Technical Support Document (TSD) for the Final Revisions to the Transport Rule

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

Final Revisions Rule State Budgets and 

New Unit Set-Asides TSD

U.S Environmental Protection Agency

Office of Air and Radiation

February 2012
2

EPA finalized the Transport Rule in July of 2011.

1

 EPA is now finalizing revisions to certain states’ emission budgets under the Transport Rule as 

well as revisions to certain new unit set-asides (NUSAs) under the Transport Rule programs. This technical support document shows the underlying data 

and calculations used to quantify the state budget revisions and new unit set-aside revisions made in the final revisions rule2

, as well as those revisions 

included in the direct final revisions rule.3

 Section A below summarizes the net impact of the revisions in each rule on each affected state budget and 

NUSA. Section B below provides a description of each revision and accompanying tables demonstrating the data and calculations associated with each 

revision as relevant to the final revisions rule; Section C below makes the same demonstration for each revision relevant to the direct final revisions rule. 

Each revision to a state budget also entails corresponding revisions to the absolute number of allowances put into the relevant new unit set-aside4 as well as 

to the absolute assurance level5

Section A: Summary of Revisions to States’ Emission Budgets and NUSAs.

for the relevant pollutant in that state, as NUSAs and assurance levels are both calculated by applying percentage values to 

the relevant state budget (using the methodologies described in the final Transport Rule).

The final revisions rule affects state emission budgets and/or NUSAs for Arkansas, Florida, Louisiana, Michigan, Mississippi, Nebraska, New 

Jersey, New York, Texas and Wisconsin. The direct final revisions rule affects state emissions budgets and/or NUSAs for South Carolina, Nebraska, 

Indiana, Ohio, New York, Kansas, Georgia, Arkansas, Louisiana, Missouri, Mississippi, Texas, Kansas and Oklahoma. These revisions to certain input 

assumptions at the unit level maintain a consistent application of the methodology described in the final Transport Rule to quantify and eliminate emissions 

that significantly contribute to nonattainment and interfere with maintenance of the NAAQS assessed in that rulemaking. The revisions to the Transport 

Rule state budgets and NUSAs are summarized in Tables A.1. and A.2. below.

 1

 Federal Implementation Plans: Interstate Transport of Fine Particulate Matter and Ozone and Correction of SIP Approvals (76 FR 48208). 2

 See preamble to the “Revisions to Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone” 3

 See preamble to the “Revisions to Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone: Part II” 4 The “Total NUSAs” presented for each state in sections B and C of this document include allowances under both the State NUSA and the Indian Country NUSA (where 

the latter exists in the given state).

5 EPA has also proposed in this action to amend the effective date of the assurance provisions in all states to start in 2014 instead of in 2012.
3

Table A.1.: Final Rule Revisions to Transport Rule State Budgets and NUSAs

2012 – 2013 State Budgets 2014 and beyond State Budgets NUSA*

SO2

Annual 

NOX

Ozone 

Season NOX SO2

Annual 

NOX

Ozone 

Season NOX SO2 Annual NOX

Ozone Season 

NOX

Michigan 5,228 5,228 2%

Nebraska 3,599 3,599 6%

Texas 50,517 1,375 1,375 50,517 1,375 1,375 5% 4% 4%

Florida 819 2%

Arkansas 5%

Wisconsin 2,473 7,757 2,473 4% 6%

New York 3,527 3,485 1,911 3,527 3,485 1,911 2% 2% 2%

New Jersey 2,096 952 746 679 349 2% 2% 2%

Louisiana 4,594 4,594 3%

Mississippi 2,154 2,154 2%

* Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations
4

Table A.2.:Direct Final Rule Revisions to Transport Rule State Budgets and NUSAs

2012 – 2013 State Budgets 2014 and beyond State Budgets NUSA*

SO2

Annual 

NOX

Ozone 

Season NOX SO2

Annual 

NOX

Ozone 

Season NOX SO2 Annual NOX

Ozone 

Season NOX

South Carolina 8,013 8,013 0 2% 2% 2%

Nebraska 3,110 3,110 4% 6%

Indiana 5,338 5,338 0 3% 3% 3%

Ohio 5,163 2,765 1,221 5,163 2,765 1,221 2% 2% 2%

New York 5,444 694 127 5,444 694 127 2% 2% 2%

Kansas 452 640 452 5,794 2% 2%

Georgia 40,334 13,198 5,762 2% 2% 2%

Arkansas1 73 73 8%

Louisiana 89 89 2%

Missouri2 26 26 26 26 3% 6% 6%

Mississippi 115 115 2%

Texas 2,731 1,142 2,731 1,142 5% 4% 4%

Oklahoma3 859 859 2%

1 This NUSA level for Arkansas takes effect for the 2014 control period and beyond.

2 These NUSA levels for Missouri take effect for the 2013 control period and beyond.

3 Revision applies in 2013 and beyond.

Section B: Technical Revisions to States’ Transport Rule (TR) Emission Budgets and NUSAs Relevant to Final Revisions Rule.

1)

EPA is finalizing an increase to Michigan’s 2012 and 2014 annual NOX budgets as proposed to correct for the assumption that Selective Catalytic 

Reduction (SCR) technology is currently installed at Monroe Unit 2. This SCR is planned for future installation but is not expected to be operating by 2012 

Michigan
5

or by 2014. Therefore, EPA is revising the state’s 2012 and 2014 annual NOX emission budgets

6

Table B.1.a.: Calculation to Determine Michigan Annual NOX Budget Revision - Assuming no SCR at Monroe Unit 2

to reflect projected emissions without this unit operating an

SCR. This results in a 5,228 ton increase to the state’s annual NOX budgets in 2012 and 2014. EPA also recognizes that this revised input assumption is 

relevant to the calculation of the state’s ozone-season NOX budget; EPA already included this revised assumption in its quantification of that budget when 

the Agency issued the Transport Rule Supplemental Notice of Final Rulemaking (SNFR) (76 FR 87060).

A B C D E F

Plant Unit

Emissions from 

TR_Remedy 

Final_2012 (1000 

tons)

Heat Input from 

TR_Remedy_Final_2012 

(TBtu)

Remedy Emission Rate 

from 

TR_Remedy_Final_2012 

(lbs/MMBtu)

Revised 

Emission 

Rate 

(lbs/MMBtu)

Revised 

Emissions

Net Budget 

Revision 

(1000 tons)

Calculation A*2/B D x B/2 E - A

Monroe 2 1.540 44.437 0.0693 0.3046 6.768 5.228

Columns A, B, and C show the NOX emissions, heat input, and emission rate from the TR_Remedy_Final_2012 modeling when an SCR is assumed 

to be present at Monroe Unit 2. Because no SCR is present, EPA modified the emission rate to reflect the “controlled NOX policy rate” in the NEEDS 

version from the September 1, 2010 TR Notice of Data Availability (NODA) (column D).

7

This budget change will not result in any impact to the percent of the budget set aside for new units. Under the methodology in the final Transport 

Rule, the NUSA for annual NOX in Michigan remains at 2%. The original and revised values for the state annual NOX budget, assurance level, and new unit 

set-aside are described in the table below.

 This value reflects the NOX emission rate assumed in EPA’s 

modeling of the Transport Rule as originally proposed, when EPA did not assume an SCR to be present at the unit. This value approximates the emission 

rate expected at the unit at a cost threshold of $500/ton when no SCR is present at the unit. EPA multiplied this NOX rate by the remedy heat input shown in 

column B to obtain a revised emissions projection for the unit (column E). The difference between this revised emission projection (no SCR assumed) and 

the final Transport Rule remedy analysis emission projection (SCR assumed) determines the amount of the increase to the state’s annual NOX budget 

(column F).

 6 Throughout this TSD and throughout the preamble to this proposal, EPA refers to a state budget for 2012 and 2013 as a “2012”state budget and refers to a state budget for 

2014 and thereafter as a “2014” state budget. Therefore, any revision of a 2012 state budget would apply to the state budget for 2012 and 2013, and any revision of a 2014 

state budget would apply to the state budget for 2014 and thereafter.

7 See National Electric Energy Data System (NEEDS) v4.10 available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html
6

Table B.1.b.: Impact of Michigan Annual NOX Budget Revision - Assuming no SCR at 

Monroe Unit 2 (tons)

Annual NOX

Budget

Assurance Level Total New Unit Set-Aside *

% of Budget Tons % of Budget Tons

2012 Initial 60,193 118% 71,028 2% 1,204

2012 Revised 65,421 - - 2% 1,308

2014 Initial 57,812 118% 68,218 2% 1,156

2014 Revised 63,040 118% 74,387 2% 1,261

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations

2)

EPA is finalizing, as proposed, an increase to Nebraska’s 2012 and 2014 annual NOX budgets to correct for the assumption that SCR technology is 

currently installed at Nebraska City Unit 1. There is no SCR existing, planned, or under construction at the unit. There will likely be no SCR available at 

the time of the 2012 and 2014 compliance periods as originally assumed in EPA’s determination of Nebraska’s annual NOX budgets. Therefore, EPA is 

revising the state’s 2012 and 2014 annual NOX emission budgets to reflect this unit operating without an SCR. This results in a 3,599 ton increase to the 

state’s 2012 and 2014 annual NOX budgets. The calculations to quantify this revision are shown in the table below.

Nebraska

Table B.2.a.: Calculation to Determine Nebraska Annual NOX Budget Revision – Assuming no SCR at Nebraska City Unit 1

A B C D E F

Plant Unit

Emissions 

from 

TR_Remedy 

Final_2012 

(1000 tons)

Heat Input from 

TR_Remedy_Final_2012 

(TBtu)

Remedy Emission Rate 

from 

TR_Remedy_Final_2012 

(lbs/MMBtu)

Revised 

Emission 

Rate 

(lbs/MMBtu)

Revised 

Emissions 

(1000 

tons)

Net 

Budget 

Revision 

(1000 

tons)

Calculation A*2/B D x B/2 E - A

Nebraska City 1 1.602 45.765208 0.070 0.2273 5.201 3.599
7

Columns A, B, and C show the NOX emissions, heat input, and emission rate from the TR_Remedy_Final_2012 modeling when an SCR is assumed 

to be present. Because no SCR is present, EPA modified the emission rate to reflect the “controlled NOX policy rate” in the NEEDS version from the 

September 1, 2010 TR Notice of Data Availability (NODA) (column D).8

The change to the annual NOX emission budget in Nebraska will result in a small change to the state’s new unit set-aside percentage for annual NOX. 

The reason for the change is that under the methodology established in the final Transport Rule, the state-specific portion of the NUSA is calculated as the

percentage equal to the projected emissions from “planned units” divided by the 2014 state budget for the relevant pollutant. In the case of Nebraska, the 

projected emissions from planned units remain unchanged, but the budget is increasing. Because the numerator remains unchanged but the denominator is 

increasing, the total new unit set-aside percentage decreases. That is, a smaller percentage of the state emission budget is needed to cover emissions from 

“planned” new units, because the budget is larger. For Nebraska, the budget revision would decrease the NUSA percentage for annual NOX from 7% to 6% 

as a result. This is applying the same NUSA methodology that is used for every state in the final Transport Rule, and the change in percentage is simply an 

outgrowth of the state’s budget revision. This change in the NUSA percentage yields only a marginal change in the absolute number of allowances in the 

Nebraska NUSA. The original and revised values for the state annual NOX budget, assurance level, and new unit set-aside are described in the table below.

 This value reflects the NOX emission rate assumed in EPA’s modeling of the 

Transport Rule as originally proposed, when EPA did not assume an SCR to be present at the unit. This value approximates the emission rate expected at 

the unit at a cost threshold of $500/ton when no SCR is present at the unit. This NOX rate was multiplied by the final remedy heat input shown in column B

to obtain a revised emissions value for the unit (column E). The difference between this revised emission projection (no SCR assumed, column E) and the 

remedy emission projection (SCR assumed, column A) determines the amount of the increase to the state’s annual NOX budget (column F).

Table B.2.b.: Impact of Nebraska Annual NOX Budget Revision – Assuming no SCR at 

Nebraska City Unit 1 (tons)

Annual NOX 

Budget

Assurance Level Total New Unit Set-Aside *

% of Budget Tons % of Budget Tons

2012 Initial 26,440 118% 31,199 7% 1,851

2012 Revised 30,039 - - 6% 1,802

2014 Initial 26,440 118% 31,199 7% 1,851

2014 Revised 30,039 118% 35,446 6% 1,802

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations

 8 See National Electric Energy Data System (NEEDS) v4.10 available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html
8

3)

EPA is finalizing, as proposed, an increase Texas’s 2012 and 2014 SO2 budgets to correct for the assumption that Flue Gas Desulfurization (FGD)

technology will be installed by 2012 for W.A. Parish Unit 6, J.T. Deely Unit 1, and J.T. Deely Unit 2. Although the facility owners had previously

announced plans to install FGD technology at these facilities, those plans have since been modified. 

Texas (Removed FGDs)

9 10

Table B.3.: Calculation to Determine Texas SO2 Budget Revision – Assuming no FGD at J.T. Deely or W A Parish unit 6

 There will likely be no FGD available at these units 

during the 2012 and 2014 compliance periods under the Transport Rule programs. Therefore, EPA is revising the state’s 2012 and 2014 SO2 emission 

budgets to reflect these units operating without an FGD. This results in a 26,359 ton increase to the state’s 2012 and 2014 SO2 budgets. The calculations to 

quantify this revision are shown in the table below.

A B C D E F

Plant Unit

Emissions 

from 

TR_Remedy 

Final_2012 

(1000 tons)

Heat Input from 

TR_Remedy_Final_2012 

(TBtu)

Remedy Emission Rate 

from 

TR_Remedy_Final_2012 

(lbs/MMBtu)

Revised 

Emission Rate

(lbs/MMBtu)

Revised 

Emissions 

(1000 tons)

Net Budget 

Revision 

(1000 tons)

Calculation A*2/B D x B/2 E - A

J T Deely 1 0.917 30.55183083 0.060 0.5800 8.860 7.943

J T Deely 2 0.914 30.46546708 0.060 0.5800 8.835 7.921

W A Parish 6 1.211 40.3658592 0.060 0.5800 11.706 10.495

Total 26.359

Columns A, B, and C show the SO2 emissions, heat input, and emission rate from the TR_Remedy_Final_2012 modeling when an FGD is assumed 

to be present at these three units. Because no FGD is present, EPA is recalculating projected emissions at these units using the emission rates shown for 

these units in EPA’s analysis of the base case for the final Transport Rule, as found in the TR_Base_Case_Final for 2012 (column D). These SO2 emission 

rates reflect generation at these units without the operation of the assumed FGDs, which did not operate in the final Transport Rule base case because they 

were modeled as “dispatchable” controls that were not found to be economic to operate in that scenario.

11

 9 “Corporate Sustainability Report”, CPS Energy, 2010. P.57. Retrieved from http://www.cpsenergy.com/files/Sustainability_Report.pdf

 The revised SO2 emission rate in column D is

multiplied by the final remedy heat input shown in column B to obtain a revised emissions projection for the unit (column E). The difference between this 

10 Business Wire, (2006). NRG Announces Comprehensive Repowering Initiative [ Press release]. Retrieved from http://phx.corporateir.net/phoenix.zhtml?c=121544&p=irol-newsArticle_Print&ID=874575&highlight 11 See "WebReady_ParsedFile_TR_Base_Case_Final_2012" in the Transport Rule docket or on EPA's CSAPR website
9

revised emission projection (no FGD assumed, column E) and the remedy emission projection (FGD assumed, column A) determines the amount of the 

increase to the state’s SO2 budget (column F).

The impacts of all revisions to the Texas state budgets on the state’s NUSAs and assurance levels are shown in Table B.13.e.

4)

EPA is also finalizing an increase to the Texas 2012 and 2014 SO2 budgets to correct for the assumption that the existing FGD technology currently 

installed at five facilities in Texas (Monticello, Martin Lake, Sandow, Oklaunion, and W A Parish) is capable of treating 100% of the flue gas at those units. 

Although EPA originally assumed removal rates at those units that the facility operators have previously reported, those facility operators have clarified to 

EPA that those reported removal rates only applied to the flue gas treated at the unit. Because of design limitations, these facilities may be substantially 

limited in the amount of flue gas that can be passed through the existing FGD. These facilities report less than 100% pass-through of flue gas on their most 

recent Energy Information Administration (EIA) 860 form.

Texas (FGD Capture)

12 Consequently, at these facilities, the effective removal rate of the FGD as applied to total SO2

emissions at the affected units would be lower than the reported removal rate would otherwise indicate. As explained in the final revisions rule preamble, 

EPA is finalizing this revision based on the SO2 removal efficiency and flue gas treatment data most recently reported for these scrubbers by the facility 

operators to the EIA on form 860. The approach results in a final SO2 budget increase of 24,158 tons.

13 

 12 Unless otherwise indicated, EPA used data from EIA form 860 as submitted for the year 2008 to calculate the revisions presented in this document, as this is the same 

year for which EPA used EIA form 860 data to inform pollution control removal efficiencies at all units in the Transport Rule power sector modeling. 13 EPA originally proposed a related budget increase of 43,708 tons, based on the same calculations presented here but using data reported for 2008 on EIA form 923.
10

Table B.4.: Calculation to Determine Texas SO2 Budget Revision - Assuming Design SO2 Removal Rates at FGD and Percent 

Flue Gas Entering FGD

A B C D E F G

Total SO2

Emissions from 

2012 

TR_Remedy_Final 

(1000 tons)

EIA 860 

Removal Rate 

(used in 

budget 

determination)

EIA 860 

Percent of 

Flue Gas 

Entering FGD

Calculated 

Removal 

Rate (used 

for budget 

revision 

estimate)

Uncontrolled 

Emissions 

(assuming no 

FGD)(1000 

tons)

Revised 

Emissions 

(assuming 

FGD with 

revised 

removal rate) 

(1000 tons)

Net 

Budget 

Revision

(1000 

tons)

B*C A/(1-B) E*(1-D) F-A

Martin Lake 1 1.862841 0.95 0.95 0.903 37.2568208 3.63254 1.7696989

Martin Lake 2 1.8540181 0.95 0.95 0.903 37.0803634 3.6153354 1.7613172

Martin Lake 3 1.745038 0.95 0.95 0.903 34.9007605 3.4028241 1.6577861

Monticello 3 2.548471 0.95 0.75 0.713 50.96942 14.6537082 12.105237

Oklaunion 1 2.2321097 0.868 0.81 0.703 16.9099223 5.0208941 2.7887843

Sandow 4 1.2522935 0.92 0.83 0.764 15.6536693 3.7005274 2.4482338

W A Parish 8 1.5948385 0.85 0.82 0.697 10.6322566 3.2215737 1.6267352

Total 13.090 6.438 6.060 5.586 203.403 37.247 24.158

Column A shows the projected emissions at these units as originally modeled in the final Transport Rule remedy for 2012. Column B shows the SO2

removal rate that those 2012 emission projections are based on. Column C shows the source reported percent of flue gas entering FGD. Column D shows 

the emission rate based on multiplying the removal rate by the percent of flue gas entering FGD. Column E shows a calculation of projected emissions at 

each unit if the previously assumed FGD removal hadn’t occurred at all; these “uncontrolled emissions” are calculated in order to allow application of the 

revised FGD removal rate shown in column D to these uncontrolled emissions, which yields the revised emission projection for each unit in column F. The 

difference between this revised emission projection (lower FGD capture assumed, column F) and the remedy emission projection (higher FGD capture 

assumed, column A) determines the amount of the increase to the state’s SO2 budget (column G). The impacts of all revisions to Texas state budgets on the 

state’s NUSAs and assurance levels are shown in Tables B.13.d and B.13.e.
11

5) Florida

EPA is finalizing, as proposed, a revision to Florida’s 2012 ozone-season NOX budget to correct for the assumption that Crystal River Unit 3, a

nuclear unit with no NOX emissions, will be available for dispatch in 2012. This unit is not expected to operate in 2012 as it is undergoing an extended 

outage for repair work. EPA is finalizing an increase to the state’s 2012 ozone season NOX budget by 819 tons to reflect projected emissions from increased

dispatch of fossil-fuel-fired capacity needed to substitute for the generation that EPA originally projected to come from Crystal River Unit 3. The 

calculations to quantify this revision are shown in the table below.

Table B.5.a.: Calculation to Determine Florida Ozone-Season NOX Budget Revisions to Offset Crystal River 3 Outage

A B C D

Plant Name

Unit 

ID

Ozone-Season 

Generation from 

TR_Remedy_Final_2012 

(GWh)

Average Heat 

Rate of 

Replacement 

Generation 

(BTU/kWh)

Average Ozone-Season 

NOX Emission Rate of 

Replacement 

Generation 

(lbs/MMBTU)

Ozone-Season NOX

Emissions from 

Replacement 

Generation (tons)

Calculation A*B*C/2000

Crystal River 3 2,976 8,340 0.066 819

Column A shows the ozone-season generation projected from the Crystal River Unit 3 under the final Transport Rule 2012 remedy modeling. 

Columns B and C show the capacity-weighted average heat rate and ozone-season NOX emission rate from combined cycle natural gas units in Florida that 

EPA assumes would be likely to increase their dispatch to replace the generation that would otherwise be available from Crystal River Unit 3.

14

The change to the ozone-season NOX budget for Florida does not impact the percentage of the budget set aside for new units in Florida, which 

remains at 2%. The original and revised values for the state ozone-season NOX budget, assurance level, and new unit set-aside are described in the table

below. 

 To 

characterize the emissions of this replacement generation, EPA selected combined cycle units that reported higher utilization in 2010 (when Crystal River 

Unit 3 was also out of service for repair) compared to their projected utilization under the final Transport Rule 2012 remedy modeling (that assumed Crystal 

River Unit 3 would operate). Because the originally projected operation of Crystal River Unit 3 did not include any NOX emissions covered by the Transport 

Rule, the emissions from likely replacement generation calculated in column D determine the amount of the increase to the state’s 2012 ozone-season NOX

budget.

 14 These capacity-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission 

rate averages used in Final Revisions Rule” found in the docket for this rulemaking.
12

Table B.5.b.: Impact of Florida Ozone-Season NOX Budget Revision – Assuming Crystal 

River Unit 3 Outage (tons)

OzoneSeason 

NOX

Budget

Assurance Level 

Total Ozone Season NOX

New Unit Set-Aside*

% of Budget Tons % of Budget Tons

2012 Initial 27,825 121% 33,668 2% 557

2012 Revised 28,644 - - 2% 573

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations

6) Arkansas

Plum Point Unit 1 in Arkansas commenced commercial operation on or after January 1, 2010. Such a date qualifies Plum Point Unit 1 as a 

“planned” new unit by the definition of that category described in the “Allowance Allocation Final Rule TSD” for the Transport Rule. However, in the final 

Transport Rule, EPA did not recognize Plum Point Unit 1as a new unit and therefore omitted its projected emissions in the determination of the ozoneseason NOX new unit set-aside for Arkansas. Because there were no other units identified as “planned” new units in Arkansas, that state’s NUSA was set at 

the minimum value of 2%.15 EPA is finalizing, as proposed, a revision to the calculation of the Arkansas ozone-season NOX new unit set-aside to reflect the 

“new unit” status of Plum Point Unit 1. The calculations to quantify this revision are shown in the table below.

Table B.6.a.: Calculation for Arkansas's NUSA 

A Projected 2020 Ozone-Season NOX Emissions from Plum Point (tons) 478

B Arkansas Ozone Season NOX State Budget (tons) 15,037

C Plum Point's Emissions as a % of Arkansas State Budget (A/B) 3%

D Base percentage for new unit set-aside 2%

E Total New Unit Set-Aside (C + D) 5%

 15 As explained in the final Transport Rule, the minimum size of any state’s new unit set-aside is this “base percentage” amount, to which “state-specific” percentages are 

added if the given state has projected emissions from “planned” new units (76 FR 48291).
13

Because Plum Point was the only “planned” new unit for the state of Arkansas, EPA divided its projected emissions into the state budget to derive 

the state-specific percentage for the new unit set-aside in Arkansas, which rounds to 3%. This value was added to the base percentage for new unit set-aside 

(2%). The resulting new unit set-aside percentage for ozone season NOX in Arkansas is 5%. This change does not impact the state budget or assurance level 

in any way. However, the new unit set-aside changes by the levels shown below.16

Table B.6.b.: Impact of Ozone Season NOX NUSA revision for Arkansas

Initial % Updated% Initial tons Revised tons*

New Unit Set-Aside 2% 5% 301 752

Existing Unit Allocation 98% 95% 14,736 14,285

Total 100% 100% 15,037 15,037

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit 

allocations

7)

The Oak Grove Unit 2 in Texas commenced commercial operation on or after January 1, 2010. Such a date qualifies Oak Grove Unit 2 as a 

“planned” new unit by the definition of that category described in the “Allowance Allocation Final Rule TSD”. However, in the final Transport Rule, EPA 

did not recognize Oak Grove Unit 2 as a new unit and therefore omitted its projected emissions in the determination of the new unit set-asides for Texas, 

which EPA then calculated to be set at 5%, 3%, and 3% for SO2, annual NOX, and ozone-season NOX, respectively. EPA is finalizing, as proposed, a 

revision to the Texas new unit set-asides to reflect the “new unit” status of Oak Grove Unit 2. The calculations to quantify these revisions are shown in the 

table below. 

Texas (NUSA)

 16 The increase to the new unit set-aside would necessarily change existing unit allowance allocations in order to maintain the state budget. To review the existing unit 

allowance allocations associated with this revision, please see the document entitled “Final Revisions Rule Unit-Level Allocations under the FIPs” found in the docket to 

this rulemaking.
14

Table B.7.: Calculation for Texas's NUSAs

SO2 NOX

Ozone 

Season NOX

A Projected 2020 Emissions from planned new fossil (tons)* 9,855 2,727 1,216

B TX State Budget (tons) 294,471 134,970 64,418

C Planned new unit emissions as a % of Texas's State Budget (A/B) 3% 2% 2%

D Base percentage for new unit set-aside 2% 2% 2%

E Total New Unit Set-Aside (C+D) 5% 4% 4%

*Revised to include emissions from Oak Grove Unit 2

The impact of all revisions to Texas state budgets (and these revisions to the NUSAs) on the state’s NUSAs and assurance levels are shown in 

Tables B.13.e.

8)

EPA is finalizing, as proposed, a revision to Wisconsin’s 2014 SO2 budget to correct for the assumption that FGD technology will be installed by 

2014 for Weston Unit 3. In the final Transport Rule analysis, this unit was not modeled to build an FGD purely in response to the $2,300 per ton threshold 

informing Wisconsin’s 2014 state SO2 budget; instead, its FGD was added as an input assumption in the base case related to information suggesting that this 

control was already scheduled for installation. However, Wisconsin Department of Natural Resources (WDNR) has informed EPA that this assumption was 

erroneous. Therefore, EPA is finalizing, as proposed, a revision to the state’s SO2 emission budget for 2014 to reflect this unit operating without an FGD. 

This results in a 5,605 ton increase to the state’s 2014 SO2 budget. This unit was not originally assumed to have an FGD by 2012, so EPA is not finalizing 

any revision related to this unit for the state’s 2012 SO2 budget. The calculations to quantify this revision are shown in the table below. 

Wisconsin

Table B.8.a.: Calculation to Determine Wisconsin's SO2 Budget Revision – Assuming 

no FGD at Weston Unit 3 in 2014 (1000 tons)

A B C

Plant Name Unit ID

Emissions 

from 

TR_Remedy 

Final_2014 

Emissions 

from 

TR_Remedy

Final_2012 Net Budget Revision

Calculation B-A

Weston 3 0.647 6.252 5.605
15

Columns A and B show Weston’s Unit 3 SO2 remedy case emissions in 2014 and 2012, respectively. In its modeling of the final Transport Rule 

remedy, EPA projected the same total heat input for Weston Unit 3 in both years. However, the total projected emissions are lower in 2014 because the 

FGD was assumed to be operating in that year. Because the projected heat input is constant at this unit between these years, EPA has calculated the 

difference between the projected emissions at this unit in 2012 (no FGD assumed, column B) and in 2014 (FGD assumed, column A) to determine the 

amount of the increase to Wisconsin’s 2014 SO2 budget related to this unit, shown in column C.

EPA is also finalizing, as proposed, a revision to Wisconsin’s 2014 SO2 budget related to scrubbers being installed at Columbia units 1 and 2. In the 

final Transport Rule analysis, EPA assumed these installations would be wet scrubbers; however, the Wisconsin Department of Natural Resources (WDNR)

has informed EPA that they have been planned and approved as dry scrubbers instead. In its analysis of the final Transport Rule, EPA assumed SO2 removal 

rates of 96% for new wet scrubbers and 92% for new dry scrubbers. Therefore, the projected emissions from these units reflected a higher SO2 removal rate 

(and consequently lower emissions) than these units would be assumed to achieve with dry scrubber technology. In accordance with this revision, EPA is 

finalizing, as proposed, a 2,152 ton increase to the Wisconsin 2014 SO2 emission budget. These units were not originally assumed to have FGD by 2012, so 

EPA is not finalizing any revision related to these units for the state’s 2012 SO2 budget.

Table B.8.b.: Calculation to Determine Wisconsin SO2Budget Revision - Assuming Dry FGD at 

Columbia in 2014 (1000 tons)

A B C D

Plant Name Unit ID

Emissions from 

TR_Remedy 

Final_2014 

(assuming 96% 

removal)

Uncontrolled 

Emissions 

(assuming no 

FGD)

Revised 

Emissions 

(assuming 

92% removal)

Net Budget

Revision

Calculation A/(1-0.96) B *(1-0.92) C-A

Columbia 1 1.089 27.231 2.179 1.09

Columbia 2 1.063 26.572 2.126 1.063

Total 2.152 53.804 4.304 2.152*

*Total reflects rounding of calculation performed for both units together

Column A shows the Columbia units’ projected emissions assuming 96% removal characteristic of a new wet scrubber. Column B shows a 

calculation of projected emissions at each unit if the previously assumed FGD removal hadn’t occurred at all; these “uncontrolled emissions” are calculated 

in order to allow application of the revised FGD removal rate of 92% to these uncontrolled emissions, which yields the revised emission projection for each 
16

unit in column C. The difference between this revised emission projection (dry scrubbers assumed, column C) and the remedy emission projection (wet 

scrubbers assumed, column A) determines the amount of the increase to the state’s 2014 SO2 budget (column D).

EPA is also finalizing, as proposed, a revision to Wisconsin’s annual NOX budget for 2012 and 2014 to correct for the assumption that an SCR will 

be in place at John P. Madgett Unit 1 in 2012 and 2014. There are currently no plans to have an SCR in place by 2014 at the unit. Therefore, EPA is 

revising the state’s 2012 and 2014 annual NOX budgets by 2,473 tons to reflect the operation of the unit without an SCR. The calculations to quantify this

revision are shown in the table below. EPA also recognizes that this revised input assumption is relevant to the calculation of the state’s ozone-season NOX

budget; EPA already included this revised assumption in its quantification of that budget when the Agency issued the Transport Rule SNFR (76 FR 87060).

Table B.8.c.: Calculation to Determine Wisconsin Annual NOX Budget Revision - Assuming no SCR at J P Madgett 

A B C D E F

Plant Name

Unit 

ID

Emissions 

from 

TR_Remedy

Final_2012 

(1000 tons)

Heat Input from 

TR_Remedy_Final_2012 

(TBtu)

Remedy Emission Rate 

fromTR_Remedy_Final_2012 

(lbs/MMBtu)

Revised 

Emission 

Rate 

(lbs/MMBtu)

Revised 

Emissions 

(1000 

tons)

Net Budget Revision 

(1000 tons)

Calculation A*2/B D x B/2 E - A

J P Madgett B1 0.588922429 23.55689678 0.05 0.26 3.062 2.473

Columns A, B, and C shows the emissions, heat input, and emission rate from the 2012 remedy modeling for the J P Madgett unit. Because no SCR is 

present, EPA is recalculating projected emissions at this unit using the emission rate shown for this units in EPA’s analysis of the base case for the final 

Transport Rule, as found in the TR_Base_Case_Final for 2012 (column D). This annual NOX emission rate reflects generation at this unit without the

operation of the assumed SCR, which did not operate in the final Transport Rule base case because it was modeled as a “dispatchable” control that was not 

found to be economic to operate in that scenario.17

The revisions to the SO2 emission budget for Wisconsin results in a small change to the state’s new unit set-aside percentage for SO2. The reason for the 

change is that under the methodology established in the final Transport Rule, the state-specific portion of the NUSA is calculated as the percentage equal to 

 The J P Madgett emission rate without operating an SCR (column D) multiplied by the remedy heat input 

(column B) yields the projected emissions from the unit if no SCR were assumed to be in place. The difference between the projected emissions when no 

SCR is in place (column E) and the projected emissions when an SCR is assumed (column A) determines the amount of the increase to the state’s 2012 and 

2014 annual NOX budgets (column F).

 17 See "WebReady_ParsedFile_TR_Base_Case_Final_2012" in the Transport Rule docket or on EPA's CSAPR website
17

the projected emissions from “planned units” divided by the state budget for the relevant pollutant. In the case of Wisconsin, the projected emissions from 

planned units remain unchanged, but the budget is increasing.18 Because the numerator remains unchanged but the denominator is increasing, the total new 

unit set-aside percentage for SO2 decreases. That is, a smaller percentage of the state emission budget is needed to cover emissions from “planned” new 

units, because the budget is larger. For Wisconsin, the budget revision decreases the NUSA percentage for SO2 from 5% to 4% as a result. This is applying 

the same NUSA methodology that is used for every state in the final Transport Rule, and the change in percentage is simply an outgrowth of the state’s 

budget revision. While this change in the NUSA percentage reduces the absolute number of allowances in the Wisconsin NUSA for SO2 as compared to the 

amount under the final Transport Rule, the revised NUSA still contains more than enough allowances in 2012 and 2014 to cover projected emissions from 

“planned” new units in Wisconsin, with the remainder still available for “potential” new units to enter the programs during that time. The original and 

revised values for the state SO2 budget, assurance level, and new unit set-aside are described in the table below.

Table B.8.d.: Impact of Wisconsin Budget Revisions – Assuming no FGD at Weston Unit 3, no 

SCR at JP Madgett, and dry FGD at Columbia (tons)

Program Budget

Assurance Level Total New Unit Set-Aside*

% of Budget Tons % of Budget Tons

2012 Initial SO2 79,480 118% 93,786 5% 3,974

2012 Revised SO2 79,480 - - 4% 3,179

2014 Initial SO2 40,126 118% 47,349 5% 2,006

2014 Revised SO2 47,883 118% 56,502 4% 1,915

2012 Initial Annual NOX 31,628 118% 37,321 6% 1,898

2012 Revised Annual NOX 34,101 - - 6% 2,046

2014 Initial Annual NOX 30,398 118% 35,870 6% 1,824

2014 Revised Annual NOX 32,871 118% 38,788 6% 1,972

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations

 18 While this relationship is also true for annual NOX, the revisions to Wisconsin’s annual NOX budget do not yield a different calculated NUSA percentage than the 

originally determined 6% under the final Transport Rule.
18

9)

EPA is finalizing, as proposed, an increase to the New York state annual NOX, ozone-season NOX, and SO2 budgets to reflect the assumption of 

near-term operational constraints affecting specific units in New York City and Long Island. These revisions are based on three types of local operating 

constraints that apply to certain generators in New York City and Long Island, which are referred to here as the N-1-1 Contingency, the Minimum Oil Burn 

Rules, and local out-of-merit-order dispatch conditions. Each calculation of the near-term emission impact found to be associated with these constraints is 

documented below; the results are summarized in Table B.9.f.

New York

N-1-1 Contingency

Certain parts of the Con Edison system in New York City are required to be designed and operated for the occurrence of a second contingency, also 

known as an N-1-1 contingency; these requirements are in addition to any requirements for the first (N-1) contingency on which the overall New York State 

power system is operated. The local rules that determine the operation and unit commitment for New York City are New York State Reliability Council 

(NYSRC) rules I-R1 through I-R4.19

The dispatch requirements apply throughout the year, but there are also additional environmental requirements unique to ozone season operation. 

During the ozone season, the NYISO determines generator operations subject to local environmental regulations that require NYISO to dispatch certain 

steam units before seeking additional power from CTs when needed, to balance the need to meet energy and reserve requirements against daily local 

emissions for these units. NYISO implements these requirements through an operational procedure that requires commitment of oil/gas steam units at 

specific plants that would otherwise not be economic to dispatch, in order to ensure these combustion turbines can be dispatched when needed. For the 

 To meet the requirements of these rules, the New York Independent System Operator (NYISO) performs a 

supplemental commitment of units in the New York City zone. The rules require additional reserves from in-city combustion turbines (CTs), as well as unit 

commitment of steam units where needed to ensure sufficient locational reserves and to guard against a potential interruption in gas supply at any given 

facility that could disrupt its generation and perturb local grid stability. These rules are in effect throughout the year and are implemented by NYISO in a 

daily and hourly unit commitment process specific to New York City. Depending on the expected load level and the pattern of load during the day, NYISO 

will commit steam units to meet intermediate load levels, while placing CTs in reserve to meet morning and afternoon peak requirements if needed. As the 

NYISO must meet multiple requirements for reserves and energy and comply with the NYSRC rules, the exact pattern of dispatch that satisfies all of these 

constraints varies throughout the year. Because the steam units in the city have long startup times and 24-hour minimum run times, NYISO must commit 

these units in advance in order to preserve the ability to dispatch the CTs during peak load or in response to grid disruption contingencies. 

 19 See Rule I-R1, NYSRC Reliability Rules For Planning and Operating the New York State Power System, Version 29, New York State Reliability Council (NYSRC), 

January 7, 2011, p. 66.
19

steam units in New York City (Arthur Kill, Ravenswood and Astoria), these procedures mean that one or more steam units must be running for the entire 

ozone season.20

Minimum Oil Burn Rules

 

In order to ensure that units do not go offline if there is a loss of natural gas supply to New York City, the NYSRC rules incorporate special 

provisions that require natural gas units to be prepared to switch from natural gas to oil immediately upon notice of a loss of natural gas supply. These 

provisions are implemented through utility applications to the NYISO for special summer and winter dispatch conditions designed to govern when 

generators must be prepared to burn oil in each season.21 For certain oil/gas steam units that do not have the ability to switch immediately from natural gas 

to oil, this provision means that they must already be burning oil at the times that they may be notified to switch. As a result, it is necessary for these units to 

operate using oil at certain times of the year. For New York City, Con Edison applies to revise this procedure twice each year based on expected conditions 

for the winter or summer season.22 There is a separate and similar minimum oil burn rule affecting units in Long Island.23

Since in the current outlook the price of oil is much higher than gas for the same heat input, EPA recognizes that these operations would not be 

captured in projections of economic generating behavior. As such, EPA has calculated revised emission projections at the units affected by the minimum oil 

burn rules based on the fraction of heat input each unit reported as oil in 2010 to the Energy Information Administration.24

Local Out-of–Merit-Order Dispatch

 

Long Island’s ability to import electricity is limited to tie lines within the state between Con Ed and the Long Island Power Authority (LIPA), and 

interstate cables connecting Long Island with the Independent System Operator for New England (ISO-NE) and the PJM Interconnection. Because the lines 

from ISO-NE and PJM are direct current (DC) lines that are not dispatched in real time and not controlled by the NYISO, the ability to serve Long Island 

load from within New York State is subject to overall import limitations. Local conditions limiting the immediate-term ability of NYISO to move power 

between southern New York state and Long Island lead NYISO to dispatch more generation from units on Long Island than regional economic dispatch 

modeling, such as EPA’s IPM projections, would suggest. The NYISO Operating Study25

 20 See Analysis of New York City Averaging Plans for Compliance with NOx Emissions Limitations, New York Independent System Operator, Inc., 2011

shows that NYISO is limited to approximately 860 MW of 

dispatchable import capacity into Long Island on a sustainable hourly basis. Even if this line were fully loaded for all hours of the year, the maximum 

amount of imports into Long Island that NYISO can dispatch would be 7.5 TWh; however, in EPA’s modeling of the final Transport Rule, Long Island has 

21 NYSRC Reliability Rules For Planning and Operating the New York State Power System, Version 29, New York State Reliability Council (NYSRC), January 7, 2011, IR3 & I-R5 Reliability Rule Applications. Rule I-R3 governs New York City operations, Rule I-R5 Long Island Operations. 22 See ConEd, Application for the Loss of Generator Gas Supply – New York City, OC Meeting – May 12, 2011, for the requirements for the summer 2011 procedures. 23 See the document, Long Island Gas Burn Procedures – 2011, in the docket for the TR Rule Revisions Proposal, Docket. 24 The EIA data used for this calculation is available at: http://www.eia.gov/cneaf/electricity/page/eia906_920.html. 25 See NYISO Operating Study Summer 2011 and Appendices, New York Independent System Operator, July 14, 2011, page C-3.
20

9.7 TWh of net imports from NYISO dispatch. Under these conditions, NYISO would have to increase local Long Island generation by 2.2 TWh to meet 

local load while respecting the 7.5 TWh limitation on imports from the rest of NYISO, notwithstanding the economic merit of that imported generation. To 

determine projected emissions associated with this local out-of-merit-order dispatch, EPA assumed that this generation would come from the Northport 

plant, on the basis that one unit at Northport is modeled to have economic generation even without this local import limitation represented, and the remaining 

units at Northport have heat rates that differ by less than one percent from the Northport unit that was modeled to dispatch.

Calculation of New York City Revised Generation and Emissions – Plant Level

To reflect the requirements of the NYSRC rules as implemented by the NYISO for New York City, EPA is assuming that additional commitment of 

units at three steam plants in New York City (Arthur Kill, Ravenswood, and Astoria) would occur in the form of two units at each facility dispatched at a 

minimum of 50% capacity at the times that the contingency conditions apply to necessitate non-economic operation of these steam units. These calculations 

establish the assumed minimum generation at each facility that would dispatch in the immediate term to meet the conditions of the NYSRC rules 

independent of the economic merit of that generation within the larger region as originally modeled. Where EPA’s originally projected generation for the 

unit was less than this minimum, EPA has calculated here the difference in generation from the unit and, most importantly, the associated emissions from 

that generation, in order to inform the revision to the New York state budgets under the Transport Rule. Calculations were performed separately for ozone 

season and non-ozone season periods. During the ozone season, these dispatch conditions were assumed to apply 100% of the time; during the rest of the 

year (non-ozone season), they were assumed to apply 40% of the time, reflecting historically observed seasonal differences in operation of these units. The 

NOX emissions from this additional generation at these units were calculated using each unit’s heat rate and NOX emission rate from EPA’s assumptions in 

its IPM modeling. The results from these unit-level calculations are shown in Tables B.9.a and B.9.b.

To account for the effects of the minimum oil burn rule in New York City, EPA calculated SO2 emissions from the revised generation at each unit by 

assuming that the unit would burn oil for the same share of its projected heat input (including the revisions discussed above) as reported to EIA in 2010. 

These calculations for New York City units are shown in Table B.9.b. To estimate additional SO2 emissions, the IPM emission rate of 1.04 lbs/MMBtu for 

residual fuel oil was used. The IPM emission rate for NOX is the same for natural gas and oil, so no changes in NOX emissions were needed to represent the 

additional use of oil. 
21

Table B.9.a.: Ozone Season NOX Revised Unit-Level Emission Projections for New York City for N-1-1 Contingency Operation

Affected Facilities Operations as modeled for the Transport Rule in IPM Revisions to Generation and Emissions

A B C D E F G H I J K L

UniqueID Plant Name

Capacity

(MW)

Capacity 

Factor

Heat 

Rate

(BTU/

kWh)

NOX Rate 

(lbs/ 

MMBtu)

Heat 

Input 

(TBtu)

Generation 

(GWh)

Minimum 

Capacity 

Factor

Revised

Generation 

(GWh)

Additional 

Generation

beyond 

IPM (GWh)

Additional 

NOX

Emissions 

(tons)

Calculation (I-H) (E*J*F)/ 

2000

2490_B_20 Arthur Kill 335 31.7% 10389 0.08 4.056 390 50.0% 615 225 90.5

2490_B_30 Arthur Kill 491 31.7% 10198 0.10 5.836 572 50.0% 901 329 165.6

2500_B_10 Ravenswood 356 0.0% 11714 0.07 0.000 0 50.0% 653 653 256.5

2500_B_30 Ravenswood 940 0.0% 11624 0.07 0.000 0 50.0% 1,726 1,726 697.7

8906_B_30 Astoria 366 44.4% 10123 0.06 6.039 597 50.0% 672 75 23.3

8906_B_40 Astoria 373 44.4% 10117 0.06 6.150 608 50.0% 685 77 23.8
22

Table B.9.b.: Annual NOX and SO2 Revised Unit-Level Emission Projections for New York City 

for N-1-1 Contingency Operation and Minimum Oil Burn Rule

 

Affected 

Facilities Operations as modeled for the Transport Rule in IPM Revisions to Generation and Emissions

A B C D E F G H I J K L M N

Unique

ID

Plant 

Name

Capacity

(MW)

Capacity 

Factor

Heat 

Rate

(BTU/

kWh)

NOX

Rate (lbs/ 

MMBtu)

Heat 

Input 

(TBtu

)

Generation 

(GWh)

Minimum 

Capacity 

Factor

Revised

Generation 

(GWh)

Additional 

Generation

beyond 

IPM (GWh)

Additional 

NOX

Emissions 

(tons)

2010 Oil 

Fraction 

Additional 

SO2

Emissions 

(tons)*

Calculation (I-H) (E*J*F)/ 

2000

M*J*1.04*

E/2000

2490_

B_20

Arthur 

Kill 335 13.3% 10389 0.08 4.056 390 32.6% 956 566 227.9 0.000 0.0

2490_

B_30

Arthur 

Kill 491 13.3% 10198 0.10 5.836 572 32.6% 1,401 829 416.9 0.000 0.0

2500_

B_10

Ravenswood 356 0.0% 11714 0.07 0.000 0 32.6% 1,015 1,015 398.7 0.039 243.1

2500_

B_30

Ravenswood 940 0.0% 11624 0.07 0.000 0 32.6% 2,682 2,682 1084.4 0.039 637.7

8906_

B_30 Astoria 366 18.6% 10123 0.06 6.039 597 32.6% 1,044 448 138.6 0.065 358.3

8906_

B_40 Astoria 373 18.6% 10117 0.06 6.150 608 32.6% 1,064 456 141.1 0.065 364.9

8906_

B_50 Astoria 359 18.6% 10120 0.06 5.921 585 18.6% 585 0 0.0 0.065 200.7

*Assumes the IPM v.4.10_FTransport SO2 emission rate of 1.04 lbs/MMBTU for oil-fired generation

Calculation of Long Island Revised Generation and Emissions – Plant Level

As discussed above, EPA is assuming that an additional 2.2 TWh of generation beyond the level projected in IPM modeling of the Transport Rule

will occur on Long Island in the immediate term to allow NYISO to dispatch enough power to meet local load while respecting the limited import capacity

into Long Island. EPA is assuming that this additional generation would occur at the Northport facility distributed across its three units. Since the three 

units have virtually identical heat rates, EPA assumes that these units would be operated at the same capacity factors; EPA therefore establishes a minimum 

capacity factor at each unit in order to produce an additional 2.2 TWh beyond the original IPM projection. In concert with these assumptions, EPA

calculated additional ozone-season NOX, annual NOX, and SO2 emissions from these Long Island units in the same way as for the New York City units 

shown above. These calculations are provided in Tables B.9.c and B.9.d below.
23

Table B.9.c.: Ozone Season NOX Revisions for Long Island for Import Limited Generation

Affected Facilities Operations as modeled for the Transport Rule in IPM Revisions to Generation and Emissions

A B C D E F G H I J K L

UniqueID

Plant 

Name

Capacity

(MW)

Capacity 

Factor

Heat 

Rate

(BTU/

kWh)

NOX

Rate 

(lbs/ 

MMBtu)

Heat 

Input 

(TBtu)

Generation 

(GWh)

Minimum 

Capacity 

Factor

Required 

Generation 

(GWh)

Additional 

Generation 

(GWh)

Additional 

NOX

Emissions 

(tons)

Calculation (I-H) (E*J*F)/ 

2000

2516_B_2 Northport 390 23.4% 10580 0.11 3.534 334 38.5% 551 217 129.6

2516_B_3 Northport 391 0.0% 10634 0.14 0.000 0 38.5% 552 552 399.0

2516_B_4 Northport 385 0.0% 10663 0.10 0.000 0 38.5% 544 544 292.2

Table B.9.d.: Annual NOX and SO2 Revisions for Long Island for Import Limited Generation and Minimum Oil Burn Rule

Affected Facilities Operations as modeled for the Transport Rule in IPM Revisions to Generation and Emissions

A B C D E F G H I J K L M N

Unique

ID

Plant 

Name

Capacity

(MW)

Capacity 

Factor

Heat 

Rate

(BTU/

kWh)

NOX

Rate 

(lbs/ 

MMBtu)

Heat 

Input 

(TBtu

)

Generation 

(GWh)

Minimum 

Capacity 

Factor

Revised

Generation 

(GWh)

Additional 

Generation

beyond 

IPM (GWh)

Additional 

NOX

Emissions 

(tons)

2010 Oil 

Fraction

Additional 

SO2

Emissions

(tons)*

Calculation (I-H) (E*J*F)/ 

2000

M*J*1.04*

E/2000

2516_

B_2 Northport 390 9.8% 10580 0.11 3.534 334 25.1% 858 524 313.4 0.122 573.7

2516_

B_3 Northport 391 0.0% 10634 0.14 0.000 0 25.1% 860 860 621.6 0.122 578.1

2516_

B_4 Northport 385 0.0% 10663 0.10 0.000 0 25.1% 847 847 455.2 0.122 570.8

Assumes the IPM v.4.10_FTransport SO2 emission rate of 1.04 lbs/MMBTU for oil-fired generation
24

Calculation of Revisions to New York State Budgets

In order to maintain the balance of electricity supply and demand as originally projected in the Transport Rule analysis, EPA is assuming that 

increased generation at the units shown above would offset the need for an equivalent amount of generation originally projected in IPM to occur at more 

efficient generators in the system. To calculate the net change in projected emissions for each pollutant relevant to establishing state budgets under the 

Transport Rule, EPA assumes that the increased generation at the units shown above displaces previously projected generation from a combined cycle unit in 

New York City, as that unit is representative of more efficient generation that is preferred in IPM determinations of least-cost dispatch. These calculations 

are shown in Table B.9.e. 

Table B.9.e.: Calculation of Emissions from Displaced Generation at a Representative Combined Cycle Unit in New 

York*

A B C D

Program 

Period

Displaced Generation 

(GWh)

Heat Rate 

(BTU/kWh)

NOX Emission Rate 

(lbs/MMBTU)

Displaced NOX Emissions

(tons)

Calculation A*B*C/2000

Annual 8,227 7,600 0.01 313

Ozone Season 4,397 7,600 0.01 167

*Assumed heat rate and emission rates are taken from the 500 CC unit in New York City, as shown in NEEDS v4.10_FTransport.

To quantify the revisions to Transport Rule state budgets in New York, EPA has calculated the net emissions change associated with the revisions to 

unit-level generation presented in this section, including the displaced emissions shown in Table B.9.e. These calculations are shown in Table B.9.f.
25

Table B.9.f.: Calculation to Determine Net New York SO2, Annual NOX, and Ozone 

Season NOX Budget Revisions 

SO2 Annual NOX

Ozone Season 

NOX

A

Additional Emissions Due to 

New York City Revisions 1,805 2,408 1,257

B

Additional Emissions Due to 

Long Island Revisions 1,723 1,390 821

C Displaced Emissions 0 313 167

D

Net Emissions Change For 

New York (A+B-C) 3,527 3,485 1,911

The revisions to the annual and ozone season NOX emission budgets for New York result in small changes to the state’s new unit set-aside percentages for 

annual NOX and ozone season NOX. The reason for these changes is that under the methodology established in the final Transport Rule, the state-specific 

portion of the NUSA is calculated as the percentage equal to the projected emissions from “planned units” divided by the state budget for the relevant

pollutant. In the case of New York, the projected emissions from planned units remain unchanged, but the budgets are increasing.26 Because the numerator 

remains unchanged but the denominator is increasing, the total new unit set-aside percentage for annual NOX and ozone season NOX decreases. That is, a 

smaller percentage of the state emission budgets is needed to cover emissions from “planned” new units, because the budgets are larger. For New York, the

budget revisions decrease the NUSA percentages for both annual NOX and ozone season NOX from 3% to 2% as a result. This is applying the same NUSA 

methodology that is used for every state in the final Transport Rule, and the change in percentages is simply an outgrowth of the state’s budget revisions. 

Despite the lower percentage value, the absolute number of allowances in the New York NUSAs rises in accordance with the budget revisions for New 

York. The original and revised values for the state’s emission budgets, assurance levels, and new unit set-asides are described in the Table B.9.g below.

 26 While this relationship is also true for SO2, the revisions to New York’s SO2 budget do not yield a different calculated NUSA percentage than the originally determined 

2% under the final Transport Rule.
26

Table B.9.g.: Impact of New York Budget Revisions – Assuming Out-of-Merit-Order Dispatch 

at New York City and Long Island Units (tons)

Program Budget

Assurance Level

Total New Unit 

Set-Aside*

% of 

Budget Tons

% of 

Budget Tons

2012 Initial SO2 27,325 118% 32,244 2% 547

2012 Revised SO2 30,852 - - 2% 617

2014 Initial SO2 18,585 118% 21,930 2% 372

2014 Revised SO2 22,112 118% 26,092 2% 442

2012 Initial Annual NOX 17,543 118% 20,701 3% 351

2012 Revised Annual NOX 21,028 - - 2% 421

2014 Initial Annual NOX 17,543 118% 20,701 3% 351

2014 Revised Annual NOX 21,028 118% 24,813 2% 421

2012 Initial Ozone-Season NOX 8,331 - - 3% 167

2012 Revised Ozone-Season NOX 10,242 121% 12,393 2% 205

2014 Initial Ozone-Season NOX 8,331 121% 10,081 3% 167

2014 Revised Ozone-Season NOX 10,242 121% 12,393 2% 205

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations

10) 

EPA is finalizing, as proposed, an increase to New Jersey’s SO2, annual NOX, and ozone season NOX budgets to correct for the assumption that 

scrubber and SCR technology would be installed by 2012 at BL England Unit 1. The scrubber and SCR had been planned to meet an Administrative 

Consent Order (AO) with New Jersey, but an agreement with the state allowed for a delay in installation of the control technology until the end of 2013. 

Additionally, the AO requires that this unit only run during the ozone season.

New Jersey

27

 27 Personal Correspondence from Bill O’Sullivan, New Jersey Department of Environmental Protection, to Sam Napolitano. September 26, 2011.

 Therefore, EPA is adjusting the state’s 2012 emission budgets to reflect this 
27

unit operating only in the ozone season and without a scrubber or SCR. This results in a 2,096 ton increase to the state’s 2012 SO2 budget; a 273 ton 

increase to the state’s 2012 annual NOX budget; and a 397 ton increase to the state’s 2012 ozone season NOX budget. As discussed later in this section, EPA 

assumes that the generation previously projected at BL England Unit 1 outside of the ozone season (and thus inconsistent with the AO) would occur instead

at well-controlled combined cycle units within the state, and their associated emissions are factored into the revisions to New Jersey state budgets.

The calculations of revised 2012 emissions from ozone-season operation of BL England Unit 1 are shown in Table B.10.a. 

Table B.10.a.: Calculation to Determine Revised Ozone Season Emissions at BL England Unit 1

A B C D E F

Pollutant

Ozone Season

Emissions 

from 

TR_Remedy 

Final_2012 

(1000 tons)

Ozone Season Heat 

Input from 

TR_Remedy_Final_2012 

(TBtu)

Remedy Emission Rate 

from 

TR_Remedy_Final_2012 

(lbs/MMBtu)

Revised 

Emission Rate 

(lbs/MMBtu)

Revised Ozone 

Season

Emissions 

(1000 tons)

Net Change 

in Ozone 

Season

Emissions

(1000 tons)

Calculation A*2/B D x B/2 E - A

SO2 0.175 2.282 0.153 2.190 2.499 2.324

NOX 0.105 2.282 0.092 0.440 0.502 0.397

Columns A, B, and C show the emissions, heat input, and emission rate from the TR_Remedy_Final_2012 modeling when the pollution control 

devices were originally assumed to be present at BL England Unit 1. Because neither a scrubber nor SCR is required by the AO in 2012, EPA modified the 

emission rates by removing the impact of the scrubber28 and adopting the “controlled NOX policy rate” in the NEEDS version from the September 1, 2010 

TR Notice of Data Availability (NODA), which does not reflect operation of an SCR at that unit (column D).29

 28 The SO2emission rate for BL England Unit 1 in TR_Remedy Final_2012 was 0.153 lbs/MMBtu. Removing the impact of that previously assumed scrubber’s SO2

removal rate of 93% yields an uncontrolled SO2 emission rate of 2.19 lbs/MMBtu.

 These values approximate the emission rates

expected at the unit at a cost threshold of $500/ton when no scrubber or SCR is present at the unit. These emission rates were multiplied by the remedy heat 

input shown in column B to obtain a revised emissions value for the unit (column E). The difference between these revised emission projections (no 

scrubber or SCR assumed, column E) and the remedy emission projections (scrubber and SCR assumed, column A) determines the net change to this unit’s 

ozone-season emissions (column F).

29 See National Electric Energy Data System (NEEDS) v4.10 available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html
28

Since the AO does not allow BL England Unit 1 to run outside of the ozone season, EPA has also determined the emissions impact from replacing 

the previously projected generation for that unit occurring outside of the ozone season. EPA assumes that this decrease in previously projected generation at 

BL England Unit 1 would be offset by increasing generation at New Jersey combined cycle units,

30 represented in these calculations as a generic unit with a 

heat rate and emission rates equal to the generation-weighted average of New Jersey combined cycle units.31 The calculations of emissions from this 

replaced generation are shown in Table B.10.b. As discussed below, the heat and emission rates of the generic unit were revised from the proposal for 

consistency across all revisions using a generation weighted average, instead of capacity weighted. Additionally, two cogeneration plants were removed 

from this average based on comments. 

Table B.10.b.: Calculation of Emissions at New Jersey Combined Cycle Units from 

Replacing BL England Unit 1’s Non-Ozone-Season Generation

A B C D

Pollutant

BL England Unit 1

Non-Ozone Season 

Generation from 

TR_Remedy 

Final_2012 (GWh)

Average 

Heat Rate of 

Replacement 

Generation 

(Btu/kWh)

Emission 

Rate of 

Replacement 

Generation 

(lbs/MMBtu)

Emissions from 

Replacement 

Generation (1000 

tons)

Calculation A*B*C/(2000*1000)

SO2 253.3 7413 0 0

NOX 253.3 7413 0.0136 0.013

EPA calculated the SO2 and NOX emissions in Table B.10.b by multiplying the replaced generation (column A) by the generic unit’s heat rate 

(column B) and relevant emission rate (column C).

In order to calculate appropriate revisions to New Jersey’s 2012 SO2, annual NOX, and ozone season NOX state budgets in accordance with the 

revisions to BL England Unit 1, EPA calculated the net change in projected emissions of each pollutant as shown in Table B.10.c below. 

 30 Excluding cogeneration facilities, whose generation is not solely based on electricity demand. 31 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission 

rate averages used in Final Revisions Rule” found in the docket for this rulemaking.
29

Table B.10.c.: Calculation to Determine New Jersey 2012 Budget Revisions Due to Changes at 

BL England Unit 1 (1000 tons)

Quantity Calculation Value

A Additional SO2 Emissions from BL England 2.324

B SO2 Emissions from Replacement Generation 0

C

BL England Unit 1 Non-Ozone Season SO2 Emissions from 

TR_Remedy Final_2012 0.228

D Net SO2 Emissions Due to Revisions of BL England Unit 1 A+B-C 2.096

E Additional Ozone Season NOX Emissions from BL England 0.397

F Annual NOX Emissions from Replacement Generation 0.013

G

BL England Unit 1 Non-Ozone Season NOX Emissions from 

TR_Remedy Final_2012 0.137

H

Net Annual NOX Emissions Due to Revisions of BL England Unit 

1 E+F-G 0.273

I

Net Ozone Season NOX Emissions Due to Revisions of BL 

England Unit 1 =E 0.397

The revisions to New Jersey’s 2012 SO2 and annual NOX budgets are determined by combining the revised emissions from ozone season operation 

without FGD or SCR at BL England Unit 1 (rows A and E) with the net change in emissions from replacing BL England’s generation during the rest of the 

year (row B minus row C for SO2, row D minus row E for NOX). The revision to New Jersey’s 2012 ozone-season NOX budget is equivalent to the change 

in ozone season NOX emissions at BL England due to removing the SCR (row E).

EPA is also finalizing, as proposed, an increase to New Jersey’s annual NOX and ozone season NOX budgets to reflect the assumption of near-term 

operational constraints affecting six plants, based on information provided by the system operator demonstrating that northern New Jersey is an out-of-meritorder dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local conditions described in recently submitted 

documentation that appear likely to necessitate non-economic generation at the units displayed below during the implementation of the Transport Rule 

programs. Specifically, EPA is assuming additional generation will be dispatched at six plants (Bergen, Edison, Essex, Kearny, Linden, and Sewaren 

Generating Stations) based on the average capacity factor representing the frequency the unit has recently been called on to operate out of merit order, 
30

calculated from dispatch logbook data provided by PSEG.

32

The calculations of the increase in ozone season NOX and annual NOX emissions due to out-of-merit-order dispatch at the six facilities are shown in 

Tables B.10.d and B.10.e, respectively. For each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, heat 

rate, generation, and emission rate are shown (columns A to G). The average out-of-merit-order capacity factor is shown in column H. The additional 

generation for out-of-merit-order dispatch was calculated by multiplying the capacity, the average out-of-merit-order capacity factor, and the number of 

hours in either the ozone season or year (column I). The additional heat input required was calculated by multiplying the incremental generation by the unit’s 

heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation was calculated by multiplying the additional heat 

input by the unit’s NOX emission rate. 

 As discussed later in this section, EPA assumes that the additional generation dispatched from 

these six facilities would offset generation that would otherwise come from combined cycle units within the state, and the revisions to New Jersey state 

budgets are based on the net change to projected emissions taking that offsetting factor into account. The net impact of these changes on the state’s 2012 and 

2014 budgets are a 679 ton increase in annual NOX and a 349 ton increase in ozone season NOX.

Table B.10.d.: Calculation to Determine New Jersey Ozone Season NOX Budget Revisions - Assuming Out-of-Merit-Order Dispatch at Six Plants

A B C D E F G H I J K

Plant Name

Unique 

ID

Capacity 

(MW)

2012 Ozone 

Season NOX

Emission 

from 

TR_Remedy 

Final_2012

(1000 tons)

Heat Rate 

(BTU/kWh)

Ozone Season 

Generation 

from 

TR_Remedy 

Final_2012

(GWh)

NOX

Emission 

Rate from 

TR_Remedy 

Final_2012 

(lbs/MMBtu)

Ozone 

Season 

Average 

Out-OfMeritOrder 

Capacity 

Factor 

Additional 

Ozone 

Season 

Generation 

(GWh)*

Additional 

Ozone

Season 

Heat Input 

(MMBtu)

Additional 

Ozone 

Season NOX

Emissions 

(tons)

Calculation C*H*3.672 E*I G*J/2000

Bergen 

2398_ 

G_1101 114 0.010 8841 55.18 0.04 20.1% 84.16 744,050 15.6

Bergen 

2398_ 

G_1201 114 0.010 8841 55.18 0.04 20.1% 84.16 744,050 15.6

Bergen 

2398_ 

G_1301 114 0.010 8841 55.18 0.04 20.1% 84.16 744,050 15.6

 32 See the spreadsheet “New Jersey Minimum Noneconomic Dispatch” provided by PSEG on September 26, 2011, in the docket for this rule making.
31

Bergen 

2398_ 

G_1401 114 0.010 8841 55.18 0.04 20.1% 84.16 744,050 15.6

Bergen 

2398_ 

G_1501 219 0.020 8841 106.00 0.04 20.1% 161.67 1,429,359 30.0

Bergen 

2398_ 

G_2101 163 0.004 9241 78.89 0.01 22.0% 131.73 1,217,340 7.3

Bergen 

2398_ 

G_2201 163 0.004 9241 78.89 0.01 22.0% 131.73 1,217,340 7.3

Bergen 

2398_ 

G_2301 224 0.006 9241 108.42 0.01 22.0% 181.03 1,672,908 10.0

PSEG 

Edison 

2400_ 

G_11 42 0.003 16763 1.37 0.27 2.1% 3.29 55,100 7.4

PSEG 

Edison 

2400_ 

G_12 42 0.003 16862 1.37 0.27 2.1% 3.17 53,375 7.1

PSEG 

Edison 

2400_ 

G_13 42 0.003 16893 1.37 0.27 1.8% 2.79 47,161 6.3

PSEG 

Edison 

2400_ 

G_14 42 0.003 16947 1.37 0.26 1.7% 2.60 44,143 5.8

PSEG 

Edison 

2400_ 

G_21 42 0.003 17182 1.37 0.28 2.0% 3.04 52,261 7.2

PSEG 

Edison 

2400_ 

G_22 42 0.003 16846 1.37 0.27 2.0% 3.07 51,731 6.9

PSEG 

Edison 

2400_ 

G_23 42 0.003 16979 1.37 0.27 1.9% 2.87 48,679 6.6

PSEG 

Edison 

2400_ 

G_24 42 0.004 17184 1.37 0.30 1.6% 2.53 43,451 6.5

PSEG 

Edison 

2400_ 

G_31 42 0.003 16953 1.37 0.27 1.6% 2.52 42,653 5.7

PSEG 

Edison 

2400_ 

G_32 42 0.003 16984 1.37 0.27 1.8% 2.76 46,909 6.3

PSEG 

Edison 

2400_ 

G_33 42 0.003 17033 1.37 0.27 1.9% 2.87 48,964 6.6

PSEG 

Edison 

2400_ 

G_34 42 0.003 16950 1.37 0.26 1.7% 2.68 45,443 6.0

PSEG 

Essex 

2401_ 

G_101 42 0.003 16968 1.37 0.30 2.6% 4.00 67,800 10.2
32

PSEG 

Essex 

2401_ 

G_102 42 0.004 17066 1.37 0.30 2.4% 3.66 62,382 9.3

PSEG 

Essex 

2401_ 

G_103 42 0.004 17188 1.37 0.30 2.1% 3.31 56,950 8.5

PSEG 

Essex 

2401_ 

G_104 42 0.004 17167 1.37 0.30 2.2% 3.33 57,220 8.6

PSEG 

Essex 

2401_ 

G_111 46 0.004 16816 1.50 0.30 2.5% 4.16 69,880 10.5

PSEG 

Essex 

2401_ 

G_112 46 0.004 17154 1.50 0.30 2.6% 4.48 76,769 11.5

PSEG 

Essex 

2401_ 

G_113 46 0.004 16847 1.50 0.30 2.3% 3.92 66,007 9.9

PSEG 

Essex 

2401_ 

G_114 46 0.004 16726 1.50 0.30 2.3% 3.86 64,566 9.7

PSEG 

Essex 

2401_ 

G_121 46 0.004 16455 1.50 0.30 2.2% 3.80 62,517 9.4

PSEG 

Essex 

2401_ 

G_122 46 0.004 16889 1.50 0.30 2.2% 3.78 63,867 9.6

PSEG 

Essex 

2401_ 

G_123 46 0.004 16771 1.50 0.30 2.3% 3.83 64,166 9.6

PSEG 

Essex 

2401_ 

G_124 46 0.001 16758 1.50 0.08 2.2% 3.67 61,540 2.6

PSEG 

Essex 

2401_ 

G_9 81 0.022 10633 13.67 0.30 0.0% 0.000 0.0

PSEG 

Kearny 

2404_ 

G_10 134 0.012 18700 4.45 0.30 0.5% 2.37 44,361 6.7

PSEG 

Kearny 

2404_ 

G_11 134 0.012 18700 4.45 0.30 0.3% 1.47 27,572 4.1

PSEG 

Kearny 

2404_ 

G_N121 43.8 0.003 9667 7.28 0.09 0.2% 0.26 2,534 0.1

PSEG 

Kearny 

2404_ 

G_N122 43.7 0.003 9791 7.26 0.09 0.2% 0.27 2,670 0.1

PSEG 

Kearny 

2404_ 

G_N123 43.8 0.003 10109 7.28 0.09 0.0% 0.02 201 0.0

PSEG 

Kearny 

2404_ 

G_N124 43.7 0.003 9704 7.26 0.09 0.2% 0.26 2,475 0.1
33

PSEG 

Linden 

2406_ 

G_5 86 0.005 12110 14.51 0.06 2.1% 6.58 79,681 2.4

PSEG 

Linden 

2406_ 

G_6 86 0.005 12601 14.51 0.05 2.1% 6.60 83,206 2.1

PSEG 

Linden 

2406_ 

G_7 84 0.005 12155 14.17 0.06 2.5% 7.83 95,173 2.8

PSEG 

Linden 

2406_ 

G_8 84 0.006 13314 14.17 0.06 2.6% 8.03 106,922 3.4

PSEG 

Sewaren 

2411_ 

B_1 104 - 12377 0.00 0.12 6.4% 24.28 300,531 17.6

PSEG 

Sewaren 

2411_ 

B_2 118 - 13581 0.00 0.16 4.7% 20.31 275,884 22.1

PSEG 

Sewaren 

2411_ 

B_3 107 - 14500 0.00 0.15 6.0% 23.73 344,085 26.1

PSEG 

Sewaren 

2411_ 

B_4 124 - 14500 0.00 0.14 3.8% 17.38 251,965 17.6

TOTAL 1,142 11,483,943 410.2

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.
34

Table B.10.e.: Calculation to Determine New Jersey Annual NOX Budget Revisions - Assuming Out-of-Merit-Order Dispatch at Six Plants

A B C D E F G H I J K

Plant Name

NEEDS 

Unique 

ID

Capacity 

(MW)

2012 Annual 

NOX

Emission 

(1000 tons) 

from 

TR_Remedy 

Final_2012

Heat Rate 

from 

TR_Remedy 

Final_2012

(Btu/kWh)

GWh Annual 

from 

TR_Remedy 

Final_2012

NOX

Emission 

Rate from 

TR_Remedy 

Final_2012 

(lbs/MMBtu)

Annual 

Average 

Out-OfMeritOrder 

Capacity 

Factor 

Additional 

Annual 

Generation 

(GWh)*

Additional 

Annual 

Heat Input 

(MMBtu)

Additional 

Annual 

NOX

Emissions 

(tons)

Calculation C*H*8.760 E*I G*J/2000

Bergen 

2398_ 

G_1101 114

 

0.015 8841

 

78.98 0.04 36.3% 362.43 3,204,207 67.3

Bergen 

2398_ 

G_1201 114

 

0.015 8841

 

78.98 0.04 36.3% 362.43 3,204,207 67.3

Bergen 

2398_ 

G_1301 114

 

0.015 8841

 

78.98 0.04 36.3% 362.43 3,204,207 67.3

Bergen 

2398_ 

G_1401 114

 

0.015 8841

 

78.98 0.04 36.3% 362.43 3,204,207 67.3

Bergen 

2398_ 

G_1501 219

 

0.028 8841

 

151.72 0.04 36.3% 696.24 6,155,451 129.3

Bergen 

2398_ 

G_2101 163

 

0.005 9241

 

86.87 0.01 35.5% 507.55 4,690,299 28.1

Bergen 

2398_ 

G_2201 163

 

0.005 9241

 

86.87 0.01 35.5% 507.55 4,690,299 28.1

Bergen 

2398_ 

G_2301 224

 

0.007 9241

 

119.38 0.01 35.5% 697.50 6,445,565 38.7

PSEG 

Edison 

2400_ 

G_11 42

 

0.003 16763

 

1.37 0.27 1.0% 3.76 63,093 8.5

PSEG 

Edison 

2400_ 

G_12 42

 

0.003 16862

 

1.37 0.27 1.0% 3.56 59,944 8.0

PSEG 2400_ 42 16893 0.27 0.8% 2.85 48,155 6.5
35

Edison G_13 0.003 1.37 

PSEG 

Edison 

2400_ 

G_14 42

 

0.003 16947

 

1.37 0.26 0.7% 2.67 45,259 6.0

PSEG 

Edison 

2400_ 

G_21 42

 

0.003 17182

 

1.37 0.28 1.0% 3.59 61,750 8.5

PSEG 

Edison 

2400_ 

G_22 42

 

0.003 16846

 

1.37 0.27 1.0% 3.60 60,655 8.1

PSEG 

Edison 

2400_ 

G_23 42

 

0.003 16979

 

1.37 0.27 0.8% 3.02 51,338 7.0

PSEG 

Edison 

2400_ 

G_24 42

 

0.004 17184

 

1.37 0.30 0.7% 2.68 46,125 6.9

PSEG 

Edison 

2400_ 

G_31 42

 

0.003 16953

 

1.37 0.27 0.8% 2.88 48,831 6.5

PSEG 

Edison 

2400_ 

G_32 42

 

0.003 16984

 

1.37 0.27 0.8% 3.10 52,620 7.1

PSEG 

Edison 

2400_ 

G_33 42

 

0.003 17033

 

1.37 0.27 0.8% 2.94 50,000 6.7

PSEG 

Edison 

2400_ 

G_34 42

 

0.003 16950

 

1.37 0.26 0.7% 2.74 46,491 6.1

PSEG 

Essex 

2401_ 

G_101 42

 

0.003 16968

 

1.37 0.30 1.6% 6.07 102,945 15.4

PSEG 

Essex 

2401_ 

G_102 42

 

0.004 17066

 

1.37 0.30 1.5% 5.39 91,989 13.8

PSEG 

Essex 

2401_ 

G_103 42

 

0.004 17188

 

1.37 0.30 1.3% 4.79 82,370 12.3

PSEG 

Essex 

2401_ 

G_104 42

 

0.004 17167

 

1.37 0.30 1.4% 5.21 89,408 13.4

PSEG 

Essex 

2401_ 

G_111 46

 

0.004 16816

 

1.50 0.30 1.7% 6.70 112,614 16.9

PSEG 

Essex 

2401_ 

G_112 46

 

0.004 17154

 

1.50 0.30 1.8% 7.15 122,683 18.4

PSEG 

Essex 

2401_ 

G_113 46

 

0.004 16847

 

1.50 0.30 1.5% 6.20 104,513 15.7

PSEG 

Essex 

2401_ 

G_114 46

 

0.004 16726

 

1.50 0.30 1.6% 6.53 109,251 16.4
36

PSEG 

Essex 

2401_ 

G_121 46

 

0.004 16455

 

1.50 0.30 1.9% 7.49 123,289 18.5

PSEG 

Essex 

2401_ 

G_122 46

 

0.004 16889

 

1.50 0.30 2.0% 7.90 133,445 20.0

PSEG 

Essex 

2401_ 

G_123 46

 

0.004 16771

 

1.50 0.30 1.9% 7.60 127,493 19.1

PSEG 

Essex 

2401_ 

G_124 46

 

0.001 16758

 

1.50 0.08 1.8% 7.24 121,333 5.1

PSEG 

Essex 

2401_ 

G_9 81

 

0.022 10633

 

13.67 0.30 0.1% 0.57 6,026 0.9

PSEG 

Kearny 

2404_ 

G_10 134

 

0.012 18700

 

4 0.30 0.3% 3.63 67,789 10.2

PSEG 

Kearny 

2404_ 

G_11 134

 

0.012 18700

 

4 0.30 0.2% 2.78 51,981 7.8

PSEG 

Kearny 

2404_ 

G_N121 43.8

 

0.004 9667

 

9 0.09 0.3% 1.25 12,097 0.6

PSEG 

Kearny 

2404_ 

G_N122 43.7

 

0.004 9791

 

9 0.09 0.3% 1.15 11,299 0.5

PSEG 

Kearny 

2404_ 

G_N123 43.8

 

0.004 10109

 

9 0.09 0.3% 1.33 13,463 0.6

PSEG 

Kearny 

2404_ 

G_N124 43.7

 

0.004 9704

 

9 0.09 0.4% 1.39 13,488 0.6

PSEG 

Linden 

2406_ 

G_5 86

 

0.005 12110

 

15 0.06 1.2% 9.20 111,371 3.3

PSEG 

Linden 

2406_ 

G_6 86

 

0.005 12601

 

15 0.05 1.3% 9.55 120,318 3.0

PSEG 

Linden 

2406_ 

G_7 84

 

0.005 12155

 

14 0.06 1.9% 14.25 173,152 5.1

PSEG 

Linden 

2406_ 

G_8 84

 

0.006 13314

 

14 0.06 1.6% 11.99 159,613 5.1

PSEG 

Sewaren 

2411_ 

B_1 104

 - 12377

0 0.12 2.8% 25.71 318,163 18.6

PSEG 

Sewaren 

2411_ 

B_2 118

 - 13581

0 0.16 1.9% 19.24 261,271 21.0

PSEG 

Sewaren 

2411_ 

B_3 107

 - 14500

0 0.15 2.7% 25.45 368,953 28.0
37

PSEG 

Sewaren 

2411_ 

B_4 124

 

- 14500 0 0.14 1.6% 17.37 251,901 17.6

TOTAL 4,119 38,694,923 886.9

*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8,760 hours of possible operation in the year; that factor is divided by 1,000 to yield units in GWh.

As calculated in Table B.10.f, EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch would be offset by decreasing 

generation at New Jersey combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column 

C) equal to the generation-weighted average of New Jersey combined cycle units.33 This is a change from the proposal where a capacity-weighted average 

was used to determine the characteristics of the representative unit. The change was made for consistency across states where generation from a 

representative unit was used to offset increased generation due to out-of-merit order dispatch. Additionally, as explained in the preamble and based on 

comments received, EPA excluded any identified cogeneration units from these calculations. Finally, separate annual and ozone season emission and heat 

rates were calculated and the applicable ones were used as the situation warranted. The ozone season and annual NOX emissions associated with the 

displaced generation (column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative 

combined cycle unit.

Table B.10.f.: Calculation of Emissions from Displaced Generation at New Jersey Combined Cycle Units

A B C D

Program 

Period

Displaced Generation 

(GWh)

Heat Rate 

(BTU/kWh)

NOX Emission Rate 

(lbs/MMBTU)

Displaced NOX Emissions

(tons)

Calculation A*B*C/2000

Annual 4,119 7,413 0.0136 208

Ozone Season 1,142 7,454 0.0144 61

The total revisions finalized to New Jersey’s state budgets due to the revisions at BL England and accounting for the out-of-merit-order dispatch are

demonstrated in Table B.10.g. The increase in emissions due to the changes at BL England Unit 1, which only impact the 2012 budgets, were added to the 

increase in emissions due to the out-of-merit-order generation, which impact both the 2012 and 2014 budgets. The emissions associated with the generation 

 33 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission 

rate averages used in Final Revisions Rule” found in the docket for this rulemaking.
38

displaced by the out-of-merit-order generation was subtracted from the increase in emissions to determine the net emission budget changes for New Jersey

(row D). 

Table B.10.g.: Calculation to Determine Net New Jersey SO2, Annual NOX, and Ozone Season NOX Budget Revisions (tons)

2012 2014

SO2

Annual 

NOX

Ozone 

Season NOX SO2

Annual 

NOX

Ozone 

Season NOX

A Net Emissions Increases Due to Changes at BL England Unit 1 2,096 273 397 0 0 0

B Additional Emissions Due to Out-Of-Merit-Order Generation 0 887 410 0 887 410

C Displaced Emissions from Out-Of-Merit-Order Generation 0 208 61 0 208 61

D Net Budget Revisions for New Jersey (A+B-C) 2,096 952 746 0 679 349

The original and revised values for the state SO2, annual NOX, and ozone season NOX budgets, assurance levels, and new unit set-asides are

described in Table B.10.h.
39

Table B.10.h.: Impact of New Jersey Budget Revisions – Assuming No FGD or SCR at BL 

England Unit 1 in 2012 and Out-of-Merit-Order Dispatch at Six Facilities (tons)

Program Budget

Assurance Level

Total New Unit 

Set-Aside*

% of 

Budget Tons

% of 

Budget Tons

2012 Initial SO2 5,574 118% 6,577 2% 111

2012 Revised SO2 7,670 - - 2% 153

2014 Initial SO2 5,574 118% 6,577 2% 111

2014 Revised SO2 5,574 118% 6,577 2% 111

2012 Initial Annual NOX 7,266 118% 8,574 2% 145

2012 Revised Annual NOX 8,218 - - 2% 164

2014 Initial Annual NOX 7,266 118% 8,574 2% 145

2014 Revised Annual NOX 7,945 118% 9,375 2% 159

2012 Initial Ozone-Season NOX 3,382 121% 4,092 2% 68

2012 Revised Ozone-Season NOX 4,128 - - 2% 83

2014 Initial Ozone-Season NOX 3,382 121% 4,092 2% 68

2014 Revised Ozone-Season NOX 3,731 121% 4,515 2% 75

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations

11)

EPA is finalizing, as proposed, an increase to Louisiana’s ozone season NOX budget for 2012 and 2014 to reflect the assumption of near-term 

operational constraints affecting units at five plants, based on information provided by the system operator demonstrating that there are three out-of-meritorder dispatch areas in Louisiana: the West of the Atchafalaya Basin (WOTAB), Down Stream of Gypsy (DSG), and Amite South regions. EPA's analysis

in the final Transport Rule did not incorporate the immediate-term local conditions described in recently submitted documentation that appear likely to 

necessitate non-economic generation at the units displayed below during the implementation of the Transport Rule programs. Specifically, EPA is assuming 

Louisiana
40

additional generation will be dispatched at five plants (Nelson, Nine Mile Point, Michoud, Little Gypsy, and Waterford) based on the average capacity factor 

representing the frequency the unit is projected to be called to operate out-of-merit-order, derived from immediate-term dispatch modeling projections 

provided by Entergy.

34

The calculations of the increase in ozone season NOX emissions due to out-of-merit-order dispatch at the five facilities is shown in Table B.11.a. For 

each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation from TR_Remedy Final_2012, 

and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out-of-merit-order capacity factor is shown in column H. The 

additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, the average out-of-merit-order capacity factor, and the 

number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the incremental generation by the unit’s 

heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation was calculated by multiplying the additional heat 

input by the unit’s NOX emission rate. 

 As discussed later in this section, EPA assumes that the additional generation dispatched from these five facilities would offset 

generation that would otherwise come from combined cycle units within the state, and the revision to Louisiana’s state budget is based on the net change to 

projected emissions taking that offsetting factor into account. The net impact of these changes on the state’s ozone season NOX budget is a 4,594 ton 

increase.

Table B.11.a.: Calculation to Determine Louisiana Ozone Season NOX Budget Revisions - Assuming Out-of-Merit-Order Dispatch at Five Plants

A B C D E F G H I J K

Plant Name

Unique 

Id

Capacity 

(MW)

2012 Ozone 

Season NOX

Emissions

from 

TR_Remedy 

Final_2012 

(1000 tons)

Heat Rate 

(BTU/

kWh)

Ozone 

Season 

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Ozone Season 

NOX Rate 

(lbs/MMBtu) 

Ozone 

Season 

Average 

Out-OfMeritOrder 

Capacity 

Factor 

Additional 

Ozone 

Season 

Generation*

Additional 

Ozone 

Season Heat 

Input 

(MMBtu)

Additional 

Ozone 

Season 

NOX

Emissions 

(tons)

Calculation C*H*3.672 E*I G*J/2000

R S Nelson

1393_ 

B_3 153 0 10476 0 0.151 16% 89.89 941,694 70.9

R S Nelson

1393_ 

B_4 500 0 10419 0 0.128 23% 422.28 4,399,735 281.3

Little Gypsy

1402_ 

B_1 244 0 9978 0 0.278 7% 62.72 625,798 86.8

 34 Correspondence from Entergy to EPA, September 29, 2011. Please see the document “Transmission System Considerations – Entergy” in the docket for this rule making.
41

Little Gypsy

1402_ 

B_2 415 0 10032 0 0.098 3% 45.72 458,627 22.5

Little Gypsy

1402_ 

B_3 545 0 10179 0 0.311 24% 480.30 4,888,949 760.0

Nine Mile 

Point

1403_ 

B_3 132 0 10264 0 0.149 11% 53.32 547,250 40.9

Nine Mile 

Point

1403_ 

B_4 738 0 9955 0 0.337 31% 840.08 8,362,998 1,409.0

Nine Mile 

Point

1403_ 

B_5 753 0 9841 0 0.298 34% 940.11 9,251,578 1,380.0

Michoud

1409_ 

B_1 100 0 11427 0 0.042 0% 0.00 0 0.0

Michoud

1409_ 

B_2 230 0 10997 0 0.207 30% 253.37 2,786,288 287.9

Michoud

1409_ 

B_3 530 0 11288 0 0.105 45% 875.77 9,885,714 518.7

Waterford 1 

& 2

8056_ 

B_1 400 0 10238 0 0.123 3% 44.06 451,127 27.9

Waterford 1 

& 2

8056_ 

B_2 405 0 10137 0 0.116 7% 104.10 1,055,274 61.2

Total 4,211.71 43,655,032 4,947.1

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.

As calculated in Table B.11.b, EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch would be offset by decreasing 

generation at Louisiana combined cycle units, shown in these calculations. Generation was first offset from Washington Parish, which commenters informed 

EPA that the plant was never completed and part were deconstructed,35 with the remaining generation offset from a representative unit with a heat rate 

(column D) and emission rate (column E) equal to the generation-weighted average of Louisiana combined cycle units.36

 35 EPA-HQ-OAR-2009-0491-4803

As explained in the preamble and 

based on comments received, EPA excluded any identified cogeneration units from these calculations. Finally, separate annual and ozone season emission 

and heat rates were calculated and the applicable ones were used as the situation warranted. The ozone season NOX emissions associated with the displaced 

36 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission 

rate averages used in Final Revisions Rule” found in the docket for this rulemaking.
42

generation (column G) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative combined 

cycle unit. The total displaced emissions (column H) were calculated by adding the emissions from the operation of Washington Parish in IPM (column F) to 

emissions displaced from the representative unit. 

Table B.11.b.: Calculation of Emissions from Displaced Generation at Louisiana Combined Cycle Units

A B C D E F G H

Program 

Period

Displaced 

Generation 

(GWh)

Generation 

Displaced 

from 

Washington

Parish

(GWh)

Generation 

Displaced 

from other 

Combined 

Cycles

(GWh)

Heat Rate 

(BTU/ 

kWh)

NOX Emission 

Rate 

(lbs/MMBTU)

Displaced 

Emissions 

from 

Washington

Parish

(tons)

Displaced 

Emissions 

from other 

Combined 

Cycles

(tons)

Total 

Displaced 

NOX

Emissions 

(tons)

Calculation A-B C*D*E/2000 F+G

Ozone 

Season 4,212 1,806 2,405 7,480 0.031765081 67.7 286 353.4

The total revision proposed to Louisiana’s state budget due to the out-of-merit-order dispatch is calculated in Table B.11.c. The emissions associated 

with the generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the out-of-merit-order 

generation (row A) to determine the net emission budget changes for Louisiana (row C). 

Table B.11.c.: Calculation to Determine Net Louisiana 

Ozone Season NOX Budget Revisions (tons)

A

Additional Emissions Due to 

Out-Of-Order-Merit Dispatch 4,947

B

Displaced Emissions From 

Out-Of-Order-Merit Dispatch 353

C

Net Emission budget Change 

For Louisiana (A-B) 4,594
43

The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are described in Table B.11.d.

Table B.11.d.: Impact of Louisiana Ozone-Season NOX Budget Revisions –

Assuming Out-of-Merit-Order Dispatch at Five Facilities (tons)

Budget

Assurance Level Total New Unit Set-Aside*

% of Budget Tons % of Budget Tons

2012 Initial 13,432 121% 16,253 3% 403

2012 Revised 18,026 - - 3% 541

2014 Initial 13,432 121% 16,253 3% 403

2014 Revised 18,026 121% 21,811 3% 541

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit 

allocations

12) 

EPA is finalizing, as proposed, an increase to Mississippi’s ozone season NOX budget in 2012 and 2014 to reflect the assumption of near-term 

operational constraints affecting units at three plants, based on information provided by the system operator demonstrating that the Mississippi Region is an 

out-of-merit-order dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local conditions described in recently 

submitted documentation that appear likely to necessitate non-economic generation at the units displayed below during the implementation of the Transport 

Rule programs. Specifically, EPA is assuming additional generation will be dispatched at three plants (Rex Brown, Gerald Andrus, and Baxter Wilson) 

based on the average capacity factor representing the frequency the unit is projected to be called to operate out-of-merit-order, derived from immediate-term 

dispatch modeling projections provided by Entergy.

Mississippi

37

 37 Correspondence from Entergy to EPA, September 29, 2011. Please see the document “Transmission System Considerations – Entergy” in the docket for this rule making.

 As discussed later in this section, EPA assumes that the additional generation dispatched from these 

three facilities would offset generation that would otherwise come from combined cycle units within the state, and the revision to Mississippi’s state budget 

is based on the net change to projected emissions taking that offsetting factor into account. The net impact of these changes on the state’s ozone season NOX

budget is a 2,154 ton increase.
44

The calculations of the increase in ozone season NOX emissions due to out-of-merit-order dispatch at the three facilities is shown in Table B.12.a. 

For each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation from TR_Remedy 

Final_2012, and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out-of-merit-order capacity factor is shown in 

column H. The additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, the average out-of-merit-order capacity 

factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the incremental generation 

by the unit’s heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation was calculated by multiplying the 

additional heat input by the unit’s NOX emission rate. 

Table B.12.a.: Calculation to Determine Mississippi Ozone Season NOX Budget Revisions - Assuming out-of-merit-order dispatch at three plants

A B C D E F G H I J K

Plant Name

Unique 

Id

Capacity 

(MW)

2012 Ozone 

Season NOX

Emissions

from 

TR_Remedy 

Final_2012

(1000 tons)

Heat Rate 

(BTU/

kWh)

Ozone 

Season 

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Ozone 

Season NOX

Rate 

(lbs/MMBtu) 

Ozone Season 

Average OutOf-MeritOrder 

Capacity 

Factor 

Additional 

Ozone 

Season 

Generation*

(GWh)

Additional 

Ozone 

Season 

Heat Input 

(MMBtu)

Additional 

Ozone 

Season 

NOX

Emissions 

(tons)

Calculation C*H*3.672 E*I G*J/2000

Rex Brown

2053_ 

B_4 200 0 14500 0 0.228 4% 29.38 425,952 48.6

Baxter 

Wilson

2050_ 

B_1 475 0 10655 0 0.318 7% 122.09 1,300,912 207.1

Baxter 

Wilson

2050_ 

B_2 771 0 10511 0 0.422 18% 509.60 5,356,407 1130.5

Gerald 

Andrus

8054_ 

B_1 670 0 10748 0 0.209 33% 811.88 8,726,078 912.8

Total 1472.95 15,809,348 2299.1

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.

As calculated in Table B.12.b, EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch would be offset by decreasing 

generation at Mississippi combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) 
45

equal to the generation-weighted average of Mississippi combined cycle units.38

Table B.12.b.: Calculation of Emissions from Displaced Generation at Mississippi Combined Cycle Units

The emission and heat rates of this representative unit changed from the 

proposal because the proposal’s calculations used annual, rather than ozone-season, data; the calculations for this final rule use ozone-season data. 

Additionally, as explained in the preamble and based on comments received, EPA excluded any identified cogeneration units from these calculations. The 

ozone season NOX emissions associated with the displaced generation (column D) were calculated by multiplying that generation by the average heat rate 

and the relevant emission rate at the representative combined cycle unit.

A B C D

Program 

Period

Displaced Generation 

(GWh)

Heat Rate 

(BTU/kWh)

NOX Emission Rate 

(lbs/MMBTU)

Displaced NOX Emissions

(tons)

Calculation A*B*C/2000

Ozone Season 1,473 7,570 0.026 145

The total revision to Mississippi’s state budget due to the out-of-merit-order dispatch is calculated in Table B.12.c. The emissions associated with 

the generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the out-of-merit-order 

generation (row A) to determine the net emission budget changes for Mississippi (row C). 

Table B.12.c.: Calculation to Determine Net Mississippi 

Ozone Season NOX Budget Revisions (tons)

A

Additional Emissions Due to 

Out-Of-Order-Merit Dispatch 2,299

B

Displaced Emissions From 

Out-Of-Order-Merit Dispatch 145

C

Net Change in Emission 

budget For Mississippi (A-B) 2,154

 38 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission 

rate averages used in Final Revisions Rule” found in the docket for this rulemaking.
46

The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are described in Table B.12.d.

Table B.12.d.: Impact of Mississippi Ozone-Season NOX Budget Revisions –

Assuming Out-of-Merit-Order Dispatch at Three Facilities (tons)

Budget

Assurance Level Total New Unit Set-Aside*

% of Budget Tons % of Budget Tons

2012 Initial 10,160 121% 12,294 2% 203

2012 Revised 12,314 - - 2% 246

2014 Initial 10,160 121% 12,294 2% 203

2014 Revised 12,314 121% 14,900 2% 246

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit 

allocations

13) 

EPA is finalizing, as proposed, an increase Texas’s annual NOX and ozone season NOX budgets in 2012 and 2014 to reflect the assumption of nearterm operational constraints affecting units at two plants, based on information provided by the system operator demonstrating that the Western and West of 

the Atchafalaya regions are out-of-merit-order dispatch areas. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local 

conditions described in recently submitted documentation that appear likely to necessitate non-economic generation at the units displayed below during the 

implementation of the Transport Rule programs. Specifically, EPA is assuming additional generation will be dispatched at two plants (Lewis Creek and 

Sabine) based on the average capacity factor representing the frequency the unit is projected to be called to operate out-of-merit-order, derived from 

immediate-term dispatch projections provided by Entergy.

Texas (Out-of-Merit-Order Dispatch)

39

The calculations of the increase in annual and ozone season NOX emissions due to out-of-merit-order dispatch at the two facilities is shown in Table

B.13.a. For each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation from TR_Remedy 

Final_2012, and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out-of-merit-order capacity factor is shown in 

 As discussed later in this section, EPA assumes that the additional generation dispatched from 

these two facilities would offset generation that would otherwise come from combined cycle units within the state, and the revisions to Texas’s state budgets 

are based on the net change to projected emissions taking that offsetting factor into account. The net impact of these changes on the state’s annual NOX and 

ozone season NOX budgets is a 1,375 ton increase to each budget.

 39 Correspondence from Entergy to EPA, September 29, 2011. Please see the document “Transmission System Considerations – Entergy” in the docket for this rule making.
47

column H. The additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, the average out-of-merit-order capacity 

factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the incremental generation 

by the unit’s heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation was calculated by multiplying the 

additional heat input by the unit’s NOX emission rate. 

Table B.13.a.: Calculation to Determine Texas NOX* Budget Revisions - Assuming Out-of-Merit-Order Dispatch at Two Plants

A B C D E F G H I J K

Plant Name

Unique 

ID

Capacity 

(MW)

2012 Ozone 

Season NOX

Emission 

from 

TR_Remedy 

Final_2012

(1000 tons)

Heat Rate 

(BTU/kWh)

Ozone 

Season 

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Ozone 

Season NOX

Rate 

(lbs/MMBtu) 

Ozone 

Season 

Average 

Out-OfMeritOrder 

Capacity 

Factor

Additional 

Ozone Season 

Generation**

(GWh)

Additional 

Ozone 

Season 

Heat Input 

(MMBtu)

Additional 

Ozone 

Season 

NOX

Emissions 

(tons)

Calculation C*H*3.672 E*I G*J/2000

Lewis Creek

3457_ 

B_1 229 0 10325 0 0.020 47% 395.22 4,080,619 40.5

Lewis Creek

3457_ 

B_2 230 0 10600 0 0.020 55% 464.51 4,923,785 48.5

Sabine

3459_ 

B_1 230 0 11172 0 0.168 37% 312.49 3,491,107 293.8

Sabine

3459_ 

B_2 230 0 10225 0 0.152 30% 253.37 2,590,688 197.2

Sabine

3459_ 

B_3 420 0 10588 0 0.104 32% 493.52 5,225,356 271.7

Sabine

3459_ 

B_4 530 0 9800 0 0.143 45% 875.77 8,582,566 613.5

Sabine

3459_ 

B_5 480 0 10442 0 0.090 15% 264.38 2,760,698 124.8

Total 3,059.25 31,654,818 1,589.8

*Note: Since the increase in generation at these units is limited to the ozone season, the revised emissions calculated here apply equally to determination of the annual NOX and ozone-season NOX state budgets.

**The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.
48

As calculated in Table B.13.b, EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch would be offset by decreasing 

generation at Texas combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) 

equal to the generation-weighted average of Texas combined cycle units.40 The ozone season NOX emissions associated with the displaced generation 

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative combined cycle unit.

Table B.13.b.: Calculation of Emissions from Displaced Generation at Texas Combined Cycle Units*

A B C D

Program 

Period

Displaced Generation 

(GWh)

Heat Rate 

(BTU/kWh)

NOX Emission Rate 

(lbs/MMBTU)

Displaced NOX Emissions

(tons)

Calculation A*B*C/2000

Ozone Season 3,059 7,376 0.019 214

*Note: Since the increase in generation at these units is limited to the ozone season, the revised emissions calculated here apply equally to determination of the annual NOX and 

ozone-season NOX state budgets. 

The total revisions to the Texas state budgets due to out-of-merit-order dispatch are calculated in Table B.13.c. The emissions associated with the 

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the out-of-merit-order generation 

(row A) to determine the net emission budget changes for Texas (row C). 

Table B.13.c.: Calculation to Determine Net Texas Annual 

NOX and Ozone Season NOX Budget Revisions*

A

Additional Emissions Due to 

Out-Of-Order-Merit Dispatch 1,590

B

Displaced Emissions From 

Out-Of-Order-Merit Dispatch 214

C

Net Emission budget Change 

For Texas (A-B) 1,375

*Note: Since the increase in generation at these units is limited to the ozone season, 

the revised emissions calculated here apply equally to determination of the annual 

NOX and ozone-season NOX state budgets.

 40 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission 

rate averages used in Final Revisions Rule” found in the docket for this rulemaking.
49

In addition to the revisions summarized in Table B.13.c., the revisions to Texas state budgets outlined above in sections 3, 4, and 7 of this technical 

support document are summarized in Table B.13.d. The cumulative impacts of all of the technical revisions to the Texas budgets and NUSAs are 

summarized in Table B.13.e.41

Table B.13.d.: Summary of Texas SO2

Budget Revisions

Removed FGD Revision 26,359

FGD Capture Revision 24,158

Total SO2 Budget Revision 50,517

 41 The increase to the new unit set-aside would necessarily change existing unit allowance allocations in order to maintain the state budget. To review the existing unit 

allowance allocations associated with this revision, please see the document entitled “Final Revisions Rule Unit-Level Allocations under the FIPs” found in the docket to 

this rulemaking.
50

Table B.13.e.: Impact of Texas Budget Revisions – Assuming Removed FGDs and Revised FGD 

Capture at Certain Units, Revised NUSAs for Oak Grove 2, and Out-of-Merit-Order Dispatch at 

Two Facilities (tons)

Program Budget

Assurance Level

Total New Unit 

Set-Aside*

% of 

Budget Tons

% of 

Budget Tons

2012 Initial SO2 243,954 118% 287,866 5% 12,198

2012 Revised SO2 294,471 - - 5% 14,724

2014 Initial SO2 243,954 118% 287,866 5% 12,198

2014 Revised SO2 294,471 118% 347,476 5% 14,724

2012 Initial Annual NOX 133,595 118% 157,642 3% 4,008

2012 Revised Annual NOX 134,970 - - 4% 5,399

2014 Initial Annual NOX 133,595 118% 157,642 3% 4,008

2014 Revised Annual NOX 134,970 118% 159,265 4% 5,399

2012 Initial Ozone-Season NOX 63,043 121% 76,282 3% 1,891

2012 Revised Ozone-Season NOX 64,418 - - 4% 2,577

2014 Initial Ozone-Season NOX 63,043 121% 76,282 3% 1,891

2014 Revised Ozone-Season NOX 64,418 121% 77,946 4% 2,577

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations
51

Section C: Technical Revisions to States’ TR Emission Budgets and NUSAs Relevant to Direct Final Rule

1)

EPA is finalizing, based on comments, an increase to South Carolina’s 2012 and 2014 SO2 budgets to correct for the assumption that Flue Gas 

Desulfurization (FGD) technology is currently installed at the W S Lee Power Plant. There is no FGD planned or under construction at the unit. Therefore, 

EPA is finalizing an increase to the state’s 2012 and 2014 SO2 emission budgets to reflect projected emissions without these units operating a FGD. This 

results in a 8,013 ton increase to the state’s SO2 budgets in 2012 and 2014. 

South Carolina

Table C.1.a.: Calculation to Determine South Carolina Budget Adjustment 

- Assuming no FGD at W S Lee

A B C D E F

Plant Unit

Emissions 

from 

TR_Remedy

Final_2012 

(1000 tons)

HI from 

TR_Remedy_Final_2012 

(TBtu)

Remedy Emission Rate 

from from 

TR_Remedy_Final_2012 

(lbs/MMBtu)

Adjusted 

Emission 

Rate 

(lbs/MMBtu)

Adjusted 

Emissions

(1000 

tons)

Budget 

Adjustment 

(1000 tons)

Calculation A*2/B D x B/2 E - A

W S Lee 1 0.480468932 3.907141013 0.246 1.320 2.579 2.098

W S Lee 2 0.477953387 3.886684777 0.246 1.320 2.565 2.087

W S Lee 3 0.903656715 7.169244286 0.252 1.320 4.731 3.828

Total 8.013

In Table C.1.a., columns A, B, and C show the SO2 emissions, heat input, and emission rate from the TR_Remedy_Final_2012 modeling when a

FGD is assumed to be present at W S Lee. Because no FGD is present, EPA modified the emission rate to reflect the TR Base Case Final 2012 Remedy 

analysis where the FGD is assumed not to dispatch at the unit. This value approximates the emission rate expected at the unit at a cost threshold of $500/ton 

when no FGD is operating at the unit. EPA multiplied this SO2 rate by the remedy heat input shown in column B to obtain a revised emissions projection for 

the unit (column E). The difference between this revised emission projection (no FGD assumed) and the final Transport Rule remedy analysis emission 

projection (FGD assumed) determines the amount of the increase to the state’s SO2 budget (column F).

This budget change will not result in any impact to the percent of the budget set aside for new units. Under the methodology in the final Transport 

Rule, the NUSA for SO2 in South Carolina remains at 2%. The original and revised values for the state SO2 budget, assurance level, and new unit set-aside

are described in the table below.
52

Table C.1.b.: Impact of South Carolina's SO2 Budget Revision - Assuming no FGD at W 

S Lee(tons)

SO2

Budget

Assurance Level 

Total New 

Unit Set-Aside 

*

% of 

Budget Tons

% of 

Budget Tons

2012 Before Direct Final Revisions Rule 88,620 - - 2% 1,772

2012 After Direct Final Revisions Rule 96,633 - - 2% 1,933

2014 Before Direct Final Revisions Rule 88,620 118% 104,572 2% 1,772

2014 After Direct Final Revisions Rule 96,633 118% 114,027 2% 1,933

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations

2)

EPA is finalizing, based on comments, an increase to Nebraska’s 2012 and 2014 SO2 budgets to correct for the assumption that FGD technology is 

currently installed at Whelan Energy Center Unit 1. There is no FGD existing, planned, or under construction at the unit. There will likely be no FGD

available at the time of the 2012 and 2014 compliance periods as originally assumed in EPA’s determination of Nebraska’s SO2 budgets. Therefore, EPA is 

finalizing a revision the state’s 2012 and 2014 SO2 emission budgets to reflect this unit operating without an FGD. This results in a 2,334 ton increase to the 

state’s 2012 and 2014 SO2 budgets. The calculations to quantify this revision are shown in the table below.

Nebraska
53

Table C.2.a.: Calculation to Determine Nebraska Budget Adjustment - Assuming no FGD at Whelan Energy Center Unit 1

A B C D E F

Plant Unit

Emissions from 

TR_Remedy 

Final_2012 

(1000 tons)

HI from 

TR_Remedy_Final_2012 

(TBtu)

Remedy Emission Rate 

from from 

TR_Remedy_Final_2012 

(lbs/MMBtu)

Adjusted 

Emission 

Rate 

(lbs/MMBtu)

Adjusted 

Emissions

Budget 

Adjustment 

(1000 tons)

Calculation A*2/B D x B/2 E - A

Whelan 

Energy 

Center 1 0.255767801 6.394195158 0.0800 0.81 2.590 2.334

EPA is also finalizing, based on comments, a revision to Nebraska’s 2012 and 2014 SO2 budgets related to FGD technology at Whelan Energy 

Center Unit 2 and Nebraska City Unit 2. In the final Transport Rule analysis, EPA assumed these installations would be wet scrubbers; however, Nebraska 

Public Power District has informed EPA through comment that they are dry scrubbers instead.42 In its analysis of the final Transport Rule, EPA assumed 

SO2 removal rates of 95.9% for the wet scrubbers. However, dry scrubbers generally have lower SO2 removal rates. EPA revised its removal assumption 

for these two units to reflect the lower SO2 removal rates as reported by the sources themselves on EIA form 860 (95% removal for Nebraska unit 2 and 

90.5% removal for Whelan unit 2). The revised projected SO2 emissions from these units reflect the lower SO2 removal rate (and consequently higher 

emissions) than these units would be assumed to achieve with wet scrubber technology. In accordance with this revision, EPA is finalizing a 776 ton 

increase to the Nebraska’s 2012 and 2014 SO2 emission budget. 

 42 EPA-HQ-OAR-2009-0491-4754
54

Table C.2.b.: Calculation to Determine Nebraska's Annual SO2 Budget Adjustment 

- Assuming dry FGD in place of Wet FGD (1000 tons)

A B C D

Unit

Emissions 

from 

TR_Remedy 

Final_2012 

(95.9% 

removal)

Emissions 

assuming no 

FGD

Emissions 

assuming 

EIA 860 

Rates

Emission 

Adjustment

Calculation A/.041

B*.05 or 

.095 C-A

Nebraska City 2 1.142 27.854 1.393 0.251

Whelan Energy Center 2 0.399 9.732 0.925 0.526

Total 1.541 37.585 2.317 0.776

Column A shows the units’ projected emissions assuming 95.9% removal characteristic of the assumed wet scrubber. Column B shows a calculation 

of projected emissions at each unit if the previously assumed FGD removal hadn’t occurred at all; these “uncontrolled emissions” are calculated in order to 

allow application of the revised FGD removal rates of 95% for Nebraska City Unit 2 and 90.5% for Whelan Energy Center Unit 2 to the uncontrolled 

emissions, which yields the revised emission projection for each unit in column C. The difference between this revised emission projection (dry scrubbers 

assumed, column C) and the remedy emission projection (wet scrubbers assumed, column A) determines the amount of the increase to the state’s 2012 and 

2014 SO2 budget (column D). The combined impact of these two budget adjustments is a 3,110 tons increase to the state’s 2012 and 2014 SO2 budgets.

This budget change will not result in any impact to the percent of the budget set aside for new units. Under the methodology in the final Transport 

Rule, the NUSA for SO2 in Nebraska remains at 4%. The original and revised values for the state SO2 budget, assurance level, and new unit set-aside are

described in the table below.
55

Table C.2.c.: Nebraska SO2 Budget, Assurance Level, and NUSA Before and After 3,800 

SO2 Budget Adjustment

SO2

Budget

Assurance Level 

Total New Unit 

Set-Aside *

% of 

Budget Tons

% of 

Budget Tons

2012 Before Direct Final Revisions Rule 65,052 - - 4% 2,602

2012 After Direct Final Revisions Rule 68,162 - - 4% 2,726

2014 Before Direct Final Revisions Rule 65,052 118% 76,761 4% 2,602

2014 After Direct Final Revisions Rule 68,162 118% 80,431 4% 2,726

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations

3)

EPA is finalizing, based on comments, an increase to Indiana’s 2012 and 2014 SO2 budgets to correct for the assumption that FGD technology is 

currently installed at Gallagher Units 2 and 4. There is no FGD existing, planned, or under construction at the units. These units do, however, have DSI 

technology installed with an SO2 removal rate that achieves approximately 60% sulfur removal according to data reported by the sources on EIA form 860. 

Therefore, EPA is finalizing a revision to the state’s 2012 and 2014 SO2 emission budgets to reflect this unit operating with DSI instead of FGD. As noted 

by the commenter, the units are also subject to a NSR settlement agreement that imposes a .8 lbs/MMBtu limit for SO2 at the units. Therefore, EPA revised 

its assumption to ensure that with the adjustment from FGD to DSI, that the source still honored its emission rate limits. This results in a 3,465 ton increase 

to the state’s 2012 and 2014 SO2 budgets. The calculations to quantify this revision are shown in the table below.

Indiana
56

Table C.3.a.: Calculation to Determine Indiana SO2 Budget Adjustment -

Assuming DSI in place of FGD in 2012 and 2014 (1000 tons)

A B C D

Emissions 

from 

TR_Remedy 

Final_2012 

(86% 

removal)

HI from 

TR_Remedy_Final_2012 

(TBtu)

Emissions 

assuming 

.8 

lbs/MMBtu 

Emission 

Rate

Emission 

Adjustment

Calculation B*.8 C-A

Gallagher 2 1.066211595 6.957289314 2.783 1.717

Gallagher 4 1.08608673 7.08697939 2.835 1.749

Total 2.152 14.044 5.618 3.465

Column A shows the units’ projected emissions with the 86% removal rate assumed in the TR_Remedy_Final. Column B shows the heat input 

projected for each unit in the TR remedy. This heat input is multiplied by the .8 lbs/mmbtu emission rate allowed under the settlement to arrive at the 

emissions value in column C – which reflects the DSI technology rather than FGD technology. The difference between this revised emission projection

(DSI assumed, column C) and the remedy emission projection (FGD assumed, column A) determines the amount of the increase to the state’s 2012 and 2014 

SO2 budget (column D). The combined impact of these two budget adjustments is a 3,465 tons increase to the state’s 2012 and 2014 SO2 budgets.

EPA is also finalizing, based on comments, an adjustment to the 2012 and 2014 SO2 budget for Indiana based on the amount of flue gas that passes 

through the FGD at Gibson Unit 5. The commenter noted that because of this scrubber’s design limitation, the facility may be limited in the amount of flue 

gas that can be passed through the existing FGD. The Gibson unit in Indiana reports less than 100% pass-through of flue gas on EIA form 860. 

Consequently, at this unit, the effective removal rate of the FGD as applied to total SO2 emissions would be lower than the reported removal rate would 

otherwise indicate. EPA is finalizing an adjustment to the Indiana budget to account for the inability of the Gibson unit to pass all of its flue gas through its 

scrubber. Consistent with the approach EPA used to finalize similar revisions, EPA is finalizing this revision based on the SO2 removal efficiency and flue 

gas treatment data reported for these scrubbers by the facility operators to the EIA on form 860. The approach results in a final 2012 and 2014 SO2 budget 

increase of 1,873 tons.
57

Table C.3.b.: Calculation to Determine Indiana SO2 Budget Adjustment – Assuming Revised SO2 removal Rates at 

FGD

A B C D E F G

Plant 

Name

Unit 

ID

Total SO2

Emissions from 

TR_Remedy_Final

(1000 tons)

EIA 860 

Removal Rate 

(used in 

budget 

determination)

EIA 860 

Percent 

of Flue 

Gas 

Entering 

FGD

Calculated 

Removal 

Rate (used 

for budget 

revision 

estimate)

Uncontrolled 

Emissions 

(assuming 

no 

FGD)(1000 

tons)

Revised 

Emissions 

(assuming 

FGD with 

revised 

removal 

rate) (1000 

tons)

Net 

Budget 

Revision 

(1000 

tons)

Calculation B*C A/(1-B) E*(1-D) F-A

Gibson 5 4.928346201 0.95 98% 0.931 98.566924 6.8011178 1.873

Column A shows the projected emissions at the unit as originally modeled in the final Transport Rule remedy for 2012. Column B shows the SO2

removal rate that the 2012 emission projections are based on. Column C shows the source reported percent of flue gas entering FGD. Column D shows the

effective removal rate based on multiplying the removal rate by the percent of flue gas entering FGD. Column E shows a calculation of projected emissions 

at each unit if the previously assumed FGD removal hadn’t occurred at all; these “uncontrolled emissions” are calculated in order to allow application of the 

revised FGD removal rate shown in column D to these uncontrolled emissions, which yields the revised emission projection for each unit in column F. The 

difference between this revised emission projection (lower FGD capture assumed, column F) and the remedy emission projection (higher FGD capture 

assumed, column A) determines the amount of the increase to the state’s SO2 budget (column G). 

The combined impact of these two changes to Indiana’s 2012 and 2014 budget is 5,338 tons. This budget change will not result in any impact to the 

percent of the budget set aside for new units. Under the methodology in the final Transport Rule, the NUSA for SO2 in Indiana remains at 3%. The original 

and revised values for the state SO2 budget, assurance level, and new unit set-aside are described in the table below.
58

Table C.3.c: Impact of Indiana's 2012 and 2014 SO2 Budget Revision

SO2

Budget

Assurance Level 

Total New Unit 

Set-Aside *

% of 

Budget Tons

% of 

Budget Tons

2012 Before Direct Final Revisions Rule 285,424 - - 3% 8,563

2012 After Direct Final Revisions Rule 290,762 - - 3% 8,723

2014 Before Direct Final Revisions Rule 161,111 118% 190,111 3% 4,833

2014 After Direct Final Revisions Rule 166,449 118% 196,410 3% 4,993

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations

4)

EPA is finalizing, based on comments, an increase to Ohio’s 2012 and 2014 annual NOX and ozone-season NOX budgets to correct for the

assumption that Selective Catalytic Reduction (SCR) technology is currently installed at Bay Shore Unit 4 in 2012. There is no SCR planned or under 

construction at the unit. Therefore, EPA is finalizing an increase to the state’s 2012 and 2014 annual NOX and ozone-season NOX emission budgets to reflect

projected emissions without this unit operating a SCR. This results in a 2,218 ton increase to the state’s annual NOX budgets in 2012 and 2014, and a 964 

ton increase in the state’s ozone-season NOX budgets in 2012 and 2014.

Ohio

Table C.4.a.: Calculation to Determine Ohio Budget Adjustment - Assuming no SCR at Bay Shore 4

A B C D E F

Plant Unit

Emissions 

from 

TR_Remedy 

Final_2012 

(1000 tons)

HI from 

TR_Remedy_Final_2012 

(TBtu)

Remedy Emission Rate 

from from 

TR_Remedy_Final_2012 

(lbs/MMBtu)

Adjusted 

Emission 

Rate 

(lbs/MMBtu)

Adjusted 

Emissions

Budget 

Adjustment 

(1000 tons)

Calculation A*2/B D x B/2 E - A

Bay Shore 4 0.468366563 13.4995095 0.069 0.398 2.686 2.218

Bay Shore 4 0.203626114 5.86901984 0.069 0.398 1.168 0.964
59

Columns A, B, and C show the NOX emissions, heat input, and emission rate from the TR_Remedy_Final_2012 modeling when a SCR is assumed 

to be present the unit. Because no SCR is present, EPA modified the emission rate to reflect the “controlled NOX policy rate” in the NEEDS version from 

the September 1, 2010 TR Notice of Data Availability (NODA) (column D).43

This budget change will not result in any impact to the percent of the budget set aside for new units. Under the methodology in the final Transport 

Rule, the NUSAs for annual NOX and ozone-season NOX in Ohio remain at 2%. Along with revisions accounting for out-of-merit order dispatch at units in 

Ohio presented below, the original and revised values for the state budgets, assurance levels, and new unit set-asides are described in Table C.18.g.

 This value reflects the NOX emission rate assumed in EPA’s modeling of the 

Transport Rule as originally proposed, when EPA did not assume a SCR to be present at the unit. This value approximates the emission rate expected at the 

unit at a cost threshold of $500/ton when no SCR is present at the unit. EPA multiplied this NOX rate by the remedy heat input shown in column B to obtain

a revised emissions projection for the unit (column E). The difference between this revised emission projection (no SCR assumed) and the final Transport 

Rule remedy analysis emission projection (SCR assumed) determines the amount of the increase to the state’s annual NOX and ozone-season NOX budget 

(column F). The first row shows the calculation for the annual NOx budget adjustment and the second row shows the calculation for ozone season NOx 

adjustment.

5)

EPA is finalizing, based on comments, an increase to New York’s 2012 and 2014 SO2 budgets to correct for the removal rate assumption regarding 

DSI technology at the Dunkirk and Huntley facilities. As noted in the “Significant Contribution and State Emissions Budgets Final Rule TSD" for the final 

Transport Rule, EPA had received comment during the rule proposal noting that these facilities had DSI in place of the FGD assumed in the modeling. EPA 

adjusted the state budgets before finalizing the Transport Rule to reflect DSI technology. Because no verifiable removal rate was submitted for the 

technologies in the comment at this time, EPA assumed the default 70% removal rate used for new DSI. However, during the comment period for the 

Revisions Rule, a commenter noted that these units’ existing DSI systems are not capable of achieving such a rate. The commenter’s claim is corroborated 

by newly available 2010 EIA 860 data providing a reported SO2 removal rate of 53% for the units. EPA has calculated a budget adjustment to New York’s 

SO2 budgets in 2012 and 2014 assuming an SO2 removal rate of 53% as opposed to the 70% rate previously assumed in the final Transport Rule at these 

units.

New York

 43 See National Electric Energy Data System (NEEDS) v4.10 available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html
60

Table C.5.a.: Calculation to Determine New York Budget Adjustment - Correcting for DSI Removal Rates

A B C D E

Unit

Removal Rate Assumed 

in 

TR_Remedy_Final_2012

Emissions from 

TR_Remedy 

Final_2012 (1000 

tons)

Emissions 

assuming 70% 

removal (1000 

tons)

Emissions 

Assuming 53% 

removal (1000 

tons)

Net Budget 

Adjustment (1000 

tons)

Calculation B/(1-A)*.3 B/(1-A)*.47 D-C

C R Huntley Generating 

Station 67 92.3% 0.340946408 1.328362629 2.081101451 0.752738823

C R Huntley Generating 

Station 68 92.3% 0.340946408 1.328362629 2.081101451 0.752738823

Dunkirk Generating Station 3 95.9% 0.383454384 2.805763788 4.3956966 1.589932813

Dunkirk Generating Station 4 95.9% 0.38488252 2.81621356 4.41206791 1.59585435

Dunkirk Generating Station 1 70.0% 0.623572839 0.623572839 0.976930781 0.353357942

Dunkirk Generating Station 2 70.0% 0.55670215 0.55670215 0.872166702 0.315464552

Total 2.63050471 9.458977594 14.8190649 5.360

Column A and B show the removal rate and corresponding emissions assumed in the initial TR_Final_Rule modeling. Column C shows the 

adjusted emissions assuming 70% removal efficiency that was assumed for the Final Transport Rule Budget determination. Column D shows the emission 

for these units assuming a 53% removal rate (as reported in the EIA 860 form for the units). Column E shows the net budget adjustment necessary to correct 

the 70% removal efficiency with a 53% removal efficiency for the DSI present at the facilities. This results in a 5,360 ton increase to the state’s SO2 budget 

for 2012 and 2014. 

This budget change will not result in any impact to the percent of the budget set aside for new units. Under the methodology in the final Transport 

Rule, the NUSA for SO2 in New York remains at 2%. Along with revisions accounting for out-of-merit order dispatch at units in New York presented 

below, the original and revised values for the state budgets, assurance levels, and new unit set-asides are described in Table C.19.g.

6)

EPA is finalizing, based on comment, an update to Kansas’s 2014 annual NOX budget to correct for the assumption that particular Westar consent 

decree emission rate and tonnage cap requirements begin in 2015, not 2014 as assumed in the final rule analysis. The final 2014 Transport Rule modeling 

applied SCR retrofit technology to some capacity at the Jeffrey Energy Center to comply with the 0.1 lb/MMBtu rate requirement of the Westar consent 

Kansas
61

decree; however, because this rate requirement does not begin until 2015, EPA is assuming that the emission rate requirements of the consent decree do not 

result in any new controls until 2015 at the Jeffrey Energy Center. This revised assumption would, if examined in isolation, yield an increase of 6,465 tons 

in projected annual NOX emissions in Kansas in 2014, which would bring total projected NOX emissions from covered EGUs in Kansas to a level that 

exceeds the state’s 2012 budget. However, as explained in the final Transport Rule, “for any covered state whose emissions of a relevant pollutant are 

projected to increase from 2012 to 2014 under the relevant cost thresholds... EPA is finalizing that state’s 2014 emission budget to maintain the same level 

of the 2012 emission budget” (76 FR 48261). Therefore, EPA is increasing the 2014 Kansas NOX budget by 5,154 tons so that it matches, not exceeds, the 

state’s 2012 budget following the methodology and rationale laid out in the final Transport Rule.

This budget change will not result in any impact to the percent of the budget set aside for new units. Under the methodology in the final Transport 

Rule, the NUSA for annual NOX in Kansas remains at 2%. Along with revisions accounting for out-of-merit order dispatch at units in Kansas presented 

below, the original and revised values for the state budgets, assurance levels, and new unit set-asides are described in Table C.14.f.

7)

EPA is finalizing, based on comment, an update to Georgia’s 2014 SO2, annual NOX, and ozone-season NOX state budgets to correct for the 

assumption in the final Transport Rule analysis that particular Georgia Multi-Pollutant State Rule control deadlines for FGD/SCR retrofits at Branch, 

Scherer, and Yates facilities would deliver emission reductions in 2014, whereas those reductions are in fact not required to occur until 12/31/2014 or later. 

Because these controls are not required by that state rule to operate in 2014, EPA is adjusting the 2014 budgets upwards to reflect the non-operation of the 

controls at these units.

Georgia

44 

 44 EPA based these revisions on the schedule of retrofit deadlines that is most consistent with comments provided, which generally reflected the requirements of the 

Georgia Multi-Pollutant State Rule as it existed when EPA finalized the Transport Rule in July of 2011.
62

Table C.7.a.: Calculation to Determine Georgia SO2 Budget Adjustments - Assuming Revised Control Start 

Dates

SO2

A B C D E

2012 Emission Rate from 

TR_Remedy_Final 

(lbs/MMBtu)

2014 Heat 

Input (TBtu)

2014 Revised 

Emissions 

(1000 tons)

2014 

TR_Remedy_Final 

Emissions (1000 tons)

Net Budget 

Adjustment

(1000 tons)

Calculation A x B C - D

Branch 1 0.92 16.50 7.60 1.85 5.74

Branch 2 0.92 20.06 9.24 2.25 6.99

Scherer 1 0.57 57.61 16.49 6.43 10.06

Yates 6 0.91 21.23 9.70 0.86 8.84

Yates 7 0.91 20.89 9.55 0.85 8.70

Total 40.334

Table C.7.b.: Calculation to Determine Georgia NOX Budget Adjustments - Assuming Revised Control Start 

Dates

Annual NOX

A B C D E

2012 Emission Rate from 

TR_Remedy_Final 

(lbs/MMBtu)

2014 Heat 

Input (TBtu)

2014 Revised 

Emissions 

(1000 tons)

2014 

TR_Remedy_Final 

Emissions (1000 tons)

Net Budget 

Adjustment

(1000 tons)

Calculation A x B C - D

Branch 1 0.45 16.50 3.75 0.60 3.15

Branch 2 0.43 20.06 4.36 0.69 3.67

Scherer 1 0.15 57.61 4.20 2.02 2.18

Yates 6 0.26 21.23 2.80 0.73 2.07

Yates 7 0.28 20.89 2.88 0.75 2.13

Total 13.198
63

Table C.7.c.: Calculation to Determine Georgia Ozone-Season NOX Budget Adjustments - Assuming Revised 

Control Start Dates

Ozone-Season NOX

A B C D E

2012 Emission Rate from 

TR_Remedy_Final 

(lbs/MMBtu)

2014 Heat 

Input (TBtu)

2014 Revised 

Emissions 

(1000 tons)

2014 

TR_Remedy_Final 

Emissions (1000 tons)

Net Budget 

Adjustment

(1000 tons)

Calculation A x B C - D

Branch 1 0.45 7.19 1.63 0.26 1.37

Branch 2 0.43 8.74 1.90 0.30 1.60

Scherer 1 0.15 25.29 1.84 0.89 0.96

Yates 6 0.26 9.27 1.22 0.32 0.91

Yates 7 0.28 9.12 1.26 0.33 0.93

Total 5.762

In each of the above tables, column A reflects the emission rate observed for that unit in the 2012 TR_Remedy_Final when no FGD or SCR is 

present. Column B reflects the heat input assumed in the 2014 TR_Remedy_Final analysis when a FGD or SCR was assumed to be present. Column C 

multiplies the heat input by the uncontrolled emission rate to get the uncontrolled emission rate assumption for 2014. The difference between this 

uncontrolled emissions values (column C) and the controlled emissions value originally assumed (column D) results in the amount of the budget increase 

(column E).

This budget change will not result in any impact to the percent of the budget set aside for new units. Under the methodology in the final Transport 

Rule, the NUSA for SO2 in Georgia remains at 2%. The original and revised values for the state budgets, assurance levels, and new unit set-asides are

described in the table below.
64

Table C.7.d.: Impact of Georgia's Budget Revisions - Assuming Revised Control Start Dates

Program Budget

Assurance Level 

Total New Unit 

Set-Aside *

% of 

Budget Tons

% of 

Budget Tons

2012 Before Direct Final Revisions Rule SO2 158,527 - - 2% 3,171

2012 After Direct Final Revisions Rule SO2 158,527 - - 2% 3,171

2014 Before Direct Final Revisions Rule SO2 95,231 118% 112,373 2% 1,905

2014 After Direct Final Revisions Rule SO2 135,565 118% 159,967 2% 2,711

2012 Before Direct Final Revisions Rule Annual NOX 62,010 - - 2% 1,240

2012 After Direct Final Revisions Rule Annual NOX 62,010 - - 2% 1,240

2014 Before Direct Final Revisions Rule Annual NOX 40,540 118% 47,837 2% 811

2014 After Direct Final Revisions Rule Annual NOX 53,738 118% 63,411 2% 1,075

2012 Before Direct Final Revisions Rule Ozone-Season NOX 27,944 - - 2% 559

2012 After Direct Final Revisions Rule Ozone-Season NOX 27,944 - - 2% 559

2014 Before Direct Final Revisions Rule Ozone-Season NOX 18,279 121% 22,118 2% 366

2014 After Direct Final Revisions Rule Ozone-Season NOX 24,041 121% 29,090 2% 481

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations

Turk Unit 1 in Arkansas commences commercial operation on or after January 1, 2010. Such a date qualifies Turk Unit 1 as a “planned” new unit 

by the definition of that category described in the “Allowance Allocation Final Rule TSD” for the final Transport Rule. However, in the final Transport 

Rule, EPA did not recognize Turk Unit 1 as a new unit and therefore omitted its projected emissions in the determination of the ozone-season NOX new unit 

set-aside for Arkansas. Prior to this revision, in keeping with a revision demonstrated above and effected in the final revisions rule, that state’s NUSA was 

set at 5%, including the minimum 2% NUSA percentage plus a 3% state-specific percentage to account for other planned units.

8) Arkansas (NUSA)

45

 45 As explained in the final Transport Rule, the minimum size of any state’s new unit set-aside is this “base percentage” amount, to which “state-specific” percentages are 

added if the given state has projected emissions from “planned” new units (76 FR 48291).

 EPA is now revising the 

calculation of the Arkansas ozone-season NOX new unit set-aside to reflect the “new unit” status of Turk Unit 1. Following the schedule established in the 
65

final Transport Rule, EPA has already recorded (i.e., distributed) allowances under the Federal Implementation Plan (FIP) for Arkansas for 2012 and 2013. 

Therefore, this revision to the NUSA will be implemented beginning in 2014.

The calculations to estimate 2020 ozone-season NOX Emissions from Turk Unit 1 are shown in the table below:

Table C.8.a.: Calculation for Arkansas' Total Ozone-Season 

NOX Emissions from Turk Unit 146

A Capacity (MW) 600

B Heat Rate (Btu/kWh) 8980

C NOX Emissions Rate (lbs/MMBtu) 0.05

D Capacity Factor 85%

E Ozone-Season Hours 3672

Total Ozone-Season NOX Emissions (tons) 

(A*D*B/1000*E*C/2000) 420

The calculations to quantify this revision are shown in the table below:

Table C.8.b.: Calculation for Arkansas' NUSA 

A

Projected 2020 Ozone-Season NOX Emissions from Turk Unit 

1 (tons) 420

B Arkansas 2014 Ozone-Season NOX State Budget (tons) 15,110

C Turk's Emissions as a % of Arkansas State Budget (A/B) 3%

D Previous Percentage for New Unit Set-Aside 5%

E Total New Unit Set-Aside (C + D) 8%

EPA divided Turk Unit 1’s projected emissions into the state budget to derive the state-specific percentage increase for the new unit set-aside in 

Arkansas, which rounds to 3%. This value was added to the new unit set-aside percentage previously calculated for the final revisions rule (5%) found 

 46 Projected 2020 ozone-season NOX emissions were estimated and the new unit set-aside was calculated using the method outlined in the final Transport Rule (76 FR 

48291) and the Technical Revisions to State Budgets and New Unit Set-Asides associated with the Final Rule. EPA used data provided by the commenter and IPM model 

plant assumptions.
66

earlier in this document. The resulting new unit set-aside percentage for ozone-season NOX in Arkansas is 8%. This change does not impact the state budget 

or assurance level in any way. However, the new unit set-aside would change by the levels shown below.47

Table C.8.c: Impact of 2014 Ozone Season NOX NUSA revision for Arkansas 

New Unit SetAside

Existing 

Unit 

Allocation Total

2014 As Finalized in Final Revisions Rule % 5% 95% 100%

2014 With Direct Final Rule Revision % 8% 92% 100%

2014 As Finalized in Final Revisions Rule tons 752 14,285 15,037

2014 With Direct Final Rule Revision tons* 1,209 13,901 15,110

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations

9)

Washington Parish Energy Center Units CTG1, CTG2 and ST1 were included in the final Transport Rule NUSA calculations as planned units to 

commence commercial operation on or after January 1, 2010. However, these units were never completed and will not be operating. Therefore, EPA is 

removing their projected emissions from calculations for the Louisiana ozone-season NOX NUSA. Prior to this revision, that state’s NUSA was set at 3%, 

including the minimum 2% NUSA percentage plus a 1% state-specific percentage to account for planned units.

Louisiana (NUSA)

48 EPA is now revising the calculation of the 

Louisiana ozone-season NOX new unit set-aside to remove the projected emissions of these units that will not be commencing operation. This change will 

take effect for Louisiana’s NUSA in 2012 and beyond.

49

 47 The increase to the new unit set-aside would necessarily change existing unit allowance allocations in order to maintain the state budget. To review the existing unit 

allowance allocations associated with this revision, please see the document entitled “Final Revisions Rule Unit-Level Allocations under the FIPs” found in the docket to 

this rulemaking.

48 As explained in the final Transport Rule, the minimum size of any state’s new unit set-aside is this “base percentage” amount, to which “state-specific” percentages are 

added if the given state has projected emissions from “planned” new units (76 FR 48291). 49 The originally projected emissions from Washington Parish Energy Center are no longer relevant to any of EPA’s emission projections for the state of Louisiana pertinent 

to the Transport Rule, as all of its projected generation was offset in the final revisions rule by revised assumptions of increased generation from other Louisiana units due to 

near-term out-of-merit-order dispatch conditions.
67

EPA subtracted the Washington Parish units’ projected emissions from the projected planned unit emissions for Louisiana. The remaining planned 

emissions were divided into the state budget to derive the revised state-specific percentage for the new unit set-aside in Louisiana, which rounds to 0%. 

Therefore, the new unit set-aside percentage for ozone-season NOX in Louisiana is 2%, the base percentage for the new unit set-aside. 

Table C.9.a.: Calculation for Louisiana's NUSA 

A Previously Calculated Total Planned Emissions (tons) 126

B Projected 2020 Ozone-Season NOX Emissions from Washington Parish (tons) 68

C Remaining Planned Emissions (A - B) 58

D Louisiana Ozone Season NOX State Budget (tons) 18,136

E Remaining Committed Emissions as a % of Arkansas State Budget (C/D) 0%

F Base percentage for new unit set-aside 2%

G Total New Unit Set-Aside (E + F\) 2%

This change does not impact the state budget or assurance level in any way. However, the new unit set-aside would change by the levels shown 

below.50 EPA intends to record any additional 2012 and 2013 allocations to existing units due to this revision once this rule, and the underlying final 

Transport Rule, are legally effective.

 50 The proposed decrease to the new unit set-aside would necessarily change existing unit allowance allocations in order to maintain the state budget. To review the existing 

unit allowance allocations associated with this revision, please see the document entitled “Final Revisions Rule Unit-Level Allocations under the FIPs” found in the docket 

to this rulemaking.
68

Table C.9.b: Impact of 2012 Ozone Season NOX NUSA revision for Louisiana

New Unit SetAsideExisting Unit 

Allocation Total

2012 As Finalized in Final Revisions Rule % 3% 97% 100%

2012 With Direct Final Rule Revision % 2% 98% 100%

2012 As Finalized in Final Revisions Rule tons 523 17,503 18,026

2012 With Direct Final Rule Revision tons* 344 17,771 18,115

2014 As Finalized in Final Revisions Rule % 3% 97% 100%

2014 With Direct Final Rule Revision % 2% 98% 100%

2014 As Finalized in Final Revisions Rule tons 523 17,503 18,026

2014 With Direct Final Rule Revision tons* 344 17,771 18,115

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations

10)

Iatan Unit 2 in Missouri commenced commercial operation on or after January 1, 2010. Such a date qualifies Iatan Unit 2 as a “planned” new unit 

by the definition of that category described in the “Allowance Allocation Final Rule TSD” for the final Transport Rule. However, in the final Transport 

Rule, EPA did not recognize Iatan Unit 2 as a new unit and therefore omitted its projected emissions in the determination of the SO2, annual NOX and ozoneseason NOX new unit set-asides for Missouri. For the final Transport Rule and the Transport Rule Supplemental Notice of Final Rulemaking, the state’s 

NUSAs were set at 2% for SO2, 3% for annual NOX and 3% for ozone-season NOX, including the minimum 2% NUSA percentage plus a state-specific 

percentage for each budget.

Missouri (NUSA)

51

 51 As explained in the final Transport Rule, the minimum size of any state’s new unit set-aside is this “base percentage” amount, to which “state-specific” percentages are 

added if the given state has projected emissions from “planned” new units (76 FR 48291).

 EPA is now revising the calculations of the Missouri new unit set-asides to reflect the “new unit” status of Iatan Unit 2. 

Following the schedule established in the final Transport Rule, EPA has already recorded (i.e., distributed) allowances under the FIPs for Missouri for 2012. 

Therefore, this revision to the NUSAs will be implemented beginning in 2013.
69

The calculations to quantify Projected 2020 Emissions from Turk Unit 1 are shown in the table below52:

Table C.10.a.: Calculation for Missouri's NUSA 

SO2 NOX

Ozone 

Season NOX

A Capacity (MW) 850 850 850

B Heat Rate (Btu/kWh) 9000 9000 9000

C Emissions Rate (lbs/MMBtu) 0.06 0.05 0.05

D Capacity Factor 85% 85% 85%

E Ozone Season Hours 8760 8760 3672

Total Emissions (tons) (A*D*B/1000*E*C/2000) 1709 1424 598

EPA divided Iatan Unit 2’s projected emissions into the state budgets to derive the increases to the state-specific percentages for the new unit setasides in Missouri, which round to 1% for SO2, 3% for annual NOX and 3% for ozone-season NOX. These values were added to the existing percentages for 

new unit set-asides from the final Transport Rule and the Transport Rule Supplemental Notice of Final Rulemaking . The resulting new unit set-aside 

percentages in Missouri are 3% for SO2, 6% for annual NOX and 6% for ozone-season NOX. This change does not impact the state budget or assurance level 

in any way. However, the NUSAs would change by the levels shown below.53

 52 Projected 2020 ozone-season NOX emissions were calculated using the method outlined in the final Transport Rule (76 FR 48291) and the Technical Revisions to State 

Budgets and New Unit Set-Asides associated with the Final Rule. EPA used data provided by the commenter, IPM model plant assumptions and plant data published in the 

following: Robert Peltier, Plant of the Year: KCP&L’s Iatan 2 Earn’s POWER’s Highest Honor, Power Magazine, August 1, 2011, available on the internet at 

<http://www.powermag.com/environmental/3882.html>. 53 The increase to the new unit set-aside would necessarily change existing unit allowance allocations in order to maintain the state budget. To review the existing unit 

allowance allocations associated with this revision, please see the document entitled “Final Revisions Rule Unit-Level Allocations under the FIPs” found in the docket to 

this rulemaking.
70

Table C.10.b: Impact of 2013 NUSA revisions for Missouri (tons)

SO2 New 

Unit SetAside

SO2 Existing 

Unit 

Allocation SO2 Total

Annual NOX

New Unit 

Set-Aside

Annual NOX

Existing Unit 

Allocation

Annual NOX

Total

OS NOX New 

Unit Set-Aside

OS NOX

Existing Unit 

Allocation

OS NOX

Total

% As Finalized in Final 

Revisions Rule 2% 98% 100% 3% 97% 100% 3% 97% 100%

% With Direct Final Rule 

Revision 3% 97% 100% 6% 94% 100% 6% 94% 100%

2013 As Finalized in Final 

Revisions Rule tons 4,149 203,317 207,466 1,571 50,803 52,374 683 22,079 22,762

2013 With Direct Final 

Rule Revision tons* 6,224 201,242 207,466 3,144 49,256 52,400 1,367 21,421 22,788

2014 As Finalized in Final 

Revisions Rule tons 3,319 162,622 165,941 1,462 47,255 48,717 632 20,441 21,073

2014 With Direct Final 

Rule Revision tons* 4,978 160,963 165,941 2,925 45,818 48,743 1,266 19,833 21,099

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations

11) 

EPA is finalizing, based on comments, an increase to Mississippi’s ozone season NOX budget in 2012 and 2014 to reflect the assumption of nearterm operational constraints affecting a unit at the Moselle plant, based on information provided by the system operator demonstrating that the plant is 

located in an out-of-merit-order dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local conditions described 

in recently submitted documentation that appear likely to necessitate non-economic generation at the units displayed below during the implementation of the 

Transport Rule programs. Specifically, EPA is assuming additional generation will be dispatched at Moselle based on the need to provide voltage support 

and regulation in the load pocket and the minimum operating constraint of a unit at Moselle.

Mississippi

54

 54 EPA-HQ-OAR-2009-0491-4763 and EPA-HQ-OAR-2009-0491-4746

 As discussed later in this section, EPA assumes that the 

additional generation dispatched from this facility would offset generation that would otherwise come from combined cycle units within the state, and the 
71

revision to Mississippi’s state budget is based on the net change to projected emissions taking that offsetting factor into account. The net impact of these 

changes on the state’s ozone season NOX budget is a 115 ton increase.

The calculations of the increase in ozone season NOX emissions due to out-of-merit-order dispatch at Moselle is shown in Table C.11.a. For the unit, 

the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation from TR_Remedy Final_2012, and emission rate from EPA’s NEEDS 

database are shown (columns A to G). The average out-of-merit-order capacity factor is shown in column H. The additional generation for out-of-meritorder dispatch was calculated by multiplying the capacity, the average out-of-merit-order capacity factor, and the number of hours in the ozone season 

(column I). The additional heat input required was calculated by multiplying the incremental generation by the unit’s heat rate (column J). Finally, the 

additional emissions associated with the out-of-merit-order generation was calculated by multiplying the additional heat input by the unit’s NOX emission 

rate. 

Table C.11.a.: Calculation to Determine Mississippi Ozone Season NOX Budget Revisions - Assuming out-of-merit-order dispatch at plant 

Moselle

A B C D E F G H I J K

Plant Name

Unique 

Id

Capacity 

(MW)

2012 Ozone 

Season NOX

Emissions

from 

TR_Remedy 

Final_2012

(1000 tons)

Heat Rate 

(BTU/

kWh)

Ozone 

Season 

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Ozone 

Season NOX

Rate 

(lbs/MMBtu) 

Ozone Season 

Average OutOf-MeritOrder 

Capacity 

Factor 

Additional 

Ozone 

Season 

Generation*

Additional 

Ozone 

Season 

Heat Input 

(MMBtu)

Additional 

Ozone 

Season 

NOX

Emissions 

(tons)

Calculation C*H*3.672 E*I G*J/2000

Moselle 2070_B_2 59 0 12878 0 0.258 34% 73.66 948,598 122.5

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.

As calculated in Table C.11.b, EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch would be offset by decreasing 

generation at Mississippi combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) 

equal to the generation-weighted average of Mississippi combined cycle units.55

 55 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission 

rate averages used in Revisions Rule Part II” found in the docket for this rulemaking.

The ozone season NOX emissions associated with the displaced generation 

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative combined cycle unit. 
72

Table C.11.b.: Calculation of Emissions from Displaced Generation at Mississippi Combined Cycle Units

A B C D

Program 

Period

Displaced Generation 

(GWh)

Heat Rate 

(BTU/kWh)

NOX Emission Rate 

(lbs/MMBTU)

Displaced NOX Emissions

(tons)

Calculation A*B*C/2000

Ozone Season 74 7,570 0.026054137 7

The total revision to Mississippi’s state budget due to the out-of-merit-order dispatch is calculated in Table C.11.c. The emissions associated with 

the generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the out-of-merit-order 

generation (row A) to determine the net emission budget changes for Mississippi (row C). 

Table C.11.c.: Calculation to Determine Net Mississippi

Ozone Season NOX Budget Revisions

A

Additional Emissions Due to 

Out-Of-Order-Merit Dispatch 123

B

Displaced Emissions From 

Out-Of-Order-Merit Dispatch 7

C

Net Change in Emission 

budget For Mississippi (A-B) 115
73

The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are described in Table C.11.d.

Table C.11.d.: Impact of Mississippi Ozone-Season NOX Budget Revisions – Assuming 

Out-of-Merit-Order Dispatch at Three Facilities (tons)

Budget

Assurance Level

Total New 

Unit SetAside*

% of 

Budget Tons

% of 

Budget Tons

2012 Before Direct Final Revisions Rule 12,314 - - 2% 246

2012 After Direct Final Revisions Rule 12,429 - - 2% 249

2014 Before Direct Final Revisions Rule 12,314 12,314 151,634,596 2% 246

2014 After Direct Final Revisions Rule 12,429 12,429 154,480,041 2% 249

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit 

allocations

12) 

EPA is finalizing, based on comments, an increase to Arkansas’s ozone season NOX budget in 2012 and 2014 to reflect the assumption of near-term 

operational constraints affecting units at the McClellan plant, based on information provided by the system operator demonstrating that the South Arkansas 

Region is an out-of-merit-order dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local conditions described 

in recently submitted documentation that appear likely to necessitate non-economic generation at the units displayed below during the implementation of the 

Transport Rule programs. Specifically, EPA is assuming additional generation will be dispatched the McClellan plant based on the average capacity factor 

representing the frequency the unit is projected to be called to operate out-of-merit-order, derived from immediate-term dispatch modeling projections 

provided by Entergy.

Arkansas

56

 56 EPA-HQ-OAR-2009-0491-4820 and Correspondence from Entergy to EPA, September 29, 2011. Please see the document “Transmission System Considerations –

Entergy” in the docket for this rule making. 

 As discussed later in this section, EPA assumes that the additional generation dispatched from this facility would offset generation 

that would otherwise come from combined cycle units within the state, and the revision to Arkansas’s state budget is based on the net change to projected 

emissions taking that offsetting factor into account. The net impact of these changes on the state’s ozone season NOX budget is a 73 ton increase.
74

The calculations of the increase in ozone season NOX emissions due to out-of-merit-order dispatch at McClellan is shown in Table C.12.a. For the 

unit, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation from TR_Remedy Final_2012, and emission rate from EPA’s NEEDS 

database are shown (columns A to G). The average out-of-merit-order capacity factor is shown in column H. The additional generation for out-of-meritorder dispatch was calculated by multiplying the capacity, the average out-of-merit-order capacity factor, and the number of hours in the ozone season 

(column I). The additional heat input required was calculated by multiplying the incremental generation by the unit’s heat rate (column J). Finally, the 

additional emissions associated with the out-of-merit-order generation was calculated by multiplying the additional heat input by the unit’s NOX emission 

rate. 

Table C.12.a.: Calculation to Determine Arkansas Ozone Season NOX Budget Revisions - Assuming out-of-merit-order dispatch at McClellan

A B C D E F G H I J K

Plant Name

Unique 

Id

Capacity 

(MW)

2012 Ozone 

Season NOX

Emissions

from 

TR_Remedy 

Final_2012

(1000 tons)

Heat Rate 

(BTU/kW

h)

Ozone 

Season 

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Ozone 

Season NOX

Rate 

(lbs/MMBtu) 

Ozone Season 

Average OutOf-MeritOrder 

Capacity 

Factor 

Additional 

Ozone 

Season 

Generation*

Additional 

Ozone 

Season 

Heat Input 

(MMBtu)

Additional 

Ozone 

Season 

NOX

Emissions 

(tons)

Calculation C*H*3.672 E*I G*J/2000

McClellan 203_B_01 134 0 10901 0 0.20229893 16% 78.73 858,210 86.8

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.

As calculated in Table C.12.b., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch would be offset by decreasing 

generation at Arkansas combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) 

equal to the generation-weighted average of Arkansas combined cycle units.57 The ozone season NOX emissions associated with the displaced generation 

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative combined cycle unit. 

 57 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission 

rate averages used in Revisions Rule Part II” found in the docket for this rulemaking.
75

Table C.12.b.: Calculation of Emissions from Displaced Generation at Arkansas Combined Cycle Units

A B C D

Program 

Period

Displaced Generation 

(GWh)

Heat Rate 

(BTU/kWh)

NOX Emission Rate 

(lbs/MMBTU)

Displaced NOX Emissions

(tons)

Calculation A*B*C/2000

Ozone Season 79 7,549 0.044891435 13

The total revision to Arkansas’s state budget due to the out-of-merit-order dispatch is calculated in Table C.12.c. The emissions associated with the 

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the out-of-merit-order generation 

(row A) to determine the net emission budget changes for Arkansas (row C). 

Table C.12.c.: Calculation to Determine Net Arkansas 

Ozone Season NOX Budget Revisions (tons)

A

Additional Emissions Due to 

Out-Of-Order-Merit Dispatch 87

B

Displaced Emissions From 

Out-Of-Order-Merit Dispatch 13

C

Net Change in Emission 

budget For Arkansas (A-B) 73
76

The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are described in Table C.12.d.

Table C.12.d.: Impact of Arkansas Ozone-Season NOX Budget Revisions –

Assuming Out-of-Merit-Order Dispatch at McClellan (tons)

Budget

Assurance 

Level

Total New 

Unit SetAside*

% of 

Budget Tons

% of 

Budget Tons

2012 Before Direct Final Revisions Rule 15,037 - - 5% 752

2012 After Direct Final Revisions Rule 15,110 - - 5% 756

2014 Before Direct Final Revisions Rule 15,037 121% 18,195 5% 752

2014 After Direct Final Revisions Rule 15,110 121% 18,283 8% 1,209

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit 

allocations

13) 

EPA is finalizing, based on comments, an increase to Texas’s annual and ozone season NOX budget in 2012 and 2014 to reflect the assumption of 

near-term operational constraints affecting units at seven plants, based on information provided by the system operator demonstrating these plants are in an 

out-of-merit-order dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local conditions described in recently 

submitted documentation that appear likely to necessitate non-economic generation at the units displayed below during the implementation of the Transport 

Rule programs. Specifically, EPA is assuming additional generation will be dispatched at seven plants (Jones, Moore County, Nichols, Plant X, Wilkes, 

Lone Star, and Knox Lee) based on the average capacity factor representing the frequency the unit is projected to be called to operate out-of-merit-order, 

derived from immediate-term dispatch modeling projections provided by SPS

Texas

58 and AEP.59

 58 EPA-HQ-OAR-2009-0491-4752 and the document “Clarification of comments originally filed on the TR Revisions Rule by SPS” found in the docket for this rulemaking.

 As discussed later in this section, EPA assumes that the

59 EPA-HQ-OAR-2009-0491-4737, EPA-HQ-OAR-2009-0491-4801, and the document “Clarification of comments originally filed on the TR Revisions Rule by AEP”

found in the docket for this rulemaking.
77

additional generation dispatched from these seven facilities would offset generation that would otherwise come from combined cycle units within the state, 

and the revision to Texas’s state budget is based on the net change to projected emissions taking that offsetting factor into account. The net impact of these 

changes on the state’s annual NOX and ozone season NOX budgets are 2,731 and 1,142 ton increases, respectively.

The calculations of the increase in annual NOX and ozone season NOX emissions due to out-of-merit-order dispatch at the seven plants is shown in 

Tables C.13.a. and C.13.b. For each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation 

from TR_Remedy Final_2012, and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out-of-merit-order capacity factor 

is shown in column H. The additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, the average out-of-merit-order 

capacity factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the incremental 

generation by the unit’s heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation was calculated by 

multiplying the additional heat input by the unit’s NOX emission rate. 

Table C.13.a.: Calculation to Determine Texas Annual NOX Budget Revisions - Assuming out-of-merit-order dispatch at seven plants

A B C D E F G H I J K

Plant Name

Unique 

Id

Capacity 

(MW)

2012 Annual

NOX

Emissions

from 

TR_Remedy 

Final_2012

(1000 tons)

Heat Rate 

(BTU/kW

h)

Annual 

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Annual NOX

Rate 

(lbs/MMBtu) 

Annual

Average OutOf-MeritOrder 

Capacity 

Factor 

Additional 

Annual

Generation*

Additional 

Annual 

Heat Input 

(MMBtu)

Additional 

Annual

NOX

Emissions 

(tons)

Calculation C*H*8.760 E*I G*J/2000

Jones 3482_B

_151B 243 0.17811372 11109 283.774892 0.11 41% 881.00 9,787,029 550.7

Jones 3482_B

_152B 243 0.119198228 10245 283.774892 0.08 50% 1069.00 10,951,905 449.5

Moore 

County

3483_B

_3 48 0 14075 0 0.12 20% 82.00 1,154,150 69.4

Nichols 3484_B 107 0.074400425 9983 125.737030 0.12 29% 276.00 2,755,308 162.8
78

_141B

Nichols 3484_B

_142B 106 0.07774879 10450 124.561917 0.12 32% 296.00 3,093,200 184.2

Nichols 3484_B

_143B 244 0 11682 0 0.16 27% 572.00 6,682,104 548.8

Plant X 3485_B

_111B 48 0 16243 0 0.32 23% 98.00 1,591,814 252.5

Plant X 3485_B

_112B 102 0 13226 0 0.08 18% 162.00 2,142,612 89.8

Plant X 3485_B

_113B 103 0 11484 0 0.17 20% 182.00 2,090,088 173.7

Plant X 3485_B

_114B 189 0 10841 0 0.10 53% 881.00 9,550,921 487.0

Knox Lee 3476_B

_2 25.0 0 14500 0 0.102 2% 4.80 69,588 3.5

Knox Lee 3476_B

_3 25.0 0 14500 0 0.123 3% 6.68 96,879 6.0

Knox Lee 3476_B

_4 77.0 0 14933 0 0.311 1% 9.84 146,910 22.9

Knox Lee 3476_B

_5 343 0 11669 0 0.174 4% 105.53 1,231,465 107.2

Wilkes

3478_B

_1 175 0 12904 0 0.136 11% 176.01 2,271,239 154.5
79

Lone Star

3477_B

_1 50.0 0 14546 0 0.230 5% 22.70 330,223 37.9

Total 4,824.56 53,945,435 3,300.56

*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8.760 hours of possible operation in year; that factor is divided by 1,000 to yield units in GWh.

Table C.13.b.: Calculation to Determine Texas Ozone-Season NOX Budget Revisions - Assuming out-of-merit-order dispatch at seven plants

A B C D E F G H I J K

Plant Name

Unique 

Id

Capacity 

(MW)

2012 Ozone 

Season NOX

Emissions

from 

TR_Remedy 

Final_2012

(1000 tons)

Heat Rate 

(BTU/kW

h)

Ozone 

Season 

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Ozone 

Season NOX

Rate 

(lbs/MMBtu) 

Ozone Season 

Average OutOf-MeritOrder 

Capacity 

Factor 

Additional 

Ozone

Season 

Generation*

Additional 

Ozone 

Season 

Heat Input 

(MMBtu)

Additional 

Ozone 

Season 

NOX

Emissions 

(tons)

Calculation C*H*3.672 E*I G*J/2000

Jones

3482_B

_151B 243 0.17811372 11109 283.774892 0.11 31% 273.00 3,032,757 170.6

Jones

3482_B

_152B 243 0.119198228 10245 283.774892 0.08 26% 228.00 2,335,860 95.9

Moore 

County

3483_B

_3 48 0 14075 0 0.12 47% 82.00 1,154,150 69.4

Nichols

3484_B

_141B 107 0.074400425 9983 125.737030 0.12 17% 65.00 648,895 38.3

Nichols

3484_B

_142B 106 0.07774879 10450 124.561918 0.12 17% 68.00 710,600 42.3

Nichols

3484_B

_143B 244 0 11682 0 0.16 32% 288.00 3,364,416 276.3
80

Plant X

3485_B

_111B 48 0 16243 0 0.32 30% 52.00 844,636 134.0

Plant X

3485_B

_112B 102 0 13226 0 0.08 23% 85.00 1,124,210 47.1

Plant X

3485_B

_113B 103 0 11484 0 0.17 30% 112.00 1,286,208 106.9

Plant X

3485_B

_114B 189 0 10841 0 0.10 55% 384.00 4,162,944 212.3

Knox Lee

3476_B

_2 25.0 0 14500 0 0.102 5% 4.80 69,589 3.5

Knox Lee

3476_B

_3 25.0 0 14500 0 0.123 7% 6.68 96,879 6.0

Knox Lee

3476_B

_4 77.0 0 14933 0 0.311 3% 7.73 115,448 18.0

Knox Lee

3476_B

_5 343 0 11669 0 0.174 4% 46.31 540,447 47.1

Wilkes

3478_B

_1 175 0 12904 0 0.136 10% 66.21 854,348 58.1

Lone Star

3477_B

_1 50.0 0 14546 0 0.230 12% 22.70 330,223 37.9

Total 1,791.44 20,671,611 1,363.79

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.
81

As calculated in Table C.13.c., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch would be offset by decreasing 

generation at Texas combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) 

equal to the generation-weighted average of Texas combined cycle units.60

Table C.13.c.: Calculation of Emissions from Displaced Generation at Texas 

Combined Cycle Units

The ozone season NOX emissions associated with the displaced generation 

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative combined cycle unit. 

A B C D

Program Period

Displaced 

Generation 

(GWh)

Heat Rate 

(BTU/kWh)

NOX Emission 

Rate 

(lbs/MMBTU)

Displaced 

NOX

Emissions 

(tons)

Calculation A*B*C/2000

Annual NOX 4,825 7,405 0.031895983 570

Ozone Season NOX 1,791 7,464 0.033113058 221

The total revision to Texas’s state budget due to the out-of-merit-order dispatch is calculated in Table C.13.d. The emissions associated with the 

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the out-of-merit-order generation 

(row A) to determine the net emission budget changes for Texas (row C). 

Table C.13.d.: Calculation to Determine Net Texas Annual and Ozone Season NOX

Budget Revisions (tons)

Annual NOX Ozone Season NOX

A

Additional Emissions Due to 

Out-Of-Order-Merit Dispatch 3,301 1364

B

Displaced Emissions From 

Out-Of-Order-Merit Dispatch 570 221

C

Net Change in Emission 

budget For Texas (A-B) 2,731 1,142

 60 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission 

rate averages used in Revisions Rule Part II” found in the docket for this rulemaking.
82

The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are described in Table C.13.e.

Table C.13.e.: Impact of Texas Budget Revisions – Assuming Removed FGDs and Revised FGD Capture at 

Certain Units, Revised NUSAs for Oak Grove 2, and Out-of-Merit-Order Dispatch at Two Facilities (tons)

Program Budget

Assurance Level

Total New Unit 

Set-Aside*

% of 

Budget Tons

% of 

Budget Tons

2012 Before Direct Final Revisions Rule SO2 294,471 - - 5% 14,724

2012 After Direct Final Revisions Rule SO2 294,471 - - 5% 14,724

2014 Before Direct Final Revisions Rule SO2 294,471 118% 347,476 5% 14,724

2014 After Direct Final Revisions Rule SO2 294,471 118% 347,476 5% 14,724

2012 Before Direct Final Revisions Rule Annual NOX 134,970 - - 4% 5,399

2012 After Direct Final Revisions Rule Annual NOX 137,701 - - 4% 5,508

2014 Before Direct Final Revisions Rule Annual NOX 134,970 118% 159,265 4% 5,399

2014 After Direct Final Revisions Rule Annual NOX 137,701 118% 162,487 4% 5,508

2012 Before Direct Final Revisions Rule Ozone-Season NOX 64,418 - - 4% 2,577

2012 After Direct Final Revisions Rule Ozone-Season NOX 65,560 - - 4% 2,622

2014 Before Direct Final Revisions Rule Ozone-Season NOX 64,418 121% 77,946 4% 2,577

2014 After Direct Final Revisions Rule Ozone-Season NOX 65,560 121% 79,328 4% 2,622

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations
83

14) 

EPA is finalizing, based on comments, an increase to Kansas’s SO2 and NOX budgets in 2012 and 2014 to reflect the assumption of near-term 

operational constraints affecting a unit at the Quindaro plant, based on information provided by the system operator demonstrating that the unit serves is an 

out-of-merit-order dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local conditions described in recently 

submitted documentation that appear likely to necessitate non-economic generation at the units displayed below during the implementation of the Transport 

Rule programs. Specifically, EPA is assuming additional generation will be dispatched Quindaro unit 1 based on the annual minimum capacity factor 

representing the frequency the unit is projected to be called to operate out-of-merit-order, provided in comments from Kansas City Board of Public 

Utilities.

Kansas

61

The calculations of the increase in SO2 and annual NOX emissions due to out-of-merit-order dispatch at Quindaro unit 1 is shown in Tables C.14.a. 

and C.14.b. For the unit, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation from TR_Remedy Final_2012, and emission rate 

from EPA’s NEEDS database are shown (columns A to G). The average out-of-merit-order capacity factor is shown in column H. The additional generation 

for out-of-merit-order dispatch was calculated by multiplying the capacity, the average out-of-merit-order capacity factor, and the number of hours in the 

ozone season (column I). The additional heat input required was calculated by multiplying the incremental generation by the unit’s heat rate (column J). 

Finally, the additional emissions associated with the out-of-merit-order generation was calculated by multiplying the additional heat input by the unit’s NOX

emission rate. 

 In the model run TR_Remedy Final_2012, this unit ran at approximately a 55% annual capacity factor. KCBPU’s comments showed that the unit 

must operate at an average annual capacity factor of 75% to serve its load. Therefore, the difference of 20% is being considered out-of-merit-order dispatch 

in this case. As discussed later in this section, EPA assumes that the additional generation dispatched from this facility would offset generation that would 

otherwise come from similarly-positioned coal-fired units within the state, and the revision to Kansas’s state budget is based on the net change to projected 

emissions taking that offsetting factor into account. The net impact of these changes on the state’s SO2 and annual NOX budgets are 452 and 640 ton 

increases, respectively.

 61 EPA-HQ-OAR-2009-0491-4779 and the document “Clarification of comments originally filed on the TR Revisions Rule by KC BPU” found in the docket for this 

rulemaking.
84

Table C.14.a.: Calculation to Determine Kansas SO2 Budget Revisions - Assuming out-of-merit-order dispatch at Quindaro unit 1

A B C D E F G H I J K

Plant Name

Unique 

Id

Capacity 

(MW)

2012 Annual

SO2

Emissions

from 

TR_Remedy 

Final_2012

(1000 tons)

Heat Rate 

(BTU/kW

h)

Annual 

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Annual SO2

Rate 

(lbs/MMBtu) 

Annual

Average OutOf-MeritOrder 

Capacity 

Factor 

Additional 

Annual

Generation*

Additional 

Annual

Heat Input 

(MMBtu)

Additional 

Annual

SO2

Emissions 

(tons)

Calculation C*H*8.760 E*I G*J/2000

Quindaro 1295_B_1 72 1.170152332 11673 345.6701925 0.579999983 33.8% 212.87 2,484,808 720.6

*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8.760 hours of possible operation in the year; that factor is divided by 1,000 to yield units in GWh.

Table C.14.b.: Calculation to Determine Kansas Annual NOX Budget Revisions - Assuming out-of-merit-order dispatch at Quindaro unit 1

A B C D E F G H I J K

Plant Name

Unique 

Id

Capacity 

(MW)

2012 Annual

NOX

Emissions

from 

TR_Remedy 

Final_2012

(1000 tons)

Heat Rate 

(BTU/kW

h)

Annual 

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Annual NOX

Rate 

(lbs/MMBtu) 

Annual

Average OutOf-MeritOrder 

Capacity 

Factor 

Additional 

Annual

Generation*

Additional 

Annual

Heat Input 

(MMBtu)

Additional 

Annual

NOX

Emissions 

(tons)

Calculation C*H*3.672 E*I G*J/2000

Quindaro

1295_B_

1 72 1.355762723 11673 345.670193 0.67182472 33.8% 212.87 2,484,808 834.7

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.

As calculated in Table C.14.c., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch would be offset by decreasing 

generation at other Kansas coal units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) equal to

the generation-weighted average of Kansas coal units.62

 62 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission 

rate averages used in Revisions Rule Part II” found in the docket for this rulemaking.

The ozone season NOX emissions associated with the displaced generation (column D) were 

calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative coal unit. EPA used representative 
85

coal-fired generation to offset the additional generation assumed now to occur at Quindaro unit 1 because it is reasonable to assume that increased baseload 

generation at Quindaro unit 1 would displace similarly-positioned baseload coal-fired generation previously projected to meet electricity demand.63

Table C.14.c.: Calculation of Emissions from Displaced Generation at Kansas Coal Units

A B C D

Program Period

Displaced 

Generation 

(GWh)

Heat Rate 

(BTU/kWh)

Displaced 

Generation 

Emission Rate 

(lbs/MMBTU)

Displaced 

Emissions 

(tons)

Calculation A*B*C/2000

SO2 213 10,707 0.23598 269

Annual NOX 213 10,707 0.170752 195

The total revision to Kansas’s state budget due to the out-of-merit-order dispatch is calculated in Table C.14.d. The emissions associated with the 

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the out-of-merit-order generation 

(row A) to determine the net emission budget changes for Kansas (row C). 

Table C.14.d.: Calculation to Determine Net Kansas SO2 and Annual NOXNOX Budget 

Revisions (tons)

2012 2014

SO2

Annual 

NOX SO2

Annual 

NOX

A

Emissions Due to Out-Of-MeritOrder Generation 721 835 721 835

B

Displaced Emissions from Out-OfMerit-Order Generation at Quindaro 269 195 269 195

C

Net Budget Revisions for Kansas 

(A-B) 452 640 452 640

 63 In addition, whereas EPA has made similar revisions affecting oil/gas steam units to other state budgets by offsetting previously projected natural gas-fired combined 

cycle generation, there are no gas-fired combined cycles in the state of Kansas that could serve as candidates for this calculation. EPA believes the calculation as 

demonstrated above, using representative coal-fired generation as a broad match for the dispatch characteristics of the assumed increase in out-of-merit-order dispatch 

at Quindaro unit 1, maintains a consistent approach with the other revisions of this type made to Transport Rule state budgets.
86

The total budget revisions for Kansas are summarized below in Table C.14.e.

Table C.14.e.: Total Budget Revisions for Kansas

Budget Year

Revisions due to 

Out-of-MeritOrder Dispatch

Revisions due to 

Unit Controls Total Change

SO2 2012 452 -- 452

SO2 2014 452 -- 452

Annual NOX 2012 640 -- 640

Annual NOX 2014 640 5,154 5,794

The original and revised values for the state budgets, assurance levels, and new unit set-asides are described in Table C.14.f.

Table C.14.f.: Impact of Kansas Budget Revisions – for Out-Of-Merit-Order Dispatch and Unit 

Controls 

Program Budget

Assurance Level

Total New Unit 

Set-Aside*

% of 

Budget Tons

% of 

Budget Tons

2012 Before Direct Final Revisions Rule SO2 41,528 - - 2% 831

2012 After Direct Final Revisions Rule SO2 41,980 - - 2% 840

2014 Before Direct Final Revisions Rule SO2 41,528 118% 49,003 2% 831

2014 After Direct Final Revisions Rule SO2 41,980 118% 49,536 2% 840

2012 Before Direct Final Revisions Rule Annual NOX 30,714 - - 2% 614

2012 After Direct Final Revisions Rule Annual NOX 31,354 - - 2% 627

2014 Before Direct Final Revisions Rule Annual NOX 25,560 118% 30,161 2% 511

2014 After Direct Final Revisions Rule Annual NOX 31,354 118% 36,998 2% 627

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations
87

15) 

EPA is finalizing, based on comments, an increase to Missouri’s annual and ozone season NOX budget in 2012 and 2014 to reflect the assumption of nearterm operational constraints affecting units at four plants, based on information provided by the system operator demonstrating that these units are called to 

dispatch out-of-merit-order to provide voltage support and regulation. EPA's analysis in the final Transport Rule did not incorporate the immediate-term 

local conditions described in recently submitted documentation that appear likely to necessitate non-economic generation at the units displayed below during 

the implementation of the Transport Rule programs. Specifically, EPA is assuming additional generation will be dispatched at four plants (Hawthorn, 

Greenwood, Ralph Green, and South Harper) based on the average capacity factor representing the frequency the unit has recently been called on to operate 

out of merit order, calculated from dispatch logbook data provided by KCPL.

Missouri

64

The calculations of the increase in annual and ozone season NOX emissions due to out-of-merit-order dispatch at the four facilities is shown in 

Tables C.15.a. and C.15.b. For each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation 

from TR_Remedy Final_2012, and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out-of-merit-order capacity factor 

is shown in column H. The additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, the average out-of-merit-order 

capacity factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the incremental 

generation by the unit’s heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation was calculated by 

multiplying the additional heat input by the unit’s NOX emission rate. 

 As discussed later in this section, EPA assumes that the additional 

generation dispatched from these four facilities would offset generation that would otherwise come from combined cycle units within the state, and the 

revision to Missouri’s state budget is based on the net change to projected emissions taking that offsetting factor into account. The net impact of these 

changes on the state’s annual and ozone season NOX budget are 26 ton increases each.

 64 EPA-HQ-OAR-2009-0491-4826 and the document “Clarification of comments originally filed on the TR Revisions Rule by KCPL” found in the docket for this 

rulemaking.
88

Table C.15.a.: Calculation to Determine Missouri Annual NOX Budget Revisions - Assuming out-of-merit-order dispatch at four plants

A B C D E F G H I J K

Plant Name Unique Id

Capacity 

(MW)

2012 Annual

NOX

Emissions

from 

TR_Remedy 

Final_2012

(1000 tons)

Heat Rate 

(BTU/kW

h)

Annual

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Annual NOX

Rate 

(lbs/MMBtu) 

Annual

Average OutOf-MeritOrder 

Capacity 

Factor 

Additional 

Annual

Generation*

Additional 

Annual

Heat Input 

(MMBtu)

Additional 

Annual

NOX

Emissions 

(tons)

Calculation C*H*8.760 E*I G*J/2000

Hawthorn 2079_G_7 77 0 13180 0 0.03072543 0.06% 0.39 5,074 0.1

Hawthorn 2079_G_8 77 0 16770 0 0.03190992 0.14% 0.97 16,233 0.3

Greenwood 6074_G_1 58 0 13300 0 0.50105250 0.31% 1.55 20,615 5.2

Greenwood 6074_G_2 58 0 13300 0 0.50105250 0.23% 1.16 15,388 3.9

Greenwood 6074_G_3 58 0 13300 0 0.50105250 0.35% 1.77 23,541 5.9

Greenwood 6074_G_4 58 0 13300 0 0.50105250 0.28% 1.40 18,673 4.7

Ralph Green 2092_G_3 71 0 14322 0 0.50105250 0.02% 0.14 2,048 0.5

South 

Harper

56151_G_

GT1 105 0 15250 0 0.05518069 0.54% 4.99 76,159 2.1

South 

Harper

56151_G_

GT2 105 0 15082 0 0.05490044 0.81% 7.47 112,632 3.1

South 

Harper

56151_G_

GT3 105 0 15250 0 0.05578315 0.48% 4.39 66,871 1.9

Total 24.22 357,235 27.5

*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8.760 hours of possible operation in year; that factor is divided by 1,000 to yield units in GWh.
89

Table C.15.b.: Calculation to Determine Missouri Ozone Season NOX Budget Revisions - Assuming out-of-merit-order dispatch at four plants

A B C D E F G H I J K

Plant Name Unique Id

Capacity 

(MW)

2012 Ozone 

Season NOX

Emissions

from 

TR_Remedy 

Final_2012

(1000 tons)

Heat Rate 

(BTU/kW

h)

Ozone 

Season 

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Ozone 

Season NOX

Rate 

(lbs/MMBtu) 

Ozone Season 

Average OutOf-MeritOrder 

Capacity 

Factor 

Additional 

Ozone 

Season 

Generation*

Additional 

Ozone 

Season 

Heat Input 

(MMBtu)

Additional 

Ozone 

Season 

NOX

Emissions 

(tons)

Calculation C*H*3.762 E*I G*J/2000

Hawthorn 2079_G_7 77 0 13180 0 0.03072543 0.14% 0.39 5,074 0.1

Hawthorn 2079_G_8 77 0 16770 0 0.03190992 0.34% 0.97 16,233 0.3

Greenwood 6074_G_1 58 0 13300 0 0.50105250 0.73% 1.55 20,615 5.2

Greenwood 6074_G_2 58 0 13300 0 0.50105250 0.54% 1.16 15,388 3.9

Greenwood 6074_G_3 58 0 13300 0 0.50105250 0.83% 1.77 23,541 5.9

Greenwood 6074_G_4 58 0 13300 0 0.50105250 0.66% 1.40 18,673 4.7

Ralph Green 2092_G_3 71 0 14322 0 0.50105250 0.05% 0.14 2,048 0.5

South 

Harper

56151_G_

GT1 105 0 15250 0 0.05518069 1.30% 4.99 76,159 2.1

South 

Harper

56151_G_

GT2 105 0 15082 0 0.05490044 1.94% 7.47 112,632 3.1

South 

Harper

56151_G_

GT3 105 0 15250 0 0.05578315 1.14% 4.39 66,871 1.9

Total 24.22 357,235 27.5

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.

As calculated in Table C.15.c., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch would be offset by decreasing 

generation at Missouri combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) 

equal to the generation-weighted average of Missouri combined cycle units.65

 65 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission 

rate averages used in Revisions Rule Part II” found in the docket for this rulemaking.

The ozone season NOX emissions associated with the displaced generation 

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative combined cycle unit. 
90

Table C.15.c.: Calculation of Emissions from Displaced Generation at 

Missouri Combined Cycle Units

A B C D

Program Period

Displaced 

Generation 

(GWh)

Heat Rate 

(BTU/kWh)

NOX Emission 

Rate 

(lbs/MMBTU)

Displaced 

NOX

Emissions 

(tons)

Calculation A*B*C/2000

Annual 24 8,049 0.018330584 2

Ozone Season 24 8,079 0.018315387 2

The total revision to Missouri’s state budget due to the out-of-merit-order dispatch is calculated in Table C.15.d. The emissions associated with the 

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the out-of-merit-order generation 

(row A) to determine the net emission budget changes for Missouri (row C). 

Table C.15.d.: Calculation to Determine Net Missouri and Ozone Season NOX

Budget Revisions (tons)

2012 2014

Annual 

NOX

Ozone 

Season 

NOX

Annual 

NOX

Ozone 

Season 

NOX

A

Emissions Due to Out-Of-MeritOrder Generation 28 28 28 28

B

Displaced Emissions from Out-OfMerit-Order Generation 2 2 2 2

C

Net Budget Revisions for Missouri 

(A-B) 26 26 26 26
91

The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are described in Table C.15.e.,which 

includes the adjustments to Missouri’s new unit set aside described in section 10. 

Table C.15.e.: Impact of Missouri Budget Revisions for Out-Of-Merit-Order Dispatch and New Unit Set-Aside

Program Budget

Assurance Level Total New Unit Set-Aside*

% of 

Budget Tons % of Budget Tons

2012 Before Direct Final Revisions Rule SO2 207,466 - - 2% 4,149

2012 After Direct Final Revisions Rule SO2 207,466 - - 2% 4,149

2013 Before Direct Final Revisions Rule SO2 207,466 - - 2% 4,149

2013 After Direct Final Revisions Rule SO2 207,466 - - 3% 6,224

2014 Before Direct Final Revisions Rule SO2 165,941 118% 195,810 2% 3,319

2014 After Direct Final Revisions Rule SO2 165,941 118% 195,810 3% 4,978

2012 Before Direct Final Revisions Rule Annual NOX 52,374 - - 3% 1,571

2012 After Direct Final Revisions Rule Annual NOX 52,400 - - 3% 1,572

2013 Before Direct Final Revisions Rule Annual NOX 52,374 - - 3% 1,571

2013 After Direct Final Revisions Rule Annual NOX 52,400 - - 6% 3,144

2014 Before Direct Final Revisions Rule Annual NOX 48,717 118% 57,486 3% 1,462

2014 After Direct Final Revisions Rule Annual NOX 48,743 118% 57,517 6% 2,925

2012 Before Direct Final Revisions Rule Ozone-Season NOX 22,762 - - 3% 683

2012 After Direct Final Revisions Rule Ozone-Season NOX 22,788 - - 3% 684

2013 Before Direct Final Revisions Rule Ozone-Season NOX 22,762 - - 3% 683

2013 After Direct Final Revisions Rule Ozone-Season NOX 22,788 - - 6% 1,367

2014 Before Direct Final Revisions Rule Ozone-Season NOX 21,073 121% 25,498 3% 632

2014 After Direct Final Revisions Rule Ozone-Season NOX 21,099 121% 25,530 6% 1,266

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations
92

16) Oklahoma

EPA is finalizing, based on comments, an increase to Oklahoma’s ozone season NOX budget in 2013 and 2014 to reflect the assumption of near-term 

operational constraints affecting units at four plants, based on information provided by the system operator demonstrating these plants are in an out-of-meritorder dispatch area. These changes do not apply to Oklahoma’s 2012 budget because similar changes were already made to the affected units’ operation in 

2012, as described in the Technical Support Document “Determination of State Budgets for the Final Ozone Supplemental of the Transport Rule.”66 EPA's 

analysis in the final Transport Rule did not incorporate the immediate-term local conditions described in recently submitted documentation that appear likely 

to necessitate non-economic generation at the units displayed below during the implementation of the Transport Rule programs. Specifically, EPA is 

assuming additional generation will be dispatched at four plants (Northeastern, Riverside , Southwestern, and Tulsa) based on the average capacity factor 

representing the frequency the unit is projected to be called to operate out-of-merit-order, derived from immediate-term dispatch modeling projections 

provided by AEP.67

The calculations of the increase in ozone season NOX emissions due to out-of-merit-order dispatch at these facilities is shown in Table C.16.a. For 

each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation from TR_Remedy Final_2012, 

and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out-of-merit-order capacity factor is shown in column H. The 

additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, the average out-of-merit-order capacity factor, and the 

number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the incremental generation by the unit’s 

heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation was calculated by multiplying the additional heat 

input by the unit’s NOX emission rate. 

 As discussed later in this section, EPA assumes that the additional generation dispatched from these facilities would offset generation 

that would otherwise come from combined cycle units within the state, and the revision to Oklahoma’s state budget is based on the net change to projected 

emissions taking that offsetting factor into account. The net impact of these changes on the state’s ozone season NOX budget is an 859 ton increase.

 66 EPA-HQ-OAR-2009-0491-485, pg 5-7. 67 EPA-HQ-OAR-2009-0491-4737, EPA-HQ-OAR-2009-0491-4801, and the document “Clarification of comments originally filed on the TR Revisions Rule by AEP”

found in the docket for this rulemaking.
93

Table C.16.a.: Calculation to Determine Oklahoma Ozone Season NOX Budget Revisions - Assuming Out-of-Merit-Order Dispatch at Four Plants

A B C D E F G H I J K

Plant Name Unique Id

Capacity 

(MW)

2012 

Ozone 

Season 

NOX

Emissions 

from TR_

Remedy 

Final_

2012 (1000 

tons)

Heat Rate 

(BTU/

kWh)

Ozone 

Season 

Generatio

n from 

TR_

Remedy 

Final_2012 

(GWh)

Ozone Season NOX

Rate (lbs/MMBtu) 

Ozone 

Season 

Average 

Out-OfMeritOrder 

Capacity 

Factor 

Additional 

Ozone 

Season 

Generation

*

Additional 

Ozone Season 

Heat Input 

(MMBtu)

Additional 

Ozone 

Season 

NOX

Emissions 

(tons)

Calculation C*H*3.672 E*I G*J/2000

Northeastern 2963_B_3302 480 0 10442 0 0.396 17.1% 301.00 3,143,054 622.6

Riverside 4940_B_1502 459 0 11094 0 0.226 8.2% 137.75 1,528,240 172.8

Southwestern

2964_B_801

N 40.0 0 20500 0 0.251 0.7% 1.02 20,862 2.6

Southwestern 2964_B_801S 40.0 0 20500 0 0.206 0.7% 1.02 20,862 2.1

Southwestern 2964_B_8002 80.0 0 11900 0 0.326 2.1% 6.26 74,476 12.1

Southwestern 2964_B_8003 311 0 11611 0 0.436 1.6% 17.75 206,123 45.0

Tulsa 2965_B_1402 165 0 14213 0 0.182 1.7% 10.33 146,755 13.4

Tulsa 2965_B_1403 85.0 0 11163 0 0.276 1.6% 4.89 54,611 7.5

Tulsa 2965_B_1404 165 0 13144 0 0.188 5.8% 35.06 460,825 43.3

Total 515.08 5,655,808 921.42

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.

As calculated in Table C.16.b., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch would be offset by decreasing 

generation at Oklahoma combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) 
94

equal to the generation-weighted average of Oklahoma combined cycle units.68

Table C.16.b.: Calculation of Emissions from Displaced Generation at Oklahoma Combined Cycle Units

The ozone season NOX emissions associated with the displaced generation 

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative combined cycle unit. 

A B C D

Program 

Period

Displaced Generation 

(GWh)

Heat Rate 

(BTU/kWh)

NOX Emission Rate 

(lbs/MMBTU)

Displaced NOX Emissions

(tons)

Calculation A*B*C/2000

Ozone Season 515 7,713 0.031566434 63

The total revision to Oklahoma’s state budget due to the out-of-merit-order dispatch is calculated in Table C.16.c. The emissions associated with the 

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the out-of-merit-order generation 

(row A) to determine the net emission budget changes for Oklahoma (row C). 

Table C.16.c.: Calculation to Determine Net Oklahoma

Ozone Season NOX Budget Revisions (tons)

A

Additional Emissions Due to 

Out-Of-Order-Merit Dispatch 921

B

Displaced Emissions From 

Out-Of-Order-Merit Dispatch 63

C

Net Change in Emission 

budget For Oklahoma (A-B) 859

 68 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission 

rate averages used in Revisions Rule Part II” found in the docket for this rulemaking.
95

The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are described in Table C.16.d.

Table C.16.d.: Impact of Oklahoma Ozone-Season NOX Budget Revisions – Assuming 

Out-of-Merit-Order Dispatch at Three Facilities (tons)

Budget

Assurance 

Level

Total New 

Unit SetAside*

% of 

Budget Tons

% of 

Budget Tons

2012 Before Direct Final Revisions Rule 36,567 - - 2% 731

2012 After Direct Final Revisions Rule 36,567 - - 2% 731

2013 Before Direct Final Revisions Rule 21,835 - - 2% 437

2013 After Direct Final Revisions Rule 22,694 - - 2% 454

2014 Before Direct Final Revisions Rule 21,835 121% 26,420 2% 437

2014 After Direct Final Revisions Rule 22,694 121% 27,460 2% 454

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit 

allocations

17) Louisiana

EPA is finalizing, based on comments, an increase to Louisiana’s ozone season NOX budget in 2012 and 2014 to reflect the assumption of near-term 

operational constraints affecting units at two plants, based on information provided by the system operator demonstrating these plants are in an out-of-meritorder dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local conditions described in recently submitted 

documentation that appear likely to necessitate non-economic generation at the units displayed below during the implementation of the Transport Rule 

programs. Specifically, EPA is assuming additional generation will be dispatched at two plants based on the average capacity factor representing the 

frequency the unit is projected to be called to operate out-of-merit-order, derived from immediate-term dispatch modeling projections provided by AEP.69

 69 EPA-HQ-OAR-2009-0491-4737, EPA-HQ-OAR-2009-0491-4801, and the document “Clarification of comments originally filed on the TR Revisions Rule by AEP”

found in the docket for this rulemaking.

 

As discussed later in this section, EPA assumes that the additional generation dispatched from these facilities would offset generation that would otherwise 
96

come from combined cycle units within the state, and the revision to Louisiana’s state budget is based on the net change to projected emissions taking that 

offsetting factor into account. The net impact of these changes on the state’s ozone season NOX budget is a 89 ton increase.

The calculations of the increase in ozone season NOX emissions due to out-of-merit-order dispatch at these facilities is shown in Table C.17.a. For 

each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation from TR_Remedy Final_2012, 

and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out-of-merit-order capacity factor is shown in column H. The 

additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, the average out-of-merit-order capacity factor, and the 

number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the incremental generation by the unit’s 

heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation was calculated by multiplying the additional heat 

input by the unit’s NOX emission rate. 

Table C.17.a.: Calculation to Determine Louisiana Ozone Season NOX Budget Revisions - Assuming out-of-merit-order dispatch at two plants

A B C D E F G H I J K

Plant Name

Unique 

Id

Capacity 

(MW)

2012 Ozone 

Season NOX

Emissions

from 

TR_Remedy 

Final_2012

(1000 tons)

Heat Rate 

(BTU/kW

h)

Ozone 

Season 

Generation 

from 

TR_Remedy

Final_2012 

(GWh)

Ozone 

Season NOX

Rate 

(lbs/MMBtu) 

Ozone Season 

Average OutOf-MeritOrder 

Capacity 

Factor 

Additional 

Ozone 

Season 

Generation*

Additional 

Ozone 

Season 

Heat Input 

(MMBtu)

Additional 

Ozone 

Season 

NOX

Emissions 

(tons)

Calculation C*H*3.672 E*I G*J/2000

J. Lamar 

Stall Unit at 

Arsenal Hill

1416_B

_5A 110 0 15,702 0 0.092 3% 11.82 185,573 8.6

Lieberman

1417_B

_1 25.0 0 14,983 0 0.420 5% 4.20 63,002 13.2

Lieberman

1417_B

_2 25.0 0 14,546 0 0.420 6% 5.41 78,671 16.5

Lieberman

1417_B

_3 111 0 12,334 0 0.124 11% 46.52 573,748 35.6

Lieberman

1417_B

_4 109 0 12,791 0 0.132 8% 32.14 411,051 27.1

Total 100.09 1312044.7 100.98

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.
97

As calculated in Table C.17.b., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch would be offset by decreasing 

generation at Louisiana combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) 

equal to the generation-weighted average of Louisiana combined cycle units.70

Table C.17.b.: Calculation of Emissions from Displaced Generation at Louisiana Combined Cycle Units

The ozone season NOX emissions associated with the displaced generation 

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative combined cycle unit. 

A B C D

Program 

Period

Displaced Generation 

(GWh)

Heat Rate 

(BTU/kWh)

NOX Emission Rate 

(lbs/MMBTU)

Displaced NOX Emissions

(tons)

Calculation A*B*C/2000

Ozone Season 100 7,480 0.031765081 12

The total revision to Louisiana’s state budget due to the out-of-merit-order dispatch is calculated in Table C.17.c. The emissions associated with the 

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the out-of-merit-order generation 

(row A) to determine the net emission budget changes for Louisiana (row C). 

Table C.17.c.: Calculation to Determine Net Louisiana 

Ozone Season NOX Budget Revisions (tons)

A

Additional Emissions Due to 

Out-Of-Order-Merit Dispatch 101

B

Displaced Emissions From 

Out-Of-Order-Merit Dispatch 12

C

Net Change in Emission 

budget For Louisiana (A-B) 89

 70 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission 

rate averages used in Revisions Rule Part II” found in the docket for this rulemaking.
98

The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are described in Table C.17.d.

Table C.17.d.: Impact of Louisiana Ozone-Season NOX Budget Revisions – Assuming 

Out-of-Merit-Order Dispatch at Three Facilities (tons)

Budget

Assurance 

Level

Total New 

Unit SetAside*

% of 

Budget Tons

% of 

Budget Tons

2012 Before Direct Final Revisions Rule 18,026 - - 3% 541

2012 After Direct Final Revisions Rule 18,115 - - 2% 362

2014 Before Direct Final Revisions Rule 18,026 121% 21,811 3% 541

2014 After Direct Final Revisions Rule 18,115 121% 21,919 2% 362

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit 

allocations

18) 

EPA is finalizing, based on comments, an increase to Ohio’s SO2, annual NOX, and ozone season NOX budget in 2012 and 2014 to reflect the 

assumption of near-term operational constraints affecting Muskingum River unit 1, based on information provided by the system operator demonstrating the 

plant operates out-of-merit-order. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local conditions described in recently 

submitted documentation that appear likely to necessitate non-economic generation at the units displayed below during the implementation of the Transport 

Rule programs. EPA is assuming additional generation will be dispatched from Muskingum River unit 1 based on operational constraints provided by 

AEP.

Ohio

71

 71 EPA-HQ-OAR-2009-0491-4737, EPA-HQ-OAR-2009-0491-4801, and the document “Clarification of comments originally filed on the TR Revisions Rule by AEP”

found in the docket for this rulemaking.

 As discussed later in this section, EPA assumes that the additional generation dispatched from this facilities would offset generation that would 

otherwise come from combined cycle units within the state, and the revision to Ohio’s state budget is based on the net change to projected emissions taking 

that offsetting factor into account. The net impact of these changes on the state’s SO2, annual NOX, and ozone season NOX budget are 5,163 ton, 528 ton, 

and 247 ton increases, respectively.
99

The calculations of the increase in SO2, annual NOX, and ozone season NOX emissions due to out-of-merit-order dispatch at this facility are shown in 

Tables C.18.a., C.18.b., and C.18.c. For each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, 

generation from TR_Remedy Final_2012, and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out-of-merit-order

capacity factor is shown in column H. The additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, the average outof-merit-order capacity factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the 

incremental generation by the unit’s heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation was calculated 

by multiplying the additional heat input by the unit’s NOX emission rate. 

Table C.18.a.: Calculation to Determine Ohio SO2 Budget Revisions - Assuming out-of-merit-order dispatch at Muskingum River

A B C D E F G H I J K

Plant Name

Unique 

Id

Capacity 

(MW)

2012 Annual

SO2

Emissions

from 

TR_Remedy 

Final_2012

(1000 tons)

Heat Rate 

(BTU/kW

h)

Annual

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Annual SO2

Rate 

(lbs/MMBtu) 

Annual

Average OutOf-MeritOrder 

Capacity 

Factor 

Additional 

Annual

Generation*

Additional 

Annual

Heat Input 

(MMBtu)

Additional 

Annual

SO2

Emissions 

(tons)

Calculation C*H*8.760 E*I G*J/2000

Muskingum 

River

2872_B

_1 190 0 10416 0 4.36 14% 227.39 2,368,533 5163.4

*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8,760 hours of possible operation in the year; that factor is divided by 1,000 to yield units in GWh.

**SO2 rates were derived assuming a similar grade of coal as was used by comparable units in IPM in that region of Ohio and the SO2 content of coal in chapter 8 of the documentation for IPM. The resulting 

SO2 rates are similar to historic rates at these units.
100

Table C.18.b.: Calculation to Determine Ohio Annual NOX Budget Revisions - Assuming out-of-merit-order dispatch at Muskingum River plants

A B C D E F G H I J K

Plant Name

Unique 

Id

Capacity 

(MW)

2012 Annual

NOX

Emissions

from 

TR_Remedy 

Final_2012

(1000 tons)

Heat Rate 

(BTU/kW

h)

Annual

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Annual NOX

Rate 

(lbs/MMBtu) 

Annual

Average OutOf-MeritOrder 

Capacity 

Factor 

Additional 

Annual

Generation*

Additional 

Annual

Heat Input 

(MMBtu)

Additional 

Annual

NOX

Emissions 

(tons)

Calculation C*H*8.760 E*I G*J/2000

Muskingum 

River

2872_B

_1 190 0 10416 0 0.46 14% 227.39 2,368,533 547.1

*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8.760 hours of possible operation in the year; that factor is divided by 1,000 to yield units in GWh.

Table C.18.c.: Calculation to Determine Ohio Ozone-Season NOX Budget Revisions - Assuming out-of-merit-order dispatch at Muskingum River

plants

A B C D E F G H I J K

Plant Name

Unique 

Id

Capacity 

(MW)

2012 Ozone 

Season NOX

Emissions

from 

TR_Remedy 

Final_2012

(1000 tons)

Heat Rate 

(BTU/kW

h)

Ozone 

Season 

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Ozone 

Season NOX

Rate 

(lbs/MMBtu) 

Ozone Season 

Average OutOf-MeritOrder 

Capacity 

Factor 

Additional 

Ozone 

Season 

Generation*

Additional 

Ozone 

Season 

Heat Input 

(MMBtu)

Additional 

Ozone 

Season 

NOX

Emissions 

(tons)

Calculation C*H*3.672 E*I G*J/2000

Muskingum 

River

2872_B

_1 190 0 10416 0 0.46 15% 106.71 1,111,521 256.8

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.

As calculated in Table C.18.d., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch would be offset by decreasing 

generation at Ohio combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) equal 
101

to the generation-weighted average of Ohio combined cycle units.72

Table C.18.d.: Calculation of Emissions from Displaced Generation at Ohio

Combined Cycle Units

The ozone season NOX emissions associated with the displaced generation (column D) 

were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative combined cycle unit. 

A B C

D

Program Period

Displaced 

Generation 

(GWh)

Heat Rate 

(BTU/kWh)

Emission 

Rate 

(lbs/MMBTU)

Displaced 

Emissions 

(tons)

Calculation A*B*C/2000

SO2 227 7,191 0 0

Annual NOX 227 7,191 0.023597394 19

Ozone Season NOX 107 7,265 0.026009641 10

The total revision to Ohio’s state budget due to the out-of-merit-order dispatch is calculated in Table C.18.e. The emissions associated with the 

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the out-of-merit-order generation 

(row A) to determine the net emission budget changes for Ohio (row C). 

 72 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission 

rate averages used in Revisions Rule Part II” found in the docket for this rulemaking.
102

Table C.18.e.: Calculation to Determine Net Ohio SO2, Annual NOX, and Ozone 

Season NOX Budget Revisions (tons)

2012 2014

SO2

Annual 

NOX

Ozone 

Season 

NOX SO2

Annual 

NOX

Ozone 

Season 

NOX

A

Additional Emissions 

Due to Out-Of-MeritOrder Generation 5,163 547 257 5,163 547 257

B

Displaced Emissions 

from Out-Of-MeritOrder Generation 0 19 10 0 19 10

C

Net Budget Revisions 

for Ohio (A-B) 5,163 528 247 5,163 528 247

The total revisions to Ohio’s budgets as a result of control and out-of-merit-order dispatch revisions are summarized below in Table C.18.f.

Table C.18.f.: Total Budget Revisions for Ohio (tons)

Budget Year

Revisions due to 

Out-of-MeritOrder Dispatch

Revisions Due to 

Unit Controls Total Change

SO2 2012 5,163 5,163

SO2 2014 5,163 5,163

Annual NOX 2012 547 2,218 2,765

Annual NOX 2014 547 2,218 2,765

Ozone Season NOX 2012 257 964 1,221

Ozone Season NOX 2014 257 964 1,221
103

The original and revised values for the state SO2, annual NOX, and ozone season NOX budgets, assurance levels, and new unit set-asides are

described in Table C.18.g.

Table C.18.g.: Impact of Ohio Budget Revisions for Out-Of-Merit-Order Dispatch and Control Revisions

Program Budget

Assurance Level

Total New 

Unit SetAside*

% of 

Budget Tons

% of 

Budget Tons

2012 Before Direct Final Revisions Rule SO2 310,230 - - 2% 6,205

2012 After Direct Final Revisions Rule SO2 315,393 - - 2% 6,308

2014 Before Direct Final Revisions Rule SO2 137,077 118% 161,751 2% 2,742

2014 After Direct Final Revisions Rule SO2 142,240 118% 167,843 2% 2,845

2012 Before Direct Final Revisions Rule Annual NOX 92,703 - - 2% 1,854

2012 After Direct Final Revisions Rule Annual NOX 95,468 - - 2% 1,909

2014 Before Direct Final Revisions Rule Annual NOX 87,493 118% 103,242 2% 1,750

2014 After Direct Final Revisions Rule Annual NOX 90,258 118% 106,504 2% 1,805

2012 Before Direct Final Revisions Rule Ozone-Season NOX 40,063 - - 2% 801

2012 After Direct Final Revisions Rule Ozone-Season NOX 41,284 - - 2% 826

2014 Before Direct Final Revisions Rule Ozone-Season NOX 37,792 121% 45,728 2% 756

2014 After Direct Final Revisions Rule Ozone-Season NOX 39,013 121% 47,206 2% 780

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations
104

19) 

EPA is finalizing, based on comments, an increase to New York’s SO2, annual NOX, and ozone season NOX budget in 2012 and 2014 to reflect the 

assumption of near-term operational constraints affecting units at the East River plant, based on information provided by the facility operator demonstrating 

that the plant is required to run for non-economic reasons. EPA's analysis in the final Transport Rule did not incorporate the immediate-term local 

conditions described in recently submitted documentation that appear likely to necessitate non-economic generation at the units displayed below during the 

implementation of the Transport Rule programs. EPA is assuming additional generation will be dispatched from units at the East River plant based on 

immediate-term operational constraints provided by Con-Ed.

New York

73

The calculations of the increase in SO2, annual NOX, and ozone season NOX emissions due to out-of-merit-order dispatch at the East River plant is

shown in Tables C.19.a., C.19.b., and C.19.c. For each unit with out-of-merit-order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, 

heat rate, generation from TR_Remedy Final_2012, and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out-of-meritorder capacity factor is shown in column H. The additional generation for out-of-merit-order dispatch was calculated by multiplying the capacity, the 

average out-of-merit-order capacity factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by 

multiplying the incremental generation by the unit’s heat rate (column J). Finally, the additional emissions associated with the out-of-merit-order generation 

were calculated by multiplying the additional heat input by the unit’s NOX emission rate. 

 As discussed later in this section, EPA assumes that the additional generation dispatched 

from East River would offset generation that would otherwise come from combined cycle units within the state, and the revision to New York’s state budget 

is based on the net change to projected emissions taking that offsetting factor into account. The net impact of these changes on the state’s SO2, annual NOX, 

and ozone season NOX budget are 84 ton, 694 ton, and 127 ton increases, respectively.

The East River units are part of the Manhattan District Heating System such that their emissions are driven by complex interactions of local 

electricity and steam demand, and all of these emissions are relevant to the state’s Transport Rule budgets. The emissions adjustments calculated in these 

tables affect the two steam units (Units 60 and 70) that did not operate in the EPA projections, but are required to run to support the district heating system 

and also provide electricity. The remaining two units (Units 1 and 2) did operate in the EPA projections at reasonable levels and are not included in the 

adjustments. In addition, since Unit 70 operates as a electricity-only unit during in ozone season so that there is no ozone-season steam requirement for noneconomic operation, Unit 70 is not included in the revisions for the ozone season. In calculating the net impact on the state budgets, only the increased 

electricity generation would affect EPA’s prior projected emissions, as such generation is assumed to offset generation at other units in the state in order to 

maintain the balance between modeled electricity supply and demand. Therefore, the heat input for each output is displayed separately to make clear the 

generation that needs to be offset, which in this particular case represents only a fraction of the revised incremental heat input. 

 73 EPA-HQ-OAR-2009-0491-4761 and the document “Clarification of comments originally filed on the TR Revisions Rule by Con-Ed” found in the docket for this 

rulemaking.
105

Table C.19.a.: Calculation to Determine New York SO2 Budget Revisions - Assuming out-of-merit-order dispatch at East River

A B C D E F G H I J K L M N

Plant 

Name

Unique 

Id

Capacity 

(MW)

2012 

Annual 

SO2

Emissions 

from TR_ 

Remedy 

Final_2012 

(1000 tons)

Heat 

Rate 

(BTU/ 

kWh)

Annual 

Generation 

from TR_ 

Remedy 

Final_2012 

(GWh)

Annual 

SO2

Rate 

(lbs/ 

MMBtu) 

Annual 

Average 

Out-OfMeritOrder 

Capacity 

Factor For 

Electricity

Additional 

Annual 

Generation*

Additional 

Annual Elec 

Heat Input 

(MMBtu)

Additional 

Annual 

Steam Heat 

Input 

(MMBtu)

Percent 

of Heat 

Input 

from 

Oil**

Additional 

Annual 

Heat Input 

from Oil

Additional 

Annual 

SO2

EmissionsTotal 

(tons)

Calcula

tion C*H*8.760 E*I (J+K)*L

G*M/200

0

East 

River

2493_ 

B_60 134 0 12,830 0 0.31 36.1% 423.8 5,436,793 499,577 5.3% 316,408.5 49

East 

River

2493_ 

B_70 180 0 11,980 0 0.31 15.4% 242.8 2,909,070 1,372,350 5.3% 228,199.7 35

Total 666.6 8,345,862 1,871,927 544,608.2 84.4

*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8.760 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.

** Average percentage of oil btu input at East River units 60 and 70 from 2010 EIA 923 data.
106

Table C.19.b.: Calculation to Determine New York Annual NOX Budget Revisions - Assuming out-of-merit-order dispatch at East River

A B C D E F G H I J K L

Plant 

Name

Unique 

Id

Capacity 

(MW)

2012 Annual 

NOX

Emissions 

from 

TR_Remedy 

Final_2012 

(1000 tons)

Heat Rate 

(BTU/kWh)

Annual 

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Annual NOX

Rate 

(lbs/MMBtu) 

Annual 

Average 

Out-OfMerit-Order 

Capacity 

Factor For 

Electricity

Additional 

Annual 

Generation*

Additional 

Annual 

Elec Heat 

Input 

(MMBtu)

Additional 

Annual 

Steam 

Heat Input 

(MMBtu)

Additional 

Annual 

NOX

EmissionsTotal 

(tons)

Calcu

lation C*H*8.760 E*I

G*(J+K)/

2000

East 

River

2493_ 

B_60 134 0 12,830 0 0.13 36.1% 423.8 5,436,793 499,577 394.1

East 

River

2493_ 

B_70 180 0 11,980 0 0.15 15.4% 242.8 2,909,070 1,372,350 328.3

Total 666.6 8,345,862 722.4

*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8.760 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.
107

Table C.19.c.: Calculation to Determine New York Ozone-Season NOX Budget Revisions - Assuming out-of-merit-order dispatch at East River

A B C D E F G H I J K L

Plant 

Name

Unique 

Id

Capacity 

(MW)

2012 Ozone 

Season NOX

Emissions 

from 

TR_Remedy 

Final_2012 

(1000 tons)

Heat Rate 

(BTU/kWh)

Ozone 

Season 

Generation 

from 

TR_Remedy 

Final_2012 

(GWh)

Ozone 

Season NOX

Rate 

(lbs/MMBtu) 

Ozone 

Season 

Average 

Out-OfMerit-Order 

Capacity 

Factor for 

Electricity

Additional 

Ozone 

Season 

Generation*

Additional 

Ozone 

Season 

Elec Heat 

Input 

(MMBtu)

Additional 

Ozone 

Season 

Steam 

Heat Input 

(MMBtu)

Additional 

Ozone 

Season 

NOX

EmissionsTotal 

(tons)

Calcu

lation C*H*3.672 E*I

G*(J+K)/

2000

East 

River 60 134 0 12,830 0 0.13 29.3% 144.2 1,849,702 160,106 133

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.

As calculated in Table C.19.d., EPA is assuming that the increase in generation reflecting out-of-merit-order dispatch would be offset by decreasing 

generation at New York combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) 

equal to the generation-weighted average of New York combined cycle units.74 The ozone season NOX emissions associated with the displaced generation 

(column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative combined cycle unit. 

 74 These generation-weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission 

rate averages used in Revisions Rule Part II” found in the docket for this rulemaking.
108

Table C.19.d.: Calculation of Emissions from Displaced Generation at New York Combined Cycle Units

A B C D

Program Period

Displaced 

Generation 

(GWh)

Heat Rate 

(BTU/kWh)

Emission 

Rate 

(lbs/MMBTU)

Displaced NOX Emissions 

(tons)

Calculation A*B*C/2000

SO2 667 7,236 0 0

Annual NOX 667 7,236 0.011824358 29

Ozone Season NOX 144 7,244 0.012305053 6

The total revision to New York’s state budget due to the out-of-merit-order dispatch is calculated in Table C.19.e. The emissions associated with the 

generation displaced by the out-of-merit-order generation (row B) were subtracted from the increase in emissions due to the out-of-merit-order generation 

(row A) to determine the net emission budget changes for New York (row C). 

Table C.19.e.: Calculation to Determine Net New York SO2, Annual NOX and Ozone Season NOX Budget 

Revisions (tons)

2012 2014

SO2

Annual 

NOX

Ozone 

Season 

NOX SO2

Annual 

NOX

Ozone 

Season NOX

A

Additional Emissions Due to 

Out-Of-Merit-Order 

Generation 84 722 133 84 722 133

B

Displaced Emissions from 

Out-Of-Merit-Order 

Generation 0 29 6 0 29 6

C

Net Budget Revisions for 

New York (A-B) 84 694 127 84 694 127
109

The total sum of changes to New York emission budgets in these revisions are shown in Table C.19.f. below.

Table C.19.f.: Total Budget Revisions for New York (tons)

Budget Year

Revisions due to 

Out-of-MeritOrder Dispatch

Revisions Due to 

Unit Controls Total Change

SO2 2012 84 5,360 5,444

SO2 2014 84 5,360 5,444

Annual NOX 2012 694 -- 694

Annual NOX 2014 694 -- 694

Ozone Season NOX 2012 127 -- 127

Ozone Season NOX 2014 127 -- 127
110

The original and revised values for the state ozone season NOX budget, assurance level, and new unit set-aside are described in Table C.19.g.

Table C.19.g.: Impact of New York Budget Revisions for Controls and Out-Of-Merit-Order Dispatch 

Revisions

Program Budget

Assurance 

Level

Total New 

Unit SetAside*

% of 

Budget Tons

% of 

Budget Tons

2012 Before Direct Final Revisions Rule SO2 30,852 - - 2% 617

2012 After Direct Final Revisions Rule SO2 36,296 - - 2% 726

2014 Before Direct Final Revisions Rule SO2 22,112 118% 26,092 2% 442

2014 After Direct Final Revisions Rule SO2 27,556 118% 32,516 2% 551

2012 Before Direct Final Revisions Rule Annual NOX 21,028 - - 2% 421

2012 After Direct Final Revisions Rule Annual NOX 21,722 - - 2% 434

2014 Before Direct Final Revisions Rule Annual NOX 21,028 118% 24,813 2% 421

2014 After Direct Final Revisions Rule Annual NOX 21,722 118% 25,632 2% 434

2012 Before Direct Final Revisions Rule Ozone-Season NOX 10,242 - - 2% 205

2012 After Direct Final Revisions Rule Ozone-Season NOX 10,369 - - 2% 207

2014 Before Direct Final Revisions Rule Ozone-Season NOX 10,242 121% 12,393 2% 205

2014 After Direct Final Revisions Rule Ozone-Season NOX 10,369 121% 12,546 2% 207

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations