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 Radiatio n

October 20112

EPA finalized the Transport Rule in July of 2011 1

. As described in the proposed “ Revisions to Federal Implementation Plans to Reduce Interstate

Transport of Fine Particulate Matter and Ozone ” p reamble, EPA is proposing to mak e revisions t o several states’ emission budget s under the Transport R ule.

EPA is also proposing to revise the new unit set

- asides (NUSAs) in certain states. T his technical support document show s the underlying data and

calculations used to quantify each proposed revis ion to state budgets and provide s the information used to determine revised NUSAs in certain states. The

fir st section below summarizes revisions to state budget and NUSA s . The second section provides a description of each revision and accompanying table s

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

- aside 2 as well as to the absolut e assurance level 3 for the relevant pollutant in that state, as

NUSAs and assurance levels are both calculated by applying percentage values to the relevant state budget (using the methodol ogies 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 . The se 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 as sessed 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 Impl ementation 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 Indi an 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 i nstead of in 2012.3 Proposed Revisions to Transport Rule State Budget s and NUSA s

2012

– 2 013 State Budgets 2014 and beyond State Budgets NUSA*

SO 2 Annual

NO X Ozone

Season

NO X SO 2 Annual

NO X Ozone

Season

NO X SO 2 Annual

NO X Ozone

Season

NO X

Florida 819 2%

New York 3,527 3,485 1,911 3,527 3,485 1,91 1 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 fo llowing rounding of existing unit allocations

Section B : Technical Revision s to States ’ TR Emission Budgets and NUSAs

.

1) Michigan

EPA is proposing to increase Michigan’s 2012 and 2014 annual NO X budget s 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 NO X emissi on b udget s 4 to reflect projected emissions without this unit operating a n

SCR. This results in a 5,228 ton increase to the state’s annual NO X budget s in 2012 and 2014 . EPA also recognizes that this revised input assumption would

4 Throughout this TSD and throughout the preambl e 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 sta te budg et 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 NO X 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 NO X Budget Revision

- Assuming no SCR at Monroe U ni t 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 1.54 0 44.437 0.0693 0.3046 6.768 5.228

Column s A, B, and C show the NO X emissions, heat input, and emission rate from the TR_Remedy_Final_2012 modeling when a n SCR is assumed

to be present at Mo nroe U nit 2 . Because n o SCR is present, EPA modified the emission rate to reflect the “controlled NO X policy rate” in the NEEDS

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

. 5 This value reflects the NO X emission rat e 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 th e unit. EPA multiplied this NO X 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 NO X

b udget (column F)

.

This budget change would not result in any impact t o the percent of the budget set aside for new units. Under the metho dology in the final Transport

Rule , the NUSA for annual NOx in Michigan would remain at 2%. The original and revis ed 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/BaseCasev4 10.html5 Table 1. 208 b.: Impact of Michigan Annual NO X Budget Revision

- Assuming no SCR at

Monroe Unit 2 (tons)

Annual NO X 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% 77,1 97 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 NO X budget s 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 avail able 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 NO X emission budget s to reflect this unit operat ing without an SCR . This results in a 3,599 ton increase to the state’s 2012 and

2014 annual NO X budget s . The calculations to quantify this revision are shown in the t able below.

Table 2.a.: Calculation to Determine Nebraska Annual NO X 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) H eat I nput from

TR_Remedy_Final_2012

(Tbtu) Remedy Emission Rate

from

TR_Remedy_Final_2012

(lbs/mmbtu) Revised

Emission

Rate

(lbs/mmbtu) Re vised

Emissions

(1000

tons) Net

Budget

Revision

(1000

tons)

Calculation A/B D x B E

- A

Nebraska City 1 1.602 45.765 208 0.070 0.2273 5.201 3.599

Column s A, B, and C show the NO X emissions, heat input, and emission rate from the TR_Remedy _Final_20 12 modeling when an SCR is assumed

to be present. Because no SCR is present, EPA modified the emission rate to reflect the “controlled NO X policy rate” in the NEEDS version from the6

September 1, 2010 TR Notice of Data Availability (NODA) (column D). 6 Thi s value reflects the NO X 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 NO X 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 thi s revised emission projection ( no SCR assume d , column E ) and the

remedy emission projection (SCR assumed , column A ) determines the amount of the proposed increase to the state’s annual NO X b udget (column F).

The proposed change to the annual NO X emission budget in Nebraska would result in a small ch ange to the state’s new unit set

- aside percentage for

annual NO X . 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 projecte d 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 in creasing. 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 b udget revision w ould decrease the NUSA percentage for

annual NO X from 7% to 6% as a resul t. This is applying the same NUSA met hodology that is used for every state in the final Transport Rule , and the

change in percentage is simply an outgrowth of the sta te’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 revis ed values for the state annual NO X budget, assurance level, and new unit set

aside 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.html7 Table 2.b.: Impact of Nebraska Annual NO X Budget Revision

– Assuming no SCR at

Nebraska City Unit 1 (tons)

Annual NO X 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 e xisting unit allocations

3) Texas (Removed FGDs)

EPA is proposing to increase Texas’s 2012 and 2014 SO 2 budget s to cor rect for the assumption that Flue Gas Desulfurization (FGD) technology will

be ins talled by 2012 for W.A. Parish U nit 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 SO 2 emission budget s to

reflect these unit s operating without an FGD . This results in a 26,359 ton increase to the state’s 2012 and 2014 SO 2 budget s . The calculations to quantify

this revis ion are shown in the table below.

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

8 Business Wire, (2006). NRG Announces Comprehensive Repowering Initiative [ Press release]. Retrieved from http://phx.corpora te

ir.net/phoenix.zhtml?c=121544&p=irol

- newsArticle_Print&ID=874575&highlight8 Table 3: Calculation to Determine Texas SO 2 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_Remed y 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 SO 2 emissions, heat input, and e mission 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 rate s shown for

these units in EPA’s analy sis of the base case for the final Transport Rule, as found in the TR_Base_Case_Final for 2012 (column D)

. These SO 2 emission

rates reflect generation at these units without the operati on of the assumed FGDs , which did not operate in the final Transport R ule base case because they

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

. 9 The revised SO 2 emission rate in column D is

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

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

proposed increase to the state’s SO 2 b udget (column F).

The impact s of all proposed revisions to the Texas state budgets on the state’s NUSA s and assurance level s are shown in Table 13.e

.

4) Texas (FGD Capture)

EPA is also proposing to increase Texas’s 2012 and 2014 SO 2 budget s 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 remo val rates at those units that the facility operators have previously reported, those facility operators ha ve clarified to

9 See "WebReady_ParsedFile_T R_Base_Case_Final_2012" in the Transport Rule docket or on EPA's CSAPR website9

EPA that those reported removal rates only applied to the flue gas treated at the unit. Because of design limitations, these faciliti es 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 rem oval rate of the FGD as applied to total SO 2 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 SO 2 emission budget to reflect the removal

rates achieve d 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 SO 2 budget. The calculations to quantify this revision are shown in the table below.

Table 4 : Calculation to Determine Texas SO 2 Budget Revision

– Assuming Revised SO 2 removal Rates at FGD

A B C D E F

Plant Name Unit

ID Total SO 2 Emission

from

TR_Remedy_Final_2012

(1000 Tons) EIA 860 SO 2 Removal Rate

(used in budget

determination) 2008 EIA 923

SO 2 Removal

Rate (used for

budget revision) Uncontrolled

Emissions

(a ssuming no

FGD ) (1000

tons) R evised Emissions

(assuming FGD

with revised

removal rate) (1000

tons) Net Budget

Revis ion

(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 SO 2

removal rate that those 2012 emission projections are based on. Column C shows the r evised 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 rev ised 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 SO 2 b udget (column F).10

The impact s of all proposed revi sions to Texas state budgets on the state’s NUSA s and assurance level s are shown in Tables 13.d and 13.e.

5) Florida

EPA is proposing a re vision to Florida’s 2012 ozone

- season NO X budget to correct for the assumption that Crystal River Unit 3 , a nuclear un it with

no NO X emissions, will be available for dispatch in 2012. This unit is not expected to operat e in 2012 as it is undergoing an extended outage for repair work.

EPA is proposing to increase the state’s 2012 ozone season NO X budget by 819 tons to re flect projected emissions from increase d dispatch of fossil

- fuel

fired capacity needed to substitute for the generation that EPA originally projected to come from Crystal River Unit 3

. The calculations to quantify this

revision are shown in the table belo w.

Table 5.a: Calculation to Determine Florida Ozone

- Season NO X 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) A verage Ozone

- Season

NO X 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 proj ected 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 NO X emission rate from combined cycle natural gas units in Florida that

EPA assumes woul d be likely to increase their dispatch to replace the generation that would otherwise be available from C rystal Ri ver Unit 3

. 10 To

characterize the emissions of this replacement generation, EPA selected combined cycle units that reported higher utilization in 2010 (when C rystal R iver

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 operati on of Crystal River Unit 3 did not include any NO X emissions covered by the Transport

Rule, t he emissions from likely replacement generation calculated in column D determine the amount of the proposed increase to the state’s 2012 ozone

season NO X 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 ave rages used in Budget Revisions” found in the docket for this rulemaking.11

T h e change to the ozone

- season NO X 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 revis e d values for the state ozone

- season NO X 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 NO X budget as originally finalized, as Crystal River Unit 3 is expected to re

enter service by that time.

Table 5.b.: Impact of Florida Ozone

- S eason NO X Budget Revision

– Assuming

Crystal River Unit 3 Outage (tons)

Ozone

- Season

NO X Budget Assurance Level Total Ozone Season NO X New Unit Set

- Aside*

% of Budget Tons % of Budget Tons

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

2012 Revised 28,6 44 121% 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. Su ch 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 1 as a new unit and therefore omitted its projected emissions in the determination of the ozone

season NO X 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 minim

um value of 2%. 11 EPA is now proposing to r evise the calculation of the Arkansas ozone

- season NO X 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 NO X Emissions from Plum

Point (tons) 478

B Arkansas Ozone Season NO X State Budget (tons) 15,037

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

D Base percentage fo r 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 st ate budget to derive

the state

- specific percentage for the new uni t 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 o zone s eason NO X in Arkansas is 5%. This change does not impact the state budget or ass urance 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 NO X NUSA revision for Arkansas

Initial % Updated% Initial tons Revised tons*

New Unit Set

- Aside 2% 5% 301 752

Existi ng 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 SO 2 , a nnual NO X , and ozone

- season NO X

, respectively. EPA is now proposing to revise the

Texas new unit set

- aside s to reflect the “new unit” status of Oak Grove Unit 2 . The calculation s to quantify these revis ions 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 exis ting

unit allowance allocations associated with this proposed revision, please see the document entitled “FIP Unit Level Allocations wi th Proposed Revisions to CSAPR” found

in the docket to this rulemaking.13 Table 7: Calculation for Texas's NUSA s

SO 2 NO X Ozone

Se ason NO X

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

B TX State Budget (tons) 331,734 13 4

, 970 6 4

, 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 NUSA s and assurance level s are

shown in T able s 13.e.

8) Wisconsin

EPA is proposing a revision to Wisconsin’s 2014 SO 2 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 SO 2 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 SO 2 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 SO 2 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 SO 2 budget. The calculation s to quantify th is revis ion are sh own in the table below.14 Table 8.a.: Calculation to Determine Wisconsin's SO 2 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 SO 2 remedy case e missions in 2014 and 201 2

, respectively

. In its modeling of the final Transport Rule

remedy, EPA projected t he same t otal heat in put for Weston Unit 3 in both years. Howeve r, 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 t he

difference between the projected emission s 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 SO 2 budget related to this unit, shown in column C

.

EPA is a lso proposing a revision to Wisconsin’s 2014 SO 2 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 Natu ral 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 SO 2 removal

rate s of 96 % for new wet scrubber s and 92 % for new dry scrubber s . Therefore, the projected emissions from these units reflected a higher SO 2 removal rate

(and consequently lower emissions) than these units would be ass umed to achieve with dry scrubber technology

. In accordance with this revision , EPA is

proposing a 2,152 ton increase to the Wisconsin 2014 SO 2 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 SO 2 budget.15 Table 8.b.: Calculation to Determine Wisconsin SO 2 Budg et Revision

- Assuming D ry 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 “uncontro lled emissions” are calcul ated

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

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

scrubbers assumed , column A ) determines the amount of the proposed increase to the state’s 2014 SO 2 b udget (column D ).

EPA is also propo sing a revision to Wisconsin’s a nnual NO X budget for 2012 and 201 4 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 20 12 and 2014 annual NO X budget s by 2,473 tons to reflect the operation of the unit without an SCR. The calculation s to quantify th is revision

are shown in the table below.16 Table 8

. c : Calculation to Deter mine Wisconsin Annual NO X Budget Revision

- Assuming no SCR at J P Madge tt

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) N et 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 u nit. 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). Th is annual NO X emission rate reflects generation at this unit without the

operati on 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 opera te 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 projecte d 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 NO X budget s (column F)

.

The proposed revisions to the SO 2 emissi on budget for Wisconsin would result in a small change to the state’s new unit set

- aside percentage for SO 2

. The reason for the change is that under the methodology established in the final Transport Rule, the state

- specific portion of the NUSA is calcula ted 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 Beca use the numerator remains unchanged but the denominator is

increasing, the total new unit set

- aside percentage for SO 2 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, t he proposed budget revision w ould decrease the NUSA percentage for SO 2 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 per centage 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 SO 2 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 NO X , the proposed revisions to Wisconsin’s annual NO X budget do not yield a different calculated NUSA percentage than

the originally determined 6% under the f inal 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 revis ed values for the state SO 2 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 SO 2 79,480 118% 93,786 5% 3,974

2012 Revised SO 2 79,480 118% 93,786 4% 3,179

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

2014 Revised SO 2 47,883 118% 56,502 4% 1,915

2012 Initial Annual NO X 31,628 118% 37,321 6% 1,898

2012 Revised Annual NO X 34,101 118% 40,239 6% 2,046

2014 Initial Annual NO X 30,398 118% 35,870 6% 1,824

2014 Revised Annual NO X 32,871 118% 38,788 6% 1,972

*Approximate set

- aside amo unts, 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 NO X , ozone

- season NO X , and SO 2 budgets to reflect the assumption of near

- term

operatio n al constraints affecting specific units in New York City and Long Island. These revisions are based on three types of local operating constraints

th at apply to certain generators in New York City and Long Island, which are referred to here as the N

- 1

- 1 C ontingency, 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 seco nd contingency, also

known as an N

- 1

- 1 contingency; these requirements are in addition to any requirements for the firs t (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 requ irements 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 t o ensure sufficient location al 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 st eam 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 the se 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 t hat 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 dispatc hed 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 applicatio ns 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 Co mpliance with NOx Emissions Limitations , New York Independent System Operator, Inc., 201119

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 time s that they may be notified to switch. As a result, it is necessary for these units to

operate using oil at certain time s of the year . For New York City, Con Edison applies to revise t his 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 t he 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 fracti on 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 d irect c urrent (DC) lines that are not dispatched in real t ime and not controlled by the NYISO, the ability to serve Long Island

load from with in New York State is subject to overall import limitations. L ocal 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

. T he NYISO Operating Study 21 show s that NYISO is limited to approximately 860 MW of

dispatc hable import capacity into Long Island on a sustainable hourly basis

. Even i f 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 generat ion 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 th is local import limitation represented, and the remaining

units at Northport have heat rates that diff er by less than one percent from the Northport unit that was modeled to dispa tch

.

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, I

R3 & 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 summe r 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 assum ing that additional commitment of

units at three steam plants in New York City ( Arthur Kill, Ravenswoo d, 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 . T hese calculations

establish the assumed minimum generation at each facilit y 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 mode led . 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 propo sed 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, the se dispatch conditions were assumed to apply 100% of the time; during t he

rest of the year ( non

- ozone season ) , the y were assum ed to apply 40% of the time, reflect ing historically observed seasonal differences in operation of these

units . The NO X emissions from this additional generation at these units were calculated using e ach unit ’s heat rate and NO X emission rate from EPA’s

assumptions in its IPM modeling

. The results from these unit

- level calculations are shown in Table s 9 .a and 9.b

.

To account for the effects of the minimum oil burn rule in New York City, EPA calculate d SO 2 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 uni t s are shown in Table 9 .b. To estimate additional SO 2 emissions, the IPM emission rate of 1.04 lbs/mmBtu for

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

additional use of oil.21

Table 9.a Ozone Season NO X Revis ed 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) NO X Rate

(lbs/

mmBtu) Heat

Input

(Tbtu) Generation

(GWh) Minimum

Capacity

Factor Revised

Generation

(GWh) Additional

Generation

beyond

IPM (GWh) Additional

NO X 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 Ravenswoo d 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 23.822

Table 9.b Annual NO X and SO 2 Revis ed 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 Generatio n 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) NO X Rate

(lbs/

mmBtu) Heat

Input

(Tbtu) Generation

(GWh) Minimum

Capacity

Factor Revised

Generation

(GWh) Additional

Generation

be yond

IPM (GWh) Additional

NO X Emissions

(tons) 2010 Oil

Fraction Additional

SO 2 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 A rthur

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

2500_

B_10 Ravens

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

2500_

B_30 Ravens

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

890 6_

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

*Assume s 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 addition al 2.2 TWh of generation beyond the le vel 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 assum ing that th is additio nal 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 mi nimum

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

calculat ed additional ozone

- season NO X , annual NO X , and SO 2 emissions from these Long Island units in t he same way as for the New York City units

shown above . The se calculations are provided in Table s 9 .c and 9 .d below.23

Table 9.c Ozone Season NO X 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) NO X

Rate

( lbs/

mmBtu ) Heat

Input

(Tbtu) Generation

(GWh) Minimum

Capacity

Factor Require d

Generation

(GWh) Additional

Generation

(GWh) Additional

NO X 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 NO X and SO 2 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) NO X

Rate

(lbs/

mmBtu) Heat

Input

(Tbtu) Generation

(GWh) Minimum

Capacity

Factor Re vised

Generation

(GWh ) Additional

Generation

beyond

IPM (GWh) Additional

NO X Emissions

(tons) 2010 Oil

Fraction Additional

SO 2 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 0.1 22 573.7

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 generation24

Calculation of Revision s 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 wo uld 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 displace s 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 I PM 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) NO X Emission Rate

(lbs/MMBTU) Displaced NO X Emissions

(tons)

Calculation A*B*C/2000

Annual 8,227 7,600 0.0 1 313

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, inclu ding the displaced emissions shown in table 9.e . T hese calculations are shown in Table 9

. f

.25 Table 9.f: Calculation to Determine Net New York SO 2 , Annual NO X , and Ozone

Season NO X Budget Revisions

SO 2 Annual NO X Ozone Season

NO X

A Additional Emissi ons Due to

N ew Y ork C ity 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 annu al and ozone season NO X emission budget s for New York would result in small change s to the state’s new unit set

- aside

percentage s for annual NO X and ozone season NO X

. The reason for the se change s is that under the methodology established in the final Trans port 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 u nits remain unchanged, but the budget s are increasing. 22 Because the

numerator remains unchanged but the denominator is increasing, the total new unit s et

- aside percentage for annual NO X and ozone season NO X decreases.

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

York, t he proposed budget revision s w ould decrease the NUSA percentages for both annual NO X and ozone season NO X from 3 % to 2 % as a resul t. 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 revision s

. Despite the lower percentage values, the absolute number of allow ances 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 budget s , assurance level s , and new unit set

- aside s are

described in the Table 9.g below

.

22 While this relationship is also true for SO 2 , the proposed revisions to New York’s SO 2 budget do not yield a different calculated NUSA pe rcentage 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 SO 2 27,325 118% 32,244 2% 547

2012 Revised SO 2 30,852 118% 36,405 2% 617

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

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

2012 Initial Annual NO X 17,543 118% 20,701 3% 351

2012 Revised Annual NO X 21,028 118% 24,813 2% 421

2014 I nitial Annual NO X 17,543 118% 20,701 3% 351

2014 Revised Annual NO X 21,028 118% 24,813 2% 421

2012 Initial Ozone

- Season NO X 8,331 121% 10,081 3% 167

2012 Revised Ozone

- Season NO X 10,242 121% 12,393 2% 205

2014 Initial Ozone

- Season NO X 8,331 121% 10,081 3% 167

2014 Revised Ozone

- Season NO X 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 SO 2 , annual NO X , and ozone season NO X 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. Addition ally, the AO requires

that this unit only run during the ozone season 23 . Therefore, EPA is adjusting the state’s 2012 emission bud get s 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 SO 2 budget; a 308 ton increase to the state’s annual NO X budget; and a 397 ton increase to the state’s ozone se ason NO X budget. As discussed later in this section, EPA assumes that the generation previously

23 Personal Correspondence from Bill O’Sullivan, New Jersey Departm ent of Environmental Protection

, t o S a m N a p o l i t a n o

. S e p t e m b e r 2 6

, 2 0 1 1

.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

wit hin the state, and the ir associated emissions are factored into the proposed revisions to New Jersey state budgets.

The calculation s of revised 2012 emissions from ozone

- season operation of BL England Unit 1 are shown in Table 10 .a.

Table 10 .a.: Calcula tion 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

Emission s (1000 tons)

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

- A

SO 2 0.175 2.282 0.150 2.190 2.499 2.324

NO X 0.105 2.282 0.092 0.440 0.5 02 0.397

C olumns 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 n either a scrubber nor SCR is re quired by the AO in 2012 , EPA modified the

emission rate s by removing the impact of the scrubber 24 and adopting the “controlled NO X policy rate” in the NEEDS version from the September 1, 2010

TR Notice of Data Availability (NODA) , which does not reflect op eration of an SCR at that unit (column D). 25 Th e s e value s approximate the emission rate s expected at the unit at a cost threshold of $500/ton when no scrubber or SCR is present at the unit. These emission rate s w ere multiplied by the remedy heat

input sho wn in column B to obtain a revised emissions value for the unit (column E). The difference between th e s e revised emission projections (no

scrubber or SCR assumed , column E ) and the remedy emission projections ( scrubber and SCR assumed , column A ) determine s 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 re placing

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

24 The SO 2 emission rate for BL England Unit 1 in TR_Remedy Final_2012 was 0.153 lb s/mmBtu. Removing the impact of that previously assumed scrubber’s SO2

removal rate of 93% yields an uncontrolled SO 2 emission rate of 2.19 lbs/mmBtu.

25 See National Electric Energy Data System (NEEDS) v4.10 available at http://www.epa.gov/airmarkets/prog sregs/epa

- ipm/BaseCasev410.html28

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 rate s equal to the capacity

- weighted average of New Jersey combined cycle units. 27 The calculations of emissions from this re placed

generation are shown in Table 10.b.

Table 10

. b .: Calculation of Emissions at New Jerse y Combined Cycle Units from Re placing

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 o f

Replacement

Generation

(lbs/mmBtu) Emissions from

Replacement

Generation (1000

tons)

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

SO 2 253.3 8550 0 0

NO X 253.3 8550 0.044 0.048

EPA calculated the SO 2 and NO X emissions in table 10.b by multiplying the replace d generation (column A) by the generic unit’s heat rate (column

B) and relevant emission rate (column C).

In order to calculate appropriate revision s to New Jersey’s 2012 SO 2 , annual NO X , and ozone season NO X state budgets in accordance with the

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

.

26 E xcluding 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 titl ed “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 Revision s Due to Changes at BL

England Unit 1 (1000 tons)

Quant ity Calculation Value

A Additional SO 2 Emissions from BL England 2.324

B SO 2 Emissions from Replacement Generation 0

C BL England Unit 1 Non

- Ozone Season SO 2 Emissions from

TR_Remedy Final_2012 0.228

D Net SO 2 Emissions Due to Revisions of BL England Unit 1 A+B

- C 2.096

E Additional Ozone Season NO X Emissions from BL England 0.397

F Annual NO X Emissions from Replacement Generation 0.048

G BL England Unit 1 Non

- Ozone Season NO X Emissions from

TR_Remedy Final_2012 0.137

H Net Annual NO X Emissions Due to Revisions of BL England

Unit 1 E+F

- G 0.308

I Net Ozone Season NO X Emissions Due to Revisions of BL

England Unit 1 =E 0.397

T he revision s to New Jersey’s 2012 SO 2 and annual NO X budgets are determined by combining the revised emissio ns 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 SO 2 , row D minus row E for NO X ). The revision to New Jersey’s 2012 ozone

- season NO X budget is equivalent to the change

in ozone season NO X emission s at BL England due to removing the SCR (row E)

.

EPA is also proposing to increas e New Jersey’s annual NO X and ozone season NO X budgets to reflect the assu mption 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 incorp orate 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 a ssuming additional generation will be dispatched at six plants (Bergen, Edison, Essex, Kearny, Linden, and Sew a ren30

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

calculated from dispatch logbook data provided by PSEG 28 . As discussed later in this section, EPA assumes that th e 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 to n increase in annual NO X and a 195 ton increase in ozone season NO X

.

The calculations of the increase in ozone season NO X and annual NO X emissions due to out

- of

- merit

- order dispatch at the six facilities are shown in

Table s 10. d a n d 10. e

, respectively. F o r 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 g eneration

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 b y 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 NO X emission rate.

Tabl e 10. d : Calculation to Determine New Jersey Ozone Season NO X Budget Revisions

- Assuming O ut

- of

- M erit

- O rder D ispatch at S ix P lants

A B C D E F G H I J K

Plant Name Unique

ID Capacity

(MW) 2012 Ozone

Season NO X Emission

from

TR_Remedy

Final_2012

( 1000 ton s ) Heat Rate

(BTU/kWh) Ozone Season

Generation

from

TR_Remedy

Final_2012

(GWh) NO X

Emission

Rate from

TR_Remedy

Final_2012

( lbs/mmBtu ) Ozone

Season

Average

Out

- Of

Merit

Order

Capacity

Factor Additional

Ozone

Season

Generation

(GWh) * Additional

Ozone

Sea son Heat Input

( mm Btu) Additional

Ozone

Season

NO X 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 m aking.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% 2.7 9 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 6.032

PSEG

Essex 2401_

G_101 4 2 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% 0.00 0 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

Kea rny 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 0.033

PSEG

Kearny 2404_

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

PSEG

Linden 240 6_

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

Sew a ren 2411_

B_1 104

- 12377 0.00 0.12 6.4% 24.28 300,531 17.6

PSEG

Sew a ren 2411_

B_2 118

- 13581 0.00 0.16 4.7% 20.31 275,884 22.1

PSEG

Sew a ren 2411_

B_3 107

- 14500 0.00 0.15 6.0% 23.73 344,085 26.1

PSEG

Sew a ren 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 NO X Budget Revisions

- Assuming O ut

- of

- M erit

- O rder Dispatch at S ix P l ants

A B C D E F G H I J K

Plant Name NEEDS

Unique

ID Capacity

(MW) 2012 Annual

NO X Emission

( 1000 tons )

from

TR_Remedy

Final_2012 Heat Rate

from

TR_Remedy

Final_2012 GWh Annual

from

TR_Remedy

Final_2012 NO X

Emission

Rate from

TR_Remedy

Final_2012

( lbs/ mmBtu ) Annual

Average

Out

- Of

Merit

Order

Capacity

Factor Additional

Annual

Generation

(GWh) * Additional

Annual

Heat Input

( mm Btu) Additional

Annual

NO X 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 3 6.3% 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 8.035

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 0.3 0 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

E ssex 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 16.436

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% 7.9 0 133,445 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 240 1_

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

Sew a ren 2411_

B_1 104

- 12377 0 0.12 2.8% 25.71 318,163 18.6

PSEG

Sew a ren 2411_

B_2 118

- 13581 0 0.16 1.9% 19.24 261,271 21.0

PSEG

Sew a ren 2411_

B_3 107

- 14500 0 0.15 2.7% 25.45 368,953 28.037

PSEG

Sew a ren 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 t he 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 w ould be offset by decreasing

generation at New Jersey combined cycle un its, 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 NO X emissions associated with the dis placed

generation ( column D) w ere calculated by multiplying th at generation by the average heat rate and the relevant emission rat e at the representative combined

cycle unit

.

Table 10

. f : Calculation of Emissions from Displaced Generation at New Jersey Com bined Cycle Unit s

A B C D

Program

Period Displaced Generation

(GWh) Heat Rate

(BTU/kWh) NO X Emission Rate

(lbs/MMBTU) Displaced NO X 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 to tal revisions proposed to New Jersey’s state budget s 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 NO X Budget Revisions (tons)

2012 2014

SO2 Annual

NO X Ozone

Se ason NO X SO2 Annual

NO X Ozone

Season NO X

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 f rom Out

- Of

- Merit

- Order Gene ration 0 775 215 0 775 215

D Net Budget Revision s f or New Jersey (A+B

- C) 2096 420 592 0 112 195

The original and r evised values for the state SO 2 , annual NO X , and ozone season NO X budget s , assurance level s , and new unit set

- aside s are

described in Tabl e 10. h

.

Table 10

. h.: Impact of New Jersey Budget Revisions

– Assuming N o 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 SO 2 5,574 118% 6,577 2% 111

2012 Revised SO 2 7,670 118% 9,05 1 2% 153

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

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

2012 Initial Annual NO X 7,266 118% 8,574 2 % 145

2012 Revised Annual NO X 7 ,686 118% 9,0 69 2% 154

2014 Initial Annual NO X 7,266 118% 8,574 2 % 145

2014 Revised Annual NO X 7,378 118% 8,706 2% 148

2012 Initial Ozone

- Season NO X 3,382 121% 4,092 2 % 68

2012 Revised Ozone

- Season NO X 3,974 121% 4,809 2% 79

2014 Initial Ozone

- Season NO X 3,382 121% 4,092 2 % 68

2014 Revised Ozone

- Season NO X 3,577 121% 4,32 8 2% 72

*Approximate set

- aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations39

11) Louisiana

EPA is proposing to increase Loui siana’s ozone season NO X 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 disp atch area s 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 doc umentation 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 Enter gy

. 30

As discussed later in this section, EPA assumes that th e 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 NO X budget is a 4,231 ton increase

.

The calculations of the increase in ozone season N O X emissions due to out

- of

- merit

- order dispatch at the five facilities is shown in Table 11.a. F or

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 emis sion 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

- me rit

- order capacity factor, and the

number of hours in t he ozone season (column I). The additional heat input required was calculated by multiplying the incremental generation by th e 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 NO X 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 NO X Budget Revisions

- Assuming O ut

- of

- M erit

- O rder Dispatch at F ive P lants

A B C D E F G H I J K

Plant Name Unique

Id Capacity

(MW) 2012 Ozone

Season NO X Emission s

from

TR_Remedy

Final_2012

(1000 tons) Heat Rate

(BTU/kW

h) Ozone

Season

Generation

from

TR_Remedy

Final_2012

(GWh) Ozone Season

NO X Rate

(lbs/mmBtu) Ozon e

Season

Average

Out

- Of

Merit

Order

Capacity

Factor Additional

Ozone

Season

Generation * Additional

Ozone

Season Heat

Input

(mmBtu) Additional

Ozone

Season

NO X 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 27.941

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 i n 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 NO X emissions associated with the displa ced generation

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

Table 11

. b : Calculation of Emissions from Displaced Generation at Louisiana Combine d Cycle Units

A B C D

Program

Period Displaced Generation

(GWh) Heat Rate

(BTU/kWh) NO X Emission Rate

(lbs/MMBTU) Displaced NO X 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

- ord er 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 calcu lations 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 NO X Budge t Revisions (tons)

A Additional Emissions Due to

Out

- Of

- Order

- Merit Dispatch 4,947

B Di splaced Emissions From

Out

- Of

- Order

- Merit Dispatch 716

C Net Emission budget Change

For Louisiana (A

- B) 4,231

The original and r evised values for the state ozone season NO X budget, assurance level, and new unit set

- aside are described in Table 1 1

. d

.

T able 11

. d.: Impact of Louisiana Ozone

- Season NO X 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% 21,37 2 3% 530

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

2014 Revised 17,663 121% 21,37 2 3% 530

*Approximate set

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

allocations

1 2 ) Mississippi

EPA is proposing to increase Mississippi’s ozone season NO X 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 demonst rating 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 n on

- economic generation at the units displayed below during the implementation of the Transport Rule43

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 th e 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 emis sions taking that offsetting factor into account

. The net impact of these changes on the state’s ozone

season NO X budget is a 2,136 ton increase

.

The calculations of the increase in ozone season NO X 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 o zone season (column I). The additional heat input required was calculated by multiplying the incremental generation by the un it’s

heat rate (column J). Finally, the additional emissions associated with the out

- of

- merit

- order generation was calculated by mu ltiplying the additional heat

input by the unit’s NO X emission rate.

32 Correspondence from Entergy to EPA, September 29, 2011. Please see the document “Transmissi on 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 C apacity

(MW) 2012 Ozone

Season NO X Emission s

from

TR_Remedy

Final_2012

(1000 tons) Heat Rate

(BTU/kW

h) Ozone

Season

Generation

from

TR_Remedy

Final_2012

(GWh) Ozone

Season NO X Rate

(lbs/mmBtu) Ozone Season

Average Out

Of

- Merit

Order

Capacity

Factor Add itional

Ozone

Season

Generation * Additional

Ozone

Season

Heat Input

(mmBtu) Additional

Ozone

Season

NO X 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 u sed 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 genera tion 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

- we ighted average of Mississippi combined cycle units. 33 The ozone season NO X 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 repr esenta tive 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 1 2

. 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) NO X Emission Rate

(lbs/MMBTU) Displaced NO X Emissions

(t ons)

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 t he 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 Miss issippi

Ozone Season NO X 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) 2,13646

The original and r evi sed values for the state ozone season NO X budget, assurance level, and new unit set

- aside are described in Table 12.d.

Table 1 2

. d.: Impact of Mississippi Ozone

- Season NO X 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% 1 2

, 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

*Approx imate 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 NO X and ozone season NO X budget s in 2012 and 2 014 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 area s. 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

implementat ion 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 co me 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 NO X and ozone season NO X budget s 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 NO X emissions due to out

- of

- merit

- order dispatch at the two facilities is shown in Table

1 3 .a. For each unit with out

- of

- merit

- ord er 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 calculat ed 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 NO X emission rate.48 Table 13 .a: Calculation to Determine Texas NO X * Budget Revisions

- Assuming O ut

- of

- M erit

- O rder Dispatch at Two P lants

A B C D E F G H I J K

Plant Name Unique

ID Capacity

(MW) 2012 Ozone

Season NO X Emission

from

TR_Remedy

Final_2012

(1000 tons) Heat Rate

(BTU/kWh) Ozone

Season

Generation

from

TR_Remedy

Final_2012

(GWh) Ozone

Season NO X Rate

(lbs/mmBtu) Ozone

Season

Average

Out

- Of

Merit

Order

Capacity

Factor Additional

Ozone Season

Generation ** Additional

Ozone

Season

Heat Input

(mmBtu) Additional

Ozone

Season

NO X 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 an nual 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 th e 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) an d emission rate (column C)49

equal to the capacity

- weighted average of Texas combined cycle units. 35 The ozone season NO X emissions associated with the displaced generation (column

D) were calculated by multiplying that generation by the average heat rate and the relev ant 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) NO X Emission Rate

(lbs/MMBTU ) Displaced NO X 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 e missions 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

NO X and Ozone Season NO X 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

F or 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

- weight ed average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of he at rate and emission

rate averages used in Budget Revisions” found in the docket for this rulemaking.50

In addition to the rev isions 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 revision s to the Texas budgets and NUSAs are summarized

in Table 13.e.

Table 13.d.: Summary of T exas SO 2 Budget

Revisions

Removed FGD R evision 26,359

FGD Capture R evision 43,708

Total SO 2 Budget R evision 70,067

Table 13

. e.: Impact of Texas Budget Revisions

– Assuming Removed FGDs and Revised FGD C apture a t Certain

Units, R evised NUSAs for Oak Grove 2, and Out

- o f

- Merit

- Order Dispatch at Two F acilities (tons)

Program Budget Assurance Level Total New Unit Set

- Aside *

% of Budget Tons % of

Budget Tons

2012 Initial SO 2 243,954 118% 287,866 5% 12,198

2012 Revised SO 2 314,021 118% 370,545 5% 15,701

2014 Initial SO 2 243,954 118% 287,866 5% 12,198

2014 Revised SO 2 314,021 118% 370,545 5% 15,701

2012 Initial Annual NO X 133,595 118% 157,642 3% 4,008

2012 Revised Annual NO X 134,970 11 8% 159,265 4% 5,399

2014 Initial Annual NO X 133,595 118% 157,642 3% 4,008

2014 Revised Annual NO X 134,970 118% 159,265 4% 5,399

2012 Initial Ozone

- Season NO X 63,043 121% 76,282 3% 1,891

2012 Revised Ozone

- Season NO X 64,418 121% 77,946 4% 2,577

2014 In itial Ozone

- Season NO X 63,043 121% 76,282 3% 1,891

2014 Revised Ozone

- Season NO X 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