Clean Air Response / Power Supply Impacts version #17

1. Clean Air Response / Power Supply Impactsversion #17 Presented by: May 13, 2009

2. Purpose • Summary of Clean Air Ruling • Decide the next steps for John Sevier (JSF) and Widows Creek (WCF1-6) in order to comply with North Carolina ruling • Discuss impact on overall power supply plan, including a variety of fleet options

3. Clean Air Ruling • North Carolina (NC) Ruling Ordered the following: • Completion of BRF scrubber • Completion of two KIF scrubbers by 12/31/2010 • Installation of scrubbers & SCRs at JSF by 12/31/2011 • Installation of scrubbers & SCRs at WCF 1-6 by 12/31/2013 • Legal Appeal • Appeal process could take years • NC Order would be in effect during an appeal process • Impacts of transmission and capacity risk need to be considered for the 2012 and 2014 deadlines • JSF and WCF - asset decision needed now TVA Board

4. WCF 1-6 and JSF Decisions NC Lawsuit alternative decisions for WCF 1-6 and JSF Decisions needed by 6/09 in order to meet compliance deadlines and reliability requirements Decision Tree WCF 1-6 JSF Add FGD & SCR by Jan 1, 2014 Add FGD & SCR by Jan 1, 2012 Retirement on Jan 1 , 2014 + 10-yr. Transm. Fix Starting ASAP Retirement on Jan 1 , 2012 + 10-yr. costly Transm. Fix Retirement + CC on-site by Jan 2012 Retirement + CC on-site by Jan 2014 Replace energy & capacity elsewhere* Replace energy & capacity elsewhere* Note: must have transmission fix in place or on-site generation at JSF to avoid shedding load in Knoxville area Significant System Risk Manageable System/Operational Risk *significant load shedding required when loads >28,000MWs *significantoperational constraints on RMPS until fixes are implemented

5. WCF 1-6 Study Summary • Costs are present value of differences between two cases. • Clean air costs – WCF 1-6 has high clean air costs compared to other unit groups. • If WCF 1-6 is retired and not replaced on-site, transmission upgrades would be required. • CO2 included in analysis

6. JSF Study Summary • Costs are present value of differences between two cases • Firm gas supply – Gas fired plant located at JSF requires substantial pipeline upgrades and new lateral to plant site • CO2 included in analysis

7. Changes Since the JSF March Evaluation • Capital costs • Controls cost could be up to $190M greater than $611M cost used in March studies. • Replacement CC cost could be $60M greater than the $789M used in March studies. • Firm gas supply • ETNG has reduced their estimate of firm gas supply by $5 million per year which is a present value cost reduction of $38 million. • Generation plan • Total system and coal generation is now much higher than in the March study • Loads are the same, but DSM, Tapoco, and nuclear uprates no longer included • A sensitivity case with higher total system and coal generation from the March study showed that the value of JSF with controls increased as the need for generation increases

8. Why Decisions Need to Be Made Now For the JSF replacement CC, the following must proceed otherwise schedule will be impacted. • Must order combustion turbines by June 12 • GE is holding three CTs for TVA until June 12 - units are subject to prior sale after Jun 12. No other CTs are available for this project – would be delayed to Sep 2012. • Must order steam turbines as soon as possible • Three steam turbines are now available; these machines are all subject to prior sale. Delays would be to mid-2013. • ETNG must begin process for gas pipeline surveys by June 8 • Requires contacting property owners for permission; delays will impact pipeline upgrade schedule and environmental data that TVA needs to complete NEPA • Consequences of delay past Jan 1, 2012 • Capacity and energy shortfall • Regional transmission impacts that could result in significant curtailments to customers

9. Why Decisions Need to Be Made Now For adding controls to JSF, the following must proceed otherwise schedule will be impacted. • The schedule includes awarding the scrubber contract by June 1. • If the scrubber contract award is delayed beyond June 1, the completion schedule will be affected month-for-month. • Consequences of delay past Jan 1, 2012 • Capacity and energy shortfall • Regional transmission impacts that could result in significant curtailments to customers

10. Why Decisions Need to Be Made Now • For adding controls to WCF1-6 • Decision delay for adding emissions controls will cause project cost and schedule impacts • Delays in adding controls will mean capacity and energy shortfall in 2014 until completion of controls • Delay will cause transmission impacts including restrictions to Raccoon Mountain pumping, Sequoyah offsite power issues, and possible load curtailments. • For shutting down WCF1-6 and upgrading the transmission system • Requires 19 transmission upgrade projects; preliminary schedule is five to ten years, depending on outages • Sequoyah offsite power and Raccoon Mountain operation will be impacted until some upgrades are completed • Decision delays extend the time that operational constraints must be imposed

11. “All-In” Cost (Fixed, Variable, Emissions) CO2 @ $33/ton Updated 5-6-09

12. Levelized All-In Cost Of Generating Options $/MWh $160 CO2 $140 Coal @ $ 3.25 /mmBtu Variable CO2 @ $33/ton $140 Fixed $4 Gas @ $ 8.00 /mmBtu $120 $110 $105 $96 $14 $100 $30 $61 $35 $80 $60 $60 $33 $36 $40 $36 $20 $42 $75 $25 CF = 35% CF = 85% CF = 85% CF = 75% $0 JSF Scrubbed Gas CC-with Duct firing SCPC Capture Ready SCPC with Capture “All-In” Cost Components – Gas at $8/mmBtu, mixed CF CF = Capacity Factor Updated 5-6-09

13. Spectra Energy Gas Supply Views

14. Marcellus ShaleDevonian ShaleCoal Bed Methane Benefits of East Tennessee Natural Gas • ~1,500 miles of pipe serving the Southeast and Mid-Atlantic markets (TN, GA, NC, KY and VA) with 1.5 Bcf/d of capacity • Access to diverse and reliable supply sources • Major pipeline interconnections • On-system Appalachian suppliers (CNX, EQT, CHK) • On-system LNG storage - ~1.1 Bcf working gas • On-system Storage - 5.5 Bcf • Experienced scheduling and operations group with 24 hour manned coverage

15. Stochastic Analysis of John Sevier Decision • Faced with decision of whether or not to comply with pollution controls (scrub) or retire and replace with NGCC technology on-site. • Decision will impact both present value of total cost from a revenue requirement perspective, which is the relevant metric since this is what TVA’s customers will pay, either in current rate increases or deferred (i.e. increased borrowing) rate increases. • Analysis takes capital (construction costs) as provided by FPG, and covers the period 2009 through 2027. • Two basic carbon worlds were studied, where carbon prices were stochastic random variables, but allocations were either 80% or zero. • Coal prices and carbon tax rates were taken from PSP assumptions. Indicative natural gas swap rate sourced from large commodities trading desk, but is indicative in nature. • System Financial Dispatch Model (SFDM) used for analysis. Allows for economic redispatch of the system under various price and carbon tax outcomes. Simulation used 1,000 iterations.

16. Key Observations • At the Median Value: • Given that GHG legislation is forecasted to begin in 2015 with an 80% allocation, JSF shows less total rate pressure impacts than NGCC since fuel costs are lower and allowances are mostly free. • With zero carbon allocation, JSF is slightly favored over the NGCC. However, NGCC outperforms JSF beginning in 2024. • Given the volatility surrounding carbon and coal prices, JSF alternative grows riskier over time and exceeds the risk of NGCC option. • Over Entire Study Period: • At an 80% carbon allocation, the NGCC option is only favored over JSF in 1.5% of the outcomes. In other words, JSF outperforms NGCC almost 99% of the time. • As allocation drops to zero, NGCC favored over JSF 38% of the time. In other words, JSF only outperforms NGCC less than 2/3rds of the time. • Given use of fixed-price gas, does not capture potential upsides of a low gas-price world, which; when combined with carbon, could increase the attractiveness of the NGCC option.

17. In about 60% of outcomes, JSF outperforms NGCC from perspective of total rate pressure

18. Power Supply – Fleet Options

19. Power Supply Plan Impacts Total System Requirements – down 3000 MW by 2020 • Total system requirements in 2020 (Aug08): 47,000 MWs • Total system requirements in 2020 (May09): 44,000 MWs • Opportunity to take advantage of lower loads

20. Power Supply Plan Impacts • A diversified portfolio in intermediate generation is best hedge against fluctuating gas prices and coal emission taxes • 2020 energy requirement is ~200,000 Gwhs. • Nuclear and hydro generation can cover 100,000 Gwhs, leaving gas/coal to cover remaining 100,000. • Equal capacity split between coal and gas allows either technology to produce 85% of 100,000 Gwhs, depending on which is most economical at the time Current 2020 Plan Potential 2020 Plan

21. Dispatch Curve – Gas and Coal swapping

22. Key Drivers - Natural Gas & Coal Price Costs shown do not include emission allowances (SO2, NOx & CO2) • PS&F currently has some gas hedged to 2013 • Recent quotes indicate a willingness to go to 2020 • Price range appears to be 25¢ above Nymex curves (~$7.40/mmBtu) • Gas Transportation would add 45-55¢/mmbtu (total ~$7.90/mmBtu) through 2020

23. Natural Gas & Coal with Emissions Costs shown include emission allowances (SO2, NOx & CO2) • By 2028, the gas forecast is $25/MWh higher than coal including emissions impacts • Including emissions impacts, a potential gas hedge crosses the coal forecast in 2025 at ~$75/MWh • Ability to hedge CO2 requirements is much more uncertain • Gas hedge is more liquid

24. Power Supply – 3 Bounding Cases • Aug 08 • August 2008 Budget Plan • May 09 – scrubbed • Accelerates existing fleet clean air schedule as needed • Achieves clean air & NC ruling compliance by installing controls • May 09 – 3000 • Similar to May09–scrubbed except ~3,000 MWs of fossil units are retired • May 09 – 7000 • Similar to May 09–scrubbed except ~7,000 MWs of fossil units are retired

25. Power Supply – Case Assumptions Case Summaries: • Aug 08 is FY09 Budget Plan • May09 cases (in yellow) includes updated loads, DSM assumptions, outage schedules, clean air plan, and commodity prices • May09 scrubbed case • May09 3000 case retires ~3000 MWs of fossil • May09 7000 case retires ~7000 MWs of fossil

26. Power Supply – Case Total Cost - 20 yrs Case Summaries: • 3000 & 7000 cases require more gas-fired generation • Bingaman Bill assumption is more expensive compared to Aug08 RPS outlook • Red circle savings from Clean Air/Plant Capital costs offsets blue circle expansion costs • Not counting fuel & emissions, Scrubbed and 3000 cases are both $78B

27. Power Supply – Cost NPVs Case Summaries: • Less than $1B separate May 09 scrubbed and May 09 – 3000 cases • Bingaman Bill, Clean Air, Fixed Expansion, and Capacity Expansion explain most of the differences between Aug 08 and May 09 – 7000 cases

28. Power Supply – Case Total Cost 5 years 10 years 15 years 20 years

29. Power Supply – Case NPVs 5 years 10 years 15 years 20 years

30. Power Supply Cost Deltas Cases - Aug 08 5 years 10 years 15 years 20 years

31. Power Supply Cost Deltas Cases -May 09 scrubbed 5 years 10 years 15 years 20 years

32. Aug 08

33. May 09 - scrubbed

34. May 09 - 3000

35. May 09 - 7000

36. Power Supply – CO2 Emissions Carbon comparison • Aug 08 • 1.97B tons • May 09 – scrubbed • 1.93B tons • May 09 – 3000 • 1.83B tons • May 09 – 7000 • 1.62B tons • CO2 per GWh of TVA load declines in May cases • From 2009 – 2020: • TVA load increases by 14% • May 3000 CO2 decreases by ~15% • May 7000 CO2 decreases by ~30% 170K GWh 200K GWh Volumes are calendar years 2010 – 2027

37. Power Supply – NOx Comparison • Aug 08 • 1,039 tons • May 09 – scrubbed • 921 tons • May 09 – 3000 • 864 tons • May 09 – 7000 • 756 tons Volumes are calendar years 2010 – 2027

38. Power Supply – SO2 Comparison • Aug 08 • 2,868 tons • May 09 – scrubbed • 2,472 tons • May 09 – 3000 • 2,317 tons • May 09 – 7000 • 2,017 tons Volumes are calendar years 2010 – 2027

39. WCF 1-6 and JSF Decisions

40. WCF 1-6 Decisions – needed now • North Carolina ruling options: • Compliance through FGD and SCR installations by 1/1/2014 • Total cost estimated to be $909M • Currently estimate that schedules can be met • Retirement with transmission fixes (no on-site generation) • Capacity and energy replaced elsewhere on the system (CTs) • $94M and up to 10 years required • Sequoyah offsite power and Raccoon Mountain operation will be impacted after WCF 1-6 is retired until transmission fixes are completed

41. JSF Decisions – needed now • North Carolina ruling options: • Compliance through FGD and SCR installations by 1/1/2012 • $662 to $805M total cost range • Schedule can be met with 19-month outage of two units • 2 units for 19 months leaves little contingency for transmission issues at high loads • Replacement CC generation – on site or within proximity • $800 to $850M dollars needed for construction • CTs may have to be run out of economic order prior to CC completion • Retirement with transmission fixes (no on-site generation) • Not a viable option due to load shedding and timing • 500+ MWs of load shedding in the Knoxville area when loads are greater than 28,000

42. Recommendation Based on consideration of economics, transmission, timing, risks and other factors, approve_______________________________ Authorize the CEO to approve all contracts, equipment orders and other actions necessary to __________________________________________