Corrected Technical Support Document 

for the 

Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone 

(Clean Air Interstate Rule): 

Notice of Final Action on Reconsideration 

Corrected CAIR SO2 Allocation Approach Analysis 

This is a corrected version of the document at docket number OAR-2003- 

0053-2360 (“CAIR SO2 Allocation Approach Analysis” TSD in the Docket on the 

Clean Air Interstate Rule). The errors made in referencing tables 

in the original document have been corrected in this document. 

EPA Docket number: OAR-2003-0053 

March 15, 2006 

Corrected April 2006 

U.S. Environmental Protection Agency 

Office of Air and Radiation 
 2

The following corrections have been made to this Technical Support Document (TSD) since the 

date of signature of the final rule. These changes correct improper references and grammatical 

errors. 

Page numbers refer to the pagination of the original TSD, Docket Number OAR-2003-0053-

2360. 

1. On Page 7, replace “EPA’s analysis of SO2 coverage ratios (the ratio of allowances to 

projected emissions, discussed to some degree in this section and presented in the 

“CAIR SO2 Allocation Approach Analysis” Technical Support Document, available in 

the docket), is not suggestive of this trend.” with “EPA’s analysis of SO2 coverage 

ratios (the ratio of allowances to projected emissions, discussed below), is not 

suggestive of this trend.” 

2. On Page 17, change the reference, “Tables 4-5,” to “Appendix A, Table E,” in the 

sentence, ‘The State budget and emissions data behind the tables in Appendix A are 

available in Tables 4-5, as well as in the docket, “SO2 Allocations Analysis Data.”’ 

3. On Page 17, replace “EPA believes that a further understanding of the overall relative 

impacts of the various allocation approaches, EPA believes that it is useful to apply the 

statistical concepts of (1) bias and (2) consistency.” with “For a further understanding of 

the overall relative impacts of the various allocation approaches, EPA believes that it is 

useful to apply the statistical concepts of (1) bias and (2) consistency.” 

4. Add the table heading, “Table E. State SO2 Budgets by Allocation Approach for 2010 

and 2015,” on page 3 of Appendix A. 
 3

Introduction

This technical support document (TSD) presents analysis the United States Environmental 

Protection Agency (EPA) performed to support its Notice of Final Action on Reconsideration of 

the Clean Air Interstate Rule (CAIR) (70 FR 25162) specific to the sulfur dioxide (SO2) 

allocation methodology. 

EPA received one petition for reconsideration that asked EPA to reconsider the SO2 allocation 

approach to be used by States participating in the EPA-administered CAIR SO2 trading program. 

As described in the Notice of Final Action on Reconsideration, this petitioner argued that the 

SO2 allowance allocation approach is unreasonable and inequitable. The petitioner argued that 

the approach is unreasonable because other approaches would be more appropriate. According 

to the petitioner, the approach is inequitable because it results in owners of units that have 

historically lower emission rates being forced to buy allowances from historically higher 

emitting units that install new emission controls. The petitioner asked EPA to establish a 

different approach. 

As described in the Notice of Reconsideration, EPA does not agree with petitioner's conclusions 

about this issue. EPA continues to believe that the approach selected is reasonable for the 

reasons explained in the CAIR final rule and further discussed below. Furthermore, numerous 

opportunities for public comment on this issue were provided, and a full discussion of the 

allowance allocation options occurred during the rule development process. Nonetheless, given 

the intense public interest in this issue, EPA decided to grant the petition for reconsideration 

insofar as it raised issues regarding alleged inequities resulting from the application of EPA’s 

SO2 allowance allocation approach. 

In the Notice of Reconsideration, EPA announced its decision to reconsider this issue and 

solicited additional public input. EPA also solicited comment on additional analyses it 

conducted in response to the petition for reconsideration concerning the impact of the SO2 

allowance allocation approach adopted in the CAIR model trading rule. This additional analysis 

compared the SO2 allocation approach in CAIR to various alternatives EPA also considered 

during the rulemaking process. In response to comment on the Notice of Reconsideration, EPA 

has further refined some of its analyses and carefully considered the arguments of the petitioner. 

EPA continues to believe that these analyses show that EPA’s selected approach to SO2 

allowance allocations is appropriate, given the objectives of CAIR and other relevant 

considerations. Moreover, EPA believes that the Agency’s approach produces a reasonable 

result in terms of equity. Therefore, in this Notice of Final Action on Reconsideration, EPA is 

not altering the approach taken in CAIR for SO2 allowance allocation. EPA’s response to public 

comments on the analyses presented in the Notice of Reconsideration and further discussion of 

the petitioner’s concerns are provided below. 

The underlying data, including data for both 2010 and 2015, are available in the docket (OAR2003-0053), as “SO2 Allowance Allocation Data.” 
 4

Considerations Relevant to Choosing an Allocation Approach

While EPA did not explicitly define a distinct set of principles that should be used in developing 

State budgets under a region-wide cap and trade program, EPA has made it clear throughout this 

process that it has relied upon several consistent, important factors in developing both the SO2 

and NOx budgets. 

The first is the impact of allowance allocations on the specific environmental objectives and 

overall cost of the rule, as well as any potential adverse effects. In general, while the chosen 

allocation or State budget calculation approach can affect the distribution of compliance costs 

under a cap-and-trade program, it will have little effect on overall compliance costs or 

environmental outcome. This is because the incentives provided by cap-and-trade encourage 

economically efficient compliance over the entire region. However, this may not always hold 

where there are interactions with existing environmental policies. In the case of NOx, EPA did 

not find this consideration to be restrictive because there was not an existing annual NOx trading 

program and the SIP Call ozone season trading program could be easily integrated into the CAIR 

ozone season trading program. As a result, a number of budget methodologies were compatible. 

For SO2, this consideration played a larger role because depending upon how the program was 

integrated within the existing Title IV structure, it could impact emissions before the program 

went into affect as well as emissions in regions not affected by the program. 

Another important consideration is that an allocation methodology must be consistent with the 

existing regulatory and legislative structure. Once again for NOx, this consideration could be 

satisfied with a wide range of budget methodologies. However, for SO2, reductions for EGUs 

using Title IV allowances is necessary in order to ensure the preservation of a viable Title IV 

program (70 FR 72272). Linking the two programs maintains the trust and confidence that has 

developed in the functioning market for title IV allowances. The EPA recognizes this familiarity 

and confidence (especially in a market-based approach) as a key source of the program’s 

success. 

A third factor is equity. In the absence of other considerations, EPA believes that it is in the 

public interest that the distribution of allowances under a cap and trade program be as equitable 

as possible. For NOx, since the other considerations could be satisfied with a number of 

different methodologies, this factor was the primary one. For SO2, where the other 

considerations were more limiting, this factor was not as central to our decisions, especially since 

the Title IV allocation structure was erected by Congress for the long term. 

SO2 Allocation Options Discussed in CAIR 

EPA considered and analyzed a variety of SO2 allowance allocation methodologies during the 

CAIR rulemaking process. After careful analysis, EPA decided to use the allocation approach 

chosen by Congress in title IV of the Clean Air Act. EPA also considered the following 

alternative approaches, which are explained in the final CAIR “Corrected Response to 

Significant Public Comments on the Proposed Clean Air Interstate Rule,” Corrected April 2005 

(Docket Number OAR-2003-0053): 
 5

- Allocations based on historic tons of actual emissions from more recent years; 

- Allocations based on heat input (with alternatives based on heat input from all 

fossil generation, and heat input from coal- and oil-fired generation only); and 

- Allocations based on electricity output (with alternatives based on all generation 

and all fossil-fired generation). 

In addition to these alternatives, EPA has analyzed other heat input-based allocation approaches 

in the reconsideration process, explained below. Each allocation approach suggested by the 

petitioner and other commenters during the CAIR rulemaking and reconsideration process has 

advantages and disadvantages for different companies and States. However, as explained in the 

final CAIR, EPA believes that the approach used in the final CAIR is the most appropriate 

among the alternatives for several reasons. 

First, EPA believes – based on strong policy and air quality concerns – that it is necessary to use 

the existing title IV allowances in order to preserve the viability and emissions reductions of the 

highly successful title IV program. The disruption of the title IV SO2 trading program would 

also potentially result in increased emissions outside of the CAIR region starting in 2010 

because, with title IV allowances having little or no value, the title IV program would no longer 

constrain SO2 emissions in those States. Further, if title IV allowances are not used for 

compliance in the CAIR SO2 trading program, the likely result will be: a significant surplus of 

title IV allowances; a collapse of the price of title IV allowances; and a title IV SO2 trading 

program that, contrary to Congressional intent, no longer provides incentives to minimize 

emission control costs and encourage pollution prevention and innovation. 

If EPA adopts an approach that does not preserve the structure of the title IV allowance market 

and the value of those allowances, the confidence in the cap-and-trade policy instrument and 

allowance markets in general, and in the CAIR cap-and-trade programs in particular, would 

likely decline. Such an outcome could result in a reduced willingness of the owners of sources in 

cap-and-trade programs to invest in control technologies that would generate excess allowances 

for sale, or to purchase allowances for compliance, for fear that the rules might change. If 

owners were to ignore the incentives provided by cap-and-trade in such a manner, efficiency and 

cost-savings provided by these programs would be lost. The preservation of title IV allowances 

for use in CAIR, then, is integral to the viability and effectiveness of both title IV and the CAIR 

trading programs. See discussion in preamble to the final CAIR in section IX (70 FR 25293-

25295). 

Second, EPA relied on the permanent allocation methodology established by Congress in title IV 

for purposes of reducing SO2 emissions. Congress chose a policy of not revisiting and revising 

these allocations and, apparently, believed that its allocation methodology for title IV allowances 

would be appropriate for future time periods. Third, title IV allowance allocations provide a 

logical and well understood starting point from which additional electric generation unit (EGU) 

SO2 emission reductions can be achieved for Acid Rain units, which account for over 90 percent 

of the SO2 emissions from CAIR EGUs. 
 6

Finally, in response to comments on the proposed CAIR, EPA performed an analysis comparing 

the title IV methodology to other methodologies. At the outset, EPA notes that the objective of 

CAIR is not to ensure that each State receives the maximum amount of SO2 allowances possible 

under any approach. The goal of CAIR is to reduce SO2 emissions that significantly contribute 

to non-attainment. As EPA has noted, selecting the most appropriate SO2 allowance allocation 

approach for CAIR has required addressing a number of different considerations. The policy and 

air quality concerns specific to the CAIR SO2 trading program and noted by EPA above 

necessitate that EPA implement the CAIR SO2 program using the existing structure of title IV. 

Nevertheless, EPA has analyzed the impact of using title IV allocations on States relative to 

other possible allocation approaches. 

EPA’s analysis indicates that the use of title IV allowances in the CAIR SO2 trading program 

has a reasonable result (See CAIR Corrected Response to Comments, section X.A.26, Docket #: 

EPA-HQ-OAR-2003-0053-2172). This analysis compares State budgets (as a percent of the 

total CAIR regional budget) calculated based on title IV allowances with State budgets 

calculated using the other suggested SO2 allocation approaches. In more than two-thirds of 

CAIR States (accounting for about 80 percent of the total heat input in the CAIR region from 

1999-2002), the use of title IV allowances results in each State having neither the highest nor the 

lowest percentage of the region-wide SO2 budget, but instead, a percentage that is well within 

the range of percentages that the States would receive under all of the alternative options 

considered. 

For example, Ohio’s trading budget for 2010 under EPA’s method is 333,520 tons, which is 

about 9 percent of the CAIR region trading budget of 3,619,196 tons.1

 If Ohio’s budget were 

calculated based on historic tons of emissions, it would receive approximately 12 percent of the 

total CAIR budget. If Ohio’s budget were calculated based on output, it would receive 

approximately 5 percent of the total CAIR budget. The allocation approach based on title IV, 

thus, provides Ohio with a budget in the middle of the range of the options analyzed. 

EPA recognizes, of course, that the relative impact of allocations based on title IV allowances as 

compared to alternative approaches will vary among States and individual companies. However, 

each alternative allocation approach would disadvantage some States or companies relative to 

another alternative allowance allocation approach. EPA must, nevertheless, select a method for 

SO2 allowance allocation and must be sensitive to competing considerations. 

In summary, EPA's use of title IV allowances in the CAIR SO2 trading program is supported by: 

(1) EPA's determination that this approach is necessary to maintain the efficacy of the title IV 

program and to prevent erosion of confidence in cap-and-trade programs in general; and (2) 

EPA's analysis showing that the allocations resulting from this approach are reasonable. 

Nevertheless, as a part of this reconsideration, EPA performed additional analyses, explained 

below, to evaluate the SO2 allocation approach in the final CAIR in light of the petitioner’s 

concerns. 

 

1

 EPA’s methodology to calculate the Regional and State budgets is described in the TSD in the 

docket http://www.epa.gov/cair/pdfs/finaltech06.pdf,
 7

Response to Comments on the Equitability of CAIR SO2 Allocation 

Approach

One commenter argued that EPA should evaluate SO2 allowance allocation approaches using the 

same metrics and methods that it used for NOx allocations. The commenter suggests that the 

metrics by which EPA assessed NOx allocations included (1) whether the EPA method avoids 

penalizing coal-fired generation units that already have installed emissions controls and (2) 

whether, relative to the alternative allocation approaches, the EPA method better minimizes for 

each State the disparity between allowances provided and projected emissions, and argued that 

EPA cites these rationales in justifying its chosen NOx allocation approach. This commenter 

also suggests that EPA’s use of title IV allowances penalizes new units and independent power 

producers (IPPs) and results in large wealth transfers from low-emitting to high-emitting States. 

 

While EPA agrees that the Agency considered these factors (among several others) in choosing 

its allocation approach under the CAIR NOx trading programs, EPA does not fully agree with 

the commenter’s characterization of EPA’s considerations. EPA believes that the commenter 

has omitted some of the significant context and caveats that were included in the discussion of 

NOx allocations and the use of fuel adjustment factors in the reconsideration notice, as well as a 

number of other factors that EPA must consider, particularly in the context of SO2 allocations. 

First, EPA noted in the June 10, 2004 Supplemental Notice of Proposed Rulemaking and in the 

Notice of Reconsideration that, “in contrast to allocations based on historic emissions, the factor 

would also not penalize coal-fired plants that have already installed pollution controls” (69 FR 

32869, 70 FR 72276, emphasis added). This language explains that allocations using historic 

heat input adjusted for fuel type, while providing additional allowances to coal-fired units that 

will likely install controls under CAIR, would not simultaneously penalize coal-fired units that 

had already made investments in emissions controls. 

An approach based on historic emissions, on the other hand, would also provide additional 

allowances to units that would likely have to install controls, but would simultaneously penalize 

units that had already done so. While EPA makes this argument in support of its chosen 

approach for NOx allocations, the Agency does not raise this point to establish a criterion for 

evaluating allowance allocation approaches. Rather, it simply notes that its chosen approach for 

NOx allocations can provide an advantage to one set of coal-fired units without disadvantaging 

another set of coal-fired units. 

 

Second, while the commenter is correct in noting that EPA stated in its discussion of NOx 

allocations in the Notice of Reconsideration that it is in the public interest to attempt to minimize 

the disparity between individual State budgets and projected emissions for each State, EPA did 

not set this goal as one of only two primary criteria for adoption of a given allocation strategy, as 

the commenter suggests. Rather, EPA notes that “In the absence of other considerations, EPA 

believes that it is in the public interest to reduce the disparity between the number of allowances 

in a State budget and total projected State EGU emissions” (70 FR 72276, emphasis added). As 

EPA has noted, equity is one of many considerations faced by EPA in choosing an SO2 

allowance allocation approach. In particular, unlike in the case of NOx, EPA had to consider an 

existing, nationwide trading program implemented by statute in the case of SO2. 

 
 8

Third, as EPA discussed in the CAIR Response to Comments, while commenters express 

concern about the availability of allowances for non-Acid Rain units, it should be noted that not 

all sources covered under the Acid Rain program received allowances. By the design of the title 

IV program (as outlined by Congress), because of the permanent allocation of allowances, new 

units beginning commercial operation after 1995 or beginning construction after 1990 did not 

receive title IV allowances. Thus, Congress recognized that, over time, new units would be built 

and covered under the program, but felt it reasonable that such units would obtain title IV 

allowances either through the auction or from the market. Under the auction, 250,000 title IV 

allowances will be auctioned annually for the years 2012 and beyond, and these allowances can 

be used for compliance with CAIR. The availability of these allowances ensures that all sources, 

including new units and non-title IV sources, will have access to a pool of allowances, protecting 

them from potential exercise of market power by market participants holding allowances. 

Finally, IPPs have the option of opting in to title IV until their exemption expires in order to 

obtain title IV allowances. EPA addresses other issues specific to IPPs in section VI.E of today’s 

CAIR FIP preamble. 

 

Fourth, while the commenter asserts that EPA’s use of title IV allowances in the CAIR SO2 

trading program will result in significant wealth transfers from low-emitting to high-emitting 

States, EPA’s analysis of SO2 coverage ratios (the ratio of allowances to projected emissions, 

discussed below), is not suggestive of this trend. In fact, looking at the differences in States’ 

projected emissions and coverage ratios between the base case and CAIR, it becomes evident 

that both lower- and higher-emitting States are projected to make investments in emissions 

reductions under CAIR, reducing their demand for allowances, or freeing up allowances for sale, 

in the process. States that might be categorized as high-emitting are not always projected to be 

net sellers of allowances, and States that might be categorized as low-emitting are not always 

projected to be net purchasers of allowances. 

 

Another commenter argues that smaller units would be forced to purchase SO2 allowances from 

the market in order to comply with CAIR. This commenter argues that the SO2 allowance 

market is not efficient and subjects forced participants to bear an undue amount of financial 

burden and/or risk. EPA believes that the commenter’s claims about the state of the SO2 

allowance market are unfounded. As is discussed in the Acid Rain Program Report (EPA 43-R05-012, October 2005), about 20,000 allowance transactions, affecting about 15.3 million 

allowances, were recorded in the EPA Allowance Tracking System in 2004. This large volume 

of transactions is evidence of a viable and well-functioning market. In addition, title IV 

compliance costs have been much lower than projected and allowance prices in the SO2 

allowance market have generally reflected this. Finally, as discussed earlier in this section, 

sources have the option of purchasing allowances directly from the annual auction. 

Further, in raising equity concerns, a couple of commenters argue for conflicting measures of 

equity within their own comments. These commenters argue that an equitable emissions 

allocation approach will result in an equivalent effective emissions rate across States. These 

commenters then point to EPA’s chosen CAIR NOx emissions allocation approach as an 

exemplary allocation approach because it limits the disparity between individual State budgets 

and projected emissions. However, the commenters fail to realize that, that approach does not 
 9

actually result in an equivalent emissions rate across States. Such a result underscores the notion 

that improving equity along one metric can actually reduce it along another. 

Finally, some commenters argued that the use of title IV allowance allocations penalizes sources 

who have already installed scrubbers prior to the start of the Acid Rain Program. This is 

because, in general, allowances under title IV were allocated to units that had not installed 

controls at a higher rate relative to units that had installed controls. The title IV approach, in that 

sense, is somewhat similar to the approach taken for NOx under CAIR, in that it provides 

additional allowances for units expected to install controls under the rule. 

EPA believes that the commenters’ arguments that the continued use of title IV allowances 

penalizes sources that installed controls prior to the Acid Rain Program are unfounded. First, 

these controls were installed over 20 years ago and are, at this point, a sunk cost. Second, these 

control installations were completed within a regulated electricity sector, such that in most cases 

the cost of installing these controls should have been recovered through an electricity price rate 

increase. Third, these controls were installed in response to requirements separate from both 

CAIR and the Acid Rain Program. Fourth, Congress was clearly aware of the issues raised by 

commenters when designing the SO2 trading program in 1990, and consciously used a formula 

for future allocations for the length of time it believed was reasonable. In general, the Acid Rain 

Program has enjoyed 10 years of operation without substantial concern over this issue and with 

industry at-large appreciating the program’s merits in providing a cost-effective, flexible, and 

fair way to provide environmental protection. Finally, analysis by one of these two commenters, 

which estimates the windfall of allowances that a hypothetical unscrubbed coal-fired unit would 

attain by installing a scrubber and reducing emissions, neglects the fact that this unit would have 

to endure the costs of installing controls. Thus, the ostensible windfall would be significantly 

smaller than was suggested by the commenter. 

Analysis of SO2 Allocation Options Presented in the Notice of 

Reconsideration 

In the Notice of Reconsideration, EPA compared three alternative SO2 allowance allocation 

methodologies to the approach in the final CAIR. In these analyses, EPA examined how 

allowances would be distributed to individual companies instead of examining how they would 

be distributed to States. According to the petitioner, the allowance distribution will result in the 

petitioner’s relatively low-emitting units being forced to buy allowances from other companies’ 

relatively high-emitting units. They thus argue the allocation approach used in CAIR is per se 

inequitable and unreasonable. To evaluate this concern, EPA compared projected allocations not 

just to individual units, but to individual companies who own these units under various 

methodologies relative to projected SO2 emissions of all the units owned by those companies. 

The logic behind this is described in detail in the Notice of Reconsideration and associated TSD 

(docket, EPA-HQ-OAR-2003-0053-2229). 

The three alternative allowance allocation methodologies EPA analyzed were suggested by 

various commenters during the rulemaking process and this reconsideration process. These 

methodologies are: 
 10

1. Allocating allowances based on more recent heat input data; 

2. Allocating allowances based on more recent heat input data adjusted for fuel type 

(e.g., coal, oil and gas); and 

3. Allocating allowances based on more recent heat input data adjusted both for fuel 

type and for coal type (e.g., bituminous, sub-bituminous and lignite). 

In comparing the CAIR SO2 allocation approach and the three alternative methodologies, EPA 

took into account certain factors that are applicable to the CAIR final allocation approach but not 

to the three alternative methodologies. For all four methodologies, EPA analyzed the resulting 

total allowance allocations, and the total projected emissions, for companies’ sources located in 

the States subject to CAIR. In addition, for all the methodologies, EPA analyzed the relationship 

between allowances and emissions in two ways. First, EPA calculated the ratio of allowances to 

total projected emissions before CAIR controls (base case emissions). This provides a 

reasonable estimate of the extent to which each company’s future emissions could have exceeded 

its allowances and, thus, indicates how much effort a company must expend for compliance 

either by purchasing allowances or installing controls. Second, EPA calculated the ratio of 

allowances to total projected emissions after the installation of CAIR controls (control case 

emissions). This provides a reasonable estimate of the number of allowances a company would 

need to purchase or would be able to sell after any controls are installed. Some companies with 

existing low-emitting units may have excess allowances to sell even if no controls are installed. 

In its analysis of the CAIR approach, EPA also considered both the allowance allocations and the 

emissions for companies’ units both within the CAIR region and outside the CAIR region. EPA 

believes that this is appropriate because, under the CAIR approach, if a company’s units outside 

the CAIR region have more title IV allowances than needed to cover their emissions under the 

Acid Rain Program, the company might be able to transfer, at little or no net cost, excess 

allowances to the company’s units in the CAIR region for use to cover emissions under the 

CAIR trading program. Under the three alternative methodologies, all of which would require 

creating new CAIR SO2 allowances independent of the existing title IV allocations, CAIR 

sources could not use title IV allowances held for sources outside (or inside) the CAIR region for 

compliance with the CAIR SO2 allowance holding requirement. 

Further, in the analysis of the CAIR approach, EPA considered the allocation of title IV 

allowances to CAIR units that are not currently in the Acid Rain Program but that could opt into 

the Acid Rain Program and receive title IV allowances (see 42 U.S.C. 7651i and 18 CFR part 74; 

and the discussion below concerning the ability of units to opt in). This analysis assumed that 

companies owning non-Acid Rain units subject to CAIR would elect to opt into the Acid Rain 

Program because they would receive title IV allowances to cover a portion of the units’ 

emissions under CAIR. EPA believes this assumption is reasonable because any of these units 

has the option of becoming an Acid Rain Program opt-in unit and thereby providing the 

company additional allowances, at little or no additional cost, and the value of title IV 

allowances could be substantial. In contrast, the analysis of the three alternative methodologies 

did not consider the impact of Acid Rain Program opt-ins because these approaches do not use 

title IV allowances for CAIR compliance. 
 11

EPA’s analysis indicated that while allocations vary from company to company under the four 

methodologies, overall the distributions of allowances that companies received relative to their 

projected emissions for the CAIR control case are very similar. EPA came to similar 

conclusions when looking at the base case.2 See Appendix B for the results. 

Changes in Data Representation

In the Notice of Reconsideration, we displayed data in figures as the cumulative number of 

companies obtaining a specific ratio (or a lower ratio). The ratios were calculated as the 

projected base case SO2 allowance allocations divided by emissions. By displaying data in this 

manner we found that the distributions of allowances relative to emissions are similar across the 

four approaches. 

Another way to display such data is by showing the percentage of companies or States that have 

a specific ratio (or a lower ratio). This method of graphing places the primary variable of 

interest, such as coverage ratio, on the x-axis, and shows the cumulative percentage of 

companies on the y-axis. Because of the ease of interpreting this format, we have chosen to 

display all relevant charts, thus. For example, see Appendix B, Figure 1. In addition, the 

statistical analysis discussed in the Appendix B, provides another way to assess system-wide 

trends in the data, which indicate whether an allocation approach is biased or inconsistent in its 

distribution of allowances across all States, as compared to other alternatives. The conclusion of 

that statistical analysis is that EPA’s method is not biased or inconsistent compared to other 

methods. 

There are two sets of analyses files associated with the Reconsideration process in the CAIR 

docket (EPA-HQ-OAR-2003-0053), “SO2 Allocations Analysis Data,” from this Notice of Final 

Action on Reconsideration, March 15, 2006, and another set from the December 2005 Notice of 

Reconsideration (OAR-2003-0053-2261). EPA used the following labels in its data files in the 

docket for the corresponding allocation approaches analyzed: 

2b = EPA’s CAIR method 

3b = Pure heat input 

4b = Heat input with fuel factors 

5b = Heat input with fuel factors and coal type 

 

Slight changes in calculations for the method 5b were made to reflect another interpretation of 

how such a heat input allocation approach could be handled. In addition, a few duplicative 

entries were found and removed in this set of data files. Detailed explanation of the 

methodology for the revised data analysis can be found in (Source: Memos from David Sellers, 

Perrin Quarles Associates, March 2006, “CAIR SO2 Allocation Analysis Data,” and “SO2 

 

2 Note: For NOx, EPA calculated a separate region-wide budget for New Jersey and Delaware using the same approach that was 

used to calculate the larger CAIR region-wide budget. This region-wide budget was then apportioned to individual State budgets

using the same approach used in CAIR. Because New Jersey and Delaware were treated separately in the context of NOx 

allocations, EPA has not included them in this SO2 analysis. EPA believes their inclusion would have made little difference in

the overall results given the relative smallness of the States’ fossil generation capacity and coal-fired capacity in particular. 
 12

Allocation Data Spreadsheets” (Docket: EPA-HQ-OAR-2003-0053). Previous calculation 

methods can be found in Appendix A of Notice of Reconsideration TSD, “Sulfur Dioxide 

Allowance Allocation Methodology Comparative Analysis” (Docket: EPA-HQ-OAR-2003-

0053-2229).3

Company-by-Company Analyses 

EPA analyzed company-by-company data for owner/operating companies, as well as 

parent/holding companies. EPA analyses at the operating company level take into account that 

companies may incur some cost to shift allowances across State lines, e.g. if the States involved 

regulate retail electricity sales. Believing that taking this into account would not have a major 

effect on the outcome of these analyses, EPA performed this portion of the analyses to test this 

assumption. 

One commenter criticized EPA’s company-by-company analysis on the grounds that EPA 

determined allowance allocations under the various allocation alternatives using title IV-based 

CAIR State budgets rather than using State budgets that were calculated using corresponding 

heat input allocation approach. EPA agrees with the commenter that determination of company 

allocations under a given alternative allocation approach should be based on State budgets 

calculated using the same approach. EPA has reanalyzed company level allocations using this 

methodology, and the revised analyses are included in this document (also see “SO2 State 

Budget Analysis Data” spreadsheet in the CAIR docket, and March 2006 memos from David 

Sellers for underlying data). 

EPA’s revised analyses for both base and CAIR control cases in 2010 and 2015 for 

owner/operating companies and parent/holding companies all show mostly similar results to 

those described in the Notice of Reconsideration SO2 Analysis TSD with one exception. As in 

the prior analyses, EPA’s SO2 allowance allocation approach is shown to be reasonable 

compared to the alternatives. This is true for 2010 and 2015 and when using emissions from 

both the base and CAIR control cases. However, because of the recalculation of the heat input 

with fuel factors approach for this final action analysis, the pure heat input approach is less far 

off from the heat input with fuel and coal factors approach under all cases and years. (See 

Appendix B for more details related to company-level analyses.) 

This is further seen in the results for the owner/operating company analyses, which were slightly 

different than the parent/holding company analyses and what was described in the Notice of 

Reconsideration. EPA’s method provides a distribution of ratios (allocations to emissions) 

similar to the heat input with fuel factors alternative, but not as close to the other two alternatives 

(see Appendix B, Figures 1, 2, 7 and 8). One reason for this difference is the owner/operator 

analyses indicate that the distributions of ratios are sensitive to the number or sources with zero 

allocations (and therefore a ratio of zero allowances to emissions). Companies may have zero 

allocations because the units they operate commenced operations after 1990. This is true for 

both 2010 and 2015 and with base case and control case emissions (see docket: EPA-HQ-OAR-

 

3 The District of Columbia is excluded from analyses that require emissions data because DC is projected to have no emissions in 

2010 or 2015. 
 13

2003-0053, “SO2 State Budget Analysis”). The vast majority of these companies have primarily 

gas generation, which has little or no emissions. For example about 94% of the 64 companies 

with a ratio of zero allowances to emissions were gas-fired for 2010 CAIR control case. This is 

true for at least 90% of companies for other years and cases, as well. Since these units have 

negligible SO2 emissions, receiving no allowances will not significantly impact the operating 

companies (see docket, OAR-2003-0053, “SO2 Allocations Analysis Data,” for related data). 

When the figures are redrawn with those zero values removed for all methods, EPA’s approach, 

again, appears to be very similar to the others analyzed (Appendix B, Figures 5, 6, 11 and 12). 

Among the three remaining methods that incorporate a fuel-adjustment factor, neither heat input 

methodology stands out as providing a more reasonable method of allocation across all 

companies when examining allowance needs under either the base case or CAIR control case. In 

addition, the CAIR method for allocating SO2 allowances is supported by EPA’s over-riding 

policy decision to preserve operation of the title IV SO2 cap and trade program as the CAIR 

method. 

State-by-State Budget Analysis

As described in the CAIR Notice of Final Action on Reconsideration, in response to comment on 

the Notice of Reconsideration, EPA performed a set of State-level SO2 budget analyses. This 

section includes additional tables with data that support EPA’s conclusions given in the Notice of 

Final Action on Reconsideration. 

EPA received several comments on various aspects of the SO2 allocation analyses presented in 

the Notice of Reconsideration. A few commenters claimed that EPA should have focused its 

analyses on State budgets rather than on projected allocations to companies because, with an 

alternative allocation approach, States would have the responsibility for allocating allowances to 

their respective affected sources and could meet control requirements differently than assumed in 

EPA’s analyses. Further, these commenters claimed a State-by-State analysis is more consistent 

with the analysis of NOx allocation methodologies in the Notice of Reconsideration and the final 

CAIR itself. Finally, one commenter noted that company-specific analysis can obscure state-bystate variation and may not be reliable given continual shifts in ownership structure. 

EPA agrees with the commenters that one method of evaluating the reasonableness of SO2 

allocation approaches is (in addition to company-by-company analyses) to compare State 

budgets calculated according to various methodologies. EPA performed the company-bycompany analyses described above in response to a specific petitioner’s claims that the SO2 

allowance allocation approach created inequities at the company-level. Despite one 

commenter’s assertion that such an analysis is made unreliable by constantly changing corporate 

structures, EPA believes that such an analysis remains instructive. A State-level analysis 

provides additional perspective on the impact of various allocation approaches, though it will, of 

course, obscure some of the potential company-level variability among allowance approaches. 

For this reason, EPA does not repeat the “Select High-emitting Companies” analysis in this 

document. 
 14

EPA presented such a State-by-State analysis in the final CAIR RTC (final CAIR “Corrected 

Response to Significant Public Comments on the Proposed Clean Air Interstate Rule,” Corrected 

April 2005 (Docket Number OAR-2003-0053)). EPA recognizes that the analysis prepared for 

the CAIR RTC did not consider two of the alternative allocation approaches discussed above. 

For today’s notice, EPA has analyzed State budgets calculated under eight different approaches 

(title IV and seven alternatives). These eight approaches are described in Table 1, below. 

Table 1. Description of Allocation Approaches Included in EPA Analysis 

Approach 

Name 

Description of Approach 

EPA Title IV Title IV allocations adjusted for the 2 to 1 allowance 

retirement ratio in 2010-2014 and the 2.86 to 1 

allowance retirement ratio in 2015 and thereafter. 

EPA’s chosen approach. 

Average 1999 -2002 (Pure) 

Heat Input 

For each State, calculates the average heat input over 

the years 1999-2002. Apportions the region-wide SO2 

cap to individual States based on each State’s share of 

the total region-wide average for those years. 

1999 -2002 Heat Input w/ Fuel 

Factors 

For each State, calculates the average adjusted heat 

input over the years 1999-2002. Adjusts heat input 

using factors of 1.0 for coal, 0.009 for natural gas, and 

0.3 for oil. Apportions the region-wide SO2 cap to 

individual States based on each State’s share of the 

total region-wide average adjusted heat input for those 

years. 

1999 -2002 Heat Input w/ Fuel 

Factors & Coal Type 

For each State, calculates the average adjusted heat 

input over the years 1999-2002. Adjusts heat input 

using factors of 2.6 for bituminous coal, 1.0 for 

subbituminous and lignite coals, 0.2 for natural gas, 

and 0.7 for oil. Apportions the region-wide SO2 cap 

to individual States based on each State’s share of the 

total region-wide average adjusted heat input for those 

years. 

Average 1999 -2002 Heat 

Input Coal + Oil 

For each State, calculates the average heat input from 

coal- and oil-fired units over the years 1999-2002. 

Apportions the region-wide SO2 cap to individual 

States based on each State’s share of the total regionwide average heat input from these units for those 

years. 

Average 1999 -2002 SO2 

Emissions 

For each State, calculates the average emissions over 

the years 1999-2002. Apportions the region-wide SO2 

cap to individual States based on each State’s share of 

the total region-wide average emissions for those 

years. 

Average 1999 -2002 

Generation Output (all sources 

fossil and non-fossil) 

For each State, calculates the average output over the 

years 1999-2002. Apportions the region-wide SO2 

cap to individual States based on each State’s share of 

the total region-wide average output for those years. 

1999 -2002 Generation 

Output (Fossil-fuel-fired units 

only) 

For each State, calculates the average output from 

fossil fuel-fired units over the years 1999-2002. 

Apportions the region-wide SO2 cap to individual 

States based on each State’s share of the total regionwide average output from these units for those years. 
 15

As is shown in Table 2, the first component of EPA’s State-level analysis compared the 

individual State shares of total region-wide SO2 allocations under the various approaches. The 

revised analysis reaffirms EPA’s original conclusion, which was that calculating State budgets 

using the title IV allowances results in about 80 percent of the States receiving a percentage of 

total SO2 allocations that is within the range of the percentages that resulted for these States 

under other suggested SO2 allocation approaches (“Sulfur Dioxide Allowance Allocation 

Methodology Comparative Analysis” Technical Support Document (Docket ID: EPA-HQ-OAR2003-0053)). In other words, 80 percent of States get neither the most nor the least allowances 

relative to what they receive under the other allocation approaches, under the title IV approach. 

Furthermore, when compared specifically to the methods supported by commenters (pure heat 

input, heat input with fuel factors, heat input with fuel factors and coal type, coal and oil heat 

input and average output all), distribution of State budgets using title IV allocations results in an 

individual State receiving its smallest or greatest share of total SO2 allocations relative to what 

the individual State receives under the alternative approaches the same number of times as the 

pure heat input methodology and fewer times than the other methodologies supported by 

commenters (see the last three rows of Table 2). Such results suggest that this approach 

performs as well as three of the other allocation approaches suggested by commenters, indicating 

that EPA’s argument that its chosen allocation approach is reasonable. While the coal and oil 

heat input approach appears to perform best in this analysis, this approach received more limited 

commenter support. 

In examining the results of this analysis for the States where commenters that submitted adverse 

comments on the use of title IV own generating units (FL, IN, MD MN,NY NC, PA, SC, TX), it 

becomes apparent that each allocation approach makes some States better off and others worse 

off. For example, North Carolina receives 3.8 percent of the total region-wide SO2 budget under 

the title IV approach, and Florida receives 7.0 percent. Under a heat input with fuel factors 

approach, North Carolina receives 4.5 percent of the total budget, while Florida receives its 

lowest share of the total budget (5.6 percent) of all eight allocation approaches. Similarly, while 

Florida and Texas receive their largest share of allowances under a fossil output-based approach 

or pure heat input approach, Maryland actually receives its lowest share of allowances under that 

approach. Florida, Maryland, Pennsylvania, and New York all receive more allowances under 

the title IV approach than they would under the heat input with fuel factors approach.4

 Further, 

while using a heat input with fuel factors approach would provide an advantage to many of the 

States that provided adverse comments on title IV, shifting to this approach would disadvantage 

10 of the 23 States (DC is not counted) relative to the title IV approach. 

 

4 Also, it is worth noting that the five most significant commenters from FL, IN, MN, NC, and SC are all in cost-ofservice States, where they should be able to pass through costs. In other words, sources in these States are likely to 

recover their cost of compliance, and the rate impact in these States, spread over all generation, transmission, and 

distribution is likely to be minimal. EPA’s Regulatory Impact Analysis for CAIR forecasts an increase of only 

about 2.0 percent and 2.7 percent in average electricity prices in the CAIR region in 2010 and 2015, respectively. 

Florida is projected to experience an increase in retail electricity prices of 0.8 percent in 2010 and 1.4 percent in 

2015. Also, the region containing North Carolina and South Carolina is forecast to have retail electricity price 

increases lower than the regional average increases under CAIR in 2010 and 2015. 

Notably, EPA found that commenters that did not like EPA’s approach to SO2 allocations owned less than 10 

percent of the coal-fire capacity in the CAIR region (see Appendix C). 
 16

Table 2. State Percentage of Regionwide Budget

State 

EPA 

Title 

IV 

Average 

1999 -2002 

(Pure) Heat 

Input 

1999 -2002 

Heat Input 

w/ Fuel 

Factors 

1999 -2002 

Heat Input w/ 

Fuel Factors 

& Coal Type 

Average 1999 

-2002 Heat 

Input Coal + 

Oil 

Average 

1999 -

2002 

Emissions 

Average1

999 -2002 

Output 

All 

Average 

1999 -

2002 

Output 

Fossil 

AL 4.4% 4.3% 4.9% 5.2% 4.7% 5.0% 4.7% 4.2% 

DC 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 

FL 7.0% 7.7% 5.6% 6.7% 7.3% 6.0% 7.2% 7.7% 

GA 5.9% 4.1% 4.7% 5.3% 4.5% 5.2% 4.5% 4.2% 

IA 1.8% 1.9% 2.4% 1.2% 2.3% 1.4% 1.5% 1.8% 

IL 5.3% 4.7% 5.4% 4.4% 5.2% 4.7% 6.6% 4.4% 

IN 7.0% 6.5% 7.9% 7.9% 7.5% 8.6% 4.6% 6.2% 

KY 5.2% 4.9% 6.0% 7.3% 5.8% 5.8% 3.5% 4.5% 

LA 1.7% 3.3% 1.6% 1.0% 1.5% 1.1% 3.4% 3.6% 

MD 2.0% 1.8% 1.9% 2.3% 2.0% 2.7% 1.9% 1.7% 

MI 4.9% 4.2% 4.4% 3.7% 4.3% 3.7% 4.1% 4.2% 

MN 1.4% 1.9% 2.3% 1.1% 2.2% 1.0% 1.9% 1.7% 

MO 3.8% 3.6% 4.3% 2.3% 4.1% 2.4% 2.9% 3.4% 

MS 0.9% 1.4% 1.0% 1.0% 1.1% 1.2% 1.6% 1.6% 

NC 3.8% 3.7% 4.5% 5.5% 4.3% 4.7% 4.5% 3.8% 

NY 3.7% 4.0% 2.2% 2.7% 3.4% 2.7% 5.3% 3.9% 

OH 9.2% 6.4% 7.9% 9.6% 7.5% 12.2% 5.4% 6.5% 

PA 7.6% 6.0% 7.1% 8.4% 6.9% 9.5% 7.4% 6.1% 

SC 1.6% 2.0% 2.3% 2.9% 2.2% 2.1% 3.4% 2.0% 

TN 3.8% 3.0% 3.7% 4.4% 3.5% 4.0% 3.5% 3.0% 

TX 8.9% 15.3% 9.4% 5.5% 9.0% 6.0% 13.9% 16.6% 

VA 1.8% 2.3% 2.5% 3.1% 2.5% 2.3% 2.8% 2.3% 

WI 2.4% 2.5% 2.9% 1.8% 2.8% 2.0% 2.2% 2.2% 

WV 6.0% 4.4% 5.4% 6.7% 5.2% 5.8% 3.4% 4.5% 

 100% 100% 100% 100% 100% 100% 100% 100% 

# of times 

method 

provides 

least 

allowances 3 4 2 7 0 2 4 4 

# of times 

method 

provides 

most 

allowances 2 1 4 6 0 4 4 4 

Total 

(most + 

least) 

5 5 6 13 0 6 8 8 

Two commenters performed alternative analyses of State budgets, modeled after the calculations 

done for the CAIR Reconsideration related to NOx budgets (CAIR Statewide NOx Budget 

Calculations, EPA Docket Number OAR-2003-0053, December 2005). The commenters claim 

that their analysis proves that EPA’s SO2 allowance allocation approach is inferior to a fueladjusted heat input method, such as the allocation approach used in the CAIR NOx model 
 17

trading rule. They assert that EPA’s analysis of NOx allocation methodologies is also the 

appropriate way to compare the reasonableness of the SO2 allocation alternatives. 

As EPA explained in the NOx TSD, to quantitatively evaluate whether the fuel factor approach is 

providing States with annual NOx budgets that more closely reflected their projected emissions, 

EPA calculated the arithmetic mean of the (absolute) difference between the ratio of each State’s 

allowance allocation under each approach to its projected emissions under CAIR (coverage 

ratio), and 1.0 (i.e., the value representing a State’s projected emissions matching the State’s 

CAIR NOx budget). In other words, EPA calculated how far off the State’s coverage ratio was 

from 1.0, and then determined the average value of this difference for each approach. 

One commenter performed a similar analysis of State budgets, comparing each State’s projected 

emissions to its projected allowances under each allocation approach. The commenter analyzed 

the results in relation to a coverage ratio of 1.0 (as EPA did in its NOx analysis) and averaged the 

values for each approach. Another commenter performed a similar analysis but presented the 

results as the cumulative value (sum) of absolute differences between the coverage ratios and 

1.0. 

EPA disagrees with the commenter’s assertion that the methodology that the Agency used to 

evaluate State NOx allocations should be the primary means by which to evaluate the 

reasonableness of the SO2 allocation methodology. As explained in the CAIR preamble, in the 

case of SO2, EPA needs to balance various considerations, including the need to allocate SO2 

allowances in a way that is less disruptive to the title IV program. In light of these 

considerations, minimizing the disparity between a State’s allocation and projected emissions 

cannot be the primary objective. For SO2, there is a pre-existing national trading program (the 

Acid Rain SO2 trading program) that Congress intended to continue as a viable program into the 

future and under which allowances have been allocated in perpetuity. For NOx, there is no preexisting national trading program where efficiency and effectiveness would be jeopardized by 

creating new CAIR NOx allowances. There is, of course, a pre-existing regional NOx ozoneseason program covering a portion of the CAIR region (the NOx Budget Trading Program, 

established by regulation, rather than directly by Congress). Under the existing NOx ozoneseason program, no State has allocated allowances past 2009 (and only a handful of States have 

allocated allowances past 2008). Therefore, in contrast with EPA’s determination concerning 

SO2 allocations, evaluation of potential approaches to NOx allocations did not involve concerns 

about Congressional intent to preserve an existing trading program and about preserving the 

value of allowances already allocated in perpetuity. For NOx, EPA does not need to consider 

other important policy concerns that are important for SO2 (as explained above and in the CAIR 

final rule). 

While the methodology used by EPA to evaluate NOx allocation methodologies for CAIR can be 

applied to analysis of SO2 allocations, EPA believes that the commenters performed their Stateby-State analyses incorrectly, overlooking a fundamental difference between the CAIR NOx and 

SO2 trading programs, which is the existence of a significant bank of pre-2010 allowances that 

will be eligible for use for compliance with CAIR. Because of the existence of a SO2 allowance 

bank, EPA believes that the commenter’s comparison of allocation approaches using a coverage 

ratio of 1.0, which would assume that in a given year total SO2 emissions in the region are equal 
 18

to the total region-wide SO2 budget, is not appropriate for evaluating the SO2 State budgets 

resulting from the various SO2 allocation methodologies. A State that had a coverage ratio of 

1.0 would have enough allowances to cover its emissions, and, while this ratio would be a 

meaningful target in the context of the CAIR NOx trading program, it is not for SO2, because 

2010 and 2015 emissions will be higher than the region-wide cap due to the use of banked 

allowances. For SO2, the region-wide ratios of allowances to projected emissions are 0.70 for 

2010 and 0.60 for 2015. On average, one would expect States to have coverage ratios similar to 

the region-wide average. 

While in both the NOx annual and NOx ozone season trading programs some allowances beyond 

the State Budgets (i.e., compliance supplement pool allowances in the annual program and 

banked allowances from the NOx Budget Trading Program in the ozone-season program) will be 

available to sources, the amount of these extra allowances will be too small to affect the Stateby-State NOx analysis. Consequently, EPA believes that a more appropriate way to evaluate 

SO2 allocation methods is to use the 0.70 (for 2010) and 0.60 (for 2015) coverage ratios, rather 

than a ratio of 1.0. Further, because each allocation approach results in allocation that are 

advantageous for different companies and States, EPA believes that the reasonableness of a 

given allocation approach should be judged by its overall impact on companies and States, not its 

specific impact on any single company or State or on a few companies or States. 

EPA has redone the commenters’ analysis, using the methodology used by EPA in its analysis of 

NOx allocations and corrected coverage ratios described above. This analysis is presented in 

Appendix A, tables A to D. The State budget and emissions data behind the tables in Appendix 

A are available in Appendix A, Table E, as well as in the docket, “SO2 Allocations Analysis 

Data.” 

While the title IV SO2 allocation approach does not perform the best of the allocation 

approaches considered using this metric, the differences observed among the approaches are of a 

lower magnitude than those suggested by the commenters. The commenters did not provide any 

benchmark in their analysis for assessing whether or not a given allocation approach was 

reasonable. Further, although the commenters discuss some of the implications of the 

differences observed between an allocation approach based on fuel factors and the allocation 

approach based on title IV, they do not conclude their analyses with any meaningful arguments 

that EPA’s approach is not reasonable. 

As EPA noted earlier in this section, there are a number of ways by which to assess the 

equitability of a given allowance allocation approach. For a further understanding of the overall 

relative impacts of the various allocation approaches, EPA believes that it is useful to apply the 

statistical concepts of (1) bias and (2) consistency. EPA determined that an appropriate statistic 

for examining the bias of a given allocation approach is the average difference between a State’s 

coverage ratio and the coverage ratio for the entire region (e.g., 0.70 for 2010 or 0.60 for 2015). 

The degree of bias inherent in a given allocation approach cannot be discerned from the absolute 

value statistic, because it ignores the degree to which positive and negative differences cancel 

each other out. A perfectly unbiased distribution under a given allocation approach would be 

one that resulted in an average difference of zero, meaning that on average a State-by-State 

coverage ratio higher than the regional coverage ratio is balanced out by a ratio below. Another 
 19

useful statistic is the percent of instances in which the allocation approach yields a State 

coverage ratio that is high (or low) relative to the regional coverage ratio. Lack of bias would be 

indicated if 50 percent of the State coverage ratios are higher than the regional coverage ratio and 

50 percent are lower. 

EPA evaluated the four allocation approaches considered during the CAIR rulemaking (title IV, 

pure heat input, heat input with fuel-factors, and heat input with fuel factors and coal type 

factors) along these metrics. From EPA’s calculations (Table 3), all the approaches are biased 

high for 2010 and all but one is biased high for 2015 (with CAIR controls). The average 

differences for EPA’s approach, 0.06 (range across approaches: 0.05 to 0.11) in 2010 and 0.17 

(range across approaches: -0.17 to 0.18) in 2015, are among the closest to zero compared to the 

alternatives examined. The one approach (heat input with fuel and coal adjustment factors) that 

exhibits less bias than the title IV approach in 2010 exhibits bias of the same magnitude (but 

opposite direction) as the title IV approach in 2015. In addition, the percent of positive 

differences for EPA’s approach for 2010 and 2015 are near 50 percent and do not greatly vary 

from the alternative methods analyzed. This demonstrates that EPA’s approach provides a 

reasonable result. (Summary tables of all metrics analyzed, including bias and consistency, are 

available in Tables 6 and 7 below. 

Table 3. Evaluation of Bias and Consistency of Four Different SO2 Allocation 

Approaches, 2010 and 2015 

2010 2015

EPA 

Title IV

Avera

ge 

1999 -

2002 

(Pure) 

Heat 

Input

1999 -

2002 

Heat 

Input 

w/ Fuel 

Factors

1999 -

2002 

Heat 

Input 

w/ Fuel 

Factors 

& Coal 

Type

EPA 

Title 

IV

Avera

ge 

1999 -

2002 

(Pure) 

Heat 

Input

1999 -

2002 

Heat 

Input 

w/ Fuel 

Factors

1999 -

2002 

Heat 

Input w/ 

Fuel 

Factors 

& Coal 

Type

Average 

Difference 0.06 0.11 0.06 0.05 0.17 0.18 0.14 -0.17 

Percent 

Positive 43% 39% 52% 48% 43% 43% 43% 52% 

Source: EPA 2006 

One commenter, who disagreed with EPA’s focus on how States fare under different 

methodologies, suggested using an “effective emission rate comparison.” However, the 

commenter proceeded to perform this comparison using of the ratio of the adjusted state SO2 

budgets to recent adjusted heat input in each affected state. The commenter failed to realize that 

using the adjusted state SO2 budget in the numerator and adjusted heat input (i.e., the heat input 

values adjusted with fuel factors, which were used to calculate the State budgets) in the 

denominator results in a constant ratio across States. Based on the commenter’s arguments, it 

appears it should have used the adjusted State budget divided by the actual projected heat input. 

This approach, however, would not result in the constant effective emission rates, which the 

commenter insinuates is most desirable. The commenter’s argument, therefore, is based on 

fatally flawed analysis. 
 20

Several commenters have raised concerns about the cost of purchasing allowances to meet 

projected emissions under EPA’s approach, relative to another alternative. To provide some 

perspective of the significance of these purchases, EPA calculated the projected cost of 

purchasing allowances as a percentage of revenue from electricity sales in 2004 for select States 

in CAIR for SO2 (Tables 4 and 5). The CAIR region-wide cost as a percentage of revenue is a 

fraction of one percent for either 2010 or 2015. These States are projected to spend less than 2% 

of their revenue on purchasing allowances in either 2010 or 2015. Most States from which 

commenting companies operate are projected to spend even less than 1 percent or less of 

revenues on allowances, and Florida is projected to be a net seller of allowances (signified by the 

negative sign for both 2010 and 2015).5 In fact, the States that are projected to spend the most 

on purchasing allowances as a percentage of revenue (Kentucky in 2010 and Michigan in 2015) 

do not have companies commenting on this Reconsideration process. 

Table 4: 2010 State Budgets, Projected Emissions and Allowance Costs for States with 

Commenters Opposing EPA Approach 

State 

 2010 

CAIR SO2 

Emissions 

(Tons) 

 2010 

Base 

Case SO2 

Emissions 

(Tons) 

Final CAIR 

2010 State 

SO2 

Budget 

Heat 

Input 

Method 

2010 

State 

Budget 

Heat 

Input w/ 

Fuel 

Factors 

2010 

State 

Budget 

Heat 

Input w/ 

Fuel 

Factors & 

Coal 

Type 

2010 

State 

Budget 

2010 

Projected 

Allowance 

Cost (2004$) 

2004 State 

Electric Power 

Revenue 

(2004$) 

2010 

Projected 

Allowance 

Cost as 

Percent of 

Current 

Revenue 

FL 

 

217,697 

 

220,670 253,450 279,084 203,650 244,120 -24,526,627 17,834,520,000 -0.1% 

IL 

 

239,867 

 

401,522 192,671 168,592 195,590 158,976 32,376,250 9,464,950,000 0.3% 

MD 

 

61,815 

 

309,968 70,697 63,847 68,691 83,869 -6,092,778 4,785,324,000 -0.1% 

MN 

 

68,734 

 

83,110 49,987 68,420 81,572 40,045 12,860,442 3,950,079,000 0.3% 

NC 

 

252,132 

 

261,352 137,342 134,643 161,807 199,711 78,745,940 8,756,173,000 0.9% 

PA 

 

234,757 

 

907,768 275,990 217,369 255,227 302,565 -28,285,975 11,485,558,000 -0.2% 

SC 

 

141,276 

 

196,065 57,271 71,616 84,298 104,757 57,627,704 4,971,537,000 1.2% 

TX 

 

398,088 

 

417,397 320,946 555,455 339,975 199,493 52,919,275 25,482,302,000 0.2% 

Note: Projected allowance costs are estimated at $686 per ton using IPM modeling run CAIR_CAMR_CAVR available at 

www.epa.gov/airmarkets/mp adjusted to 2004$. Electric power revenues are based on U.S. Department of Energy, Energy Information

Administration, "Electric Power Annual 2004," available at www.eia.doe.gov/cneaf/electricity/epa/epa_sum.html 

 

5 Based on EPA calculations of Acid Rain Program emissions data from 2003 to 2004 compared to SO2 

allocations over the same time period, EPA sees that Minnesota Power and Florida Power and Light have 

had more allowances than they needed to cover their emissions in recent years. As net “sellers” of 

allowances, companies in these States have been able to either build up an allowance bank for future use 

or sell their excess allowances.
 21

Table 5: 2015 State Budgets, Projected Emissions and Allowance Costs for States with Commenters 

Opposing EPA Approach 

State 

 2015 

CAIR SO2 

Emissions 

(Tons) 

 2015 

Base 

Case SO2 

Emissions 

(Tons) 

Final CAIR 

2015 State 

SO2 

Budget 

Heat 

Input 

Method 

2015 

State 

Budget 

Heat 

Input w/ 

Fuel 

Factors 

2015 

State 

Budget 

Heat 

Input w/ 

Fuel 

Factors 

& Coal 

Type 

2015 

State 

Budget 

2015 

Projected 

Allowance 

Cost (2004$) 

2004 State 

Electric Power 

Revenue 

(2004$) 

2015 

Projected 

Allowance 

Cost as 

Percent of 

Current 

Revenue 

FL 

 

167,154 

 

220,670 177,415 195,359 142,555 170,884 -10,199,335 17,834,520,000 -0.1% 

IL 

 

239,660 

 

446,728 134,869 118,015 136,913 111,283 104,162,453 9,464,950,000 1.1% 

MD 

 

23,813 

 

312,974 49,488 44,693 48,084 58,708 -25,520,851 4,785,324,000 -0.5% 

MN 

 

71,988 

 

82,046 34,991 47,894 57,100 28,031 36,774,521 3,950,079,000 0.9% 

NC 

 

137,886 

 

142,109 96,139 94,250 113,264 139,798 41,496,518 8,756,173,000 0.5% 

PA 

 

132,469 

 

851,260 193,193 152,158 178,659 211,795 -60,359,557 11,485,558,000 -0.5% 

SC 

 

104,436 

 

170,353 40,089 50,131 59,008 73,330 63,960,421 4,971,537,000 1.3% 

TX 

 

352,064 

 

417,558 224,662 388,818 237,982 139,645 126,637,389 25,482,302,000 0.5% 

Note: Projected allowance costs are estimated at $994 per ton using IPM modeling run CAIR_CAMR_CAVR available at 

www.epa.gov/airmarkets/mp adjusted to 2004$. Electric power revenues are based on U.S. Department of Energy, Energy Information

Administration, "Electric Power Annual 2004," available at www.eia.doe.gov/cneaf/electricity/epa/epa_sum.html 

EPA’s approach provides values within the range of alternatives considered for all of the metrics 

examined in the SO2 analyses as presented in the following tables (6-7). Furthermore, when 

examining metrics using base case emissions, EPA’s approach performs better than the heat 

input with fuel factors approach. By these measures, EPA’s approach better distributes 

allowances across the system before control decisions are made to meet CAIR emission 

reduction goals. 
 22

Table 6. Summary -- CAIR Control Case Difference of State-by-State SO2 Coverage Ratios 

(Budget: Emission) from Region-wide Percent Reduction 

 2010 2015 

 

Final 

CAIR 

SO2 

Heat 

Input 

(3b) 

Heat 

Input w/ 

Fuel 

Factors 

(4b) 

Heat 

Input w/ 

Fuel 

Factors 

& Coal 

Type 

(5b) 

Final 

CAIR 

SO2 

Heat 

Input 

(3b) 

Heat 

Input w/ 

Fuel 

Factors 

(4b) 

Heat 

Input w/ 

Fuel 

Factors 

& Coal 

Type (5b) 

Average 

Coverage Ratio 0.76 0.81 0.76 0.75 0.77 0.78 0.74 0.77 

Average 

Difference 0.06 0.11 0.06 0.05 0.17 0.18 0.14 -0.17 

Percent Positive 43% 39% 52% 48% 43% 43% 43% 52% 

Cumulative 

Absolute 

Difference 6.13 7.29 4.37 5.94 8.06 8.36 5.97 9.03 

Average 

Absolute 

Difference 0.27 0.32 0.19 0.26 0.35 0.36 0.26 0.39 

Source: EPA, 2006 

Table 7. Base Case Difference of State-by-State SO2 Coverage Ratios (Budget: Emission) from 

Regionwide Percent Reduction 

 

 2010 2015 

Final 

CAIR 

SO2 

Heat 

Input 

(3b) 

Heat 

Input w/ 

Fuel 

Factors 

(4b) 

Heat 

Input w/ 

Fuel 

Factors & 

Coal Type 

(5b) 

Final 

CAIR 

SO2 

Heat 

Input 

(3b) 

Heat 

Input w/ 

Fuel 

Factors 

(4b) 

Heat 

Input w/ 

Fuel 

Factors & 

Coal Type 

(5b) 

Average 

Coverage Ratio 0.48 0.54 0.50 0.46 0.35 0.39 0.36 0.34 

Average 

Difference 0.06 0.12 0.08 0.04 0.05 0.14 0.08 0.04 

Percent Positive 43% 43% 61% 52% 39% 43% 52% 57% 

Cumulative 

Absolute 

Difference 3.60 5.86 3.82 2.71 2.35 4.00 2.62 2.08 

Average Absolute 

Difference 0.16 0.25 0.17 0.12 0.20 0.33 0.22 0.17 

Source: EPA, 2006 
 23

Further examination of the analyses shows that each approach advantages and disadvantages 

electric generating units using fossil fuels some in States. A few States receive coverage ratios 

that are consistently on one end of the spectrum or the other regardless of which approach is 

taken, according to EPA projections. Michigan and Georgia have coverage ratios in the bottom 

5 of all CAIR States analyzed (low category). New York and Maryland receive among the 5 

highest coverage ratios in 2010 under the CAIR control case (high category). Meanwhile, some 

States are particularly advantaged or disadvantaged by one or a few of the approaches and not 

others (see Tables 8 to 11). For example, choosing the pure heat input method would put 

Tennessee into the low category, while bringing Texas and Louisiana into the high category. On 

the other hand, choosing any of the fuel adjusted methods, including EPA’s method, would 

guarantee that Ohio, Pennsylvania, Maryland and New York are in the high category, while 

Georgia, Mississippi, and Michigan would be in the low category. Minnesota has among the 

highest relative rank with heat input with fuel factors, but Iowa joins the low category in that 

case. South Carolina is in the low category in 2010 CAIR control case for all approaches except 

heat input with fuel factors and coal type. 

These tables further demonstrate that each allocation approach results in a somewhat different 

mix of States who, in general, will be net sellers or buyers of allowances. This alone is not 

enough to assess the fairness of a particular method, as some commenters have alleged. 

However, after evaluating multiple approaches compared to EPA’s approach with several 

analytical and statistical methods seen throughout this TSD and its appendices, EPA has 

determined that its SO2 allowance allocation methodology is a rational choice among the options 

to support the objectives stated above. 
 24

Table 8. 2010 State-by-State CAIR Control Case Coverage Ratios in Descending 

Order 

State 

CAIR 

SO2 State 

Heat 

Input State 

Heat Input 

with Fuel 

Factors State 

Heat Input 

with Fuel 

Factors and 

Coal Type 

NY 2.04 NY 2.20 MN 1.19 NY 1.45 

PA 1.18 LA 1.94 NY 1.17 MD 1.36 

FL 1.16 TX 1.40 MD 1.11 PA 1.29 

MD 1.14 FL 1.28 PA 1.09 OH 1.17 

OH 1.12 MD 1.03 OH 0.95 FL 1.12 

LA 0.97 MN 1.00 FL 0.94 WV 0.97 

WV 0.86 PA 0.93 LA 0.93 VA 0.82 

TX 0.81 OH 0.78 TX 0.85 NC 0.79 

IL 0.80 IL 0.70 IL 0.82 KY 0.77 

MN 0.73 WI 0.65 WV 0.78 TN 0.75 

TN 0.65 WV 0.63 WI 0.77 SC 0.74 

WI 0.64 VA 0.61 IA 0.72 IN 0.67 

IN 0.59 MS 0.59 IN 0.66 IL 0.66 

MO 0.57 IA 0.59 VA 0.66 AL 0.59 

KY 0.55 IN 0.55 NC 0.64 LA 0.58 

NC 0.54 MO 0.54 MO 0.64 MN 0.58 

IA 0.54 NC 0.53 KY 0.64 TX 0.50 

AL 0.49 KY 0.52 TN 0.63 WI 0.47 

GA 0.48 TN 0.52 SC 0.60 MS 0.44 

MI 0.47 SC 0.51 AL 0.55 GA 0.43 

VA 0.47 AL 0.48 MS 0.42 IA 0.37 

SC 0.41 MI 0.40 MI 0.42 MI 0.35 

MS 0.39 GA 0.33 GA 0.38 MO 0.34 

Source: EPA, 2006 
 25

Table 9. 2010 State-by-State Base Case Coverage Ratios in Descending Order 

State 

CAIR 

SO2 State 

Heat 

Input State 

Heat Input 

with Fuel 

Factors State 

Heat Input with 

Fuel Factors and 

Coal Type 

FL 1.15 TX 1.33 MN 0.98 FL 1.11 

NY 1.03 FL 1.26 MO 0.98 NY 0.74 

TX 0.77 LA 1.21 FL 0.92 KY 0.59 

LA 0.60 NY 1.12 TX 0.81 VA 0.58 

MN 0.60 MN 0.82 NC 0.63 WI 0.58 

MO 0.60 MO 0.82 NY 0.60 SC 0.53 

NC 0.55 MS 0.59 LA 0.58 MN 0.48 

IL 0.48 NC 0.53 KY 0.49 MO 0.48 

MI 0.46 VA 0.44 IL 0.49 TX 0.48 

KY 0.42 WI 0.44 VA 0.47 TN 0.45 

MS 0.39 IL 0.42 WI 0.47 IN 0.44 

IN 0.39 KY 0.40 IN 0.44 MS 0.44 

TN 0.39 MI 0.40 SC 0.43 WV 0.42 

WV 0.37 SC 0.37 MS 0.42 IL 0.40 

GA 0.36 IN 0.36 MI 0.41 AL 0.39 

IA 0.36 AL 0.32 TN 0.38 LA 0.36 

VA 0.33 TN 0.31 AL 0.37 MI 0.35 

WI 0.33 WV 0.27 WV 0.33 PA 0.33 

AL 0.33 GA 0.25 GA 0.29 NC 0.33 

PA 0.30 IA 0.25 IA 0.29 GA 0.33 

SC 0.29 PA 0.24 PA 0.28 IA 0.33 

OH 0.24 MD 0.21 MD 0.22 MD 0.27 

MD 0.23 OH 0.17 OH 0.21 OH 0.25 

Source: EPA, 2006 
 26

Table 10. 2015 State-by-State CAIR Control Case Coverage Ratios in Descending Order 

State CAIR SO2 State Heat Input State 

Heat Input 

with Fuel 

Factors State 

Heat Input 

with Fuel 

Factors and 

Coal Type 

NY 2.32 NY 2.51 MD 2.02 MD 2.47 

MD 2.08 MD 1.88 PA 1.35 NY 1.65 

PA 1.46 LA 1.36 NY 1.34 PA 1.60 

WV 1.28 FL 1.17 WV 1.15 WV 1.44 

OH 1.12 PA 1.15 OH 0.96 OH 1.17 

FL 1.06 TX 1.10 FL 0.85 FL 1.02 

NC 0.70 WV 0.94 NC 0.82 NC 1.01 

LA 0.68 OH 0.79 MN 0.79 SC 0.70 

TX 0.64 NC 0.68 TX 0.68 TN 0.69 

TN 0.60 MN 0.67 LA 0.65 KY 0.68 

GA 0.60 VA 0.50 TN 0.58 VA 0.67 

IL 0.56 IL 0.49 IL 0.57 IN 0.57 

IN 0.51 SC 0.48 SC 0.57 GA 0.54 

KY 0.49 TN 0.48 KY 0.56 AL 0.52 

MN 0.49 WI 0.48 IN 0.56 IL 0.46 

WI 0.46 IN 0.47 WI 0.56 LA 0.41 

AL 0.43 KY 0.46 VA 0.54 TX 0.40 

MO 0.39 MS 0.44 AL 0.48 MN 0.39 

SC 0.38 AL 0.42 IA 0.48 WI 0.34 

VA 0.38 GA 0.41 GA 0.48 MS 0.33 

IA 0.36 IA 0.39 MO 0.44 IA 0.25 

MI 0.32 MO 0.37 MS 0.31 MI 0.24 

MS 0.29 MI 0.28 MI 0.29 MO 0.23 

Source: EPA, 2006 
 27

Table 11. 2015 State-by-State Base Case Coverage Ratios in 

Descending Order 

State CAIR SO2 State Heat Input State 

Heat Input 

with Fuel 

Factors State 

Heat Input 

with Fuel 

Factors and 

Coal Type 

FL 0.80 TX 0.93 MN 0.70 FL 0.77 

NY 0.72 FL 0.89 MO 0.70 NY 0.51 

TX 0.54 LA 0.85 FL 0.65 KY 0.44 

MN 0.43 NY 0.77 TX 0.57 VA 0.43 

MO 0.43 MN 0.58 NC 0.43 WI 0.43 

LA 0.42 MO 0.58 NY 0.41 SC 0.43 

NC 0.38 MS 0.42 LA 0.41 IN 0.38 

IN 0.34 NC 0.36 IN 0.37 TN 0.35 

KY 0.32 VA 0.32 KY 0.37 WV 0.34 

MI 0.31 WI 0.32 VA 0.35 MN 0.34 

WV 0.31 IN 0.31 WI 0.35 MO 0.34 

TN 0.30 KY 0.30 SC 0.35 TX 0.33 

IL 0.30 SC 0.29 IL 0.31 AL 0.33 

MS 0.28 MI 0.27 AL 0.30 MS 0.31 

AL 0.27 AL 0.27 TN 0.30 LA 0.26 

GA 0.25 IL 0.26 MS 0.30 IL 0.25 

IA 0.25 TN 0.24 MI 0.28 PA 0.25 

VA 0.25 WV 0.22 WV 0.28 MI 0.24 

WI 0.25 PA 0.18 PA 0.21 GA 0.23 

SC 0.24 GA 0.17 GA 0.20 IA 0.23 

PA 0.23 IA 0.17 IA 0.20 OH 0.23 

OH 0.22 OH 0.15 OH 0.19 NC 0.23 

MD 0.16 MD 0.14 MD 0.15 MD 0.19 

Source: EPA, 2006 
 28

Appendix A – EPA Difference Tables 
 29
 1

Table A. 2010 State-by-State CAIR Control Case Coverage Ratios, CAIR & Alternatives CAIR SO2 Heat Input Heat Input w/ Fuel Factors 

Heat Input w/ Fuel Factors & Coal 

Type 

State 

Coverage 

Ratio: 

Budget 

to 

Emission 

Difference 

(from 

0.70) 

Absolute 

Difference 

(from 

0.70) 

Coverage 

Ratio: 

Budget 

to 

Emission 

Difference 

(from 

0.70) 

Absolute 

Difference 

(from 

0.70) 

Coverage 

Ratio: 

Budget 

to 

Emission 

Difference 

(from 

0.70) 

Absolute 

Difference 

(from 

0.70) 

Coverage 

Ratio: 

Budget 

to 

Emission 

Difference 

(from 

0.70) 

Absolute 

Difference 

(from 

0.70) 

AL 0.49 -0.21 0.21 0.48 -0.22 0.22 0.55 -0.15 0.15 0.59 -0.11 0.11 FL 1.16 0.46 0.46 1.28 0.58 0.58 0.94 0.24 0.24 1.12 0.42 0.42 GA 0.48 -0.23 0.23 0.33 -0.37 0.37 0.38 -0.32 0.32 0.43 -0.27 0.27 IA 0.54 -0.16 0.16 0.59 -0.11 0.11 0.72 0.02 0.02 0.37 -0.33 0.33 IL 0.80 0.10 0.10 0.70 0.00 0.00 0.82 0.12 0.12 0.66 -0.04 0.04 IN 0.59 -0.11 0.11 0.55 -0.15 0.15 0.66 -0.04 0.04 0.67 -0.03 0.03 KY 0.55 -0.15 0.15 0.52 -0.18 0.18 0.64 -0.06 0.06 0.77 0.07 0.07 LA 0.97 0.26 0.26 1.94 1.24 1.24 0.93 0.23 0.23 0.58 -0.12 0.12 MD 1.14 0.44 0.44 1.03 0.33 0.33 1.11 0.41 0.41 1.36 0.66 0.66 MI 0.47 -0.24 0.24 0.40 -0.30 0.30 0.42 -0.28 0.28 0.35 -0.35 0.35 MN 0.73 0.02 0.02 1.00 0.30 0.30 1.19 0.49 0.49 0.58 -0.12 0.12 MO 0.57 -0.14 0.14 0.54 -0.16 0.16 0.64 -0.06 0.06 0.34 -0.36 0.36 MS 0.39 -0.31 0.31 0.59 -0.11 0.11 0.42 -0.28 0.28 0.44 -0.26 0.26 NC 0.54 -0.16 0.16 0.53 -0.17 0.17 0.64 -0.06 0.06 0.79 0.09 0.09 NY 2.04 1.33 1.33 2.20 1.50 1.50 1.17 0.47 0.47 1.45 0.75 0.75 OH 1.12 0.41 0.41 0.78 0.08 0.08 0.95 0.25 0.25 1.17 0.47 0.47 PA 1.18 0.47 0.47 0.93 0.23 0.23 1.09 0.39 0.39 1.29 0.59 0.59 SC 0.41 -0.30 0.30 0.51 -0.19 0.19 0.60 -0.10 0.10 0.74 0.04 0.04 TN 0.65 -0.05 0.05 0.52 -0.18 0.18 0.63 -0.07 0.07 0.75 0.05 0.05 TX 0.81 0.10 0.10 1.40 0.70 0.70 0.85 0.15 0.15 0.50 -0.20 0.20 VA 0.47 -0.24 0.24 0.61 -0.09 0.09 0.66 -0.04 0.04 0.82 0.12 0.12 WI 0.64 -0.07 0.07 0.65 -0.05 0.05 0.77 0.07 0.07 0.47 -0.23 0.23 WV 0.86 0.16 0.16 0.63 -0.07 0.07 0.78 0.08 0.08 0.97 0.27 0.27 Total 1.40 6.13 2.62 7.29 1.46 4.37 1.11 5.94 Average 0.76 0.06 0.27 0.81 0.11 0.32 0.76 0.06 0.19 0.75 0.05 0.26 Percent Positive 43% 39% 52% 48% 

Source: EPA, 2006 
 2

Table B. 2015 State-by-State CAIR Control Coverage Ratios, CAIR & Alternatives 

CAIR SO2 Heat Input Heat Input w/ Fuel Factors 

Heat Input w/ Fuel Factors & Coal 

Type 

State 

Coverage 

Ratio: 

Budget to 

Emission 

Difference 

(from 

0.60) 

Absolute 

Difference 

(from 

0.60) 

Coverage 

Ratio: 

Budget 

to 

Emission 

Difference 

(from 

0.60) 

Absolute 

Difference 

(from 

0.60) 

Coverage 

Ratio: 

Budget to 

Emission 

Difference 

(from 

0.60) 

Absolute 

Difference 

(from 

0.60) 

Coverage 

Ratio: 

Budget to 

Emission 

Difference 

(from 

0.60) 

Absolute 

Difference 

(from 

0.60) 

AL 0.43 -0.17 0.17 0.42 -0.18 0.18 0.48 -0.12 0.12 0.52 0.08 0.08 FL 1.06 0.46 0.46 1.17 0.57 0.57 0.85 0.25 0.25 1.02 -0.42 0.42 GA 0.60 0.00 0.00 0.41 -0.19 0.19 0.48 -0.12 0.12 0.54 0.06 0.06 IL 0.56 -0.04 0.04 0.49 -0.11 0.11 0.57 -0.03 0.03 0.46 0.14 0.14 IN 0.51 -0.09 0.09 0.47 -0.13 0.13 0.56 -0.04 0.04 0.57 0.03 0.03 IA 0.36 -0.24 0.24 0.39 -0.21 0.21 0.48 -0.12 0.12 0.25 0.35 0.35 KY 0.49 -0.11 0.11 0.46 -0.14 0.14 0.56 -0.04 0.04 0.68 -0.08 0.08 LA 0.68 0.08 0.08 1.36 0.76 0.76 0.65 0.05 0.05 0.41 0.19 0.19 MD 2.08 1.48 1.48 1.88 1.28 1.28 2.02 1.42 1.42 2.47 -1.87 1.87 MI 0.32 -0.28 0.28 0.28 -0.32 0.32 0.29 -0.31 0.31 0.24 0.36 0.36 MN 0.49 -0.11 0.11 0.67 0.07 0.07 0.79 0.19 0.19 0.39 0.21 0.21 MS 0.29 -0.31 0.31 0.44 -0.16 0.16 0.31 -0.29 0.29 0.33 0.27 0.27 MO 0.39 -0.21 0.21 0.37 -0.23 0.23 0.44 -0.16 0.16 0.23 0.37 0.37 NY 2.32 1.72 1.72 2.51 1.91 1.91 1.34 0.74 0.74 1.65 -1.05 1.05 NC 0.70 0.10 0.10 0.68 0.08 0.08 0.82 0.22 0.22 1.01 -0.41 0.41 OH 1.12 0.52 0.52 0.79 0.19 0.19 0.96 0.36 0.36 1.17 -0.57 0.57 PA 1.46 0.86 0.86 1.15 0.55 0.55 1.35 0.75 0.75 1.60 -1.00 1.00 SC 0.38 -0.22 0.22 0.48 -0.12 0.12 0.57 -0.03 0.03 0.70 -0.10 0.10 TN 0.60 0.00 0.00 0.48 -0.12 0.12 0.58 -0.02 0.02 0.69 -0.09 0.09 TX 0.64 0.04 0.04 1.10 0.50 0.50 0.68 0.08 0.08 0.40 0.20 0.20 VA 0.38 -0.22 0.22 0.50 -0.10 0.10 0.54 -0.06 0.06 0.67 -0.07 0.07 WV 1.28 0.68 0.68 0.94 0.34 0.34 1.15 0.55 0.55 1.44 -0.84 0.84 WI 0.46 -0.14 0.14 0.48 -0.12 0.12 0.56 -0.04 0.04 0.34 0.26 0.26 Total 3.81 8.06 4.11 8.36 3.25 5.97 -3.99 9.03 Average 0.77 0.17 0.35 0.78 0.18 0.36 0.74 0.14 0.26 0.77 -0.17 0.39 Percent Positive 43% 43% 43% 52% 

Source: EPA, 2006 
Table E. State SO2 Budgets by Allocation Approach for 2010 and 2015 

 3

ST ABBR 

Final 

CAIR 

2010 

State SO2 

Budget 

Final CAIR 

2015 State 

SO2 Budget 

Method 3b 

2010 State 

Budget 

Method 3b 

2015 State 

Budget 

Method 4b 

2010 State 

Budget 

Method 4b 

2015 State 

Budget 

Method 5b 

2010 State 

Budget 

Method 5b 

2015 State 

Budget 

AL 157,582 110,307 154,288 108,001 175,798 123,058 188,339 131,837DC 708 495 513 359 189 133 212 148FL 253,450 177,415 279,084 195,359 203,650 142,555 244,120 170,884GA 213,057 149,140 146,955 102,868 169,928 118,950 192,536 134,775IA 64,095 44,866 70,019 49,013 85,715 60,001 43,853 30,697IL 192,671 134,869 168,592 118,015 195,590 136,913 158,976 111,283IN 254,599 178,219 235,113 164,579 284,195 198,936 287,174 201,022KY 188,773 132,141 178,489 124,942 217,936 152,555 262,395 183,676LA 59,948 41,963 120,325 84,228 57,551 40,286 36,197 25,338MD 70,697 49,488 63,847 44,693 68,691 48,084 83,869 58,708MI 178,605 125,024 153,030 107,121 160,502 112,351 134,708 94,295MN 49,987 34,991 68,420 47,894 81,572 57,100 40,045 28,031MO 137,214 96,050 130,563 91,394 155,103 108,572 81,931 57,351MS 33,763 23,634 50,870 35,609 36,089 25,263 37,669 26,369NC 137,342 96,139 134,643 94,250 161,807 113,264 199,711 139,798NY 135,139 94,597 146,004 102,203 77,937 54,556 96,342 67,439OH 333,520 233,464 233,407 163,385 284,404 199,082 348,166 243,716PA 275,990 193,193 217,369 152,158 255,227 178,659 302,565 211,795SC 57,271 40,089 71,616 50,131 84,298 59,008 104,757 73,330TN 137,216 96,051 109,435 76,604 133,420 93,394 157,948 110,563TX 320,946 224,662 555,455 388,818 339,975 237,982 199,493 139,645VA 63,478 44,435 82,995 58,097 89,665 62,765 110,935 77,654WI 87,264 61,085 89,598 62,719 105,025 73,518 64,197 44,938WV 215,881 151,117 158,567 110,997 194,929 136,450 243,059 170,141 3,619,196 2,533,434 3,619,196 2,533,434 3,619,196 2,533,434 3,619,197 2,533,433

Source: EPA, 2006
 1

Table C. 2010 State-by-State Coverage Ratios using Projected Emissions from Base Case, CAIR & Alternatives

 CAIR SO2 Heat Input (3b) Heat Input w/ Fuel Factors (4b) 

Heat Input w/ Fuel Factors & Coal 

Type (5b) 

State 

Coverage 

Ratio: 

Budget 

to 

Emission 

Difference 

(from 

0.42) 

Absloute 

Difference 

(from 

0.42) 

Coverage 

Ratio: 

Budget to 

Emission 

Difference 

(from 

0.41) 

Absloute 

Difference 

(from 

0.42) 

Coverage 

Ratio: 

Budget 

to 

Emission 

Difference 

(from 

0.41) 

Absloute 

Difference 

(from 

0.42) 

Coverage 

Ratio: 

Budget 

to 

Emission 

Difference 

(from 

0.41) 

Absloute 

Difference 

(from 

0.42) 

AL 0.33 -0.09 0.09 0.32 -0.10 0.10 0.37 -0.05 0.05 0.39 -0.03 0.03 FL 1.15 0.73 0.73 1.26 0.84 0.84 0.92 0.50 0.50 1.11 0.69 0.69 GA 0.36 -0.06 0.06 0.25 -0.17 0.17 0.29 -0.13 0.13 0.33 -0.09 0.09 IL 0.48 0.06 0.06 0.42 0.00 0.00 0.49 0.07 0.07 0.40 -0.02 0.02 IN 0.39 -0.03 0.03 0.36 -0.06 0.06 0.44 0.02 0.02 0.44 0.02 0.02 IA 0.36 -0.06 0.06 0.25 -0.17 0.17 0.29 -0.13 0.13 0.33 -0.09 0.09 KY 0.42 0.00 0.00 0.40 -0.02 0.02 0.49 0.07 0.07 0.59 0.17 0.17 LA 0.60 0.18 0.18 1.21 0.79 0.79 0.58 0.16 0.16 0.36 -0.06 0.06 MD 0.23 -0.19 0.19 0.21 -0.21 0.21 0.22 -0.20 0.20 0.27 -0.15 0.15 MI 0.46 0.04 0.04 0.40 -0.02 0.02 0.41 -0.01 0.01 0.35 -0.07 0.07 MN 0.60 0.18 0.18 0.82 0.40 0.40 0.98 0.56 0.56 0.48 0.06 0.06 MS 0.39 -0.03 0.03 0.59 0.17 0.17 0.42 0.00 0.00 0.44 0.02 0.02 MO 0.60 0.18 0.18 0.82 0.40 0.40 0.98 0.56 0.56 0.48 0.06 0.06 NY 1.03 0.61 0.61 1.12 0.70 0.70 0.60 0.18 0.18 0.74 0.32 0.32 NC 0.55 0.13 0.13 0.53 0.11 0.11 0.63 0.21 0.21 0.33 -0.09 0.09 OH 0.24 -0.18 0.18 0.17 -0.25 0.25 0.21 -0.21 0.21 0.25 -0.17 0.17 PA 0.30 -0.12 0.12 0.24 -0.18 0.18 0.28 -0.14 0.14 0.33 -0.09 0.09 SC 0.29 -0.13 0.13 0.37 -0.05 0.05 0.43 0.01 0.01 0.53 0.11 0.11 TN 0.39 -0.03 0.03 0.31 -0.11 0.11 0.38 -0.04 0.04 0.45 0.03 0.03 TX 0.77 0.35 0.35 1.33 0.91 0.91 0.81 0.39 0.39 0.48 0.06 0.06 VA 0.33 -0.09 0.09 0.44 0.02 0.02 0.47 0.05 0.05 0.58 0.16 0.16 WV 0.37 -0.05 0.05 0.27 -0.15 0.15 0.33 -0.09 0.09 0.42 0.00 0.00 WI 0.33 -0.09 0.09 0.44 0.02 0.02 0.47 0.05 0.05 0.58 0.16 0.16 Total 1.35 3.60 2.87 5.86 1.83 3.82 1.01 2.71 Average 0.48 0.06 0.16 0.54 0.12 0.25 0.50 0.08 0.17 0.46 0.04 0.12 Percent Positive 43% 43% 61% 52% Source: EPA, 2006 
 2

Table D. 2015 State-by-State Coverage Ratios using Projected Emissions from Base Case, CAIR & Alternatives  CAIR SO2 Heat Input (3b) Heat Input w/ Fuel Factors (4b) 

Heat Input w/ Fuel Factors & Coal 

Type (5b) 

State 

Coverage 

Ratio: 

Budget to 

Emission 

Difference 

(from 

0.32) 

Absloute 

Difference 

(from 

0.32) 

Coverage 

Ratio: 

Budget 

to 

Emission 

Difference 

(from 

0.32) 

Absloute 

Difference 

(from 

0.32) 

Coverage 

Ratio: 

Budget 

to 

Emission 

Difference 

(from 

0.32) 

Absloute 

Difference 

(from 

0.32) 

Coverage 

Ratio: 

Budget 

to 

Emission 

Difference 

(from 

0.32) 

Absloute 

Difference 

(from 

0.32) 

AL 0.27 -0.05 0.05 0.27 -0.05 0.05 0.30 -0.02 0.02 0.33 0.01 0.01 FL 0.80 0.48 0.48 0.89 0.57 0.57 0.65 0.33 0.33 0.77 0.45 0.45 GA 0.25 -0.07 0.07 0.17 -0.15 0.15 0.20 -0.12 0.12 0.23 -0.09 0.09 IL 0.30 -0.02 0.02 0.26 -0.06 0.06 0.31 -0.01 0.01 0.25 -0.07 0.07 IN 0.34 0.02 0.02 0.31 -0.01 0.01 0.37 0.05 0.05 0.38 0.06 0.06 IA 0.25 -0.07 0.07 0.17 -0.15 0.15 0.20 -0.12 0.12 0.23 -0.09 0.09 KY 0.32 0.00 0.00 0.30 -0.02 0.02 0.37 0.05 0.05 0.44 0.12 0.12 LA 0.42 0.10 0.10 0.85 0.53 0.53 0.41 0.09 0.09 0.26 -0.06 0.06 MD 0.16 -0.16 0.16 0.14 -0.18 0.18 0.15 -0.17 0.17 0.19 -0.13 0.13 MI 0.31 -0.01 0.01 0.27 -0.05 0.05 0.28 -0.04 0.04 0.24 -0.08 0.08 MN 0.43 0.11 0.11 0.58 0.26 0.26 0.70 0.38 0.38 0.34 0.02 0.02 MS 0.28 -0.04 0.04 0.42 0.10 0.10 0.30 -0.02 0.02 0.31 -0.01 0.01 MO 0.43 0.11 0.11 0.58 0.26 0.26 0.70 0.38 0.38 0.34 0.02 0.02 NY 0.72 0.40 0.40 0.77 0.45 0.45 0.41 0.09 0.09 0.51 0.19 0.19 NC 0.38 0.06 0.06 0.36 0.04 0.04 0.43 0.11 0.11 0.23 -0.09 0.09 OH 0.22 -0.10 0.10 0.15 -0.17 0.17 0.19 -0.13 0.13 0.23 -0.09 0.09 PA 0.23 -0.09 0.09 0.18 -0.14 0.14 0.21 -0.11 0.11 0.25 -0.07 0.07 SC 0.24 -0.08 0.08 0.29 -0.03 0.03 0.35 0.03 0.03 0.43 0.11 0.11 TN 0.30 -0.02 0.02 0.24 -0.08 0.08 0.30 -0.02 0.02 0.35 0.03 0.03 TX 0.54 0.22 0.22 0.93 0.61 0.61 0.57 0.25 0.25 0.33 0.01 0.01 VA 0.25 -0.07 0.07 0.32 0.00 0.00 0.35 0.03 0.03 0.43 0.11 0.11 WV 0.31 -0.01 0.01 0.22 -0.10 0.10 0.28 -0.04 0.04 0.34 0.02 0.02 WI 0.25 -0.07 0.07 0.32 0.00 0.00 0.35 0.03 0.03 0.43 0.11 0.11 Total 0.63 2.35 1.67 4.00 1.00 2.62 0.48 2.08 Average 0.35 0.05 0.20 0.39 0.14 0.33 0.36 0.08 0.22 0.34 0.04 0.17 Percent Positive 39% 43% 52% 57% 

Source: EPA, 2006 
 3
 4

EcoStat, Inc.

P. O. Box 425

Mebane, N. C. 27302

Ph/Fx: (919) 304-6029 billwh@mindspring.com

April 12, 2006 

To: Chitra Kumar 

From: William Warren-Hicks, Ph.D. 

Subject: Evaluation of Alternative SO2 Allocation Approaches under CAIR 

Introduction

This memorandum presents an analysis of alternative approaches for generating SO2 allocations 

and State budgets under EPA’s Clean Air Interstate Rule (CAIR). The analysis was conducted, in 

part, in response to petitions for reconsideration of the SO2 allocation approach based on Title 

IV which EPA relied upon for CAIR. The objective of the analyses presented in this report are to 

statistically evaluate the relationship among allocations and State budgets generated by EPA’s 

approach and alternative approaches. All data evaluated in this report were generated by EPA. 

A complete description of EPA’s procedures for projecting allocations and emissions in the years 

2010 and 2015 is found in the CAIR SO2 Allocation Approach Analysis Technical Support 

Document (TSD, EPA Docket number OAR-2003-0053) and a memorandum from Perrin 

Quarles Associates dated March 2006 which can be found in the Docket number OAR-2003-

0053. In the Notice of Final Action on Reconsideration SO2 TSD, EPA evaluated the ratio of 

SO2 allowances to total projected emissions before CAIR controls (called the base case) and 

with CAIR controls installed (called the control case). We provide further evaluation of each of 

these cases in this report. In addition to the EPA approach, the following three alternative 

approaches (which were also evaluated by EPA) are addressed in this report: 

 1. allowances based on heat input data (termed heat input approach), 

 2. allowances based on heat input data adjusted for fuel factor (e.g., coal, oil, 

and gas; termed the heat input & fuel factor approach), and 

 3. allowances based on heat input data adjusted both for fuel type and coal 

type (e.g., bituminous, sub-bituminous, and lignite; termed the heat input & fuel 

factor, coal type approach). 
5

Allocations and emissions in the years 2010 and 2015 were aggregated at the company ownerlevel and company parent-level. A complete explanation of these organizational units and 

approaches for aggregating emissions is available in the TSD. 

In addition to the parent-level and owner-level allowance allocations, EPA generated allowance 

budgets for States (see memorandum from Perrin Quarles Associates, March 2006). In this 

report, we evaluate the ratio (termed State coverage ratios) of the 2010 and 2015 CAIR State 

SO2 allowance budgets to projected State-level emissions for each of the four alternative 

approaches. EPA also generated region-wide SO2 budgets. The relationship of a State allowance 

budget to the region-wide allowance budget was computed for each of the four alternative 

approaches, as well as four additional approaches (see Notice of Final Action on Reconsideration 

in the docket). We examine the above State and region-wide data in the analyses presented in 

this report. 

Statistical Approach

The objective of the analyses presented in this report is to compare allocations and budgets 

generated based on EPA’s approach and alternative approaches proposed by commenters on the 

CAIR. We evaluate the relationship among the candidate approaches based on an analysis of 

distribution and an analysis of centrality. In the context of the CAIR, an approach is biased if it 

results in allocations or budgets that are consistently higher or lower than other possible 

approaches. Bias is generally assessed against a measure of centrality, like the sample mean. In 

this report, the concept of bias is addressed in the calculation of a percent difference. Generally, 

four allocations (or budgets) are available for each source (e.g., parent, owner, or State) in a data 

set (e.g., four allocation values, each from a different approach, associated with a specific parent 

company for the year 2015). The mean of these four approaches represents a measure of central 

tendency among the alternative approaches. Calculation of the approach-specific percent 

difference provides a measure of relative bias with respect to the other approaches. The average 

of all the percent differences (i.e., across all sources in the spreadsheet) provides an objective 

approach for judging the overall relationship among the four approaches. The perfect approach 

would have an average percent difference of zero, indicating that allocations generated by the 

approach were on average near the center of all allocations associated with the source 

population. An approach that consistently results in a positive percent difference could be 

considered to be biased high relative to the other approaches. An approach that consistently 

results in a negative percent difference could be considered to be biased low. The magnitude of 

the percent differences for any single source is not of particular interest, but the average of the 

percent differences across all sources effectively increases the sample size available for judging 

bias and provides an overall measure of the degree of bias associated with a single approach. The 

use of zero values in the calculations results in non-interpretable results, therefore, sources with 

zero allocations are not used to generate this statistic. By examining the average percent 

differences calculated across all sources in the spreadsheet, the effective sample size is increased 

and the results are interpretable. 
6

The other approach used in this study to evaluate allocation approaches extends the analysis 

beyond measures of centrality and examines the distribution of allocations across all sources. 

From a regulatory perspective, EPA is charged with reducing SO2 emissions that significantly 

contribute to non-attainment through the CAIR. Therefore, rather than examining individual 

sources subject to CAIR, a statistical method that evaluates the entire population of sources 

subject to the rule is preferable. Examination of distributions provides an approach for assessing 

allocations across the entire population affected by the program. For any given company or State, 

EPA’s approach may produce a different result than an alternative approach. However, from a 

regulatory perspective, the objective is to examine the entire population of sources subject to 

CAIR, and evaluate the relationship among the competing approaches. Two fundamental 

approaches are used for these evaluations. First, a cumulative distribution of allocations or State 

budgets provides a visual examination of the relative consistency among the results generated by 

the four competing approaches. Overlapping distributions indicate a general consistency among 

the approaches. Second, examination of the number of positive and negative percent differences 

provides a semi-qualitative approach for examining the relative bias associated with an approach. 

The perfect approach would be associated with 50% positive readings and 50% negative 

readings, indicating that the approach is not biased high, nor biased low. 

Results: Parent- and Owner/Operator-level Analyses

Figures 1 - 4 display cumulative distributions of the ratio of allocations to emissions at the 

parent-level and owner/operator-levels of aggregation in the years 2010 and 2015. Data in the 

four figures represent the CAIR control case. Examination of the figures provides the following 

findings: 

• At the owner-level, the distributions of EPA and the heat input & fuel factor 

approaches seem to be grouped separately from the other two approaches. The 

owner-level of aggregation displays a large variability among the four 

approaches, with each approach somewhat distinct from the others. The EPA 

approach results in approximately 28% of the owner/operators having zero 

allocations. Examination of the data indicates that the zero allocations are 

associated with gas-fired units (see additional comments in the conclusions 

section of this report). Regeneration of the distributions after eliminating those 

owner/operators in which any of the four approaches resulted in a zero allocation 

(Figures 5 and 6) indicates that the resulting distributions are very similar. 

• At the parent-level, the ratio of distributions are similar among the four 

approaches. The EPA approach is in general agreement with the other approaches 

at the smaller ratios (ratio < 0.7). As the cumulative percentage approaches a ratio 

of 1.0, EPA’s approach is shown to have a larger number of owner/operators in 

this range than the other approaches. The number of owner/operators with zero 

allocations is similar among the four approaches. 
7

Base case distributions of the ratios are displayed in Figures 7 - 10. Examination of the figures 

provides the following findings: 

• The patterns for the base case are similar to those for the CAIR control case. The 

four distributions at the owner-level are generally distinct. Again, EPA has a 

larger number of owner/operators with zero allocations. Figures 11 and 12 display 

the distributions after those owners/operators with a zero allocation for any 

approach are eliminated from the data. As in the CAIR control case, the 

elimination of sources in which any of the four approaches resulted in a zero 

allocation dramatically changes the distribution shape and indicates that the four 

approaches have similar distributions. 

• At the parent-level, the distributions among the four approaches are very close in 

the range of 0 <= ratio <= 0.7. As the distribution approaches 1.0, EPA’s 

approach incorporates a larger number of parents than the other approaches. This 

effect extends to a ratio of about 1.2. One way of visualizing this effect is to 

notice that the EPA curve is steeper in this range. Also, in this range, the EPA 

approach separates from the other approaches, indicating a larger percentage of 

parents associated with any given ratio in the range. 

Tables 1 - 4 present the calculations of percent difference in allocations for owner/operators and 

parents in the years 2010 - 2015. Results using the base case and CAIR control case are similar, 

therefore only the CAIR control case is presented. For each owner or parent, the allocation 

associated with each of the four approaches is shown. In addition, the percent difference from the 

mean allocation for each of the four approaches is displayed. At the bottom of the table, the 

average percent difference and the number of positive percent differences is indicated for each of 

the four approaches. Examination of the tables results in the following findings: 

• Table 1 indicates that the average percent difference for the EPA approach (8.8%) 

is slightly larger than the other approaches at the owner-level in 2010. However, 

in 2015 (Table 2) the EPA approach has an average percent difference near zero 

(1.07%). In both 2010 (Table 1) and 2015 (Table 2), the percent of positive values 

associated with the EPA approach is near 50% (44.8% and 45.1%, respectively). 

The heat input and heat input & fuel factor are shown to have average percent 

differences near zero in 2010 and 2015 (2.32% and -2.58%, respectively), 

however, the number of positive values in these years are distant from the ideal 

50% value (17.8% and 75.9%, respectively). The statistics for the four approaches 

in 2015 (Table 2) at the owner-level indicate that all of the approaches are very 

similar. 

• Table 3 and 4 indicate relatively good agreement among all four approaches at the 

parent-level of aggregation. The average percent difference associated with the 

EPA allocation approach is larger than the other approaches in both 2010 and 

2015 (11.1% and 12.5%, respectively). However, the percent of positive values is 
8

near the ideal 50% value in both years (51.8% and 52.8%). The heat input & fuel 

factor, coal type on average has allocations that are less than the other approaches 

in both 2010 and 2015 (-13.3% and -12.8%, respectively). The heat input and heat 

input & fuel factor approaches have average percent differences near zero in both 

2010 and 2015. 

 

Results: State Budget Analyses

Figures 13 and 14 present cumulative distributions of State coverage ratios for 2010 and 2015, 

respectively. Examination of the figures indicates that the EPA distribution overlaps and is 

similar to the distributions associated with the other approaches. Effectively, the distributions 

associated with the four approaches are indistinguishable. 

Figure 15 presents cumulative distributions for EPA and seven alternative approaches based on 

the percent of region-wide budgets associated with twenty-five CAIR States. Data used to 

generate Figure 15 are shown in Table 5. Again, the distributions are similar. 

Conclusions

The objective of this analysis was to compare allocations and State budgets generated using EPA 

approaches to alternative approaches. An evaluation of the ratio of allowance allocations to 

emissions at the parent- and owner-level of aggregation generally showed that the approaches 

perform similarly. At the owner-level, the EPA approach results in a distribution of ratios that is 

similar to the heat input with fuel factors distribution, but is dissimilar to the distributions 

associated with the other approaches. Examination of the data indicated that the distributions 

were sensitive to the number of sources with zero allocations (and therefore a ratio of zero 

allowances to emissions). Companies may have zero allocations because the units they operate 

commenced operations after 1990. This is true for both 2010 and 2015, and with base case and 

control case emissions. The vast majority of these companies are primarily gas-fired facilities, 

which have little or no emissions. For example, about 94% of the 64 companies with a ratio of 

zero allowances to emissions were gas-fired for the 2010 CAIR control case. This is true for at 

least 90% of companies for other years and cases, as well. Since these units have negligible SO2 

emissions, receiving no allowances will not significantly impact the operating companies (see 

docket EPA-HQ-OAR-2003-0053, ‘SO2 State Budget Analysis’, for related data). When the 

distributions are re-evaluated after eliminating owners/operators where any of the approaches 

resulted in a zero allocation, the EPA approach appears to be very similar to the other 

approaches. 

An analysis of the parent-level distributions indicates that the four approaches are very similar 

across all sources. 
9

Examination of percent differences based on allocations, including the percent of positive values, 

indicates that the four approaches perform similarly. 

The EPA approach is shown to have a higher percentage of owner/operators and parents with 

ratios in the range between 0.7 and 1.0. 

Examination of both State coverage ratios and the distribution of percent of region-wide budgets 

indicates that the four approaches have very similar distributions. 

For any single parent, owner, or State, the four approaches can provide very different allocations. 

However, when the populations of interest are evaluated, the approaches have similar 

characteristics. 
10

Method: EPA Heat Input

Heat Input & Fuel Factor Heat Input & Fuel Factor, Coal Type

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

Ratio: SO2 Allocation to CAIR Control Case Emissions

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

Method: EPA Heat Input

Heat Input & Fuel Factor Heat Input & Fuel Factor, Coal Type

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

Ratio: SO2 Allocation to CAIR Control Case Emissions

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

Figure 1. Ratio of SO2 Allowances to CAIR Control Case Emissions in 2010 for 234 

Company Owner/Operators under EPA’s CAIR Approach and Alternatives*

Figure 2. Ratio of SO2 Allowances to CAIR Control Case Emissions in 2015 for 230 

Company Owner/Operators under EPA’s CAIR Approach and Alternatives*
11

Method: EPA Heat Input

Heat Input & Fuel Factor Heat Input & Fuel Factor, Coal Type

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

Ratio: SO2 Allocation to CAIR Control Case Emissions

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

Method: EPA Heat Input

Heat Input & Fuel Factor Heat Input & Fuel Factor, Coal Type

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

Ratio: SO2 Allocation to CAIR Control Case Emissions

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

Figure 3. Ratio of SO2 Allowances to CAIR Control Case Emissions in 2010 for 111 

Parent Companies under EPA’s CAIR Approach and Alternatives*

Figure 4. Ratio of SO2 Allowances to CAIR Control Case Emissions in 2015 for 109 

Parent Companies under EPA’s CAIR Approach and Alternatives*
12

Method: EPA Heat Input

Heat Input & Fuel Factor Heat Input & Fuel Factor, Coal Type

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

Ratio: SO2 Allocation to CAIR Control Case Emissions

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

Method: EPA Heat Input

Heat Input & Fuel Factor Heat Input & Fuel Factor, Coal Type

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

Ratio: SO2 Allocation to CAIR Control Case Emissions

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

Figure 5. Ratio of SO2 Allowances to CAIR Control Case Emissions in 2010. Company 

Owner/Operators with Zero Allocations Removed From Data*

Figure 6. Ratio of SO2 Allowances to CAIR Control Case Emissions in 2015. Company 

Owner/Operators with Zero Allocations Removed From Data*
13

Method: EPA Heat Input

Heat Input & Fuel Factor Heat Input & Fuel Factor, Coal Type

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

Ratio: SO2 Allocation to Base Case Emissions

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

Method: EPA Heat Input

Heat Input & Fuel Factor Heat Input & Fuel Factor, Coal Type

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

Ratio: SO2 Allocation to Base Case Emissions

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

Figure 7. Ratio of SO2 Allowances to CAIR Base Case Emissions in 2010 for 234 

Company Owner/Operators under EPA’s CAIR Approach and Alternatives*

Figure 8. Ratio of SO2 Allowances to CAIR Base Case Emissions in 2015 for 236 

Company Owner/Operators under EPA’s CAIR Approach and Alternatives*
14

Method: EPA Heat Input

Heat Input & Fuel Factor Heat Input & Fuel Factor, Coal Type

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

Ratio: SO2 Allocation to Base Case Emissions

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

Method: EPA Heat Input

Heat Input & Fuel Factor Heat Input & Fuel Factor, Coal Type

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

Ratio: SO2 Allocation to Base Case Emissions

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

Figure 9. Ratio of SO2 Allowances to CAIR Base Case Emissions in 2010 for 113 Parent 

Companies under EPA’s CAIR Approach and Alternatives*

Figure 10. Ratio of SO2 Allowances to CAIR Base Case Emissions in 2015 for 111 Parent 

Companies under EPA’s CAIR Approach and Alternatives* 
15

Method: EPA Heat Input

Heat Input & Fuel Factor Heat Input & Fuel Factor, Coal Type

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

Ratio: SO2 Allocation to Base Case Emissions

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

Method: EPA Heat Input

Heat Input & Fuel Factor Heat Input & Fuel Factor, Coal Type

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

Ratio: SO2 Allocation to Base Case Emissions

0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0

Figure 11. Ratio of SO2 Allowances to Base Case Emissions in 2010. Company 

Owner/Operators with Zero Allocations Removed From Data* 

Figure 12. Ratio of SO2 Allowances to Base Case Emissions in 2015. Company 

Owner/Operators with Zero Allocations Removed From Data* 
16

Method: EPA Heat Input

Heat Input & Fuel Factor Heat Input & Fuel Factor, Coal Type

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

State Coverage Ratio

0.0 0.5 1.0 1.5 2.0 2.5

Method: EPA Heat Input

Heat Input & Fuel Factor Heat Input & Fuel Factor, Coal Type

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

State Coverage Ratio

0.0 0.5 1.0 1.5 2.0 2.5

*

 Note: Ratios greater than 4.0 are not shown on the graphic. Therefore, the cumulative distributions may not reach 

100% within the range of the displayed graphic. Greater than 85% of the companies with ratios greater than 4.0 are 

projected to emit less than 100 tons of SO2 under the both the CAIR Control Case and the Base Case. 

Figure 13. State Coverage Ratios in 2010 for 23 CAIR States under EPA’s CAIR Approach 

and Alternatives 
17

Figure 14. State Coverage Ratios in 2015 for 23 CAIR States under EPA’s CAIR Approach 

and Alternatives 
18

Method: EPA Heat Input

Heat Input & Fuel Factor Heat Input & Fuel Factor, Coal Type

Average Heat Input Coal + Oil Average Emissions

Average Output All Average Output Fossil

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

State Percentage of Regionwide Budget

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

Figure 15. Percent of Region-wide Budget for 24 CAIR States under EPA’s CAIR Approach 

and Alternatives 
19

Table 1. 2010 Owner-Level Company Allocations

Allocations to 2010 Company Owner/Operators Difference from Mean

Owner/Operator EPA Heat 

Input

Heat Input 

& Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

EPA Heat Input Heat 

Input & 

Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

AEP Texas Central Company 7,525 16,142 9,683 13,275 -35.44% 38.48% -16.93% 13.89%

AEP Texas North Company 362 4,386 498 1,885 -79.69% 146.04% -72.06% 5.72%

AES Beaver Valley 1,219 2,446 3,115 4,156 -55.41% -10.53% 13.94% 52.01%

AES Cayuga LLC 5,080 4,173 5,286 5,052 3.72% -14.80% 7.93% 3.15%

AES Greenidge 2,577 2,027 2,568 2,382 7.90% -15.13% 7.52% -0.28%

AES Somerset LLC 6,956 8,426 10,675 12,405 -27.66% -12.37% 11.02% 29.01%

AES Westover LLC 2,434 1,728 2,189 1,872 18.40% -15.94% 6.48% -8.94%

AES WR Ltd Partnership 899 2,008 2,478 3,374 -58.94% -8.30% 13.16% 54.08%

Alabama Electric Coop Inc 7,534 8,634 9,674 10,754 -17.65% -5.63% 5.74% 17.54%

Alabama Power Co 111,840 109,468 129,297 134,325 -7.75% -9.70% 6.65% 10.80%

Alcoa Generating Corp 5,264 10,476 12,970 17,276 -54.21% -8.88% 12.82% 50.27%

Allegheny Energy Supply Co LLC 100,447 76,148 94,092 83,874 13.32% -14.09% 6.15% -5.38%

Ameren Energy Generating Co 46,968 37,622 45,413 41,779 9.37% -12.40% 5.75% -2.72%

American Bituminous Power LP 717 1,448 1,783 2,382 -54.67% -8.50% 12.67% 50.50%

Ames City of 1,120 981 1,207 1,190 -0.39% -12.75% 7.34% 5.80%

Appalachian Power Co 88,571 66,508 81,578 71,893 14.82% -13.78% 5.76% -6.80%

Aquila, Inc. 4,730 7,200 8,437 10,496 -38.70% -6.68% 9.35% 36.03%

Associated Electric Coop Inc 28,196 30,442 36,295 39,743 -16.26% -9.58% 7.80% 18.04%

Austin City of (MN) 528 313 388 270 40.93% -16.46% 3.56% -28.02%

Austin Energy 258 5,244 7 1,585 -85.45% 195.67% -99.61% -10.61%

Birchwood Power Partners LP 776 2,393 2,874 4,112 -69.44% -5.74% 13.20% 61.98%

Black River Power LLC 198 845 1,070 1,576 -78.56% -8.38% 16.01% 70.93%

Brazos Electric Power Coop Inc 1,024 2,825 4 264 -0.52% 174.45% -99.61% -74.32%

Cambria CoGen Co 748 1,501 1,911 2,550 -55.42% -10.52% 13.93% 52.01%

Cardinal Operating Co 24,410 16,151 19,986 15,758 27.96% -15.33% 4.77% -17.39%

Carolina Power & Light Co 65,479 57,348 67,278 65,167 2.60% -10.14% 5.42% 2.11%

Cedar Falls City of 278 122 149 54 84.41% -19.07% -1.16% -64.18%

CenterPoint Energy Houston 

Electric, LLC

53,249 86,097 67,645 83,393 -26.65% 18.60% -6.82% 14.87%

Central Electric Power Coop 2,733 702 873 -424 181.46% -27.70% -10.09% -143.67%

Central Iowa Power Coop 2,792 515 582 -914 275.35% -30.76% -21.76% -222.83%

Central Power & Lime Inc 877 1,657 2,144 2,826 -53.24% -11.68% 14.28% 50.64%

Cincinnati Gas & Electric Co 47,307 51,692 62,995 69,686 -18.32% -10.75% 8.76% 20.31%

CLECO Power LLC 21,143 22,494 18,222 17,699 6.30% 13.10% -8.38% -11.01%

Cleveland Electric Illuminating Co 27,454 14,137 17,494 9,735 59.57% -17.83% 1.68% -43.42%

Cogentrix of Richmond Inc 983 3,241 3,894 5,617 -71.39% -5.61% 13.40% 63.59%

Cogentrix of Rocky Mount Inc 558 1,800 2,242 3,218 -71.47% -7.90% 14.72% 64.64%

Colmac Clarion Inc 264 537 684 915 -56.04% -10.50% 14.00% 52.54%

Columbia City of 2,334 173 209 -1,220 523.93% -53.75% -44.13% -426.04%

Columbus Southern Power Co 23,556 18,225 22,554 20,443 11.14% -14.01% 6.41% -3.55%

Constellation Power Source Gen 25,002 27,397 31,581 34,572 -15.64% -7.56% 6.56% 16.65%
20

Table 1. 2010 Owner-Level Company Allocations

Allocations to 2010 Company Owner/Operators Difference from Mean

Owner/Operator EPA Heat 

Input

Heat Input 

& Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

EPA Heat Input Heat 

Input & 

Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

Consumers Energy Co 47,623 39,280 45,748 42,342 8.86% -10.21% 4.57% -3.21%

Corn Belt Power Coop 190 97 120 66 60.79% -17.91% 1.55% -44.43%

Dairyland Power Coop 9,179 9,167 11,339 12,055 -12.04% -12.15% 8.66% 15.52%

Dayton Power & Light Co 48,054 35,034 43,085 37,089 17.73% -14.16% 5.56% -9.13%

Detroit Edison Co 105,695 79,349 94,568 82,077 16.89% -12.25% 4.58% -9.23%

Dominion Energy Services Co 14,313 10,796 13,534 12,102 12.82% -14.90% 6.68% -4.61%

Dominion Virginia Power 71,177 78,603 85,994 93,408 -13.51% -4.49% 4.49% 13.50%

Duke Energy Corp 71,382 73,583 90,974 98,238 -14.56% -11.92% 8.89% 17.59%

Dynegy Midwest Generation Inc 45,326 33,507 41,440 36,205 15.87% -14.35% 5.93% -7.45%

Dynegy Northeast Gen Inc 19,270 11,068 7,773 1,207 96.04% 12.60% -20.92% -87.72%

E S Joslin LP 105 1,017 1 270 -69.86% 191.96% -99.71% -22.39%

East Kentucky Power Coop Inc 19,695 17,220 20,776 20,311 1.00% -11.69% 6.54% 4.16%

Ebensburg Power Co 562 968 1,233 1,592 -48.36% -11.09% 13.25% 46.20%

Edison Mission 30,454 20,999 26,739 22,349 21.16% -16.46% 6.38% -11.09%

Electric Energy Inc 14,520 15,673 19,648 21,742 -18.86% -12.42% 9.79% 21.49%

Empire District Electric Company 4,897 4,405 2,858 2,014 38.19% 24.31% -19.35% -43.16%

Entergy Gulf States Inc 11,186 45,840 9,163 20,040 -48.11% 112.64% -57.49% -7.04%

Exelon Generation Co LLC 8,243 19,308 10,319 14,699 -37.28% 46.91% -21.48% 11.85%

Florida Power & Light Co 59,086 85,708 21,426 17,747 28.47% 86.36% -53.41% -61.41%

Florida Power Corp 58,664 48,503 38,998 29,056 33.92% 10.72% -10.97% -33.67%

Gainesville Regional Utilities 4,234 3,581 3,220 2,664 23.63% 4.56% -5.98% -22.21%

Garland City of 108 2,476 4 759 -87.09% 195.94% -99.52% -9.32%

Georgia Power Co 201,120 133,210 164,824 130,089 27.85% -15.32% 4.78% -17.30%

Gilberton Power Co 835 1,429 1,820 2,346 -48.04% -11.11% 13.21% 45.93%

Grand Haven City of 744 641 795 778 0.62% -13.31% 7.52% 5.17%

Gulf Power Co 22,014 17,581 19,155 16,724 16.67% -6.82% 1.52% -11.36%

Hamilton City of 581 518 641 640 -2.35% -12.94% 7.73% 7.56%

Henderson City Utility Comm 406 66 82 -139 291.64% -36.33% -20.90% -234.41%

Holland City of 824 482 444 203 68.74% -1.30% -9.08% -58.36%

Hoosier Energy R E C Inc 18,533 17,557 21,596 22,292 -7.31% -12.19% 8.01% 11.49%

Independence City of 2,339 294 365 -975 362.41% -41.88% -27.84% -292.69%

Indiana Michigan Power Co 45,648 41,151 50,948 51,216 -3.37% -12.89% 7.85% 8.41%

Indiana-Kentucky Electric Corp 25,288 14,609 18,087 12,127 44.27% -16.65% 3.19% -30.81%

Indianapolis Power & Light Co 35,996 33,089 40,621 41,194 -4.58% -12.29% 7.68% 9.19%

Indiantown Cogeneration LP 1,193 3,659 4,734 6,736 -70.76% -10.33% 16.01% 65.08%

Interstate Power and Light Co 22,966 24,559 29,925 32,776 -16.66% -10.88% 8.60% 18.94%

James River Cogeneration Co 753 1,321 1,586 2,053 -47.27% -7.51% 11.04% 43.74%

Jamestown City of 1,522 531 598 -40 133.20% -18.64% -8.38% -106.18%

JEA 21,444 27,980 28,386 32,879 -22.51% 1.11% 2.58% 18.81%

Kansas City Power & Light Co 34,564 20,670 24,464 16,466 43.77% -14.02% 1.76% -31.51%

Kentucky Power Co 12,512 12,045 14,924 15,572 -9.09% -12.48% 8.43% 13.14%
21

Table 1. 2010 Owner-Level Company Allocations

Allocations to 2010 Company Owner/Operators Difference from Mean

Owner/Operator EPA Heat 

Input

Heat Input 

& Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

EPA Heat Input Heat 

Input & 

Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

Kentucky Utilities Co 38,767 34,627 42,200 41,964 -1.58% -12.09% 7.13% 6.54%

KeySpan Generation LLC 26,514 22,819 6,627 -1,234 93.79% 66.79% -51.56% -109.02%

Lakeland City of 6,431 7,634 6,740 7,244 -8.29% 8.87% -3.88% 3.30%

Lansing City of 8,710 5,237 6,493 4,596 39.16% -16.33% 3.74% -26.57%

LG&E Power Services 894 2,830 3,526 5,049 -70.93% -7.96% 14.68% 64.21%

Lon C Hill, LP 172 2,715 4 796 -81.34% 194.58% -99.57% -13.67%

Louisiana Generating LLC 21,321 23,536 30,127 33,801 -21.60% -13.46% 10.78% 24.28%

Louisville Gas & Electric Co 31,190 30,880 37,710 39,780 -10.60% -11.49% 8.08% 14.02%

Lower Colorado River Authority 21,360 27,414 26,613 30,382 -19.22% 3.67% 0.65% 14.90%

Madison Gas & Electric Co 546 1,296 1,315 1,821 -56.13% 4.13% 5.66% 46.34%

Manitowoc Public Utilities 862 628 778 672 17.28% -14.56% 5.85% -8.57%

Marquette City of 251 659 817 1,142 -65.00% -8.11% 13.92% 59.19%

Michigan South Central Pwr Agy 907 765 948 914 2.65% -13.42% 7.29% 3.48%

MidAmerican Energy Co 32,911 40,437 49,452 57,474 -26.98% -10.28% 9.73% 27.53%

Midwest Generations EME LLC 57,288 58,103 66,137 69,358 -8.66% -7.36% 5.45% 10.58%

Minnesota Power Inc 11,580 16,846 20,234 24,874 -37.01% -8.36% 10.07% 35.31%

Mirant Chalk Point LLC 15,249 12,659 10,760 8,400 29.59% 7.58% -8.56% -28.61%

Mirant Mid-Atlantic LLC 26,285 17,912 21,716 17,402 26.20% -14.00% 4.26% -16.45%

Mirant New York Inc 9,148 8,191 6,190 4,885 28.78% 15.31% -12.86% -31.23%

Mirant Potomac River LLC 6,024 5,085 6,109 5,824 4.57% -11.73% 6.05% 1.11%

Mississippi Power Co 23,995 25,286 23,361 23,580 -0.25% 5.12% -2.89% -1.98%

Monongahela Power Co 8,207 6,816 8,396 7,995 4.50% -13.21% 6.91% 1.80%

Morgantown Energy Associates 636 1,041 1,283 1,634 -44.66% -9.35% 11.72% 42.29%

Muscatine City of 1,697 3,209 3,948 5,202 -51.71% -8.68% 12.35% 48.04%

Northampton Generating Co LP 604 1,438 1,831 2,518 -62.23% -10.00% 14.60% 57.62%

Northeastern Power Co 557 1,272 1,620 2,213 -60.65% -10.13% 14.45% 56.33%

Northern Indiana Pub Serv Co 25,352 33,752 41,011 49,031 -32.01% -9.48% 9.99% 31.50%

Northern States Power Co 35,221 48,441 58,587 70,782 -33.87% -9.04% 10.01% 32.91%

NRG Dunkirk Operations Inc 8,650 6,107 7,736 6,584 19.00% -15.99% 6.42% -9.43%

NRG Huntley Operations Inc 10,847 6,492 8,225 5,899 37.90% -17.47% 4.57% -25.00%

Nueces Bay WLE, LP 273 3,683 5 1,052 -78.22% 193.86% -99.60% -16.04%

Ohio Edison Co 48,259 29,758 35,929 25,652 38.28% -14.73% 2.95% -26.50%

Ohio Power Co 86,379 63,892 78,941 68,966 15.88% -14.29% 5.90% -7.48%

Ohio Valley Electric Corp 19,610 12,411 15,358 11,541 33.13% -15.74% 4.26% -21.65%

Orion Power Holdings Inc 19,804 15,576 18,688 16,907 11.61% -12.22% 5.32% -4.72%

Orion Power Holdings-Newcastle 5,645 3,343 4,257 3,027 38.77% -17.82% 4.65% -25.59%

Orion Power Midwest LP 8,460 5,898 7,510 6,339 19.97% -16.36% 6.50% -10.10%

Orlando Utilities Comm 5,977 10,573 13,362 17,356 -49.42% -10.53% 13.08% 46.87%

Otter Tail Power Company 15,285 1,734 2,147 -6,749 392.40% -44.14% -30.83% -317.43%

Owensboro City of 4,517 5,774 7,153 8,451 -30.23% -10.81% 10.49% 30.54%

Panther Creek Partners 817 1,427 1,817 2,354 -49.05% -11.02% 13.30% 46.77%
22

Table 1. 2010 Owner-Level Company Allocations

Allocations to 2010 Company Owner/Operators Difference from Mean

Owner/Operator EPA Heat 

Input

Heat Input 

& Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

EPA Heat Input Heat 

Input & 

Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

Pella City of 882 272 333 -53 146.08% -24.11% -7.09% -114.88%

Pennsylvania Power Co 20,666 24,844 31,634 36,683 -27.38% -12.70% 11.17% 28.91%

Power Authority of State of NY 3,225 7,613 1,906 2,929 -17.69% 94.30% -51.36% -25.25%

PPL Brunner Island LLC 24,340 13,102 16,683 10,385 50.92% -18.76% 3.44% -35.61%

PPL Martins Creek LLC 18,179 5,374 4,009 -4,983 222.05% -4.80% -28.98% -188.27%

PPL Montour LLC 24,370 14,666 18,674 13,541 36.81% -17.67% 4.84% -23.98%

PSI Energy Inc 71,955 64,059 76,914 75,935 -0.36% -11.29% 6.51% 5.15%

Public Service Co of Oklahoma 22,012 8,068 10,923 2,579 102.03% -25.95% 0.25% -76.33%

R J Reynolds Tobacco Co 2,901 1,411 1,758 880 66.98% -18.80% 1.17% -49.35%

Reliant Energy Mid-Atlantic PH 79,188 53,327 67,686 55,232 24.01% -16.49% 5.99% -13.51%

Richmond City of 4,474 1,318 1,632 -367 153.60% -25.29% -7.49% -120.82%

Rochester Gas & Electric Corp 4,433 2,930 3,712 2,971 26.25% -16.56% 5.71% -15.40%

Rochester Public Utilities 1,569 404 483 -267 186.75% -26.17% -11.73% -148.86%

San Antonio Public Service Bd 21,754 29,172 24,038 27,272 -14.89% 14.14% -5.95% 6.70%

San Miguel Electric Coop Inc 8,326 5,863 7,937 6,986 14.40% -19.44% 9.05% -4.01%

Savannah Electric & Power Co 5,986 4,994 5,095 4,467 16.56% -2.76% -0.79% -13.01%

Schuylkill Energy Resource Inc 1,797 1,683 2,142 2,219 -8.32% -14.14% 9.27% 13.19%

Scrubgrass Generating Co LP 822 1,477 1,881 2,453 -50.45% -10.92% 13.45% 47.92%

Seminole Electric Coop Inc 18,420 18,090 21,437 22,333 -8.22% -9.87% 6.81% 11.27%

Sempra Energy Resources 2,817 4,032 5,458 6,743 -40.85% -15.34% 14.60% 41.59%

Sikeston City of 3,401 3,444 4,282 4,590 -13.44% -12.35% 8.98% 16.82%

South Carolina Electric&Gas Co 22,813 22,460 26,640 27,798 -8.48% -9.90% 6.87% 11.51%

South Carolina Genertg Co Inc 7,924 7,624 9,654 10,131 -10.29% -13.69% 9.29% 14.69%

South Carolina Pub Serv Auth 21,577 34,920 41,801 52,990 -42.95% -7.67% 10.52% 40.10%

South Mississippi El Pwr Assn 5,106 5,059 5,080 5,056 0.61% -0.32% 0.10% -0.38%

Southern Illinois Power Coop 4,160 3,082 3,864 3,406 14.66% -15.05% 6.50% -6.12%

Southern Indiana Gas & Elec Co 10,234 11,446 13,857 15,469 -19.74% -10.24% 8.67% 21.31%

Southwestern Electric Power Co 37,276 34,927 38,055 37,532 0.89% -5.47% 3.00% 1.58%

Southwestern Public Service Co 26,681 35,807 38,335 45,262 -26.94% -1.96% 4.97% 23.93%

Springfield City of 8,965 10,052 12,324 13,806 -20.57% -10.94% 9.19% 22.32%

State Line Energy LLC 4,742 5,295 6,556 7,345 -20.76% -11.52% 9.55% 22.73%

Sunbury Generation LLC 8,291 4,054 5,162 2,707 64.07% -19.78% 2.15% -46.44%

Tallahassee City of 3,030 3,742 5 -766 101.63% 149.01% -99.67% -150.97%

Tampa Electric Co 41,972 30,401 37,936 32,734 17.37% -14.99% 6.08% -8.46%

Tennessee Valley Authority 208,137 185,217 226,027 224,350 -1.33% -12.19% 7.16% 6.36%

TES Filer City Station LP 253 961 1,191 1,740 -75.58% -7.25% 14.94% 67.89%

Texas Municipal Power Agency 6,952 5,218 7,064 6,523 7.96% -18.97% 9.70% 1.30%

TIFD VIII-W Inc 2,500 4,889 1,632 2,139 -10.39% 75.23% -41.51% -23.34%

Toledo Edison Co 12,059 6,529 7,697 4,400 57.20% -14.89% 0.34% -42.65%

Trigen-Syracuse Energy Corp 435 1,063 1,347 1,860 -62.98% -9.64% 14.50% 58.12%

TXU Generation Co LP 123,836 124,513 102,722 95,910 10.82% 11.43% -8.07% -14.17%
23

Table 1. 2010 Owner-Level Company Allocations

Allocations to 2010 Company Owner/Operators Difference from Mean

Owner/Operator EPA Heat 

Input

Heat Input 

& Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

EPA Heat Input Heat 

Input & 

Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

UAE Mecklenburg Cogeneration 

LP

467 1,503 1,806 2,598 -70.71% -5.67% 13.34% 63.04%

UGI Development Co 1,130 655 764 484 49.04% -13.61% 0.77% -36.21%

Union Electric Co 61,989 56,996 70,452 71,609 -5.01% -12.67% 7.95% 9.73%

US Operating Services Co.- 

Cedar Bay

1,271 3,762 4,867 6,896 -69.73% -10.41% 15.91% 64.23%

Vandolah Power Co LLC 0 45 0 15 

Victoria WLE, LP 168 1,680 2 451 -70.79% 192.09% -99.65% -21.65%

Western Kentucky Energy Corp 26,290 24,066 29,817 30,251 -4.77% -12.82% 8.01% 9.58%

Wheelabrator Environmental 

Systems

637 805 1,025 1,210 -30.68% -12.44% 11.49% 31.63%

Whiting Clean Energy Inc 0 778 1 261 

Wisconsin Electric Power Co 42,903 42,759 52,168 55,208 -11.10% -11.40% 8.10% 14.40%

Wisconsin Power & Light Co 28,260 26,701 32,051 32,795 -5.65% -10.85% 7.01% 9.49%

Wisconsin Public Service Corp 10,005 12,851 15,106 17,755 -28.17% -7.74% 8.45% 27.47%

Wyandotte Municipal Serv Comm 547 702 812 952 -27.38% -6.80% 7.80% 26.39%

 

Average 8.82% 2.32% -2.58% -8.55%

Percent Positive 44.83% 17.82% 75.86% 54.02%
24

Table 2. 2015 Owner-Level Company Allocations

Allocations to 2015 Company Owner/Operators Difference from Mean 

Owner/Operator EPA Heat 

Input

Heat 

Input & 

Fuel 

Factor

Heat 

Input & 

Fuel 

Factor, 

Coal 

Type

EPA Heat 

Input

Heat 

Input & 

Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

AEP Texas Central Company 5,267 11,299 6,776 7,132 -30.87% 48.31% -11.06% -6.39%

AEP Texas North Company 253 3,071 348 478 -75.61% 196.00% -66.46% -53.93%

AES Beaver Valley 853 1,712 2,180 2,727 -54.32% -8.36% 16.70% 45.98%

AES Cayuga LLC 3,556 2,921 3,700 4,826 -5.19% -22.12% -1.35% 28.67%

AES Greenidge 1,804 1,419 1,798 2,345 -2.04% -22.94% -2.36% 27.34%

AES Somerset LLC 4,870 5,898 7,473 9,746 -30.40% -15.70% 6.81% 39.29%

AES Westover LLC 1,704 1,209 1,532 1,998 5.79% -24.94% -4.89% 24.04%

AES WR Ltd Partnership 629 1,405 1,735 2,129 -57.32% -4.72% 17.66% 44.38%

Alabama Electric Coop Inc 5,274 6,044 6,772 7,561 -17.76% -5.75% 5.60% 17.91%

Alabama Power Co 78,288 76,628 90,508 88,644 -6.26% -8.25% 8.37% 6.14%

Alcoa Generating Corp 3,684 7,333 9,079 4,455 -39.98% 19.47% 47.92% -27.42%

Allegheny Energy Supply Co LLC 70,314 53,304 65,864 82,196 3.53% -21.52% -3.03% 21.02%

Ameren Energy Generating Co 32,878 26,335 31,787 31,931 6.98% -14.31% 3.43% 3.90%

American Bituminous Power LP 502 1,013 1,248 1,556 -53.49% -6.19% 15.58% 44.10%

Ames City of 784 687 845 405 15.25% 0.99% 24.22% -40.46%

Appalachian Power Co 62,000 46,555 57,105 71,272 4.67% -21.40% -3.59% 20.32%

Aquila, Inc. 3,310 5,041 5,906 2,852 -22.61% 17.86% 38.08% -33.32%

Associated Electric Coop Inc 19,737 21,309 25,407 12,262 0.30% 8.28% 29.11% -37.69%

Austin City of (MN) 369 219 271 339 23.21% -26.88% -9.52% 13.19%

Austin Energy 180 3,671 5 63 -81.63% 274.69% -99.49% -93.57%

Birchwood Power Partners LP 543 1,675 2,012 2,524 -67.84% -0.80% 19.16% 49.48%

Black River Power LLC 138 591 749 489 -71.86% 20.16% 52.28% -0.58%

Brazos Electric Power Coop Inc 717 1,978 3 33 5.02% 189.71% -99.56% -95.17%

Cambria CoGen Co 523 1,051 1,338 1,673 -54.34% -8.32% 16.72% 45.94%

Cardinal Operating Co 17,086 11,305 13,990 17,432 14.26% -24.40% -6.44% 16.58%

Carolina Power & Light Co 45,835 40,143 47,094 58,315 -4.20% -16.10% -1.57% 21.88%

Cedar Falls City of 194 85 104 129 51.56% -33.59% -18.75% 0.78%

CenterPoint Energy Houston 

Electric, LLC

37,272 60,270 47,349 26,278 -12.90% 40.84% 10.65% -38.59%

Central Electric Power Coop 1,913 491 611 736 104.00% -47.64% -34.84% -21.51%

Central Iowa Power Coop 1,955 361 407 506 142.18% -55.28% -49.58% -37.32%

Central Power & Lime Inc 614 1,160 1,501 1,923 -52.74% -10.74% 15.50% 47.98%

Cincinnati Gas & Electric Co 33,115 36,184 44,096 54,956 -21.32% -14.03% 4.77% 30.57%

CLECO Power LLC 14,799 15,746 12,756 7,830 15.77% 23.18% -0.21% -38.75%

Cleveland Electric Illuminating Co 19,218 9,896 12,246 14,989 36.42% -29.75% -13.07% 6.40%

Cogentrix of Richmond Inc 688 2,269 2,726 3,419 -69.77% -0.28% 19.80% 50.26%

Cogentrix of Rocky Mount Inc 390 1,260 1,570 1,942 -69.76% -2.37% 21.65% 50.47%

Colmac Clarion Inc 185 376 479 599 -54.93% -8.21% 16.93% 46.22%

Columbia City of 1,634 121 146 71 231.44% -75.46% -70.39% -85.60%

Columbus Southern Power Co 16,489 12,757 15,788 19,671 1.93% -21.14% -2.40% 21.60%

Constellation Power Source Gen 17,500 19,176 22,107 27,060 -18.46% -10.65% 3.01% 26.09%

Consumers Energy Co 33,336 27,495 32,024 31,701 7.06% -11.70% 2.84% 1.80%

Corn Belt Power Coop 133 68 84 104 36.76% -30.08% -13.62% 6.94%

Dairyland Power Coop 6,425 6,417 7,937 5,915 -3.72% -3.84% 18.93% -11.37%

Dayton Power & Light Co 33,637 24,523 30,159 37,580 6.87% -22.09% -4.18% 19.40%

Detroit Edison Co 73,987 55,547 66,196 50,841 20.03% -9.89% 7.39% -17.52%

Dominion Energy Services Co 10,019 7,557 9,474 6,604 19.08% -10.18% 12.60% -21.51%

Dominion Virginia Power 49,823 55,024 60,198 75,160 -17.03% -8.37% 0.24% 25.16%

Duke Energy Corp 49,967 51,509 63,682 78,818 -18.08% -15.55% 4.41% 29.22%
25

Table 2. 2015 Owner-Level Company Allocations

Allocations to 2015 Company Owner/Operators Difference from Mean 

Owner/Operator EPA Heat 

Input

Heat 

Input & 

Fuel 

Factor

Heat 

Input & 

Fuel 

Factor, 

Coal 

Type

EPA Heat 

Input

Heat 

Input & 

Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

Dynegy Midwest Generation Inc 31,729 23,456 29,007 35,521 6.02% -21.63% -3.08% 18.69%

Dynegy Northeast Gen Inc 13,489 7,747 5,441 6,864 60.87% -7.61% -35.11% -18.14%

E S Joslin LP 74 712 1 12 -62.95% 256.45% -99.50% -93.99%

East Kentucky Power Coop Inc 13,787 12,054 14,542 18,137 -5.76% -17.61% -0.60% 23.97%

Ebensburg Power Co 394 678 863 1,080 -47.77% -10.04% 14.51% 43.30%

Edison Mission 21,317 14,700 18,717 23,413 9.11% -24.76% -4.20% 19.84%

Electric Energy Inc 10,164 10,971 13,753 6,617 -2.05% 5.73% 32.54% -36.23%

Empire District Electric Company 3,427 3,084 2,001 1,199 41.16% 27.03% -17.58% -50.61%

Entergy Gulf States Inc 7,830 32,088 6,414 4,345 -38.20% 153.27% -49.37% -65.70%

Exelon Generation Co LLC 5,771 13,515 7,224 9,036 -35.06% 52.08% -18.71% 1.68%

Florida Power & Light Co 41,360 59,995 14,999 17,527 23.57% 79.25% -55.19% -47.63%

Florida Power Corp 41,064 33,951 27,297 34,478 20.08% -0.72% -20.18% 0.82%

Gainesville Regional Utilities 2,963 2,507 2,253 2,897 11.60% -5.57% -15.14% 9.11%

Georgia Power Co 140,781 93,246 115,376 130,230 17.41% -22.24% -3.78% 8.61%

Gilberton Power Co 585 1,000 1,274 613 -32.62% 15.21% 46.78% -29.37%

Grand Haven City of 520 449 556 700 -6.52% -19.28% -0.04% 25.84%

Gulf Power Co 15,411 12,307 13,409 17,205 5.68% -15.61% -8.05% 17.98%

Hamilton City of 407 363 449 559 -8.44% -18.34% 1.01% 25.76%

Henderson City Utility Comm 284 46 57 71 148.03% -59.83% -50.22% -37.99%

Holland City of 577 338 311 392 42.65% -16.44% -23.11% -3.09%

Hoosier Energy R E C Inc 12,973 12,291 15,117 18,851 -12.39% -17.00% 2.09% 27.30%

Independence City of 1,637 206 256 320 170.69% -65.94% -57.67% -47.09%

Indiana Michigan Power Co 31,953 28,806 35,664 23,838 6.28% -4.19% 18.62% -20.71%

Indiana-Kentucky Electric Corp 17,702 10,226 12,661 9,613 41.05% -18.52% 0.88% -23.41%

Indianapolis Power & Light Co 25,196 23,163 28,435 35,223 -10.03% -17.29% 1.54% 25.78%

Indiantown Cogeneration LP 835 2,561 3,314 4,246 -69.50% -6.50% 20.99% 55.01%

Interstate Power and Light Co 16,073 17,191 20,948 11,530 -2.21% 4.60% 27.46% -29.85%

James River Cogeneration Co 527 924 1,111 536 -31.94% 19.30% 43.44% -30.80%

Jamestown City of 1,065 372 419 211 106.10% -28.01% -18.92% -59.17%

JEA 15,010 19,585 19,870 20,345 -19.74% 4.72% 6.24% 8.78%

Kansas City Power & Light Co 24,195 14,469 17,125 8,306 50.99% -9.70% 6.87% -48.16%

Kentucky Power Co 8,759 8,432 10,447 13,027 -13.84% -17.06% 2.76% 28.14%

Kentucky Utilities Co 27,136 24,239 29,539 35,950 -7.12% -17.04% 1.11% 23.05%

KeySpan Generation LLC 18,561 15,973 4,638 5,478 66.28% 43.10% -58.45% -50.92%

Lakeland City of 4,501 5,344 4,717 5,793 -11.55% 5.02% -7.31% 13.84%

Lansing City of 6,097 3,667 4,545 3,986 33.30% -19.83% -0.63% -12.85%

LG&E Power Services 626 1,981 2,469 3,055 -69.22% -2.54% 21.47% 50.30%

Lon C Hill, LP 120 1,900 3 32 -76.64% 269.83% -99.42% -93.77%

Louisiana Generating LLC 14,925 16,475 21,089 12,777 -8.53% 0.97% 29.25% -21.69%

Louisville Gas & Electric Co 21,833 21,617 26,396 32,919 -15.02% -15.86% 2.74% 28.13%

Lower Colorado River Authority 14,951 19,190 18,630 10,266 -5.13% 21.77% 18.22% -34.86%

Madison Gas & Electric Co 382 906 920 1,023 -52.71% 12.16% 13.90% 26.65%

Manitowoc Public Utilities 603 440 545 262 30.38% -4.86% 17.84% -43.35%

Marquette City of 176 461 572 277 -52.62% 24.09% 53.97% -25.44%

Michigan South Central Pwr Agy 635 535 664 803 -3.68% -18.85% 0.72% 21.81%

MidAmerican Energy Co 23,037 28,307 34,617 16,590 -10.14% 10.41% 35.02% -35.29%

Midwest Generations EME LLC 40,103 40,671 46,295 22,323 7.38% 8.90% 23.96% -40.23%

Minnesota Power Inc 8,106 11,793 14,164 6,841 -20.73% 15.32% 38.51% -33.10%

Mirant Chalk Point LLC 10,674 8,861 7,532 9,093 18.08% -1.98% -16.68% 0.59%

Mirant Mid-Atlantic LLC 18,400 12,538 15,201 18,657 13.59% -22.60% -6.16% 15.17%
26

Table 2. 2015 Owner-Level Company Allocations

Allocations to 2015 Company Owner/Operators Difference from Mean 

Owner/Operator EPA Heat 

Input

Heat 

Input & 

Fuel 

Factor

Heat 

Input & 

Fuel 

Factor, 

Coal 

Type

EPA Heat 

Input

Heat 

Input & 

Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

Mirant New York Inc 6,403 5,733 4,333 5,486 16.66% 4.45% -21.06% -0.05%

Mirant Potomac River LLC 4,217 3,560 4,276 5,363 -3.15% -18.24% -1.79% 23.17%

Mississippi Power Co 16,796 17,700 16,353 17,253 -1.35% 3.96% -3.95% 1.34%

Monongahela Power Co 5,745 4,771 5,877 7,328 -3.12% -19.55% -0.90% 23.57%

Morgantown Energy Associates 445 729 898 1,120 -44.25% -8.64% 12.54% 40.36%

Muscatine City of 1,188 2,247 2,764 1,324 -36.83% 19.47% 46.96% -29.60%

Northampton Generating Co LP 422 1,007 1,282 617 -49.23% 21.02% 54.06% -25.85%

Northeastern Power Co 390 891 1,134 546 -47.33% 20.37% 53.20% -26.24%

Northern Indiana Pub Serv Co 17,746 23,627 28,708 26,146 -26.23% -1.79% 19.33% 8.68%

Northern States Power Co 24,655 33,907 41,010 19,999 -17.52% 13.43% 37.19% -33.10%

NRG Dunkirk Operations Inc 6,055 4,275 5,415 7,063 6.19% -25.03% -5.03% 23.87%

NRG Huntley Operations Inc 7,593 4,544 5,757 7,509 19.56% -28.45% -9.35% 18.24%

Nueces Bay WLE, LP 191 2,578 4 44 -72.88% 266.06% -99.43% -93.75%

Ohio Edison Co 33,780 20,831 25,149 31,202 21.77% -24.91% -9.34% 12.48%

Ohio Power Co 60,464 44,724 55,259 68,869 5.47% -21.99% -3.61% 20.13%

Ohio Valley Electric Corp 13,727 8,688 10,751 13,395 17.93% -25.36% -7.64% 15.07%

Orion Power Holdings Inc 13,864 10,903 13,081 16,329 2.36% -19.50% -3.42% 20.56%

Orion Power Holdings-Newcastle 3,952 2,340 2,980 3,727 21.61% -27.99% -8.30% 14.69%

Orion Power Midwest LP 5,922 4,129 5,257 6,576 8.24% -24.53% -3.91% 20.20%

Orlando Utilities Comm 4,184 7,401 9,353 11,986 -49.17% -10.08% 13.63% 45.62%

Otter Tail Power Company 10,701 1,214 1,503 722 202.72% -65.66% -57.48% -79.58%

Owensboro City of 3,162 4,041 5,007 6,158 -31.14% -12.00% 9.04% 34.10%

Panther Creek Partners 572 999 1,272 612 -33.79% 15.66% 47.27% -29.14%

Pella City of 617 190 233 112 114.24% -34.03% -19.10% -61.11%

Pennsylvania Power Co 14,466 17,391 22,144 25,568 -27.28% -12.57% 11.32% 28.53%

Power Authority of State of NY 2,258 5,329 1,334 1,587 -14.05% 102.85% -49.22% -39.59%

PPL Brunner Island LLC 17,038 9,171 11,678 14,607 29.83% -30.12% -11.01% 11.30%

PPL Martins Creek LLC 12,725 3,762 2,806 3,401 124.29% -33.69% -50.54% -40.05%

PPL Montour LLC 17,059 10,266 13,072 16,351 20.24% -27.64% -7.86% 15.25%

PSI Energy Inc 50,368 44,839 53,840 67,151 -6.81% -17.04% -0.39% 24.24%

Public Service Co of Oklahoma 15,408 5,648 7,646 4,177 87.45% -31.29% -6.98% -49.18%

R J Reynolds Tobacco Co 2,031 988 1,231 1,523 40.73% -31.54% -14.71% 5.53%

Reliant Energy Mid-Atlantic PH 55,432 37,329 47,381 58,990 11.35% -25.02% -4.82% 18.49%

Richmond City of 3,131 923 1,142 1,424 89.18% -44.23% -31.00% -13.96%

Rochester Gas & Electric Corp 3,104 2,051 2,598 3,389 11.43% -26.37% -6.73% 21.67%

Rochester Public Utilities 1,098 283 338 422 105.14% -47.13% -36.85% -21.16%

San Antonio Public Service Bd 15,228 20,420 16,826 9,322 -1.43% 32.18% 8.91% -39.66%

San Miguel Electric Coop Inc 5,828 4,104 5,556 3,035 25.85% -11.38% 19.98% -34.46%

Savannah Electric & Power Co 4,191 3,496 3,566 4,457 6.71% -10.99% -9.20% 13.48%

Schuylkill Energy Resource Inc 1,258 1,178 1,500 722 8.03% 1.16% 28.81% -38.00%

Scrubgrass Generating Co LP 575 1,034 1,317 1,647 -49.69% -9.56% 15.19% 44.06%

Seminole Electric Coop Inc 12,894 12,663 15,005 18,500 -12.67% -14.24% 1.62% 25.29%

Sempra Energy Resources 1,972 2,822 3,821 2,087 -26.29% 5.48% 42.81% -22.00%

Sikeston City of 2,381 2,411 2,997 1,445 3.14% 4.44% 29.82% -37.41%

South Carolina Electric&Gas Co 15,969 15,722 18,649 23,395 -13.37% -14.71% 1.17% 26.91%

South Carolina Genertg Co Inc 5,547 5,337 6,758 8,474 -15.04% -18.26% 3.51% 29.79%

South Carolina Pub Serv Auth 15,105 24,445 29,262 36,696 -42.73% -7.32% 10.94% 39.12%

South Mississippi El Pwr Assn 3,574 3,541 3,556 4,848 -7.88% -8.73% -8.34% 24.96%

Southern Illinois Power Coop 2,912 2,158 2,705 3,384 4.38% -22.65% -3.04% 21.30%

Southern Indiana Gas & Elec Co 7,164 8,012 9,700 12,097 -22.49% -13.32% 4.94% 30.87%
27

Table 2. 2015 Owner-Level Company Allocations

Allocations to 2015 Company Owner/Operators Difference from Mean 

Owner/Operator EPA Heat 

Input

Heat 

Input & 

Fuel 

Factor

Heat 

Input & 

Fuel 

Factor, 

Coal 

Type

EPA Heat 

Input

Heat 

Input & 

Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

Southwestern Electric Power Co 26,094 24,447 26,638 14,632 13.69% 6.51% 16.06% -36.25%

Southwestern Public Service Co 18,677 25,066 26,834 14,744 -12.44% 17.51% 25.80% -30.88%

Springfield City of 6,274 7,036 8,626 7,434 -14.55% -4.17% 17.48% 1.25%

State Line Energy LLC 3,320 3,707 4,589 2,201 -3.89% 7.32% 32.85% -36.28%

Sunbury Generation LLC 5,804 2,838 3,613 3,276 49.48% -26.91% -6.95% -15.63%

Tallahassee City of 2,121 2,619 4 39 77.38% 119.03% -99.67% -96.74%

Tampa Electric Co 29,380 21,281 26,556 30,462 9.14% -20.95% -1.35% 13.16%

Tennessee Valley Authority 145,695 129,649 158,219 193,448 -7.05% -17.29% 0.94% 23.41%

TES Filer City Station LP 177 672 834 1,049 -74.07% -1.61% 22.10% 53.58%

Texas Municipal Power Agency 4,866 3,653 4,945 2,701 20.41% -9.61% 22.36% -33.16%

TIFD VIII-W Inc 1,750 3,422 1,143 1,429 -9.60% 76.75% -40.96% -26.19%

Toledo Edison Co 8,441 4,570 5,388 2,757 59.60% -13.59% 1.87% -47.87%

Trigen-Syracuse Energy Corp 305 744 943 473 -50.53% 20.74% 53.03% -23.24%

TXU Generation Co LP 86,685 87,160 71,906 39,836 21.41% 22.08% 0.71% -44.20%

UAE Mecklenburg Cogeneration LP 327 1,052 1,264 1,586 -69.10% -0.49% 19.56% 50.02%

UGI Development Co 791 459 535 361 47.44% -14.45% -0.28% -32.71%

Union Electric Co 43,393 39,896 49,319 27,499 8.41% -0.33% 23.22% -31.30%

US Operating Services Co.- Cedar 

Bay

890 2,633 3,407 4,365 -68.49% -6.75% 20.66% 54.59%

Victoria WLE, LP 118 1,176 2 20 -64.13% 257.45% -99.39% -93.92%

Western Kentucky Energy Corp 18,401 16,846 20,871 21,814 -5.55% -13.53% 7.12% 11.96%

Wheelabrator Environmental 

Systems

446 564 718 345 -13.93% 8.82% 38.54% -33.43%

Wisconsin Electric Power Co 30,030 29,933 36,518 25,188 -1.27% -1.59% 20.06% -17.19%

Wisconsin Power & Light Co 19,782 18,691 22,435 10,782 10.38% 4.29% 25.18% -39.84%

Wisconsin Public Service Corp 7,003 8,996 10,574 5,085 -11.52% 13.66% 33.60% -35.75%

Wyandotte Municipal Serv Comm 383 492 569 276 -10.93% 14.42% 32.33% -35.81%

 

Average 1.07% 4.57% -0.70% -4.94%

Percent Positive 45.09% 32.37% 53.76% 53.76%
28

Table 3. 2010 Parent Company Allocations

Allocations to 2010 Parent Companies Difference from Mean

Parent Company EPA Heat 

Input

Heat 

Input & 

Fuel 

Factor

Heat 

Input & 

Fuel 

Factor, 

Coal Type

EPA Heat 

Input

Heat 

Input & 

Fuel 

Factor

Heat 

Input & 

Fuel 

Factor, 

Coal Type

AE 108,654 83,426 102,488 127,896 2.88% -21.01% -2.96% 21.10%

AEP 393,878 310,508 362,178 377,306 9.12% -13.98% 0.34% 4.53%

AES 57,975 57,511 68,187 86,110 -14.04% -14.73% 1.10% 27.67%

ALABAMA ELECTRIC COOPERATIVE 7,534 8,634 9,674 10,801 -17.76% -5.75% 5.60% 17.91%

Alcoa 5,264 10,476 12,970 6,364 -39.97% 19.47% 47.92% -27.42%

ALLETE INC 11,580 16,846 20,234 9,772 -20.73% 15.32% 38.51% -33.11%

Alliant Energy 51,226 51,752 61,977 31,880 4.10% 5.17% 25.95% -35.21%

Ameren 123,596 110,291 135,513 94,354 6.60% -4.87% 16.88% -18.62%

AMERICAN CONSUMER INDUSTRIES 

INC

264 537 684 855 -54.91% -8.19% 16.94% 46.17%

AQUILA INC 4,730 7,203 8,437 4,074 -22.60% 17.87% 38.06% -33.33%

ASSOCIATED ELECTRIC 

COOPERATIVE INC

28,196 30,442 36,295 17,518 0.30% 8.29% 29.11% -37.69%

Austin City of (MN) 528 313 388 484 23.29% -26.91% -9.40% 13.02%

Austin Energy 258 5,244 7 90 -81.57% 274.64% -99.50% -93.57%

Austin Energy and Lower Colorado River 

Authority

21,018 19,651 26,602 14,532 2.77% -3.91% 30.08% -28.94%

BLACK RIVER POWER LLC 198 845 1,070 698 -71.86% 20.25% 52.27% -0.67%

BOARD OF PUBLIC UTILTIIES 

JAMESTOWN

1,522 531 598 301 106.23% -28.05% -18.97% -59.21%

Brazos Electric Power Coop Inc 1,024 2,825 4 49 4.97% 189.60% -99.59% -94.98%

Calpine 0 11,703 16 195

Cedar Falls City of 278 121 149 185 51.71% -33.97% -18.69% 0.95%

CenterPoint 53,249 86,097 67,645 37,543 -12.90% 40.83% 10.65% -38.59%

CENTRAL ELECTRIC POWER 

COOPERATIVE

2,733 702 873 1,052 103.96% -47.61% -34.85% -21.49%

CENTRAL IOWA POWER 

COOPERATIVE

2,792 515 582 724 142.10% -55.34% -49.53% -37.22%

Cinergy 119,262 115,751 139,909 174,439 -13.16% -15.72% 1.87% 27.01%

CITY OF AMES 1,120 981 1,207 578 15.29% 0.98% 24.24% -40.50%

CITY OF COLUMBIA, MO 2,334 173 209 101 231.42% -75.43% -70.32% -85.66%

CITY OF GAINESVILLE 4,234 3,581 3,220 4,139 11.61% -5.60% -15.12% 9.11%

CITY OF INDEPENDENCE 2,339 294 365 458 170.72% -65.97% -57.75% -46.99%

CITY OF ROCHESTER, MN 1,569 404 483 603 105.17% -47.17% -36.84% -21.15%

CITY OF SIKESTON 3,401 3,444 4,282 2,065 3.12% 4.43% 29.84% -37.39%

CLECO CORPORATION 21,143 22,494 18,222 11,187 15.78% 23.18% -0.22% -38.74%

CMS ENERGY 47,623 39,280 45,748 45,287 7.06% -11.70% 2.84% 1.80%

Cogentrix 5,533 16,694 20,843 24,637 -67.31% -1.38% 23.14% 45.55%

Conectiv 8,251 72 9 11 295.59% -96.55% -99.57% -99.47%

CONSTELLATION ENERGY GROUP 28,319 33,713 35,030 41,573 -18.29% -2.73% 1.07% 19.95%

Corn Belt Power Coop 190 97 120 149 36.69% -30.22% -13.67% 7.19%

DAIRYLAND POWER COOPERATIVE 9,179 9,167 11,339 8,449 -3.72% -3.84% 18.94% -11.38%

Delta Power Company 877 1,657 2,144 2,747 -52.74% -10.74% 15.50% 47.98%

Dominion 91,334 98,717 109,174 123,833 -13.64% -6.66% 3.22% 17.08%

DPL INC 48,054 35,034 43,085 53,687 6.87% -22.09% -4.18% 19.40%

DTE ENERGY CO 105,695 79,349 94,568 72,628 20.03% -9.89% 7.39% -17.52%

Duke 83,314 76,989 90,977 112,646 -8.43% -15.38% 0.00% 23.81%

Dynegy 64,596 44,575 49,213 60,551 18.02% -18.56% -10.09% 10.63%

EAST KENTUCKY POWER 

COOPERATIVE

19,695 17,220 20,776 25,910 -5.77% -17.61% -0.59% 23.97%
29

Table 3. 2010 Parent Company Allocations

Edison International 88,459 80,550 94,659 67,559 6.83% -2.73% 14.31% -18.41%

EL PASO CORP 748 1,501 1,911 2,391 -54.34% -8.35% 16.69% 46.00%

Empire District Electric Company 4,897 4,405 2,858 1,713 41.20% 27.01% -17.60% -50.61%

ENERGY EAST CORPORATION 4,433 2,930 3,712 4,841 11.41% -26.36% -6.71% 21.66%

Entergy 20,548 88,813 11,960 10,205 -37.51% 170.10% -63.63% -68.96%

Exelon 31,963 20,675 10,321 12,931 68.47% 8.97% -45.60% -31.84%

First Energy 109,909 75,549 92,754 106,457 14.29% -21.44% -3.55% 10.70%

FPL 59,921 88,196 23,247 25,930 21.49% 78.81% -52.87% -47.43%

Garland City of 108 2,476 4 42 -83.57% 276.58% -99.39% -93.61%

Grand Haven City of 744 641 795 999 -6.39% -19.35% 0.03% 25.70%

GREAT PLAINS ENERGY 34,564 20,670 24,464 11,865 51.00% -9.70% 6.87% -48.17%

Henderson City Utility Comm 406 66 82 102 147.56% -59.76% -50.00% -37.80%

HOLLAND BOARD OF PUBLIC WORKS 824 482 444 561 42.62% -16.57% -23.15% -2.90%

HOOSIER ENERGY REC INC 18,533 17,557 21,596 26,931 -12.39% -17.00% 2.09% 27.31%

JEA 21,444 27,980 28,386 29,063 -19.74% 4.72% 6.24% 8.78%

KeySpan 31,940 32,206 10,194 12,002 47.97% 49.20% -52.77% -44.40%

Kissimmee Utility Authority 0 2,093 3 31

LAKELAND ELECTRIC 6,431 7,634 6,740 8,275 -11.54% 5.01% -7.29% 13.82%

Lansing City of 8,710 5,237 6,493 5,694 33.31% -19.84% -0.62% -12.85%

LGE 97,141 96,610 113,259 133,986 -11.89% -12.37% 2.73% 21.53%

Lower Colorado River Authority 342 7,763 11 133 -83.42% 276.43% -99.47% -93.55%

Madison Gas & Electric Co 546 1,296 1,315 1,462 -52.72% 12.23% 13.88% 26.61%

MANITOWOC PUBLIC UTILITIES 862 628 778 374 30.51% -4.92% 17.79% -43.38%

Marquette City of 251 659 817 395 -52.69% 24.22% 54.01% -25.54%

MCDERMOTT INTERNATIONAL 562 968 1,233 1,542 -47.76% -10.06% 14.56% 43.27%

Michigan South Central Pwr Agy 907 765 948 1,147 -3.69% -18.77% 0.66% 21.79%

Mid-America Energy 32,911 40,437 49,452 23,701 -10.14% 10.41% 35.02% -35.29%

Mirant 72,299 46,440 44,779 55,182 32.23% -15.06% -18.10% 0.93%

MORA-SAN MIGUEL ELECTRIC CO-OP 8,326 5,863 7,937 4,336 25.86% -11.37% 19.98% -34.46%

MUSCATINE POWER & WATER 1,697 3,209 3,948 1,892 -36.83% 19.45% 46.96% -29.57%

Nisource 25,352 33,752 41,011 37,350 -26.23% -1.79% 19.34% 8.68%

Northampton Generating Company LP, 

Cogentrix, and Foster Wheeler

604 1,438 1,831 881 -49.21% 21.00% 54.08% -25.87%

NRG Energy 50,948 44,210 47,096 40,303 11.63% -3.13% 3.19% -11.69%

ORLANDO UTILITIES CO 5,977 10,573 13,362 17,123 -49.17% -10.08% 13.63% 45.62%

Otter Tail Corp 15,285 1,734 2,147 1,031 202.72% -65.66% -57.48% -79.58%

OWENSBORO MUNICIPAL UTILITIES 4,517 5,774 7,153 8,797 -31.15% -11.99% 9.04% 34.10%

Pella City of 882 272 333 160 114.21% -33.94% -19.13% -61.14%

PG&E CORP 8,235 1,477 1,881 2,353 136.19% -57.64% -46.05% -32.51%

Power Authority of State of NY 3,225 7,613 1,906 2,266 -14.06% 102.88% -49.21% -39.61%

PP&L 81,781 33,733 39,924 49,359 59.73% -34.11% -22.02% -3.59%

Progress Energy 124,143 106,938 106,277 132,581 5.67% -8.98% -9.54% 12.85%

Reliant 129,292 96,864 102,152 127,111 13.56% -14.92% -10.28% 11.64%

Reynolds American Inc. 2,901 1,411 1,758 2,176 40.74% -31.56% -14.73% 5.55%

RICHMOND POWER & LIGHT 4,474 1,318 1,632 2,035 89.20% -44.26% -30.99% -13.94%

San Antonio Public Service Bd 21,754 29,172 24,038 13,317 -1.43% 32.18% 8.92% -39.66%

SCANA CORPORATION 30,737 30,084 36,294 45,526 -13.81% -15.64% 1.78% 27.67%

SCHUYLKILL ENERGY RESOURCES 1,797 1,683 2,142 1,031 8.05% 1.18% 28.78% -38.01%

SEMINOLE ELECTRIC COOPERATIVE 

INC

18,420 18,090 21,437 26,428 -12.68% -14.24% 1.63% 25.29%

SEMPRA ENERGY 3,535 13,127 5,470 3,137 -44.04% 107.80% -13.41% -50.34%

SOUTH CAROLINA PUBLIC SERVICE 

AUTH.

21,577 34,920 41,801 52,423 -42.74% -7.33% 10.94% 39.13%

SOUTH MISSISSIPPI ELECTRIC 

POWER ASSOC.

5,106 5,059 5,080 6,924 -7.87% -8.72% -8.34% 24.93%
30

Table 3. 2010 Parent Company Allocations

Southern 364,955 291,167 341,733 368,281 6.86% -14.75% 0.06% 7.83%

Southern Illinois Power Coop 4,160 3,082 3,864 4,834 4.39% -22.66% -3.04% 21.30%

Springfield CWLP 8,965 10,052 12,324 10,621 -14.54% -4.18% 17.48% 1.24%

SUEZ ENERGY INTERNATIONAL 557 4,989 6,454 3,308 -85.45% 30.36% 68.64% -13.56%

Tallahassee City of 3,030 3,742 5 55 77.40% 119.09% -99.71% -96.78%

TECO ENERGY INC 41,972 30,401 37,936 43,517 9.14% -20.95% -1.35% 13.16%

TEXAS MUNICIPAL POWER AGENCY 6,952 5,218 7,064 3,859 20.42% -9.62% 22.36% -33.16%

Tondu Corporation 253 961 1,191 1,498 -74.07% -1.51% 22.06% 53.52%

TRIGEN ENERGY CORP 435 1,063 1,347 676 -50.54% 20.75% 53.00% -23.21%

TVA 208,137 185,217 226,027 276,356 -7.05% -17.29% 0.93% 23.41%

TXU 123,836 124,513 102,722 56,908 21.41% 22.08% 0.71% -44.20%

UGI CORPORATION 1,130 655 764 516 47.47% -14.52% -0.29% -32.66%

VECTREN CORP 10,234 11,446 13,857 17,282 -22.50% -13.32% 4.94% 30.88%

WE Energies 42,903 42,759 52,168 35,984 -1.27% -1.60% 20.05% -17.19%

Wheelabrator Technologies Inc. 637 805 1,025 493 -13.89% 8.77% 38.50% -33.38%

WPS 18,496 18,649 21,774 12,690 3.32% 4.17% 21.63% -29.12%

WYANDOTTE DEPARTMENT OF 

MUNICIPAL Services

547 702 812 394 -10.88% 14.38% 32.30% -35.80%

XCel Energy 61,902 84,248 96,922 49,634 -15.41% 15.13% 32.45% -32.17%

 

Average 11.08% 5.73% -3.54% -13.27%

Percent Positive 51.82% 34.55% 56.36% 43.64%
31

Table 4. 2015 Parent Company Allocations

 Allocations to 2015 Parent Companies Difference from Mean 

Parent Company EPA Heat 

Input

Heat 

Input & 

Fuel 

Factor

Heat 

Input & 

Fuel 

Factor, 

Coal 

Type

EPA Heat Input Heat Input 

& Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

AE 76,059 58,399 71,741 89,529 2.88% -21.01% -2.96% 21.10%

AEP 275,713 217,353 253,524 264,113 9.12% -13.98% 0.34% 4.53%

AES 40,583 40,256 47,731 60,276 -14.04% -14.73% 1.10% 27.67%

ALABAMA ELECTRIC 

COOPERATIVE 5,274 6,044 6,772 7,561 -17.76% -5.75% 5.60% 17.91%

Alcoa 3,684 7,333 9,079 4,455 -39.98% 19.47% 47.92% -27.42%

ALLETE INC 8,106 11,793 14,164 6,841 -20.73% 15.32% 38.51% -33.10%

Alliant Energy 35,855 36,226 43,383 22,317 4.09% 5.17% 25.95% -35.21%

Ameren 86,518 77,202 94,859 66,047 6.61% -4.87% 16.88% -18.62%

AQUILA INC 3,310 5,043 5,906 2,852 -22.62% 17.89% 38.06% -33.33%

ASSOCIATED ELECTRIC 

COOPERATIVE INC 19,737 21,309 25,407 12,262 0.30% 8.28% 29.11% -37.69%

Austin City of (MN) 369 219 271 339 23.21% -26.88% -9.52% 13.19%

Austin Energy 180 3,671 5 63 -81.63% 274.69% -99.49% -93.57%

Austin Energy and Lower 

Colorado River Authority 14,712 13,756 18,622 10,173 2.77% -3.91% 30.08% -28.94%

BLACK RIVER POWER LLC 138 591 749 489 -71.86% 20.16% 52.28% -0.58%

BOARD OF PUBLIC UTILITIES 

JAMESTOWN 1,065 372 419 211 106.10% -28.01% -18.92% -59.17%

Brazos Electric Power Coop Inc 717 1,978 3 33 5.02% 189.71% -99.56% -95.17%

Cedar Falls City of 194 84 104 129 51.86% -34.25% -18.59% 0.98%

CenterPoint 37,272 60,270 47,349 26,278 -12.90% 40.84% 10.65% -38.59%

CENTRAL ELECTRIC POWER 

COOPERATIVE 1,913 491 611 736 104.00% -47.64% -34.84% -21.51%

CENTRAL IOWA POWER 

COOPERATIVE 1,955 361 407 506 142.18% -55.28% -49.58% -37.32%

CINERGY 83,483 81,023 97,936 122,107 -13.16% -15.72% 1.87% 27.01%

CITY OF AMES 784 687 845 405 15.25% 0.99% 24.22% -40.46%

CITY OF COLUMBIA, MO 1,634 121 146 71 231.44% -75.46% -70.39% -85.60%

CITY OF GAINESVILLE 2,963 2,507 2,253 2,897 11.60% -5.57% -15.14% 9.11%

CITY OF INDEPENDENCE 1,637 206 256 320 170.69% -65.94% -57.67% -47.09%

CITY OF ROCHESTER, MN 1,098 283 338 422 105.14% -47.13% -36.85% -21.16%

CITY OF SIKESTON 2,381 2,411 2,997 1,445 3.14% 4.44% 29.82% -37.41%

CLECO CORPORATION 14,799 15,746 12,756 7,830 15.77% 23.18% -0.21% -38.75%

CMS ENERGY 33,336 27,495 32,024 31,701 7.06% -11.70% 2.84% 1.80%

Cogentrix 3,873 11,685 14,592 17,247 -67.31% -1.39% 23.15% 45.55%

Conectiv 5,775 51 6 7 295.62% -96.51% -99.59% -99.52%

CONSTELLATION ENERGY 

GROUP 19,822 23,597 24,522 29,101 -18.30% -2.73% 1.08% 19.95%

Corn Belt Power Coop 133 68 84 104 36.76% -30.08% -13.62% 6.94%

DAIRYLAND POWER 

COOPERATIVE 6,425 6,417 7,937 5,915 -3.72% -3.84% 18.93% -11.37%
32

Table 4. 2015 Parent Company Allocations

 Allocations to 2015 Parent Companies Difference from Mean 

Parent Company EPA Heat 

Input

Heat 

Input & 

Fuel 

Factor

Heat 

Input & 

Fuel 

Factor, 

Coal 

Type

EPA Heat Input Heat Input 

& Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

Delta Power Company 614 1,160 1,501 1,923 -52.74% -10.74% 15.50% 47.98%

Dominion 63,934 69,105 76,424 86,685 -13.65% -6.66% 3.22% 17.08%

DPL INC 33,637 24,523 30,159 37,580 6.87% -22.09% -4.18% 19.40%

DTE ENERGY CO 73,987 55,547 66,196 50,841 20.03% -9.89% 7.39% -17.52%

Duke 58,320 53,891 63,684 78,854 -8.43% -15.38% -0.01% 23.81%

Dynegy 45,218 31,203 34,448 42,385 18.02% -18.56% -10.09% 10.63%

EAST KENTUCKY POWER 

COOPERATIVE 13,787 12,054 14,542 18,137 -5.76% -17.61% -0.60% 23.97%

Edison International 61,922 56,384 66,260 47,292 6.83% -2.73% 14.31% -18.41%

EL PASO CORP 523 1,051 1,338 1,673 -54.34% -8.32% 16.72% 45.94%

Empire District Electric Company 3,427 3,084 2,001 1,199 41.16% 27.03% -17.58% -50.61%

ENERGY EAST CORPORATION 3,104 2,051 2,598 3,389 11.43% -26.37% -6.73% 21.67%

Entergy 14,383 62,169 8,371 7,145 -37.51% 170.10% -63.63% -68.96%

Exelon 22,376 14,472 7,225 9,050 68.48% 8.97% -45.60% -31.86%

First Energy 76,935 52,885 64,927 74,519 14.29% -21.44% -3.55% 10.70%

FPL 41,945 61,736 16,274 18,151 21.49% 78.81% -52.87% -47.43%

Grand Haven City of 520 449 556 700 -6.52% -19.28% -0.04% 25.84%

GREAT PLAINS ENERGY 24,195 14,469 17,125 8,306 50.99% -9.70% 6.87% -48.16%

Henderson City Utility Comm 284 46 57 71 148.03% -59.83% -50.22% -37.99%

HOLLAND BOARD OF PUBLIC 

WORKS 577 338 311 392 42.65% -16.44% -23.11% -3.09%

HOOSIER ENERGY REC INC 12,973 12,291 15,117 18,851 -12.39% -17.00% 2.09% 27.30%

JEA 15,010 19,585 19,870 20,345 -19.74% 4.72% 6.24% 8.78%

KeySpan 22,359 22,544 7,135 8,401 47.98% 49.20% -52.78% -44.40%

LAKELAND ELECTRIC 4,501 5,344 4,717 5,793 -11.55% 5.02% -7.31% 13.84%

Lansing City of 6,097 3,667 4,545 3,986 33.30% -19.83% -0.63% -12.85%

LGE 67,996 67,628 79,279 93,788 -11.89% -12.37% 2.73% 21.53%

Lower Colorado River Authority 239 5,434 8 93 -83.44% 276.45% -99.45% -93.56%

Madison Gas & Electric Co 382 906 920 1,023 -52.71% 12.16% 13.90% 26.65%

MANITOWOC PUBLIC UTILITIES 603 440 545 262 30.38% -4.86% 17.84% -43.35%

Marquette City of 176 461 572 277 -52.62% 24.09% 53.97% -25.44%

MCDERMOTT INTERNATIONAL 394 678 863 1,080 -47.77% -10.04% 14.51% 43.30%

Michigan South Central Pwr Agy 635 535 664 803 -3.68% -18.85% 0.72% 21.81%

Mid-America Energy 23,037 28,307 34,617 16,590 -10.14% 10.41% 35.02% -35.29%

Mirant 50,609 32,507 31,345 38,628 32.23% -15.06% -18.10% 0.93%

MORA-SAN MIGUEL ELECTRIC 

CO-OP 5,828 4,104 5,556 3,035 25.85% -11.38% 19.98% -34.46%

MUSCATINE POWER & WATER 1,188 2,247 2,764 1,324 -36.83% 19.47% 46.96% -29.60%

Nisource 17,746 23,627 28,708 26,146 -26.23% -1.79% 19.33% 8.68%

Northampton Generating 

Company LP, Cogentrix, and 

Foster Wheeler 422 1,007 1,282 617 -49.23% 21.02% 54.06% -25.85%
33

Table 4. 2015 Parent Company Allocations

 Allocations to 2015 Parent Companies Difference from Mean 

Parent Company EPA Heat 

Input

Heat 

Input & 

Fuel 

Factor

Heat 

Input & 

Fuel 

Factor, 

Coal 

Type

EPA Heat Input Heat Input 

& Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

NRG Energy 35,664 30,946 32,967 28,213 11.63% -3.13% 3.19% -11.69%

ORLANDO UTILITIES CO 4,184 7,401 9,353 11,986 -49.17% -10.08% 13.63% 45.62%

Otter Tail Corp 10,701 1,214 1,503 722 202.72% -65.66% -57.48% -79.58%

OWENSBORO MUNICIPAL 

UTILITIES 3,162 4,041 5,007 6,158 -31.14% -12.00% 9.04% 34.10%

Pella City of 617 190 233 112 114.24% -34.03% -19.10% -61.11%

PG&E CORP 5,764 1,034 1,317 1,647 136.18% -57.63% -46.04% -32.51%

Power Authority of State of NY 2,258 5,329 1,334 1,587 -14.05% 102.85% -49.22% -39.59%

PP&L 57,246 23,613 27,947 34,549 59.73% -34.11% -22.02% -3.60%

Progress Energy 86,899 74,854 74,391 92,804 5.67% -8.98% -9.54% 12.85%

Reliant 90,507 67,805 71,504 88,976 13.56% -14.92% -10.28% 11.64%

Reynolds American Inc. 2,031 988 1,231 1,523 40.73% -31.54% -14.71% 5.53%

RICHMOND POWER & LIGHT 3,131 923 1,142 1,424 89.18% -44.23% -31.00% -13.96%

San Antonio Public Service Bd 15,228 20,420 16,826 9,322 -1.43% 32.18% 8.91% -39.66%

SCANA CORPORATION 21,516 21,059 25,407 31,869 -13.81% -15.64% 1.78% 27.67%

SCHUYLKILL ENERGY 

RESOURCES 1,258 1,178 1,500 722 8.03% 1.16% 28.81% -38.00%

SEMINOLE ELECTRIC 

COOPERATIVE INC 12,894 12,663 15,005 18,500 -12.67% -14.24% 1.62% 25.29%

SEMPRA ENERGY 2,475 9,188 3,831 2,195 -44.03% 107.77% -13.37% -50.36%

SOUTH CAROLINA PUBLIC 

SERVICE AUTH. 15,105 24,445 29,262 36,696 -42.73% -7.32% 10.94% 39.12%

SOUTH MISSISSIPPI ELECTRIC 

POWER ASSOC. 3,574 3,541 3,556 4,848 -7.88% -8.73% -8.34% 24.96%

Southern 255,467 203,816 239,213 257,795 6.86% -14.75% 0.06% 7.83%

Southern Illinois Power Coop 2,912 2,158 2,705 3,384 4.38% -22.65% -3.04% 21.30%

Springfield CWLP 6,274 7,036 8,626 7,434 -14.55% -4.17% 17.48% 1.25%

SUEZ ENERGY 

INTERNATIONAL 390 3,493 4,518 2,316 -85.45% 30.37% 68.63% -13.56%

Tallahassee City of 2,121 2,619 4 39 77.38% 119.03% -99.67% -96.74%

TECO ENERGY INC 29,380 21,281 26,556 30,462 9.14% -20.95% -1.35% 13.16%

TEXAS MUNICIPAL POWER 

AGENCY 4,866 3,653 4,945 2,701 20.41% -9.61% 22.36% -33.16%

Tondu Corporation 177 672 834 1,049 -74.07% -1.61% 22.10% 53.58%

TRIGEN ENERGY CORP 305 744 943 473 -50.53% 20.74% 53.03% -23.24%

TVA 145,695 129,649 158,219 193,448 -7.05% -17.29% 0.94% 23.41%

TXU 86,685 87,160 71,906 39,836 21.41% 22.08% 0.71% -44.20%

UGI CORPORATION 791 459 535 361 47.44% -14.45% -0.28% -32.71%

VECTREN CORP 7,164 8,012 9,700 12,097 -22.49% -13.32% 4.94% 30.87%

WE Energies 30,030 29,933 36,518 25,188 -1.27% -1.59% 20.06% -17.19%

Wheelabrator Technologies Inc. 446 564 718 345 -13.93% 8.82% 38.54% -33.43%

WPS 12,947 13,054 15,241 8,883 3.32% 4.17% 21.62% -29.11%
34

Table 4. 2015 Parent Company Allocations

 Allocations to 2015 Parent Companies Difference from Mean 

Parent Company EPA Heat 

Input

Heat 

Input & 

Fuel 

Factor

Heat 

Input & 

Fuel 

Factor, 

Coal 

Type

EPA Heat Input Heat Input 

& Fuel 

Factor

Heat Input 

& Fuel 

Factor, 

Coal Type

WYANDOTTE DEPARTMENT OF 

MUNICIPAL Services 383 492 569 276 -10.93% 14.42% 32.33% -35.81%

XCel Energy 43,332 58,973 67,844 34,743 -15.41% 15.13% 32.45% -32.17%

 

Average 12.49% 3.10% -2.83% -12.76%

Percent Positive 52.78% 34.26% 55.56% 43.52%
35

Table 5. Percent of Region-wide Budget for 24 CAIR States under EPA’s CAIR Approach 

and Alternatives (Data Used To Generate Cumulative Distributions) 

State 

EPA 

Title IV 

Average 

(Pure) 

Heat 

Input 

Heat 

Input 

w/ Fuel 

Factors 

Heat Input 

w/ Fuel 

Factors & 

Coal Type 

Average 

Heat 

Input 

Coal + 

Oil 

Average 

Emissions

Average 

Output 

All 

Average 

Output 

Fossil 

Alabama 4.4% 4.7% 5.4% 5.9% 4.7% 5.0% 4.7% 4.2% 

District of Columbia 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 

Florida 7.0% 8.5% 6.3% 7.6% 7.3% 6.0% 7.2% 7.7% 

Georgia 5.9% 4.5% 5.3% 6.0% 4.5% 5.2% 4.5% 4.2% 

Iowa 1.8% 5.1% 6.1% 5.0% 2.3% 1.4% 1.5% 1.8% 

Illinois 5.3% 7.2% 8.8% 9.0% 5.2% 4.7% 6.6% 4.4% 

Indiana 7.0% 2.1% 2.7% 1.4% 7.5% 8.6% 4.6% 6.2% 

Kentucky 5.2% 5.4% 6.7% 8.2% 5.8% 5.8% 3.5% 4.5% 

Louisiana 1.7% 3.7% 1.8% 1.1% 1.5% 1.1% 3.4% 3.6% 

Maryland 2.0% 1.9% 2.1% 2.6% 2.0% 2.7% 1.9% 1.7% 

Michigan 4.9% 4.7% 5.0% 4.2% 4.3% 3.7% 4.1% 4.2% 

Minnesota 1.4% 2.1% 2.5% 1.3% 2.2% 1.0% 1.9% 1.7% 

Missouri 3.8% 1.5% 1.1% 1.2% 4.1% 2.4% 2.9% 3.4% 

Mississippi 0.9% 4.0% 4.8% 2.6% 1.1% 1.2% 1.6% 1.6% 

North Carolina 3.8% 4.4% 2.4% 3.0% 4.3% 4.7% 4.5% 3.8% 

New York 3.7% 4.1% 5.0% 6.2% 3.4% 2.7% 5.3% 3.9% 

Ohio 9.2% 7.1% 8.8% 10.9% 7.5% 12.2% 5.4% 6.5% 

Pennsylvania 7.6% 6.6% 7.9% 9.5% 6.9% 9.5% 7.4% 6.1% 

South Carolina 1.6% 2.2% 2.6% 3.3% 2.2% 2.1% 3.4% 2.0% 

Tennessee 3.8% 3.3% 4.1% 4.9% 3.5% 4.0% 3.5% 3.0% 

Texas 8.9% 16.9% 10.5% 6.2% 9.0% 6.0% 13.9% 16.6% 

Virginia 1.8% 2.5% 2.8% 3.5% 2.5% 2.3% 2.8% 2.3% 

Wisconsin 2.4% 4.8% 6.0% 7.6% 2.8% 2.0% 2.2% 2.2% 

West Virginia 6.0% 2.7% 3.3% 2.0% 5.2% 5.8% 3.4% 4.5% 

Source: EPA, 2006 

 
36
37

Appendix C: Commenter Information Summary Table 

Company 

Preferred 

Allocations 

Approach 

Best Allocation 

Approach (in 

terms of coverage) 

2010: 

Emissions – 

Allowances 

2010: Cost 

of 

Allowances 

(million 

2004$) 

Revenues 

(million 

2004$) 

2010: Allowance 

Costs as Percent 

of Revenue (%) 

2010: Coal Capacity 

(GW) 

AES Updating HI w/FF & Coal 

Type 

17,808 12 9,463 0.1 3.2 

Minnesota Power 

HI w/FF (coal & oil only) 

HI w/ FF 16,785 12 737 1.6 1.3 

Duke HI w/ FF HI w/FF & Coal 

Type 

80,328 55 16,746 0.3 8.3 

FPL Output or 

Simple HI 

Simple HI -56,160 -39 10,522 -0.4 0.2 

JEA HI w/FF HI w/FF & Coal 

Type 

-6,177 -4 1,013 -0.4 3.5 

NIPSCO HI w/FF HI w/ FF 43,541 29 6,666 0.4 3.1 South Carolina Public Service Authority 

HI w/FF HI w/FF & Coal 

Type 

15,221 10 1,350 0.8 2.8 

2010: Total Coal Capacity by these Companies: 22.4 / Total CAIR-affected Coal Capacity: 243.8 GW = 9.2% Note: (Emission-Allowances) are based on 2010 CAIR projected emissions and CAIR allocations. Cost of allowances are based on IPM modeling run CAIR_CAMR_CAVR available at www.epa.gov/airmarkets/mp adjusted to 2004$. Electric power revenues and capacity are based on company 

information given to EPA or available at company websites. Source: EPA, 2006