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 the 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 programs.

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 pursuant 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 headquarters. 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 trading 
2

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 programs 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 Policy 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 Program. 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, data 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 reduction 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 season 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 annual 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 the 
3

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 initial 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 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. 
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 August. 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 that 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 SO2 Group 1 allowances at $2,600 and a price for each of annual and 

ozone-season NOx 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 introductory 

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 allowance 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 SO2, 

$600-800 for Group 2 SO2, and $800-1800 for both Annual NOx and Ozone Season NOx.

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. This 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 replacement 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 Daily 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://www.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 resulted 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 SO2 allowances, 50,000 each from 

2012 and 2013 markets, along with an undisclosed amount of annual and ozone season 

NOx allowances. This auction provided a significant injection of liquidity into the market 

by a single entity, further indication 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 another 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 flexibility 

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 utilityspecific 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, the Transport Rule state budgets for 2012 do 

not, in fact, require any new (unplanned) post-combustion control installations, relying 

instead on immediate-term emission reductions available from optimization of existing 

control equipment, anticipated reductions from additional control equipment already 

slated 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%20FES%20Successfully%20Concludes%20Emission%20Allowance%20Auction.pdf>.
6

electricity 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 SO2 and NOX 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 stringencies of the final rule and the proposal are highly comparable as

the projected costs 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 budgets 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 starts 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 budgets) 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 projections of baseline emissions using updated information provided by 

commenters.

Kansas Utilities

21. Data 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, preliminary 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 season. 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 projects 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 tons. 

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 Banister 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 tons8 and the Florida 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 difference 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 to 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 

considered 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 

Budget10

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 states 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 calculate 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, Louisiana, 

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 

total of 187,072 tons of emissions in 201111 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 budgets 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 these 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, 2011
9

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 Utilities’ 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 below, 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 regarding 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 ozoneseason 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 when it argues that “EPA did not intend to require 

Entergy States to reduce emissions”.13

 13 On page 14 of their motion, Entergy claims 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 cost-effective emission reductions.”

As explained in the preamble to the final rule, the 

state budgets were set based on projected state emissions at a cost threshold of $500 

per ton. In the states referenced 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 were 
10

subject to the cost threshold 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 downwind 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 threshold, (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 NOx allocation 

in the final rule, 603 tons, 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 difference between actual NOx emissions from the City’s units 

and the number of their allocated allowances as. Ames’ annual NOx emissions have 

been steadily decreasing. Actual annual NOx 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 budget (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 Annual NOx

(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 

SO2 emissions and the number of SO2 allowances allocated to it. Based on the last four 

quarters, MEAG SO2 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 allowances 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 Energies’ 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. Recent emissions data demonstrates that total EGU emissions in Michigan are unlikely 

to exceed the state’s assurance level in 2012. As demonstrated in the table below, total 

EGU SO2 emissions in Michigan are well below the 2012 assurance level, and have been 

trending downwards, see table below. In addition, total EGU NOx 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 supports, 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-HQ-OAR-2009-0491-4426 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, Docket #EPA-HQ-OAR-2009-0491-2851.
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 state'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 purchases are implemented.

2010 and 2011 SO2

(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 NOX

(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 Document “Analysis 

to Quantify Significant Contribution” EPA-HQ-OAR-2009-0491-4456). 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 responsibility.19

 18U.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 micrograms/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 to 
13

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 without Georgia’s state rule.

State of Ohio

40. The final rule’s state budgets, including the state budget for Ohio, factored 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 facility, Sammis, provide an 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 state’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 reasonable and 

obvious, not “arbitrary”, updates to the modeling contributed to tighter budgets in 2012 

in the final Transport Rule relative to the proposed 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 

retirements (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 significant 

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 emissions 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-HQ-OAR-2009-0491-2657
14

Expected or Potential Sources of “On the Way” 2012 SO2 Emission Reductions in Ohio*

(Tons)

Source of SO2 Emission Reduction Tons of SO2 Reduction

FGD installation at Kyger Creek21 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 Shore Facility due to reduced 

demand

7,000

Announced reduced operation at Ashtabula Facility due to reduced 

demand22

5,000

*Reductions from 2010 emission levels

43. These types of “on the way” reductions will facilitate compliance with 2012 state 

budgets and 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 levels 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 Ohio 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” First Energy, News 

Release. August 12, 2010. Retrieved at http://investors.firstenergycorp.com/phoenix.zhtml?c=102230&p=irolnewsArticle&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 highly focused, peer-reviewed, and publicly-reviewed tool that is populated with highquality 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 

insufficient 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 

construction, planned retirements, announced installation of controls, and myriad statelevel environmental regulations.

46. IPM incorporates factors that affect the trend of future EGU emissions, including 

announced unit retirements and controls that are planned 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 projections may be expected 

to, and in fact frequently do, differ from historically 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 “Entergy 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 transmission 

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/epaipm/transport.html).

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 detail 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-HQ-OAR-2009-

0491-2847)
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 

and other reliability rules imposed on transmission systems, were not altered or 

modified in any significant way27 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 supportable 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, and 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 rulemaking. 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 economic 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 issues 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 the 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 budgets 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 stakeholders, 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 NERC 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 

that projections are consistent with regional resource adequacy.

 29 “IPM is a least cost model 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 projecting 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 any 

predictive model” Transport Rule IPM Assumptions Response to Comment document (EPA-HQ-OAR-2009-0491-

4512).

30 “EPA believes that it is reasonable to use IPM for determining state budgets. While there is significant potential 

variation at the unit level which 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 between 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 level 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-HQ-OAR-2009-0491-4513).
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 limits 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 dispatch 

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 comments arguing that IPM’s structural 

limitation in addressing unit-level transmission detail meant that EPA should not base 

unit-level allowance allocations on IPM unit-level projections. In response to these 

comments, EPA based final unit-level allowance allocations 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 constraints 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 determine 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-HQ-OAR-2009-0491-0309), Section 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 supported 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 projects a cost-effective compliance pattern at the state 

and regional level subject to regional reserve margin constraints. Units 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 IPM Projections for the Transport Rule” 

(docket ID # EPA-HQ-OAR-2009-0491-4455). 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 Term 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 (MATS, 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 compliance 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 only 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 rules 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 reserve 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 

other 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 letter 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). There is no basis for SPP’s assumption that these 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 dispatch 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 201034. 

59. The SPP analysis 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. The 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. The fact that a unit is shown in 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 unitlevel 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 reliability.

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 

might 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 conditions 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.camddataandmaps.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 data 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 interregional 

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 this 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 considered

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 

consistent 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. There is nothing to suggest 

that Ames will not be able to meet peak summer demands 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 regions, 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/v410/Chapter3.pdf.
22

State of Alabama, Mississippi 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 

incompatible 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. The 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% reserve 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 database 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 moderate case38

 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-HQ-OAR-2009-0491, 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 additional allowances, that fuel switching 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 becoming 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 margins approved by the 

North American Electric Reliability Corporation (NERC) [Resource Adequacy and 

Reliability in the IPM Projections for the Transport Rule TSD, Document ID: EPA-HQOAR-2009-0491-4399]. Furthermore, EPA’s analysis shows the Florida Reliability 

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 supported 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 low 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 sulfur 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 former 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 subbituminous 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 development 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 spot 
24

markets,39 and 97% of new fuel contracts are short term (less than 5 years).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 contract 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 is 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-HQ-OAR-2009-0491-4529.)

71. EPA’s IPM modeling allows a limited amount of biomass co-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 Rule. 

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) postcombustion 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 emitters 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 premise 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.html
25

claims regarding the feasibility of installing FGD by 2014 are not relevant 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 characterizes 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 in the 

proposal. In 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. at 45,291). It

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 (75 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 (Transport 

Rule Primary Response to Comments, Section IV.E. Document ID: EPA-HQ-OAR-2009-

0491-4513) and used a method it 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 enough 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-season 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 Energy 

Balance.” http://38.96.246.204/cneaf/electricity/page/eia906_920.html Accessed November 30, 2011. 

42 Calculated from file TR_Remedy_Final.CAR, located in the DC Docket Center. Document ID: EPA-HQ-OAR-2009-

0491-4508, 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 longterm 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 growth 

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 compliance under the Multipollutant Law 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-factor 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 available 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 facility 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-HQ-OAR-2009-0491-4385, p. 69.
27

80. Further, the Transport Rule provides 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 option 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 compliance 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 are 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, which states that overall emission reductions and air quality improvements 

will be similar under either CAIR or the Transport Rule. I have concluded that the 

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 thirtystate 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 Transport 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 described 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 of 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/ARPCAIR10_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. This assessment relies on budgets 

and not projected emissions, thereby 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 maintenance 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 were 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 final 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. The health benefits of the Transport Rule, as detailed later in this 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 reductions 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 matter, EPA concluded that the “nothreshold” model best represents the PM2.5-mortality concentration-response 

relationship.46

 45 Comments of Southern Company 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-HQ-OAR-2009-0491-2864).

 This conclusion has been confirmed by two separate rounds of peer 

review from EPA’s independent Clean Air Scientific Advisory Committee 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 Assessment 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 to 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 Corporation

86. I have reviewed Entergy’s claims that it would have to curtail generation and thus would 

not be able to meet its obligation to provide reliable power. Both claims appear to be 

based on incorrect assumptions. It 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 could not achieve compliance with the 

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 be 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 taken 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, which 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 state 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 conclusion 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 combined 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 result 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 incentive. These are typically driven by state rule or consent decree requirements. 

For instance, due to the Illinois state rule, ozone 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 from 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 motion 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 ozoneseason NOx trading program began 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, facilities in which Entergy owns a majority interest are included as Entergy facilities while those 

facilities in which Entergy owns a minority interest are excluded. This 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. Retrieved at 

http://epw.senate.gov/public/index.cfm?FuseAction=Files.View&FileStore_id=fc4c5288-525a-47d6-812c809d000c617b
31

Florida Electric Power Coordinating 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 bases 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 recently observed price of 

Transport Rule ozone-season NOx allowances at approximately $900,48 which is even 

lower than EPA’s projected market-clearing price of $1,300 per ton (Regulatory Impact 

Analysis for the Federal Transport Rule, p. 260. Document ID: EPA-HQ-OAR-2009-0491-

4409). At recent prices, even if Florida utilities chose not to adjust their 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 Transport 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 well 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 designed specifically to give states flexibility in case of 

unexpected events, like a hurricane. (76 FR 48,303)

93. The claims of harm to Orlando Utilities Commission 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 surrender 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 2012 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. Shelton 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 received 

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 allowances 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 received 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 operation 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 2008, 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 Level Allocations Under the FIP, Document 

ID: EPA-HQ-OAR-2009-0491-4400) 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 requires 

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 minimal 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.gov/gdm>.
33

d. Dispatchable SCRs are 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-dispatchable 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 budgets it would be costeffective 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. For 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 Affidavit’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 tons50 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 Transport 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-HQ-OAR-2009-

0491-4400
34

state budget of 41,528 tons. Kansas also is closer to the annual NOx budget than 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, or 

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 2009/2010 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 2012 

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 presented 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 of 0.24 lbs/mmBtu. 

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/mmBtu through installation and use of Low NOx 

combustion systems no later than December 31, 2011.53 These units installed controls 

slightly ahead of schedule and are already demonstrating an emission rate of 0.159 

lbs/mmBtu.54 Simply continuing to operate at this rate as required by the consent 

decree means that this facility’s NOx emissions would drop from approximately 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=irolfundsnapshot; Board of Public Utilities 2010 Comprehensive Annual Report 062311; Sunflower Electric Power 

Corporation 2010 Financial Statements 

http://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 data
35

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/mmBtu (Quindaro) and

from 0.402 lbs/mmBtu to 0.26 lbs/mmBtu (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 of 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 of 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. Finally, 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.html
36

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 with 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 for 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 allowances 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 

Wisconsin 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 surplus 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-oar-2009-0491-4431, U.S. EPA, Clean Air Markets - Data 

and Maps, http://camddataandmaps.epa.gov
37

coal at Nelson Dewey (a fuel switch that the state has indicated is being planned)57 will 

bring the SO2 emission levels in Wisconsin close 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 to 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/mmBtu to less than .3 lbs/mmBtu. 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 the 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 

state’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 budgets 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://camddataandmaps.epa.gov 60 U.S. EPA, Clean Air Markets - Data and Maps, http://camddataandmaps.epa.gov. 

“WebReady_ParsedFile_TR_Remedy_Final_2012” epa-hq-oar-2009-0491-4431
38

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 over 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 Information for Power Plants Assuming 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 Genoa facility SO2. For Genoa, 

2012 SO2 emissions are adjusted to reflect year 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. The 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 changes 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 that 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 approximate 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 rolling 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 operating as the emission rate has dropped from over 2 

63 http://www.dairynet.com/energy_resources/equipment.php
40

lbs/mmBtu to less than 0.3 lbs/mmBtu. 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) then 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 100,000 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 station 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 state’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 at 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 Wisconsin - 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-HQ-OAR-2009-0491-4425 66 “TR_Remedy_Final” Document #: EPA-HQ-OAR-2009-0491-4425
41

misunderstandings on the WSPC’s behalf 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 state 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 claims of harm are based largely on the assumption that there will 

not be enough allowances available to cover Ohio’s 2012 emissions 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 will occur. Current SO2 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 assurance 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 trigger 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 - Data and Maps, http://camddataandmaps.epa.gov 68 “WebReady_ParsedFile_TR_Remedy_Final_2012” epa-hq-oar-2009-0491-4431
42

121. The Transport Rule is projected to achieve greater emission reductions compared to 

CAIR69

• 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 around 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 CAIR 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 since 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 available 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 2014 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 from 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 deduction of allowances to cover 2011 emissions, it is highly likely 

www.epa.gov/airmarkets/progsregs/epa-ipm/cair/index.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.gov/airmarkets/progsregs/epa-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 needed 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 covered EGUs. It would therefore be possible for 

emissions 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 emissions 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 over 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 state (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 for 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 existing 

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 preserve 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 significant uncertainty for the regulated community, and 

create significant uncertainty 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 are 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 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, 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 2010 Progress Report 

is attached to this declaration.
45

because current 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 transition 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 revisions 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 allocations 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 to 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 flexibility 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 percent – 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 their 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 Rule 
46

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 revisions 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 date 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 rulemaking 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. Florida 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 adjustments 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 those 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-Asides TSD, p. 40-44. EPA-HQ-OAR-2009-0491-4728.) 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 include 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 these states. 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 

revisions were not in response to a widespread problem with IPM as Entergy suggests.

75“WebReady_ParsedFile_TR_Remedy_Final_2012” epa-hq-oar-2009-0491-4431,
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 

finalized, 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 proposed 

revisions, 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%, above 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 offers 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 revisions 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 Stack 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 Report
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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 (SO2) and nitrogen oxides (NOx) 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 SO2 and NOx 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 SO2 and annual NOx reductions and May 1, 2012 for ozone season NOx reductions. Additional SO2

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 (PM2.5) pollution. CAIR requires certain eastern states to limit annual emissions of NOx and SO2, which contribute to the

formation of ozone and PM2.5. It also requires certain states to limit ozone season NOx 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 NOx ozone season trading program, the CAIR NOx annual trading program, and the CAIR SO2 annual trading

program. The CAIR NOx ozone season and annual programs began in 2009, while the CAIR SO2 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 PM2.5 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 SO2 and NOx, the

primary precursors of acid rain, from the power sector. The SO2 program sets a permanent cap on the total amount of SO2 that may be

emitted by electric generating units (EGUs) in the contiguous United States. The program is phased in, with the final 2010 SO2 cap set at

8.95 million tons, a level of about one-half of the emissions from the power sector in 1980. NOx 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 NOx Budget Trading Program (NBP) operated from 2003 to 2008. The NBP was a cap and trade

program that required NOx 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

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reductions in power sector emissions of SO2 and NOx 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 NOx Budget

Trading Program/NOx SIP Call website.

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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 NOx 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 SO2 and NOx from 24 states and D.C. (to achieve improvements

in fine particle pollution in downwind areas) and emission reductions of NOx 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

SO2 and NOx programs.

Source: EPA, 2011

Affected Units

The CAIR SO2 and NOx annual programs generally apply to large EGUs — boilers, turbines, and combined cycle units that primarily burn
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fossil fuels to generate electricity for sale. The CAIR NOx 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 SO2 and NOx annual programs and 3,309 EGUs and industrial facility

units at 953 facilities in the CAIR NOx 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 SO2 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 SO2 emissions result from coalfired EGUs, although the program also applies to oil and gas units. Of the 3,349 units in the CAIR SO2 program, 2,626 (78 percent) were

also covered by the ARP in 2010. The other units are largely fossil fuel generation units that entered SO2 control under the broader

applicability requirements of CAIR.

The ARP also requires NOx emission reductions for older, large coal-fired EGUs by limiting their NOx emission rate (expressed in

lb/mmBtu). The goal of the NOx program is to limit NOx 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 NOx program.

Table 1: Affected Units in CAIR and ARP, 2010

Fuel ARP SO2 Program ARP NOx Program CAIR NOx Ozone 

Season Program

CAIR NOx and SO2

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

Top of page

Emission Reductions

Milestone Years for Measuring Progress under CAIR and ARP

1980: The Clean Air Act specified that annual SO2 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 NOx monitoring. Units participating in the two CAIR NOx trading

programs were required to monitor and report their emissions, but were not required to hold

allowances for compliance

2009: First year of CAIR NOx annual and CAIR NOx ozone season programs (Phase 1). “Training

year” for CAIR SO2 monitoring

2010: First year of CAIR SO2 annual program (Phase 1)

Overall Trends

Table 2, below, shows a large reduction in annual SO2 and NOx emissions from CAIR and ARP sources between 2005 and 2010. Tons of

SO2 emitted fell 49 percent from the 2005 level, and annual NOx emissions dropped 42 percent. During this same period, ozone season

NOx 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 SO2 sources, 42 percent

for annual NOx sources, and 25 percent for ozone season NOx sources. A drop in emission rate represents an overall increase in the

environmental efficiency of these sources as power generators installed controls, ran their NOx controls year round, switched to different

fuels, or otherwise cut their SO2 and NOx 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 SO2 emissions and emission rate. These reductions occurred

despite an 8 percent increase in demand for electricity. Annual NOx 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 emissions
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x

increased considerably (20 percent) as demand for electricity at these facilities rose substantially (more than 16 percent). Despite these

increases in NOx emissions as sources ran their controls less often, facilities were still below both the CAIR NOx ozone season and CAIR

NOx 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 SO2 Trends

SO2 Emissions (thousand tons) SO2 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 NOx Trends

NOx Emissions (thousand tons) NOx 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 NOx Trends

NOx Emissions (thousand tons) NOx 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 NOx Trends

NOx Emissions (thousand tons) NOx 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 NOx annual program facilities are not included in the annual NOx data for 2005 or 2008, and CAIR SO2 annual program facilities are not

included in the annual SO2 data for 2005, 2008, or 2009.

The CAIR NOx 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 NOx annual and ozone season programs.

2009 was a monitoring and reporting “training year” for facilities covered by the CAIR SO2 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

SO2 Emission Reductions
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Figure 3, below, shows that the CAIR SO2 program continues and complements the ARP’s history of SO2 emission reductions. In 2010, the

first year of operation of the CAIR SO2 trading program, sources in both the CAIR SO2 annual program and the ARP together reduced SO2

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 SO2 in 2010, well below the ARP’s statutory annual cap of 8.95 million tons.

Annual SO2 emissions from sources in the CAIR SO2 program alone fell from 9 million tons in 2005 to 4.4 million tons in 2010, a 51

percent reduction. Between 2009 and 2010, SO2 emissions fell 123,000 tons, or 6 percent. However, the 2010 emissions total is higher

than the CAIR SO2 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 SO2 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: SO2 Emissions from CAIR SO2 Annual Program and ARP Sources, 1980–2010

Note: For CAIR units not in the ARP, the 2009 annual SO2 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 SO2 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 SO2 emissions in the nationwide ARP dropped in 40 states and D.C. by a total of approximately 10.5 million

tons. In contrast, annual SO2 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 SO2 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 SO2 emission budgets.

Figure 4: State-by-State Annual SO2 Emission Levels for CAIR and ARP Sources, 1990–2010
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Note: State-level data shown in this map are available for download.

Source: EPA, 2011

Thirty-five ARP units installed SO2 controls in 2010, reducing their collective SO2 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 SO2 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 SO2 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 SO2 Emission Rates, 2010

Source: EPA, 2011

NOx Emission Reductions

Ozone Season NOx Reductions

Figure 6, below, shows ozone season NOx emissions from 1990 to the present for CAIR and NBP sources. In 2010, the second year of the

CAIR NOx 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 NOx emissions from 816,000 tons in 2005 (before implementation of

CAIR) to 599,000 tons in 2010, a decrease of 27 percent. NOx 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).
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Between 2005 and 2010, ozone season NOx 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 NOx emissions from sources in the CAIR NOx 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 NOx emissions totaled 594,000 tons in 2010, 5 percent below the 2010 regional emission budget of 624,698 tons.

Figure 6: Ozone Season NOx Emissions from CAIR and NBP Sources, 1990–2010

Note: For CAIR units not in the NBP, the 2008 NOx emissions were applied retroactively to 1990 and 2000 if the unit operated in the previous year’s ozone

season.

Source: EPA, 2011

The average NOx 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 NOx 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 NOx 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 NOx 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 NOx 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 NOx emission rate. EPA expects the average NOx emission rate to continue to improve in future years under

the regulatory certainty provided by CSAPR. The higher NOx 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 NOx emissions from CAIR and former NBP sources fell in every state participating in the CAIR NOx

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 NOx Emission Levels from CAIR Sources, 2000–2010
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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 NOx ozone season program and the former NBP, prior programs such as the Ozone Transport Commission’s (OTC)

NOx Budget Program and current regional and state NOx emission control programs have also contributed significantly to the ozone season

NOx 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 NOx 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, NOx emissions grew

proportionately (17 percent), while the NOx emission rate increased by less than two percent. The fact that the NOx 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 NOx Emissions and Generation
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Source: EPA, 2011

Annual NOx Reductions

Figure 9, below, shows that from 1990 to 2010, annual NOx 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 NOx annual program, NOx 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 NOx annual program sources alone were 1.43 million tons in 2010, 73,000 tons (5 percent) below the 2010 CAIR NOx

annual program’s regional budget of 1.5 million tons. Annual NOx emissions were 1.2 million tons lower (47 percent) than in 2005, but
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were 115,000 tons (9 percent) higher than in 2009. This recent increase was largely a result of sources not operating NOx controls as often

and increased demand for electricity.

ARP sources emitted 2.1 million tons of NOx in 2010. This level is 6 million tons less than the projected level in 2000 without the ARP, and

triple the Title IV NOx emission reduction objective.

Although the ARP and CAIR NOx programs were responsible for a large portion of these annual NOx reductions, other programs — such as

the NBP, the OTC NOx Budget Program, and other regional and state NOx emission control programs — also contributed significantly to the

annual NOx reductions achieved by sources in 2010.

Figure 9: Annual NOx Emissions from CAIR and ARP Sources, 1990–2010

Note: For CAIR units not in the ARP in 1990, 2000, and 2005, the 2008 annual NOx 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 NOx annual program continued to

reduce year-round emissions in 2010 as program participants operated NOx control devices on EGUs outside the summer months. From

2005 to 2010, NOx emissions from units in the CAIR NOx 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 NOx Annual Program Sources, 2005 vs. 2010

Note: The CAIR NOx 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 NOx annual program decreased their emissions, as indicated in Figure 11, below.

Comparing 2005 to 2010, all states in the CAIR region emitted less NOx except Delaware and D.C., which increased their NOx emissions by

855 tons. The total NOx 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 NOx Emission Levels for CAIR and ARP Sources, 1990–2010
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

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Note: State-level data shown in this map is available for download.

Source: EPA, 2011

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CAIR and ARP Program Compliance

SO2 Programs

Because SO2 allowances from the ARP are used by sources to comply with the CAIR SO2 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 SO2

facilities were in compliance with both programs and held enough allowances to cover their SO2 emissions.

Table 3: CAIR and ARP SO2 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 CAIRSO2 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 SO2 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 SO2 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 SO2 Programs

Reported emissions (tons): 5,166,487

Compliance issues, rounding, and report resubmission

adjustments (tons): –45,912

Emissions not covered by allowances (tons): 0
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

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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 SO2 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 SO2 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 SO2 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 SO2 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 SO2 allowances were

banked and carried forward to the 2011 compliance year.

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NOx Programs

CAIR NOx Compliance Results

Tables 4 and 5, below, show how NOx allowances were used in 2010. All covered facilities were in compliance with the CAIR NOx annual

and ozone season programs and held enough allowances to cover their NOx emissions.

Table 4: CAIR NOx 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 NOx 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 NOx 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 NOx 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 NOx 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 NOx 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 NOx 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: 1,420,621
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

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On May 1, 2009, the NBP transitioned to the CAIR NOx ozone season program and transferred a total of 275,367 allowances from the NBP

to the CAIR NOx ozone season program. By the end of the 2009 ozone season, 392,799 allowances were banked and available for program

compliance in 2010. Because NOx 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 NOx annual program, 342,975 allowances were carried over from 2009. Because annual NOx 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 NOx Compliance Results

The ARP NOx Program does not impose a cap on NOx 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 NOx emission reduction requirements in a cost-effective manner. In

2010, all 956 units that were subject to the ARP NOx Program achieved compliance.

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Controls and Monitoring

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 NOx program

combined cycle units in 2010.

SO2 Controls in 2010

The wide variety of SO2 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

SO2. As discussed in detail above, 35 units in the ARP added new SO2 controls in 2010. Sources added FGDs at 34 of the units in the CAIR

SO2 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: SO2 Controls in 2010 on Coal-Fired Units in the ARP and CAIR Annual SO2 Program

SO2 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

NOx Controls in 2010

Sources have a variety of options by which to reduce NOx emissions. New selective catalytic reduction units (SCRs), the most efficient NOx

controls, were installed at five generation units under the CAIR NOx 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 NOx ozone season

program (see Table 7, below).

Table 7: NOx Controls in 2010 CAIR NOx Ozone Season Program

NOx 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 NOx 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 NOx ozone season program, uncontrolled units represent two percent of coal-fired

generation and one percent of combined cycle generation under the CAIR NOx annual program.

Table 8: NOx Controls in 2010 CAIR NOx Annual Program

Share of Combined Cycle 
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

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NOx 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 NOx emissions — over 99 percent —

were measured by CEMS. Similarly, CEMS monitored over 99 percent of SO2 emissions including 100 percent from coal-fired units and 18

percent from oil-fired units. Coal-fired units were required to use CEMS for NOx concentration and stack gas flow rate to calculate and

record their NOx mass emissions. Oil-fired and gas-fired units could use a NOx CEMS in conjunction with a fuel flow meter to determine

NOx mass emissions. Alternatively, for oil-fired and gas-fired units that either operated infrequently or had very low NOx emissions, Part

75 provided low-cost alternatives to conservatively estimate NOx 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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Market Activity

SO2 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 SO2 budget and the new compliance deadlines. With the start of the

CAIR SO2 program in 2010, the Acid Rain SO2 market essentially has become the CAIR SO2 market. See Table 9, below, for a summary of

the 2010 SO2 allowance market.

Table 9: SO2 Allowance Market in Brief (close of 2010)

Total Value of the SO2 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

NOx Allowance Markets in 2010

The 2010 CAIR NOx 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 NOx 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: NOx 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, 2011
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

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In 2010, the second year of the CAIR ozone season and annual NOx programs, CAIR sources emitted about 594,000 tons of NOx 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 NOx were 1.4 million

tons, about 82,000 tons less than the overall budget. The CAIR annual NOx 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 NOx ozone season allowance market, it has been EPA’s expectation that the CAIR annual NOx cap would be the

binding constraint and absorb most of the capital costs of controls (i.e., SCRs), while the NOx ozone season allowance prices would

primarily be driven by operating costs. As expected, the current CAIR NOx allowance prices are below the total expected control cost.

However, in the middle of 2010, CAIR annual NOx 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 NOx Ozone Season Distinct Organizations 132,854 36%

Related Organizations 237,151 64%

CAIR NOx Annual Distinct Organizations 344,758 39%

Related Organizations 540,267 61%

ARP and CAIR SO2 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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