Technical Support Document (TSD) for the Cross State Air Pollution Rule Addendum

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

Technical Revisions to State Budgets and 

New Unit Set-Asides

U.S Environmental Protection Agency

Office of Air and Radiation

October 2011
2

EPA finalized the Transport Rule in July of 20111. As described in the proposed “Revisions to Federal Implementation Plans to Reduce Interstate 

Transport of Fine Particulate Matter and Ozone” preamble, EPA is proposing to make revisions to several states’ emission budgets under the Transport Rule. 

EPA is also proposing to revise the new unit set-asides (NUSAs) in certain states. This technical support document shows the underlying data and 

calculations used to quantify each proposed revision to state budgets and provides the information used to determine revised NUSAs in certain states. The 

first section below summarizes revisions to state budget and NUSAs. The second section provides a description of each revision and accompanying tables 

demonstrating the data and calculations associated with each revision. Each proposed revision to a state budget also entails corresponding revisions to the 

absolute number of allowances put into the relevant new unit set-aside2as well as to the absolute assurance level3for 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).

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

EPA is proposing revisions to state emission budgets and/or NUSAs for Arkansas, Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, 

New York, Texas, and Wisconsin. 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. These changes are minor relative to the scope of each Transport Rule program. The proposed revisions to the 

Transport Rule state budgets and NUSAs are summarized in the table below.

 

1

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

2 The “Total NUSAs” presented for each state in section B of this document include allowances under both the State NUSA and the Indian Country NUSA (where the latter 

exists in the given state).

3 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

Proposed 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

Florida 819 2%

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

New Jersey 2,096 420 592 0 112 195 2% 2% 2%

Louisiana 4,231 4,231 3%

Mississippi 2,136 2,136 2%

Texas 70,067 1,375 1,375 70,067 1,375 1,375 5% 4% 4%

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

Nebraska 3,599 3,599 6%

Michigan 5,228 5,228 2%

Arkansas 5%

Total Revisions to 

Each Transport 

Rule Program 75,690 16,580 11,064 81,351 16,272 9,848 N/A N/A N/A

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

Section B: Technical Revisions to States’ TR Emission Budgets and NUSAs.

1) Michigan

EPA is proposing to increase Michigan’s 2012 and 2014 annual NOX budgets 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 or by 2014. 

Therefore, EPA is proposing to revise the state’s 2012 and 2014 annual NOX emission budgets

4

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 would

 

4 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 proposed revision of a 2012 state budget would apply to the state budget for 2012 and 2013, and any proposed 

revision of a 2014 state budget would apply to the state budget for 2014 and thereafter.
4

affect the calculation of the state’s ozone-season NOX budget, and EPA will address that budget when finalizing the Transport Rule Supplemental Notice of 

Proposed Rulemaking (SNPR).

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

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/B D x B 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).

5

 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 proposed increase to the state’s annual NOX

budget (column F).

This budget change would 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 would remain 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.

 

5

See National Electric Energy Data System (NEEDS) v4.10 available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html
5

Table 1.208b.: 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 65,421 118% 77,197 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) Nebraska

EPA is proposing to increase 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 proposing to revise 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.

Table 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/B D x B E - A

Nebraska City 1 1.602 45.765208 0.070 0.2273 5.201 3.599

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 
6

September 1, 2010 TR Notice of Data Availability (NODA) (column D).6 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 proposed increase to the state’s annual NOX budget (column F).

The proposed change to the annual NOX emission budget in Nebraska would 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 proposed 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 setaside are described in the table below.

 

6

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

Table 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 30,039 118% 35,446 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

3) Texas (Removed FGDs)

EPA is proposing to 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. 7 8 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 proposing to revise 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.

 

7

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

8 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
8

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

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/B D x B 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.

9

 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 

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

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

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

4) Texas (FGD Capture)

EPA is also proposing to increase Texas’s 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 

 

9

See "WebReady_ParsedFile_TR_Base_Case_Final_2012" in the Transport Rule docket or on EPA's CSAPR website
9

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 EIA 860 form. 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. Therefore, EPA is proposing to revise the state’s SO2 emission budget to reflect the removal 

rates achieved by these FGDs in 2008 as reported on the EIA 923 form. This recalculation to projected emissions at these units results in a 43,708 ton 

increase to the state’s SO2 budget. The calculations to quantify this revision are shown in the table below.

Table 4: Calculation to Determine Texas SO2 Budget Revision – Assuming Revised SO2 removal Rates at FGD

A B C D E F

Plant Name

Unit 

ID

Total SO2 Emission 

from 

TR_Remedy_Final_2012 

(1000 Tons)

EIA 860 SO2

Removal Rate 

(used in budget 

determination)

2008 EIA 923 

SO2 Removal 

Rate (used for 

budget revision)

Uncontrolled 

Emissions 

(assuming no 

FGD) (1000 

tons)

Revised Emissions 

(assuming FGD 

with revised 

removal rate) (1000 

tons)

Net Budget 

Revision

(1000 tons)

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

Martin Lake 1 1.86284104 0.95 0.657 37.25682081 12.77908954 10.9162485

Martin Lake 2 1.854018172 0.95 0.795 37.08036345 7.601474507 5.747456334

Martin Lake 3 1.745038028 0.95 0.748 34.90076056 8.794991661 7.049953633

Monticello 3 2.548471002 0.95 0.659 50.96942003 17.38057223 14.83210123

Oklaunion 1 2.232109754 0.868 0.726 16.90992238 4.633318731 2.401208977

Sandow 4 1.252293549 0.92 0.766 15.65366936 3.662958629 2.410665081

W A Parish WAP8 1.594838503 0.85 0.817 10.63225669 1.945702974 0.350864471

Total

 

13.090 

 

56.798 

 

43.708 

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 revised emission rate based on EIA 923 data. Column D 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 C to these uncontrolled emissions, which yields the revised emission 

projection for each unit in column E. The difference between this revised emission projection (lower FGD capture assumed, column E) and the remedy 

emission projection (higher FGD capture assumed, column A) determines the amount of the proposed increase to the state’s SO2 budget (column F). 
10

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

5) Florida

EPA is proposing 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 proposing to increase the state’s 2012 ozone season NOX budget by 819 tons to reflect projected emissions from increased dispatch of fossil-fuelfired 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 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.

10

 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 proposed increase to the state’s 2012 ozoneseason NOX budget.

 

10 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 Budget Revisions” found in the docket for this rulemaking.
11

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. EPA’s proposed revision does not affect Florida’s 2014 ozone-season NOX budget as originally finalized, as Crystal River Unit 3 is expected to reenter service by that time.

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

Crystal River Unit 3 Outage (tons)

Ozone-Season 

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 28,644 121% 34,659 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%.11 EPA is now proposing to revise 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.

 

11 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).
12

Table 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%

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 would change by the levels shown below.12

Table 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) Texas (NUSA)

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 now proposing to revise 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. 

 

12 The proposed 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 proposed revision, please see the document entitled “FIP Unit Level Allocations with Proposed Revisions to CSAPR” found 

in the docket to this rulemaking.
13

Table 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) 331,734 134,970 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 proposed revisions to Texas state budgets (and these revisions to the NUSAs) on the state’s NUSAs and assurance levels are

shown in Tables 13.e.

8) Wisconsin

EPA is proposing 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 proposing to revise 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 proposing 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. 
14

Table 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

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

EPA is also proposing 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 

proposing 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 

proposing any revision related to these units for the state’s 2012 SO2 budget.
15

Table 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 

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 proposed increase to the state’s 2014 SO2 budget (column D).

EPA is also proposing 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 proposing to revise 

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. 
16

Table 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/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.13 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 proposed increase to the state’s 

2012 and 2014 annual NOX budgets (column F).

The proposed revisions to the SO2 emission budget for Wisconsin would result 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 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.14 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 proposed budget revision would decrease 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 would reduce 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 

 

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

14 While this relationship is also true for annual NOX, the proposed 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.
17

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 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 79,480 118% 93,786 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 34,101 118% 40,239 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

9) New York

EPA is proposing to increase 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 9.f.
18

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. 15 To meet the requirements of these rules, the New York ISO (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. 

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 

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.16 

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 

 

15 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.

16 See Analysis of New York City Averaging Plans for Compliance with NOx Emissions Limitations, New York Independent System Operator, Inc., 2011
19

generators must be prepared to burn oil in each season.17 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.18 There is a separate and similar minimum oil burn rule affecting units in Long Island.19

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.20 

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 Study21 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 

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

 

17 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.

18 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.

19 See the document, Long Island Gas Burn Procedures – 2011, in the docket for the TR Rule Revisions Proposal, Docket.

20 The EIA data used for this calculation is available at: http://www.eia.gov/cneaf/electricity/page/eia906_920.html.

21 See NYISO Operating Study Summer 2011 and Appendices, New York Independent System Operator, July 14, 2011, page C-3.
20

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 proposed 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 9.a and 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 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 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 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 9.c and 9.d below.
23

Table 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 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 9.e. 

Table 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 proposed 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 9.e. These calculations are shown in Table 9.f.
25

Table 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 proposed revisions to the annual and ozone season NOX emission budgets for New York would 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.22 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 proposed budget revisions would 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 values, the absolute number of allowances in the New York NUSAs would rise in accordance with the 

proposed 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 9.g below.

 

22 While this relationship is also true for SO2, the proposed 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 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 30,852 118% 36,405 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 21,028 118% 24,813 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 8,331 121% 10,081 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) New Jersey

EPA is proposing to increase 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 season23. Therefore, EPA is adjusting the state’s 2012 emission budgets to reflect this 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 SO2 budget; a 308 ton increase to the state’s annual NOX

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

 

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

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 proposed 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 10.a. 

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

SO2 0.175 2.282 0.150 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 scrubber24 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).25 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).

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 

 

24 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.

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

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

26 represented in these calculations as a generic unit with a 

heat rate and emission rates equal to the capacity-weighted average of New Jersey combined cycle units.27 The calculations of emissions from this replaced 

generation are shown in Table 10.b. 

Table 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 8550 0 0

NOX 253.3 8550 0.044 0.048

EPA calculated the SO2 and NOX emissions in table 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 10.c below. 

 

26 Excluding cogeneration facilities, whose generation is not solely based on electricity demand.

27 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 Budget Revisions” found in the docket for this rulemaking.
29

Table 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 0.048

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 0.308

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 proposing to increase 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-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 six plants (Bergen, Edison, Essex, Kearny, Linden, and Sewaren 
30

Generating Stations) 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 PSEG28. 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 proposed 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 112 ton increase in annual NOX and a 195 ton increase in ozone season NOX.

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 10.d and 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. 

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

 

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

G_1301

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
32

PSEG 

Essex 

2401_ 

G_10142 0.003 16968 1.37 0.30 2.6% 4.00 67,800 10.2

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
33

PSEG 

Kearny 

2404_ 

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

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 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

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
35

PSEG 

Edison 

2400_ 

G_13 42

 

0.003 16893

 

1.37 0.27 0.8%

2.85 48,155 6.5

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 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 capacity-weighted average of New Jersey combined cycle units.29 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 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 8,850 0.044 775

Ozone Season 1,142 8,850 0.044 215

The total revisions proposed 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 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 

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). 

 

29 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 Budget Revisions” found in the docket for this rulemaking.
38

Table 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 2,096 308 397 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 0 775 215 0 775 215

D Net Budget Revisions for New Jersey (A+B-C) 2096 420 592 0 112 195

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 10.h.

Table 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 7,670 118% 9,051 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 7,686 118% 9,069 2% 154

2014 Initial Annual NOX

7,266 118% 8,574 2% 145

2014 Revised Annual NOX 7,378 118% 8,706 2% 148

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

2012 Revised Ozone-Season NOX

3,974 121% 4,809 2% 79

2014 Initial Ozone-Season NOX

3,382 121% 4,092 2% 68

2014 Revised Ozone-Season NOX 3,577 121% 4,328 2% 72

*Approximate set-aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations
39

11) Louisiana

EPA is proposing to increase 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-merit-order 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 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.

30

 

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 proposed 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 4,231 ton increase.

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 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. 

 

30 Correspondence from Entergy to EPA, September 29, 2011. Please see the document “Transmission System Considerations – Entergy” in the docket for this rule making.
40

Table 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/kW

h)

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

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
41

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 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 as a representative unit with a heat rate (column B) and emission rate (column C) 

equal to the capacity-weighted average of Louisiana combined cycle units.31 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 11.b: Calculation of Emissions from Displaced Generation at Louisiana 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 4,212 6,798 0.05 716

The total revision proposed to Louisiana’s state budget due to the out-of-merit-order dispatch is calculated in Table 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). 

 

31 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 Budget Revisions” found in the docket for this rulemaking.
42

Table 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 716

C

Net Emission budget Change 

For Louisiana (A-B) 4,231

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

Table 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 17,663 121% 21,372 3% 530

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

2014 Revised 17,663 121% 21,372 3% 530

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

allocations

12) Mississippi

EPA is proposing to increase 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 
43

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.

32

 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 proposed 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 2,136 ton increase.

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 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. 

 

32 Correspondence from Entergy to EPA, September 29, 2011. Please see the document “Transmission System Considerations – Entergy” in the docket for this rule making.
44

Table 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/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

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 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) 

equal to the capacity-weighted average of Mississippi combined cycle units.33 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.

 

33 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 Budget Revisions” found in the docket for this rulemaking.
45

Table 12.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 1,473 7,388 0.03 163

The total revision proposed to Mississippi’s state budget due to the out-of-merit-order dispatch is calculated in Table 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 12.c: Calculation to Determine Net Mississippi 

Ozone Season NOX Budget Revisions

A

Additional Emissions Due to 

Out-Of-Order-Merit Dispatch 2,299

B

Displaced Emissions From 

Out-Of-Order-Merit Dispatch 163

C

Net Change in Emission 

budget For Mississippi (A-B) 2,136
46

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

Table 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 12,296 121% 14,878 2% 246

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

2014 Revised 12,296 121% 14,878 2% 246

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

allocations

13) Texas (Out-of-Merit-Order Dispatch)

EPA is proposing to increase Texas’s annual NOX and ozone season NOX budgets 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 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.

34

 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 proposed 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.

 

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

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

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 

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. 
48

Table 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**

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.

As calculated in Table 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) 
49

equal to the capacity-weighted average of Texas combined cycle units.35 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 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

Annual 3,059 7,376 0.019 214

Ozone Season 3,059 7,376 0.019 214

The total revisions proposed to the Texas state budgets due to out-of-merit-order dispatch are calculated in Table 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 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.

 

35 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 Budget Revisions” found in the docket for this rulemaking.
50

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

in Table 13.e. 

Table 13.d.: Summary of Texas SO2 Budget 

Revisions

Removed FGD Revision 26,359

FGD Capture Revision 43,708

Total SO2 Budget Revision 70,067

Table 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 314,021 118% 370,545 5% 15,701

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

2014 Revised SO2 314,021 118% 370,545 5% 15,701

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

2012 Revised Annual NOX 134,970 118% 159,265 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 64,418 121% 77,946 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