1 

### IN THE UNITED STATES COURT OF APPEALS

FOR THE DISTRICT OF COLUMBIA CIRCUIT

EME HOMER CITY GENERATION, L.P., ) ) Petitioner, ) )

v. ) No. 11

- 1302 (and ) consolidated cases) UNITED STATES ENVIRONMENTAL ) PROTECTION AGENCY, et al., ) ) Respondents. ) _________________________________________)

DECLARATION OF SAM NAPOLITANO

1. I, Sam Napolitano, under penalty of perjury, affirm and declare that the following statements are true and correct to th e best of my knowledge and belief, and are based on my own personal knowledge or on information contained in the records of the United States Environmental Protection Agency (EPA) or supplied to me by EPA employees under my supervision.

2. I am the Director of the Clean Air Markets Division (CAMD) of the Office of Atmospheric Programs (OAP) within the Office of Air and Radiation (OAR) at EPA. CAMD develops and manages emissions trading programs and assists other countries with the development of such progra ms.

3. In my capacity as Director of CAMD, I oversee EPA’s implementation of major portions of the Clean Air Act (CAA), including Title IV and parts of Title I. In coordination with other OAR Offices, I manage the promulgation of significant regulations pur suant to the CAA, such as the NOx SIP Call, the Clean Air Interstate Rule (CAIR), and the Transport Rule, and regulations relating to the Acid Rain Program. I also manage and evaluate the centralized implementation of such regulations from EPA headquarter s. In addition, I serve as a national expert and global consultant on air emissions trading programs. I have directed CAMD since 2002.

4. Prior to becoming Director of CAMD, I was senior advisor to the Director of OAP in OAR. I advised the Director on the design and implementation of air emissions trading2 programs for the electric power industry and other aspects of the operation of the electric power industry. I also have worked on mobile sources of emissions, indoor air programs, and climate change prog rams within OAR since 1994 and have worked on environmental programs across the Agency for over 25 years. I hold a bachelor’s degree in Political Science from College of the Holy Cross, Massachusetts, and a Masters of Business Administration with Public P olicy concentration from Cornell University.

5. My division in OAP, in coordination with other OAR offices, developed the Transport Rule. As such, I am very familiar with the Transport Rule emission reduction requirements including the state emission budget levels, unit

- level allocations, compliance timing, Transport Rule emission trading program requirements, and the status of program implementation. The Transport Rule is also known as the Cross

- State Air Pollution Rule (CSAPR).

6. In coordination with other OAR offices, my division also developed the CAIR and the CAIR Federal Implementation Plans (FIPs). I am centrally involved in and oversee implementation of the CAIR trading programs, the Acid Rain trading program, and previously the NOx Budget Trading Pr ogram. I manage the two branches within CAMD that administer CAIR in conjunction with EPA’s regional offices and States. I am familiar with all aspects of the operation of the CAIR trading programs, including the allocation and tracking of allowances, da ta collection and other critical aspects of CAIR such as allowance surrender and State plan approval. I also oversee all aspects of CAIR administration and the establishment of program polices and guidance for CAIR. I am familiar with the CAIR emission r eduction requirements including the cap levels and timing, the CAIR SO2 and NOx trading programs, the status of CAIR implementation, and the July 11, 2008 decision of the U.S. Court of Appeals for the D.C. Circuit in North Carolina v. EPA, 531 F.3d 896 (D. C. Cir 2008), as modified on rehearing, 550 F.3d 1176 (D.C. Cir. 2008).

7. I oversee the work of CAMD staff who track allowance market activity and emissions for the trading programs including the three CAIR trading programs (SO2, annual NOx, and

ozone seaso n NOx), the Acid Rain trading program, and formerly the NOx SIP Call NOx Budget Program (NBP) trading program. I am in regular contact with emission allowance traders, and I routinely monitor allowance markets and prices. I have been personally involved in monitoring and evaluating emission trading markets for nine
years.

8. Throughout the year, I am involved in and oversee staff efforts to track the implementation of the CAIR trading programs and the Acid Rain trading program. I manage the production of an nual progress reports for these trading programs (and formerly the NOx SIP Call NBP trading program), analyzing and presenting allowance transfer activity including volumes of trades, banking of allowances, emissions and compliance information to evaluate the effectiveness of the programs. I managed the3 production of the Clean Air Interstate Rule, Acid Rain Program, and former NOx Budget Trading Program 2010 Progress Report which is attached to this declaration.

9. This declaration is filed in support of EPA’S Consolidated Opposition to Remaining Motions for Stay Pending Judicial Review of EPA’S Final Transport Rule in the above captioned case.



### The Transport Rule is a Flexible Program that Protects the Health of Millions of Americans

10. The Transport Rule protects the health of millions of Americans by reducing pollution and helping states attain clean air standards. It requires 27 states to significantly improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states. The Transport Rule’s Federal Implementation Plans (FIPs) implement these emission reductions in each state through flexible emissions trading programs.

11. The Transport Rule does not establish any unit

- specific or utility

- specific emission reduction requirements. It does not require specific reductions at any individual unit or any individual plant. Rather, the rule limits the total emissions from covered sources within a state. Individual units are allocated emission allowances and can sell the allowances, use them for compliance, or bank them for future use. A unit’s initial allowance allocation does not constitute a unit

- level “emission budget” or emission limit for that unit. In other words, EPA does not purport that initia l allowance allocations should equal each unit’s emissions under the Transport Rule programs, as the programs’ regulatory structure is explicitly designed to allow individual units to make this determination for themselves.

12. Based on the improvement in air quality that will occur under the Transport Rule and the resulting human health benefits expected, a stay of the rule would immediately forgo human health benefits across every state in the eastern U.S. The reductions of air pollution under the rule will deliver significant human health benefits starting in 2012. Based on EPA’s health impacts assessment modeling of the emission reductions anticipated from the Transport Rule and the resulting improvement in air quality in 2014, we expect this rule to prev ent between 13,000 and 34,000 premature deaths annually. Additionally, the rule will avoid 15,000 non

- fatal heart attacks, 19,000 hospital and emergency department visits, 19,000 cases of acute bronchitis, 400,000 incidences of aggravated asthma, and 1.8 million days when people miss work or school annually.4 The monetized value of all quantified health and welfare benefits of the Transport Rule is estimated to be between $120 billion and $280 billion annually. 1



### Transport Rule Allowance Markets are Already Active

13. Facilities have had direct access to 2012 Transport Rule allowances ever since EPA formally recorded them into designated facility accounts on October 18, 2011. In fact, there has been an active market in Transport Rule allowances since Au gust. Allowance trades occurred even in advance of the allowances themselves being created; this immediate activity in the marketplace underscores the liquidity of the Transport Rule emission markets and undermines the credibility of any compliance plan t hat presumes the absence of any Transport Rule allowance markets throughout the 2012 compliance period. The first trades of Transport Rule allowances on August 30 and 31, 2011 yielded an initial price for SO 2 Group 1 allowances at $2,600 and a price for e ach of annual and

ozone

- season NO x allowances at $3,750. 2 Initial transactions have been followed by further trades and contracts in all of the Transport Rule trading programs.

14. This market is following a common pattern of allowance markets in their intro ductory stages: prices are initially high and then drop rapidly as parties become familiar with the characteristics of the market through repeated iterations of bids, offers, and trades. This pattern has been confirmed by recent market data. In initial a llowance trading activity, observed allowance prices have been steadily decreasing from initial highs. This past month, prices for 2012 allowances have been around $400

- 800 for Group 1 SO 2 , $600

- 800 for Group 2 SO 2 , and $800

- 1800 for both Annual NO x and Ozone Season NO x . 3 These prices are already below or trending toward the projected equilibrium values in EPA’s analysis of the final Transport Rule. 4

15. EPA is confident that markets are developing quickly for all of the Regional Transport allowances. There is precedent for such rapid market development in all of the previous emission trading programs that EPA has implemented, including the Acid Rain Trading Program, the NOx Budget Program, and most recently CAIR, predecessor to the Transport Rule. Th is trading is taking place through a public and private infrastructure

1 U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis (RIA) for the final Transport Rule. Office of Air and Radiation, Washington, DC. June. Available on the Internet at <http://www.epa.gov/airtransport/pdfs/FinalRIA.pdf>.

2 Environmental Finance. First trades complete in repl acement SO2 and NOx market. September 5, 2011. Available on the Internet at <http://www.environmental

- finance.com/news/view/1953>.

3 Estimations are based on calculated as well as bid and ask prices available from subscription services such as Argus Air D aily and BGC Environmental Brokerage Services.

4 U.S. Environmental Protection Agency (U.S. EPA). 2011. Regulatory Impact Analysis (RIA) for the final Transport Rule. Office of Air and Radiation, Washington, DC. June. Available on the Internet at <http://w ww.epa.gov/airtransport/pdfs/FinalRIA.pdf>.5 that has been established and refined during these previous markets and is familiar to the relevant parties. Academic research has widely found that EPA’s allowance markets have result ed in robust trading and significant cost savings.

16. Several allowance transfers have been reported to the EPA, indicating exchange of allowances between sources. Further, on Thursday, November 17, 2011, First Energy held a successful auction of a minimum of a 100,000 SO 2 allowances, 50,000 each from 2012 and 2013 markets, along with an undisclosed amount of annual and ozone season NO x allowances. This auction provided a significant injection of liquidity into the market by a single entity, further indicat ion that a sufficient number of allowances will be available to meet the needs of sources. First Energy noted the auction “demonstrates the effectiveness of the auction process and the liquidity of the CSAPR market.” First Energy is planning to hold anot her auction by April 30, 2012. 5



### The Transport Rule’s State

- Level Emission Reductions are Attainable by 2012 and Offer Significant Flexibility for Individual Sources

17. Many of the stay motions incorrectly describe the Transport Rule requirements and the actual reductions necessary to reach the Transport Rule state budgets by ignoring the most recent emissions data available and thereby obscuring the trend the power sector is already on to comply with the rule by 2012. This section describes the flexi bility inherent in the rule and illustrates the actual differential between current emissions and the level of emissions required under the Transport Rule in each relevant state.

18. As discussed above, the Transport Rule does not establish any unit

- specific or utility

specific emission reduction requirements. Instead, the Transport Rule establishes state budgets and assurance levels, and allows each unit within the state significant flexibility to identify its preferred compliance strategy.

19. Furthermore, EPA specifically quantified 2012 state budgets to reflect only the emission reductions that were feasibly obtainable in the time available for implementation. As explained in the preamble to the final rule, t he Transport Rule state budgets for 2012 do not, i n fact, require any new (unplanned) post

- combustion control installations, relying instead on immediate

- term emission reductions available from optimizatio n of existing control equipment, anticipated reductions from additional control equipment already sla ted for installation by 2012 , and switching to a lower

- emitting fuel mix (76 FR 48280). Coal consumption for electricity generation has declined 6.0% from 2005 to 2010 and the Energy Information Administration (EIA) expects that coal consumption for

5 First Energy. FirstEnergy Successfully Concludes Emission Allowance Auction. Press release. November 18, 2011. Available on the Internet at <http://www.fescsaprauction.info/Portals/0/Documents/News/2011

- 11

- 18%2 0FES%20Successfully%20Concludes%20Emission%20Allowance%20Auction.pdf>.6 elect ricity generation will be lower by 1.6% in 2011 and 6.1% in 2012 as compared to 2010 levels. In contrast, total electricity generation increased by 1.6% from 2005 to 2010 and EIA expects that total electricity generation will be higher by 0.3% in 2011 and lower by 0.1% in 2012 as compared to 2010 levels. The share of electricity generation from coal has fallen from 50% in 2005 to 45% in 2010 and is predicted by EIA to fall to 44% in 2011 and 42% in 2012. 6 Against this forecasted backdrop of lowered coal

- fired generation (which produces the majority of SO 2 and NO X emissions of the power industry) EPA believes that utilities will be able to employ a variety of pollution reduction strategies to comply in 2012 with the Transport Rule.

20. In addition, the stringenc ies of the final rule and the proposal are highly comparable as the projected cost s per ton incurred by participating emitters (the primary cost of the rule faced by covered sources) are highly comparable . The cost thresholds used to develop budg ets for covered states in the final rule were similar to the cost thresholds EPA used to develop the proposal (about $500 per ton on annual NOx, ozone

- season NOx, and Group 2 SO2, and between $2,000

- 2,300 per ton on Group 1 SO2 in the second phase that sta rts in 2014). While this stringency level remained similar between the proposed and final rules, its application to updated calculations of future baseline emissions necessarily yielded lower values for remaining emissions in the state (i.e., state budget s) when subjected to this stringency of control. As such, the state budgets in the final rule are not the result of increases to the stringency of the rule’s requirements but are instead a natural result of a consistent stringency reapplied to improved pr ojections of baseline emissions using updated information provided by
commenters.

Kansas Utilities

21. D ata from the last four quarters for Kansas show that SO2 emissions from covered electric generating units (EGUs) in the state are less than 0.5% above the 2012 state budget. Specifically, emissions data submitted to EPA from EGUs, demonstrates that SO2 emissions from covered EGUs in Kansas was 41,671 tons in the last four quarters. 7

6 Short

- Term Energy Outlook, US EIA, November 8, 2011, http://www.eia.gov/forecasts/steo/index.cfm The state budget is 41,528, or less than 0.5% below current SO2 emissions levels. The state assurance level of 49,003 tons is significantly above current SO2 emission levels.

7 EPA Emissions Data. Available on the Internet at <http:www.camddataandmaps.epa.gov/ gdm>. 2011 emissions are preliminary data submitted to EPA from sources as of November 22, 2011. At this time, preliminary 2011 emissions are available for the first three quarters of 2011. To calculate estimated preliminary
2011 annual emissions , prelim inary emissions from the first three quarters of 2011 are added to emissions from the final quarter of 2010. The preliminary 2011 ozone season NOx emissions referenced in subsequent tables simply uses the preliminary data from the complete 2011 ozone seas on. All included data are available in EPA's Data and Maps http://camddataandmaps.epa.gov/gdm/index.cfm?fuseaction=emissions.wizard). EPA will update data here as it receives and verifies data.7 22. Total emissions from Kansas are also close to the annual NOx budget for the State . In the last four quarters, actual annual NOx emissions were estimated at 45,798 tons. As explained below in this declaration, NOx emissions reductions of about 10,000 tons are expected in Kansas in 2012 irrespective of the Transport Rule to comply with state rules and consent decrees and to complete retrofit proje cts already permitted and in progress. With the achievement of these reductions, Kansas would be expected to emit around 35,500 tons annually or around 5,000 tons above the 2012 state budget of 30,714 tons and below the state assurance level of 36,243 ton s.

Florida Electric Power Coordinating Group, Inc. (FCG)

23. I have read and am familiar with the Florida Electric Power Coordinating Group’s Motion for Stay (date October 14, 2011) and its attached materials including: the FDEP Letter to EPA Director Banis ter dated September 9, 2011, the Written Testimony before House Committee on Science, Space and Technology by Chip Merriam dated September 15, 2011, the FCG Letter to EPA dated September 30, 2011, the FCG Petition for Reconsideration and Stay dated October 6, 2011, the FDEP Petition for Reconsideration and Stay dated Oct. 7, 2011, and the Affidavit of Farzie Shelton dated Oct. 13, 2011.

24. Florida’s 2011 ozone season NOx emissions from units covered by the Transport Rule were roughly 29,712 tons 8 and the Flor ida 2012 budget is 27,825. Thus covered entities in Florida had emissions only 1,887 tons, or about 7%, above the state’s 2012 budget.

25. The assertion in the FCG’s stay motions, that Florida is required to make 79% of the required ozone

- season NOx emission reductions (Motion p. 6) is incorrect. In 2011, total ozone

- season NOx emissions in states covered by the Transport Rule ozone

- season program was about 549,349 tons, 9 while the sum of these states’ 2012 ozone

- season budgets is 495,314 tons. The differe nce between actual 2011 emissions and the 2012 budgets for the region as a whole is roughly 54,000 tons. Based on the table below, the difference between actual 2011 emissions in Florida and the 2012 budget is only 1,887 tons. Thus, Florida is expected t o supply only 3% of the total ozone

- season NOx reductions from recent levels to meet Transport Rule requirements, far less than the 79% number presented in the motion.

8 EPA Emissions Data. Available on the Internet at <http: www.camddataandmaps.epa.gov/gdm>.

9 EPA Emissions Data. Available on the Internet at <http:www.camddataandmaps.epa.gov/gdm>. Note this figure does not include the six states (Iowa, Kansas, Michigan, Missouri, Oklahoma, and Wisconsin) that are being consid ered in the Supplemental Notice of Proposed Rulemaking, published in the Federal Register July 11, 2011.8 2010 and 2011 Ozone

- Season NOx Emissions, Budget, and Assurance Levels for Florida (Tons)

State 2010 Emissions Preliminary
2011 Emissions Final TR 2012 Budget 2012
Assurance Level Proposed Revised 2012 Budget 10

Florida 37,450 29,712 27,825 33,668 28,644

26. The assertion by FCG that Florida has to make 90% of the required ozone

- season NOx emission reductions from states linked to Harris County (Motion p. 6) is also incorrect. FCG’s calculations appear to be based on the incorrect assumption that only 9 state s are linked to Harris County receptors, while in fact 11 states are linked to Harris County. 9 states are linked to nonattainment receptors in Harris County, 7 of these states plus two others are linked to maintenance receptors in Harris County.

27. To ca lculate the total ozone

- season NOx reductions from recent emission levels needed from states linked to Harris County and Florida’s percentage of those reductions, states’ 2011 actual ozone season emissions (not their base case emissions) must be compared with their 2012 budgets. This analysis demonstrates that Florida is not responsible for an outsized proportion of the reductions. The states linked in the final rule to Harris County, Texas are: Alabama, Florida, Georgia, Illinois, Indiana, Kentucky, Lou isiana, Mississippi, Missouri, South Carolina, and Tennessee. Of these states, Alabama, Georgia, South Carolina, and Tennessee had 2011 ozone

- season NOx emissions that were already lower than their 2012 Transport Rule budgets. The remaining states had a
t otal of 187,072 tons of emissions in 2011 11 and combined 2012 budgets of 155,668
tons. 12 (76 FR 48,262

- 3) The difference between these levels is 31,404 tons. The difference between actual 2011 emissions in Florida and the state’s 2012 budgets is only 1,887 tons, as described above. Thus, the rule anticipates that Florida will supply only 6% of the total ozone

- season NOx reductions from recent levels in states linked to Harris County, Texas.

10 As discussed later in this declaration, EPA signed a proposed rule on October 6, 2011, proposing technical adjustments to the Transport Rule (76 Fed. Reg., 63,860; October 14, 2011). The proposed adjustments include recalculation of state emission budget s for certain states. This column shows how the state budget would change if the proposed adjustments are finalized as proposed.

11 EPA Emissions Data. Available on the Internet at <http:www.camddataandmaps.epa.gov/gdm>.

12 Missouri was not included in the se calculation because it does not have a budget under the Transport Rule as finalized because it is being covered under the Supplemental Notice of Proposed Rulemaking, published in the Federal Register July 11, 20119 Entergy

28. I have read and am familiar with the Entergy Motion for Stay (date October 26, 2011) and its exhibits, including: Entergy’s Petition for Reconsideration of CSAPR (October 7, 2011), the October 26, 2011 declaration of Myra H. Glover, the Entergy letter to EPA dated September 29, 2011, the Exhibit B of Kansas Ut ilities’ Motion for Stay of Final Rule, and the Southwest Power Pool Letter to EPA dated September 20, 2011.

29. Entergy’s stay motion misstates the differences between actual emissions and the 2012 state budgets for ozone

- season NOx. As shown in the table be low, 2011 ozone

- season emissions were lower than 2010 ozone

- season emissions in all three states, bringing actual emissions closer to the 2012 budgets.

2010 and 2011 Ozone

- Season NOx Emissions, Budgets, and Assurance Levels for Arkansas, Louisiana, and Mississippi (Tons)

State 2010 Emissions Preliminary 2011 Emissions Final TR
2012 Budget 2012
Assurance Level Proposed Revised 2012 Budget

Arkansas 18,300 17,868 15,037 18,195 15,037

Louisiana 23,218 22,784 13,432 16,253 17,663

Mississippi 16,089 13,394 10,160 12,294 12,296

30. By using data regardin g average emissions between 2008

- 2010, the Entergy motion exaggerates the difference between its current ozone

- season emissions and the number of allowances allocated to its units in 2012. When Entergy’s preliminary 2011 ozone

season emissions data from its facilities in these three states are compared to 2012 the initial allocation to these sources would cover all but approximately 35% of their recent emission levels.

31. Entergy misstates EPA’s intentions w hen it argues that “EPA did not intend to require Entergy States to reduce emissions”. 13

13 On page 14 of their motion, Entergy c laims that “By setting the Entergy States’ budgets at the 2012 base case, EPA did not intend to require the Entergy States to reduce emissions, because the state budgets were based on the IPM’s base case prediction, without the imposition of any further co st

- effective emission reductions.” As explained in the preamble to the final rule, t he state budgets were set based on projected state emissions at a cost threshold of $500 per ton. In the states referen ced by Entergy, EPA’s analysis found that ozone

- season NOx emissions would rise if these states were left out of the Transport Rule programs (effectively facing no cost threshold on the pollutant) while other upwind states were10 subject to the cost threshol d of $500 per ton. EPA therefore determined that those states must also be subject to a cost threshold of $500 per ton in order to eliminate the emissions that would otherwise occur, as those states contributed at least 1% to ozone concentrations at downw ind receptors projected to be in nonattainment of, or to be at risk of failing to maintain attainment of, the 1997 ozone NAAQS. (76 FR 48,263)

. EPA developed the budgets in the Transport Rule to achieve all available emission reductions at that cost thres hold, ( id. ) not to preserve historic level of emissions as the movant suggests

City of Ames, Iowa

32. I have read and am familiar with the October 23, 2011 declaration of Brian Trower, Assistant Director of Electrical Services for the Ames Municipal Electric System.

33. The City of Ames motion misstates the difference between actual emissions from the city’s EGUs and the number of their allocated allowances. Ames’ annual NO x allocation in the final rule, 603 t ons, is only 24% less than the Ames units’ actual emissions for the last four quarters, much less than the 46% difference alleged by the City based on 2006

- 2010 data (Motion p. 14).

34. The use of average emissions data from 2006

- 2010 instead of using recent emissions data , exaggerates the differenc e between actual NOx emissions from the City’s units and the number of their allocated allowances as. Ames’ annual NO x emissions have been steadily decreasing. Actual annual NO x emissions from the Ames units in the last four quarters, 787 tons, are much less than 2006

- 2010 average emissions equaling 1,107
tons.

35. The flexibility of the Transport Rule allows for a variety of compliance options including purchasing allowances. In fact, NOx emissions from covered units in the state of Iowa

are already quite close to the annual NOx state budget and excess allowances are thus likely to be available from in

- state sources . There is only a 4% difference between the 2012 annual NOx bu dget (38,335 tons) and actual annual NOx emissions in Iowa over the last four quarters (39,898 tons). 14

14 EPA Emissions Data. Available on the Internet at <http:www.camddataandmaps.epa.gov/gdm> In addition to a liquid allowance market in Iowa, the City also has the option of purchasing allowances out of state.11 2010 and 2011 A nnual NO x (Tons) Emissions, Budgets, and Assurance Levels for Iowa

2010 Emissions Emissions in Most Recent Four Quarters Final TR 2012 Budget 2012 Assurance Level

45,045 39,898 38,335 45,235

Municipal Electric Authority of Georgia (MEAG)

36. The stay motion by MEAG incorrectly describes the difference between MEAG’s actual SO 2 emissions and the number of SO 2 allowances allocated to it. Based on the last four quarters, MEAG SO 2 emissions have been only 955 tons (or about 9.4%) above MEAG’s 2012 Transport Rule allocations. 15 In addition, MEAG’s units appear likely to continue a long term trend of decreasing emissions, culminating in new controls that are currently being installed on MEAG’s highest emitting plants for operation ahead of 2014.

Wisconsin Electric Power Company (We Energies)

37. We Energies’ stay motion is based upon the assumption that if We Energies purchases sufficient allo wances to allow it to continue emitting at 2010 levels (such as at the Presque Isle Plant), the company will be exposed to assurance penalties in 2012 and 2013 (Motion p. 8). Those penalties , however, would only be assessed if total emissions associated with We En ergies’ designated representative exceed the designated representative’s assurance level, and only if total emissions from Michigan EGUs exceed the state’s assurance level (118% of its budget). 76 Fed. Reg. 48,294

- 96.

38. R ecent emissions data demonstrates t hat total EGU emissions in Michigan are unlikely to exceed the state’s assurance level in 2012. As demonstrated in the table below, total EGU SO 2 emissions in Michigan are well below the 2012 assurance level, and have been trending downwards, see table be low. In addition, total EGU NO x emissions in the state have been experiencing significant declines and 2011 preliminary emissions are already much closer to the state’s 2012 budget than 2010 emissions, see table below. EPA anticipates , and its analysis s upports, that they will be below their annual NOx assurance levels in 2012 due to variety of compliance and emission reductions strategies available to the state. 16 For example, as noted on Detroit Edison’s website and comments on the Transport Rule three of the four units at Monroe are retrofitted with a SCR. 17

15 EPA Emissions Data. Available on the Internet at <http:www.camddataandmaps.epa.gov/gdm> However, the 2010 and 2011 NOx emissions data suggest that only two of these

16 TR_Remedy_Final_State_Emissions. Docket # EPA

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17 Detroit Edison. Emission Controls website. Available on the Internet at <http://www.dteenergy.com/dteEnergyCompany/environment/generation/controls.html>. Also, see Detroit Edison’s comments on the Transport Rule, Doc ket #EPA

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- 2851.12 controlled units (units 3 & 4) were operating the SCR and achieving an emission rate of .08 or lower. The third controlled unit (unit 1) was emitting at a rate similar to unit 2's (the lone uncontrolled unit) emission rate. 18 If Unit 1 begins operating its SCR in a manner similar to the other two Monroe units with a SCR, the unit's emissions, and consequently the st ate's emissions, could be reduced by approximately 5,000 tons. This change alone would bring Michigan’s potential annual NOx emissions below its assurance level and substantially closer to its budget, before any other control strategies or allowance purch ases are implemented.

2010 and 2011 SO 2 (Tons) Emissions, Budgets, and Assurance Levels for Michigan

2010 Emissions Emissions in Most Recent Four Quarters Final TR 2012 Budget 2012 Assurance Level

243,417 233,132 229,303 270,578

2010 and 2011 Annual NO X (Tons) Emissions, Budgets, and Assurance Levels for Michigan

2010 Emissions Emissions in Most Recent Four Quarters Final TR 2012 Budget 2012 Assurance Level Proposed Revised 2012 Budget

80,390 75,462 60,193 71,028 65,421

State of Georgia’s Response in Support of and Notice of Joinder in Kansas’ Stay Motion

39. The State of Georgia’s argument that the Transport Rule analysis is improper because it “zeroed

- out” the capital costs of controls mandated by state rules ignores the fact that EPA determined, even after considering all controls mandated by the rule in 2012, the state was significantly contributing to and/or interfering with maintenance in another state (76 FR 48213, 48240, 48242, 48245, 48257; Technical Support Documen t “Analysis to Quantify Significant Contribution” EPA

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- 4456). EPA took the reductions required by the state rule into account when calculating the state’s base case emissions (i.e., its emissions without CAIR or the Transport Rule) (76 FR 48223, 48224, 48261). If EPA had not done so, it is possible that Georgia’s emissions would have been so high as to link it to downwind receptors requiring greater upwind reductions, potentially subjecting the state to an even greater emission reduction r esponsibility. 19

18 U.S. EPA, Clean Air Markets

- Data and Maps, http://camddataandmaps.epa.gov.

19 In the final Transport Rule modeling, Georgia’s daily PM2.5 contribution to Lancaster, PA (receptor 420710007) was projected to be 0.29 microgra ms/m3, a value approaching the 1 percent threshold of 0.35 micrograms/m3 for consideration of Georgia as a Group 1 state. Without the immediate

- term reductions occurring in response to13 In short, Georgia actually got a head start on eliminating its significant contribution by implementing its state rule and therefore likely has fewer required reductions from the Transport Rule than would otherwise have been the case witho ut Georgia’s state rule.

State of Ohio

40. The final rule’s state budgets , including the state budget for Ohio, factor ed in new data and information provided by commenters on the rule. Among other things EPA received comments from stakeholders indicating that certain units had more reduction capability in 2012 than previously recognized by EPA. These types of comments led to logical updates to the model, which resulted in tighter budgets in some cases.

41. Updates to the modeling for a particular Ohio facil ity, Sammis, provide a n illustration. First Energy comments on the proposed Transport Rule pointed out that FGDs were installed at Sammis units 1

- 5 (coming online in 2010). 20 In EPA’s proposed modeling (completed prior to 2010), it had not recognized and factored in the potential emission reductions from these controls into the sta te’s 2012 SO2 budget determination

. Because EPA had received new and updated information from a covered source during notice and comment, it was logical to update its model to reflect the control status at these units. Once the control status was appropriately updated, the anticipated emissions from these sources in 2012 were 20,000 tons less than what had been assumed for purposes of the proposed budget. These types of very r easonable and obvious, not “arbitrary”, updates to the modeling contributed to tighter budgets in 2012 in the final Transport Rule relative to the p roposed rule.

42. EPA believes significant reductions in EGU emissions from Ohio are already planned and on the way. These reductions come, for example, from controls that were already under construction prior to Transport Rule finalization and scheduled to be completed by 2012, sources operating at previously demonstrated emission rates, scheduled retiremen t s (planned prior to the final Transport Rule, and reduced operation from baseload units (planned prior to and independent of the final Transport Rule). Below, EPA approximates some of the likely and/or possible emission reductions in 2012 that fall into these categories. EPA notes that these calculations are preliminary and could fluctuate for certain units. In particular, for units where it has been decided not to operate them as baseload units, their emissions could still potentially remain significan t depending on how they are dispatched as peaking units. However, the reduction capability from facilities like Kyger Creek, which is completing a FGD project this month are highly likely (see attachment from Ohio Valley Electric Cooperative).

Georgia’s state rule (that EPA included in its base case), Georgia’s e missions may have led its contribution to exceed the 1 percent threshold at that receptor. Group 1 states are subject to more stringent SO2 emission reduction requirements than Group 2, the group that Georgia is in under the final Transport Rule.
20 EPA

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- 265714 Expected or Potential Sources of “O n the W ay” 2012 SO2 Emission Reductions in Ohio * (Tons)

Source of SO2 Emission Reduction Tons of SO2 Reduction

FGD installation at Kyger Creek 21 100,000

Beckjord units 5 & 6 returning to 2008 emission rates 35,000

Discontinuing baseload operation at Eastlake Units 1

- 4 16 ,000

Retirement of Richard Gorsuch facility 16,000

Reduced emissions at Burger facility due to Consent Decree 5 ,000

Reduction from year round operation of Sammis FGD 10,000

Announced reduced operation at Bay S hore Facility due to reduced demand 7,000

Announced reduced operation at Ashtabula Facility due to reduced demand 22 5,000

*Reductions from 2010 emission levels

43. These types of “on the way” reductions will facilitate compliance with 2012 state budgets an d assurance levels for Ohio. For instance, Ohio’s 2010 SO2 Emissions were 572,000 tons, its 2012 budget is 310,000, its 2012 SO2 assurance level is approximately 366,000 tons. 23 Therefore, the state’s 2010 SO2 emissions were 206,000 tons above its 2012 assurance level and approximately 262,000 tons above its 2012 budget. The “on the way” reduction potential listed above will deliver significant progress towards 2012 assurance l evels and budget levels for the state even before considering additional reduction opportunities through fuel switching, generation shifting, running existing controls more aggressively, allowance purchases and other compliance options at the remaining Ohi o facilities are considered.

21 See attachment. Ohio Valley Electric Corporation Kyger Creek Station Amended New Stack and FGD System Notification. October 25, 2011.

22 “First Energy Generation Corp. Announces Plans to Reduce Operations at Smaller Plants” Fi rst Energy, News Release. August 12, 2010. Retrieved at http://investors.firstenergycorp.com/phoenix.zhtml?c=102230&p=irol

newsArticle&ID=1459646&highlight= 23 U.S. EPA, Clean Air Markets

- Data and Maps, http://camddataandmaps.epa.gov.15 

### EPA’s Integrated Planning Model (IPM) 24 

### was Fully Reviewed and Carefully Applied to the Transport Rule

44. IPM is an economic model used to determine the least

- cost method of generating electricity. It forecasts how the power sector produces electricity at least cost while meeting energy demands, reliability constraints, and environmental requirements. It is a hi ghly focused, peer

- reviewed, and publicly

- reviewed tool that is populated with high

quality real

- world data to project the impacts of power sector regulations. IPM was developed as a tool for this purpose because historic operation data by itself is insuff icient to project either the impact of or the need for future regulations.

45. IPM incorporates and relies on real data including unit heat rates, emission rates, control configurations, coal and natural gas availabilities and costs, units currently under

con struction, planned retirements, announced installation of controls, and myriad state

level environmental regulations.

46. IPM incorporates factors that affect the trend of future EGU emissions, including announced unit retirements and controls that are planne d to come online in response to consent decrees, agreements, or state regulations. By design it takes into account factors that may affect future EGU emissions and thus its project ion s may be expected to, and in fact frequently do, differ from historicall y observed outcomes.

47. EPA’s use of IPM during the TR Proposal to develop 2012 and 2014 state emission budgets received strong support from many commenters. For example, Entergy, supported the use of IPM in their comments, writing in its comments “Enterg y supports the IPM results to determine state budgets,” qualified only by a qualification on natural gas prices (which EPA subsequently adjusted). 25 Furthermore, Entergy comments indicated it was aware of how IPM represented transmission and local transmiss ion constraints, 26 but wrote that these limitations would have “limited impact for state

- level modeling results ”.

24 IPM is a multi

- regional, dynamic, deterministic linear programming model of the U.S. electric power sector. Full documentation of the model is available on EPA’s website ( www

. epa

. gov / airmarkets / progsregs / epa

ipm / transport

. htm l ).
25 This directly conflicts with the critiques that Entergy makes in their motion, particularly because their comments indicated they were fully aware of how IPM represented voltage support requirements and local constraints. This is addressed in more de tail later in this section.
26 “Transmission

- related issues inherent to IPM’s regional models include missing intraregional load pockets, voltage support, ancillary services, local requirements, etc. These limitations are further exacerbated by the limited number of regions in EPA’s IPM, resulting in the premature reduced generation from oil/gas steam units” (Comment submitted by Joseph Hantz, Entergy Services on October 1, 2010. Document ID: EPA

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- 2847)16 48. Although some aspects of the model were updated as identified in the September 1, 2010 NODA (discussed below), numerous other aspects of IPM, including the manner in which it considers transmission constraints, voltage support requirements, load pockets

an d other reliability rules imposed on transmission systems, were not altered or modified in any significant way 27 between the version of IPM used for the proposal modeling and the version used for the final rule modeling. EPA continued to use the most suppo rtable set of assumptions in IPM for this purpose

.

49. EPA provided opportunity for public comment on IPM when we proposed the Transport Rule in 2010

-- making the model inputs, outputs, and documentation available to the public

-- and received and addressed extensive comments on the model. EPA also published a notice of data availability (“IPM NODA”) on September 1, 2010 (75 FR 53613) that provided the opportunity to comment on, among other things, an updated version of IPM that EPA indicated we planned to use in the final rule. The updated model version available for comment in the IPM NODA included updated unit

- level input data and a set of model run results with the updated modeling platform, detailed documentation of the updated version of the model, an d user guides to input assumptions and model outputs. EPA regularly updates IPM to reflect the best available data because that forms the best basis for decision making. The IPM NODA also included a list of further planned updates to support the final ru lemaking. EPA received and addressed extensive public comments on the IPM NODA. EPA stated in the IPM NODA that changes in emission projections from an updated model could impact the final rule in a number of ways including changing the cost and emission projections used in the determination of the amount of emissions that represent significant contribution in each state (in other words, used in determining the state emission budgets) (75 FR 53614).

50. EPA has used IPM to support its understanding of the e conomic and emissions impacts of air regulations on the power sector for two decades. EPA uses the best available information from utilities, industry experts, gas and coal market experts, financial institutions, and government statistics as the basis for the detailed power sector modeling in IPM. 28

27 Two small changes related to these is sues were made to IPM between the proposal and final rules. These are: 1) representing Canada endogenously rather than exogenously in the model and 2) updating the reserve margins in each region to more recent data, though notably the reserve margin for th e Entergy region did not change. The model’s projected emissions are a reasonable expectation of what a state’s EGUs can be expected to emit at certain cost levels and therefore a

28 EPA used IPM to project future power sector emissions in the base case (i.e., without the Transport Rule) and with the rule. IPM projections of base case power sector emissions

-- along with emission from other (non

- EGU ) emission sources

-- are inputs to the air quality modeling which identified downwind nonattainment and/or maintenance receptors and linkages to upwind states. EPA also used IPM to analyze power sector cost impacts of the rule.17 reliable basis for informing the level of state emission budget s in the Transport Rule

. 29 , 30

51. IPM undergoes periodic formal peer review, which includes participation by independent expert panels on the model itself, and EPA’s key modeling input assumptions. For example, over the past ten years several separate panels of independent experts have been convened to review IPM’s coal supply and transportation assumptions, natural gas assumptions, and model formulation. The rulemaking process also provides opportunity for expert review and comment by a variety of stakehold ers, including owners and operators of the electricity sector that is represented by the model, public interest groups, and developers of other U.S. electricity sector models. The feedback that the Agency receives provides a highly detailed reality check of key input assumptions, model representation, and modeling results.

52. IPM includes 32 power regions with detailed representation of the inter

- regional transmission system and reflects the regional aspects of natural gas and coal markets. IPM projects a cost

- effective compliance pattern at the state and regional level subject to regional reserve margin constraints. IPM relies on NERC reference reserve margins as the basis for these requirements. These margins incorporate the studies performed by each NE RC region or subregion to ensure that regional resource adequacy meets N

- 1 (or more stringent where applicable) contingency conditions and loss of load requirements. By using these reserve margins and limiting transmission between regions, IPM ensures tha t projections are consistent with regional resource adequacy.

29 “IPM is a least cost mod el with perfect foresight. As commenters noted, projections from this approach may vary from actual future values at particular sources as the model may not capture non

- economic variables. Furthermore, IPM does not purport to be 100% accurate when projecti ng future operations at the source

- level. The projections are reasonable approximations of what sources can be expected to do under typical economic constraints. However, there are inherent differences between predicted value and actual future values in an y predictive model” Transport Rule IPM Assumptions Response to Comment document (EPA

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30 “EPA believes that it is reasonable to use IPM for determining state budgets. While there is significant potential variation at the unit level wh ich commenters highlighted and served as part of EPA's rationale for finalizing a different allocation methodology, this variation is diminished and/or eliminated as unit level data is aggregated to get the state totals. That is, potential variation betwee n projected results and observed results is reduced as data is aggregated. The well documented law of large numbers theorem indicates that the average results from a trial or sample will more closely approximate the actual value as the number of trials or samples increases. While the unit level projection constitutes a sample or trial of just 1, the average # of modeled units within a Transport Rule state is approximately 370. Because of the large number of units (e.g., samples) that comprise the state leve l total, the average variation at the state level is significantly less than it is at the unit level.” Transport Rule Primary Response to Comments document, p. 2108 (EPA

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- 4513).18 

### Maintaining Electric Reliability

53. In order to maintain compatibility with reliable operation of the existing grid, EPA’s IPM projections for the Transport Rule explicitly take into account detailed regional constraints on electricity transmission, informed by planning studies conducted by the North American Electric Reliability Corporation (NERC), an entity that is federally mandated to ensure electric system reliability. IPM transmission l imits are based on average hourly transmission capacities applicable to separate time periods representing different system load conditions throughout the year, in each of IPM’s 32 modeling regions. IPM’s transmission limits include both non

- simultaneous limits between regions and simultaneous transfer limits between multiple regions, such that IPM’s least

- cost dispatch solution remains subject to a reasonable representation of the existing grid’s ability to conduct interregional transmission. 31

54. IPM’s 32 modeling regions are constructed to capture, directly within the model, significant limitations of the existing grid to deliver least

- cost electricity under various scenarios; EPA recognizes, that smaller

- scale limitations may exist that affect the ability of specific individual units to dispatch in a least

- cost manner. Such local, unit

- specific transmission limitations are rarely published for public consumption, but where EPA can obtain adequate information documenting any particular unit’s required disp atch pattern pertinent to meeting operational constraints of the grid, EPA can make adjustments to its power sector modeling projections to complement the ability of IPM to project least

- cost dispatch. 32

55. In developing the final rule, EPA considered comment s arguing that IPM’s structural limitation in addressing unit

- level transmission detail meant that EPA should not base unit

- level allowance allocation s on IPM unit

- level projections . In response to these comments, EPA based final unit

- level allowance allo cations not on IPM projections, but instead on a combination of historic heat input and historic emissions data. (76 FR 48,284

- 48,290.) These historic data necessarily reflect specific unit

- level behavior that may be driven by local transmission constrain ts and other operational needs of the grid, meaning that unit

- level allowance allocations under the final Transport Rule reflect the historic response of these units to maintain electric reliability.

56. As explained above, EPA did not use IPM modeling to det ermine any unit

- specific regulatory treatment under the final Transport Rule, so a unit

- specific projection from IPM could not negatively impact any given unit’s ability to meet any electric reliability

31 See IPM documentation (docket #EPA

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- 0309), S ection 3.3.1 Inter

- regional Transmission Capability.
32 For example, EPA recently received such detailed unit

- specific information from certain unit operators and grid operators, submitted after the final Transport Rule was issued; that information supporte d a limited set of proposed technical revisions to assist the implementation of the Transport Rule programs (76 FR 63860).19 obligations it may have. IPM project s a cost

- effecti ve compliance pattern at the state and regional level subject to regional reserve margin constraints. U nits have the flexibility under the Transport Rule to adjust operations to meet local reliability needs and are in no way constrained by their particular unit

- level IPM projections

.

57. During development of the rule, EPA analyzed impacts of the rule on electric reliability and summarized the results of the analysis in a technical support document entitled “Resource Adequacy and Reliability in the I PM Projections for the Transport Rule” (docket ID # EPA

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- 4455). EPA found that the rule will not impair the ability of the electric system regions to meet their electric reliability objectives. As part of the recently released 2011 Long T erm Reliability Assessment, NERC included the results of a study of the reliability impacts of EPA rules. This study projected the impact on resource adequacy and reserve margins for the combined impact of the Transport Rule and three proposed rules (MA TS, 316b and CCR) for two cases (Moderate and Strict) and three years (2013, 2015 and 2018). The study is best considered a stress test of potential impact of EPA rules on reliability: even the Moderate Case is based on worst case assumptions of complianc e requirements and costs, and assumes that no new generation is built in response to any potential impacts from EPA rules. The impact of the EPA rules on regional reserve margins is presented only for the combined impact of all EPA rules; as a result onl y the results for 2013 are directly applicable to the Transport Rule, since results for later years include additional impact from other proposed rules. Even the results for 2013 are overstated, since the study assumed some early compliance impact from ru les with later compliance dates. In spite of these worst case assumptions NERC found no impacts on reserve margins in 2013 from the Transport Rule in the Moderate Case ; in the strict case all regions but one remained significantly above their required res erve margins and the remaining region fell less than a 0.1 percent below. 33 These results confirm the findings that EPA reached through careful study of the impact of the rule on resource adequacy

.
Reliability in the SPP Region

58. The Southwest Power Pool (SPP) analysis of electric reliability suffers from a fatally flawed representation of the Transport Rule that has no bearing on how units will actually operate in 2012 to be in compliance with the Transport Rule while meeting othe r operational needs of the grid. SPP based its analysis on the assumption that, if a unit is shown to consume zero fuel in an EPA IPM modeling run in 2012, the unit will not be available for dispatch to meet reliability needs. Specifically, the SPP lette r states that, to conduct its analysis, it “removed all generation units in its models that consumed zero fuel in the EPA models.” (Kansas Utilities Exhibit A and Entergy Exhibit 5, p.1 fn.2) . T here is no basis for SPP’s assumption that th ese units will not be available. · IPM modeling projects all units in SPP to be available in 2012, the model’s predictions of

33 November 2011 Long Term Reliability Assessment, P. 153. The one region with a change in the strict case was the Texas Reliability Entity (TRE), also known as ERCOT.20 each unit’s economic operations are simply not germane to the question of whether a unit will continue to be available for occasional dis patch to meet reliability needs. IPM modeling does not purport to project how frequently a unit will be available to run following promulgation of the Transport Rule. Instead, it is an economic model which predicts whether a unit would be economic to run . The general accuracy of IPM projections for these types of units is confirmed by the fact that half of the units in the EPA emissions data that are projected to consume zero fuel in IPM ran less than five percent of the time in 2010 34

.

59. The SPP analysi s departs from standard approaches to assessing reliability impacts by removing, as inputs to the model, units that are projected to be uneconomic to run even though the units were projected to be available to run. T he SPP analysis bases its inputs

on data that have no relevance to the question purportedly addressed by the analysis, which is whether units will be available for potential operation to ensure reliability in SPP following promulgation of the Transport Rule. T he fact that a unit is shown i n an IPM modeling run as consuming zero fuel has no impact on whether that unit will be available to run in any given time period. Furthermore, the Transport Rule does not require any particular unit to shut down, nor does the rule constrain emissions at any particular unit to its initial allowance allocation. While EPA’s modeling includes projections of unit

- level dispatch consistent with the determination of a least

- cost solution for meeting electricity demand on a regional level, EPA has not used these unit

level dispatch projections to set any unit

- specific regulatory requirements under the Transport Rule. There is no basis for SPP’s assumption that units shown as consuming zero fuel in an EPA model run will suddenly not be available to ensure grid rel iability.

60. The September 30, 2011 letter from SPP also states that after removing all generation units which the IPM model showed consumed zero fuel “no other SPP model adjustments were made.” (SPP letter at p.1 fn.2). This statement suggests that SPP

m ight have assumed that no other changes in the system would occur if the units identified were assumed to be unavailable. If true, this is another major flaw in the SPP analysis because the removal of units from service necessarily impacts other units in the same grid resulting in system changes. It would not be reasonable to assume no such changes would occur. If true, this assumption would further distort the SPP analysis such that its results cannot be expected to reflect realistic operating condition s because this assumption would not allow existing grid resources to compensate for any units that SPP assumed would be unavailable in its analysis.

34 Of the 78 units with zero fuel in the 2012 IPM projected that could be identified in the EPA emissions data, 39 units had a capacity factors below 5% in 2010. Data available on the Internet at <http:www.camddataandma ps.epa.gov/gdm>.21 61. I have reviewed the September 30, 2011 letter from SPP and conclude that it does not provide any basis for the conclusion that the Transport Rule will cause reliability problems in SPP. For the reasons given above, I believe the conclusions in the September 30, 2011 letter are all based on fundamentally flawed assumptions and that the SPP analysis misused da ta provided by EPA. In sum, I do not believe the conclusions in that letter shed any light on reliability issues in SPP following promulgation of the Transport Rule.

Entergy

62. EPA’s modeling results for the Transport Rule are fully compatible with the in terregional transmission limitations presented in Entergy’s motion (Glover Declaration Attachment 1, p 3). Entergy indicates a total of 10,590 MW of transfer limits with neighboring regions. The EPA analysis assumed that only an average of 2,428 MW of th is total import capacity would be used in 2012. 35 Therefore, EPA’s projections fall well within the limitations Entergy cites.

63. Also contrary to Entergy’s critique, EPA’s modeling of the Transport Rule also consider ed simultaneous transfer capability from combinations of regions into Entergy. EPA’s modeling assumptions regarding simultaneous transfer capabilities are clearly displayed in the IPM documentation, and the results from the Transport Rule modeling are consi stent with these interregional transmission limitations. 36

City of Ames, Iowa

64. The City of Ames motion’s arguments about transmission limitations are not consistent with the data provided in its own attached Trower declaration. The motion suggests the city can import very little power, but the declaration suggests it can import between 53 MW in the summer to 71 MW in the winter (para 11)

– 54% and 72% respectively of the combined capacity of the MW Ames two

- boiler EGU plant, which Ames says has a capacity of 98 MW (para 9). Ames also has two peaking plants (another 45 MW of capacity), one of which is not subject to the Transport Rule. T here is nothing to suggest that Am es will not be able to meet peak summer demand s as high as 128 MW by some combination of purchasing allowances to support additional generation or importing power from the Midwest Independent System Transmission Operator (MISO).

35 In the IPM projections for 2012, the Entergy region annual load was 153,007 GWh and total annual generation in the Entergy region was 131,734 GWh. The net total annual transmission into the Entergy regions is the difference between the load and the generation and was therefore 21,273 GWh in 2012 for an hourly average of 2,428 MW per hour over the 8,760 hours in the year.
36 For example, EPA assumed that the Entergy region could import only 1,362 MW simultaneously from the SPPN and SPPS r egions, which is lower than the aggregate importation capacity assumed between Entergy and each of those two regions (1,800 MW and 850 MW respectively, for a total of 2,650 MW). Tables 3

- 4 and 3

- 5, http :// www

. epa

. gov / airmarkets / progsregs / epa

- ipm / docs / v 410/ Chapter 3. pdf

.22 State of Alabama, Mississi ppi Public Service Commission and City of Springfield, Illinois, Office of Public Utilities Response in Support of and Notice of Joinder in Kansas’ Stay Motion

65. I have read the Response from the State of Alabama, the Mississippi Public Service Commission ( MPSC), and the City of Springfield, Illinois, Office of Public Utilities (filed Oct. 31, 2011) as well as the attached exhibits (including Exhibit 2 from the MPSC Motion, dated Oct. 5, 2011). The MPSC argument that IPM results for specific units are incom patible with reliable operation of the grid (MPSC Motion Exhibit 2, p.13

- 17) misconstrues EPA’s application of IPM. The Transport Rule does not set any unit

- specific requirements based on unit

- level IPM results, and therefore it is improper to assume that units are constrained by the rule to operate in 2012 at the level of their IPM projections.

Kansas Utilities

66. T he region which includes Kansas has a large reserve margin of available capacity that provides a key buffer to manage electric reliability concerns. EPA’s analysis of the Transport Rule projected that the NERC region containing Kansas, the Southwest Power Pool (SPP) , would maintain a 31.5% r eserve margin in 2014 under the rule, which is far in excess of that region’s reliability planning target reserve margin of 13.6%. 37 This analysis is based on EPA’s modeling representation of the existing fleet, as shown in the detailed unit

- level NEEDS da tabase was subjected to public comment at proposal and in the rule’s IPM NODA. If instead, EPA were to base that analysis range of anticipated reserve margins projected by NERC with the Transport Rule in place, 23.6% in a strict case and 25.5% in a modera te case 38

37 The NERC SPP region in IPM is the combined region consisting of SPPN and SPPS in IPM. In the 2014 IPM projections, SPPN has capacity of 16,374 MW and a projected margin of 75.2% for available reserves of 6,785 MW. SPPS has capacity of 31,900 MW and a margin of 19.2% for available reserves of 6,090 MW. Therefore, the combined SPP region has a total of 54,364 MW and reserves of 12,875 MW for a margin of 31.5%. See Technical Support Document for the final Transport Rule, Docket ID No. EPA

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- 04 91, Resource Adequacy and Reliability in the IPM projections for the Transport Rule, June 2011. , there would still be at least 10% excess reserves above the reference level of 13.6%. The modeling presented by Kansas Utilities not only ignores this large buffer, but assumes from the outset that the companies will not be able to acquire any a dditional allowances, that fuel switchi ng is not an option, and that they will not be able to purchase any power from the grid. All three of these assumptions are incorrect. As discussed above, allowance trading is already underway and the markets are be coming increasingly liquid. Finally, Westar references SPP’s flawed study, described above, to assert a transmission

- limited inability to import even a single electron under any condition beyond historic levels.

38 2011 Long

- Term Reliability Assessment, North American Electric Reliability Corporation, November 2011, p. 153.23 Florida Electric Power Coordinating Group, Inc. (FCG)

67. EPA’s analysis for the Transport Rule found that only about 1% of national generation capacity may retire by 2014 in response to the rule, and that such a limited loss in capacity would not threaten any of the regional target reserve mar gins approved by the North American Electric Reliability Corporation (NERC ) [ Resource Adequacy and Reliability in the IPM Project ions for the Transport Rule TSD, Document ID: EPA

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- 4399]. Furthermore, EPA’s analysis shows the Florida Reliabi lity Coordinating Council (FRCC), which covers most of Florida, having a reserve margin of 22.2% in 2014, well above the FRCC required level of 19.3%, [ id. 7 ] and none of the 2014 retirements that EPA projected would occur in the FRCC grid region. [ id. 8 ]



### Factually Incorrect Assertions in Motions and Responses

American Electric Power (AEP) Response in Support of Louisiana’s Motion for a Stay

68. I have read and am familiar with AEP’s Response in Support of Louisiana’s Motion for a Stay, or, in the Alternative, for Expedited Review. I have also read and am familiar with AEP’s Request for Reconsideration and Stay of the Transport Rule which is attached to AEP’s Response in Support of Louisiana’s Stay Motion as Exhibit A.

69. EPA’s IPM modeling, which su pported the Transport Rule analysis, already projects consumption of low

- sulfur coal in 2012 (415 million tons) to be lower than production of low

- sulfur coal in 2010 (423 million tons). AEP ’s assertion that EPA wrongly assumed that mines supplying very l ow sulfur coal could increase output quickly is incorrect. EPA’s Transport Rule modeling projects lower use of low

- sulfur coal in 2012 compared to 2010 production. Low sulfur sub

- bituminous coal can be further subdivided into relatively “lower” low sulfu r coal (sulfur content below 0.08 lbs/mmBtu) and relatively “higher” low sulfur coal (sulfur content above 0.08 lbs/mmBtu). EIA data from 2010 demonstrates that U.S. production of low sulfur sub

- bituminous coal is skewed toward production of coal in the f ormer category. EIA data demonstrates that 339 million tons of “lower” low sulfur sub

- bituminous coal with sulfur content lower than 0.08 lbs/mmBtu were produced in 2010, and 84 million tons of “higher” low

- sulfur sub

bituminous coal with sulfur content higher than 0.08 lbs/mmBtu were produced in that same year. The coal supply curves that are implemented in EPA modeling were reviewed independently by industry experts and were available for two rounds of public review during the Transport Rule developmen t process in 2010.

70. EPA does not believe existing fuel contracts pose barriers to Transport Rule compliance for several reasons. First, the utility sector purchases 20% of its fuel from spot24 markets, 39 and 97% of new fuel contracts are short term (less t han 5 y ea rs). 40 Also, the electric power sector manages fuel contracts through a tiered (or layered) structure that does not lock in the total fuel portfolio at a given unit for long periods of time (as various portions of that portfolio come up for contra ct renewal at frequent intervals). Utilities therefore have a large degree of existing flexibility in year

- to

- year fuel selection decisions even under existing contracts. Secondly, units have the flexibility to determine what proportion of fuel blending i s economic in response to the Transport Rule’s state emission budgets, which does not prescribe a specific degree of fuel switching at any specific unit. In addition, the Transport Rule’s program structure offers the flexibility to purchase allowances as an interim measure if a utility desires extra time to negotiate a transition to new fuel contracts. (Transport Rule Engineering Feasibility Response to Comments document; EPA

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. )

71. EPA’s IPM modeling allows a limited amount of biomass c o

- firing in coal power plants as an economic decision, which is consistent with recent industry trends and practices. EPA’s IPM modeling incorporates a set of geographically differentiated biomass supply curves, which reflect a real

- world fuel choice like any other. The modeling includes limits on the amount of biomass that can be co

- fired to 10% (or 50 MW), and applies additional costs associated with some modest engineering conversions and upgrades that would need to be undertaken. Overall, biomass co

- firing represents a very small percentage of fuel use in EPA projections, and EPA seeks to reflect the full array of fuel options available to sources based on technical considerations, availability, and economics. For example, biomass represents roughly 1% of total generation from coal plants in both the base case and the remedy scenario. The levels of biomass burned are very small and the projections for this fuel do not materially impact EPA modeling of the power sector used to support the Transport Ru le.

72. As discussed above, EPA determined the 2012 Transport Rule state budgets to reflect only the emission reductions that are feasible to obtain in the time available for implementation; the state budgets for 2012 do not require any new (unplanned) post

combustion control installations (76 FR 48280

- 48281). EPA does not anticipate any advanced post

- combustion controls

-- including DSI

-- to be installed in response to the Transport Rule in 2012. Further, the Transport Rule does not require specific unit

- level level controls and there are no requirements to install LNB by 2012. The only states in the final Transport Rule expected to achieve a significant amount of reduction from installation/upgrade of LNB are Kansas and Nebraska. The major NOx emitter s in these states are already in the process (prior to Transport Rule finalization) of installing LNB and reducing emissions because of consent decrees and/or state rules. Even if it is impossible for remaining sources to install LNB by early 2012 (a prem ise that EPA disagrees with), covered sources in the states would still be able to comply with the Transport Rule through already scheduled reductions and control installations. AEP’s

39 EIA Quarterly Coal Report Oct

- Dec 2010”; http ://www.eia.gov/cneaf/coal/quarterly/qcr_sum.pdf

40 EIA “Coal Transportation: Rates and Trends”; http://www.eia.gov/cneaf/coal/page/trans/ratesntrends.html25 claims regarding the feasibility of installing FGD by 2014 are not rele vant to a decision whether to stay the Transport Rule in 2012. In any case, for the reasons discussed in the preamble to the final rule (76 FR 48281

- 48283), EPA believes that FGD installation is feasible by 2014.

Florida Electric Power Coordinating Group , Inc.

73. FCG incorrectly c haracterizes EPA’s statements in the Transport Rule proposal when it
states that EPA said in the proposal that it would not use IPM modeling to determine state budgets. In fact, EPA used IPM to develop both 2012 and 2014 budgets i n the proposal. I n the proposal, EPA explained that it would develop state budgets based on a combination of historical heat input, historical emissions rates, and, projected emissions rates for new SCR units expected between then and 2012 (75 Fed. Reg. a t 45,291). I t used IPM both to identify 2012 base case emissions (75 Fed. Reg. at 45,243) and, in some cases, to calculate the emissions remaining in each state after all emission reductions available at the appropriate cost thresholds were implemented (7 5 Fed. Reg. at 45,290). EPA provided an opportunity to comment on this methodology which was used in the final rule to develop all state budgets. EPA received myriad comments on how to best apply the use of cost thresholds to determining state budgets (Tr ansport Rule Primary Response to Comments, Section IV.E. Document ID: EPA

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- 4513) and used a method i t determined was most consistent with the goals of the Transport Rule. (76 Fed. Reg. at 48,260

- 48,261).

74. FCG ’s claim (Motion p. 12) that EPA projected Florida’s heat

- input level in 2012 to be approximately 13% below 2010 levels is incorrect for two reasons. First, FCG’s calculations only include units covered by the Transport Rule, while electric generation in the state can be met by both units covered by the Transport Rule and other sources, including nuclear, renewable and other generators not covered by the Transport Rule.

75. Second, electricity generated, not heat input, is the most appropriate metric for determining if IPM projected eno ugh generation to meet Florida's needs. Data from the Energy Information Administration (EIA) demonstrates that Florida's 2010 ozone

- season generation from all sources was roughly 108 TWh. 41 The IPM runs used for the Transport Rule projected 2012 ozone

- sea son generation in Florida to be 105 TWh, 42 only 3% lower than 2010 electricity generation, not the 13% lower that FCG cited.

41 Calculated from “2010: EIA

- 923 January

- December, Final, Generation and Fuel Data and Nonutility En ergy Balance.” http ://38.96.246.204/ cneaf / electricity / page / eia 906_920. html Accessed November 30, 2011.

42 Calculated from file TR_Remedy_Final.CAR, located in the DC Docket Center. Document ID: EPA

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- 4508, or on the IPM Analysis for the Transport Rule website <http://www.epa.gov/airmarkets/progsregs/epa

- ipm/transport.html>26 76. FCG claims that IPM is flawed because it has a smaller load growth rate for the FRCC grid region than that projected by Florida Reliability Coordinating Council (FRCC). The IPM load growth is derived from data from the EIA, an authoritative source within the energy modeling community. The EIA data incorporates assumptions about short

- and long

term growth and macroeconomics, yielding a growth rate that evolves over time to reflect economic recovery and growth. The FRCC projection assumes a relatively constant electricity growth rate over the next ten years. In the long

- term, the growt h rates projected by IPM and FRCC are relatively similar.

Municipal Electric Authority of Georgia (MEAG)

77. I have read and am familiar with the October 14, 2011 declaration of Steven Mark Jackson, Vice

- President of Power Supply at the Municipal Electric Authority of Georgia (MEAG).

78. MEAG’s claim that the Transport Rule did not account for MEAG’s compliance with the Georgia Multipollutant Law (Ga. Comp. R. & Regs 391

- 3

- 1

- .02(2)(sss)) is incorrect. The controls required for compl iance under the Multipollut ant L aw were included in EPA’s IPM base case. 43 The method of integrating the Georgia law into the cost analysis for the Transport Rule is specifically described in the preamble of the final Transport Rule (76 FR 48261). Contrary to MEAG’s assertions, the municipal utility got an early start eliminating its significant contribution by complying with its state rule and should have fewer required reductions under the Transport Rule than they would have faced without Georgia’s rule.

79. MEAG ’s motion misconstrues the Rule’s SO2 $500/ton cost threshold as a binding cap on the cost of potential compliance options. This threshold was not used in any way to define units of utility

- specific compliance requirements. The threshold was developed as part of a multi

- facto r approach to estimate a cost per ton at which air quality impacts in downwind states noticeably changed. EPA determined that the downwind problems at receptors linked to Georgia for PM2.5 were resolved when all reductions from covered EGUs in the state a vailable at the $500 cost threshold were implemented. The threshold was used to determine state

- level reduction requirements, not to establish utility specific caps on potential compliance costs. EPA did not identify the SO2 reductions each individual fa cility can make for $500/ton and require the utility to reduce its emissions by that precise amount. Whether a particular utility can reduce SO2 emissions at $500/ton or not does not alter its obligation to hold allowances sufficient to cover emissions. ( 76 FR 48249) In fact, the preamble details how Georgia’s 2014 budget decreases, though the $500/ton cost threshold is held constant, because of the impacts of reductions from the Georgia Multi

- pollutant Law. (76 FR 48261)

43 EPA. Documentation Supplement for EPA Base Case, EPA

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- 4385, p. 69.27 80. Further, the Transport Rule prov ides flexibility in compliance options. Covered EGUs may choose to comply using methods that costs less or more than $500 per ton. The actual cost of compliance to a particular utility may be influenced by numerous factors including: the compliance opti on selected by the utility, the number of allowances allocated to the utility’s sources, the distributions of emissions across a utility’s sources and any of a variety of other factors outside the rule that affect resource planning.

81. MEAG’s estimate of com pliance costs are also flawed because it is premised on the assumption that no allowances will be available for purchase. The section above on the Transport Rule’s market formation contradicts this assumption, and demonstrates that markets for emissions a re developing.

Southern Company Services et al. Response in Support of Responses and Joinder in Kansas’ Stay Motion Filed by Alabama, Georgia, and Mississippi

82. I have read and am familiar with the response of Southern Company in support of responses and joinder by the State of Alabama, the Mississippi Public Service Commission and City of Springfield, Illinois, Office of Public Utilities in the State of Kansas’ Motion for Stay of the Transport Rule and the response and joinder by the State of Georgia, wh ich states that overall emission reductions and air quality improvements will be similar under either CAIR or the Transport Rule. I have concluded that t he assessment performed by Southern Company contains several fatal flaws that invalidate the company’s conclusions.

83. Southern Company’s assertion that overall emission reductions and air quality improvements will be similar under either the Clean Air Interstate Rule (CAIR) or the Transport Rule is based on incorrect and misleading “emissions” data and the use of outdated models. Southern Company states, “as demonstrated in Table 4 below, CAIR and [the Transport Rule] achieve similar total EGU emission reductions across the thirty

state eastern US area subject to the rules.” However, Table 4 depicts emission budgets under CAIR and the Transport Rule , not actual emissions. Emission budgets defined by CAIR and the Trans port Rule do not necessarily determine actual emissions levels, particularly for CAIR. This is incorrect for CAIR because it does not account for the large bank of SO2 and NOx allowances that would be available for use by sources under CAIR in 2012. As d escribed below, after completing allowance deductions for 2010 compliance with the ARP and CAIR, EPA found that over 15 million SO2 allowances and over 400,000 NOx allowances were banked and carried forward to the 2011 compliance
year. 44

44 Clean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report; available online at The availability o f banked allowances for compliance under CAIR means that sources within any state can emit levels that exceed that state’s budget. Because there

http :// www

. epa

. gov / airmarkets / progress / ARPCAIR 10_01. html

.28 are so many banked allowances available, if banked allowances are only useful for CAIR compliance for 2012 or 2012 and 2013, then the supply of available allowances would vastly exceed demand for allowances, allowances prices would drop to near zero, and CAIR would not constrain covered sources emissions during those periods.

84. Southern Company also uses EPA’s Air Quality Assessment Tool (AQAT) for the Proposed Rule to assess the air quality results of “ emissions” under CAIR and the Transport Rule, concluding that they have nearly identical results. T his assessment relies on budgets and not projected emissions, the reby ignoring the excess banked allowances that would be available to sources to avoid reducing emissions under CAIR. As Southern Company explained, “CAIR and CSAPR [the Transport Rule] result in roughly the same number of remaining nonattainment and main tenance areas in 2012 and 2014 based on EPA’s own projections of CSAPR and our projections for CAIR using EPA’s modeling tools for the proposed Transport Rule and CAIR Budgets (emphasis added) . ” See also Southern Company’s October 1, 2010 comment letter, which states: “To compare the air quality benefits achieved by the CAIR budgets versus the Transport Rule budgets using our version of AQAT, it was necessary to supplement the documented budgets available from the CAIR final rule to include states that we re not considered in CAIR.” 45 Further, Southern Company utilized EPA’s AQAT from the proposed rule for this assessment. EPA received extensive comment on the flaws and biases of AQAT as constructed for the proposal and substantially improved AQAT for the f inal rule. In short, Southern Company’s assessment is based not only on an incorrect assumption about the impact of budgets on emissions but also on use of an outdated version of AQAT.

85. T he health benefits of the Transport Rule , as detailed later in thi s declaration, are very significant

-- preventing between 13,000 and 34,000 premature deaths annually. In addition , while the Transport Rule reduces emissions that significantly contribute to downwind air quality problems at specific receptors, these reduct ions also improve air quality in other areas. Based on the best available science, there does not appear to be a level of exposure to fine particles at which health effects do not occur. After reviewing the body of scientific literature on particulate matt er, EPA concluded that the “no

threshold” model best represents the PM2.5

- mortality concentration

- response relationship. 46

45 Comments of Southern Com pany on the U.S. Environmental Protection Agency’s proposed Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone (Oct. 1, 2010), at page 10 (EPA docket # EPA

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- 2864). This conclusion has been confirmed by two separate rounds of peer review from EPA’s independent Clean Air Scientific Advisory Committ ee and public comment. This means that reductions in PM2.5 concentrations will provide public health benefits even in areas with relatively good air quality, and it is important to

46 Integrated Science Assessmen t for Particulate Matter (Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R

- 08/139F. Available on the Internet at

< http :// cfpub

. epa

. gov / ncea / cfm / recordisplay

. cfm ? deid =216546>

.29 account for the full public health benefits of clean air. EPA’s approach t o estimating PM2.5

- related health benefits is well established, including accounting for benefits that occur below 15 μg/m3 (the level of the current annual standard).



### Claims of Harm

Entergy Corporatio n

86. I have reviewed Entergy ’s claim s that it would have to c urtail generation and thus would not be able to meet its obligation to provide reliable power. Both claims appear to be based on incorrect assumptions

. I t does not appear to me that Entergy has given full consideration to a multi

- pronged strategy (buying allowances, buying power from others when possible, and re

- dispatching their system). The evidence presented by Entergy does not demonstrate that the company coul d not achieve compliance with th e Transport Rule through a multi

- pronged approach of making some reductions (for example, through some re

- dispatching if its units), buying some allowances, and purchasing some power.

87. Entergy’s claims are based on the assumption that allowances will not b e available for purchase. However, as shown above, the Transport Rule allowance markets are developing as expected. Entergy’s claims are also based on the assumption that it will not be able to purchase power because of transmission constraints do not ta ken into account the fact , as explained in paragraph 62 above, that EPA’s modeling results for the Transport Rule are fully compatible with the interregional transmission limitations presented in Entergy’s motion

.

88. I have also reviewed Entergy ’s assertion (p. 14) that “IPM significantly underestimated generation needs in the majority of states in the ozone season NOx program” and find no basis for this assertion. Entergy cites Exhibit B to the Kansas Utilities Motion for Stay of Final Rule, wh ich calculates the difference between 2010 seasonal NOx emissions across all Transport Rule states and the sum of their 2012 budgets. This exhibit does not address generation, much less demonstrate whether an underestimation of generation exists in any st ate or that states will be unable to meet their 2012 budgets while generating sufficient electricity. Instead, the exhibit only shows that the Transport Rule requires emissions reductions from 2010 levels.

89. I also find no basis for Entergy’s assertion (p. 14) that since all covered states seasonal NOx emissions in 2010 exceed the covered states combined budgets, allowances will not be available for purchase. According to this faulty logic, emissions trading programs could never achieve reductions, a conclu sion that conflicts with the overwhelming success of ARP, CAIR, and a myriad of other trading programs. Moreover, Entergy ’ s argument claims that there is a large gap between 2010 emissions and 2012 budgets,30 summed across all covered states. However, the c ombined 2010 ozone

- season emissions of all covered states were only 15% above the sum of all covered states ’

ozone

- season NOx budgets. More recent 2011 emissions data shows that ozone season emissions have already declined below 2010 levels, with the resu lt that they are only 11% above the total of the state budgets for the Transport Rule region. Further, this does not reflect the additional reductions that will be realized from emission controls that are planned to come on line by the start of the 2012 ozone season. EPA anticipates many sources have planned reductions on the way for 2012 regardless of the Transport Rule ince ntive. These are typically driven by state rule or consent decree requirements. For instance, due to the Illinois state rule, ozo ne season NOx emissions should fall in 2012. Even absent the Transport Rule, EPA anticipates that ozone

- season emissions in Illinois will drop approximately 6,000 additional tons fro m the state’s current levels

. 47 This alone, will deliver more than 1% of the remaining 10% of the reductions needed. Similar “on the way” reductions exist in other covered states as well, and Entergy’s failure to incorporate them into their motion leads to an overstatement of the overall 2012 compliance burden.

90. Entergy’s mot ion focuses on its facilities in three states covered by the CAIR ozone season NOx program

-- Arkansas, Louisiana, and Mississippi. In all three states, Entergy adopted a compliance strategy based on purchasing allowances instead of reducing emissions. Entergy has purchased significant numbers of CAIR ozone

- season NOx allowances since 2009. In fact, as shown in the table below, since the CAIR ozone

season NOx trading program be gan in 2009, total ozone

- season NOx emissions from covered facilities owned by Entergy in these states actually have increased slightly. Further, in the past two years, Entergy has purchased more than half of the allowances the company used for compliance with the CAIR ozone

- season trading program.

CAIR Ozone

- Season NOx Emissions from Facilities Owned by Entergy *

State 2009 2010 Preliminary 2011

Arkansas 13,708 14,908 13,893

Louisiana 10,184 11,916 11,467

Mississippi 3,529 4,851 3,782

Total 27,420 31,676 29,142

* In this table, f acilities in which Entergy owns a majority interest are included as Entergy facilities while those facilities in which Entergy owns a minority interest are excluded. T his affects a small number of Entergy's facilities

.

47 Written Testimony of Douglas P. Scott

- Director, Illinois Environmental Protection Agency

– Before the U.S. Senate Committee on Clean Air and Nuclear Safety. Retriev ed at http://epw.senate.gov/public/index.cfm?FuseAction=Files.View&FileStore_id=fc4c5288

- 525a

- 47d6

- 812c

809d000c617b31 Florida Electric Power Coordinatin g Group, Inc.

91. FCG miscalculates the difference between Florida’s most recent emissions and its 2012 state budget, and FCG grossly overstates the cost of potentially purchasing allowances to cover that gap (FCG Motion p. 17) . Whereas FCG states that the 2012 budget is 9,500 tons less than 2010 emissions, this calculation ignores that the state’s most recent ( 2011 ) ozone season emissions were only 1,887 tons less than its 2012 state budget
, significantly less than the 9,500 ton difference on which FCG base s its claims of irreparable harm

. Moreover, FCG assumes that any purchased allowances would cost $3,750 per ton, which is several times higher than the most recent ly observed price of Transport Rule ozone

- season NOx allowances at approximately $900, 48 which is even lower than EPA’s pr ojected market

- clearing price of $1,300 per ton (Regulatory Impact Analysis for the Federal Transport Rule, p. 260. Document ID: EPA

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. At recent prices, even if Florida utilities chose not to adjust t heir behavior under the Transport Rule and operate exactly as they had in 2011, the cost of buying allowances would only amount to about $1.7 million per year, significantly lower than the $35 million that Florida estimated.

92. FCG’s claims that the Transpor t Rule threatens reliability in Florida are inconsistent with data showing that few reductions from current emission levels are needed for compliance. Florida’s 2011 ozone

- season NOx emissions were only 1,887 tons above its 2012 budget, or about 7%, and w ell within its assurance level that is 121% of the state budget, suggesting that few changes, if any, are needed to comply with the Transport Rule. Furthermore, the variability limit allowing states to emit up to 21% above their seasonal NOx budgets was d esigned specifically to give states flexibility in case of unexpected events, like a hurricane. (76 FR 48,303)

93. The claim s of harm to Orlando Ut i lities Com m ission are all premised on the incorrect assumption that allowances will not be available for purchase. FCG cites to the testimony of Chip Merriam before the U.S. House of Representatives’ Committee on Science, Space, and Technology wherein Mr. Merriam claims that the Orlando Utilities Commission (“OUC”) will have to lower the capacity of its 450 MW coal unit to 100 MW because of the number of allowances it has received and the restrictions on trading. It is claimed that this would cause the plant to have to spend $40 million to handle storm water that the plant now evaporates. This claim is based upon the assumption that allowances will not be available for purchase. As described above in this declaration, evidence shows that markets are developing and EPA fully expects that allowances will be available in the market well before utilities must sur render allowances to comply with the Transport Rule. Further, as described in the State Level Emission Reductions section of this declaration, Florida’s 2011 ozone

- season emissions were already well below its 2012 assurance level and only 7% above its 201 2 budget. There is little reason

48 Estimations are based on calculated as well as bid and ask prices available from subscription services such as Argus Air Daily and BGC Environmental Brokerage Services.32 for concern, therefore, that total ozone

- season NOx emissions from covered EGUs in Florida would rise above the assurance level in 2012 and thus no basis for concerns that purchasing allowances would cause a utility to be exposed to the assurance penalty provisions.

94. FCG’s claims that Lakeland Electric is harmed because it received too few allowances also do not withstand scrutiny for the reasons explained below

. a. FCG cites to the affidavit of Farzie Shelton, wherein Mr. S helton claims (para. 6) that Lakeland Electric received an “under

- allocation” of allowances due to errors in the methodology and modeling supporting the final Transport Rule. Mr. Shelton claims (para. 7) that its C.D. McIntosh Jr. Power Plant’s Unit 3 rec eived too few allowances because it allegedly had only one “normal” year of operation in the last 5 years, due to unspecified “significant downtime” related to the installation of pollution controls and unit malfunctions. EPA’s method for allocating allowa nces based on the average heat input of the highest three of the last five years was designed to mitigate the impact of unit downtime due to the installation of pollution controls or maintenance issues. (76 FR 48,290) The method was proposed and the EPA re ceived many comments supportive of the method as being a fair means for distributing allowances. (76 FR 48,287) b. Furthermore, the Shelton Affidavit claims that the “high three” heat input average for C.D. McIntosh Unit 3 does not reflect “normal” unit opera tion due to unit downtime at points throughout 2007 to 2010. This implies that 2006 was a normal operating year for the unit. However, the heat input during the 2006 ozone season was 8.4 TBtu, which is significantly lower than the heat input in 2007 and 20 08, which were 11.3 TBtu and 13.7 TBtu, respectively. The average heat input in those three years, which were the highest of the five years considered, is 11.1 TBtu. This quantity was used to determine this unit’s allocation. (Final Transport Rule Unit Lev el Allocations Under the FIP, Document ID: EPA

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- 4400) Additionally, the heat input during the 2011

ozone

- season was 10.1 TBtu, 49

c. The claims in the Shelton Affidavit (para. 8) that the C.D . McIntosh Unit 3 was “under

- allocated” because EPA wrongly classified Unit 3 as a "dispatchable SCR" appear to be based on a misunderstanding of the relevance of SCR classifications in the IPM model. Mr. Shelton claims that Lakeland’s Title V permit r equires the SCR unit to operate, making the SCR “non

- dispatchable”. However, the classification of a SCR as dispatchable or non

- dispatchable has no impact on size of Florida’s budget or unit

- level allowance allocations to Florida EGUs. which is lower than the “high

- three” average, suggesting that the downtime that Mr. Shelton refers to had a mini mal impact on the allowance allocations. Further, looking at data reported on EIA form 923, it is unclear that the “downtime” in any of the “high three” years even occurred during the ozone season.

49 EPA Emissions Data. Available on the Internet at <http:www.camddataandmaps.epa.go v/gdm>.33 d. Dispatchable SCRs a re those controls that EPA identified in the model as available for dispatch but which the source was not required to run. In general, EPA assumed such SCRs would not necessarily be run in the absence of a rule like CAIR or the Transport Rule. Non

- dispat chable SCRs, in contrast, are SCRs that the source is required to run. These SCRs were assumed to run regardless of the presence of a rule like CAIR or the Transport Rule. However, at the $500 per ton of NOx cost threshold used to determine the state bud gets it would be cost

effective to run dispatchable SCRs. (76 FR 256) Thus, regardless of whether Unit 3’s SCR is classified in the model as dispatchable or nondispatchable, it would be assumed to run in the modeling scenario used to set state budgets. Fo r this reason, the classification of the SCR had no impact on determining Florida’s budget. Furthermore, since unit level allocations were based on historic heat input, the presence or absence of a SCR would have no impact on allocations.

e. The Shelton Affid avit’s conclusion (para. 9) that Lakeland Electric is expected to spend a great deal of money to comply with the Transport Rule is based on exaggerated and unsupported assumptions regarding price and availability of allowances. f. Mr. Shelton overstates the need for emission allowances. Combined, all of the units at CD McIntosh had 2011 seasonal ozone emissions of 952 tons 50 and 2012 seasonal NOx allowance allocations of 561 tons, 51 a difference of only 391 tons. In addition, as described above in the Emission Reduction Requirement section of this declaration, the difference between Florida’s 2011 emissions and 2012 budget is only 1,887 tons, significantly less than the 9,500 tons Shelton cites. Finally, as described allowance market section of this declaration, the recent seasonal NOx price is approximately $900 per ton. At current prices, CD McIntosh could operate at 2011 emission levels and buy allowances to cover the gap for only $505,000.

95. FCG claims (Motion p. 19) that compliance costs for Phase I of the Tr ansport Rule in 2012 will be significantly higher than the $1.4 billion that the EPA projected are based on incorrect assumptions. In particular, FCG assumes, but provides no credible evidence, that Florida will have to significantly reduce its emissions and that allowances will not be available or will be prohibitively expensive

– assumptions that, as noted above, are incorrect. Florida’s 2011 emissions are close to the level of its 2012 budgets and well under its 2012 assurance level.

Kansas Utilities

96. Data from the last four quarters for Kansas show that SO2 emissions from covered EGUs in the state were 41,671 tons in the last four quarters, a mere 150 tons higher than the

50 Id.
51 Calculated from: Final Transport Rule Unit Level Allocations Under the FIP. Document ID: EPA

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- 440034 state budget of 41,528 tons. Kansas also is closer to the annual NOx budget th an they would seem if only 2010 data were considered. In the last four quarters, actual annual NOx emissions were estimated at 45,798 tons. As explained in the following paragraphs, in 2012, Kansas would be expected to emit around 35,500 tons annually, o r around 5,000 tons above the state budget of 30,714 tons. If allowances were purchased to fill the gaps, the SO2 allowances would cost sources around $105,000 at today’s calculated Group 2 SO2 allowances prices. Annual NOx allowances would cost around $ 4.5 million at today’s prices. For some perspective on these costs, the combined annual revenues of Westar Energy , BPU and Sunflower Electric were around $2.5 billion in 2010

. 52

97. The Kansas Utilities’ claims of harm are premised on the incorrect assumption that without the Transport Rule EGUs in Kansas would be able to continue emitting at 2010 levels. It is my understanding that it would be extremely difficult, if not impossible, from an operational standpoint for many EGUs in Kansas to operate at 2009/20 10 levels and/or that doing so would violate Kansas state law or consent decree commitments. Many Kansas EGUs have already added combustion controls to reduce emissions rates, and these controls cannot simply be turned off or bypassed. Furthermore, by 20 12 many Kansas EGUs will be required to operate with emissions at much lower levels than their 2010 levels as a result of state regulations or binding consent decrees. Therefore,

an across

- the

- board assumption that Kansas EGUs would have operated at 2010 levels but for the Transport Rule alone is an incorrect basis from which to estimate allowances that may be required. For this reason, the comparison of the Transport Rules 2012 allowance budgets for Kansas with 2010 emission in the state that is presente d by Kansas Utilities does not provide a basis for evaluating the impact of the rule on EGUs in Kansas.

98. For example, the state’s largest EGU sources of NOx emissions

– Jeffrey Energy Center

– emitted 18,347 tons of NOx in 2010 and had an emission rate o f 0.24 lbs/mm B tu. However, the source is subject to a consent decree that requires each unit at the plant to meet an emission rate of 0.18 lb/mm B tu through installation and use of Low NOx combustion systems no later than December 31, 2011. 53 These units i nstalled controls slightly ahead of schedule and are already demonstrating an emission rate of 0.159 lbs/mm B tu. 54 Simply continuing to operate at this rate as required by the consent decree means that this facility’s NOx emissions would drop from approximat ely 18,300 tons in 2010 to approximately 12,100 tons in 2012

– more than a 6,200 ton differential.

52 Westar Energy Fundamentals

- Snapshot http :// phx

. corporate

- ir

. net / phoenix

. zhtml ? c =89455& p = irol

fundsnapshot ; Board of Public Utilities 2010 Comprehensive Annual Report 062311; Sunflower Electric Power Corporation 2010 Financial Statements htt p://www.sunflower.net/documents/2010SEPCannualreportauditorsreportonlyforweb.pdf

53 http://www.epa.gov/compliance/resources/decrees/civil/caa/westarenergy

- cd.pdf

54 CAMD Data and Maps. 2011 Q2 data35 99. Two other EGU sources, Quindaro and Nearman, are subject to a state rule that will result in them lowering their emission rate from 0.31 to 0.2 lbs/mm B tu (Quindaro) and from 0.402 lbs/mmB tu to 0.26 lbs/mm B tu (Nearman) by 2012.

100. I have read and am familiar with the October 21, 2011 declaration of Wayne E. Penrod, Manager of Environmental Policy for Sunflower Electric Power Corporation, submitted in support o f the Kansas Utilities stay motion. Sunflower’s claims (Motion p. 13) that the utility will receive NOx allowances sufficient to cover only about 50% of its requirements and that it will be forced to reduce generation at its Holcomb 1 EGU to 50% capacity, rather than running it at its normal 80% capacity are exaggerations. As Mr. Penrod acknowledges in his declaration (Exhibit D para 29), it has submitted a PSD application proposing to reduce NOx emissions through the use of LNB combined with OFA controls , and plans to install these controls in January 2012. This project is estimated to reduce NOx emissions from 4,687 tons per year to 2,672 tons per year, resulting in a 2,000 ton per year reduction in NOx emissions starting in 2012. 55 Therefore, instead o f emitting around 5,000 tons in 2012 (Exhibit D, para 12), Sunflower would be expected to emit around 3,000 tons of NOx annually. Sunflower’s allowance allocation under the Transport Rule is therefore approximately 700 tons less than their projected needs

.

101. Reductions at Jeffrey Energy Center, Quindaro, and Nearman due to state rules and/or consent decrees and the reductions from Holcomb 1’s retrofit project are expected to collectively reduce Kansas EGU annual NOx emissions by around 10,000 tons. Even if no additional changes were to be made in Kansas between 2010 and 2012, the reduction in annual NOx emissions from EGUs would result in 2012 emissions about 5,000 tons higher than the state budget under the rule.

Municipal Electric Authority of Georgia

102. MAEG’s claims of harm are exaggerated. First, as explained above, MAEG overstates the difference between its current emissions and the number of allowances allocated to it for 2012. Further, MEAG does not provide any basis for its estimate that it will cost them $2,400

- $6,300 per ton to employ one of the compliance options they have identified, a non

- economic dispatch that would switch generation from uncontrolled to controlled plants. Fina lly, MEAG’s claim that they lack authority to switch generation unilaterally due to co

- ownership of the plants is surprising in light of the fact that the four co

- owners of the four units in question (Scherer 1, Scherer 2, Wansley 1, and Wansley 2) are the same, and all may have similar interest in changing the generation dispatch.

55 http://www.kdheks.gov/bar/sunflowerunit1/sunflowerunit1.html36 City of Ames, Iowa

103. The “termination notice” cited in the stay motion of the City of Ames, Iowa provided notice that certain allowances that could not be used for compliance wi th any trading programs, would be removed from trading program accounts. This action did not constitute a denial of the City’s Oct 7 administrative petition or change any of the City’s Transport Rule compliance obligations or options.

104. The allowances that EPA “terminated” were allowances that could not, in any event, be used for compliance with the Transport Rule NOx trading programs (or for compliance with CAIR NOx trading program requirements for 2011) . EPA had previously allocated 2012 CAIR annual NOx allowances to sources covered by the CAIR trading programs, and sources covered by the Acid Rain Program received SO2 allowances under the statute. Neither the EPA issued NOx allowances nor the Acid Rain Program SO2 allowances, however, can be used fo r compliance with the Transport Rule trading programs regardless of whether they are withdrawn from a source’s account. Further, EPA did not withdraw any Acid Rain Program SO2 allowances from source’s accounts as sources will still need to hold such allow ances to comply with the Acid Rain Program. EPA’s action to withdraw the CAIR NOx allowances from compliance accounts was simply an administrative action that needed to be taken to avoid confusion with 2012 Transport Rule allowances.

State of Wisconsin

105. The State of Wisconsin’s claims of harm are premised on the incorrect assumption that, under the Transport Rule, EGUs in Wisconsin will either have to reduce generation or purchase allowances (Motion at 13). As explained below, EPA analysis anticipates Wi sconsin will have slightly higher fossil generation in 2012 than 2010 levels and will have a surplus of allowances that will be available for sale or banking. EPA anticipates that Wisconsin will be able to maintain this higher level of generation and sur plus of SO2 and NOX allowances in 2012 budget through a combination of under

- construction controls and fuel switching. 56

106. Wisconsin does not take into account the emission reductions already “on the way” in its assessment of 2012 compliance feasibility and its assertion that generation reductions or allowance purchase are its only means to continue to generate at historic levels. The South Oak Creek facility and the Genoa power plant will be installing one as well (construction on both of these began before final Transport Rule). On their own, these reductions combined with the fuel switching from petroleum coke to low sulfur

56 U.S. EPA, Clean Air Markets

- Data and Maps, http://camddataandmaps.epa.gov. “WebReady_ParsedFile_TR_Remedy_Final_2012” epa

- hq

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- 4431, U.S. EPA, Clean Air Markets

- Data and Maps, h ttp://camddataandmaps.epa.gov37 coal at Nelson Dewey (a fuel switch that the state has indicated is being planned) 57 will bring the SO2 emission levels in Wisconsin c lose to their 2012 budget levels. On the NOx side of the equation, Wisconsin facilities are already emitting at levels close to their budget and no major reductions are needed. 58

107. The Genoa facility provides a clear illustration of why Wisconsin’s assertion that its power industry must buy allowances or reduce electricity generation to comply with the 2012 budgets is incorrect . The FGD is being installed at Genoa Unit 3 according t o the facility owner. A comparison of Q3 data this year to Q3 data last year indicates that this FGD has been completed and is now operating as the emission rate has dropped from over 2 lbs/mm B tu to less than .3 lbs/mm B tu. Its Q3 emissions in 2010 were over 4,000 tons, while in Q3 2011 they were about 300 tons of SO2. That is nearly a 3,700 ton drop

– in just one quarter, for just one unit. In this case, the facility can continue to generate at historic levels with no need to buy allowances because of the reductions that have been achieved through completion and operation of planned controls. Ignoring these types of “real

- world” reductions leads to exaggerated claims about the necessity for significant allowance purchase or reduced generation. 59

108. As th e data shows below, NOx emissions from covered EGUs in Wisconsin are already below the state’s assurance level and near its budget level for NOx. For SO2, emissions from covered EGUs are trending downwards as well, and EPA analysis suggests that, in large part due to reductions already planned or being implemented, by 2012 total SO2 emissions and NOx emissions from covered EGUs in the state will be below the state’s 2012 budget. The expected, or on the way SO2 emission reductions, alone will take the
stat e’s SO2 emission levels below 2012 assurance level and closer to the 2012 SO2 budget level. If facilities in the state simply continue to reduce emissions at the same rate it has for the first 3 quarters of this year, they will be at or below their budget s in 2012. 60

57 Wisconsin Petition for Reconsideration and Request to Stay the Final Rule, page 9 of 20.

58 U.S. EPA, Clean Air Markets

- Data and Maps, http://camddataandmaps.epa.gov

59 U.S. EPA, Clean Air Markets

- Data and Maps, http://cam ddataandmaps.epa.gov

60 U.S. EPA, Clean Air Markets

- Data and Maps, http://camddataandmaps.epa.gov. “WebReady_ParsedFile_TR_Remedy_Final_2012” epa

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- 443138 2010 and 2011 SO2 and NOx Emissions, Budgets, and Assurance Levels for Wisconsin (Tons)

2008 Emissions 2010 Emissions Emissions in the Last Four Quarters Final Transport Rule 2012 Budget 2012 Assurance Level Proposed Revised 2012 Budget

SO2 129,695 109,476 97,559 79,480 93,786 NA

NOx 47,805 33,466 32,455 31,628 37,321 34,101

Expected or “On the Way” SO2 Emission Reductions for Wisconsin Power Plants (Tons)

Power Plant 2010 SO2 Emissions 2012 Expected SO2 Emissions SO2 Emission Reductions

South Oak Creek 11,780 8,331 3,449

Genoa 8,874 903 7,971

Nelson Dewey 13,450 3,554 9,896

Total 34,104 12,788 21,316

109. Finally, the state of Wisconsin ’s assertions regarding the impact of the rule on the availability of affordable power is inconsistent with our analysis demonstrating that retail electricity prices in the different regions of Wisconsin would increase by only 0.4% to 2%

- well within the range of normal price fluctuations. 61

Dairyland Power Cooperative

110. Dairyland Power Cooperative exaggerates the purported difference between its allowances allocations and recent actual emissions from its plants . On the annual NOx side, its 2012 total allocation would be approximately 3,700 allowances, but its emissions o ver the last four quarters of fully reported data are approximately 4,500 tons

– meaning only about 800 tons must be reduced or 800 allowances purchased. Notably Dairyland does not claim to be short of SO2 allowances in 2012. The table below confirms why the motion is noticeably quiet on this issue. Based on EPA’s calculations, Dairyland will have a 2012 SO2 allowance surplus that is far greater than any shortage it will incur on the NOx (see table below).

61 “Regulatory Impact Assessment for Final Transport Rule”, p.266.39 Dairyland Power Emissions and Allocations Info rmation for Power Plants Assumi ng a Business as Usual Scenario (Tons)

Power Plant 2012 SO2 Emissions 2012 SO2 Allocations 2012 NOx Emissions 2012 NOx Allocations

Alma 1,440 1,173 411 433

Elk Mound Generating Station 0 0 6 9

Genoa 903 3,560 987 1,313

J P Madgett 4,665 4,475 2,827 1,650

Weston Unit 4 @30%** 277 336 267 277

Total 7,285 9,544 4,497 3,682
Surplus/(Shortage) 2,259 (816)

* 2012 emissions in this table reflect a business as usual scenario. That is, they reflect actual operations and emissions observed over last 4 quarters (Q1

- Q3 2011, Q4 2010), with exception of Geno a facility SO2. For Genoa, 2012 SO2 emissions are adjusted to reflect yea r round operation of recently completed FGD. **Weston unit 4 allocations and emissions were multiplied by 0.3 to reflect Dairyland’s 30% ownership of unit.

111. T he difference between current SO2 emissions from Wisconsin EGUs and the Wisconsin 2012 SO2 budget is much smaller than the 27% cited by Dairyland and further reductions will occur before 2012 due to increased operation of pollution control equipment and ch anges in state law. SO2 emissions in the past four quarters (97,559 tons) are already significantly lower than 2010 emissions and only 23% (not 27%) above the 2012 Wisconsin State SO2 budget (79,480 tons).

112. Dairyland also appears to incorrectly assume t hat Wisconsin must reduce SO2 emissions down to these budget levels. Wisconsin’s assurance level is 93,786 tons. To reach this level, facilities in the state would only have to reduce approximately 4,000 tons (4% of current emissions). 62 Achieving an app roximate 4% reduction over the next 5 quarters is very modest and conservative compared to the reductions Wisconsin facilities have achieved over the past several years. For example, since 2007, Wisconsin facilities have averaged a 9% reduction in its rol ling annual emissions total, where as only a 4% reduction would be needed over the next 1.25 years to bring them into compliance with the state’s 2012 assurance level. There are many “planned” reductions on the way in Wisconsin that will continue to push emissions down towards 2012 budget levels. For example, Dairyland’s website acknowledges that a FGD is being installed at the Genoa 3 unit. 63

62 U.S. EPA, Clean Air Markets

- Data and Maps, http://camddataandmaps.epa.gov A comparison of Q3 data this year to Q3 data last year indicates that this FGD has been completed and is now ope rating as the emission rate has dropp ed from over 2

63 http://www.dairynet.com/energy_resources/equipment.php40 lbs/mmBtu to less than 0.3 lbs/mmB tu. In the same period, its Q3 emissions in 2010 were over 4,000 tons, while in Q3 2011 they were about 300 tons of SO2. 64 That is a 3,700 ton drop

– in just one quarter , for just one unit (see table in Wisconsin section).

113. Further, even if it was assumed that for some reason no further reductions in the state were possible between 2011 and the 2012 compliance period (a hypothetical that we know is overly conservative) th en the entire state would need to purchase about 1,000 NOx allowances, and 17,000 SO2 allowances. This amount has already been offered for sale through sellers putting their allowances on the markets through actions such as the November 17th auction of 10 0,000 SO2 and NOx allowances by First Energy.

114. Dairyland also mistakenly claims that the final Transport Rule “limited” the Wisconsin budget and will lead to a shortage of allowances in 2012 (Motion at 17). These claims are exaggerated. As the tables in the previous section highlight, the state is already operating (more than a year in advance) at NOx levels close to its 2012 budget level. EPA modeling predicts that the state will have a surplus of NOx allowances in 2012, not a shortage of allowances as claimed. For SO2, the state’s emissions are trending downwards as well. Scheduled reductions from scrubber installation at the South Oak Creek and Genoa plants, and fuel switching from petroleum coke to low sulfur coal at the Nelson Dewey generating stat ion alone will likely bring the state’s emissions close to the 2012 SO2 budget. EPA anticipates a surplus of SO2 allowances in the state for 2012 that will be available for trading or banking. The most recent data reported supports the notion that the st ate’s emissions are trending towards its 2012 budget level. 65

115. Dairyland’s prediction that the wholesale electricity rate will increase by 2.9% and asserts (with no supporting quantitative evidence) that their compliance cost would be $9.1 million (motion a t 18) are also exaggerated. This analysis appears to be predicated on faulty assumptions of allowances not being available for purchase. EPA predicts retail electricity prices in that region will increase by .4% to 2% for the different regions in Wiscons in

- well within the range of typical price variation.

116. EPA predicts a surplus, not a shortage, of SO2 and annual NOx allowances in 2012 (both at state level and regional level) due to the compliance actions that are available to power generators in the TR region. In fact, EPA predicts some allowances will be banked in 2012 to assist with compliance for the tighter 2014 budgets. 66

117. Dairyland references Wisconsin Public Service Corporation’s (WSPC) allegations of errors in what environmental controls were modeled at particular units. These concerns were already addressed in my declaration responding to WPSC’s motion to stay, which is attached to this declaration. As explained therein, most of these concerns were simply

64 U.S. EPA, Clean Air Markets

- Data and Maps, http://camddataandmaps.epa.gov quarterly data

65 “TR_Remedy_Final” Document #: EPA

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66 “TR_Remedy_Final” Document #: EPA

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- 442541 misunderstandings on the WSPC’s beha lf of what the model was showing or how it was used. 67 68 There is no support for Dairyland’s claim (or WSPC’s claim) that the budgets are “tens of thousands of tons” too low. Data reported by the sources themselves demonstrate that the facilities in the s tate are already emitting at levels less than 1,000 tons above the final 2012 NOx budget.

State of Ohio

118. The State of Ohio’s claim s of harm are based largely on the assumption that there will not be enough allowances available to cover Ohio’s 2012 emissio ns and that sources will not be able to purchase allowances. However, as explained above an active and robust trading market is developing and will continue to be available to help Ohio’s sources secure enough allowances to cover their emissions. For example, First Energy
, a stakeholder with a substantial generation portfolio in the state of Ohio
, recently conducted an auction of Transport Rule allowances.

Wisconsin Electric Power Company (We Energies)

119. We Energies is incorrect in its assumption that Michigan would exceed its assurance level

– something recent emissions data demonstrates is highly unlikely. As explained above, current emissions data, as compared to the final rule budget and allocations, show that there is little risk that this w ill occur. Current SO 2 emissions are within 2% of the state budget and well below assurance levels. Current NOx emissions are declining and operating existing controls more effectively can bring the state below its assurance levels and very close to its budget. The value of the NOx allowances will provide a strong incentive for this to occur. We Energies’ argument speculates that there is a high probability that the designated representative for the Presque Isle plant will exceed their share of assuranc e provisions and that Michigan will exceed the state’s assurance level and thus put the plant at risk of penalties. The emissions assessment above shows there is little risk that using additional allowances for compliance at the Presque Isle Plant will tr igger assurance penalties.



### A Stay of the Transport Rule Would Cause Substantial Harm to Other Parties Even if CAIR Remains in Place

120. As discussed above, we expect the Transport Rule to prevent between 13,000 and 34,000 premature deaths annually. Additionally, the rule will avoid 15,000 non

- fatal heart attacks, 19,000 hospital and emergency department visits, 19,000 cases of acute bronchitis, 400,000 incidences of aggravated asthma, and 1.8 million days when people miss work or school annually.

67 U.S. EPA, Clean Air Markets

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68 “WebReady_ParsedFile_TR_Remedy_Final_2012” epa

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**•** EPA estimates that by 2012, power plants in states common to both the Transport Rule and CAIR will achieve annual SO2 emissions around 1.5 million tons lower and annual NOx emissions around 116,000 tons lower than what would have been achieved at that time under CAIR. :

**•** Further, by 2014, power plants in states common to both rules will achieve annual SO2 emissions around 1.8 million tons lower and annual NOx emissions ar ound 76,000 tons lower than what would have been achieved under CAIR.

122. If the CAIR requirements were to remain in place in only one or a few states (as requested by certain movants) but all other CAIR requirements were replaced by the Transport Rule, the CAIR requirements would cease to act as a constraint on emissions for several reasons. Under the CAIR requirements, sources in CAIR states must surrender, for each ton of emissions during the year or ozone season, one allowance allocated for that year or ozone season (or allocated for a prior year or ozone season ). The sources must use Acid Rain Program (ARP) SO2 allowances to comply with the CAIR SO2 trading program, CAIR annual NOx allowances to comply with the CAIR annual NOx trading program, and/or CA IR ozone

- season NOx allowances to comply with the CAIR

ozone

- season NOx trading program. Under CAIR, a source may use an allowance regardless of whether the allowance was originally allocated in the state in which the source is located. In the years sinc e promulgation of these programs, substantial banks of ARP and CAIR NOx allowances (i.e., pools of unused allowances allocated for prior years) have developed.

123. At the end of the 2010 control periods, over 15 million banked ARP SO2 allowances were availabl e for use by ARP sources (the vast majority of which are in the CAIR and Transport Rule regions). 70

69 This comparison includes emissions from EGUs with capacity greater than 25 MW, in only the group of states

covered in both the Transport Rule and CAIR in order to allow for comparable results from both programs. CAIR emission are estimated for 2012 and 2 014 based on modeling results presented in the CAIR RIA; the IPM outputs are available on the web at: SO2 emissions from EGUs in 2010 in any one state were orders of magnitude smaller than the size of the ARP SO2 allowance bank. For example, SO2 emissions f rom Wisconsin EGUs in 2010 were about 109 thousand tons. The existing ARP allowance bank is thus more than 130 times the level of recent Wisconsin power sector emissions. While we cannot know in advance the exact size of the bank that will remain after d eduction of allowances to cover 2011 emissions, it is highly likely

www

. epa

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. html (“IPM CAIR 2010 Parsed” and “IPM CAIR 2015 Parsed”). Transport Rule projections are from modeling of the final rule which is available on the web at: www

. epa

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- ipm / transport

. html (“TR_Remedy_Final” state emissions file).

70 Data about the number of banked allowances is presented in the Clean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report, attached to this declaration.43 that the bank will be similarly disproportionately sized to the total potential emissions from any one (or a few) states. Implementation of CAIR in only one state (or a few states) would allow power plants in that state (or those states) to access virtually the entire bank of ARP SO2 allowances for compliance use. Competition for these allowances would be drastically reduced as the other sources in the CAIR region that had previously need ed to hold additional ARP allowances for compliance with CAIR, in the ratio of two allowances to one ton emitted, would no longer need to hold those additional ARP allowances starting in 2012. 71 The gross mismatch of supply of and demand for ARP allowances would drive the price of these allowances toward zero, thereby effectively neutralizing the constraining effect of CAIR on emissions.

124. For these reasons, implementation of CAIR in only one state (or a few states) would not constrain SO2 emissions from cov ered EGUs. It would therefore be possible for emission s from covered EGUs to rise above the level achieved in 2010 when power plants in several other states were also seeking Acid Rain Program allowances for CAIR compliance.

125. A bank of CAIR annual NOx emi ssions allowances also exists, and at the end of the 2010 compliance period it contained over 400 thousand annual CAIR NOx allowances. Likewise, a bank of ozone

- season NOx allowances exists, and at the end of the 2010 compliance period it also contained o ver 400 thousand ozone

- season NOx allowances. The size of each of these NOx allowance banks dwarfs the relevant 2010 EGU NOx emissions (annual emissions and ozone

- season emissions, respectively) from any one state. Implementation of CAIR in only one stat e (or a few states) would allow covered power plants to access to the entire banks of annual and ozone

- season NOx allowances because no other sources would be required to hold such allowances starting in 2012. The gross mismatch of supply of and demand fo r these allowances would drive the price of these allowances toward zero and thus, implementation of CAIR in only one state (or a few states) would not constrain NOx emissions from covered EGUs.

126. As documented in the 2010 progress report for CAIR, the ARP, and the former NOx Budget program, 72

71 Most of these sources would be required to continue holding one ARP allowance per ton emitted to comply with the ongoing Acid Rain Program, but as annual allocation of these allowances (about 8.95 million allowances) now significantly exceeds total ARP SO2 emissions (about 5.12 million tons in 2010), the net result is a further increase
in the total ARP allowance bank and thus a further increase in the allowances available to utilities subject to CAIR in this scenario. data from 2010 demonstrates that when allowance prices are very low, sources can and often do increase emissions. While emissions may vary year to year due to changes in electricity demand, the average ozone

- season NOx emission rate has fallen every year since 2004, except 2010, when allowances prices fell to below

72 Attached to this declaration.44 $50/ton. 73 Ozone

- season NOx mass emissions also rose in 2010, with much of the increase coming from coal

- fired units that reduced the removal efficiency of e xisting controls or even turned the controls off entirely. This behavior was observed at relatively low allowance price levels that were still much higher than the prices that could be expected if the CAIR requirements were to remain in place in only one state (or a few states) and all other CAIR requirements were replaced by the Transport Rule.

127. In short, simply leaving the existing CAIR regulations in place in only one state (or a few states) pending judicial review of the Transport Rule would not preser ve the status quo because

-- for the reasons discussed above

-- CAIR as currently promulgated would no longer constrain emissions.

128. Moreover, staying the Transport Rule for all states and leaving CAIR in place, would disrupt trading markets, create signifi cant uncertainty for the regulated community, and create significant uncer tainty for downwind states that need to develop attainment plans. As discussed in detail above, trading of Transport Rule allowances has begun; at least one company has already held an auction of Transport Rule allowances. The emissions market has already shifted toward the Transport Rule and away from CAIR and companies are developing compliance plans in anticipation of compliance with the Transport Rule in 2012. Further, there ar e differences in state coverage between CAIR and the Transport Rule. Certain states that were covered by CAIR are not included in the Transport Rule; likewise, the Transport Rule covers new states not included in CAIR. Moreover, for many of those states included in both CAIR and the Transport Rule, the pollutants covered (i.e., SO2, annual NOx, and ozone season NOx) are different under the two rules.

129. The response of Southern Company in support of responses and joinder by the State of Alabama, the Mississ ippi Public Service Commission and City of Springfield, Illinois, Office of Public Utilities in the State of Kansas’ Motion for Stay of the Transport Rule and the response and joinder by the State of Georgia, states that overall emission reductions and air quality improvements will be similar under either CAIR or the Transport Rule. As discussed in detail above, the assessment performed by Southern Company includes several factual discrepancies that make the assessment erroneous.

130. The motion for stay from Municipal Electric Authority of Georgia (MEAG) argues that no harm will occur if the Transport Rule is stayed, an argument premised on misinterpretations of designation and the Transport Rule base case. First, MEAG confuses clean data determinations with a redesignation in claiming that receptors indicate that Jefferson County, AL is in attainment. Second, the Transport Rule properly employs a projected 2012 base case scenario, rather than current air quality readings,

73 The Clean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 20 10 Progress Report is attached to this declaration.45 because cur rent data includes the effects of CAIR, which the Rule must replace, as explained in the Transport Rule (76 FR 48223). Even if current air quality readings were relevant, Georgia’s contribution to nonattainment in Jefferson County for daily PM2.5 is

more than three times the air quality threshold (1.10 microgram/m3 compared to threshold of 0.35) (Table V.D

- 4; 76 FR 48242).



### Impact of October 6, 2011 Proposed Revisions to the Transport Rule

131. On October 6, 2011, EPA signed a proposed rule (“revisions rule”) proposing technical adjustments to the Transport Rule. This proposal was published in the Federal Register on October 14, 2011 (76 Fed. Reg

. , 63,860). The Transport Rule is a sound, achievable, market

- based program that will deliver strong public health protections. No changes have been proposed to the core elements of the program. The proposed revisions provide important technical adjustments that will promote the liquidity of the already developing Transport Rule allowance market and smooth the trans ition from the CAIR programs to the Transport Rule programs. The proposed revisions reflect new information with technical merit that was brought to the EPA by stakeholders from a small number of units after publication of the final rule.

132. In the revision s rule EPA proposed to recalculate state emissions budgets for Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York, Texas, and Wisconsin, as well as new unit set

- asides in Arkansas and Texas. EPA also proposed to revise allowance all ocations to specific units covered by certain consent decrees in order to make additional allowances available for compliance use by any source under the Transport Rule programs without increasing the state’s emissions budgets. And finally, EPA proposed t o change the effectiveness date of the assurance provisions to 2014. This change would temporarily ease certain restrictions on the use of allowances in order to accelerate an already developing allowance marketplace, which would increase compliance flexi bility in the first two years as sources transition from CAIR. The proposed changes otherwise largely leave the Transport Rule as finalized. While individual state budget adjustments vary, overall, the proposed budget increases are slight

– about one per cent

– when compared to the millions of tons of pollution reductions secured by the Transport Rule.

133. The changes proposed in the revisions rule do not alter the conclusions presented above in this declaration. In fact, the changes if finalized as proposed would provide further support for the conclusions presented herein. If the emissions budgets of Florida, Louisiana, Michigan, Mississippi and Wisconsin are increased as proposed, the compliance options of sources in these states would be expanded and the ir costs of compliance reduced. Likewise, if the effectiveness date of the assurance provisions is changed to 2014 (easing restrictions on the use of allowances in the first two years of the program), this change would further promote liquidity of the new Transport Rule46 allowance markets and instill confidence that utilities can flexibly comply through a variety of unit

- level operational strategies.

134. Florida Electric Power Coordinating Group, Inc., (motion p. 13) mischaracterizes EPA’s statement in the re visions rule that a “limited postponement of the effectiveness of these provisions [the assurance provisions] is justified in order to smooth the transition from the existing CAIR programs,” as if this statement were an admission that the 2012 effective da te of the rule itself is unnecessary. This is false. EPA proposed to delay only the effectiveness date of the assurance provisions to 2014

-- EPA did not propose to delay the compliance deadlines of the rule, the state budgets, or any other core features. The Transport Rule’s compliance deadlines and state budgets are of critical importance in responding to the Court remand of CAIR.

135. As discussed above, EPA’s application of IPM undergoes extensive review, including periodic formal peer review. The rulema king process also provides opportunity for expert review and comment by a variety of stakeholders. The feedback that EPA receives on IPM provides a highly detailed reality check of key input assumptions, model representation, and modeling results. Florid a Electric Power Coordinating Group, Inc., (motion p. 13) claims that EPA recently admitted that its modeling supporting the Transport Rule is “riddled with errors” by virtue of the fact that we proposed in the revisions rule a limited number of adjustment s to the Transport Rule. The scope of the proposed revisions is extremely narrow relative to the overall scope of the rule. For example, out of about 3,632 units covered by the Transport Rule, the proposed revisions affect the modeling of just 3% of thos e units. Furthermore, the revisions were prompted by new information supplied by stakeholders, not by any failure of the modeling itself.

136. Entergy’s claim (Mot. at 9) that the model predicts grossly incorrect utilization levels for many units in Arkansas, Louisiana, and Mississippi is exaggerated. In the revisions proposal, we proposed to make adjustments to projected generation at 17 units in Louisiana, and Mississippi ( and none in Arkansas)

. 74 (Technical Revisions to State Budgets and New Unit Set

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. ) Overall there are 286 units in those three states covered by the Transport Rule. 75

74 This includes the 17 units that have proposed revisions increasing their generation and emissions due to additional information EPA received. This does not incl ude the impact of second

- order effects of reducing generation at other units to offset increased generation at the 17 units

. In other words, we proposed revisions at just 6% of the total units in the se state s . Moreover, as noted above, these revisions are predicated on information that was not available to the Agency during the rulemaking process. Finally, the overall proposed revisions increase seasonal NOx budgets by a total of 2 % in the covered states, which suggests that the revisi ons were not in response to a widespread problem with IPM as Entergy suggests.

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- 4431,47 137. The proposed revisions significantly reduce the difference between 2011 emissions and the proposed revised budgets for Louisiana and Mississippi. If the revisions are finalize d, Louisiana’s 2012 budget would be approximately 22% below their preliminary 2011 emissions (as opposed to 41%). Mississippi’s 2012 budget would be only 8% below their 2011 preliminary emissions. Arkansas’s 2012 budget, unaffected by the prop o sed revisi ons, is only 16% below its 2011 emissions. Additionally, Arkansas 2011 emissions are already within the assurance level finalized in the Transport Rule.

138. The Florida Electric Power Coordinating Group’s claim that it is required to reduce emissions 30% (Motion p. 12) exaggerates the amount of reductions EGUs in Florida will need to achieve from its most recent emissions level, as discussed in the Emission Reduction Requirement section of this declaration. Florida’s 2011 seasonal NOx emissions were only 7 % above their 2012 budget under the finalized Transport Rule. The burden is even lower when the revisions proposed on October 6, 2011 are considered. If the revisions are finalized, Florida’s 2011 ozone season emissions would be 1,068 tons, or about 4%, ab ove their 2012 budget.

139. In Kansas Utilities’ motion (Motion p. 11), BPU’s claim that its SO2 emission allowances will last only until mid

- May assumes that BPU will not make any emission reductions at all, ignoring the fact that the Transport Rule program o ffers incentives to utilities to reduce even those emissions covered by initial allowance allocations, as the allowances have a market value that is forgone if the utility continues to emit. Furthermore, BPU ignores that if EPA’s proposed Transport Rule r evisions are finalized for Kansas, BPU is positioned to receive about 50% more SO2 allowances. Notwithstanding its level of initial allowance allocations, BPU’s arguments asserting an entitlement to historic emissions levels disregard the fundamental goal of the Transport Rule, which is to reduce emissions to improve downwind air quality.

140. Finalization of the proposed revisions would render moot the stay motion from We Energies. In fact, We Energies acknowledges the proposed revisions would implement the change in the assurance provisions that they request and they specifically state that their motion is only a protective measure in the event that the revisions are not finalized.

141. Michigan is already well positioned to comply with the rule as finalized. The proposed revisions further reinforce their capacity to comply. The assurance level amendments in the revisions will eliminate the chance of any potential assurance penalties in 2012

- 13, and the recalculation of the Michigan annual NOx budget means that their 2011 annual NOx emissions is only 14 % above their 2012 budget before any other compliance options are implemented, including existing installed controls or allowance trades.

## ATTACHMENT 1 TO DECLARATION OF SAM NAPOLITANO



# Ohio Valley Electric Corporation Kyger Creek Station

Amended New St ack and FGD System Notification

## ATTACHMENT 2 TO DECLARATION OF SAM NAPOLITANO



# Clean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress ReportClean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report | Progress Reports | Clean Air Markets | Air & Radiation | US EPA

http://www.epa.gov/airmarkets/progress/ARPCAIR10_01.html [10/6/2011 11:36:32 AM] You are here: EPA Home Air & Radiation Clean Air Markets Progress Reports Clean Air Interstate Rule, Acid Rain Program, and Former NO x Budget Trading Program 2010 Progress Report SO 2 and NO x Emissions, Compliance, and Market Analyses Report Clean Air Markets

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### Clean Air Interstate Rule, Acid Rain Program, and Former NO x 

### Budget Trading Program 2010 Progress Report

SO 2 and NO x Emissions, Compliance, and Market Analyses Report

CAIR Litigation and the Cross-State Air Pollution Rule | CAIR, ARP, and NBP Affected States and Units | Emission Reductions | CAIR and ARP Program Compliance | Controls and Monitoring | Market Activity

The Clean Air Interstate Rule (CAIR) and the Acid Rain Program (ARP) are both cap and trade programs designed to reduce emissions of sulfur dioxide (SO 2 ) and nitrogen oxides (NO x ) from power plants. On July 6, 2011, EPA finalized the Cross-State Air Pollution Rule (CSAPR) , which will replace CAIR starting in 2012.

The CSAPR will require 27 states in the eastern half of the U.S. to improve significantly air quality by reducing power plant emissions of SO 2 and NO x that cross state lines and contribute to smog (ground-level ozone) and soot (fine particle pollution) in other states. The first phase of compliance begins January 1, 2012 for SO 2 and annual NO x reductions and May 1, 2012 for ozone season NO x reductions. Additional SO 2 reductions are required by sixteen Group 1 states in 2014 to eliminate their contribution to downwind air quality problems.

CAIR, which will be implemented through 2011, also addresses regional interstate transport of ozone and fine particle (PM 2.5 ) pollution. CAIR requires certain eastern states to limit annual emissions of NO x and SO 2 , which contribute to the
formation of ozone and PM 2.5 . It also requires certain states to limit ozone season NO x emissions, which contribute to the formation of smog during the summer ozone season (May to September). CAIR includes three separate cap and trade programs to achieve the required reductions: the CAIR NO x ozone season trading program, the CAIR NO x annual trading program, and the CAIR SO 2 annual trading program. The CAIR NO x ozone season and annual programs began in 2009, while the CAIR SO 2 annual program began in 2010. All three programs will be implemented through the 2011 compliance periods. The CSAPR will replace CAIR starting in 2012. The reduction in ozone and PM 2.5 formation resulting from implementation of CAIR provides health benefits as well as improved visibility in national parks and improvements in freshwater aquatic ecosystems in the eastern U.S.
The ARP, established under Title IV of the 1990 Clean Air Act (CAA) Amendments, requires major emission reductions of SO 2 and NO x , the primary precursors of acid rain, from the power sector. The SO 2 program sets a permanent cap on the total amount of SO 2 that may be emitted by electric generating units (EGUs) in the contiguous United States. The program is phased in, with the final 2010 SO 2 cap set at 8.95 million tons, a level of about one-half of the emissions from the power sector in 1980. NO x reductions under the ARP are achieved through a program that applies to a subset of coal-fired EGUs and is closer to a traditional, rate-based regulatory system. Since the program began in 1995, the ARP has achieved significant emission reductions.

The NO x Budget Trading Program (NBP) operated from 2003 to 2008. The NBP was a cap and trade program that required NO x emission reductions from power plants and industrial units in the eastern U.S. during the summer months.

Figure 1 contains important milestones for CAIR, ARP, CSAPR, and the former NBP.

Figure 1: History of CAIR, ARP, CSAPR, and Former NBP

Source: EPA, 2011

For the first time, EPA is combining emissions and compliance data for both CAIR and the ARP into one report to more holistically show Air & Radiation Home

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http://www.epa.gov/airmarkets/progress/ARPCAIR10_01.html [10/6/2011 11:36:32 AM] reductions in power sector emissions of SO 2 and NO x and the collective effect of these regional programs on human health and the environment. Over the next several months, EPA will release a series of reports summarizing progress in 2010 under both CAIR and the ARP. This first report presents 2010 data on combined emission reductions and compliance results for CAIR and the ARP. This report also presents some historic NBP emissions data and evaluates shared progress under these programs in 2010 by analyzing emission reductions and market activity. A forthcoming report will compare changes in emissions to changes in a variety of human health and environmental indicators. For more information on the CSAPR, please visit the CSAPR website . For more information on CAIR, please visit the CAIR website . For more information on the ARP, please visit the ARP website . For more information on the NBP, please visit the NO x Budget Trading Program/NO x SIP Call website

.

Top of page CAIR Litigation and the Cross-State Air Pollution Rule

CAIR was finalized in 2005. However, in July 2008, the U.S. Court of Appeals for the D.C. Circuit granted several petitions for review of CAIR, finding significant flaws in the rule. Subsequently, in December 2008, the court issued a ruling to keep CAIR and the CAIR Federal Implementation Plans (FIPs) — including the CAIR trading programs — in place temporarily until EPA issues new rules to replace the CAIR and the CAIR FIPs.
On July 6, 2011, EPA finalized the Cross-State Air Pollution Rule (CSAPR) to replace CAIR. This rule responds to the court’s concerns and fulfills the “good neighbor” provision of the Clean Air Act by addressing the problem of air pollution that is transported across state boundaries.
In a separate but related regulatory action, EPA also issued a supplemental notice of proposed rulemaking (SNPR) to require six states — Iowa, Kansas, Michigan, Missouri, Oklahoma, and Wisconsin — to make summertime NO x reductions under the CSAPR ozone-season control program. Finalizing this supplemental proposal would bring the total number of covered states under the CSAPR to 28.

Visit the CSAPR website for more information.

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CAIR, ARP, and NBP Affected States and Units

Affected States

The ARP is a nationwide program affecting large fossil fuel-fired power plants across the country. CAIR covers 27 eastern states and the District of Columbia (D.C.) and requires reductions in annual emissions of SO 2 and NO x from 24 states and D.C. (to achieve improvements in fine particle pollution in downwind areas) and emission reductions of NO x during the ozone season from 25 states and D.C. (to achieve improvements in ozone pollution in downwind areas). The former NBP affected 20 eastern states and D.C. State coverage for CAIR, ARP, and NBP is shown in Figure 2.

Figure 2: CAIR, ARP, and NBP States

Note: In November 2009, EPA finalized a rule staying the requirements of CAIR for Minnesota. Minnesota is therefore not currently included in the CAIR annual SO 2 and NO x programs.
Source: EPA, 2011

Affected Units

The CAIR SO 2 and NO x annual programs generally apply to large EGUs — boilers, turbines, and combined cycle units that primarily burnClean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report | Progress Reports | Clean Air Markets | Air & Radiation | US EPA

http://www.epa.gov/airmarkets/progress/ARPCAIR10_01.html [10/6/2011 11:36:32 AM] fossil fuels to generate electricity for sale. The CAIR NO x ozone season program includes EGUs as well as, in some states, large industrial units that produce electricity or steam primarily for internal use and that have been carried over from the NBP. Examples of these units are boilers and turbines at heavy manufacturing facilities, such as paper mills, petroleum refineries, and iron and steel production facilities. These units also include steam plants at institutional settings, such as large universities or hospitals.

In 2010, there were 3,349 affected EGUs at 955 facilities in the CAIR SO 2 and NO x annual programs and 3,309 EGUs and industrial facility
units at 953 facilities in the CAIR NO x ozone season program (see Table 1 , below). The variation in the number of units covered under the programs is due to the difference in states that are included in each program (see Figure 2, above ). The CAIR programs cover a range of unit types, including units that operate year round to provide baseload power to the electric grid as well as units that provide power on peak demand days only and may not operate at all during some years.

The SO 2 requirements under the ARP apply to the 3,613 large (greater than 25 megawatts) fossil fuel-fired combustion units that serve a generator that provides electricity for sale at 1,241 facilities across the country. The vast majority of ARP SO 2 emissions result from coalfired EGUs, although the program also applies to oil and gas units. Of the 3,349 units in the CAIR SO 2 program, 2,626 (78 percent) were also covered by the ARP in 2010. The other units are largely fossil fuel generation units that entered SO 2 control under the broader applicability requirements of CAIR.

The ARP also requires NO x emission reductions for older, large coal-fired EGUs by limiting their NO x emission rate (expressed in lb/mmBtu). The goal of the NO x program is to limit NO x emission levels from the affected coal-fired boilers so that their emissions are at least two million tons less than the projected level for the year 2000 without implementation of Title IV. In 2010, 956 units at 379 facilities were subject to the ARP NO x program.

Table 1: Affected Units in CAIR and ARP, 2010

Fuel ARP SO 2 Program ARP NO x Program CAIR NO x Ozone Season Program CAIR NO x and SO 2 Annual Programs

Coal EGUs 1,055 944 875 922

Gas EGUs 2,333 10 1,657 1,945

Oil EGUs 200 0 555 463

Industrial Units 0 0 203 0

Unclassified EGUs 9 0 1 4

Other Fuel EGUs 16 2 18 15

Total Units 3,613 956 3,309 3,349

Notes:

“Unclassified” units have not submitted a fuel type in their monitoring plan and did not report emissions. “Other” fuel refers to units that burn waste, wood, petroleum coke, tire-derived fuel, etc. Source: EPA, 2011
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Emission Reductions

Milestone Years for Measuring Progress under CAIR and ARP

1980: The Clean Air Act specified that annual SO 2 emissions be cut to 10 million tons below the
1980 level
1990: Baseline emission levels for the ARP
1995: First year of the ARP (Phase 1)
2000: Phase 2 of the ARP
2005: Baseline emission levels for CAIR
2008: “Training year” for CAIR NO x monitoring. Units participating in the two CAIR NO x trading programs were required to monitor and report their emissions, but were not required to hold allowances for compliance
2009: First year of CAIR NO x annual and CAIR NO x ozone season programs (Phase 1). “Training year” for CAIR SO 2 monitoring

2010: First year of CAIR SO 2 annual program (Phase 1)

Overall Trends

Table 2 , below, shows a large reduction in annual SO 2 and NO x emissions from CAIR and ARP sources between 2005 and 2010. Tons of
SO 2 emitted fell 49 percent from the 2005 level, and annual NO x emissions dropped 42 percent. During this same period, ozone season
NO x emissions from CAIR sources alone decreased by approximately 27 percent. These reductions occurred while electricity demand (measured as heat input) remained relatively stable, indicating that the reduction in emissions was not driven by decreased electric generation. Instead, there was a significant drop in emission rate for sources in all three programs: 49 percent for SO 2 sources, 42 percent
for annual NO x sources, and 25 percent for ozone season NO x sources. A drop in emission rate represents an overall increase in the environmental efficiency of these sources as power generators installed controls, ran their NO x controls year round, switched to different fuels, or otherwise cut their SO 2 and NO x emissions while meeting relatively steady demand for power. Most of the reductions since 2005 are from early reduction incentives and stricter emission limits under CAIR.

Between 2009 and 2010, CAIR and ARP sources continued to reduce their SO 2 emissions and emission rate. These reductions occurred despite an 8 percent increase in demand for electricity. Annual NO x emissions from CAIR and ARP sources, however, rose slightly (4 percent) and in line with a similar increase in heat input (6 percent) during this time. Finally, CAIR sources’ ozone season NO emissionsClean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report | Progress Reports | Clean Air Markets | Air & Radiation | US EPA

http://www.epa.gov/airmarkets/progress/ARPCAIR10_01.html [10/6/2011 11:36:32 AM] x increased considerably (20 percent) as demand for electricity at these facilities rose substantially (more than 16 percent). Despite these increases in NO x emissions as sources ran their controls less often, facilities were still below both the CAIR NO x ozone season and CAIR
NO x annual budgets for the year.

Visit EPA’s Quarterly Emissions Tracking site for the most up-to-date emissions and control data for sources in the ARP.

Table 2: Comparison of Emissions, Emission Rates, and Heat Input for CAIR, ARP, and NBP Sources, 2000– 2010

CAIR and ARP Annual SO 2 Trends

SO 2 Emissions (thousand tons) SO 2 Rate (lb/mmBtu) Heat Input (billion mmBtu)

Primary Fuel 2000 2005 2008 2009 2010 2000 2005 2008 2009 2010 2000 2005 2008 2009 2010

Coal 10,707 9,835 7,514 5,653 5,089 1.04 0.95 0.74 0.63 0.53 20.67 20.77 20.25 18.02 19.29

Gas 28 36 10 6 7 0.02 0.01 0.00 0.00 0.00 3.71 5.35 6.22 6.50 7.19

Oil 464 347 83 54 44 0.76 0.71 0.35 0.29 0.21 1.22 0.98 0.47 0.37 0.41

Other 1 4 9 8 26 0.23 0.27 0.28 0.27 0.53 0.01 0.03 0.06 0.06 0.10

Total 11,201 10,223 7,616 5,722 5,166 0.88 0.75 0.56 0.46 0.38 25.61 27.13 27.00 24.95 26.99

CAIR and ARP Annual NO x Trends

NO x Emissions (thousand tons) NO x Rate (lb/mmBtu) Heat Input (billion mmBtu)

Primary Fuel 2000 2005 2008 2009 2010 2000 2005 2008 2009 2010 2000 2005 2008 2009 2010

Coal 4,586 3,356 2,816 1,847 1,922 0.44 0.32 0.28 0.20 0.20 20.67 20.77 20.25 18.27 19.29

Gas 321 142 130 133 139 0.17 0.05 0.04 0.04 0.04 3.71 5.35 6.22 6.71 7.19

Oil 195 129 46 34 34 0.32 0.26 0.19 0.18 0.17 1.22 0.98 0.47 0.38 0.41

Other 2 6 5 5 7 0.26 0.42 0.16 0.12 0.13 0.01 0.03 0.06 0.09 0.10

Total 5,104 3,633 2,996 2,020 2,102 0.40 0.27 0.22 0.16 0.16 25.61 27.13 27.00 25.45 26.99

NBP Ozone Season NO x Trends

NO x Emissions (thousand tons) NO x Rate (lb/mmBtu) Heat Input (billion mmBtu)

Primary Fuel 2000 2005 2008 2000 2005 2008 2000 2005 2008

Coal 1,111 494 456 0.46 0.19 0.19 4.85 5.10 4.93

Gas 15 23 17 0.08 0.05 0.04 0.37 0.85 0.85

Oil 34 32 9 0.21 0.21 0.14 0.32 0.31 0.13

Other 0 0 0 0.74 0.50 0.13 0.00 0.00 0.01

Total 1,160 549 482 0.42 0.18 0.16 5.54 6.27 5.91

CAIR Ozone Season NO x Trends

NO x Emissions (thousand tons) NO x Rate (lb/mmBtu) Heat Input (billion mmBtu)

Primary Fuel 2000 2005 2008 2009 2010 2000 2005 2008 2009 2010 2000 2005 2008 2009 2010

Coal 1,398 695 625 442 527 0.45 0.22 0.20 0.17 0.18 6.19 6.31 6.14 5.21 5.85

Gas 62 43 34 33 42 0.15 0.06 0.05 0.04 0.04 0.84 1.47 1.40 1.53 1.96

Oil 83 72 28 19 22 0.29 0.27 0.20 0.18 0.16 0.57 0.53 0.28 0.21 0.27

Other 1 2 2 2 2 0.15 0.17 0.14 0.14 0.12 0.02 0.02 0.03 0.02 0.04

Total 1,545 812 689 495 594 0.41 0.20 0.18 0.14 0.15 7.62 8.33 7.85 6.97 8.12

Notes:

The data shown here for the annual programs and the NBP reflect totals for those facilities required to comply with each program in each respective year. This means that CAIR NO x annual program facilities are not included in the annual NO x data for 2005 or 2008, and CAIR SO 2 annual program facilities are not
included in the annual SO 2 data for 2005, 2008, or 2009.
The CAIR NO x ozone season table includes emissions and heat input data for 2005 that were reported under other programs. For facilities that were not covered by another program and did not report 2005 emissions, their reported emissions for 2008 were substituted. 2008 was a “training year” for facilities covered by the CAIR NO x annual and ozone season programs. 2009 was a monitoring and reporting “training year” for facilities covered by the CAIR SO 2 annual program. Fuel type represents primary fuel type; units might combust more than one fuel. Totals may not reflect the sum of individual rows due to rounding. Each year’s total emission rate does not equal the arithmetic mean of the four fuel-specific rates, as each facility influences the annual emission rate in proportion to its heat input, and heat input is unevenly distributed across the fuel categories. EPA data in these tables and used elsewhere in this report are current as of July 2011, and may differ from past or future reports as a result of resubmissions by sources and ongoing data quality assurance activities. Source: EPA, 2011

SO 2 Emission ReductionsClean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report | Progress Reports | Clean Air Markets | Air & Radiation | US EPA

http://www.epa.gov/airmarkets/progress/ARPCAIR10_01.html [10/6/2011 11:36:32 AM] Figure 3 , below, shows that the CAIR SO 2 program continues and complements the ARP’s history of SO 2 emission reductions. In 2010, the first year of operation of the CAIR SO 2 trading program, sources in both the CAIR SO 2 annual program and the ARP together reduced SO 2 emissions by over 10 million tons (67 percent) from 1990 levels (before implementation of the ARP), 6 million tons (54 percent) from 2000 levels (ARP Phase 2), and 5 million tons (49 percent) from 2005 levels (before implementation of CAIR). All ARP and CAIR sources together emitted a total of 5.2 million tons of SO 2 in 2010, well below the ARP’s statutory annual cap of 8.95 million tons.

Annual SO 2 emissions from sources in the CAIR SO 2 program alone fell from 9 million tons in 2005 to 4.4 million tons in 2010, a 51 percent reduction. Between 2009 and 2010, SO 2 emissions fell 123,000 tons, or 6 percent. However, the 2010 emissions total is higher
than the CAIR SO 2 program’s state budget total of 3.6 million tons, indicating that affected sources used banked allowances carried over from the ARP for compliance with CAIR (see Table 3 , below).

ARP units alone emitted 5.1 million tons of SO 2 in 2010, meaning that ARP sources reduced emissions by 10.6 million tons (67 percent) from 1990 levels and 12.1 milllion tons (70 percent) from 1980 levels.

Figure 3: SO 2 Emissions from CAIR SO 2 Annual Program and ARP Sources, 1980–2010

Note: For CAIR units not in the ARP, the 2009 annual SO 2 emissions were applied retroactively for each pre-CAIR year following the year in which the unit began operating. Source: EPA, 2011

The states with the highest emitting sources in 1990 have generally seen the greatest SO 2 reductions under the ARP, and this trend continues under CAIR (see Figure 4 , below). Most of these states are upwind of the areas the ARP and CAIR were designed to protect, and reductions have resulted in important environmental and health benefits over a large region.

From 1990 to 2010, annual SO 2 emissions in the nationwide ARP dropped in 40 states and D.C. by a total of approximately 10.5 million tons. In contrast, annual SO 2 emissions increased by a total of only 30,700 tons in eight states (Idaho, Louisiana, Montana, North Dakota, Nebraska, Oregon, Rhode Island, and Vermont) from 1990 to 2010.

Between 2005 and 2010, annual SO 2 emissions fell in all 27 states in the CAIR region with the exception of Arkansas and D.C., which increased emissions by a total of only 933 tons. Sixteen states and D.C. exceeded their state SO 2 emission budgets.

Figure 4: State-by-State Annual SO 2 Emission Levels for CAIR and ARP Sources, 1990–2010Clean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report | Progress Reports | Clean Air Markets | Air & Radiation | US EPA

http://www.epa.gov/airmarkets/progress/ARPCAIR10_01.html [10/6/2011 11:36:32 AM] Note: State-level data shown in this map are available for download. Source: EPA, 2011

Thirty-five ARP units installed SO 2 controls in 2010, reducing their collective SO 2 emission rate from 1.15 lb/mmBtu in January to 0.10 lb/mmBtu in December. The remaining sources in the ARP reported a steady annual SO 2 rate of about 0.41 lb/mmBtu (see Figure 5

, below). Had these newly-controlled units maintained their collective annual 2009 emission rate of 1.20 lb/mmBtu through 2010, their estimated emissions would have remained around a half million tons. In actuality, the 35 units emitted 64 percent less SO 2 in 2010 than in 2009 by adding scrubbers, contributing about half of the total program-wide reduction of 600,000 tons between 2009 and 2010. Because the new controls were installed at different times throughout 2010, the annual reduction reflects only partial operation, and the overall benefits of the new systems will be even greater in 2011.

Figure 5: Monthly SO 2 Emission Rates, 2010

Source: EPA, 2011

NO x Emission Reductions

Ozone Season NO x Reductions

Figure 6 , below, shows ozone season NO x emissions from 1990 to the present for CAIR and NBP sources. In 2010, the second year of the
CAIR NO x ozone season program, sources from both CAIR and the former NBP, together with a small number of sources that were previously in the NBP but did not enter CAIR, reduced their overall NO x emissions from 816,000 tons in 2005 (before implementation of CAIR) to 599,000 tons in 2010, a decrease of 27 percent. NO x emissions were nearly 1.5 million tons lower (71 percent) than in 1990 and 860,000 tons lower (59 percent) than in 2000 (before implementation of the NBP).Clean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report | Progress Reports | Clean Air Markets | Air & Radiation | US EPA

http://www.epa.gov/airmarkets/progress/ARPCAIR10_01.html [10/6/2011 11:36:32 AM] Between 2005 and 2010, ozone season NO x emissions from sources in the CAIR program alone have fallen 211,000 tons, a decrease of 22 percent. From 2009 to 2010, however, ozone season NO x emissions from sources in the CAIR NO x ozone season program increased by 99,000 tons (20 percent) as sources operated controls less often and electricity demand rose. Despite the year-over-year increase, ozone season NO x emissions totaled 594,000 tons in 2010, 5 percent below the 2010 regional emission budget of 624,698 tons.

Figure 6: Ozone Season NO x Emissions from CAIR and NBP Sources, 1990–2010

Note: For CAIR units not in the NBP, the 2008 NO x emissions were applied retroactively to 1990 and 2000 if the unit operated in the previous year’s ozone

season. Source: EPA, 2011

The average NO x emission rate is a key measure of program effectiveness. While emissions may vary year to year due to changes in electricity demand the average ozone season NO x emission rate has fallen every year since 2004 — except 2010. The driver of the increase
in rate was coal-fired units with add-on controls. The NO x emission rate at these units, which are historically responsible for the deepest reductions, increased as a group over 14 percent from 2009 to 2010.

Ozone season NO x mass emissions rose about 99,000 tons between 2009 and 2010. Nearly a third of the increase (28,192 tons) resulted from fifty coal-fired units with add-on controls that posted significantly poorer performance in 2010. These fifty units “dialed back” control removal efficiency or even turned installed controls off. At 24 units, the 2010 NO x emission rate was double that of 2009. In an emissions trading program, operators of plants are assumed to optimize operations by balancing the costs of fuel, allowances, and running controls. For example, the relatively low cost of gas drove the 35 percent increase in gas-fired generation in 2010. Similarly, the drop in allowance prices could lead to a higher NO x emission rate. EPA expects the average NO x emission rate to continue to improve in future years under the regulatory certainty provided by CSAPR. The higher NO x allowance prices that should exist in 2012 under CSAPR would provide incentive for sources to improve the effectiveness of existing pollution controls.

Between 2005 and 2010, ozone season NO x emissions from CAIR and former NBP sources fell in every state participating in the CAIR NO x ozone season program except Pennsylvania, Arkansas, Kentucky, and D.C. (see Figure 7 , below), where emissions increased by a total of 15,000 tons. In the 2010 ozone season, the total emissions from participating sources were about 31,000 tons below the regional emission budget. Sixteen states had emissions below their allowance budgets, collectively by about 80,000 tons. Another ten states exceeded their 2010 budgets by a total of about 49,000 tons, indicating that, on an aggregate basis, sources within those states covered a portion of their emissions with allowances banked from earlier years, transferred from an out-of-state account, or purchased from the market.

Figure 7: State-by-State Ozone Season NO x Emission Levels from CAIR Sources, 2000–2010Clean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report | Progress Reports | Clean Air Markets | Air & Radiation | US EPA

http://www.epa.gov/airmarkets/progress/ARPCAIR10_01.html [10/6/2011 11:36:32 AM] Notes:

State-level data shown in this map is available for download. The 2000 and 2005 ozone season values reflect data that were reported under other programs (ARP and NBP). For facilities that were not covered by another program and did not report 2000 or 2005 emissions, their reported emissions for the earliest subsequent year (usually the 2008 training year) were substituted. Source: EPA, 2011

In addition to the CAIR NO x ozone season program and the former NBP, prior programs such as the Ozone Transport Commission’s (OTC)
NO x Budget Program and current regional and state NO x emission control programs have also contributed significantly to the ozone season
NO x reductions achieved by sources in 2010.

High Electric Demand Days

Ozone season demand for electricity is driven by economic conditions and weather. Figure 8 , below, compares 2009 and 2010 ozone season daily NO x emissions and generation (as measured by gross megawatt hours), and highlights the ten days of each year's peak generation. Comparing the ten peak generation days in 2009 to 2010, generation increased 14 percent, NO x emissions grew proportionately (17 percent), while the NO x emission rate increased by less than two percent. The fact that the NO x rate during the ten days of highest electric demand remained below the ozone season average implies that the increased demand did not result in less efficient, higher-emitting units being called into service, as had historically been the case.

Figure 8: Ozone Season Daily NO x Emissions and GenerationClean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report | Progress Reports | Clean Air Markets | Air & Radiation | US EPA

http://www.epa.gov/airmarkets/progress/ARPCAIR10_01.html [10/6/2011 11:36:32 AM] Source: EPA, 2011

Annual NO x Reductions

Figure 9 , below, shows that from 1990 to 2010, annual NO x emissions from CAIR and ARP units together dropped by about 4.3 million tons to 2.1 million tons, a decrease of 67 percent. In 2010, the second year of the CAIR NO x annual program, NO x emissions from all ARP and CAIR units were 1.5 million tons lower (42 percent) than in 2005 and 3 million tons lower (59 percent) than in 2000.

Emissions from CAIR NO x annual program sources alone were 1.43 million tons in 2010, 73,000 tons (5 percent) below the 2010 CAIR NO x annual program’s regional budget of 1.5 million tons. Annual NO x emissions were 1.2 million tons lower (47 percent) than in 2005, butClean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report | Progress Reports | Clean Air Markets | Air & Radiation | US EPA

http://www.epa.gov/airmarkets/progress/ARPCAIR10_01.html [10/6/2011 11:36:32 AM] were 115,000 tons (9 percent) higher than in 2009. This recent increase was largely a result of sources not operating NO x controls as often and increased demand for electricity.

ARP sources emitted 2.1 million tons of NO x in 2010. This level is 6 million tons less than the projected level in 2000 without the ARP, and triple the Title IV NO x emission reduction objective.

Although the ARP and CAIR NO x programs were responsible for a large portion of these annual NO x reductions, other programs — such as the NBP, the OTC NO x Budget Program, and other regional and state NO x emission control programs — also contributed significantly to the
annual NO x reductions achieved by sources in 2010.

Figure 9: Annual NO x Emissions from CAIR and ARP Sources, 1990–2010

Note: For CAIR units not in the ARP in 1990, 2000, and 2005, the 2008 annual NO x emissions were applied retroactively for each pre-CAIR year following the year in which the unit began operating. Source: EPA, 2011

Figure 10 , below, shows that, compared with 2005, before implementation of CAIR, sources in the CAIR NO x annual program continued to reduce year-round emissions in 2010 as program participants operated NO x control devices on EGUs outside the summer months. From 2005 to 2010, NO x emissions from units in the CAIR NO x annual program and ARP fell 42 percent, while heat input remained stable, falling less than one percent.

Figure 10: Monthly Emissions and Heat Input from CAIR NO x Annual Program Sources, 2005 vs. 2010

Note: The CAIR NO x annual program had not begun in 2005, so the set of participating units from 2008 was used as the 2005 baseline in this figure. Facilities that were not covered by the ARP did not report emissions in 2005. For these facilities, the earliest subsequent reported values, usually from the 2008 CAIR training year, were substituted. Source: EPA, 2011

From 1990 to 2010, all states participating in the CAIR NO x annual program decreased their emissions, as indicated in Figure 11 , below. Comparing 2005 to 2010, all states in the CAIR region emitted less NO x except Delaware and D.C., which increased their NO x emissions by
855 tons. The total NO x emissions from participating sources in 2010 were about 55,000 tons below the regional emission budget of 1,490,264 tons. Ten states and D.C. exceeded their 2010 budgets by a total of about 109,000 tons, indicating that, on an aggregate basis,sources within those states covered a portion of their emissions with allowances banked from earlier years, transferred from an out-ofstate account, or purchased from the market.

Figure 11: State-by-State Annual NO x Emission Levels for CAIR and ARP Sources, 1990–2010Clean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report | Progress Reports | Clean Air Markets | Air & Radiation | US EPA

http://www.epa.gov/airmarkets/progress/ARPCAIR10_01.html [10/6/2011 11:36:32 AM] Note: State-level data shown in this map is available for download. Source: EPA, 2011
Top of page CAIR and ARP Program Compliance

SO 2 Programs

Because SO 2 allowances from the ARP are used by sources to comply with the CAIR SO 2 annual program, compliance results for both programs are displayed together in this report. Table 3 , below, shows how ARP and CAIR allowances were used. All ARP and CAIR SO 2 facilities were in compliance with both programs and held enough allowances to cover their SO 2 emissions.

Table 3: CAIR and ARP SO 2 Allowance Reconciliation Summary, 2010

Total Allowances Held (1995–2010 Vintage) 21,505,185
Affected Facility Accounts: 14,599,394
Other (General and Non-Affected Facility Accounts): 6,905,791
Allowances Deducted for Acid Rain Compliance* 5,081,366
Penalty Allowance Deductions (2011 Vintage) 0
Banked Allowances (prior to CAIRSO 2 deductions) 16,423,819

Affected Facility Accounts: 9,518,028
Other (General and Non-Affected Facility Accounts): 6,905,791
Acid Rain Program Allowances Deducted for CAIR SO 2 Compliance 1,188,678

Banked Allowances 15,235,141
Affected Facility Accounts: 8,329,350
Other (General and Non-Affected Facility Accounts): 6,905,791

*Includes 6,111 allowances deducted from opt-ins for reduced utilization.

Compliance Results As of July 2, 2011, the reported 2010 SO 2 emissions by CAIR and ARP sources totaled 5,166,487 tons. Because of variation in rounding conventions, changes due to resubmissions by sources, and allowance compliance issues at certain units, this number is lower than the sums of emissions used for reconciliation purposes shown in Table 3 , above. Therefore, the allowance totals deducted for actual emissions in Table 3 differ from the number of emissions shown elsewhere in this report.

CAIR and ARP SO 2 Programs
Reported emissions (tons): 5,166,487 Compliance issues, rounding, and report resubmission adjustments (tons): –45,912
Emissions not covered by allowances (tons): 0Clean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report | Progress Reports | Clean Air Markets | Air & Radiation | US EPA

http://www.epa.gov/airmarkets/progress/ARPCAIR10_01.html [10/6/2011 11:36:32 AM] Additional vintage 2010 allowances deducted for CAIR: +1,143,358 Total allowances deducted for emissions (includes some 2 for 1 CAIR deductions: 6,263,933

2010 was the first year for compliance with the CAIR SO 2 program. Under this program, allowances are used to cover emissions based on the vintage year of the allowances, with pre–2010 vintage allowances used at 1 allowance for 1 ton of SO 2 emissions, and 2010 vintage allowances used at 2 allowances for 1 ton. For facilities covered by both CAIR and the ARP, reconciliation is a two-step process. First, ARP deductions are made. Then, any additional deductions to comply with the CAIR SO 2 program are made. The additional deductions under CAIR could be to cover the 2 for 1 use of 2010 allowances or to cover emissions for units that are subject to CAIR, but not the ARP.

In 2010, almost 22 million SO 2 allowances were available for compliance under both programs (9 million vintage 2010 and almost 13 million banked from prior years). Just over 5 million allowances were deducted for ARP compliance and an additional 1.2 million allowances were deducted to complete reconciliation for CAIR. After reconciliation for both programs, over 15.2 million ARP SO 2 allowances were banked and carried forward to the 2011 compliance year.

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NO x Programs

CAIR NO x Compliance Results

Tables 4 and 5 , below, show how NO x allowances were used in 2010. All covered facilities were in compliance with the CAIR NO x annual and ozone season programs and held enough allowances to cover their NO x emissions.

Table 4: CAIR NO x Ozone Season Allowance Reconciliation Summary, 2010

Total Allowances Held (2003–2010 Vintage) 1,002,016
Affected Facility Accounts: 873,775
Other (General, State Holding and Non-Affected Facility Accounts): 128,241

Allowances Deducted for CAIR NO x Ozone Season Trading Program 587,127
Penalty Allowance Deductions (2011 Vintage) 0

Banked Allowances 414,889
Affected Facility Accounts: 286,648
Other (General, State Holding and Non-Affected Facility Accounts): 128,241

Table 5: CAIR NO x Annual Allowance Reconciliation Summary, 2010

Total Allowances Held (2009–2010 Vintage) 1,823,717
Affected Facility Accounts: 1,723,440
Other (General, State Holding and Non-Affected Facility Accounts): 100,277

Allowances Deducted for CAIR NO x Annual Trading Program 1,420,621
Penalty Allowance Deductions (2011 Vintage) 0

Banked Allowances 403,096
Affected Facility Accounts: 302,819
Other (General, State Holding and Non-Affected Facility Accounts): 100,277

Compliance Results As of July 3, 2011, the reported 2010 ozone season NO x emissions by CAIR sources totaled 593,669 tons, and annual emissions totaled 1,427,301 tons. Because of variation in rounding conventions, changes due to resubmissions by sources, and allowance compliance issues at certain units, these numbers are different from the sums of emissions used for reconciliation purposes shown in Table 4 (ozone season reconciliation) and Table 5 (annual reconciliation). Therefore, the allowance totals deducted for actual emissions in Tables 4 and 5 differ from the number of emissions shown elsewhere in this report.

CAIR NO x Ozone Season
Reported emissions (tons): 593,669 Compliance issues, rounding, and report resubmission adjustments (tons): –6,542
Emissions not covered by allowances (tons): 0
Total allowances deducted for emissions: 587,127
CAIR NO x Annual Program
Reported emissions (tons): 1,427,301 Compliance issues, rounding, and report resubmission adjustments (tons): -6,680
Emissions not covered by allowances (tons): 0
Total allowances deducted for emissions: 1,420,621Clean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report | Progress Reports | Clean Air Markets | Air & Radiation | US EPA

http://www.epa.gov/airmarkets/progress/ARPCAIR10_01.html [10/6/2011 11:36:32 AM] On May 1, 2009, the NBP transitioned to the CAIR NO x ozone season program and transferred a total of 275,367 allowances from the NBP
to the CAIR NO x ozone season program. By the end of the 2009 ozone season, 392,799 allowances were banked and available for program compliance in 2010. Because NO x emissions in the 2010 ozone season were below the CAIR budget, sources were able to bank additional allowances, leaving 414,889 allowances available for use in 2011.

Under the CAIR NO x annual program, 342,975 allowances were carried over from 2009. Because annual NO x emissions in 2010 were also below the CAIR budget, after reconciliation, 403,096 allowances remained in the bank to be carried over into 2011.

ARP NO x Compliance Results

The ARP NO x Program does not impose a cap on NO x emissions and does not rely on allowance trading. The program allows affected sources to comply either by meeting a unit-specific emission rate or by including two or more units in an emission rate averaging plan. These options provide affected sources with the flexibility to meet the NO x emission reduction requirements in a cost-effective manner. In 2010, all 956 units that were subject to the ARP NO x Program achieved compliance.

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To meet the ARP and CAIR emission reduction targets, some sources opt to install control technologies. A wide set of controls are available to help reduce emissions. The following is an analysis of controls on ARP and CAIR program coal-fired units and CAIR NO x program combined cycle units in 2010.

SO 2 Controls in 2010

The wide variety of SO 2 control options available to sources includes switching to low sulfur coal or employing various types of flue gas desulfurization units (FGDs), such as fluidized bed limestone units. FGDs on coal-fired generators are the principal means of controlling SO 2 . As discussed in detail above, 35 units in the ARP added new SO 2 controls in 2010. Sources added FGDs at 34 of the units in the CAIR
SO 2 annual program. Across both programs the share of generation, measured in megawatt hours (MWh), at controlled units was 60 percent of coal-fired generation in 2010 (see Table 6 , below).

Table 6: SO 2 Controls in 2010 on Coal-Fired Units in the ARP and CAIR Annual SO 2 Program

SO 2 Control Type Number of Units Share of Units Share of MWh Generation

FGD 427 38% 59%

Other 44 4% 1%

Uncontrolled 643 58% 39%

Note: Due to rounding, percentages shown may not add up to 100%. Source: EPA, 2011

NO x Controls in 2010

Sources have a variety of options by which to reduce NO x emissions. New selective catalytic reduction units (SCRs), the most efficient NO x controls, were installed at five generation units under the CAIR NO x ozone season program in 2010. Units with add-on controls — SCR or selective non-catalytic reduction (SNCR) — accounted for nearly two-thirds of coal-fired generation (59 percent) and 80 percent of generation at combined cycle units (gas- or oil-fired). Although 124 coal-fired units and 15 combined cycle units remain uncontrolled, they represent only two percent of coal-fired generation and one percent of combined cycle generation under the CAIR NO x ozone season program (see Table 7 , below).

Table 7: NO x Controls in 2010 CAIR NO x Ozone Season Program

NO x Control Type Number of Coal-Fired Units Share of Coal-Fired MWh Generation Number of Combined Cycle Units (Gas- or Oil-Fired) Share of Combined Cycle (Gas- or Oil-Fired) MWh Generation

Combustion 446 37% 66 13%

Non-Controlled 124 2% 15 1%

Other Control 38 1% 91 6%

SCR 207 51% 317 80%

SNCR 127 8% 0 0%

Note: Due to rounding, percentages shown may not add up to 100%. Source: EPA, 2011

Seven sources in the CAIR NO x annual program installed add-on controls in 2010. The 347 coal-fired units with add-on controls (either SCRs or SNCRs) generated 57 percent of annual generation, and the 379 combined cycle units with SCRs generated 75 percent of annual generation (see Table 8 , below). Similar to the CAIR NO x ozone season program, uncontrolled units represent two percent of coal-fired generation and one percent of combined cycle generation under the CAIR NO x annual program.

Table 8: NO x Controls in 2010 CAIR NO x Annual Program

Share of Combined CycleClean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report | Progress Reports | Clean Air Markets | Air & Radiation | US EPA

http://www.epa.gov/airmarkets/progress/ARPCAIR10_01.html [10/6/2011 11:36:32 AM] NO x Control Type Number of Coal-Fired Units Share of Coal-Fired MWh Generation Number of Combined Cycle Units (Gas- or Oil-Fired) (Gas- or Oil-Fired) MWh Generation

Combustion 436 38% 120 20%

Non-Controlled 99 2% 19 1%

Other Control 40 2% 88 4%

SCR 222 49% 379 75%

SNCR 125 8% 0 0%

Note: Due to rounding, percentages shown may not add up to 100%. Source: EPA, 2011
Continuous Emission Monitoring Systems

Accurate and consistent emissions monitoring is the foundation of a cap and trade system. EPA has developed detailed procedures (40 CFR Part 75) to ensure that sources monitor and report emissions with a high degree of precision, accuracy, reliability, and consistency. Sources use continuous emission monitoring systems (CEMS) or other approved methods. Part 75 requires sources to conduct stringent quality assurance tests of their monitoring systems, such as daily and quarterly calibration tests and a semiannual or annual relative accuracy test audit. These tests ensure that sources report accurate data and provide assurance to market participants that a ton of emissions measured at one facility is equivalent to a ton measured at a different facility.

While many CAIR units with low levels of emissions did not have to use CEMS, the vast majority of NO x emissions — over 99 percent — were measured by CEMS. Similarly, CEMS monitored over 99 percent of SO 2 emissions including 100 percent from coal-fired units and 18 percent from oil-fired units. Coal-fired units were required to use CEMS for NO x concentration and stack gas flow rate to calculate and
record their NO x mass emissions. Oil-fired and gas-fired units could use a NO x CEMS in conjunction with a fuel flow meter to determine
NO x mass emissions. Alternatively, for oil-fired and gas-fired units that either operated infrequently or had very low NO x emissions, Part 75 provided low-cost alternatives to conservatively estimate NO x mass emissions. The relatively low percentage for oil-fired units with CEMS is consistent with the decline in oil-fired heat input, as most of these units were used infrequently and qualified for reduced monitoring.

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SO 2 Allowance Market in 2010

Over the first decade of the ARP, allowance prices were stable and significantly lower than projected. When CAIR was proposed in late 2003, allowance prices were influenced by the more stringent CAIR SO 2 budget and the new compliance deadlines. With the start of the
CAIR SO 2 program in 2010, the Acid Rain SO 2 market essentially has become the CAIR SO 2 market. See Table 9 , below, for a summary of
the 2010 SO 2 allowance market.

Table 9: SO 2 Allowance Market in Brief (close of 2010)

Total Value of the SO 2 Allowance Market: $290 million

Average Nominal Price: $19 per ton
Total Allowance Volume (Allowable Emissions): 15,233,537

Note: Total value of allowance market is a snapshot based on the average nominal price as of December 2010 ($19/ton) and total allowance volume available for 2010 compliance. Source: EPA, 2011 and CantorCO2e Market Price Index, 2011

NO x Allowance Markets in 2010

The 2010 CAIR NO x ozone season allowance market continued its price decline from the previous year closing at the end of December at $30 per ton (see Figure 12 ). The annual NO x allowance price, as reported by the CantorCO2e Market Price Index, climbed briefly to $716 early in 2010 and then declined to $325 per ton by the end of the year.

Figure 12: NO x Annual and Ozone Season Allowance Spot Price (Prompt Vintage), January — December 2010

Note: Prompt vintage is the vintage for the current compliance year. Source: EPA, 2011 and CantorCO2e Market Price Index, 2011Clean Air Interstate Rule, Acid Rain Program, and Former NOx Budget Trading Program 2010 Progress Report | Progress Reports | Clean Air Markets | Air & Radiation | US EPA

http://www.epa.gov/airmarkets/progress/ARPCAIR10_01.html [10/6/2011 11:36:32 AM] EPA Home Privacy and Security Notice Contact Us
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Last updated on Thursday, October 06, 2011 In 2010, the second year of the CAIR ozone season and annual NO x programs, CAIR sources emitted about 594,000 tons of NO x during the ozone season (May through September), a 20 percent increase from 2009 levels, but still below the overall budget. CAIR sources emitted about 31,000 tons less than their overall ozone season budget, resulting in about 415,000 banked allowances. Not surprisingly, the downward tendency of ozone season allowance prices continued through most of 2010. Emissions of CAIR annual NO x were 1.4 million tons, about 82,000 tons less than the overall budget. The CAIR annual NO x bank grew to more than 400,000 allowances.

Generally, sources in a cap and trade program may consider several emission reduction alternatives and are allowed to trade allowances as part of their compliance strategies. By allowing trades, the overall market can achieve emission targets at a lower cost than through a command and control program because abatement costs are not the same for all sources. A market for emission allowances will emerge, and the allowance price will reflect the marginal cost of emission reductions. Emission control decisions will be made based on the cost of control options relative to the market price of allowances. The allowance price motivates those who have relatively low cost opportunities for emission reductions to make those investments and then sell their surplus allowances to those with higher marginal abatement costs. Looking at the CAIR NO x ozone season allowance market, it has been EPA’s expectation that the CAIR annual NO x cap would be the binding constraint and absorb most of the capital costs of controls (i.e., SCRs), while the NO x ozone season allowance prices would primarily be driven by operating costs. As expected, the current CAIR NO x allowance prices are below the total expected control cost. However, in the middle of 2010, CAIR annual NO x allowance prices dipped below $500 per ton — the variable SCR cost and theoretical floor price — and remained there through the rest of the year.
Transaction Types and Volumes

Allowance transfer activity includes two types of transfers: EPA transfers to accounts and private transactions. EPA transfers to accounts include the initial allocation of allowances by states or EPA, as well as transfers into accounts related to special set-asides. This category does not include transfers due to allowance retirements. Private transactions include all transfers initiated by authorized account representatives for any compliance or general account purposes.

To help better understand the trends in market performance and transfer history, EPA classifies private transfers of allowance transactions into two categories:

Transfers between separate and distinct economic entities, which may include companies with contractual relationships such as power purchase agreements, but excludes parent-subsidiary types of relationships. These transfers are categorized broadly as “economically significant trades.” Transfers within a company or between related entities (e.g., holding company transfers between a unit compliance account and any account held by a company with an ownership interest in the unit).

While all transactions are important to proper market operation, EPA follows trends in the economically significant transaction category with particular interest because these transactions represent an actual exchange of assets between unaffiliated participants. In 2010, about a third of each program’s traded allowances were exchanged between unrelated parties, often with a broker facilitating the trade (see Table 10 , below).

Table 10: 2010 Allowance Transfers under CAIR and ARP

Program Transfer Type Number of Allowances Transferred Share of Program Allowances Transferred

CAIR NO x Ozone Season Distinct Organizations 132,854 36%
Related Organizations 237,151 64%

CAIR NO x Annual Distinct Organizations 344,758 39%
Related Organizations 540,267 61%

ARP and CAIR SO 2 Annual Distinct Organizations 3,009,858 33%
Related Organizations 6,056,910 66%

Note: Due to rounding, percentages shown may not add up to 100%. Source: EPA, 2011

Brokers play an important role in the emissions allowance markets. They primarily facilitate and conduct trades between willing buyers and sellers, undertaking the direct costs of identifying trading partners and transacting sales at a price acceptable to both parties. In the allowance trading market, the fees charged by brokerage firms are often considered to be transaction costs. These costs associated with buying and selling allowances are generally low.

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