1. Natural Gas Fuel Switching Consequences for Public Power Utilities 2012-2017 Theresa Pugh & J.P. Blackford April 27, 2010 APPA Energy & Air QualityTask Force

2. Retrofit existing fired power plant with Hazardous Air Pollutant Controls (Minimum of Scrubbers or Baghouses Activated Carbon & ESP) and CCS meeting roughly natural gas standard for CO 2 Fuel Switch to Natural Gas (and deal with hedging, build new infrastructure & price volatility issues) Door #1 Door #2 Door #3 Use Clean Air Act’s NSPS for reasonable, available and cost effective energy efficiency (DSM) and renewables [heavy lift]

3. 3 Possible Timeline for Environmental Regulatory Requirements for the Utility Industry Ozone '08'09'10 '11'12'13 '14 '15 '16 '17 Beginning CAIR Phase I Seasonal NOx Cap HAPs MACT proposed rule Beginning CAIR Phase II Seasonal NOx Cap Revised Ozone NAAQS Begin CAIR Phase I Annual SO 2 Cap -- adapted from Wegman (EPA 2003) Updated 2.15.10 Beginning CAIR Phase II Annual SO 2 & NOx Caps Next PM- 2.5 NAAQS Revision Next Ozone NAAQS Revision SO 2 Primary NAAQS SO 2 /NO 2 Secondary NAAQS NO 2 Primary NAAQS SO 2 /NO 2 New PM-2.5 NAAQS Designations CAMR & Delisting Rule vacated Hg/HAPS Final EPA Nonattainment Designations PM-2.5 SIPs due (‘06) Proposed CAIR Replacement Rule Expected HAPS MACT final rule expected CAIR Vacated HAPS MACT Compliance 3 yrs after final rule CAIR Remanded CAIR Begin CAIR Phase I Annual NOx Cap PM-2.5 SIPs due (‘97) 316(b) proposed rule expected 316(b) final rule expected 316(b) Compliance 3-4 yrs after final rule Effluent Guidelines proposed rule expected Water Effluent Guidelines Final rule expected Effluent Guidelines Compliance 3-5 yrs after final rule Begin Compliance Requirements under Final CCB Rule (ground water monitoring, double monitors, closure, dry ash conversion) Ash Proposed Rule for CCBs Management Final Rule for CCBs Mgmt Final CAIR Replacement Rule Expected Compliance with CAIR Replacement Rule CO 2 CO 2 Regulation Reconsidered Ozone NAAQS PM 2.5

4. Retrofit Decisions Driven by HAPs & CAIR Regulations Before CO 2 CURRENT CAPITAL COST AND COST- EFFECTIVENESS OF POWER PLANT EMISSIONS CONTROL TECHNOLOGIES Prepared by J. Edward Cichanowicz Prepared for Utility Air Regulatory Group January 2010 “The capital cost of retrofitting either wet FGD or SCR increased over the recent 4-year period, from about 2005 through 2009, and specifically for a 500 MW plant, by approximately $50- 65/kW. This same rate of cost escalation is anticipated to continue for the next 4-6 years, elevating the cost of equipment installed in 2014 and 2015 for a CAIR Phase 2 mandate and the anticipated HAPs MACT rule.”

5. Update screen shot

7. Current Natural Gas Pipeline

8. Current U. S. Natural Gas Storage Maps (no differentiation for storage capacity)

9. Table 6: Gas Burn by State if Existing Coal-Fired MW Converted to Natural Gas State2008 Gas Use Additional Use If Coal Converted Coal Use As % of Current Gas Use Alabama0.4040.533132% Alaska0.3420.0051% Arizona0.40.24662% Arkansas0.2350.16671% California2.450.0181% Colorado0.5050.22344% Connecticut0.1670.02615% Delaware0.0480.04594% Florida0.9430.47951% Georgia0.4250.614144% Hawaii0.0030.009316% Idaho0.0890.0011% Illinois1.0010.73974% Indiana0.5510.906164% Iowa0.320.27485% Kansas0.2830.2381% Kentucky0.2250.694308% Louisiana1.2390.15813% Maine0.0610.0047% Maryland0.1960.22112% Massachusetts0.3740.07520% Michigan0.7790.54270% Minnesota0.4010.23859%

10. Additional Use IfCoal Use As % of State2008 Gas UseCoal ConvertedCurrent Gas Use Mississippi0.3550.11332% Missouri0.2960.497168% Montana0.0760.107140% Nebraska0.1680.13480% Nevada0.2650.11644% New Hampshire0.0710.02636% New Jersey0.6150.09415% New Mexico0.2470.18475% New York1.180.1815% North Carolina0.2430.558230% North Dakota0.0630.179283% Ohio0.7921.002126% Oklahoma0.670.24136% Oregon0.2680.0259% Pennsylvania0.750.861115% Rhode Island0.08900% South Carolina0.170.272160% South Dakota0.0640.0231% Tennessee0.230.433188% Texas3.5460.89325% Utah0.2240.21495% Vermont0.00900% Virginia0.2990.26187% Washington0.2980.06121% West Virginia0.1110.646580% Wisconsin0.4090.29973% Wyoming0.1430.259182%

11. Map of States Requiring more than 100% of their current NG consumption to replace coal fired capacity with natural gas

12. Natural Gas Price Volatility Source: EIA Report “An Analysis of Price Volatility in Natural Gas Markets” (2007) http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2007/ngprivolatility/ngprivolatility.pdf

13. Switching from Coal to Natural Gas: Understanding the Environmental and Operational Impacts At APPA National Conference, June 19-23, 2010, Orlando, FL Cost to Members: $375; Cost to Non-Members: $750 Sunday, June 20, 2010 - Full day 8:30 a.m. – 4:30 p.m. The U. S. Environmental Protection Agency’s “perfect storm” of new environmental regulations (air, climate, water and waste) may lead many utilities to switch from coal to natural gas for base load energy production to reduce carbon dioxide, sulfur dioxide and fine particulate matter. While natural gas may be an easier environmental choice, the utility’s operational issues may grow far more complex when producing electricity with natural gas. Operational issues range from anticipating how much gas to use in lieu of coal, the purchasing (“nomination”) process, natural gas transportation issues, and local storage when the gas is not used within 24 hours. The speaker will address all aspects of natural gas use, from nomination, to setting up procurement operations, to re-sale of natural gas in the market if storage is not available. Instructors: Ted Chapman, Director, Standard & Poor's, Dallas, Texas; Catherine Elder, Senior Associate, Aspen Environmental Group, Sacramento, Calif.; Doug Hunter, General Manager, Utah Associated Municipal Power Systems, Salt Lake City, Utah; and Joanie Teofilo, Vice President, Risk Control & CRO, The Energy Authority, Jacksonville, Fla. http://www.appanet.org/events/annualeventdetail.cfm?ItemNumber=26074&sn.ItemNumber=0

14. Overview * Cumulative impacts of air, water, and waste rules will require coal plants to make significant environmental control investments to continue operating. Size and timing of these expenditures could result in many retirements. Three major adverse impacts could result: – Regional reliability and reserve margin requirement shortfalls – Misallocation of financial resources and stranded investments – Likely very large increases in use of natural gas by the power sector Timing, sequencing, and other regulatory parameters are critical. – HAPs, water, CCBs, and CO 2 are significant issues; juggling and sequencing these regulatory tracks may be the most important challenge. EPA’s analysis can take specific steps to reflect these issues The cumulative impact to power plants from overlapping regulations around 2015-2017 * These slides excerpted from a presentation by a group of utilities to EPA on 2/10/10

15. 15 Multi-Media Compliance Challenges over the Next Decade * 20102020 HAPs (MACT): Coal and oil units – ACI/FGD/SCR/BH (capital plus O&M) Air Quality (new CATR, NAAQS, Visibility): All fossil plants – FGD/SCR (capital plus O&M) Water (New Effluent Guidelines): All plants/coal focused – Treatment/dry ash disposal (capital plus O&M) Cooling Water Intake Structures (316(b)): All plants – Fine screens/cooling towers (capital plus O&M) Ash Management: All coal units – Monitoring/dry ash disposal/new landfills/liners (capital plus O&M) Climate Change, Renewables and End Use Efficiency: All fossil units – Gas or biomass conversion; retirements; demand loss (capital + conversion cost + O&M + retire & replace + RECs or ACPs + CO 2 allowances) Rulemakings & Implementation Compliance Required Maintaining Compliance & New Standards 15 Need final rules to commit to a specific technology or compliance strategy.  Retrofit technologies, selection and cost, are dependent on unit design, fuels, age, & location.  Technologies to reduce GHGs (e.g., CCS) are in early development. There is a cumulative impact to power plants from multiple regulations. * These slides excerpted from a presentation by a group of utilities to EPA on 2/10/10

16. Decision Timelines for Existing Coal Units * Timeframes vary by unit--Fleet considerations may extend the time needed for any specific unit conversion Unit Continue to operate on coal Convert to gas operation (if possible) Convert to biomass (limited controls) Retire and Replace Retire 3-5 year FGD/SCR engineer/construction timeline 4 year conversion timeline 3-4 year conversion timeline 3-6 year combined cycle develop/construct timeline Transmission Implications 5-10 years 5-10 year dry ash conversion timeline 2-5 year cooling tower eng./const timeline Final rule  Key investment decisions and resource allocations cannot be made until rules are final.  Some regulated companies must obtain commission approval for emission control projects.  Most must obtain commission approval for new generation.  Financing relies on final EPA regulations.  Compliance deadlines preceding the construction/conversion completion could lead to early retirement. Decisions for a single unit are further complicated as we consider multiple units, plants, fleets, NERC regions and the nation. * These slides excerpted from a presentation by a group of utilities to EPA on 2/10/10

17. Cumulative Capital Impacts May Force Retirements * Financial viability compares the continuing cost to operate to the replacement cost. Continuing cost to operate includes all costs, including capital for: – Air – Water – CCBs (Coal combustion products) – CO 2 Cumulatively, these costs may make many units uneconomic, leading to retirement. Replacement generation would be necessary. This type of analysis is not uniform across the industry, with variations in frameworks and risk tolerance. When the continuing to operate costs exceed the avoided cost of replacement, it is more economic to shut down and replace the unit. Example for illustrative purposes only * These slides excerpted from a presentation by a group of utilities to EPA on 2/10/10

18. What is the EPA Thinking? EPA has convened an unofficial BACT working group—process largely influenced by the vendors including those selling natural gas, natural gas combined cycle units, gas turbines, and equipment/instruments for IGCC plants. EPA is very impressed with natural gas and abundance/low cost—”easy solution for the power sector” EPA does not understand that over reliance upon one fuel source is risky—cost & reliability issues Sec 116 Waxman-Markey “US CAP” 18

19. Some of the EPA’s BACT Options – None Good EPA Workgroup to Advise EPA on GHG BACT (9/09-2/10) TO DIRECT EPA ON NEEDED GUIDANCE – Phase 1 Report to EPA 2/2/10 – Phase 2 - 8 White Papers on Unknown Topics by 2/19/10 Phase 1 Report Reflects General Disagreement Between Stakeholders and Asks EPA for Guidance On: – Changing the Definition of Source for Purposes of Applying BACT – Guidance for Determining When Energy Efficiency Constitutes BACT To date - BACT applies to the unit at which a physical change occurs Must change traditional notion of where BACT applies in order to-- – Allow Fuel Switching (require a coal plant to become a gas plant) – Provide for Energy Efficiency measures at other plant units – Accommodate Demand Side EE? See BACT Determination for 612 MW gas-fired Calpine Hayward, CA – BACT Analysis excludes CCS – BACT = ENERGY EFFICIENCY OF 7,730 Btu/KWH at that unit

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21. Presentation by CALPINE Feb. 4, 2010 21

22. Could BACT Force Fuel Switching? EPA’s Dec. 2009 - Feb. 2010 BACT Decisions: Change in BACT by pushing consideration of IGCC technologies & asking why natural gas wasn’t considered Kentucky CASH Case Arkansas AEP Case Rumors of a 3 rd BACT case 22

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24. U.S. Coal Fleet Demographics * Size – Over 75 GW that are <250 MWs Age – Over 45 GW >50 years old today – Another 67 GW between 40 and 50 years old Environmental Controls – Over 190 GW do not have FGD – Over 190 GW do not have SCR or SNCR – Over 280 GW do not have FF – Only 9 GW have all three installed-- FGD,SCR/SNCR,FF – 38% (275 GW) of fossil fuel fired units at risk of cooling towers retrofits – 169 GW with wet ash handling/disposal of CCBs 1 Notes: *Coal Unit Data: Energy Information Administration (www.eia.doe.gov/cneaf/electricity/page/capacity/existingunitsbs2008.xls) *Air Emission Control Data: EPA Clear Air Markets Division (http://camddataandmaps.epa.gov/gdm/)http://camddataandmaps.epa.gov/gdm/ 1 EIA 767 data, 2005 Total US coal MW: 333,018 MW at Risk**: 137,248 ** MW at risk: MW without both an FGD and an SCR. * These slides excerpted from a presentation by a group of utilities to EPA on 2/10/10

25. Environmental Control Cost Assumptions * Retrofits, replacements and investment in low carbon or other technologies will compete for capital. Required TechnologyCost per kW or facility AIR (coal plants 300 –1,000 MW) FGD $300 – 500/kw (EPA using $120 – $240/kW) 1 SCR$200 – 400/kw (EPA using $110 – 120/kW) 1 FFAdditional costs WATERCooling tower retrofit~$185/kW (EPA used $58 - $62/kW) 2 CCBsImpoundment closure>$50 million/facility Note: Cost estimates do not include capital for replacement generation or transmission. This table does not include the uncertain costs of carbon regulation/legislation. 1 EPA’s CAPA Proposal Analysis, 2009. 2 DOE’s comments in Phase II rule, 2002 and EPA, http://www.epa.gov/waterscience/316b/phase2/devdoc/ph2toc.pdf * These slides excerpted from a presentation by a group of utilities to EPA on 2/10/10

26. Reliability Concerns: The Issues* Numerous and costly compliance requirements for air, water and CCBs could lead to significant number of retirements. Timing may result in many units being taken off-line at the same time to complete needed retrofits. Regional planning/reliability requirements must be coordinated to maintain the reserve margin (e.g., retirements, outages, etc.). For regulated utilities, concentrated rate case hearings coupled with rate shock concerns may prohibit timely resolution by state utility commissions. Concerns are applicable to most regions, especially those with significant coal generation. * These slides excerpted from a presentation by a group of utilities to EPA on 2/10/10

27. APPA Natural Gas Study In anticipation of the EPA actions on BACT or NSPS, or NAAQS regulations, APPA has commissioned a natural gas study with Katie Elder, Aspen Environmental, CA. Gas study to demonstrate operational differences from baseload coal to gas Study not designed to question value of gas—but to describe nomination/purchase/re-sale and hedging in a volatile market Natural gas storage/pipeline issues different from state to state 27

28. Fossil Fuel Based Generation Map – Showing Large Number of Potential Plants Requiring Access to Natural Gas Source: NatCarb Atlas 28

29. Availability of APPA Natural Gas Study? Katie Elder, Aspen Environmental March 2010 APPA Natural Gas Workshop, June 2010 at National Conference, Orlando, FL 29

30. 30 Source of Map: NatCarb Atlas; Overlay: APPA Optimal Location Criteria Maps without CO 2 pipelines Note: Optimal Locations are for new plants, not retrofit of existing power plants Existing Fossil Generation & Optimal CCS Locations Without Any Drinking Water Resource Location Analysis

31. Deep Saline Aquifer Locations 31

32. Deep Saline Aquifer Locations & ‘Lenient’ Seismic 32

33. Deep Saline Aquifer Locations & ‘Stringent’ Seismic 33

34. Saline Aquifers, CO 2 Pipelines, & ‘Lenient’ Seismic 34

35. Other Considerations – Transmission Lines 35

36. Other Considerations – Railroads 36

37. Optimal Sites – Using Existing CO 2 Pipelines 37

38. Optimal Sites – Not Requiring Proximity to CO 2 Pipelines 38

39. APPA Contacts 39 CO 2, EPA liaison, CAA, & new generation (including renewables) Theresa Pugh Director, Environmental Services 202-467-2943 TPugh@APPAnet.org GHG Reporting, 316(b), biomass and effluent guidelines J.P. Blackford Environmental Services Engineer 202-467-2956 JPBlackford@APPAnet.org