Clean Air Response / Power Supply Impacts – BACKUP SLIDES

1. Clean Air Response / Power Supply Impacts – BACKUP SLIDES Presented by Bill McCollum May 13, 2009

2. Other Clean Air Regulatory Changes • May 2008 Clean Air Plan was primarily driven by the Clean Air Interstate Rule (CAIR) and Clean Air Mercury Rule (CAMR). CAIR addresses SO2 and NOx emissions. Both were cap-and-trade rules. • The D.C. Circuit Court of Appeals vacated CAMR in February 2008. • TVA and the industry expect CAMR will be replaced by a mercury Maximum Achievable Control Technology (MACT) rule by 2014-15. • Rather than cap-and-trade, a mercury MACT rule would require mercury emissions reductions at each plant site. • The D.C. Circuit Court of Appeals issued a decision vacating CAIR in July 2008. The Court reversed its vacatur decision on Dec. 23 and remanded the rule to EPA. • CAIR will remain in place in full until EPA promulgates a replacement rule which could take several years. There is no timeline for a replacement rule. • A new rule is expected to restrict or eliminate interstate emissions trading. • Current CAIR SO2 and NOx requirements are expected to remain in effect at least through CY 2010. • Local ozone and fine particulate ambient air quality standards will continue to get more stringent.

3. JSF Controls Risk • Schedule risk • Scrubber vendor award by 5/1/09. Award delays will impact schedule at least day-for-day. • SCR approval to proceed by 6/4/09. Approval delays will impact schedule at least day-for-day. • Schedules are based on normal durations and do not reflect possible impacts from site congestion with concurrent scrubber and SCR construction. Possible 0-6 month impact. • Cost risk • Productivity impact from concurrent scrubber and SCR construction. Possible impact up to 20%. • The SCR cost estimate was not updated by URS last fall when the other SCR estimates were updated. Possible impact up to 80%. • Power system risk • Only two units will be available for a 19 month period due to construction. If a forced outage occurs on one of the remaining two units during this time and load is above 30,000 MW, curtailments may be required.

4. Combined Cycle Plant RiskFor a Plant to be Located on the JSF Site • Schedule risks • Biggest risk lies with the upfront activities that must be completed prior to starting construction • This is primarily for CC operation. • For simple cycle operation by 1/1/12 risks are very low. • NEPA process must be completed by April 2010 to meet June 2012 CC operation date • Air permitting must be completed by June 2010 to meet CC schedule of June 2012 • Simple cycle operation by Jan 1, 2012 impacted only if NEPA delayed more than 6 months • Upfront activities for natural gas supply is another pre-construction risk for CC operation • Gas supply environmental review must be included in the TVA EA to be completed by April 2010 (for June 2012 CC operation) • Risk to simple cycle operation by Jan 1, 2012 of gas supply not being completed on time is mitigated by fuel oil capability • If upfront activities can be completed on-time, we do not see the plant construction as a significant risk at this time, and the risks for simple cycle operation by Jan 1, 2012 are very low • If the EPC contract has to be re-bid, there is risk that permitting and construction may be delayed • Cost risk • A target cost estimate has not been developed. • We have not performed any site-specific cost estimates. Costs may have to change as we learn details about how we will fit into this existing plant site. • Contingencies have been built into the cost assumptions to mitigate these potential issues • We will have to accomplish construction while not interfering with coal plant operation.

5. Combined Cycle Plant RiskFor a Plant to be Located on the JSF Site • Power system risk • Risk to plant being available by Jan 1, 2012 • We now plan for three CTs (~500 MW) to be available for simple cycle operation by Jan 1, 2012. • As with any construction project, there is some risk, small in this case, that the CTs will not be available by this date. • Note that some out-of-economic order dispatch will likely be needed during this period. • Natural gas supply risk • The plant has some small risk to interruption to gas supply. If gas supply is interrupted, say for a breach of the lateral to the plant, it is highly likely that generation will be interrupted. • Oil backup can mitigate this risk (by helping avoid a long gas supply interruption, by allowing some generation on oil) but does not remove it. • Steam cycle trips - we will mitigate the risk of steam cycle trips to plant operation by including full condenser bypass and bypass diverter dampers to allow simple cycle operation with no interruption in generation.

6. BackupCombined Cycle Plant Risk For a Plant to be Located on the JSF Site • Schedule risk • Biggest risk lies with the upfront activities that must be completed prior to starting construction • This is primarily for CC operation. • For simple cycle operation by 1/1/12 risks are very low. • NEPA process must be completed by April 2010 to meet CC scheduled operation of June 2012 • Completion April 2010 is based on an environmental assessment (EA). If an Environmental Impact Statement (EIS) is required (which is unlikely), Simple Cycle operation by 1/1/12 could be impacted only if schedule increased greater than 6 months ( NEPA complete by October 2010). Low risk for simple cycle operation. • Air permitting must be completed by June 2010 to meet CC schedule of June 2012. • The CC schedule does not allow for the typical Prevention of Significant Deterioration (PSD) permit. We must be able to net out using the existing JSF plant emissions (which is very likely). • Low risk for simple cycle operation. However, for simple cycle operation by 1/1/12, air permit could be received as late as November 2010 • Note that one air permit will be obtained for both simple cycle and CC operations.The simple cycle portion will be included as an “alternative operating scenario”. • The natural gas supply is another pre-construction risk for CC operation • The environmental review for the gas supply will be included in the TVA EA that will be completed by April 2010 (for CC operation in June 2012) • Also, FERC approvals must be obtained and the gas supply lateral and upgrades must be completed by Sep 2011 • Risk for simple cycle operation by 1/1/12 is mitigated by fuel oil capability (if gas supply not completed on time) • If upfront activities can be completed on-time, we do not see the plant construction as a significant risk at this time, and the risks for simple cycle operation by 1/1/12 is very low. • If the EPC contract has to be re-bid, there is risk that permitting and construction may be delayed. • Cost risk • A target cost estimate has not been developed. • We have not performed any site-specific cost estimates. Costs may have to change as we learn details about how we will fit into this existing plant site. • Contingencies have been built into the cost assumptions mitigate these potential issues • We will have to accomplish construction while not interfering with coal plant operation.

7. Bingaman’s 2009 Draft Bill Renewable Portfolio Standard (RPS) • Senator Bingaman released a discussion draft bill proposing a national RPS in January of 2009. The draft language is expected to change significantly but current requirements are 4% by 2011 increasing to 20% by 2021 with no exemption for public power. • TVA has been planning to a federal RPS since August 2007. • TVA’s current planning targets are provided for comparison and are 3% by 2013 increasing to 15% by 2022. These percentages are total RPS requirements and vary from those quoted in the Nov 2008 Regulatory Outlook Documents (RODs). Energy efficiency credits were deducted from the total RPS requirements to produce the Nov 08 ROD targets of 2% in 2013 ramping to 11% by 2022. • Bingaman's bill begins earlier, affects fewer distributors (lowering the GWh requirements), but counts essentially none of TVA’s incremental hydropower as renewables. • The Obama administration is proposing an RPS requiring 10% of US electricity be from renewable resources by 2012 and increasing to 25% by 2025.

8. Comparison of TVA Renewable Planning Targets vs Bingaman 2009 Draft Bingaman’s Draft Bill • Renewable Portfolio Standard requiring 4% renewable generation beginning in 2011 escalating to 20% by 2021. • Energy efficiency credits (EECs) can meet up to 25% of the compliance obligation for utilities in a state that has obtained DOE approval to do so. • The percentage is based on total load of consumers with a sales forecast of >4,000 GWhs. • Alternative compliance purchases are set at $30 per MWh. • Existing renewables: solar, wind, geothermal, ocean, biomass, and landfill gas. • New renewables: wind, solar, geothermal, ocean, biomass, landfill gas, and incremental hydro capacity installed from 2006 forward. Current Planning Target: • Renewable Portfolio Standard of 3% renewable generation beginning in 2013 escalating to 15% by 2022. * • Energy efficiency credits (EECs) are expected to be included as compliance options. • The percentage is based on total load of distributors with a sales forecast of >1,000 GWhs. • Renewable credit purchases are projected to be $25 per MWh (Nominal dollars) . • Renewables in an RPS are a subset of TVA’s renewables limited to wind, solar, methane, new biomass, and incremental hydro capacity installed from 2001 forward. TVA’s RPS Requirements per the Nov 2008 ROD Planning Targets TVA’s RPS Requirements per the Bingaman Draft Bill Most of TVA’s renewables would not apply due to change in definition of “new” renewables. The availability of EECs cannot be determined until actions are taken by DOE and State Governors. Gap: Amount of RPS credits TVA would need to purchase for compliance.

9. Clean Air – Aug 08 Budget Assumptions used in SFS

10. Clean Air – May Assumptions used in SFS

11. Bingaman Comments • The 2011 start date seems problematic. • Compliance is achieved by submitting renewable energy credits, energy efficiency credits, buying alternative compliance credits, or a combination of those options. All three compliance credit options can be banked up to 3 years. • Generators will receive tradable credits for “new” renewable energy and non-tradable credits for “existing” renewable energy. Non-tradable credits can only be used by TVA for its own obligations, i.e., the supply to its direct-served customers. • “New” renewables are defined as solar, wind, geothermal, ocean, landfill gas and incremental hydropower placed in service after January 1, 2006. This does not give credit for early actions to diversify generation mix. • “Existing” renewables definition does not include incremental hydro capacity. Most of TVA’s incremental hydropower would not count as “new” renewables, and hence, TVA would receive no compliance benefits for the HMOD program. • Raising the statutory trigger to >4,000 GWhs for electric consumers results in less stringent requirements than current planning targets and favors wholesaler utilities like TVA. • Small renewable distributed generators on retail customer sites (³ 1 MW) receive triple credits requiring careful design of Generation Partners. • The Governor must petition DOE in order for the state to utilize energy efficiency credits for compliance purposes. These credits can only be used in the state of origination causing administrative burden on multi-state electric utilities.

12. Other Clean Air Regulatory Changes • May 2008 Clean Air Plan was primarily driven by the Clean Air Interstate Rule (CAIR) and Clean Air Mercury Rule (CAMR). CAIR addresses SO2 and NOx emissions. Both were cap-and-trade rules. • The D.C. Circuit Court of Appeals vacated CAMR in February 2008. • TVA and the industry expect CAMR will be replaced by a mercury Maximum Achievable Control Technology (MACT) rule by 2014-15. • Rather than cap-and-trade, a mercury MACT rule would require mercury emissions reductions at each plant site. • The D.C. Circuit Court of Appeals issued a decision vacating CAIR in July 2008. The Court reversed its vacatur decision on Dec. 23 and remanded the rule to EPA. • CAIR will remain in place in full until EPA promulgates a replacement rule which could take several years. There is no timeline for a replacement rule. • A new rule is expected to restrict or eliminate interstate emissions trading. • Current CAIR SO2 and NOx requirements are expected to remain in effect at least through CY 2010. • Local ozone and fine particulate ambient air quality standards will continue to get more stringent.

13. Clean Air – National Outlook • Bullets listed below may be considered temporary placeholders rather than draft material • CAMR • description • CAIR • description • BART • Description • MACT • Description

14. Aug 08 annual detail

15. May 09 - scrubbed annual detail

16. May 09 - 3000 annual detail

17. May 09 - 7000 annual detail

18. .

19. Aug 08 – MW

20. May 09 Scrubbed– MW

21. May 09 3000– MW

22. May 09 5000– MW

23. May 09 7000– MW

24. Aug 08 – $

25. May 09 Scrubbed– $

26. May 09 3000– $

27. May 09 5000– $

28. May 09 7000 – $

29. JOF 2022 replaced by on-site SCPC • BFN1 EPU 2013 • BLN 2018, 2020, • AP1000 in 2025, 2027 • No acquisitions included • No DSM MWs or Dollars included Aug 08 May 09 - scrubbed Asset Strategy Asset Strategy • JOF 2022 replaced by on-site SCPC • BFN EPUs 2010, 2011 • BLN 2018, 2019 • AP1000 in 2025, 2026 • No acquisitions included • DSM MWs and Dollars included • JOF 2018 replaced by on-site CC • BLN 2018, 2020 • BFN1 EPU 2013 • AP1000 in 2025, 2027 • No acquisitions included • No DSM MW or dollars included May 09 - 3000 • JOF 2016 replaced by on-site CC • BFN1 EPU 2013 • BLN 2018, 2020 • AP1000 in 2025, 2027 • No acquisitions included • No DSM MW or dollars included May 09 - 7000 Asset Strategy Asset Strategy Power Supply - Four Alternatives

30. Aug 08 May 09 - scrubbed May 09 - 3000 May 09 - 7000 Power Supply - Four Alternatives

31. Aug 08 May 09 - scrubbed May 09 - 3000 May 09 - 7000 Power Supply - Four Alternatives

32. Power Supply - Four Alternatives Cost summary of four cases • Main drivers for differences (WHY) • Case risks

33. Power Supply - Four Alternatives Cost summary DELTA of four cases • PV impacts, bucket summary, etc.

34. Options / Information / Decisions