1

Technical Support Document (TSD) for the Transport Rule

Docket ID No. EPA-HQ-OAR-2009-0491

Allowance Allocation Final Rule TSD

U.S Environmental Protection Agency

Office of Air and Radiation

June 2011
2

Allowance Allocation to Existing and New Units under the Transport Rule Federal Implementation 

Plan (FIP)

This Technical Support Document (TSD) provides information that supports EPA‟s 

determination of unit-level allocations for existing and new units under the final Transport Rule. Section 

VI.D of the preamble discusses state budgets, and section VII.D discusses how the budgets are 

apportioned (i.e., allocated) to existing and new units under FIP program structure. This TSD provides 

additional information in support of unit level allocations and elaborates on the data and methodology 

used to arrive at the final allocations. The TSD is organized as follows:

1) Overview

2) New Unit Set-Asides and Allocations

3) Allocation Methodology for Existing Units

a. List of Existing Units

b. Data and Calculations

4) Appendix A: Effects of Allowance Allocations on the Competition between Power Plants

EPA anticipates that some states will submit State Implementation Plans (SIPs) with revised unit-level 

allocations to existing units that will replace those defined in the FIP. Section X of the final Transport 

Rule preamble explains when and how states may replace the FIP allocations, which can occur by vintage 

year 2013 or later through specific SIP procedures.

1. Overview

As discussed in preamble section VI, each state‟s budget is comprised of the emissions that EPA 

estimates remain after the state has made the reductions required to eliminate its significant contribution 

to nonattainment and interference with maintenance of the relevant National Ambient Air Quality 

Standards (NAAQS) in downwind states in an average year. EPA finalized the Transport Rule with four

limited interstate trading programs. Emission allowances are used in the implementation of these 

programs. Specifically, EPA creates one allowance for each ton of emissions allowed in each year under 

each state‟s budget. Each allowance has a “vintage” year, which is the year for which the allowance is 

issued. Covered sources are required to submit such an allowance for each ton of the relevant pollutant 

emitted on an annual basis. To implement the programs, allowances are initially allocated among covered 

sources within a state. 

As discussed in the preamble, under the FIP, EPA allocates allowances to sources in the state equal to 

that state‟s total budget. The methodology used to determine states budgets is independent of and not 

affected by the methodology used to determine initial allowance allocations. In other words, initial 

allowance allocations in no way impact the state budgets. The state budgets are determined 
3

independently through the multi-factor analysis outlined in section VI of the Transport Rule preamble. 

Regardless of the methodology used by EPA or a state to allocate allowances to sources within the state, 

all emissions in each covered state that significantly contribute to nonattainment or interfere with 

maintenance in another state will be prohibited. In sum, the allocation methodology has no impact on the 

rule‟s ability to satisfy the statutory mandate of CAA section 110(a)(2)(D)(i)(I) to eliminate significant 

contribution and interference with maintenance in downwind states.

As discussed in section VII.D of the preamble, under the FIPs, EPA will distribute the entire 

budget to sources located in the state subject to the FIP. However, this budget would first be divided into 

three different subgroups listed below (note, amounts vary by state):

1) New source set-aside

2) Indian Country set-aside 

3) Existing unit budget 

An initial amount of the state budget (92% to 98%, depending on the state) would be distributed to 

existing sources (i.e. sources online before January 1, 2010) in advance of the vintage year for which they 

are issued. The remaining amount would be held back for new units in a new source set-aside account. If 

any of the new source set-aside allowances remained unclaimed two weeks prior to the allowance transfer 

deadline, then they would be allocated to existing units on the same pro-rata heat input basis as the initial 

existing unit budget so they will be available to existing units for compliance. 

The final Transport Rule identifies potentially covered existing Transport Rule units and allocations 

for each of those units under the FIP. This TSD details how the list of potentially existing units was 

determined, how allocations were calculated, and how the quantity of allowance set-asides for new units 

and Indian Country units were determined. Following these descriptions, an appendix showing each 

affected EGU‟s allocation under the final Transport Rule FIP along with the underlying data and 

calculations used to derive the allocation comprises most of the document.

2) New Unit Set Asides and Allocations

As explained in section VII.D, the final Transport Rule uses January 1, 2010 as the cut-off date to 

distinguish “new units” from “existing units” for purposes of allowance allocation. Allocations to

existing units are based on historic heat input over a five-year baseline as well as historic emissions data. 

To allocate on this basis, EPA needs at least one full year of heat input and emissions data from an 

“existing unit” to determine its allocation using this methodology. If a unit did not come online prior to 

January 1, 2010, it cannot have provided a full year of data at the time of the Transport Rule‟s

finalization. For this reason, EPA could not use a date later than Jan. 1, 2010 for the cut-off date. Units 

that came online after January 1, 2010 are considered “new units” for purposes of allocation under the 

final Transport Rule FIPs and will receive their allocations from the new source set-aside. In the 

proposal, only units that came online after January 1, 2012 were considered “new units”. Therefore, 

“planned” units coming online on or after January 1, 2010 represent a unique subset of units that were 

considered “existing units” at proposal, but “new units” in the final Transport Rule. EPA recognizes that 

the final rule‟s designation of these units as “new units” would, all else held equal, increase the demand 

for allowances in the new unit set-asides. As a result, EPA‟s methodology for establishing each state‟s 

new unit set aside in the final Transport Rule accounts specifically for the inclusion of units that 

commenced commercial operation on or after January 1, 2010 as described below. 
4

The new unit set-aside for SO2, annual NOX, and ozone-season NOX for each state is a percentage 

of the state‟s total budget. This percentage is the sum of a “base” percentage that all states receive for 

“potential” new units and a state-specific percentage reflecting emissions from “planned” units. For 

purposes of this document, the “potential” units on which the new source set-aside base percentage relies 

are those units that are projected new builds in the IPM modeling of the Transport Rule. In other words, 

they are units that do not show up in the modeling input, but do show up in the modeling output as 

surrogate facilities representing potential new EGUs that come online in future years in response to 

demand increases or other market drivers. “Planned” units, on which the state-specific percentage of the 

new source set-aside is based, are those units that are already identified in the modeling input (NEEDS) 

because they are specific plants that already built or are under construction, but that commence 

commercial operation on or after January 1, 2010. Because the location of these “planned” units is 

already known and identified in the modeling input, the portion of the new unit set-aside corresponding to 

these units is state-specific. 

EPA determined the base percentage of the new unit set-aside by assessing the share of each 

state‟s budget that is emitted in 2020 by new capacity build projected by the model (i.e., “potential 

units”). EPA identified each state‟s projected net new emissions in 2020 as a percent of the state‟s total 

budget. It then selected the maximum percentage among all states for all pollutants at the state level as 

the “base” percentage for each state‟s new unit set aside.

1

 By selecting the maximum percentage, EPA 

chose a conservative envelope that would provide a pool of new source set-aside allowances large enough 

to cover emissions from “potential” new units in any state. EPA chose this basis in order to preserve a 

reasonable amount of allowances for new unit allocations in every state, as new units may not be sited in 

the same locations that EPA‟s modeling assumes for analytical purposes. The maximum percentages of 

the total emissions represented by the projected net new emissions in 2020 at the state level are: 

SO2: 0.00 %

Annual NOX: 1.80%

Ozone-season NOX: 1.76%

In the final Transport Rule, EPA relied on this analysis to establish a “base” percentage for each 

pollutant as 2 percent of each state‟s total emissions budget for each pollutant. This base percentage is 

smaller than the 3 percent share EPA proposed to use in the proposed Transport Rule and is the result of 

EPA‟s updated power sector modeling, which projects a lower share of future emissions from “potential” 

new capacity build that the model projects.

The “state-specific” percentage represents the share of each state budget that EPA projects to be 

emitted from “planned” units in 2020. As discussed previously, determining the state-specific percentage 

is necessary given the new unit definition used in the final rule. EPA is determining a state-specific 

percentage for projected emissions from “planned” units because unlike the location of new capacity that 

the model projects to be built, the location of planned units is already known.

The base and state-specific percentages were added for each state and each pollutant to 

determine that state‟s size of the new-unit set asides, which are shown below in Tables 1 through 3

below.2

 

1 Net new emissions for each pollutant are equal to the projected 2020 emissions from newly built units by IPM 

(which does not include planned units) less the sum of allocations to units projected to be retire more than 4 years in 

advance of 2020. As explained in section VII.D of the preamble for the final Transport Rule, after 4 years of non 

operation, existing units have their allocation redirected to the new unit set asides, thereby offsetting the need for 

additional allowances to be withheld from existing unit allocations for purposes of the new unit set asides.

2 The ozone-season NOX values in these tables reflect EGUs in the 20 states covered by this rule for purposes of the 

ozone NAAQS and the six states that would be covered for the ozone NAAQS if EPA finalizes its supplemental 

proposal.
5

Table 1 - State New Unit Set-Aside

Accounts (As % of Total State Budget)

Annual 

SO2

Annual 

NOX

OzoneSeason 

NOX

Alabama 2% 2% 2%

Arkansas --- --- 2%

Florida --- --- 2%

Georgia 2% 2% 2%

Illinois 5% 8% 8%

Indiana 3% 3% 3%

Iowa 2% 2% 2%

Kansas 2% 2% 2%

Kentucky 6% 4% 4%

Louisiana --- --- 3%

Maryland 2% 2% 2%

Michigan 2% 2% 2%

Minnesota 2% 2% ---

Mississippi --- --- 2%

Missouri 2% 3% 3%

Nebraska 4% 7% ---

New Jersey 2% 2% 2%

New York 2% 3% 3%

North Carolina 8% 6% 6%
6

Ohio 2% 2% 2%

Oklahoma --- --- 2%

Pennsylvania 2% 2% 2%

South Carolina 2% 2% 2%

Tennessee 2% 2% 2%

Texas 5% 3% 3%

Virginia 4% 5% 5%

West Virginia 7% 5% 5%

Wisconsin 5% 6% 6%

Table 2: State New Unit Set-Aside Accounts (tons).*

SO2 in 

2012-

2013

SO2 in 

2014 and 

Later

NOX

Annual 

in 2012-

2013

NOX

Annual 

in 2014 

and 

Later

OzoneSeason 

NOX in 

2012-

2013

OzoneSeason 

NOX in 

2014

Alabama 4,321 4,265 1,454 1,439 635 630

Arkansas

--- --- --- --- 301 301

Florida --- --- --- --- 557 557

Georgia 3,171 1,905 1,240 811 559 366

Illinois 11,744 6,206 3,830 3,830 1,697 1,697

Indiana 8,563 4,833 3,292 3,253 1,406 1,385

Iowa 2,142 1,503 766 749 331 324

Kansas 831 831 615 512 271 220

Kentucky 13,960 6,377 3,403 3,090 1,447 1,307

Louisiana --- --- --- --- 403 403

Maryland 602 564 333 331 144 144

Michigan 5,486 2,880 1,204 1,156 515 495

Minnesota 840 840 592 592 --- ---

Mississippi

--- --- --- --- 203 203

Missouri 4,149 3,319 1,571 1,462 683 632

Nebraska 2,602 2,602 1,850 1,850 --- ---

New Jersey 111 111 145 145 68 68

New York 547 372 527 527 250 250
7

North Carolina 10,951 4,610 3,036 2,494 1,330 1,107

Ohio 6,205 2,742 1,854 1,750 801 756

Oklahoma --- --- --- --- 437 437

Pennsylvania 5,573 2,240 2,400 2,384 1,044 1,038

South Carolina 1,773 1,773 649 649 278 278

Tennessee 2,963 1,177 714 387 298 160

Texas 12,198 12,198 4,008 4,008 1,891 1,891

Virginia 2,833 1,402 1,662 1,662 723 723

West Virginia 10,232 5,297 2,974 2,729 1,264 1,165

Wisconsin 3,974 2,006 1,898 1,823 822 793

*Amounts shown reflect total set aside portion of budget (including set aside for Indian Country new units). 

Values are approximate, may vary slightly due to rounding. See Transport Rule rule text for final set-aside 

values.

For each control period, any allowances remaining in a state‟s new unit set-aside (after 

allocations are made to new units that requested allowances) are distributed to the existing units in that 

state in proportion to the existing units‟ original allocations. This ensures that total allocations to units in 

the state are equal to the state budget in that year. 

Each Indian country set-aside equals a proportion of the “base” new unit set-aside included in this 

final Transport Rule (the base percentage, as described above, is calculated as 2 percent of the state 

budget). EPA is reserving allowances for the Indian country set-aside from each state‟s “base” 

percentage of the new unit set-aside. EPA is not reserving these allowances from the state-specific 

percentage of each state‟s new unit set-aside because that percentage is specifically calculated on the 

basis of projected emissions from “planned” units, none of which are located in Indian country. EPA is 

creating Indian country set-asides in each state as a share of that state‟s base percentage portion of the

new unit set-aside, i.e., as a share of the 2 percent portion of the total budget in that state. EPA is 

determining the size of the Indian country set-aside (within that 2 percent portion of the state budget) on 

the basis of the percentage of Indian country relative to the entire state. EPA calculates the maximum 

percentage of Indian country in any state within the Transport Rule region to equal 5 percent, and is using 

that level as a basis for establishing Indian country set-asides for all states whose geographic boundaries 

encompass Indian country. Therefore, the Indian country set-aside is 5 percent of the base percentage 

new unit set-aside, which is equivalent to 0.1 percent of the total state budget (i.e., 5 percent of 2 percent 

is 0.1 percent). EPA assessed the share of Indian country within each state using the American Indian 

Reservations/Federally Recognized Tribal Entities dataset, which contains data for the 562 federally 

recognized Tribal entities in the contiguous U.S. and Alaska. EPA analyzed the share of square miles of 

Indian country within the total square miles of a state whose geographic boundaries encompass that

Indian country. As explained above, EPA then took the highest percentage as the number to be applied 

across all states with Indian country to determine the Indian country new unit set-aside. The Indian 

country new unit set-asides in the following Transport Rule states with Indian Country are shown in 

Table 4.

Table 3: New Unit Set-Aside Allowances for Indian Country (tons)
8

For SO2 in 

2012-2013, 

Indian 

Country

For SO2 in 

2014, 

Indian 

Country

For NOX 

Annual in 

2012-2013, 

Indian 

Country

For NOX 

Annual in 

2014, 

Indian 

Country

For OzoneSeason 

NOX in 

2012-2013, 

Indian 

Country

For OzoneSeason 

NOX in 

2014, 

Indian 

Country

Florida --- --- --- --- 28 28

Iowa 107 75 38 37 17 16

Kansas 42 42 31 26 14 11

Louisiana --- --- --- --- 13 13

Michigan 229 144 60 58 26 25

Minnesota 42 42 30 30 --- ---

Mississippi --- --- --- --- 10 10

Nebraska 65 65 26 26 --- ---

New York 27 19 18 18 8 8

North 

Carolina

137 58 51 42 22 18

South 

Carolina

89 89 32 32 14 14

Texas 244 244 134 134 63 63

Wisconsin 79 40 32 30 14 13

*Values are approximate, may vary slightly due to rounding. See Transport Rule rule text for final set-aside values

New units are allocated allowances from the set aside accounts described above. The final rule 

provides that a unit‟s new unit set-aside allocation initially equals that unit‟s emissions for the control 

period (annual or ozone-season) in the preceding year. EPA determines whether the total amount of 

initial allowance allocations for all units in a state for a control period exceeds the amount in the state‟s 

new unit set-aside for the control period. If the amount in the new unit set-aside is exceeded, EPA 

allocates each unit a proportionate share of the new unit set-aside based on the unit‟s initial allocation 

amount. Any unallocated allowances in the new unit set-aside are allocated to existing units in proportion 

to their share of the current existing-unit allocations. Unused allowances in the Indian country set aside 

are first transferred to the respective state‟s new unit set-aside. If allowances remain unused in the state‟s 

new unit set aside, they are then proportionally distributed, as previously described, to existing units in 

that state. 

3) Allocation Methodology for Existing Units

The allocation methodology bases a unit‟s allocation off heat input but limits any unit‟s allocation to 

its historic maximum emissions. Implementation of this methodology involves identifying potentially 

covered units and determining appropriate data baselines for each unit. EPA first identified the list of 

potential TR covered units. Next, it compiled reported data on each unit and calculated its share of heat 

input. Both stages are described below. 

a) List of Potential Existing Transport Rule Units

The list of units to which final allocations are adopted in the final rule is based on final 

applicability criteria discussed in section VII.B of the preamble and Sections 97.404, 97.504, 97.604, and 
9

97.704 of the final Transport Rule regulations. Existing units are units that are covered under these 

criteria and that commenced commercial operation prior to January 1, 2010. This cutoff date is used in 

the definition of existing unit because it assures that at least one full year of historic data is available to 

determine each existing unit‟s allocation. The baseline years used in the January 7, 2011 NODA (76 FR 

1109) ended in 2009 for similar reasons – at the time, it was the most recent year for which EPA had 

complete and quality assured data. Since publishing the NODA, the 2010 data has been reported and 

verified. Because an additional year of data is available, EPA updated it cut-off date for existing units to 

January 1, 2010, its heat input baseline from 2005-2009 to 2006-2010, and its historic emission baseline 

to 2003-2010. These final allocation tables available in the docket and on EPA‟s website contain a list of 

units that EPA believes, based on best available data, meet the covered and existing unit criteria. As 

described above, the percent of the state budgets allocated to existing units varies between 92% and 98% 

for each state depending on the number of planned units in each state.

To identify the potential existing Transport Rule units, EPA relied largely on data reported to 

EPA. To develop the list of potential existing Transport Rule units, EPA first included any fossil-fuelfired unit serving a generator greater than 25 MWe producing electricity for sale that is in a Transport 

Rule state and on line prior to January 1, 2010 and that reported emissions data in 2010 under at least one 

of the following ongoing EPA trading programs: the CAIR NOX or CAIR SO2 annual trading program or

the Acid Rain Program. EPA did not include units that were flagged as opt-in units. Data reported to 

EPA under CAIR and the Acid Rain Program meet the requirements of Part 75 and have been certified as 

to their accuracy and completeness by the source‟s designated representative. About 98% of the 

potential existing covered units listed in the final rule allocation tables were identified in this manner.

Next, EPA supplemented the list of units by using data from the Integrated Planning Model 

v.4.10 (IPM) to identify potential existing units under the Transport Rule that were not reporting data to 

EPA under the CAIR NOX or SO2 annual or Acid Rain trading program. Specifically, IPM‟s National 

Electric Energy Data System (NEEDS) was used to identify units that were potentially fossil-fuel-fired 

units serving generators greater than 25 MWe producing electricity for sale that are in a Transport Rule 

state and were not reporting under one of these ongoing EPA trading programs. To identify whether the 

NEEDs unit potentially met the fossil fuel criteria of a covered unit, EPA identified those units with a 

capacity greater than 25 MW and a plant type listing of coal steam, combined cycle, combustion turbine, 

fossil waste, IGCC, landfill gas, Municipal Solid Waste, O/G Steam, tires or biomass. Approximately 2% 

of the potential existing covered units listed in the final rule allocation tables were identified in this 

manner.

This subset of units identified through NEEDS was then screened to remove units that were not 

potential existing Transport Rule units and thus not eligible to obtain allocations. In particular, if the unit 

was retired or in cold storage in 2010 or is a steam turbine at a combined cycle (CC) plant that was listed 

as a separate unit in NEEDS but reported to EPA as one CC unit, then it was not included as a unit in the 

list of potential existing Transport Rule units. The remaining units in this subset of units were added to 

the list. For instance, there were units in Nebraska and Kansas that were identified through NEEDS as 

being potential existing Transport Rule units that were not currently reporting under the CAIR NOX or 

SO2 annual or Acid Rain trading program because the units were not Acid Rain Program units and were 

not in a CAIR state. Finally, a small number of units were added to or removed from the list based on 

comment and supporting data previously submitted to EPA during the comment period on the proposed 

Transport Rule and/or the January 7, 2011 NODA by the unit owner or operator.

Units identified using the EPA and NEEDS databases were included in the list of potential 

existing Transport Rule units if they were in one of the following states covered by the Transport Rule: 

Alabama, Arkansas, Florida, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland, 

Michigan, Minnesota, Mississippi, Missouri, Nebraska, New Jersey, New York, North Carolina, Ohio, 

Oklahoma, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West Virginia, and Wisconsin.
10

EPA notes that inclusion of a unit in, or exclusion of a unit from, the list of potential existing 

Transport Rule units presented in the final Transport Rule Allocation tables reflects only a preliminary 

assessment of the applicability of the final Transport Rule and in no way suggests that EPA has made a 

determination about the applicability of the final Transport Rule to any unit. As discussed above, the list 

of units developed for this NODA enables EPA to calculate allowance allocations for potential existing 

units based on the final allocation methodology. While allocations calculated for the final Transport Rule 

are based on the best available data provided to EPA by the time of the calculation, the applicability of the 

final Transport Rule to an individual unit is determined based on all relevant data, whether or not EPA 

has such data at the time that allocations are calculated. In fact, because any list of units developed for 

purposes of allowance allocation may not be entirely consistent with applicability determinations made in 

the future, the final Transport Rule establishes procedures to be applied when the Administrator 

determines that a unit allocated allowances turns out not to actually be a Transport Rule unit. For 

example, under these procedures, if such a determination would be made after EPA‟s recordation of the 

allowance allocation but before EPA‟s deduction of allowances for compliance with the requirement to 

hold allowances covering emissions, the Administrator would deduct the recorded allowances and 

transfer them to a new unit set-aside for the appropriate state. 

b) Data and Calculations

For the 98% of units identified through the process in section 3.a. above because they were 

reporting under the ARP and/or CAIR programs, EPA used reported heat-input and emissions data from 

the EPA database for the years 2003 through 2010. For units included in the list of potential existing 

Transport Rule units that were not reporting under one of these ongoing EPA trading programs, EPA used 

historic heat input and emissions data from Energy Information Administration (EIA) forms 767, 860, 

906, 920, and 923. These data are publicly available at

http://www.eia.doe.gov/cneaf/electricity/page/data.html. The heat input based allocation method 

finalized and described below is used to allocate the existing unit portion of the state‟s budget (i.e., the 

state budget less the state‟s new unit set-aside and, if applicable, the Indian Country new unit set-aside for 

the state).

The final Transport Rule uses a heat input allocation approach subject to a maximum allocation 

limit for any individual unit based on its maximum historic emissions. As described in the Transport rule 

preamble section VII.D, allocations under the Transport Rule FIP are determined by establishing a 

baseline historic heat input value for each potential existing Transport Rule unit and setting the unit‟s

initial share of available allowances under each Transport Rule trading program equal to the unit‟s 

percentage share of the total baseline historic heat input for all potential existing Transport Rule units in 

the state. This approach is applied to each state separately, using the portion of that state‟s budget 

available for potential existing Transport Rule units in that state. In instances where the heat input based 

allocation exceeds the unit‟s historic maximum emissions over the baseline period, this historic maximum 

emissions is used as an upper bound on the allocation and the source‟s allocation is set equal to this 

emission level. 

Allocations under this approach for each existing unit are determined by applying the following 

steps.

1. For each unit in the list of potential existing Transport Rule units, annual heat input values for the 

baseline period of 2006 through 2010 are identified using data reported to EPA or, where EPA 

data is unavailable, EIA. For a baseline year for which a unit has no data on heat input (e.g., for a 

baseline year before the year when a unit started operating), the units is assigned a zero value. 
11

(Step 2 explains how such zero values are treated in the calculations.) The allocation method 

uses a five-year baseline in order to improve representation of a unit‟s normal operating 

conditions over time. 

2. For each unit, the three highest, non-zero annual heat input values within the 5 year baseline are 

selected and averaged. Selecting the three highest, non-zero annual heat input values within the 

five-year baseline reduces the likelihood that any particular single year‟s operations (which might 

be negatively affected by outages or other unusual events) determine a unit‟s allocation. If a unit 

does not have three non-zero heat input values during the 5 year baseline period, EPA averages 

only those years for which a unit does have non-zero heat input values. For example, if a unit has 

only reported data for 2008 and 2009 among the baseline years and the reported heat input values 

are 2 and 4 mmBtus respectively, then the unit‟s average heat input used to determine its pro-rata 

share of the state budget is (2+4)/2 = 3.

3. Each unit is assigned a baseline heat input value calculated as described in step 2 above. This 

baseline heat input value is referred to in the data tables in the rulemaking docket, and on the 

website referenced previously, as the "three-year average heat input". 

4. The three-year average heat inputs of all potential existing Transport Rule units in a state is 

summed to obtain that state‟s total “three-year average heat input”.

5. Each unit‟s three-year average heat input is divided by the state‟s total three-year average heat 

input to determine that unit‟s share of the state‟s total three-year average heat input.

6. Each unit‟s share of the state‟s total three-year average heat input is multiplied by the existingunit portion of the state budget (i.e., the state budget less the state‟s new unit set-aside and, if 

applicable, the Indian Country new unit set-aside for the state) to determine that unit‟s initial 

allocation. 

7. An eight-year (2003-2010) historic emissions baseline is established for SO2, NOX, and ozoneseason NOX based on data reported to EPA or, where EPA data is unavailable, EIA data. This 

eight-year historic emissions baseline is used in order to capture the unit-level emission before 

and after the promulgation of the Clean Air Interstate Rule (CAIR) and the NOX Budget Program 

(NBP).

8. For each unit, the maximum annual historic SO2 and NOX emission amount is identified within 

the eight-year baseline. Similarly, the maximum ozoneseason NOX emission amount from the 

eight-year baseline for each unit is identified. These values are referred to as the “maximum 

historic baseline emissions” for each unit.

9. If a unit has an initial historic heat-input based allocation (as determined in step 6) that exceeds 

its maximum historic baseline emissions (as determined in step 8), then its allocation equals the 

maximum historic baseline emissions for that unit.

10. The difference (if positive) under step 9 between a unit‟s historic heat-input-based allocation and 

its “maximum historic baseline emissions” would be reapportioned on the same basis as 

described in steps 1 through 6 to units whose historic-heat-input-based allocation does not exceed 

its maximum historic baseline emissions. Steps 7, 8, and 9 are repeated with each revised 

allocation distribution until the entire existing-unit portion of the state budget would be allocated. 

The resulting allocation value is rounded to the nearest whole ton using conventional rounding. 

The table below provides an example application of the steps 1-10 in a hypothetical state.
12

Table 4 - Demonstration of Allocations Using Final Allocation 

Methodology in a Three-Unit State With a 80 Ton State Budget

Step 1-6 Step 7,8,9 Step 10

Historic Heat-inputbased Initial AllocationMaximum Historic 

Baseline Emissions

Final 

Allocation

Unit 

A 20 16 16

Unit 

B 30 50 32

Unit 

C 30 50 32

Where can I find this data?

The unit level allocations can be found in the separate file titled “Final Transport Rule Unit Level 

Allocations under the FIP” published as a PDF and an Excel file and available in the Transport Rule 

Docket and on EPA‟s website www.epa.gov/airtransport under technical information. The PDF file 

displays each unit and its final allocation under each of the trading programs The Excel file contains two 

worksheets. The first, titled “Final Allocations” is identical the PDF document. The second worksheet, 

titled “Underlying Data”, shows all the data and calculations that are numerated above. Each of the ten 

steps are color coded and displayed in sequential order moving from left to right across the worksheet. 

The formulas to derive any calculated values are explained directly beneath the column header. The final 

column in the second worksheet labeled “commenter data substitution” identifies units for which some 

commenter-provided data corrections were incorporated for the underlying heat input and emissions data. 

Rounding

EPA uses conventional rounding for its allocation purposes and applies rounding at the unit level for 

existing unit allocations. For example, if State A has a 500 ton budget with a 5% new source set-aside, 

than its existing unit allocation would be 475 tons. If there are only two covered existing units in the state 

with equal heat inputs and a historic maximum emissions above 500 tons, than the steps described above 

would result in an allocation of 237.5 tons for each unit. This unit level allocation for each of these units 

would round to 238 allowances, which would sum to 476 allowances. The difference between the sum of 

the rounded existing unit level allocations and the state budget (i.e., 500-476), would be the actual new 

source set-aside budget for the state. EPA notes that because of rounding, the actual number of 

allowances in the new source set aside will sometimes sum to a total value whose percentage of the state 

value is marginally greater or less than the percentage identified in the tables above. In other words, the 

percentage approximated for the new source set aside in the tables above may be 5% in a particular state, 

but the actual total new source set-aside allowances may equal 5.01% or 4.99% of the state budget. 

Because EPA does not issue allowances nor require compliance using fractional tons, this type of 

rounding is necessary.
13

Appendix A: Effects of Allowance Allocations on the Competition between Power Plants

Introduction 

This paper addresses a question about the potential effects of the allocation system set up by the Transport 

Rule. The question is: if the owners of a given power plant are granted a permanently larger stream of 

allowances, will that advantage lead to their plant gaining a larger share of the electricity market than 

would otherwise have occurred? The analysis presented below shows that the answer to this question is 

no. Careful consideration of the incentive effects of initial allowance allocations at the outset of a trading 

program, as well as a review of the extensive literature on this topic, will show that all generators must 

factor in the price of emitting a ton (as reflected by the allowance price) under a trading program when 

selling power no matter the original pattern of initial allocations. 

We begin with a very brief review of cap-and-trade regulations and the need for a mechanism for 

distributing the emission allowances that serve as the “trade goods” in the markets set up by these 

regulations. Then, we show why freely allocated allowances under the Transport Rule‟s programs do not 

change the economic equation of how much to generate – first in the simpler context of a deregulated 

competitive market, and then in the somewhat more complex case of a “cost-of-service” (COS) market.

Allocation of Allowances for “Cap-and-Trade” Regulations

“Cap-and-Trade” is a common term for flexible, market-based environmental regulations that aim to limit 

total emissions from an industry or region to a specified maximum (the “cap”). This approach recognizes 

that, if the environmental goal can be met by controlling the total level of emissions in a given region 

rather than emission levels at specific sources, regulated sources can realize significant cost savings by 

working out among themselves the most convenient and efficient way to reach the cap. Coordinating all 

the competing economic interests across a large set of sources, in a way that ensured that the emissions 

cap was not exceeded, would be virtually impossible without a decentralized market-based system for 

spreading around a fixed quantity of emissions. To make this market work, the total cap is divided into 

“allowances,” each of which constitutes a permit to emit one ton of the regulated substance. 

Environmental protection is ensured by the limited number of allowances, and flexibility is provided by 

the sources‟ right to transfer or trade allowances to other sources as they see fit. 

To set up this market for trading allowances, though, there must be an initial allocation of the allowances 

comprising the cap. That allocation can be made through an auction (requiring sources to compete in a 

bidding process for their initial allocation) or through free allocations directly awarded to sources. Free 

allocation procedures may determine the number of allowances received by each source in proportion to 

various metrics, including its capacity, its output, or its inputs. Furthermore, the metric could be 

something fixed (like its recorded fuel input in a particular time period), or something dynamic (like its 

fuel input in the previous year on an updating basis). The Transport Rule programs freely allocate 

allowances to existing sources in proportion to annual fuel input in a specified period not to exceed 

annual maximum emissions at each source during that specified period. This allocation pattern is fixed 

once-and-for-all (henceforth referred to as grandfathered allocation), though actual allocations can change 
14

over time (e.g., due to new unit set-asides) and still fall under the definition of “fixed” as long as they do 

not depend on the actions of the affected industry. 

The amount of freely allocated allowances does have an impact on the financial well-being of the owners

(i.e., shareholders) of the emission sources; however, as explained below, freely allocated allowances to 

sources do not have any impact on any source‟s marginal cost of producing electricity. For example, 

Williams-Derry and Drake (2008) quotes CBO testimony to show, “Giving allowances away to 

companies that supply fossil fuels or that use large quantities of fossil fuels in their production processes 

could create “windfall” profits for those firms.” 

Therefore, while the imposition of caps on sulfur dioxide and nitrogen oxides clearly provides a broad 

incentive shared across the fleet for cleaner generation, the Transport Rule‟s provision of free allowances 

to existing units (based on a fixed, or grandfathered, allocation pattern) does not affect incentives and 

competition among individual power plants. To understand why, we need to consider the economics of 

power production.

The Dispatch Problem 

At any point in time, for a given price of electricity, there will be a particular demand for electric power 

(measured in megawatts (MWs)). Many power plants will be available at that point in time, with an 

aggregate capacity that is usually well above the amount demanded. Thus, a decision needs to be made as 

to what combination of plants, contributing how much power each, will be used to meet the demand. 

This decision is termed the “dispatch problem.” It is well known that the most efficient way to solve this 

problem is to rank the plants in order of efficiency, and, choosing the most efficient one first, continue 

choosing the most efficient of those that remain, until the aggregate output of the chosen plants reaches 

the demand. Choosing the plants in this way ensures not only that the demand is met but that none of the 

plants that are not used is more efficient than any of the plants that are used. Thus, there is no way to add 

any of the unused plants into the mix without either over-producing power or displacing a more efficient 

plant. 

For a simplified description how electricity generation and dispatch works, see, for example, Palmer et al. 

(2006), which explains how the Resources for the Future (RFF) operationlizes dispatch in their Haiku 

model. Similarly, see http://www.eia.gov/oiaf/servicerpt/ceca/appd.html, which explains the same 

process as it is used in the Department of Energy‟s NEMS modeling system. Finally, EPA‟s IPM base 

case (v4.10) documentation explains how EPA conducts dispatch modeling in its policy analysis (see IPM 

documentation, Section 2.3.6).

The measure of efficiency used in solving the dispatch problem is the short-run marginal cost of 

generation, meaning the increase in variable cost of a small increment in output, per unit of additional 

output, for an existing facility. Fixed costs do not factor into this equation because they are already 

incurred over the long run and do not vary with the amount of generation selected. For example, see Shu 

et al. (2008), which argues, “...dispatch calculation does not directly consider the impact of these fixed 

costs. Dispatch involves variable and marginal costs of the power plants.” Similarly, Palmer et al. 

(2009), describe the logic behind dispatch modeling in Haiku as follows: “Operation of the electricity 

system (generator dispatch) in the model is based on the minimization of short-run variable costs of 

generation, including fuel costs, variable operating and maintenance costs and the costs of operating 
15

pollution control equipment plus the opportunity costs of using emission allowances...” (page 11-12). In 

other words, the short-run marginal cost of generation for a particular power plant will be the cost of 

buying enough additional fuel to generate an additional MWh, plus any additional maintenance costs 

necessitated by increasing output by an additional MWh, plus any costs associated with the additional 

emissions that result from generating an additional MWh. The emission-related costs are particularly 

important in the context of a cap-and-trade program, in which additional emissions must be covered by 

surrendering additional allowances. Because the allowances are tradable in a market, they have an 

explicit monetary value: if burning the fuel needed to generate another MWh releases another 2 pounds 

of NOx, and the market value of NOx allowances is $2,000 per ton, or $1/pound, then generating another 

MWh has an emission-related cost of 2 pounds x $1/pound or $2. 

Note that these emission-related costs will be the same whether the allowances were freely allocated or 

bought at auction, or whether the allowances were part of the initial allocation or have to be purchased 

from another power plant‟s owner. This independence of the origin of allowances from the cost of 

generation stems from the fact that all tradable allowances that have to be used have an opportunity cost. 

Even if an electricity generating unit (EGU) or its parent company received more allowances than it could 

use in a free allocation, the use of one more allowance means the firm has one fewer allowance to sell in 

the market. Thus, because the firm loses the opportunity of selling an unneeded allowance when it emits 

another ton of NOx, even the emission of a ton covered by a “free” allowance causes the generator to 

incur the cost of that allowance‟s market price, which the owner must forego by emitting that ton and 

using that allowance. 

The concept of the opportunity costs of allowances is explained in several studies, including Mannaerts 

and Mulder (2003), which states: “the cost of using a permit is the opportunity cost of not selling the 

permit on the permit market. This opportunity cost exists no matter whether the emitter has received the 

permits by grandfathering or by auctioning.” Also, Wrake et al. (2010) argues, “... economic theory 

indicates that retail prices will increase [when entities receive free allowances], reflecting the economic 

value of permits whether polluting entities received them for free or not, because economic costs include 

the opportunity cost of using a permit that otherwise could be sold in the permit market.” Williams-Derry 

and Drake (2008) provide a simple analogy to make this point. They argue that even if a scalper obtained 

a World Series ticket “on the ground” without having to pay for it, he will not sell that ticket for any less 

than those he had to pay for, because the “street price of World Series tickets is based on supply and 

demand,” which is the same irrespective of how the scalper obtained the tickets. Thus the value of the 

commodity is determined by its opportunity cost (or what it could be sold for in the market), not by 

whatever previous cost may have been incurred to obtain the commodity. 

Note also that the short-run marginal cost of electricity generation does not include any offset for the 

value of the allowances allocated to that power plant‟s owners, if that allocation does not change at all 

when the electricity output is increased (i.e., allocations are not updated). Again, short-run marginal cost 

is the change in total costs resulting from a change in output – so if the allocation is grandfathered before 

the program starts, it will not enter into the calculation of marginal cost, as it does not affect the variable 

costs. Certainly, the free allocation of a stream of valuable allowances does offer firms a subsidy that 

affects the overall corporate balance sheet. As Mannearts argues, “the transfer of wealth [under 

grandfathering] to the emitters can be seen as fixed subsidy, independent of future production.” But a 

fixed stream of allowances affects fixed costs (i.e., the portion that is insensitive to output), not the 
16

variable costs (the portion that changes when output is increased). In making short-run economic 

decisions, changes to the fixed costs are properly treated as “sunk costs” (or sunk benefits) and are 

ignored when making operational decisions (as the saying goes, “let bygones be bygones”).

This reasoning can be made clearer with a concrete example. The table below shows the inputs that 

might be needed to operate a plant at various levels of output. (Note that the values used for these 

illustrations are hypothetical, and do not represent any particular plant in the real world.) 

Table 1: Illustrative Resource Requirements for Generating Electricity: 

Grandfathered Allocation of 1 NOx Allowance (in tons)

Output 

(in MWh)

Fuel Use 

(in MMBtu)

Fixed O&M 

(in labor 

hours)

Variable 

O&M 

(in labor 

hours)

Emissions 

of NOx

(in pounds)

Allocated 

allowances 

(in tons)

97 970 20 10 194 1

98 980 20 10.05 196 1

99 990 20 10.1 198 1

100 1,000 20 10.15 200 1

101 1,010 20 10.2 202 1

These inputs can be translated into dollar values. Suppose fuel costs $3 per MMBtu, labor hours cost $50 

each, and NOx allowances are sold on the market for $2,000 per ton (or, equivalently, $1 per pound). 

Then, Table 1 becomes Table 2:

Table 2: Cost Components for Generating Electricity

Output 

(in MWh)

Fuel 

cost

Fixed 

O&M 

cost

Variable 

O&M 

cost

Cost of 

Emissions 

of NOx

Value of 

Allocated 

allowances 

Total Cost 

Minus Value 

of Allocation 

(Total Net 

Cost)

Change in 

Total Net 

Cost to Add 

One MWh

97 $2,910 $1,000 $500.0 $194 $2,000 $2,604.0

98 $2,940 $1,000 $502.5 $196 $2,000 $2,638.5 $34.5

99 $2,970 $1,000 $505.0 $198 $2,000 $2,673.0 $34.5

100 $3,000 $1,000 $507.5 $200 $2,000 $2,707.5 $34.5

101 $3,030 $1,000 $510.0 $202 $2,000 $2,742.0 $34.5

Note: the table above excludes fixed costs because they do not affect marginal cost calculations, but are part of the 

cost schedule faced by EGUs.
17

Note that the last column shows the change in the total cost as output is increased by one MWh – e.g., the 

last row shows the increase in cost (which we can call the „incremental‟ or „marginal‟ cost) as ($2,742-

$2,707.5), or $34.5 per additional MWh. 

Table 3 below presents the same cost structure for a utility, with the only difference that the plant is now 

awarded twice as many allowances than in the previous case. 

Table 3: Illustrative Resource Requirements for Generating Electricity: 

Grandfathered Allocation of 2 NOx Allowances (in tons)

Output 

(in 

MWh)

Fuel 

cost

Fixed 

O&M 

cost

Variable 

O&M 

cost

Cost of 

Emissions 

of NOx 

Value of 

Allocated 

allowances 

Total Cost 

Minus 

Value of 

Allocation 

(Total Net 

Cost)

Change in 

Total Net 

Cost to 

Add One 

MWh

97 $2,910 $1,000 $500.0 $194 $4,000 $604.0 

98 $2,940 $1,000 $502.5 $196 $4,000 $638.5 $34.5 

99 $2,970 $1,000 $505.0 $198 $4,000 $673.0 $34.5 

100 $3,000 $1,000 $507.5 $200 $4,000 $707.5 $34.5 

101 $3,030 $1,000 $510.0 $202 $4,000 $742.0 $34.5 

Notice that the allocation of additional allowances does not change the marginal cost (i.e., change in total 

net cost to add one MWh) at all, because the additional allowances do not depend on or change with 

output.

The foregoing exercise has clear implications for competition between power plants. If dispatch (the 

choice of which units operate to what extent) is decided using cost minimization, the provision of freelyallocated allowances to various firms does not affect competitiveness because grandfathered allowances 

do not change the marginal costs of electricity generation, which is instead affected by the market price of 

any emissions subject to the cap. Firms that get larger grandfathered allowance allocations end up with a 

subsidy to offset their costs, but that does not mean those firms run inefficient plants any more than they 

would have if they had received smaller allocations.

Effects of Allowance Allocations under Cost-of-Service Rules

As shown above, grandfathered allocations are expected to have no effect on freely competitive electricity 

markets: prices, outputs, and competition among the power plants would be driven by the marginal cost 

of emitting under the programs‟ emission caps. The value of surrendered allowances would be factored 

into the marginal cost of generation whether or not they were originally received through free allocations. 

The situation is slightly different in the case of regulated electricity markets, which make up roughly half 

of all markets in the US (see Burtraw and Palmer, 2007). In regulated markets, the electric utility acts as 

a monopolist (in that it faces no competition within its own service area), but its prices and operations are 
18

controlled or overseen by an authority (e.g., a Public Utilities Commission or PUC) to ensure that it 

serves its customers‟ needs and does not profit unduly. Electricity prices in these markets are set not at 

the marginal costs of generating and supplying power but at the average costs, including a reasonable 

return on invested capital. An important contrast with the competitive case is that, though changes in 

grandfathered allocations have no effect on marginal costs, they do change the average costs, because the 

value of the allocated allowances offsets other long-run costs for the utilities. To put this in another way, 

in a regulated market, if allowances are allocated for free, they are not included in the PUC‟s rate base 

calculations, since the utility “will not have spent anything to acquire its permit holdings” (Hahn and 

Stavins, 2010). 

Higher allocations, then, lower a utility‟s average costs, and lower average costs translate into lower 

electricity prices in cost-of-service regulated markets. Lower prices, in turn, lead to a higher quantity of 

electricity demanded. Thus, other things being equal, giving a utility a higher allocation can be expected 

to result in it producing more electricity. 

But this fact does not imply that changes in grandfathered allocations to various units changes the 

competitive balance among those units. First, though a regulated utility as a whole may see a small 

increase in its output if it is given a larger allocation vis-à-vis another regulated utility, the choice within 

that utility of which units to dispatch will still be made on the basis of marginal costs, not average costs. 

For example, Massey et al. (2006), argue, “For years, utility system operators have used an integrated 

least cost dispatch model that matches generation and load in real time... The utility system operator, in a 

purely cost-of-service world, dispatches the mix of generation units necessary to achieve both reliability 

and least cost” (page 346). 

So as described above, retail electricity pricing in a cost-of-service market is determined by regulators on 

the basis of average cost, which can be affected by freely allocated allowances to that market‟s regulated 

utility. However, this impact only affects how much money consumers are required (through the rate 

base) to pay to the utility for electricity generation overall; in other words, the freely allocated allowances 

act as a subsidy to consumers, which is why electricity demand for that particular utility may rise. 

Whatever the electricity demand to be met, the regulated utility still makes the dispatch decision on the 

basis of marginal costs among the units in its fleet, which is not affected by the amount of allowances that 

any particular unit in that fleet was initially allocated.

Thus, within a monopolistic regulated utility in a cost-of-service market, a unit whose characteristics 

resulted in a large allocation for its utility would not be advantaged in producing more output, under a 

grandfathered allocation. The relative outputs of two different regulated utilities, where one is given a 

large allocation and the other is given a small allocation, will be expected to change. Electricity prices in 

the former utility‟s service area will fall relative to prices in the latter‟s, and this change in relative prices 

will lead to small changes in relative output as different consumer bases receive a different degree of 

subsidization through freely allocated allowances to the regulated utilities in their respective cost-ofservice territories. But because regulated utilities in two separate cost-of-service areas are not 

competitors, it cannot be said that one has a competitive advantage over the other. 
19

References:

Alpha-Gamma Technologies, Inc. Market Mechanisms and Incentives: Applications to Environmental Policy. A 

Workshop Proceeding, Session Four, US-EPA, Center for Environmental Economics, and National Center 

for Environmental Research. Washington, D.C. May 2003.

Burtraw, Dallas and Karen Palmer. Compensation Rules for Climate Policy in the Electricity Sector. RFF 

Discussion paper DP 07-41. Resources for the Future. July 2007. 

Hahn, Robert and Robert Stavins. The Effect of Allowance Allocations on Cap-and-Trade System Performance. 

RFF Discussion paper DP 10-21. Resources for the Future. March 2010.

Mannaerts, Hein and Machiel Mulder. Emissions Trading and the European Electricity Market. CPB Netherlands‟ 

Bureau for Policy Analysis. January 2003.

Massey, William, Robert Fleishman, and Mary Doyle. Reliability-Based Competition in Wholesale Electricity: 

Legal and Policy Perspectives. Energy Law Journal. Volume 25:319. 2006.

Montgomery, D.W. “Markets in Licenses and Efficient Pollution Control Programs.” Journal of Economic Theory. 

5,395. 1972.

Neuhoff, Karsten, Kim Martinez, and Misato Sato. Allocation, Incentives, and Distortions: The Impact of ETS 

Emissions Allowance Allocations to the Electric Sector. Climate Policy. 6, 73-91. 2006

Palmer, Karen, Dallas Burtraw, and Danny Kahn. Simple Rules for Targeting CO2 Allowance Allocations to 

Compensate Firms. Discussion paper 06-28. Resources for the Future. June 2006.

Palmer, Karen, Dallas Burtraw and Anthony Paul. Allowance Allocation in a CO2 Emissions Cap-and-Trade 

Program for the Electricity Sector in California. RFF Discussion paper 09-41. Resources for the Future. 

October 2009. 

Schulkin, J., Benjamin Hobbs, and Jong-Shi Pang. Long-Run Equilibrium Modeling of Alternative Emissions 

Allowance Allocation Systems in Electric Power Markets. Electricity Policy. Cambridge Working Papers 

in Economics. September 2007.

Schwyzer, Diana. The Potential of Wind Power and Energy Storage in California. Energy and Resources Group. 

University of California, Berkeley. 2006(?).

Shu, Gary, Mort Webster, and Howard Herzog. Scenario Analysis of Carbon Capture and Sequestration Generation 

Dispatch in the Western U.S. Electricity System. Energy Procedia. 2008.

US EPA/OAR. Economic Analysis of Alternate Methods of Allocating NOx Emission Allowances. Prepared by 

ICF Consulting. October 1999.

Wals, Adrian and Fieke Rijkers. How will a CO2 Price Effect the Playing Field in the Northwest European Power 

Sector? Research Symposium European Electricity Market. September 2003.

Williams-Derry, Clark and Eric de Place. Why Free Allocation of Carbon Allowances Means Windfall Profits for 

Energy Companies at the Expense of Consumers. Sightline Institute. February 2008.

Wråke, Markus, Erica Myers, Svante Mandell, Charles Holt, and Dallas Burtraw. Opportunity Cost for Free 

Allocations of Emissions Permits: An Experimental Analysis. Environmental and Resource Economics. 

Vol. 46, No. 3. 331-336.