shown below:

In addition to the cash requirements, above, TVA has contractual obligations in the form of revenue discounts related to energy prepayments. See Note 1 — Energy Prepayment Obligations and Discounts on Sales.

Debt. At September 30, ~~2012~~2013, TVA had outstanding discount notes of $~~1.5~~2.4 billion and long-term debt (including current maturities) at varying maturities and interest rates of $~~22.6~~22.4 billion for total outstanding indebtedness of $~~24.1~~24.8 billion. See Note 12.

Debt of VIEs. At September 30, ~~2012~~2013, TVA had outstanding long-term debt (including current maturities) ~~for~~attributable to its ~~two~~three VIEs of which it is the primary beneficiary of $~~994~~1.3 billion. See Note 8.

Membership Interests of VIE Subject to Mandatory Redemption. At September 30, 2013, TVA had outstanding membership interests subject to mandatory redemption (including current portion) of $40 million. issued by one of its VIEs of which it is the primary beneficiary. See Note 8.

Leases. TVA leases certain property, plant, and equipment under agreements with terms ranging from one to 80 years. Of the total obligations for TVA’s capital leases, $1018 million represents the cost of financing. TVA’s rental expense for operating leases was $71 million in 2013, $67 million in 2012, and $77 million in 2011~~, and $57 million~~ in ~~2010~~.

Power Purchase Obligations. TVA has contracted with various independent power producers and ~~power distributor customers~~LPCs for additional capability to be made available to TVA. Several of these agreements have contractual minimum payments. In total, these agreements provide ~~1,222~~1,621 MW of summer net capability. The remaining terms of the agreements range ~~from~~ ~~3 months~~up to 2019 years. TVA ~~spent~~incurred $322 million, $447 million, and $713 million~~, and $504 million~~ of expense under power purchase agreements during 2013, 2012, and 2011, ~~and~~ ~~2010~~, respectively. Certain power purchase obligations are accounted for as capital leases. Costs under TVA’s power purchase agreements not accounted for as capital leases are included in TVA's consolidated statements of operations as purchased power expense and are expensed as incurred.

Under federal law, TVA is obligated to purchase power from qualifying facilities, cogenerators, and small power producers. AtAs of September 30, ~~2012~~2013, there was a combined qualifying capacity of ~~918~~913 MW, from ~~eight~~six different suppliers, from which TVA purchased power under this law. TVA’s obligations to purchase power from these qualifying facilities are not included in the Commitments and Contingencies table.

TVA, along with others, contracted with the Southeastern Power Administration ("SEPA") to obtain power and energy from eight U.S. Army Corps of Engineers hydroelectric facilities on the Cumberland River system. The agreement with SEPA can be terminated upon three years’ notice, but this notice of termination may not become effective prior to June 30, 2017. The contract requires SEPA to provide TVA an annual minimum of 1,500 hours of ~~power~~energy for each megawatt of TVA’s 405 MW allocation, and all surplus ~~power~~energy from the Cumberland River system. Because hydroelectric production has been reduced at two of the hydroelectric facilities on the Cumberland River system and because of reductions in the summer stream flow on the Cumberland River, SEPA declared “force majeure” on February 25, 2007. SEPA then instituted an emergency operating plan that, among other things, eliminates SEPA’s obligation to provide TVA and other affected customers with a minimum amount of ~~power.~~power or energy. It is unclear how long the emergency operating plan will remain in effect. TVA’s obligations under its contract with SEPA are not included in the Commitments and Contingencies table.

Fuel Purchase Obligations. TVA has approximately $~~2.8~~2.3 billion in long-term fuel purchase commitments ranging in terms of up to 1110 years primarily for the purchase and transportation of coal. TVA also has approximately $~~4.3~~4.0 billion of long-term commitments ranging in terms of up to 1917 years for the purchase of enriched uranium and fabrication of nuclear fuel assemblies.

Other Obligations. Other obligations of $~~1.9~~2.6 billion consist of contracts at September 30, ~~2012~~2013, for goods and services primarily related to capital projects as well as other major recurring operating costs.

Nuclear Insurance. The Price-Anderson Act provides a layered framework of protection to compensate for losses arising from a nuclear event in the United States. For the first layer, all of the NRC nuclear plant licensees, including TVA, purchase $375 million of nuclear liability insurance from American Nuclear Insurers for each plant with an operating license. Funds for the second layer, the Secondary Financial Program, would come from an assessment of up to $~~118~~127 million from the licensees of each of the 104 NRC licensed reactors in the United States. The assessment for any nuclear accident would be limited to $1819 million per year per unit. American Nuclear Insurers, under a contract with the NRC, administers the Secondary Financial Program. With its six licensed units, TVA could be required to pay a maximum of $~~705~~764 million per nuclear incident, but it would have to pay no more than $~~105~~114 million per incident in any one year. When the contributions of the nuclear plant licensees are added to the insurance proceeds of $375 million, over $~~12.0~~13.0 billion, including a five percent surcharge for

TVA carries property, decommissioning, and decontamination insurance of $4.6 billion for its licensed nuclear plants, with up to $2.1 billion available for a loss at any one site, to cover the cost of stabilizing or shutting down a reactor after an accident. Some of this insurance, which is purchased from Nuclear Electric Insurance Limited ("NEIL"), may require the payment of retrospective premiums up to a maximum of approximately $~~109~~105 million.

TVA purchases accidental outage (business interruption) insurance for TVA’s nuclear sites from NEIL. In the event that an accident covered by this policy takes a nuclear unit offline or keeps a nuclear unit offline, NEIL will pay TVA, after a waiting period, an indemnity (a set dollar amount per week) up to a maximum indemnity of $490 million per unit. This insurance policy

Decommissioning Costs. TVA recognizes legal obligations associated with the future retirement of certain tangible long-lived assets related primarily to coal-fired generating plants and nuclear generating plants, hydroelectric generating plants/dams, transmission structures, and other property-related assets.

Nuclear. Provision for decommissioning costs of nuclear generating units is based on options prescribed by the NRC procedures to dismantle and decontaminate the facilities to meet the NRC criteria for license termination. At September 30, ~~2012~~2013, the present value ~~under GAAP~~ of the estimated future decommissioning cost of $~~2.2~~2.4 billion was included in AROs. The actual decommissioning costs may vary from the derived estimates because of, among other things, changes in current assumptions, such as the assumed dates of decommissioning, changes in regulatory requirements, changes in technology, and changes in the cost of labor, materials, and equipment. Utilities that own and operate nuclear plants are required to use different procedures in calculating nuclear decommissioning costs under GAAP than those that are used in calculating nuclear decommissioning costs when reporting to the NRC. The two sets of procedures produce different estimates for the costs of decommissioning primarily because of the difference in the discount rates used to calculate the present value of decommissioning costs.

TVA maintains a NDT to provide funding for the ultimate decommissioning of its nuclear power plants. ~~The balance at~~ ~~September 30, 2012, was less than the present value of the estimated future nuclear decommissioning costs under the NRC methodology and under GAAP.~~ TVA monitors the ~~monetary~~ value of its NDT and believes that, over the long term and before cessation of nuclear plant operations and commencement of decommissioning activities, adequate funds from investments will be available to support decommissioning. TVA’s nuclear power units are currently authorized to operate until 2020-2036, depending on the unit. It may be possible to extend the operating life of some of the units with approval from the NRC. See Note 7 — Nuclear Decommissioning Costs and Note 11.

Non-Nuclear Decommissioning. The present value of the estimated future non-nuclear decommissioning cost ARO was $1.1 billion at September 30, ~~2012~~2013. This decommissioning cost estimate involves estimating the amount and timing of future expenditures and making judgments concerning whether or not such costs are considered a legal obligation. Estimating the amount and timing of future expenditures includes, among other things, making projections of the timing and duration of the asset retirement process and how costs will escalate with inflation. The actual decommissioning costs may vary from the derived estimates because of changes in current assumptions, such as the assumed dates of decommissioning, changes in regulatory requirements, changes in technology, and changes in the cost of labor, materials, and equipment.

TVA maintains an ART to help fund the ultimate decommissioning of its power assets. Estimates involved in determining if additional funding will be made to the ART include inflation rate and rate of return projections on the fund investments. See Note 7 — Non-Nuclear Decommissioning Costs and Note 11.

Environmental Matters. TVA’s power generation activities, like those across the utility industry and in other industrial sectors, are subject to most federal, state, and local environmental laws and regulations. Major areas of regulation affecting TVA’s activities include air quality control, water quality control, and management and disposal of solid and hazardous wastes. In the future, regulations in all of these areas are expected to become more stringent. Regulations are also expected to apply to new emissions and sources, with a particular emphasis on climate change, renewable generation, and energy efficiency.

TVA has incurred, and expects to continue to incur, substantial capital and operating and maintenance costs to comply with evolving environmental requirements primarily associated with, but not limited to, the operation of TVA’s coal-fired generating units. It is virtually certain that environmental requirements placed on the operation of TVA’s coal-fired and other generating units will continue to become more restrictive and potentially apply to new emissions and sources. Litigation over emissions or discharges from coal-fired generating units is also occurring, including litigation against TVA. Failure to comply with environmental and safety laws can result in TVA being subject to enforcement actions, which can lead to the imposition of significant civil liability, including fines and penalties, criminal sanctions, and/or the shutting down of non-compliant facilities.

From 1977 to ~~2012~~2013, TVA spent approximately $~~5.4~~5.6 billion to reduce emissions from its power plants, including $38182 million, $3438 million, and $5834 million in ~~2012~~2013, ~~2011~~2012, and ~~2010~~2011, respectively. TVA estimates that compliance with future Clean Air Act ("CAA") requirements (excluding greenhouse gas ("GHG") requirements) could lead to additional costs of $~~2.3~~1.3 billion from ~~2013~~2014 to ~~2018.~~2022. There could be additional material costs if reductions of GHGs, including carbon dioxide ("CO₂"), are mandated

Liability for releases and cleanup of hazardous substances is primarily regulated by the federal Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), and other federal and parallel state statutes. In a manner similar to many other industries and power systems, TVA has generated or used hazardous substances over the years.

TVA is aware of alleged hazardous-substance releases at certain non-TVA areas for which it may have some liability. Although there is little or no known evidence that TVA contributed any significant quantity of hazardous substances to most of the non-TVA areas, there is evidence that TVA sent some materials to Ward Transformer, a non-TVA site in Raleigh, North Carolina. The Ward Transformer site is contaminated by PCBs from electrical equipment. There is documentation showing that TVA sent a limited amount of electrical equipment containing PCBs to the site in 1974. A working group of potentially responsible parties (the "PRP Work Group") is cleaning up on-site contamination in accordance with an agreement with the EPA. The cleanup effort has been divided into four areas: two phases of soil cleanup; cleanup of off-site contamination in the downstream drainage basin; and supplemental groundwater remediation. The cost estimate for the first phase of soil cleanup is approximately $55 million. The cost estimate for the second phase of soil cleanup is $10 million. Estimates for cleanup of off-site contamination in the downstream drainage basin range from $6 million to $25 million. There are no reliable estimates for the supplemental groundwater remediation phase. On April 30, 2009, the PRP Work Group filed an amended complaint in federal court against potentially responsible parties who had not yet settled, including TVA, regarding the two phases of soil cleanup. TVA settled this lawsuit and its potential liability for the two phases of soil cleanup for $300 thousand and has been dismissed as a party. Although the settlement with respect to the first two phases does not prohibit TVA from having liability in connection with the other two phases or any natural resource damages, the U.S. Department of Justice is attempting to negotiate a government-wide settlement of the liability of all federal agencies (including TVA) for cleanup of offsite contamination in the downstream drainage basin and the investigative portion of the supplemental groundwater remediation. TVA believes that its liability for the remaining two phases and natural resource damages is less than $1 million.

TVA operations at some TVA facilities have resulted in oil spills and other contamination that TVA is addressing. At September 30, ~~2012~~2013, TVA’s estimated liability for cleanup and similar environmental work for those sites for which sufficient information is available to develop a cost estimate (primarily the TVA sites) was approximately $1115 million on a non-discounted basis and was included in Accounts payable and accrued liabilities and Other long-term liabilities on the Balance Sheet.

Other. TVA is undertaking cost reduction initiatives with the goal of keeping rates low, keeping reliability high, and continuing to fulfill its broader mission of environmental stewardship and economic development. TVA will focus on reducing operating and maintenance costs through further efficiency gains and streamlining the organization. Given that approximately 80 percent of TVA's operating and maintenance costs are related to labor, staffing level reductions will necessarily result from this process. The evaluation of staffing levels will take into account attrition, elimination of open positions, and retirements in order to minimize the impact on current personnel. Certain employees may be eligible for severance payments if impacted by the reorganization, but the amount of such payments is not reasonably estimable at this time as management's evaluation of staffing levels is not yet complete. Accordingly, no severance costs have been accrued as of September 30, 2013. TVA’s goal is to reduce operating and maintenance costs by $500 million by 2015 as compared to its 2013 budget.

From time to time, TVA is party to or otherwise involved in lawsuits, claims, proceedings, investigations, and other legal matters ("Legal Proceedings") that have arisen in the ordinary course of conducting TVA's activities, as a result of a catastrophic event or otherwise.

General. At September 30, 2013, TVA had accrued approximately $~~354~~302 million of ~~potential~~probable losses with respect to Legal Proceedings at and estimated the range of these losses to be from $~~September 30, 2012~~302 million to $314 million. Of ~~this~~the accrued amount, $~~237~~189 million is included in Other long-term liabilities, $~~107~~85 million is included in Accounts payable and accrued liabilities, and $1028 million is included in Regulatory assets. TVA is currently unable to estimate any amount or any range of amounts of reasonably possible losses, ~~in excess of the established accruals, but~~and no assurance can be given that TVA will not be subject to significant additional claims and liabilities. If actual liabilities significantly exceed the estimates made, TVA's results of operations, liquidity, and financial condition could be materially adversely affected.

Environmental Agreements. In April 2011, TVA entered into two substantively similar agreements, one with the EPA and the other with Alabama, Kentucky, North Carolina, Tennessee, and three environmental advocacy groups: the Sierra Club, the National Parks Conservation Association, and Our Children's Earth Foundation (collectively, the "Environmental Agreements”). They became effective in June 2011. Under the Environmental Agreements, TVA committed to (1) retire on a phased schedule 18 coal-fired units with a combined summer net dependable capability of 2,200 MW, (2) control, convert, or retire additional coal-fired units with a combined summer net dependable capability of 3,500 MW, (3) comply with annual, declining emission caps for SO₂ and NO_x, (4) invest $290 million in certain TVA environmental projects, (5) provide $60 million to Alabama, Kentucky, North Carolina, and Tennessee to fund environmental projects, and (6) pay civil penalties of $10 million. In exchange for these commitments, most ~~existing and possible~~past claims against TVA based on alleged New Source Review and associated

The liabilities related to the Environmental Agreements are included in Accounts payable and accrued liabilities and Other long-term liabilities on the September 30, ~~2012~~2013 Consolidated Balance Sheet. In conjunction with the approval of the Environmental Agreements, the TVA Board determined that it was appropriate to record TVA's liabilities under the Environmental Agreements as regulatory assets, and they are included as such on the September 30, ~~2012~~2013 Consolidated Balance Sheet and will be recovered in rates in future periods.

Legal Proceedings Related to the Kingston Ash Spill. Seventy-eight lawsuits based on the Kingston ash spill have been filed in the United States District Court for the Eastern District of Tennessee. Fifteen of these lawsuits have been dismissed, and 63 lawsuits are active and in various stages of litigation. Plaintiffs are residents, businesses, and property owners in the Kingston area and allege tort claims for damage to property (for example, nuisance, strict liability, trespass, and

A bench trial on the issue of dike failure causation in the seven earliest cases was held in September and October 2011 ("Phase I trial"). Plaintiffs in the 56 remaining cases have agreed to be bound by the Phase I trial record and decision. In August 2012, the court issued its Phase I decision, finding that certain actions by TVA contributed to the ash spill. On November 20, 2012, the court ordered the parties to participate in mediation within 120 days of the issuance of the order. The court has extended the mediation period three times, and the mediation period is now scheduled to end on January 14, 2014. If the case is not resolved through mediation, the case will ~~now~~ proceed to the damages phase ("Phase II") trial, during which the individual plaintiffs must prove both that they incurred damages and that the ash spill was the cause of the damages. The date for the Phase II trial has not yet been set.

TVA has received several notices of intent to sue under various environmental statutes from both individuals and environmental groups, but no such suits have been filed.

Civil Penalty and Natural Resource Damages for the Kingston Ash Spill. In June 2010, TDEC issued a civil penalty order of approximately $12 million to TVA for the Kingston ash spill, citing violations of the Tennessee Solid Waste Disposal Act and the Tennessee Water Quality Control Act. Of the $12 million, TVA has satisfied $10 million, and TDEC has approved environmental projects valued at $2 million as a credit against the penalty amount. In January 2011, TVA entered into a memorandum of agreement with TDEC and the U.S. Fish and Wildlife Service establishing a process and a method for resolving the natural resource damage claim associated with the Kingston ash spill. As part of this memorandum of agreement, TVA agreed to pay $250 thousand each year for three years as a down payment on the amount of natural resource damages ultimately established, and to reimburse TDEC and the U.S. Fish and Wildlife Service for their costs.

Case Involving Tennessee Valley Authority Retirement System. In March 2010, eight current and former participants in and beneficiaries of ~~the~~ TVARS filed suit in the United States District Court for the Middle District of Tennessee against the six then-current members of the TVARS Board. The lawsuit challenged the TVARS Board's decision to suspend the TVA contribution requirements for 2010 through 2013, and to amend the TVARS Rules and Regulations to (1) reduce the calculation for COLA benefits for CY 2010 through CY 2013, (2) reduce the interest crediting rate for the fixed fund accounts, and (3) increase the eligibility age to receive COLAs from age 55 to 60. The plaintiffs allege that these actions violated the TVARS Board members' fiduciary duties to the plaintiffs (and the purported class) and the plaintiffs' contractual rights, among other claims. The plaintiffs sought, among other things, unspecified damages, an order directing the TVARS Board to rescind the amendments, and the appointment of a seventh TVARS Board member. Five of the six individual defendants filed motions to dismiss the lawsuit, while the remaining defendant filed an answer to the complaint. In July 2010, TVA moved to intervene in the suit in the event it was not dismissed. In September 2010, the district court dismissed the breach of fiduciary duty claim against the directors without prejudice, allowing the plaintiffs to file an amended complaint within 14 days against TVARS and TVA but not the individual directors. The plaintiffs previously had voluntarily withdrawn their constitutional claims, so the court also dismissed those claims without prejudice. The court dismissed with prejudice the plaintiffs' claims for breach of contract, violation of the Internal Revenue Code, and appointment of a seventh TVARS Board member.

Case Arising out of Hurricane Katrina. In April 2006, TVA was added as a defendant to a class action lawsuit brought in the United States District Court for the Southern District of Mississippi by 14 Mississippi residents allegedly injured by Hurricane Katrina. The plaintiffs sued seven large oil companies and an oil company trade association, three large chemical companies and a chemical trade association, and 31 large companies involved in the mining and/or burning of coal, alleging that the defendants' GHG emissions contributed to global warming and were a proximate and direct cause of Hurricane Katrina's increased destructive force. Action by the United States Supreme Court in January 2011 ended this case in a manner favorable to TVA.

Case Involving the NRC Waste Confidence Decision on Spent Nuclear Fuel Storage. In June 2012, the U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") vacated the NRC's updated ~~Waste Confidence Decision ("WCD")~~.WCD. The WCD is a generic determination by the NRC that spent nuclear fuel can be safely managed until a permanent off-site repository is established and has been a key component of the NRC licensing activities since 1984. The most recent update provided that the permanent repository would be available when necessary and that spent fuel could be stored for 60 years after a plant's license terminated. The D.C. Circuit vacated this update on the grounds that, among other things, the NRC failed to support it with an adequate National Environmental Policy Act review and the NRC did not evaluate what would happen if the repository was never built.

~~Case~~Administrative Proceeding Regarding ~~Bellefonte~~Renewal of Operating License for Sequoyah Nuclear ~~Plant Units 1 and 2.~~Plant. In ~~March 2009, in response to a request by TVA,~~May 2013, the ~~NRC reinstated the construction permits for Bellefonte Units 1 and 2.~~ Blue Ridge Environmental Defense League ("BREDL") ~~subsequently~~, the Bellefonte Efficiency and Sustainability Team ("BEST"), and Mothers Against Tennessee River Radiation filed ~~petitions in~~a petition with the ~~D.C. Circuit~~NRC opposing the renewal of the operating license for Sequoyah Nuclear Plant Units 1 and 2. The petition contains eight specific contentions challenging the ~~NRC's authority~~adequacy of the license renewal application that TVA submitted to ~~reinstate~~ the ~~construction permits.~~NRC in January 2013. TVA ~~asked to participate~~filed a response with the Atomic Safety and ~~was granted intervenor status in~~Licensing Board ("ASLB") opposing the ~~cases.~~admission of all eight of the petitioners' contentions. In July ~~2010,~~2013, the ~~D.C. Circuit consolidated~~ASLB concluded that BREDL is the only one of the ~~two~~three ~~BREDL petitions~~petitioners that has standing to intervene in this proceeding. The ASLB also held that seven of the contentions were inadmissible, and ~~stayed~~held one portion of the ~~combined proceeding pending the conclusion of an administrative proceeding which raised several contentions regarding the reinstatement, including some~~remaining contention related to WCD in abeyance pending further direction from the NRC's legal authority to reinstate the permits. The administrative proceeding was completed in September 2010, with the dismissal of all of BREDL's contentions. The D.C. Circuit returned the cases to the court's active docket and decided in February 2012 that BREDL's petitions failed to properly challenge the NRC's final orders reinstating the construction permits, and dismissed the petitions for lack of jurisdiction.NRC.

Administrative Proceedings Regarding Bellefonte Units 3 and 4. TVA submitted its combined construction and operating license application ("CCOLA") for two Advanced Passive 1000 reactors at Bellefonte Units 3 and 4 to the NRC in October 2007. In June 2008, Bellefonte Efficiency and Sustainability Team ("BEST"), BREDL, and Southern Alliance for Clean Energy ("SACE") submitted a joint petition for intervention and a request for a hearing. The Atomic Safety and Licensing Board ("ASLB") denied standing to BEST and admitted four of the 20 contentions submitted by BREDL and SACE. The NRC reversed the ASLB's decision to admit two of the four contentions, leaving only two contentions (concerning the estimated costs of the new nuclear plant and the impact of the facility's operations on aquatic ecology) to be litigated in a future hearing. In January 2012, TVA notified the ASLB that the NRC had placed the CCOLA in “suspended” status indefinitely at TVA's request, and TVA requested that the ASLB hold the proceeding in abeyance pending a decision by TVA regarding the best path forward with regards to the CCOLA.

Administrative Proceedings Regarding Watts Bar ~~Nuclear Plant~~ Unit 2. In July 2009, SACE, the Tennessee Environmental Council, the Sierra Club, We the People, and BREDL filed a request for a hearing and petition to intervene in the NRC administrative process reviewing TVA's application for an operating license for Watts Bar Unit 2. In November 2009, the ASLB granted SACE's

~~Shawnee~~National Environmental Policy Act Challenge at Gallatin Fossil Plant. To comply with the Environmental Agreements and the Mercury and Air Toxics Standards, TVA chose to reduce emissions at the Gallatin Fossil Plant ~~("Shawnee")~~ ~~Clean Air Act Permit. In December 2010, the Environmental Integrity Project~~by installing controls and ~~SACE filed a petition with the EPA requesting that the EPA Administrator object~~an associated landfill. Pursuant to the ~~proposed CAA renewal permit issued~~National Environmental Policy Act ("NEPA"), TVA completed an Environmental Assessment in March 2013 to ~~TVA~~assess the impact of installing these emission controls. In April 2013, the Tennessee Environmental Council, Tennessee Scenic Rivers Association, Sierra Club, and Center for ~~operations at Shawnee. Among other things, the petitioners allege that repair, maintenance, or replacement undertaken at Shawnee Units 1 and 4~~Biological Diversity filed suit in the ~~1989-90 period triggered~~United States District Court for the ~~PSD requirements~~Middle District of Tennessee alleging that TVA violated NEPA when it decided to install additional emission controls and construct an associated landfill at the Gallatin Fossil Plant. Plaintiffs demand that TVA prepare an Environmental Impact Statement, and are asking the court to enjoin TVA from taking any further action relating to these matters pending compliance with NEPA. This case has been transferred to the United States District Court for SO₂ ~~and NO~~_x~~. The current permit remains in effect pending KDAQ’s finalization~~the Eastern District of ~~the renewal permit. The EPA dismissed this petition in August 2012.~~Tennessee.

Kingston Fossil Plant NPDES Permit Administrative Appeal. The Sierra Club filed a challenge to the National Pollutant Discharge Elimination System ("NPDES") permit issued by Tennessee for the scrubber-gypsum pond discharge at Kingston in November 2009 before the Tennessee Board of Water Quality, ~~Control Board~~Oil, and Gas ("~~TWQCB"~~TN Board"). In addition to its allegation that Tennessee violated the Clean Water Act by failing to set specific limits on certain toxic discharges, the Sierra Club alleges that no discharges from the pond infrastructure should be allowed because zero-discharge scrubbers exist. TDEC is the defendant in the challenge, and TVA has intervened in support of TDEC's decision to issue the permit. The matter was set for a hearing before the ~~TWQCB~~TN Board in February 2011, but has since been stayed by agreement of the parties.

Bull Run Fossil Plant NPDES Permit Administrative Appeal. SACE and the Tennessee Clean Water Network ("TCWN") filed a challenge to the NPDES permit for the Bull Run Fossil Plant ~~("Bull Run")~~ in November 2010. TDEC is the defendant in the challenge, and TVA's motion to intervene to support TDEC's decision to issue the permit was granted in January 2011. ~~Petitioners'~~At the contested case hearing in October 2013, the TN Board granted TDEC's and TVA's joint motion for ~~summary judgment was denied, and~~involuntary dismissal following the ~~parties expect~~conclusion of the ~~case to be presented to TWQCB in February 2013.~~petitioners' presentation of evidence.

Johnsonville Fossil Plant NPDES Permit Administrative Appeal. SACE and TCWN filed a challenge to the NPDES permit for the Johnsonville Fossil Plant in March 2011. TDEC is the defendant in the challenge. TVA's motion to intervene was granted in August 2011. The matter has not yet been given a hearing date before the ~~TWQCB.~~TN Board.

John Sevier Fossil Plant NPDES Permit Administrative Appeal. SACE and TCWN filed a challenge to the NPDES permit for John Sevier in May 2011. TDEC is the defendant in the challenge. TVA's motion to intervene was granted in August 2011. The matter has not yet been given a hearing date before the ~~TWQCB.~~TN Board.

Gallatin Fossil Plant NPDES Permit Administrative Appeal. SACE, TCWN, and the Sierra Club filed a challenge to the NPDES permit for the Gallatin Fossil Plant ~~("Gallatin")~~ in June 2012. TDEC is the defendant in the challenge. TVA's motion to intervene was granted in September 2012. Administrative discovery is underway. The matter has been set for a hearing before the TN Board in September 2014.

~~Information Request~~Case Involving Colbert Fossil Plant. On April 1, 2013, the Alabama Department of Environmental Management ("ADEM") filed suit in the Circuit Court of Colbert County, Alabama, alleging that unauthorized discharges from TVA's Colbert Fossil Plant were violating the ~~EPA~~Alabama Water Pollution Control Act. On May 13, 2013, TVA and ADEM entered into a consent decree which resolves this lawsuit. The decree requires, among other things, that TVA continue remediation efforts TVA had begun prior to the suit being filed and stop using an unlined landfill after a lined landfill is approved and constructed. TVA also agreed to pay $~~. In April 2008, TVA received a request from the EPA under Section 114 of the CAA requesting extensive information about maintenance, repair, and replacement projects at and the operations of~~ 14 ~~coal-fired units. The Environmental Agreements have resolved most issues related to this information request, excluding claims related to sulfuric acid mist. See~~ ~~Environmental Agreements~~150 thousand.

Petitions Resulting from Japanese Nuclear Events. As a result of events that occurred at the Fukushima ~~events,~~Daiichi Nuclear Power Plant in March 2011, petitions have been filed with the NRC which could impact TVA's nuclear program. While some petitions have been dismissed after review, petitions that remain open include the following:

Federal Salary Freeze. In December 2010, Congress passed the Continuing Appropriations and Surface Transportation Extensions Act of 2011, which included a two-year freeze on statutory pay adjustments for all executive branch pay schedules and a two-year freeze by executive agencies on base salary increases to all senior executives. These two-year freezes ~~apply~~applied to calendar years 2011 and 2012. The TVA Board members are covered by the first freeze and TVA's officers

Salary. The salaries of the Named Executive Officers for ~~2012~~2013 were as follows: $950,000 for Mr. Johnson, $850,000 for Mr. Kilgore, $520,000 for Mr. Thomas, ~~$650,000 for Ms. Greene,~~ $545,000 for Mr. Swafford, ~~and~~ $400,000 for Mr. ~~Rodgers.~~Rodgers, and $415,000 for Mr. Skaggs. As a result of the federal salary freeze, ~~described above,~~ the ~~2012~~2013 salaries for ~~Named Executive Officers~~Mr. Kilgore, Mr. Thomas, Mr. Swafford and Mr. Rodgers were the same as in ~~2011.~~2011 and 2012.

More information about the approval of Mr. ~~Kilgore's~~Johnson's compensation for ~~2012~~2013 is ~~provided~~ below. See Considerations Specific to Mr. ~~Kilgore~~Johnson.

Annual Incentive Compensation. All executives, including the Named Executive Officers, participate in the ~~EAIP.~~Executive Annual Incentive Plan ("EAIP"). The EAIP is designed to encourage and reward executives for ~~their contributions to~~ successfully achieving annual financial and operational goals. For ~~2012,~~2013, the EAIP focused on achieving ~~corporate level~~both enterprise-wide and strategic business unit goals. The specific award opportunities, metrics and associated goals are described below.

Considerations Specific to Mr. ~~Kilgore.~~Johnson. AtAs a part of the ~~beginning of 2012,~~TVA Board's employment negotiations with Mr. Johnson, the Committee, in consultation with ~~its independent executive compensation consultant,~~ Towers Watson, ~~evaluated Mr. Kilgore's overall performance and then-current~~developed a compensation relative to TVA's peer group to determine whether to recommend adjustments to Mr. Kilgore's compensation to the TVA Board for 2012. After a thorough review, including the consideration of chief executive officer median compensation data provided to the Committee by Towers Watson based on TVA's peer grouppackage commensurate with his experience and the ~~salary freeze in effect for senior executives in~~position, while taking into account the ~~executive agencies, the Committee recommended that the TVA Board approve the same~~Board-approved compensation ~~and incentive opportunities~~ for Mr. Kilgore ~~for 2012 as for 2011. At its November 17, 2011, meeting,~~ the previous year. The TVA Board, with recommendation of the Committee, approved on October 30, 2012, the following compensation ~~and incentive opportunities~~package for Mr. ~~Kilgore for 2012 recommended by the Committee:~~Johnson, effective January 1, 2013: annual salary of ~~$850,000,~~$950,000, a target EAIP incentive opportunity of 100 percent of salary (subject to proration based on the number of months employed during the fiscal year), a target ELTIP incentive opportunity of 150 percent of salary (eligible for full award beginning in 2011-2013 performance cycle), a $300,000 credit under an LTDCP agreement, and ~~a credit~~an award of up to $325,000 under ~~an incentive-based long-term deferred compensation~~a performance incentive arrangement ~~(which is described~~(described in Other Agreements below). The credit provided under the LTDCP in 2013 is reported in both the "Non-Equity Incentive Plan Compensation" column of the Summary Compensation Table and the "Registrant Contributions in Last FY" column of the Nonqualified Deferred Compensation Table.

Pension Benefits. All ~~of the~~ Named Executive Officers are eligible to participate in the following qualified plans available to ~~and on the same terms and conditions applicable to,~~ all annual TVA employees:

Perquisites. Vehicle allowances are granted on a “business need” basis to a limited number of executives. In ~~2012,~~2013, TVA provided certain executives, including Mr. Thomas, ~~Ms. Greene,~~ Mr. Swafford, ~~and~~Mr. Rodgers and Mr. Skaggs, a flat-dollar biweekly vehicle allowance that may be applied toward the purchase or lease of a vehicle, operating fees, excess mileage, maintenance, repairs and insurance. TVA eliminated its vehicle allowance program, effective September 22, 2013. Vehicle ~~allowances are granted on a “business need” basis to a limited number of executives. The amount of the vehicle allowances granted to~~allowance amounts for the Named Executive Officers isare reported in the “All Other Compensation” column in the Summary Compensation Table.

Health and Other Benefits. TVA offers a group of health and other benefits (medical, dental, vision, life and accidental death and disability insurance, and long-term disability insurance) that are available to a broad group of employees. The Named Executive Officers are eligible to participate in TVA's health benefit plans and other non-retirement benefit plans on the same terms and at the same contribution rates as other TVA employees.

Other Agreements. As discussed in “Considerations Specific to Mr. ~~Kilgore” above,~~Johnson,” at the time of Mr. Johnson's appointment as CEO, the TVA Board approved ~~for Mr. Kilgore for 2012 the continuation of~~ an ~~additional incentive-based long-term deferred compensation~~ arrangement under which ~~credits~~he would be eligible to receive an additional performance incentive award ("PIA") of up to $325,000 per year based on the evaluation of his performance, which may be ~~awarded~~subjective and/or based ~~upon Mr. Kilgore's~~on the achievement of ~~specific~~defined short- and/or long-term goals. ~~When this~~Under the arrangement, ~~was first approved in 2011,~~ the TVA Board delegated to its

The TVA Long-Term Deferred Compensation Plan ~~is designed to provide long-term~~offers incentives to executives to encourage them to stay with TVA and to provide competitive levels of total direct compensation to such executives.Participating executives enter ~~into deferral~~ agreements ~~with TVA under~~in which deferred compensation credits are made to an account in the participant's name.Credits are made on an annual basis for an established period of time.Interest is credited daily to the balance reflected in the participant's deferral account.Interest is calculated based on the composite rate of all marketable U.S. Treasury issues. ~~In the alternative,~~Alternatively, participants may choose to have their balance adjusted based on the return on certain mutual funds.Credits vest after a period fixed in the agreement and ~~are distributed to~~distribution is based on the ~~participant either~~election made at ~~vesting or following termination as provided in~~ the ~~particular agreement. Set forth below are descriptions~~time the agreement is entered. A summary of the LTDCP agreements, ~~that~~some of which are reflected in the Summary Compensation Table for the Named Executive ~~Officers.~~ Officers, is listed below. The date and amount of each credit, as well as the vesting of each award, is outlined in the table.See also the Nonqualified Deferred Compensation Table below, which also includes information with respect to amounts credited under these and prior LTDCP agreements.

The ~~following~~ table below provides the actuarial present value of the Named Executive Officers' accumulated benefits, including the number of years of credited service, under TVA's retirement and pension plans as of September 30, ~~2012~~2013, determined using a methodology and interest rate and mortality rate assumptions ~~that are~~ consistent with those used in the

Qualified Defined Benefit Plan. TVA sponsors a qualified defined benefit plan which is administered by the Tennessee Valley Authority Retirement System ("TVARS"). The plan has two structures -- the OBS and the CBBS. Participation in the OBS is limited to employees who were covered under the plan prior to January 1, 1996. All employees first hired by TVA on or after January 1, 1996, participate in the CBBS. ~~As with any other qualified retirement plan, there are~~TVARS rules and IRS regulations set limits on employee and employer contributions and compensation that can be counted ~~for~~in benefit ~~calculations set by TVARS rules and IRS regulations.~~calculations.

OBS. Mr. Rodgers is the only Named Executive Officer who participates in the OBS. The pension provided under the OBS is based on a final average pay formula that includes the member's years of creditable service (to the nearest month), highest average compensation during any three consecutive years of creditable service, and a pension factor, less a small

CBBS. All ~~of the~~ other Named Executive Officers are members of the ~~CBBS. Under the~~ CBBS, under which each member has a cash balance account that receives pay credits equal to six percent of ~~his/her~~ compensation each pay period (every two weeks). For executives who are members of the CBBS, compensation is defined as annual salary only for benefit calculation purposes and is shown under the column titled “Salary” in the Summary Compensation ~~Table, although~~Table. The compensation in 2013 could not exceed ~~$245,000 in 2012~~$250,000 pursuant to the IRS annual compensation limit applicable to qualified plans. The account is credited with interest each month, and interest is compounded on an annual basis. The annual interest rate used for interest credits is determined each January 1. The interest rate is three percent greater than the percentage increase in the 12-month average of the Consumer Price Index for the period ended on the previous October 31. The minimum interest rate is six percent and the

Supplemental Executive Retirement Plan. The SERP is a non-qualified defined benefit pension plan similar to those typically found in other companies in TVA's peer group and is provided to a limited number of executives, including the Named Executive Officers. TVA's SERP was created to recruit and retain key executives. The plan is designed to provide a competitive level of retirement benefits in excess of the limitations on contributions and benefits imposed by TVA's qualified defined benefit plan and IRS code section 415 limits on qualified retirement plans.

SERP Tier 1. All of the Named Executive Officers are participants in Tier 1. The Tier 1 structure is designed to replace 60 percent of the amount of a participant's compensation at the time the participant reaches age 62 and has accrued 24 years of ~~service at TVA.~~TVA service.

The TVA Sponsored 401(k) Plan. Members of the TVA Retirement System, including the Named Executive Officers, may elect to participate in the TVA Retirement System's 401(k) plan on a before-tax, after-tax and/or Roth basis. For OBS members, TVA provides a matching contribution of ~~$.25~~$0.25 on every dollar contributed on a before-tax, after-tax and/or Roth basis, up to 1.5 percent of the participant's annual salary. For CBBS members, TVA provides a matching contribution of ~~$.75~~$0.75 on every dollar contributed on a before-tax, after-tax and/or Roth basis, up to 4.5 percent of the participant's annual salary.

TVA normally allows participants in the EAIP, ELTIP and LTDCP ~~to elect~~ to defer all or a portion of the compensation earned under those plans ~~that is~~and eligible for deferral under ~~the~~plan terms ~~of each plan~~ and ~~applicable~~ IRS regulations.All deferrals are credited to each participant in a deferred compensation account, and the deferral amounts are then funded into a rabbi trust.Each participant may elect one or more of several notional investment options made available by TVA or allow some or all funds to accrue interest at the rate established by the beginning of each fiscal year equal to the composite rate of all Treasury issues.Participants may elect to change from either one notional investment option or the TVA interest bearing option to another at any time.Upon termination, funds are distributed pursuant to elections made in accordance with applicable IRS regulations.

The TVA Act provides for up to nine directors on the TVA Board. Under the TVA Act, each ~~of TVA's directors~~director receives certain stipends that are increased annually by the same percentage increase applicable to adjustments under 5 U.S.C. § 5318, which ~~provides for adjustments in~~adjusts the annual rates of pay of employees on the Executive Schedule of the United States Government. As discussed under Compensation Discussion and Analysis— Executive Compensation Program Components — Federal Salary Freeze, pursuant to federal legislation, a ~~two-year~~three-year freeze on these statutory pay adjustments to TVA director stipends applied to calendar years 2011, ~~and~~ 2012 ~~which has been extended through March 27,~~and 2013. Accordingly, as of September 30, ~~2012~~,2013, the base stipend for TVA directors was and remains $48,900 per year unless (1) the director ~~is the chair of~~chairs a TVA Board committee, in which case the stipend was and remains $50,000 per ~~year,~~year; or (2) the director is the Chairman of the TVA Board, in which case the stipend was and remains $54,500 per year. Directors are also reimbursed under federal law for travel, lodging and related expenses ~~that they incur in~~while attending meetings and for other official TVA ~~business in the same manner as other persons employed intermittently in federal government service.~~business.

The directors are not eligible to participate in any incentive programs available to TVA employees. The directors do not participate in the TVA Retirement System and do not participate in TVA's SERP. However, as appointed officers of the United States government, the directors are members of the Federal Employees Retirement System ("FERS"). FERS is a tiered retirement plan that includes three components: (1) Social Security benefits, (2) the Basic Benefit Plan, and (3) the Thrift Savings Plan ("TSP"). As members of FERS, each director is required to make a mandatory small percentage contribution ~~of 0.8 percent~~ of his or her stipend to the Basic Benefit ~~Plan.~~Plan in the amount of 0.8 percent for those directors appointed prior to January 1, 2013, and 3.1 percent for those directors appointed on or after January 1, 2013.

All TVA employees, including directors and executive officers, are subject to the conflict of interest laws and regulations applicable to employees of the federal government. Accordingly, the general federal conflict of interest statute (18 U.S.C. § 208) and the Standards of Ethical Conduct for Employees of Executive Branch (5 C.F.R. part 2635) ("Standards of Ethical Conduct") form the basis of TVA’s policies and procedures for the review, approval, or ratification of related party transactions. The general federal conflict of interest statute, subject to certain exceptions, prohibits each government employee, including TVA’s directors and executive officers, from participating personally and substantially (by advice, decision, or otherwise) as a government employee in any contract, controversy, proceeding, request for determination, or other official particular matter in which, to his or her knowledge, he or she (or his or her spouse, minor child, general partner, organization with which he or she serves as officer, director, employee, trustee, or general partner, or any person or organization with which he or she is negotiating, or has an arrangement, for future employment) has a financial interest. Exceptions to the statutory prohibition relevant to TVA employees are (1) financial interests which have been deemed by the Office of Government Ethics, in published regulations, to be too remote or inconsequential to affect the integrity of the employee’s services, or (2) interests which are determined in writing, after full disclosure and on a case by case basis, to be not so substantial as to be deemed likely to affect the integrity of the employee’s services for TVA. In accordance with the statute, individual waiver determinations are made by the official responsible for the employee’s appointment. In the case of TVA directors, the determination may be made by the Chairman of the TVA Board, and in the case of the Chairman of the TVA Board, the determination may be made by the Counsel to the President of the United States.

The previously described restrictions are reflected in TVA’s Standard Programs and Processes 11.8.1, Business Ethics, which requires employees, including TVA’s directors and executive officers, to comply with the guidelines outlined in the Standards of Ethical Conduct and which restates the standard of the conflict of interest statute.

TVA also has access to a financing arrangement with the U.S. Treasury. TVA and the U.S. Treasury have a memorandum of understanding under which the U.S. Treasury provides TVA with a $150 million credit facility. ~~TVA did not borrow~~There were no outstanding borrowings under the facility ~~during 2012.~~at September 30, 2013. This credit facility matures on September 30, ~~2013~~2014 and is expected to be renewed. This



A corporate agency of the United States created by an act of Congress (State or other jurisdiction of incorporation or organization)			62-0474417 (IRS Employer Identification No.)

400 W. Summit Hill Drive Knoxville, Tennessee (Address of principal executive offices)			37902 (Zip Code)



Table of Contents
GLOSSARY OF COMMON ACRONYMS.......................................................................................................................................................................................................	4
FORWARD-LOOKING INFORMATION.........................................................................................................................................................................................................	6
GENERAL INFORMATION............................................................................................................................................................................................................................	7

PART I

ITEM 1. BUSINESS......................................................................................................................................................................................................................................	8
The Corporation.................................................................................................................................................................................................................................	8
Service Area.......................................................................................................................................................................................................................................	8
Customers..........................................................................................................................................................................................................................................	9
Rates..................................................................................................................................................................................................................................................	11
~~Current~~ Power ~~Supply~~......................................................................................................................................................................................................................... Supply......................................................................................................................................................................................................................................	12
~~Future Power Supply~~.......................................................................................................................................................................................................................... Cleaner Energy Initiatives..................................................................................................................................................................................................................	2019
Fuel Supply.........................................................................................................................................................................................................................................	2221
Transmission......................................................................................................................................................................................................................................	2423
Weather and Seasonality....................................................................................................................................................................................................................	2524
Competition........................................................................................................................................................................................................................................	2524
Research and Development...............................................................................................................................................................................................................	24
Flood Control Activities.......................................................................................................................................................................................................................	25
Environmental Stewardship Activities.................................................................................................................................................................................................	2625
Economic Development Activities......................................................................................................................................................................................................	26
Regulation..........................................................................................................................................................................................................................................	26
Taxation and Tax Equivalents.............................................................................................................................................................................................................	2827
Environmental Matters.......................................................................................................................................................................................................................	28
Employees..........................................................................................................................................................................................................................................	3732

ITEM 1A. RISK FACTORS............................................................................................................................................................................................................................	3732

ITEM 1B. UNRESOLVED STAFF COMMENTS............................................................................................................................................................................................	4742

ITEM 2. PROPERTIES..................................................................................................................................................................................................................................	4742
Generating Properties........................................................................................................................................................................................................................	4742
Transmission Properties.....................................................................................................................................................................................................................	4743
Natural Resource Stewardship Properties.........................................................................................................................................................................................	4743
Buildings.............................................................................................................................................................................................................................................	4843
Disposal of Property...........................................................................................................................................................................................................................	4843


ITEM 3. LEGAL PROCEEDINGS..................................................................................................................................................................................................................	4843

ITEM 4. MINE SAFETY DISCLOSURES......................................................................................................................................................................................................	4844

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES............	4945

ITEM 6. SELECTED FINANCIAL DATA........................................................................................................................................................................................................	5046

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS...................................................................	5147
Overview.............................................................................................................................................................................................................................................	5147
~~TVA's~~ Business and Vision.................................................................................................................................................................................................................Vision...........................................................................................................................................................................................................................	5147
Executive Overview............................................................................................................................................................................................................................	5449
Results of Operations.........................................................................................................................................................................................................................	5449
Liquidity and Capital Resources.........................................................................................................................................................................................................	5954
Off-Balance Sheet Arrangements.......................................................................................................................................................................................................	6562
Key Initiatives and Challenges...........................................................................................................................................................................................................	6662
Critical Accounting Policies and Estimates.........................................................................................................................................................................................	7167
Fair Value Measurements...................................................................................................................................................................................................................	7776
New Accounting Standards and Interpretations.................................................................................................................................................................................	7977
Legislative and Regulatory Matters....................................................................................................................................................................................................	7977
Environmental Matters.......................................................................................................................................................................................................................	7978
Legal Proceedings..............................................................................................................................................................................................................................	7978
Risk Management Activities...............................................................................................................................................................................................................	79
~~Subsequent Event~~s............................................................................................................................................................................................................................	8478

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK...........................................................................................................................	8482

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..........................................................................................................................................................	8583
Consolidated Statements of Operations.............................................................................................................................................................................................	8583
Consolidated ~~Balance Sheets~~Statements of ............................................................................................................................................................................................................Comprehensive Income (Loss).............................................................................................................................................................	8683



Consolidated Balance Sheets............................................................................................................................................................................................................	84
Consolidated Statements of Cash Flows...........................................................................................................................................................................................	8886
Consolidated Statements of Changes in Proprietary Capital.............................................................................................................................................................	8987
Notes to Consolidated Financial Statements.....................................................................................................................................................................................	9088
Report of Independent Registered Public Accounting Firm................................................................................................................................................................	~~146~~145

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE................................................................	~~147~~146

ITEM 9A. CONTROLS AND PROCEDURES...............................................................................................................................................................................................	~~147~~146
Disclosure Controls and Procedures..................................................................................................................................................................................................	~~147~~146
Internal Control over Financial Reporting...........................................................................................................................................................................................	~~147~~146
Report of Independent Registered Public Accounting Firm................................................................................................................................................................	~~148~~147

ITEM 9B. OTHER INFORMATION................................................................................................................................................................................................................	~~149~~148

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE.............................................................................................................................	~~150~~149
Directors..............................................................................................................................................................................................................................................	~~150~~149
Executive Officers...............................................................................................................................................................................................................................	151
Disclosure and Financial Code of Ethics.............................................................................................................................................................................................	~~153~~152
Committees of the TVA Board.............................................................................................................................................................................................................	~~153~~152

ITEM 11. EXECUTIVE COMPENSATION.....................................................................................................................................................................................................	153
Compensation Discussion and Analysis..............................................................................................................................................................................................	153
Executive Compensation Tables and Narrative Disclosures...............................................................................................................................................................	168
Retirement and Pension Plans............................................................................................................................................................................................................	~~171~~172
Potential Payments on Account of Retirement/Resignation, Termination without Cause, Termination with Cause, or Death/Disability.............................................	~~174~~175
Other Agreements...............................................................................................................................................................................................................................	~~177~~178
Director Compensation........................................................................................................................................................................................................................	~~177~~178
Compensation Committee Interlocks and Insider Participation...........................................................................................................................................................	~~179~~180
Compensation Committee Report.......................................................................................................................................................................................................	~~179~~180

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS......................................	~~179~~181

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.........................................................................................	~~179~~181
Director Independence........................................................................................................................................................................................................................	~~179~~181
Related Party Transactions.................................................................................................................................................................................................................	~~179~~181

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES......................................................................................................................................................................	~~181~~183

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.....................................................................................................................................................................	~~182~~184

SIGNATURES................................................................................................................................................................................................................................................	~~187~~190
EXHIBIT INDEX.............................................................................................................................................................................................................................................	~~189~~192


Operating Revenues By State For the years ended September 30 (in millions)	Operating Revenues By State For the years ended September 30 (in millions)						Operating Revenues By State For the years ended September 30 (in millions)
	2012		2011		2010		2013		2012		2011
Alabama	$	1,556	$	1,699	$	1,495	$	1,551	$	1,556	$	1,699
Georgia	234		272		253		260		234		272
Kentucky	1,230		1,159		1,195		1,019		1,230		1,159
Mississippi	1,038		1,095		974		1,029		1,038		1,095
North Carolina	69		58		53		52		69		58
Tennessee	6,889		7,370		6,693		6,818		6,889		7,370
Virginia	49		60		48		53		49		60
Subtotal	11,065		11,713		10,711		10,782		11,065		11,713
Sale for resale and other	21		10		2		47		21		10
Subtotal	11,086		11,723		10,713		10,829		11,086		11,723
Other revenues	134		118		161		127		134		118
Operating revenues	$	11,220	$	11,841	$	10,874	$	10,956	$	11,220	$	11,841


Operating Revenues by Customer Type For the years ended September 30 (in millions)	Operating Revenues by Customer Type For the years ended September 30 (in millions)						Operating Revenues by Customer Type For the years ended September 30 (in millions)
	2012		2011		2010		2013		2012		2011
Sales of electricity
Municipalities and cooperatives	$	9,506	$	10,144	$	9,275
Local power companies							$	9,463	$	9,506	$	10,144
Industries directly served	1,442		1,440		1,321		1,199		1,442		1,440
Federal agencies and other	138		139		117		167		138		139
Total sales of electricity	11,086		11,723		10,713		10,829		11,086		11,723
Other revenues	134		118		161		127		134		118
Operating revenues	$	11,220	$	11,841	$	10,874	$	10,956	$	11,220	$	11,841



GLOSSARY OF COMMON ACRONYMS
Following are definitions of terms or acronyms frequently used in this Annual Report on Form 10-K for the fiscal year ended September 30, ~~2012~~2013 (the “Annual Report”):

Term or Acronym		Definition
AFUDC		Allowance for funds used during construction
ARO		Asset retirement obligation
ART		Asset Retirement Trust
ASLB		Atomic Safety and Licensing Board
BEST		Bellefonte Efficiency and Sustainability Team
BREDL		Blue Ridge Environmental Defense League
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CCOLA		Combined construction and operating license application
CCP		Coal combustion products
CCR		Coal combustion residual
CCW		Coal combustion waste
CERCLA		Comprehensive Environmental Response, Compensation, and Liability Act
CME		Chicago Mercantile Exchange
CO₂		Carbon dioxide
CO₂e		Carbon dioxide equivalent
COLA		Cost of living adjustment
CSAPR		Cross State Air Pollution Rule
CTs		Combustion turbine unit(s)
CVA		Credit valuation adjustment
CY		Calendar year
EPA		Environmental Protection Agency
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FPA		Federal Power Act
FTP		Financial Trading Program
GAAP		Accounting principles generally accepted in the United States of America
GAO		U.S. Government Accountability Office
GHG		Greenhouse gas
GWh		Gigawatt hour(s)
IRP		Integrated Resource Plan
IRUs		Indefeasible rights of use
JSCCG		John Sevier ~~Combined-Cycle~~Combined Cycle Generation LLC
kWh		Kilowatt hour(s)
LIBOR		London Interbank ~~Offer~~Offered Rate
LPC		Local Power Company Customer of TVA
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
mmBtu		Million British thermal unit(s)
MtM		Mark-to-market
MW		Megawatt
NAAQS		National Ambient Air Quality Standards
NAV		Net asset values
NDT		Nuclear Decommissioning Trust
NEIL		Nuclear Electric Insurance Limited
NEPA		National Environmental Policy Act



NERC		North American Electric Reliability Corporation
NO_x		Nitrogen oxides
NPDES		National Pollutant Discharge Elimination System



NRC		Nuclear Regulatory Commission
NRP		Natural Resource Plan
NSPS		New Source Performance Standards
NSR		New Source Review
OCI		Other comprehensive income (loss)
~~PAL~~PARRS		~~Plant wide applicability limitation(s)~~Putable Automatic Rate Reset Securities
PM		Particulate matter
PSD		Prevention of Significant Deterioration
QTE		Qualified technological equipment and software
SACE		Southern Alliance for Clean Energy
SCCG		Southaven Combined Cycle Generation, LLC
SCRs		Selective catalytic reduction systems
SEC		Securities and Exchange Commission
SERP		Supplemental Executive Retirement Plan
Seven States		Seven States Power Corporation
SMR		Small modular reactor(s)
SO₂		Sulfur dioxide
SSSL		Seven States Southaven, LLC
TCWN		Tennessee Clean Water Network
TDEC		Tennessee Department of Environment & Conservation
TOU		Time-of-use
TVARS		Tennessee Valley Authority Retirement System
TWQCB		Tennessee Water Quality Control Board
USEC		United States Enrichment Corporation
VIE		Variable interest entity
XBRL		eXtensible Business Reporting Language
WCD		Waste Confidence Decision


TVA Distributor Customer Contracts At September 30, 2012
TVA Local Power Company Customer Contracts At September 30, 2013						TVA Local Power Company Customer Contracts At September 30, 2013
Contract Arrangements⁽¹⁾	Number of Distributor Customers	Sales to Distributor Customers in 2012		Percentage of Total Operating Revenues in 2012		Number of LPCs	Sales to LPCs in 2013		Percentage of Total Operating Revenues in 2013
		(in millions)					(in millions)
15-year termination notice	5	$	105	0.9	%	6	$	155	1.4	%
10-year termination notice	47	3,152		28.1	%	47	3,103		28.3	%
5-year termination notice	103	6,249		55.7	%	102	6,205		56.6	%
Total	155	$	9,506	84.7	%	155	$	9,463	86.3	%


Power Supply from TVA-Operated Generation Facilities For the years ended September 30 (millions of kWh)	Power Supply from TVA-Operated Generation Facilities For the years ended September 30 (millions of kWh)												Power Supply from TVA-Operated Generation Facilities For the years ended September 30 (millions of kWh)
	2012				2011				2010				2013				2012				2011
Coal-fired	58,584		41	%	74,583		52	%	74,590		51	%	62,519		43	%	58,584		41	%	74,583		52	%
Nuclear	55,244		38	%	49,562		34	%	53,339		36	%	52,100		36	%	55,244		38	%	49,562		34	%
Hydroelectric	12,817		9	%	12,706		9	%	14,013		9	%	18,178		12	%	12,817		9	%	12,706		9	%
Natural gas and/or oil-fired	16,650		12	%	6,809		5	%	5,475		4	%	13,102		9	%	16,650		12	%	6,809		5	%
Renewable resources (non-hydro)	25	⁽¹⁾	<1%		17	⁽¹⁾	<1%		4	⁽¹⁾	<1%		9	⁽¹⁾	<1%		25	⁽¹⁾	<1%		17	⁽¹⁾	<1%
Total	143,320		100	%	143,677		100	%	147,421		100	%	145,908		100	%	143,320		100	%	143,677		100	%


SUMMER NET CAPABILITY⁽¹⁾ At September 30, 2012
SUMMER NET CAPABILITY⁽¹⁾ At September 30, 2013						SUMMER NET CAPABILITY⁽¹⁾ At September 30, 2013
Source of Capability	Location	Number of Units	Summer Net Capability (MW)	Date First Unit Placed in Service	Date Last Unit Placed in Service	Location	Number of Units	Summer Net Capability (MW)	Date First Unit Placed in Service	Date Last Unit Placed in Service
TVA-Operated Generating Facilities
Coal-Fired(2)
Allen⁽²⁾⁽³⁾	Tennessee	3	741	1959	1959	Tennessee	3	741	1959	1959
Bull Run	Tennessee	1	863	1967	1967	Tennessee	1	863	1967	1967
Colbert	Alabama	5	1,184	1955	1965
Colbert^(3),(4)						Alabama	5	1,184	1955	1965
Cumberland	Tennessee	2	2,470	1973	1973	Tennessee	2	2,470	1973	1973
Gallatin	Tennessee	4	976	1956	1959	Tennessee	4	976	1956	1959
John Sevier⁽³⁾	Tennessee	4	704	1955	1957
Johnsonville⁽³⁾	Tennessee	8	924	1951	1959
Johnsonville⁽⁵⁾						Tennessee	8	924	1951	1959
Kingston	Tennessee	9	1,398	1954	1955	Tennessee	9	1,398	1954	1955
Paradise	Kentucky	3	2,201	1963	1970	Kentucky	3	2,201	1963	1970
Shawnee⁽³⁾	Kentucky	9	1,206	1953	1955
Widows Creek⁽³⁾	Alabama	2	938	1954	1965
Shawnee⁽⁵⁾						Kentucky	9	1,206	1953	1955
Widows Creek^(5),(6)						Alabama	2	938	1954	1965
Total Coal-Fired		50	13,605				46	12,901
Nuclear
Browns Ferry	Alabama	3	3,309	1974	1977	Alabama	3	3,309	1974	1977
Sequoyah	Tennessee	2	2,278	1981	1982	Tennessee	2	2,292	1981	1982
Watts Bar	Tennessee	1	1,123	1996	1996	Tennessee	1	1,123	1996	1996
Total Nuclear		6	6,710				6	6,724
Hydroelectric
Conventional Plants	Alabama	36	1,190	1925	1962	Alabama	36	1,176	1925	1962
	Georgia	2	35	1931	1956	Georgia	2	35	1931	1956
	Kentucky	5	223	1944	1948	Kentucky	5	223	1944	1948
	North Carolina	6	492	1940	1956	North Carolina	6	492	1940	1956
	Tennessee	60	1,891	1912	1972	Tennessee	60	1,891	1912	1972
Pumped-Storage⁽⁴⁾	Tennessee	4	1,616	1978	1979
Pumped-Storage⁽⁷⁾						Tennessee	4	1,616	1978	1979
Total Hydroelectric		113	5,447				113	5,433
Natural Gas and/or Oil-Fired^(5),(6)
Natural Gas and/or Oil-Fired^(8),(9)
Simple-Cycle Combustion Turbine
Allen⁽⁷⁾	Tennessee	20	456	1971	1972
Allen⁽¹⁰⁾						Tennessee	20	456	1971	1972
Brownsville	Tennessee	4	468	1999	1999	Tennessee	4	468	1999	1999
Colbert	Alabama	8	392	1972	1972	Alabama	8	392	1972	1972
Gallatin⁽⁸⁾	Tennessee	8	600	1975	2000
Gleason⁽⁹⁾	Tennessee	3	465	2000	2000
Gallatin						Tennessee	8	600	1975	2000
Gleason⁽¹¹⁾						Tennessee	3	465	2000	2000
Johnsonville	Tennessee	20	1,133	1975	2000	Tennessee	20	1,133	1975	2000
Kemper	Mississippi	4	312	2002	2002	Mississippi	4	312	2002	2002
Lagoon Creek	Tennessee	12	941	2001	2002	Tennessee	12	941	2001	2002
Marshall County	Kentucky	8	621	2002	2002	Kentucky	8	621	2002	2002
Subtotal Simple-Cycle Combustion Turbine		87	5,388				87	5,388
Combined-Cycle Combustion Turbine
Caledonia	Mississippi	3	765	2003	2003
John Sevier⁽¹⁰⁾	Tennessee	1	870	2012	2012
Lagoon Creek⁽¹¹⁾	Tennessee	1	525	2010	2010
Caledonia⁽¹²⁾						Mississippi	3	765	2003	2003
John Sevier⁽¹³⁾						Tennessee	1	870	2012	2012
Lagoon Creek⁽¹⁴⁾						Tennessee	1	525	2010	2010
Magnolia	Mississippi	3	920	2003	2003	Mississippi	3	920	2003	2003
Southaven	Mississippi	3	774	2003	2003	Mississippi	3	774	2003	2003
Subtotal Combined-Cycle Combustion Turbine		11	3,854				11	3,854
Total Natural Gas and/or Oil-Fired		98	9,242				98	9,242


Diesel Generator
Diesel Generator⁽¹⁵⁾
Meridian	Mississippi	5	9	1998	1998	Mississippi	5	9	1998	1998
Albertville	Alabama	4	4	2000	2000
Total Diesel Generators		9	13				5	9
TVA Renewable Resources (non-hydro)⁽¹²⁾			< 1
TVA Renewable Resources (non-hydro)⁽¹⁶⁾								< 1
Total TVA-Operated Generating Facilities			35,017					34,309
Contract Renewable Resources⁽¹³⁾			36
Contract Renewable Resources⁽¹⁷⁾								43
Power Purchase and Other Agreements			2,272					2,242
Total Summer Net Capability			37,325					36,594



Fossil Plant	Total Units	Existing Scrubbers and SCRs⁽¹⁾	Requirements Under Environmental Agreements	Retirements Implemented or Planned to be Implemented by TVA as a Result of Environmental Agreements
John Sevier	2	None	· Retire two units no later than December 31, 2012	· ~~Retire~~Retired Units 1 and 2 byon December 31, 2012
Johnsonville	10	None	· Retire six units no later than December 31, 2015 · Retire four units no later than December 31, 2017	· Retire six units by December 31, 2015 · Retire four units by December 31, 2017 · Idled Units 7 and 8 effective March 1, 2012 · ~~Plans to idle~~Idled Units ~~5-6~~5 and 6 and Units ~~9-10 by September 30,~~9 and 10 on October 1, 2013
Widows Creek	6	Scrubbers and SCRs on Units 7 and 8	· Retire two of Units 1-6 no later than July 31, 2013 · Retire two of Units 1-6 no later than July 31, 2014 · Retire two of Units 1-6 no later than July 31, 2015	· Idled Units 1-6 in October 2011 · Retired Units 3 and 5 on July 31, 2013



Fossil Plant	~~Total~~ Units Impacted	Existing Scrubbers and SCRs	Requirements Under Environmental Agreements	Other ~~Required~~ Actions Taken or Planned to be Taken by TVA ~~as a Result of Environmental Agreements~~
Allen	3	SCRs on all three units	Install scrubbers or retire no later than December 31, 2018	~~Had planned~~Still evaluating what actions to ~~add scrubbers on all three units but was re-evaluating its options as of September 30, 2012~~take
Bull Run	1	Scrubber and SCRs on unit	Continuously operate current and any new emission control equipment	Continuously operate existing emission control equipment
Colbert	5	SCR on Unit 5	· Remove from service, control⁽¹⁾, convert⁽²⁾, or retire Units 1-4 no later than June 30, 2016 · Remove from service, control⁽¹⁾, or retire Unit 5 no later than December 31, 2015 · Control or retire removed from service units within three years	· ~~Still evaluating what actions to take with respect to all Colbert units~~Idled Unit 5 in October 2013 · Retire Units 1-5 no later than June 30, 2016
Cumberland	2	Scrubbers and SCRs on both units	Continuously operate ~~current and any new~~existing emission control equipment	Continuously operate existing emission control equipment
Gallatin	4	None	Control⁽¹⁾, convert⁽²⁾, or retire all four units no later than December 31, 2017	Add scrubbers and SCRs on all four units by December 31, 2017
John Sevier	2	None	· Remove from service two units no later than December 31, 2012 and control⁽¹⁾, convert⁽²⁾, or retire those units no later than December 31, 2015	· ~~Remove from service~~Idled Units 3 and 4 byin December ~~31,~~ 2012 · ~~Still evaluating what additional actions to take with respect to~~ Units 3 and 4 will be retired by December 31, 2015
Kingston	9	Scrubbers and SCRs on all nine units	Continuously operate ~~current and any new~~existing emission control equipment	Continuously operate existing emission control equipment
Paradise	3	Scrubbers and SCRs on all three units	· Upgrade scrubbers on Units 1 and 2 no later than December 31, ~~2012~~2013 · Continuously operate emission control equipment on Units 1-3	~~Upgrade~~ · Upgraded scrubbers on Units 1 and 2 ~~by December 31,~~in 2012 · Continuously operate emission control equipment on Units 1-3 · The Board approved the construction of a gas-fired plant at the current location of the Paradise coal-fired plant · Retire Units 1 and 2 after completion of the gas-fired plant
Shawnee	2	None	Control⁽¹⁾, retire, or convert⁽²⁾ Units 1 and 4 no later than December 31, 2017	· Still evaluating what actions to take with respect to Units 1 and 4 · Idled Shawnee Unit 10 in October 2010
Widows Creek	2	Scrubbers and SCRs on Units 7 and 8	· Continuously operate ~~current and any new~~existing emissions control equipment on Units 7 and 8	· Continuously operate ~~current or equivalent~~existing emissions control equipment on Units 7 and 8 · Retire Unit 8 in the future


TVA Nuclear Power At September 30, 2012
TVA Nuclear Power At September 30, 2013						TVA Nuclear Power At September 30, 2013
Nuclear Unit	Status	Nameplate Capacity (MW)	Net Capacity Factor for 2012	Date of Expiration of Operating License	Date of Expiration of Construction Permits	Status	Nameplate Capacity (MW)	Net Capacity Factor for 2013	Date of Expiration of Operating License	Date of Expiration of Construction Permits
Sequoyah Unit 1	Operating	1,221	86.4	2020	—	Operating	1,221	97.0	2020*	—
Sequoyah Unit 2	Operating	1,221	97.0	2021	—	Operating	1,221	73.7	2021*	—
Browns Ferry Unit 1	Operating	1,150	97.0	2033	—	Operating	1,264	82.9	2033	—
Browns Ferry Unit 2	Operating	1,190	97.5	2034	—	Operating	1,190	80.6	2034	—
Browns Ferry Unit 3	Operating	1,190	80.0	2036	—	Operating	1,190	93.1	2036	—
Watts Bar Unit 1	Operating	1,230	88.6	2035	—	Operating	1,270	88.7	2035	—
Watts Bar Unit 2	Under construction	1,220	—	—	2013*	Under construction	1,220	—	—	2013*



	2012	Percent Change	2011	Percent Change	2010
Combined degree days (normal 5,244)	4,714	(14.9)%	5,541	(8.2)%	6,036



	2013	Percent Change	2012	Percent Change	2011
Combined degree days (normal 5,223)	5,095	8.1%	4,714	(14.9)%	5,541


Selected Financial Data⁽¹⁾⁽²⁾ For the years ended, or at, September 30 (dollars in millions)	Selected Financial Data⁽¹⁾⁽²⁾ For the years ended, or at, September 30 (dollars in millions)										Selected Financial Data⁽¹⁾⁽²⁾ For the years ended, or at, September 30 (dollars in millions)
	2012		2011		2010		2009		2008		2013		2012		2011		2010		2009
Sales (millions of kWh)	165,255		167,730		173,662		163,804		176,304		161,925		165,255		167,730		173,662		163,804

Peak load (MW)	31,098		31,434		31,778		32,572		32,027		28,726		31,098		31,434		31,778		32,572

Operating revenues	$	11,220	$	11,841	$	10,874	$	11,255	$	10,382	$	10,956	$	11,220	$	11,841	$	10,874	$	11,255

Fuel expense	$	2,680	$	2,926	$	2,092	$	3,114	$	2,756	$	2,820	$	2,680	$	2,926	$	2,092	$	3,114

Purchased power expense	$	1,189	$	1,427	$	1,127	$	1,631	$	1,420	$	1,027	$	1,189	$	1,427	$	1,127	$	1,631

Operating and maintenance expense	$	3,510	$	3,617	$	3,232	$	2,395	$	2,307	$	3,428	$	3,510	$	3,617	$	3,232	$	2,395

Net interest expense	$	1,273	$	1,305	$	1,294	$	1,272	$	1,376	$	1,226	$	1,273	$	1,305	$	1,294	$	1,272

Net income	$	60	$	162	$	972	$	726	$	817	$	271	$	60	$	162	$	972	$	726

Construction expenditures	$	2,119	$	2,417	$	2,015	$	1,793	$	1,984	$	2,051	$	2,119	$	2,417	$	2,015	$	1,793

Total assets	$	47,334	$	46,393	$	42,753	$	40,017	$	37,137	$	46,106	$	47,334	$	46,393	$	42,753	$	40,017

Financial obligations
Long-term debt, net⁽³⁾
Long-term power bonds, net	$	20,269	$	22,412	$	22,389	$	21,788	$	20,404	$	22,315	$	20,269	$	22,412	$	22,389	$	21,788
Long-term debt of variable interest entities	$	981	$	—	$	—	$	—	$	—	$	1,311	$	981	$	—	$	—	$	—
Total long-term debt, net	$	21,250	$	22,412	$	22,389	$	21,788	$	20,404	$	23,626	$	21,250	$	22,412	$	22,389	$	21,788

Current debt, net⁽³⁾
Short-term debt, net	$	1,507	$	482	$	27	$	844	$	185	$	2,432	$	1,507	$	482	$	27	$	844
Current maturities of power bonds	$	2,308	$	1,537	$	1,008	$	8	$	2,030	$	32	$	2,308	$	1,537	$	1,008	$	8
Current maturities of long-term debt of variable interest entities	$	13	$	—	$	—	$	—	$	—	$	30	$	13	$	—	$	—	$	—
Total short-term debt, net	$	3,828	$	2,019	$	1,035	$	852	$	2,215	$	2,494	$	3,828	$	2,019	$	1,035	$	852

Total debt⁽³⁾	$	25,078	$	24,431	$	23,424	$	22,640	$	22,619	$	26,120	$	25,078	$	24,431	$	23,424	$	22,640

Capital leases⁽⁴⁾	$	35	$	5	$	47	$	77	$	95	$	43	$	35	$	5	$	47	$	77

Membership interests of variable interest entity subject to mandatory redemption⁽⁴⁾											$	40	$	—	$	—	$	—	$	—



Corporate Measure	Results Achieved	Threshold	Target	Stretch
Corporate total spend ($ millions)	$766	$809	$792	$774
Total financing obligations over productive assets	75.3%	75.6%	75.2%	74.8%
Nuclear operating availability factor	96.8%	96.1%	97.2%	98.1%
Critical coal seasonal equivalent forced outage rate	5.3%	7.1%	4.6%	2.5%
Combined cycle seasonal equivalent forced outage rate	7.6%	3.6%	2.7%	1.6%
Clean energy percentage	49%	41%	43%	45%
Safe workplace (recordable injuries/hours worked)	.46	1.01	.86	.71


Renewable Wind Contracts At September 30, 2012
Renewable Wind Contracts As of September 30, 2013			Renewable Wind Contracts As of September 30, 2013
Location of Wind Farm	Wind Farm Nameplate Capacity (in MW)	Date Delivery Began or Is Expected to Begin	Wind Farm Nameplate Capacity (in MW)	Date Delivery Began
Illinois	300 *	2010	300*	2010
Iowa	115	2010
Iowa	83	2012	198	2010
Iowa	101	2012	101	2012
Kansas	201	2012	201	2012
Kansas	165	2013	165	2013
Illinois	200	2012	150	2012
Illinois	150	2012	200	2012
Illinois	200	2013	200	2013


Purchased Power* For the years ended September 30	Purchased Power* For the years ended September 30						Purchased Power* For the years ended September 30
	2012		2011		2010		2013		2012		2011
Millions of kWh	25,294		27,168		28,782		18,848		25,294		27,168
Percent of TVA’s Total Power Supply	15.0	%	15.9	%	16.3	%	11.4	%	15.0	%	15.9	%


Fuel for TVA-Operated Facilities* For the years ended September 30 (in millions)
Fuel Expense for TVA-Owned Facilities* For the years ended September 30 (in millions)							Fuel Expense for TVA-Owned Facilities* For the years ended September 30 (in millions)
	2012		2011		2010		2013		2012		2011
Coal	$	1,824	$	2,315	$	2,126	$	1,890	$	1,824	$	2,315
Natural gas	527		265		236		504		527		265
Fuel oil	46		54		38		36		46		54
Nuclear fuel	319		261		277		317		319		261
Total fuel	$	2,716	$	2,895	$	2,677	$	2,747	$	2,716	$	2,895


Fuel Expense Per kWh⁽¹⁾⁽²⁾ For the years ended September 30 (cents/kWh)	Fuel Expense Per kWh⁽¹⁾⁽²⁾ For the years ended September 30 (cents/kWh)			Fuel Expense Per kWh⁽¹⁾⁽²⁾ For the years ended September 30 (cents/kWh)
	2012	2011	2010	2013	2012	2011
Coal	3.18	3.17	2.90	3.07	3.18	3.17
Natural gas and fuel oil	3.19	3.96	4.37	3.89	3.19	3.96
Nuclear	0.58	0.53	0.52	0.61	0.58	0.53
Average fuel cost per kWh net thermal generation from all sources	2.08	2.21	2.01	2.15	2.08	2.21


Natural Gas Purchases for Tolling Plants⁽¹⁾ For the years ended September 30
Natural Gas Purchases for Non-TVA Owned Facilities⁽¹⁾ For the years ended September 30							Natural Gas Purchases for Non-TVA Owned Facilities⁽¹⁾ For the years ended September 30
	2012		2011		2010		2013		2012		2011
Cost of fuel (in millions)	$	255	$	343	$	381	$	138	$	255	$	343
Average fuel expense (cents/kWh)	3.79		5.40		5.93		2.95		2.36		2.42



Percentage of Coal Supply Delivery Methods For the years ended September 30
	2013		2012
Rail	6	%	7	%
Barge	21	%	20	%
Barge and rail combination	60	%	59	%
Truck	13	%	14	%


Air, Water, and Waste Quality Estimated Potential Environmental Expenditures At September 30, 2012 (in millions)
Air, Water, and Waste Quality Estimated Potential Environmental Expenditures⁽¹⁾ At September 30, 2013 (in millions)				Air, Water, and Waste Quality Estimated Potential Environmental Expenditures⁽¹⁾ At September 30, 2013 (in millions)
	Estimated Timetable	Total Estimated Expenditures		Estimated Timetable	Total Estimated Expenditures
Site environmental remediation costs⁽¹⁾⁽²⁾	2013+	$	11	2014+	$	15
Coal combustion residuals⁽²⁾	2013-2022	1,400
Coal combustion residual conversion and remediation⁽³⁾				2014-2023	1,400
Proposed clean air control projects⁽³⁾⁽⁴⁾	2013-2018	2,278		2014-2022	1,300
Clean Water Act requirements⁽⁴⁾⁽⁵⁾	2013-2020	1,224		2014-2022	700


3.	The rates TVA charges for power are set solely by the TVA Board of Directors (the "TVA Board") and are not set or reviewed by another entity, such as a public utility commission. In setting rates, however, the TVA Board is charged by the TVA Act to have due regard for the primary objectives of the TVA Act, including the objective that power be sold at rates as low as feasible.



Non-GAAP Reconciliation For the year ended September 30, 2012

Net cash flow provided by operating activities	$	2,574
Plus: Net cash flow used in investing activities	(2,513		)
Less: Net cash flow from change in fuel cost adjustment deferral	(61		)
Planned cash flow	$	(977	)
Net cash flow	$	1,099


Sales of Electricity For the years ended September 30 (millions of kWh)	Sales of Electricity For the years ended September 30 (millions of kWh)							Sales of Electricity For the years ended September 30 (millions of kWh)
	2012	Percent Change		2011	Percent Change		2010	2013	Percent Change		2012	Percent Change		2011
Municipalities and cooperatives	131,885	(3.8	)%	137,042	(3.1	)%	141,448
Local power companies								132,154	0.2	%	131,885	(3.8	)%	137,042
Industries directly served	30,446	6.6	%	28,563	(5.1	)%	30,099	26,016	(14.6	)%	30,446	6.6	%	28,563
Federal agencies and other	2,924	37.6	%	2,125	0.5	%	2,115	3,755	28.4	%	2,924	37.6	%	2,125
Total sales of electricity	165,255	(1.5	)%	167,730	(3.4	)%	173,662	161,925	(2.0	)%	165,255	(1.5	)%	167,730

																									Degree Days
	2012	Normal⁽¹⁾	Percent Variation		2011	Normal⁽¹⁾	Percent Variation		2012	2011	Percent Change		2013	Normal⁽¹⁾	Percent Variation		2012	Normal⁽¹⁾	Percent Variation		2013	2012	Percent Change

Heating Degree Days	2,598	3,381	(23.2	)%	3,418	3,381	1.1	%	2,598	3,418	(24.0	)%	3,333	3,360	(0.8	)%	2,598	3,381	(23.2	)%	3,333	2,598	28.3	%

Cooling Degree Days	2,116	1,863	13.6	%	2,123	1,863	14.0	%	2,116	2,123	(0.3	)%	1,762	1,863	(5.4	)%	2,116	1,863	13.6	%	1,762	2,116	(16.7	)%

Total Degree Days													5,095	5,223	(2.5	)%	4,714	5,244	(10.1	)%	5,095	4,714	8.1	%


Summary Consolidated Statements of Operations	Summary Consolidated Statements of Operations						Summary Consolidated Statements of Operations
	2012		2011		2010		2013		2012		2011
Operating revenues	$	11,220	$	11,841	$	10,874	$	10,956	$	11,220	$	11,841
Operating expenses	9,920		10,404		8,632		9,503		9,920		10,404
Operating income	1,300		1,437		2,242		1,453		1,300		1,437
Other income, net	33		30		24		44		33		30
Net interest expense	1,273		1,305		1,294		1,226		1,273		1,305
Net income (loss)	$	60	$	162	$	972
Net income							$	271	$	60	$	162


	Variance 2012 vs. 2011			Variance 2011 vs. 2010			Variance 2013 vs. 2012			Variance 2012 vs. 2011
Fuel cost recovery	$	(355	)	$	1,211		$	(55	)	$	(355	)
Base revenue	(294		)	(210		)	(230		)	(294		)
Other	28			(34		)	21			28
Total	$	(621	)	$	967		$	(264	)	$	(621	)


Operating Expenses For the years ended September 30	Operating Expenses For the years ended September 30										Operating Expenses For the years ended September 30
	2012		Percent Change		2011		Percent Change		2010		2013		Percent Change		2012		Percent Change		2011
Fuel	$	2,680	(8.4	)%	$	2,926	39.9	%	$	2,092	$	2,820	5.2	%	$	2,680	(8.4	)%	$	2,926
Purchased power	1,189		(16.7	)%	1,427		26.6	%	1,127		1,027		(13.6	)%	1,189		(16.7	)%	1,427
Operating and maintenance	3,510		(3.0	)%	3,617		11.9	%	3,232		3,428		(2.3	)%	3,510		(3.0	)%	3,617
Depreciation and amortization	1,919		8.3	%	1,772		2.8	%	1,724		1,680		(12.5	)%	1,919		8.3	%	1,772
Tax equivalents	622		(6.0	)%	662		44.9	%	457		548		(11.9	)%	622		(6.0	)%	662
Total operating expenses	$	9,920	(4.7	)%	$	10,404	20.5	%	$	8,632	$	9,503	(4.2	)%	$	9,920	(4.7	)%	$	10,404


Interest Expense For the years ended September 30	Interest Expense For the years ended September 30													Interest Expense For the years ended September 30
	2012			Percent Change		2011			Percent Change		2010			2013			Percent Change		2012			Percent Change		2011
Interest Expense⁽¹⁾
Interest expense⁽¹⁾
Interest expense	$	1,444		0.9	%	$	1,431		4.2	%	$	1,373		$	1,394		(3.5	)%	$	1,444		0.9	%	$	1,431
Allowance for funds used during construction and nuclear fuel expenditures	(171		)	35.7	%	(126		)	59.5	%	(79		)	(168		)	(1.8	)%	(171		)	35.7	%	(126		)
Net interest expense	$	1,273		(2.5	)%	$	1,305		0.9	%	$	1,294		$	1,226		(3.7	)%	$	1,273		(2.5	)%	$	1,305

	2012			Percent Change		2011			Percent Change		2010			2013			Percent Change		2012			Percent Change		2011
Interest Rates (average)
Interest rates (average)
Long-term outstanding power bonds⁽²⁾	5.860		%	1.1	%	5.799		%	(1.9	)%	5.909		%	5.725		%	(2.3	)%	5.860		%	1.1	%	5.799		%
Long-term debt of VIE	4.874		%	100.0	%	—			—		—			4.824		%	(1.0	)%	4.874		%	100.0	%	—
Membership interests of variable interest entity subject to mandatory redemption														6.887		%	100.0	%	—		%	—	%	—		%
Discount notes	0.079		%	(42.3	)%	0.137		%	53.9	%	0.089		%	0.078		%	(1.3	)%	0.079		%	(42.3	)%	0.137		%
Blended	5.589		%	(2.2	)%	5.712		%	0.5	%	5.683		%	5.273		%	(5.7	)%	5.589		%	(2.2	)%	5.712		%

																																					Short-Term Borrowing Table
	At September 30 2012			For the year ended September 30 2012			At September 30 2011			For the year ended September 30 2011			At September 30 2010			For the year ended September 30 2010			At September 30 2013			For the year ended September 30 2013			At September 30 2012			For the year ended September 30 2012			At September 30 2011			For the year ended September 30 2011
Amount Outstanding (at End of Period) or Average Amount Outstanding (During Period)
Discount notes	$	1,507		$	1,148		$	482		$	363		$	27		$	905		$	2,432		$	1,887		$	1,507		$	1,148		$	482		$	363
Weighted Average Interest Rate
Discount notes	0.085		%	0.079		%	0.001		%	0.137		%	0.040		%	0.089		%	0.042		%	0.078		%	0.085		%	0.079		%	0.001		%	0.137		%
Maximum Month-End Amount Outstanding (During Period)
Discount notes	N/A			$	2,550		N/A			$	1,401		N/A			$	1,176		N/A			$	3,261		N/A			$	2,550		N/A			$	1,401



Summary of Long-Term Credit Facilities At September 30, 2012 (in billions)
Maturity Date	Facility Limit		Letters of Credit Outstanding		Cash Borrowings		Availability
January 2014	$	0.5	$	0.5	$	—	$	—
January 2014	1.0		—		—		1.0
June 2017	1.0		0.6		—		0.4
	$	2.5	$	1.1	$	—	$	1.4


Summary Cash Flows For the years ended September 30	Summary Cash Flows For the years ended September 30									Summary Cash Flows For the years ended September 30
	2012			2011			2010			2013			2012			2011
Cash provided by (used in):
Operating activities	$	2,574		$	2,437		$	1,901		$	2,597		$	2,574		$	2,437
Investing activities	(2,513		)	(3,142		)	(2,458		)	(2,385		)	(2,513		)	(3,142		)
Financing activities	300			884			684			522			300			884
Net change in cash and cash equivalents	$	361		$	179		$	127		$	734		$	361		$	179


Future Planned Construction Expenditures⁽¹⁾ As of September 30	Future Planned Construction Expenditures⁽¹⁾ As of September 30										Future Planned Construction Expenditures⁽¹⁾ As of September 30
	Actual				Estimated Construction Expenditures						Actual				Estimated Construction Expenditures
	2012				2013		2014		2015		2013				2014		2015		2016
Watts Bar Unit 2	$	397			$	500	$	500	$	500	$	564			$	652	$	374	$	99
Other capacity expansion expenditures(2)	321				219		212		330		26				16		40		102
Environmental expenditures	38				392		750		739		196				448		280		197
Coal combustion residual	141				107		97		79		75				99		132		113
Transmission expenditures	256				324		420		428		172				339		405		458
Other capital expenditures⁽²⁾	727				589		767		786
Other capital expenditures^(3),(4)											873				798		831		823
Total construction expenditures	$	1,880	⁽³	⁾	$	2,131	$	2,746	$	2,862	$	1,906	⁽⁵	⁾	$	2,352	$	2,062	$	1,792


Commitments and Contingencies Payments due in the year ending September 30	Commitments and Contingencies Payments due in the year ending September 30														Commitments and Contingencies Payments due in the year ending September 30
	2013		2014		2015		2016		2017		Thereafter		Total		2014		2015		2016		2017		2018		Thereafter		Total
Debt⁽¹⁾	$	3,815	$	32	$	1,032	$	32	$	1,555	$	17,638	$	24,104	$	2,464	$	1,032	$	32	$	1,555	$	1,682	$	18,056	$	24,821
Interest payments relating to debt	1,240		1,154		1,153		1,108		1,094		18,201		23,950		1,200		1,207		1,162		1,148		1,059		18,121		23,897
Debt of VIEs	13		13		14		15		16		923		994		30		32		33		35		36		1,175		1,341
Interest payments relating to debt of VIEs	48		48		47		46		46		716		951		62		60		58		58		56		747		1,041
Lease obligations
Capital	2		2		2		2		2		25		35		5		5		5		5		5		36		61
Non-cancelable operating	62		39		26		25		25		124		301		37		30		29		28		27		87		238
Purchase obligations
Power	161		156		156		168		169		3,501		4,311		219		204		219		231		230		3,336		4,439
Fuel	1,441		1,105		1,063		672		366		2,466		7,113		1,419		1,176		794		442		498		2,002		6,331
Other	164		158		142		140		129		1,185		1,918		255		210		184		182		502		1,221		2,554
Environmental Agreements	87		87		87		—		—		—		261		73		80		63		41		14		—		271
Membership interests of variable interest entity subject to mandatory redemption															2		2		2		2		2		30		40
Interest payments related to membership interests of variable interest entity subject to mandatory redemption															3		3		3		2		2		16		29
Nuclear power															11		36		1		—		—		—		48
Litigation settlements	8		8		4		—		—		—		20		11		2		—		—		—		—		13
Environmental cleanup costs-Kingston ash spill	126		104		39		—		—		—		269		102		67		—		—		—		—		169
Payments on other financings	489		100		104		104		104		505		1,406		100		104		104		104		104		401		917
Payments to U.S. Treasury
Return of Power Program Appropriation Investment	20		10		—		—		—		—		30		10		—		—		—		—		—		10
Return on Power Program Appropriation Investment	20		19		18		18		18		198		291		5		8		8		8		8		93		130
Total	$	7,696	$	3,035	$	3,887	$	2,330	$	3,524	$	45,482	$	65,954	$	6,008	$	4,258	$	2,697	$	3,841	$	4,225	$	45,321	$	66,350