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

Docket ID No. EPA

- HQ

- OAR

- 2009

- 0491



# Final Revisions Rule State Budgets and

New Unit Set

- Asides TSD

U.S Environmental Protection Agency

Office of Air and Radiation

February 20122 EPA finalized the Transport Rule in July of 2011

. 1 EPA is now finalizing revisions to certain states’ emission budget s under the Transport R ule as
well as revis ions to certain new unit set

- asides (NUSAs) under the Transport Rule programs

. T his technical support document show s the underlying data

and calculations used to quantify the state budget revisions and new unit set

- aside revisions made in the final revisions rule 2 , as well as those revisions

included in the d irect f inal revisions r ule. 3 Section A below summarizes the net impact of the revisions in each rule on each affected state budget and

NUSA

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

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

Each revision to a state budget also entails corresponding revisions to the absolute number of allowances put into the relevant ne w unit set

- aside 4 as well as

to the absolute assurance level 5

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

. for the relevant pol lutant in that state, as NUSAs and assurance levels are both calculated by applying percentage values to the relevant state budget (using the methodologies described in the final Transport Rule).

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

. The direct final revisions rule affects state emissions budgets and/or NUSAs for South Carolina, Nebraska, Indiana, Ohio, New York, Kansas, Georgia, Arkansas, Louisiana

, Missouri , Mississippi, Texas, Kansas and Oklahoma

. 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 assessed in that rulemaking

. The revisions to the Transport

Rule state budgets and NUSAs are summarized in T able s A.1. and A.2. below.

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

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

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

4 The “Tot al NUSAs” presented for each state in section s B and C of this document include allowances under both the State NUSA and the Indian Country NUSA (where the latter exists in the given state).

5 EPA has also proposed in this action to amend the effective dat e of the assurance provisions in all states to start in 2014 instead of in 2012.3 Table A.1.: Final Rule Revisions to Transport Rule State Budgets and NUSAs

2012

– 2013 State Budgets 2014 and beyond State Budgets NUSA*

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 Michigan 5,228 5,228 2%

Nebraska 3,599 3,599 6%

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

Florida 819 2%

Arkansas 5%

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

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

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

Louisiana 4,594 4,594 3%

Mississippi 2,154 2,154 2%

* Approximate set

- aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations4 Table A.2.:Direct Final Rule Revisions to Transport Rule State Budgets and NUSAs

2012

– 2013 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
South Carolina 8,013 8,013 0 2% 2% 2%

Nebraska 3,110 3,110 4% 6%

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

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

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

Kansas 452 640 452 5,794 2% 2%

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

Arkansas 1 73 73 8 %

Louisiana 89 89 2%

Missouri 2 26 26 26 26 3% 6% 6%

Mississippi 115 115 2%

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

Oklahoma 3 859 859 2%

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

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

3 Revision applies in 2013 and beyond.

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

.

1)

EPA is finalizing an increase to Michigan’s 2012 and 2014 annual NO X budget s as proposed to correct for the assumption that Selective Catalytic Reduction (SCR) technology is currently installed at Monroe Unit 2 . This SCR is planned for future installation but is not expected to be operating by 2012 Michigan5 or by 2014. Therefore, EPA is revis ing the state’s 2012 and 2014 annual NO X emissi on budget s 6

Table B. 1.a

. : Calculation to Determine Michigan Annual NO X Budget Revision

- Assuming no SCR at Monroe U nit 2 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 as sumption is

relevant to the calculation of the state’s ozone

- season NO X budget ; EPA already included this revised assumption in its quantification of that budget when the Agency issued the Transport Rule Supplemental Notice of Final Rulemaking ( SN F R ) (76 FR 87060)

.

A B C D E F

Plant Unit Emissions from TR_Remedy Final_2012 (1000 tons) Heat Input from

TR _Remedy_Final_2012 ( TBtu ) Remedy Emission Rate
from TR_Remedy_Final_2012 (lbs/ MMBtu ) Revised
Emission

Rate (lbs/ MMBtu ) Revised
Emissions Net Budget
Revision (1000 tons)

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

- A

Monroe 2 1.54 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 Monroe 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)

. 7

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

Rule , the NUSA for annual NO X in Michigan remain s at 2%. 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. This 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 S CR to be present at the unit. This value approximates the emission rate expected at the unit at a cost threshold of $500/ton when no SCR is present at the unit. EPA multiplied this NO X rate by the remedy heat input shown in

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

the final Transport Rule remedy analysis emission projection (SCR assumed) determines the amount of the increase to the state’s annual NO X b udget
(column F)

.

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

201 4 and thereafter as a “2014” state budget. Therefore, any revision of a 2012 state budget would apply to the state budget for 2012 and 2013, and any revision of a 2014 state budget would apply to the state budget for 2014 and thereafter.

7 See National El ectric Energy Data System (NEEDS) v4.10 available at http://www.epa.gov/airmarkets/progsregs/epa

- ipm/BaseCasev410.html6 Table B. 1.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

- - 2% 1,308

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

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

*Approximate set

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

2)

EPA is finalizing , as proposed, an increase to Nebraska’s 2012 and 2014 annual 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 wi ll likely be no SCR available at the time of the 2012 and 2014 compliance per iods as originally assumed in EPA’s determination of Nebraska’s annual NO X budgets . Therefore, EPA is

revis ing the state’s 2012 and 2014 annual NO X emission budget s to reflect this unit operating 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. Nebraska

Table B. 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 ) Revised
Emissions (1000 tons) Net Budget
Revision (1000 tons)

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

- A
Nebraska City 1 1.602 45.765 208 0.070 0.2273 5.201 3.5997 Column s A, B, and C show the NO X emissions, heat input, and emission rate from the TR_Remedy _Final_2012 modeling when an SCR is assumed to be present. Because no SCR is present, EPA modified the emission rate to reflect the “controlled NO X policy rate” in the NEEDS version from the September 1, 2010 TR Notice of Data Availability (NODA) (column D). 8

The change to the annual NO X emission budget in Nebraska will result in a small change 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 projected emissions from “planned units” divided by the 2014 state budget for the relevant pollutant. In the case of Nebraska, the projected emissions from planned units remain unch anged, 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 fro m “planned ” new units, because the budget is larger. For Nebraska, the budget 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 Trans port Rule , and the change in percentage is simply an outgrowth of the state’s budget revision

. This change in the NUSA percentage yields only a marginal change in the absolute number of allowances in the

Nebraska NUSA. The original and revis ed values for the state annual NO X budget, assurance level, and new unit set

- aside are described in the table below. This 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 assumed , column E ) and the remedy emission projection (SCR assumed , column A ) determines the amount of the increase to the state’s annual NO X b udget (column F).

Table B. 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

- - 6% 1,802

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

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

*Approximate set

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

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

- ipm/BaseCasev410.html8 3)

EPA is finalizing, as proposed, an 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. Texas (Removed FGDs)

9 10

Table B. 3

. : Calculation to Determine Texas SO 2 Budget Revision

– Assuming no FGD at J.T. Deely or W A Parish unit 6 There will likely be no FGD available at these units during the 2012 and 2014 compliance periods under the Transport Rule programs . Therefore, EPA is revising the state’s 2012 and 2014 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.

A B C D E F

Plant Unit Emissions
from TR_Remedy Final_2012 (1000 tons) Heat Input from TR_Remedy_Final_2012 ( TBtu ) Remedy Emission Rate
from TR_Remedy_Final_2012 (lbs/ MMBtu ) Revised
Emission Rate (lbs/ MMBtu ) Revised
Emissions (1000 tons) Net Budget
Revision (1000 tons)

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

- A
J T Deely 1 0.917 30.55183083 0.060 0.5800 8.860 7.943
J T Deely 2 0.914 30.46546708 0.060 0.5800 8.835 7.921

W A Parish 6 1.211 40.3658592 0.060 0.5800 11.706 10.495

Total 26.359

Columns A, B, and C show the SO 2 emissions, heat input, and emission rate from the TR_Remedy_Final_2012 modeling when an FGD is assumed to be present at these three units . Because no FGD is present, EPA is recalculating projected emissions at these units using the emission rate s shown for

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

. These 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 Rule base case because they

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

. 11

9 “Corporate Sustainability Report”, CPS Energy, 2010. P.57. Retrieved from http://www.cpsenergy.com/files/Sustainability_Rep ort.pdf The rev ised SO 2 emission rate in column D is multiplied by the final remedy heat input shown in column B to obtain a revised emissions projection for the unit (column E) . The difference between this

10 Business Wire, (2006). NRG Announces Comprehensive Repowering Initiative [ Press release]. Retrieved from http://phx.co rporate

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

- newsArticle_Print&ID=874575&highlight

11 See "WebReady_ParsedFile_TR_Base_Case_Final_2012" in the Transport Rule docket or on EPA's CSAPR website9 revised emission projection (no FGD assumed , column E ) an d the remedy emission projection (FGD assumed , column A ) determines the amount of the

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

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

.

4)

EPA is also finalizing an increase to t h e Texas 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 removal rates at those units that the facility operators have previously reported, those facility operators ha ve clarified to

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

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

- through of flue gas on their most

recent Energy Information Administration ( EIA ) 860 form. Texas (FGD Capture)

12 Consequently, at these facilities, the effective removal rate of the FGD as applied to total SO 2 emissions at the affected units would be lower than the reported removal rate would otherwise indicate

. As explained in the final revisions rule preamble, EPA is finalizing this revision based on the SO 2 removal efficiency and flue gas treatment data most recently report ed for these scrubbers by the facility operators to the EIA on form 860 . The approach results in a final SO 2 budget increase of 24,158 tons

. 13

12 Unless otherwise indicated, EPA used data from EIA form 860 as submitted for the year 2008 to calculate the revisions present ed in this document, as this is the same year for which EPA used EIA form 860 data to inform pollution control removal efficiencie s at all units in the Transport Rule power sector modeling.

13 EPA originally proposed a related budget increase of 43,708 tons, based on the same calculations presented here but using dat a reported for 2008 on EIA form 923.10 Table B. 4

. : Calculation to Determine Texas SO 2 Budget Revision

- Assuming Design SO 2 Removal Rates at FGD and Percent Flue Gas Entering FGD

A B C D E F G

Total SO 2 Emissions from

2012 TR_Remedy_Final (1000 tons) EIA 860
Removal Rate (used in budget determination) EIA 860
Percent of

Flue Gas Entering FGD Calculated
Removal

Rate (used for budget

revision estimate) Uncontrolled

Emissions (assuming no FGD)(1000 tons) Revised

Emissions (assuming

FGD with
revised removal rate) (1000 tons) Net Budget
Revision (1000 tons)

B*C A/(1

- B) E*(1

- D) F

- A

Martin Lake 1 1.862841 0.95 0.95 0.903 37.2568208 3.63254 1.7696989

Martin Lake 2 1.8540181 0.95 0.95 0.903 37.0803634 3.6153354 1.7613172

Martin Lake 3 1.745038 0.95 0.95 0.903 34.9007605 3.4028241 1.6577861

Monticello 3 2.548471 0.95 0.75 0.713 50.96942 14.6537082 12.105237

Oklaunion 1 2.2321097 0.868 0.81 0.703 16.9099223 5.0208941 2.7887843

Sandow 4 1.2522935 0.92 0.83 0.764 15.6536693 3.7005274 2.4482338

W A Parish 8 1.5948385 0.85 0.82 0.697 10.6322566 3.2215737 1.6267352

Total 13.090 6.438 6.060 5.586 203.403 37.247 24.158

Column A shows the projected emissions at these units as originally modeled in the final Transport Rule remedy for 2012 . Column B shows the SO 2 removal rate that those 2012 emission projections are based on. Column C shows the source reported percent of flue gas entering FGD. Column D shows

the emission rate based on multiplying the removal rate by the percent of flue gas entering FGD

. Column E shows a calculation of projected emissions at each unit if the previously assumed FGD removal hadn’t occurred at all; these “uncontrolled emissions” are calculated in orde r to allow application of the

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

. The

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

assumed , col umn A ) determines the amount of the increase to the state’s SO 2 b udget (column G ). The impact s of all revisions to Texas state budgets on the

state’s NUSA s and assurance level s are shown in Tables B. 13.d and B. 13.e.11 5) Florida

EPA is finalizing, as proposed, a re vision to Florida’s 2012 ozone

- season NO X budget to correct for the assumption that Crystal River Unit 3 , a
nuclear unit 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 finalizing an increase to the state’s 2012 ozone season NO X budget by 819 tons to reflect 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 below.

Table B. 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) Average Ozone

- Season

NO X Emission Rate of Replacement
Generation (lbs/MMBTU) Ozone

- Season NO X Emissions from Replacement
Generation (tons)

Calculation A*B*C/2000 Crystal River 3 2,976 8,340 0.066 819

Column A shows the ozone

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

Columns B and C show the capacity

- weighted average heat rate and ozone

- season NO X emission rate from combined cycle natural gas units in Florida that

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

. 14

Th 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 t able

below. 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 operation 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 increase to the state’s 2012 ozone

- season NO X budget.

14 These capacity

- weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “ Calculation of heat rate and emission rate averages used in Final Revisions Rule ” found in the docket for this rulemaking.12 Table B. 5.b.: Impact of Florida Ozone

- Season 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 28,644

- - 2% 573

*Approximate set

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

6) Arkansas

Plum Point Unit 1 in Arkansas commenced commercial operation on or after January 1, 2010. Such a date qualifies Plum Point Unit 1 as a “planned” new unit by the definition of that category described in the “ Allowance Allocation Final Rule TSD ” for the Transport Rule

. However, in the final Transport Rule , EPA did not recognize Plum Point Unit 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 minimum value of 2%. 15 EPA is finalizing, as proposed , a revision to 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.

Table B. 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 for new unit set

- aside 2%

E Total New Unit Set

- Aside ( C + D ) 5%

15 A s explained in the final Transport Rule, the minimum size of any state’s new unit set

- aside is this “base percentage” amount, to which “state

- specific” percentages are added if the given state has projected emissions from “planned” new units (76 FR 48291).13 Because Plum Point was the only “planned” new unit for the state of Arkansas, EPA divided its projected emissions into the state budget to derive

the state

- specific percentage for the new unit set

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

- aside
(2 %). The resulting new unit set

- aside percentage for o zone s eason NO X in Arkansas is 5%. This change does not impact the state budget or assurance level in any way. However, the new unit set

- aside change s by the levels shown below. 16

Table B. 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
Existing Unit Allocation 98% 95% 14,736 14,285

Total 100% 100% 15,037 15,037
*Approximate set

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

allocations

7)

The Oak Grove Unit 2 in Texas commenced commercial operation on or after January 1, 2010. Such a date qualifies Oak Grove Unit 2 as a “planned” new unit by the definition of that category described in the “ Allowance Allocation Final Rule TSD ” . However, in the final Transport Rule

, EPA did not recognize Oak Grove Unit 2 as a new unit and therefore omitted its projec ted 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 finalizing, as proposed , a
revision to 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. Texas (NUSA)

16 The increase to the new unit set

- aside would necessarily change existing unit allowance allocations in order to maintain the state budget. To review the existing u nit
allowance allocations associated with this revision , please see the document entitled “ Final Revisions Rule Unit

- Level Allocations under the FIPs ” found in the docket to this rulemaking

.14 Table B. 7

. : Calculation for Texas's NUSA s

SO 2 NO X Ozone

Season NO X
A Projected 2020 Emissions from planned new fossil (tons)* 9,855 2,727 1,216

B TX State Budget (tons) 294,471 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 revisions to Texas state budgets (and these revisions to the NUSAs) on the state ’s NUSA s and assurance level s are shown in

Table s B. 13.e.

8)

EPA is finalizing, as proposed, 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 finalizing, as proposed, a revision to 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 finalizing

any revision related to this unit for the state’s 2012 SO 2 budget. The calculation s to quantify th is revis ion are shown in the table below. Wisconsin

Table B. 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 5.60515 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 input 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 cal culated 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 dete rmine the

amount of the increase to Wisconsin’s 2014 SO 2 budget related to this unit, shown in column C

.

EPA i s also finalizing, as proposed, 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 Natural Resources (WDNR)

has informed EPA that they have been planned and approved as dry scrubbers instead. In its analysis of the final Transport Rule, EPA assumed 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 finalizing, as proposed, 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 finalizing any revision related to these units for the state’s 2012 SO 2 budget.

Table B. 8.b.: Calculation to Determine Wisconsin SO 2 Budget 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 calculated in order to allow application of the revised FGD removal rate of 92% to these uncon trolled emissions, which yields the revised emission projection for each16 unit in column C. The difference between this revised emission projection ( dry scrubbers assumed , column C ) and the remedy emission projection ( wet

scrubbers assumed , column A ) deter mines the amoun t of the increase to the state’s 2014 SO 2 b udget (column D ).

EPA is also finalizing, as proposed, a revision to Wisconsin’s a nnual NO X budget for 2012 and 2014 to correct for the assumption that an SCR will be in place at John P. Madgett Un it 1 in 2012 and 2014. There are currently no plans to have an SCR in place by 2014 at the unit. Therefore, EPA is revising the state’s 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. EPA also recognizes that this revised input assumption is relevant to the calculation of the state’s ozone

- season NO X budget ; EPA already included this revised assumption in its quantification of that budget when the Agency issued the Transport Rule SN F R (76 FR 87060)

.

Table B. 8

. c

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

- Assuming no SCR at J P Madgett

A B C D E F

Plant Name Unit

ID Emissions

from TR_Remedy Final_2012 (1000 tons) Heat Input from TR_Remedy_Final_2012 ( TBtu ) Remedy Emission Rate fromTR_Remedy_Final_2012 (lbs/ MMBtu ) Revised

Emission

Rate (lbs/ MMBtu ) Revised

Emissions (1000 tons) Net Budget Revision (1000 tons)

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

- A J P Madgett B1 0.588922429 23.55689678 0.05 0.26 3.062 2.473

Columns A, B, and C shows the emissions, heat input, and emission rate from the 2012 remedy modeling for the J P Madgett unit

. Because no SCR is present, EPA is recalculating projected emissions at this unit using the emission rate shown for this units in EPA’s analysis of the base case for the final Transport Rule, as found in the TR_Base_Case_Final for 2012 (column D). This annual NO X emission rate reflects generation at this unit wit hout 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 operate in that scenario. 17

The revisions to the SO 2 emission budget for Wisconsin result s 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 calculated as the percentage equal to The J P Madgett emission rate without ope rating an SCR (column D) multiplied by the remedy heat input
(column B) yields the projected emissions from the unit if no SCR were assumed to be in place. The difference between the projected emissions when no SCR is in place (column E) and the projected emissions when an SCR is assumed (column A) determines the amount of the increase to the state’s 2012 and

2014 annual NO X budget s (column F)

.

17 See "WebReady_ParsedFile_TR_Base_Case_Final_2012" in the Transport Rule docket or on EPA's CSAPR website17 the projected emissions from “planned units” divided by the state budget for the relevant pollutant. In the case of Wisconsin, the projected emissions from planned units remain unchanged, but the budget is increasing. 18 Because the numerator remains unchanged but the d enominator 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 budget revision decrease s 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 percentage is simply an outgrowth of the state’s budget revision

. While this change in the NUSA percentage reduce s 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 and 20 14 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 B. 8.d.: Impact of Wisconsin Budget Revisions

– Assuming no FGD at Weston Unit 3, no SCR at JP Madgett, and dry FGD at Columbia (tons)

Program Budget Assurance Level Total New Unit Set

- Aside *

% of Budget Tons % of Budget Tons

2012 Initial SO 2 79,480 118% 93,786 5% 3,974

2012 Revised SO 2 79,480

- - 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

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

18 While this relationship is also true for annu al NO X , the revision s to Wisconsin’s annual NO X budget do not yield a different calculated NUSA percentage than the originally determined 6% under the final Transport Rule.18 9)

EPA is finalizing, as proposed, an increase to the New York state annual NO X , ozone

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

near

- term operation 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 Contingency, the Minimum O il Burn
Rules, and local out

- of

- merit

- order dispatch conditions. Each calculation of the near

- term emission impact found to be associated with these constraints is
documented below; the results are summarized in Table B. 9 .f

. New York

N

- 1

- 1 Contingency

Certain par ts of the Con Edison system in New York City are required to be designed and operated for the occurrence of a second continge ncy, also

known as an N

- 1

- 1 contingency; these requirements are in addition to any requirements for the first (N

- 1) contingency on which the overall New York State power system is operated. The local rules that determine the operation and unit commitment for New York City are New York State Reliability Council
(NYSRC) rules I

- R1 through I

- R4. 19

The dispatch requirements apply throughout the year, but there are also additional environmental requirements unique to ozone season operation. During the ozone season, the NYISO determines generator operations su bject to local environmental regulations that require NYISO to dispatch certain steam units before seeking additional power from CTs when needed, to balance the need to meet energy and reserve requirements against daily local

emissions for these units. NY ISO 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 need ed. For the To meet the requirements of these rules, the New York Independent System Operator (NYISO) performs a supplemental commitment of units in the New York City zone. The rules require additional reserves from in

- city combustion turbines (CTs), as well as uni t

commitment of steam units where needed to 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 effe ct throughout the year and are implemented by NYISO in a daily and hourly unit commitment process specific to New York City. Depending on the expected load level and the pattern of load during the day, NYISO

will commit steam units to meet intermediate lo ad 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 th ese 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 res ponse to grid disruption contingencies.

19 See Rule I

- R1 , NYSRC Reliability Rules For Planning and Operating the New York State Power System , Version 29, New York State Reliability Council (NYSRC), January 7, 2011, p. 66.19 steam units in New York City (Arthur Kill, Ravenswood and Astoria), these procedures mean that one or more steam units must be running for the entire

ozone season. 20

Minimum Oil Burn Rules

In order to ensure that units do not go offline if th ere is a loss of natural gas supply to New York City, the NYSRC rules incorporate special provisions that require natural gas units to be prepared to switch from natural gas to oil immediately upon notice of a loss of natural gas supply. These provisions are implemented through utility applications to the NYISO for special summer and winter dispatch conditions designed to gover n when generators must be prepared to burn oil in each season. 21 For certain oil/gas steam units that do not have the ability to sw itch 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 this procedure twice each year based on expected conditions

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

Since in the current outlook the price of oil is much higher than gas for the same heat input , EPA recognizes that these operations would not be captured in projections of economic generating behavior. As such, EPA has calculated revised emission projections at the units affected by the minimum oil

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

Local Out

- of

–

Merit

- Order Dispatch

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

interstate cables connecting Long Island with the Independent System Operator for New England ( ISO

- NE ) and the PJM Interconnection

. Because the lines

from ISO

- NE and PJM are d irect c urrent (DC) lines that are not dispatched in real time 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 NYIS O 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 25

20 See Analysis of New York City Averaging Plans for Compliance with NOx Emissions Limitations , New York Independent System Operator, Inc., 2011 show s that NYISO is limited to approximately 860 MW of dispatchable 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

21 NYSRC Rel iability 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 Islan d Operations.

22 See ConEd, Application for the Loss of Generator Gas Supply

– New York City, OC Meeting

– May 12, 2011 , for the requirements for the summer 2011 procedures.

23 See the document, Long Island Gas Burn Procedures

– 2011 , in the docket for the T R Rule Revisions Proposal, Docket.

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

25 See NYISO Operating Study Summer 2011 and Appendices, New York Independent System Operator, July 14, 2 011, page C

- 3.20 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 res pecting the 7.5 TWh limitation on imports from the rest of NYISO, notwithstanding the economic merit of that imported generat ion . 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 per cent from the Northport unit that was modeled to dispatch

.

Calculation of New York City Revised Generation and Emissions

– Plant Level

To reflect the requirements of the NYSRC rules as implemented by the NYISO for New York City , EPA is assuming that additi onal 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 . These calculations

establish the assumed minimum generation at each facilit y that would dispatch in the immediate term to meet the conditions o f the NYSRC rules independent of the economic merit of that generation within the larger region as originally modeled . Where EPA’s originally projected generation for the
unit was less than this minimum, EPA has calculated here the difference in generatio n from the unit and, most importantly, the associated emissions from that generation, in order to inform the revision to the New York state budgets under the Transport Rule . Calculations were performed separately for ozone

season and non

- ozone season peri ods. During the ozone season, the se dispatch conditions were assumed to apply 100% of the time; during the 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 each 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 B. 9 .a and B. 9.b

.

To account for the effects of the minimum oil burn rule in New York City, EPA calculated 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 unit s ar e shown in Table B. 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 represent the

additional use of oil.21 Table B. 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 Ravenswood 356 0.0% 11714 0.07 0.000 0 50.0% 653 653 256.5

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

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

8906_B_40 Astoria 373 44.4% 10117 0.06 6.150 608 50.0% 685 77 23.822 Table B. 9.b .: Annual NO X and SO 2 Revised Unit

- Level Emission Projections for New York City
for N

- 1

- 1 Contingency Operation and Minimum Oil Burn Rule

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

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

Unique

ID Plant

Name Capacity (MW) Capacity

Factor Heat

Rate (BTU/ kWh) 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) 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 Arthur

Kill 491 13.3% 10198 0.10 5.836 572 32.6% 1,401 829 416.9 0.000 0.0
2500_ B_10 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
8906_ B_30 Astoria 366 18.6% 10123 0.06 6.039 597 32.6% 1,044 448 138.6 0.065 358.3
8906_ B_40 Astoria 373 18.6% 10117 0.06 6.150 608 32.6% 1,064 456 141.1 0.065 364.9
8906_ B_50 Astoria 359 18.6% 10120 0.06 5.921 585 18.6% 585 0 0.0 0.065 200.7

*Assumes the IPM v.4.10_FTransport SO 2 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 level projected in IPM modeling of the Transport Rule

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

into L ong Island. EPA is assum ing that th is additional generation would occur at the Northport facility distributed across its three units. Since the three units have virtually identical heat rates, EPA assumes that these units would be operated at the same ca pacity factors; EPA therefore establishes a minimum capacity factor at each unit in order to produce an additional 2.2 TWh beyond the original IPM projection

. In concert with these assumptions, EPA

calculat ed additional ozone

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

shown above . The se calculations are provided in Table s B. 9 .c and B. 9 .d below.23 Table B. 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 Required
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 B. 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 0.122 573.7
2516_ B_3 Northport 391 0.0% 10634 0.14 0.000 0 25.1% 860 860 621.6 0.122 578.1
2516_ B_4 Northport 385 0.0% 10663 0.10 0.000 0 25.1% 847 847 455.2 0.122 570.8

Assumes the IPM v.4.10_FTransport SO 2 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 would offset the need for an equivalent amount of gen eration 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 IPM determinations of least

- cost dispatch . These calculations

are shown in Table B. 9

. e

.

Table B. 9

. e

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

York *

A B C D Program
Period Displaced Generation (GWh) Heat Rate (BTU/kWh) 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 revisions to Transport Rule state budgets in New York, EPA has calculated the net emissions change associated with the revisions to

unit

- level generation presented in this section, including the displ aced emissions shown in T able B. 9.e . T hese calculations are shown in Table B. 9

. f

.25 Table B. 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 Emissions 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 revisions to the annual and ozone season NO X emission budget s for New York 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 Transport Rule, the state

- specific portion of the NUSA is calculated as the percentage equal to the projected emissions from “planned units” divided by the state budget for the relevant pollutant. In the case of New York , the projected emissions from planned units remain unchanged , but the budget s are increasing. 26 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 budget revision s decrease the NUSA percentages for both annual NO X and ozone season NO X from 3 % to 2 % as a result. This is applying the same NUSA

me thodology 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 value , the absolute number of allowances in the New York NUSAs rise s in accordance with the 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 B. 9.g below

.

26 While this relationship is also true for SO 2 , the revision s to New York’s SO 2 budget do not yield a different calculated NUSA percentage than the originally determined 2% under the final Transport Rule.26 Table B. 9.g.: Impact of New York Budget Revisions

– Assuming Out

- of

- Merit

- Order Dispatch at New York City and Long Island Units (tons)

Program Budget Assurance Level Total New Unit

Set

- Aside*

% of Budget Tons % of Budget Tons

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

2012 Revised SO 2 30,852

- - 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

- - 2% 421

2014 Initial 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

- - 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 )

EPA is finalizing, as proposed , an increase to 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 all owed for a delay in installation of the control technology until the end of 2013. Additionally, the AO requires that this unit only run during the ozone season

. New Jersey

27

27 Personal Correspondence from Bill O’Sullivan, New Jersey Department of Environmental Protection, to Sam Napolitano. September 26, 2011. Therefore, EPA is adjusting the state’s 2012 emission budget s to reflect this27 unit operating only in the ozone season and without a scrubber or SCR. This results in a 2,096 ton increase to the state’s 2012 SO 2 budget; a 273 ton

increase to the state’s 2012 annual NO X budget; and a 397 ton increase to the state’s 2012 ozone season NO X budget. As discussed later in this section, EPA

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

at well

- controlled combined cycle units within the s tate, and the ir associated emissions are factored into the revision s 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 B. 10 .a.

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

A B C D E F

Pollutant Ozone Season
Emissions
from TR_Remedy Final_2012 (1000 tons) Ozone Season Heat Input from TR_Remedy_Final_2012 ( TBtu ) Remedy Emission Rate
from TR_Remedy_Final_2012 (lbs/ MMBtu ) Revised
Emission Rate (lbs/ MMBtu ) Revised Ozone
Season
Emissions (1000 tons) Net Change
in Ozone
Season
Emission s (1000 tons)

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

- A

SO 2 0.175 2.282 0.15 3 2.190 2.499 2.324

NO X 0.105 2.282 0.092 0.440 0.502 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 required by the AO in 2012 , EPA modified the

emission rate s by removing the impact of the scrubber 28 and adopting the “controlled NO X policy rate” in the NEEDS version from the September 1, 2010 TR Notice of Data Availability (N ODA) , which does not reflect operation of an SCR at that unit (column D). 29

28 The SO 2 emission rate for BL England Unit 1 in TR_Remedy Final_2012 was 0.153 lbs/ MMBtu . Removing the impact of that previously assumed scrubber’s SO 2 removal rate of 93% yields an uncontrolled SO 2 emission rate of 2.19 lbs/ MMBtu

. 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 multipli ed by the remedy heat input shown 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 ) determines the net change to this unit’s

ozone

- season emissions (column F).

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

- ipm/BaseCasev410.html28 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 unit occurring outside of the ozone season. EPA assumes that this decrease in previously projected generation at BL England Unit 1 would be offset by increasing generation at New Jersey combined cycle units

, 30 represented in these calculations as a generic unit with a

heat rate and emission rate s equal to the generation

- weighted average of New Jersey combined cycle units. 31 The calculations of emissions from this

re placed generation are shown in Table B. 10.b. As discussed below, the heat and emission rates of the generic unit were revised from the proposal for consistency across all revisions using a generation weighted average, instead of capacity weighted. Additionally, two cogener ation plants were removed

fr om this average based on comments.

Table B. 10

. b .: Calculation of Emissions at New Jersey 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 of Replacement
Generation (lbs/ MMBtu ) Emissions from Replacement Generation (1000 tons)

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

SO 2 253.3 7413 0 0

NO X 253.3 7413 0. 0 136 0. 0 13

EPA calculated the SO 2 and NO X emissions in T able B. 10.b by multiplying the replaced generation (column A) by the generic unit’s heat rate
(column B) and relevant emission rate (column C).

In order to calculate appropriate 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 B. 10. c below

.

30 E xcluding cogeneration facilities, wh ose generation is not solely based on electricity demand.

31 These generation

- weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “ Calculation of heat rate and emission rate averages used in Final Revisions Rule ” found in the docket for this rulemaking.29 Table B. 10. c .: Calculation to Determine New Jersey 2012 Budget Revision s Due to Changes at BL England Unit 1 (1000 tons)

Quantity 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. 0 13

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. 273

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 emissions from ozone season operation without FGD or SCR at BL England Unit 1 (rows A and E) with the net change in emissions from replacing BL England’s generation during the rest of the year (row B minus row C for 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 chan ge
in ozone season NO X emission s at BL England due to removing the SCR (row E)

.

EPA is also finalizing, as proposed, an increas e to New Jersey’s annual NO X and ozone season NO X budgets to reflect the assumption of near

- term operational constraints affecting six plants, based on information provided by the system operator demonstrating that northern New Jersey is an out

- of

- merit

order dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate

- term local conditions de scribed in recently submitted documentation that appear likely to necessitate non

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

programs. Specifically, EPA is assuming additional generation will be dispat ched at six plants (Bergen, Edison, Essex, Kearny, Linden, and Sew a ren Generating Stations) based on the average capacity factor representing the frequency the unit has recently been called on to operate out of merit order,30 calculated from dispatch logbook data provided by PSEG

. 32

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

- of

- merit

- order dispatch at the six facilities are shown in

Table s B. 10. d a n d B. 10. e , respectively. F or each unit with out

- of

- merit

- order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012 , heat rate, generation, and emission rate are shown (columns A to G). The average out

- of

- merit

- order capacity factor is shown in column H. The additional generation for out

- of

- merit

- order dispatch was calculated by multiplying the capacity, the average out

- of

- merit

- order capacity factor, and the number of hours in either the ozone season or year (column I). The additional heat input required was calculated by multiplying the incremental generation by the unit’s heat rate (column J). Finally, the additional emissions associated with the out

- of

- merit

- order generation was calculated by multiplying the additional heat input by the unit’s NO X emission rate. 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 revision s to New Jersey state budgets are based on the net change to projected emissions taking that offsetting factor into account

. The net impact of these changes on the state’s 2012 and

2014 budgets are a 679 ton increase in annual NO X and a 349 ton increase in ozone season NO X
.

Tab le B. 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 tons ) 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
Season Heat Input ( MMBtu ) 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_ G_1301 114 0.010 8841 55.18 0.04 20.1% 84.16 744,050 15.6

32 See the spreadsheet “New Jersey Minimum Noneconomic Dispatch” provided by PSEG on September 26, 2011, in the docket for this rule making.31 Bergen 2398_ G_1401 114 0.010 8841 55.18 0.04 20.1% 84.16 744,050 15.6

Bergen 2398_ G_1501 219 0.020 8841 106.00 0.04 20.1% 161.67 1,429,359 30.0

Bergen 2398_ G_2101 163 0.004 9241 78.89 0.01 22.0% 131.73 1,217,340 7.3

Bergen 2398_ G_2201 163 0.004 9241 78.89 0.01 22.0% 131.73 1,217,340 7.3

Bergen 2398_ G_2301 224 0.006 9241 108.42 0.01 22.0% 181.03 1,672,908 10.0

PSEG
Edison 2400_ G_11 42 0.003 16763 1.37 0.27 2.1% 3.29 55,100 7.4

PSEG
Edison 2400_ G_12 42 0.003 16862 1.37 0.27 2.1% 3.17 53,375 7.1

PSEG
Edison 2400_ G_13 42 0.003 16893 1.37 0.27 1.8% 2.79 47,161 6.3

PSEG
Edison 2400_ G_14 42 0.003 16947 1.37 0.26 1.7% 2.60 44,143 5.8

PSEG
Edison 2400_ G_21 42 0.003 17182 1.37 0.28 2.0% 3.04 52,261 7.2

PSEG
Edison 2400_ G_22 42 0.003 16846 1.37 0.27 2.0% 3.07 51,731 6.9

PSEG
Edison 2400_ G_23 42 0.003 16979 1.37 0.27 1.9% 2.87 48,679 6.6

PSEG
Edison 2400_ G_24 42 0.004 17184 1.37 0.30 1.6% 2.53 43,451 6.5

PSEG
Edison 2400_ G_31 42 0.003 16953 1.37 0.27 1.6% 2.52 42,653 5.7

PSEG
Edison 2400_ G_32 42 0.003 16984 1.37 0.27 1.8% 2.76 46,909 6.3

PSEG
Edison 2400_ G_33 42 0.003 17033 1.37 0.27 1.9% 2.87 48,964 6.6

PSEG
Edison 2400_ G_34 42 0.003 16950 1.37 0.26 1.7% 2.68 45,443 6.0

PSEG

Essex 2401_ G_101 42 0.003 16968 1.37 0.30 2.6% 4.00 67,800 10.232 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 Kearny 2404_ G_N122 43.7 0.003 9791 7.26 0.09 0.2% 0.27 2,670 0.1

PSEG Kearny 2404_ G_N123 43.8 0.003 10109 7.28 0.09 0.0% 0.02 201 0.0

PSEG Kearny 2404_ G_N124 43.7 0.003 9704 7.26 0.09 0.2% 0.26 2,475 0.133 PSEG

Linden 2406_ G_5 86 0.005 12110 14.51 0.06 2.1% 6.58 79,681 2.4

PSEG

Linden 2406_ G_6 86 0.005 12601 14.51 0.05 2.1% 6.60 83,206 2.1

PSEG

Linden 2406_ G_7 84 0.005 12155 14.17 0.06 2.5% 7.83 95,173 2.8

PSEG

Linden 2406_ G_8 84 0.006 13314 14.17 0.06 2.6% 8.03 106,922 3.4

PSEG

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 B. 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 lants

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 (Btu/kWh) 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 ( MMBtu ) 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 36.3% 696.24 6,155,451 129.3

Bergen 2398_ G_2101 163 0.005 9241 86.87 0.01 35.5% 507.55 4,690,299 28.1

Bergen 2398_ G_2201 163 0.005 9241 86.87 0.01 35.5% 507.55 4,690,299 28.1

Bergen 2398_ G_2301 224 0.007 9241 119.38 0.01 35.5% 697.50 6,445,565 38.7

PSEG
Edison 2400_ G_11 42 0.003 16763 1.37 0.27 1.0% 3.76 63,093 8.5

PSEG
Edison 2400_ G_12 42 0.003 16862 1.37 0.27 1.0% 3.56 59,944 8.0

PSEG 2400_ 42 16893 0.27 0.8% 2.85 48,155 6.535 Edison G_13 0.003 1.37

PSEG

Edison 2400_ G_14 42 0.003 16947 1.37 0.26 0.7% 2.67 45,259 6.0

PSEG

Edison 2400_ G_21 42 0.003 17182 1.37 0.28 1.0% 3.59 61,750 8.5

PSEG

Edison 2400_ G_22 42 0.003 16846 1.37 0.27 1.0% 3.60 60,655 8.1

PSEG

Edison 2400_ G_23 42 0.003 16979 1.37 0.27 0.8% 3.02 51,338 7.0

PSEG

Edison 2400_ G_24 42 0.004 17184 1.37 0.30 0.7% 2.68 46,125 6.9

PSEG

Edison 2400_ G_31 42 0.003 16953 1.37 0.27 0.8% 2.88 48,831 6.5

PSEG

Edison 2400_ G_32 42 0.003 16984 1.37 0.27 0.8% 3.10 52,620 7.1

PSEG

Edison 2400_ G_33 42 0.003 17033 1.37 0.27 0.8% 2.94 50,000 6.7

PSEG

Edison 2400_ G_34 42 0.003 16950 1.37 0.26 0.7% 2.74 46,491 6.1

PSEG

Essex 2401_ G_101 42 0.003 16968 1.37 0.30 1.6% 6.07 102,945 15.4

PSEG

Essex 2401_ G_102 42 0.004 17066 1.37 0.30 1.5% 5.39 91,989 13.8

PSEG

Essex 2401_ G_103 42 0.004 17188 1.37 0.30 1.3% 4.79 82,370 12.3

PSEG

Essex 2401_ G_104 42 0.004 17167 1.37 0.30 1.4% 5.21 89,408 13.4

PSEG

Essex 2401_ G_111 46 0.004 16816 1.50 0.30 1.7% 6.70 112,614 16.9

PSEG

Essex 2401_ G_112 46 0.004 17154 1.50 0.30 1.8% 7.15 122,683 18.4

PSEG

Essex 2401_ G_113 46 0.004 16847 1.50 0.30 1.5% 6.20 104,513 15.7

PSEG

Essex 2401_ G_114 46 0.004 16726 1.50 0.30 1.6% 6.53 109,251 16.436 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% 7.90 133,445 20.0

PSEG

Essex 2401_ G_123 46 0.004 16771 1.50 0.30 1.9% 7.60 127,493 19.1

PSEG

Essex 2401_ G_124 46 0.001 16758 1.50 0.08 1.8% 7.24 121,333 5.1

PSEG

Essex 2401_ G_9 81 0.022 10633 13.67 0.30 0.1% 0.57 6,026 0.9

PSEG Kearny 2404_ G_10 134 0.012 18700 4 0.30 0.3% 3.63 67,789 10.2

PSEG Kearny 2404_ G_11 134 0.012 18700 4 0.30 0.2% 2.78 51,981 7.8

PSEG Kearny 2404_ G_N121 43.8 0.004 9667 9 0.09 0.3% 1.25 12,097 0.6

PSEG Kearny 2404_ G_N122 43.7 0.004 9791 9 0.09 0.3% 1.15 11,299 0.5

PSEG Kearny 2404_ G_N123 43.8 0.004 10109 9 0.09 0.3% 1.33 13,463 0.6

PSEG Kearny 2404_ G_N124 43.7 0.004 9704 9 0.09 0.4% 1.39 13,488 0.6

PSEG
Linden 2406_ G_5 86 0.005 12110 15 0.06 1.2% 9.20 111,371 3.3

PSEG
Linden 2406_ G_6 86 0.005 12601 15 0.05 1.3% 9.55 120,318 3.0

PSEG
Linden 2406_ G_7 84 0.005 12155 14 0.06 1.9% 14.25 173,152 5.1

PSEG
Linden 2406_ G_8 84 0.006 13314 14 0.06 1.6% 11.99 159,613 5.1

PSEG

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 the year; that factor is divided by 1,000 to yield units in GWh.

As calculated in Table B. 10. f

, EPA is assuming that the increase in generation reflecting out

- of

- merit

- order dispatch w ould be offset by decreasing generation at New Jersey combined cycle units, shown in these calculations as a representative unit with a heat rate ( column B) and emission rate ( column C) equal to the generation

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

- weighted average was used to determine the characteristics of the representa tive unit. The change was made for consistency across states where generation from a representative unit was used to offset increased generation due to out

- of

- merit order dispatch. Additionally, as explained in the preamble and based on
comments received, EPA excluded any identified cogeneration units from these calculations. Finally, separate annual and ozone season emission and heat rates were calculated and the applicable ones were used as the situation warranted. The ozone season and annual NO X emissio ns associated with the displaced 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 B. 10

. f

. : Calculation of Emissions from Displaced Generation at New Jersey Combined 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 7,413 0.0136 208

Ozone Season 1,142 7,454 0.0144 61

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

increase in emissions due to the out

- of

- merit

- order generation, which impact both the 2012 and 2014 budgets. The emissions associated with the generation

33 These generation

- weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “ Calculation of heat rate and emission rate averages used in Final Revisions Rule ” found in the docket for this rulemaking.38 displaced by the out

- of

- merit

- order generation was subtracted from the increase in emissions to determine the net emission budget changes for New Jersey (row D).

Table B. 10. g

. : Calculation to Determine Net New Jersey SO 2 , Annual NO X , and Ozone Season NO X Budget Revisions (tons)

2012 2014

SO 2 Annual

NO X Ozone
Season NO X SO 2 Annual

NO X Ozone
Season NO X
A Net Emissions Increases Due to Changes at BL England Unit 1 2,096 273 397 0 0 0

B Additional Emissions Due to Out

- Of

- Merit

- Order Generation 0 887 410 0 887 410

C Displaced Emissions f rom Out

- Of

- Merit

- Order Generation 0 208 61 0 208 61

D Net Budget Revisions f or New Jersey (A+B

- C) 2
, 096 952 746 0 679 349

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 Table B. 10. h

.39 Table B. 10.h.: Impact of New Jersey Budget Revisions

– Assuming No FGD or SCR at BL England Unit 1 in 2012 and Out

- of

- Merit

- Order Dispatch at Six Facilities (tons)

Program Budget Assurance Level Total New Unit

Set

- Aside*

% of Budget Tons % of Budget Tons

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

2012 Revised SO 2 7,670

- - 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 8,218

- - 2% 164

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

2014 Revised Annual NO X 7,945 118% 9,375 2% 159

2012 Initial Ozone

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

2012 Revised Ozone

- Season NO X 4,128

- - 2% 83

2014 Initial Ozone

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

2014 Revised Ozone

- Season NO X 3,731 121% 4,515 2% 75

*Approximate set

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

11)

EPA is finalizing, as proposed , an increase to Louisiana’s ozone season 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 dispatch 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 documentation that appear likely to

necessitate non

- economic generation at the units displayed below during the implementation of the Trans port Rule programs. Specifically, EPA is assuming Louisiana40 additional generation will be dispatched at five plants ( Nelson, Nine Mile Point, Michoud, Little Gypsy, and Waterford ) based on the average capacity factor representing the frequency the unit is projected to be called to operate out

- of

- merit

- order

, derived from immediate

- term dispatch modeling projections provided by Entergy

. 34

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

- of

- merit

- order dispatch at the five facilities is shown in Table B. 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 emission rate from EPA’s NEEDS database are shown (columns A to G). The average out

- of

- merit

- order c apacity 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 t he ozone season (column I). The additiona l heat input required was calculated by multiplying the incremental generation by the unit’s heat rate (column J). Finally, the additional emissions associated with the out

- of

- merit

- order generation was calculated by multiplying the additional heat input b y the unit’s NO X emission rate. 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 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 chan ges on the state’s ozone season NO X budget is a 4, 594 ton

increase

.

Table B. 11. a

. : Calculation to Determine Louisiana Ozone Season NO X Budget Revisions

- Assuming O ut

- of

- M erit

- O rder Dispatch at Five 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/ 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

R S Nelson 1393_ B_3 153 0 10476 0 0.151 16% 89.89 941,694 70.9

R S Nelson 1393_ B_4 500 0 10419 0 0.128 23% 422.28 4,399,735 281.3

Little Gypsy 1402_ B_1 244 0 9978 0 0.278 7% 62.72 625,798 86.8

34 Correspondence f rom Entergy to EPA, September 29, 2011. Please see the document “Transmission System Considerations

– Entergy” in the docket for this rule making.41 Little Gypsy 1402_ B_2 415 0 10032 0 0.098 3% 45.72 458,627 22.5

Little Gypsy 1402_ B_3 545 0 10179 0 0.311 24% 480.30 4,888,949 760.0

Nine Mile

Point 1403_ B_3 132 0 10264 0 0.149 11% 53.32 547,250 40.9

Nine Mile

Point 1403_ B_4 738 0 9955 0 0.337 31% 840.08 8,362,998 1

, 409.0

Nine Mile

Point 1403_ B_5 753 0 9841 0 0.298 34% 940.11 9,251,578 1

, 380.0

Michoud 1409_ B_1 100 0 11427 0 0.042 0% 0.00 0 0.0

Michoud 1409_ B_2 230 0 10997 0 0.207 30% 253.37 2,786,288 287.9

Michoud 1409_ B_3 530 0 11288 0 0.105 45% 875.77 9,885,714 518.7

Waterford 1

& 2 8056_ B_1 400 0 10238 0 0.123 3% 44.06 451,127 27.9

Waterford 1

& 2 8056_ B_2 405 0 10137 0 0.116 7% 104.10 1,055,274 61.2

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

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

As calculated in Table B. 11.b, EPA is assuming that the increase in generation reflecting out

- of

- merit

- order dispatch would be offset by decreasing generation at Louisiana combined cycle units, shown in these calculations . Generation was first offset from Washington Parish, which commenters informed EPA that the plant was never completed and part were deconstructed, 35 with the remaining generation offset from a representative unit with a heat rate
(column D ) and emission r ate (column E ) equal to the generation

- weighted average of Louisiana combined cycle units. 36

35 EPA

- HQ

- OAR

- 2009

- 0491

- 4803 A s explained in the preamble and
based on comments received, EPA excluded any identified cogeneration units from these calculations. Finally, separate annual and o zone season emission and heat rates were calculated and the applicable ones were used as the situation warranted. The ozone season NO X emissions associated with the displaced

36 These generation

- weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission rate averages used in Final Revisions Rule” found in the docket for this rulemaking.42 generation (column G ) were calculated by multiplying that generation by the avera ge heat rate and the relevant emission rate at the representative combined cycle unit. The total displaced emissions (column H) were calculated by adding the emissions from the operation of Washington Parish in I PM (column F) to emissions displaced from th e representative unit.

Table B. 11.b

. : Calculation of Emissions from Displaced Generation at Louisiana Combined Cycle Units

A B C D E F G H

Program
Period Displaced
Generation (GWh) Generation Displaced
from Washington
Parish (GWh) Generation Displaced
from other
Combined Cycles (GWh) Heat Rate (BTU/ kWh) NO X Emission

Rate (lbs/MMBTU) Displaced
Emissions
from Washington
Parish (tons) Displaced
Emissions
from other
Combined Cycles (tons) Total Displaced

NO X Emissions (tons)

Calculation A

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

Ozone

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

The total revision proposed to Louisiana’s state budget due to the out

- of

- merit

- order dispatch is calculated in Table B. 11.c. The emissions associated with the generation displaced by the out

- of

- merit

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

- of

- merit

- order generation (row A) to determine the net emission budget changes for Louis iana (row C).

Table B. 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 Displaced Emissions From

Out

- Of

- Order

- Merit Dispatch 353

C Net Emission budget Change For Louisiana (A

- B) 4,59443 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 B. 1 1

. d

.

Table B. 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 18,026

- - 3% 541

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

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

*Approximate set

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

1 2 )

EPA is finalizing, as proposed , an increase to 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 demonstrating that the Mississippi Region is an

out

- of

- merit

- order dispatch area

. EPA's analysis in the final Transport Rule did not incorporate the immediate

- term local conditions described in recently submitted documentation that appear likely to necessitate non

- economic generation at the units displayed below during the implementation of the Transport Rule programs. Specifically, EPA is assuming additional generation will be dispatched at three plants (Rex Brown, Gerald Andrus, and Baxter Wilson) based on the average capacity factor representing the fre quency the unit is projected to be called to operate out

- of

- merit

- order, derived from immediate

- term dispatch modeling projections provided by Entergy

. Mississippi

37

37 Correspondence from Entergy to EPA, September 29, 2011. Please see the docum ent “Transmission System Considerations

– Entergy” in the docket for this rule making. 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 revision to Mississippi’s state budget

is based on the net change to projected emissions taking that offsetting fac tor into account

. The net impact of these changes on the state’s ozone season NO X budget is a 2, 154 ton increase

.44 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 B. 12.a.

For each unit with out

- of

- merit

- order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012 , heat rate, generation from TR_Remedy
Final_2012 , and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out

- of

- merit

- order capacity factor is shown in column H. The additional generation for out

- of

- merit

- order dispatch was calculated by multiplying the capacity, the average out

- of

- merit

- order capacity
factor, and the number of hours in the ozone season (column I). The ad ditional heat input required was calculated by multiplying the incremental generation by the unit’s heat rate (column J). Finally, the additional emissions associated with the out

- of

- merit

- order generation was calculated by multiplying the

additional heat input by the unit’s NO X emission rate.

Table B. 12 .a

. : Calculation to Determine Mississippi Ozone Season NO X Budget Revisions

- Assuming out

- of

- merit

- order dispatch at three plants

A B C D E F G H I J K

Plant Name Unique

Id Capacity (MW) 2012 Ozone
Season NO X Emission s 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 * (GWh) 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 used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.

As calculated in Table B. 12.b, EPA is assuming that the in crease in generation reflecting out

- of

- merit

- order dispatch would be offset by decreasing generation at Mississippi combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C)45 equal to the generation

- weighted average of Mississippi combined cycle units. 38

Table B. 1 2

. b

. : Calculation of Emissions from Displaced Generation at Mississippi Combined Cycle Units The emission and heat rates of this representative unit changed from the proposal because the proposal’s calculations used annual, rather than ozone

- season, data; the calculations for this final rule use ozone

- season data

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

ozone season NO X emissions associated with the displaced generati on (column D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative combined cycle unit.

A B C D Program
Period Displaced Generation (GWh) Heat Rate (BTU/kWh) NO X Emission Rate (lbs/MMBTU) Displaced NO X Emissions (tons)

Calculation A*B*C/2000

Ozone Season 1,473 7,570 0.026 145

The total revision to Mississippi’s state budget due to the out

- of

- merit

- order dispatch is calculated in Table B. 12.c. The emissions associated with the generation displaced by the out

- of

- merit

- order generation (row B) were subtracted from the increase in emissions due to t he out

- of

- merit

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

Table B. 12

. c

. : Calculation to Determine Net Mississippi
Ozone Season NO X Budget Revisions (tons)

A Additional Emissions Due to

Out

- Of

- Order

- Merit Dispatch 2,299

B Displaced Emissions From

Out

- Of

- Order

- Merit Dispatch 145

C Net Change in Emission budget For Mississippi (A

- B) 2,1 54

38 These generation

- weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “ Calculation of heat rate and emissi on rate averages used in Final Revisions Rule ” found in the docket for this rulemaking.46 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 B. 12.d.

Table B. 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

, 314

- - 2% 246

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

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

*Approximate set

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

allocations

13 )

EPA is finalizing, as proposed, an increase Texas’s annual NO X and ozone season NO X budget s in 2012 and 2014 to reflect the assumption of near

term operational constraints affecting units at two plants, based on information provided by the system operator demonstrating that the Western and West of the Atchafalaya regions are out

- of

- merit

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

Sabine ) based on the average capacity factor representing the frequency the unit is projected to be called to operate out

- of

- merit

- order

, derived from

immediate

- term dispatch projections provided by Entergy

. Texas (Out

- of

- Merit

- Order Dispatch)

39

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

- of

- merit

- order dispatch at the two facilities is shown in Table

B. 1 3 .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

- or der capacity factor is shown in As discussed later in this section, EPA assumes that the additional generation dispatched from

these two facilities would offset generation that would otherwise come from combined cycle units within the state, and the revision s 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

.

39 Correspondence from Entergy to EPA, September 29, 2011. Please see the document “Transmission System Considerations

– Entergy” in the docket for this rule making.47 column H. The additional generation for out

- of

- merit

- order dispatch was calculated by multiplying the capacity, the average out

- of

- merit

- order capacity
factor, and the number of hours in the ozone season (column I). The addi tional heat input required was calculated by multiplying the incremental generation by the unit’s heat rate (column J). Finally, the additional emissions associated with the out

- of

- merit

- order generation was calculated by multiplying the

additional heat in put by the unit’s NO X emission rate.

Table B. 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 ** (GWh) 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 ar e 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.48 As calculated in Table B. 13.b, EPA is assuming that the increase in generation reflecting out

- of

- merit

- order dispatch would be offset by decrea sing 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) equal to the generation

- weighted average of Texas combined cycle units. 40 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 esentative combined cycle unit.

Table B. 13

. b

. : Calculation of Emissions from D isplaced 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

Ozone Season 3,059 7,376 0.019 214

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

ozone

- season NOX state budgets.

The total revisions to the Texas state budgets due to out

- of

- merit

- order dispatch are calculated in Table B. 13.c. The emissions associated with the generation displaced by the out

- of

- merit

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

- of

- meri t

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

Table B. 13.c

. : Calculation to Determine Net Texas Annual

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 For Texas (A

- B) 1,375

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

- season NOX state budgets.

40 These generation

- weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission rate averages used in Final Revisions Rule” found in the docket for this rulemaking.49 In addition to the revisions summarized in Table B. 13.c., the revisions to Texas state budgets outlined above in sections 3, 4, and 7 of this technical support document are summarized in Table B. 13.d. The cumulative impacts of all of the technical revision s to the Texas budgets and NUSAs are

summarized in Table B. 13.e. 41

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

Removed FGD R evision 26,359

FGD Capture Revision 24,158

Total SO 2 Budget R evision 50,517

41 The increase to the new unit set

- aside would necessarily change existing unit allowance allocations in order to maintain the state budget. To review the existing u nit

allowance allocations associated with this revision , please see the document entitled “ F inal Revisions Rule Unit

- Level Allocations under the FIPs ” found in the docket to this rulemaking.50 Table B. 13.e.: Impact of Texas Budget Revisions

– Assuming Removed FGDs and Revised FGD Capture at Certain Units, Revised NUSAs for Oak Grove 2, and Out

- of

- Merit

- Order Dispatch at
Two Facilities (tons)

Program Budget Assurance Level Total New Unit

Set

- Aside*

% of Budget Tons % of Budget Tons

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

2012 Revised SO 2 294,471

- - 5% 14,724

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

2014 Revised SO 2 294,471 118% 347,476 5% 14,724

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

2012 Revised Annual NO X 134,970

- - 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

- - 4% 2,577

2014 Initial 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 allocations51 S ection C: Technical Revisions to States’ TR Emission Budgets and NUSAs Relevant to Direct Final Rule

1)

EPA is finalizing , based on comments, an increase to South Carolina ’s 2012 and 2014 SO 2 budget s to correct for the assumption that Flue Gas
Desulfurization (FGD) technology i s currently installed at the W S Lee Power Plant. There is no FGD planned or under construction at the unit. Therefore,

EPA is finalizing an increase to the state’s 2012 and 2014 SO 2 emissi on budget s to reflect projected emissions without these unit s ope rating a FGD. This
results in a 8,013 ton increase to the state’s SO 2 budget s in 2012 and 2014

. South Carolina

Table C. 1

. a. : Calculation to Determine South Carolina Budget Adjustment

- Assuming no FGD at W S Lee

A B C D E F

Plant Unit Emissions

from TR_Remedy Final_2012 (1000 tons) HI from TR_Remedy_Final_2012 ( TBtu ) Remedy Emission Rate

from from TR_Remedy_Final_2012 (lbs/ MMBtu ) Adjusted

Emission

Rate (lbs/ MMBtu ) Adjusted

Emissions (1000 tons) Budget Adjustment (1000 tons)

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

- A

W S Lee 1 0.480468932 3.907141013 0.246 1.320 2.579 2.098

W S Lee 2 0.477953387 3.886684777 0.246 1.320 2.565 2.087

W S Lee 3 0.903656715 7.169244286 0.252 1.320 4.731 3.828

Total 8.013

In Table C.1.a., c olumns A, B, and C show the SO 2 emissions, heat input, and emission rate from the TR_Remedy_Final_2012 modeling when a

FGD is assumed to be present at W S Lee . Because no FGD is present, EPA modified the emission rate to reflect the TR Base Case Final 2012 Remedy analysis where the FGD is assumed not to dispatch at the unit. This value approximates the emission rate expected at the unit at a cost th reshold of $500/ton
when no FGD is operating at the unit

. EPA multiplied this SO 2 rate by the remedy heat input shown in column B to obtai n a revised emissions projection for
the unit (column E). The difference between this revised emission projection (no FGD assumed) and the final Transport Rule remedy analysis emission projection (FGD assumed) determines the amount of the increase to the state’s SO 2 b udget (column F).

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

Rule , the NUSA for SO 2 in South Carolina remain s at 2%. The original and re vised values for the state SO 2 budget, assurance level, and new unit set

- aside

are described in the table below.52 Table C. 1

. b. : Impact of South Carolina's SO 2 Budget Revision

- Assuming no FGD at W S Lee(tons)

SO 2 Budget Assurance Level Total New

Unit Set

- Aside

*

% of Budget Tons % of Budget Tons

2012 Before Direct Final Revisions Rule 88,620

- - 2% 1,772

2012 After Direct Final Revisions Rule 96,633

- - 2% 1,933

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

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

*Approximate set

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

2)

EPA is finalizing , based on comments, an increase to Nebraska’s 2012 and 2014 SO 2 budget s to cor rect for the assumption that FGD technology is

curr ently installed at Whelan Energy Center Unit 1. There is no FGD existing, planned, or under construction at the un it. There will likely be no FGD

available at t he time of the 2012 and 2014 compliance periods as originally assumed in EPA’s determination of Nebraska’s SO 2 budgets . Therefore, EPA is finalizing a revision the state’s 2012 and 2014 SO 2 emission budgets to reflect this unit operating without an FGD. This results in a 2,334 ton increase to the

state’s 2012 and 2014 SO 2 budget s . The calculations to quantify this revision are shown in the table below. Nebraska53 Table C. 2.a. : Calculation to Determine Nebraska Budget Adjustment

- Assuming no FGD at Whelan Energy Center Unit 1

A B C D E F

Plant Unit Emissions from TR_Remedy Final_2012 (1000 tons) HI from TR_Remedy_Final_2012 ( TBtu ) Remedy Emission Rate

from from TR_Remedy_Final_2012 (lbs/ MMBtu ) Adjusted

Emission

Rate (lbs/ MMBtu ) Adjusted

Emissions Budget Adjustment (1000 tons)

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

- A

Whelan Energy

Center 1 0.255767801 6.394195158 0.0800 0.81 2.590 2.334

EPA is also finalizing, based on comments, a revision to Nebraska’s 2012 and 2014 SO 2 budgets related to FGD technology at Whelan Energy Center Unit 2 and Nebraska City Unit 2. In the final Transport Rule analysis, EPA assumed these installations would be wet scrubbers; however, Nebraska

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

SO 2 removal rates of 95.9% for the wet scrubbers

. However, dry scrubbers generally have lower SO 2 removal rates. EPA revised its removal assumption

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

90.5% removal for Whelan unit 2 ) . T he revised projected SO 2 emi ssions from these units reflect the lower SO 2 re m oval rate (and consequently highe r emissions) than these units would be ass umed to achieve with wet scrubber technology. In accordance with this revision, EPA is finalizing a 776 ton

increase to the Nebraska’s 2012 and 2014 SO 2 emission budget.

42 EPA

- HQ

- OAR

- 2009

- 0491

- 475454 Table C. 2

. b. : Calculation to Determine Nebraska's Annual SO 2 Budget Adjustment

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

A B C D

Unit Emissions

from TR_Remedy Final_2012 (95.9% removal) Emissions assuming no

FGD Emissions assuming

EIA 860

Rates Emission Adjustment

Calculation A/.041 B*.05 or

.095 C

- A

Nebraska City 2 1.142 27.854 1.393 0.251

Whelan Energy Center 2 0.399 9.732 0.925 0.526

Total 1.541 37.585 2.317 0.776

Column A shows the units’ projected emissions assuming 95.9% removal characteristic of the assumed wet scrubber. Column B shows a calculation of projected emissions at each unit if the previously assumed FGD removal hadn’t occurred at all; these “uncontrolled emissio ns” are calculated in order to allow applic ation of the revised FGD removal rate s of 95% for Nebraska City Unit 2 and 90.5% for Whelan Energy Center Unit 2 to the uncontrolled emissions, which yields the revised emission projection for each unit in column C. The difference between this revised emission projection ( dry scrubbers
assumed, column C ) and the remedy emission projection ( wet scrubbers assumed, column A ) determines the amoun t of the increase to the state’s 2012 and

2014 SO 2 b udget (column D ). The combined impact of these t wo budget a djustments is a 3,110 tons increase to the state’s 2012 and 2014 SO 2 budgets.

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

Rule , the NUSA for SO 2 in Neb raska remain s at 4 %. The original and revised values for the state SO 2 budget, assurance level, and new unit set

- aside are
described in the table below.55 Table C.2.c.: Nebraska SO 2 Budget, Assurance Level, and NUSA Before and After 3,800
SO 2 Budget Adjustment

SO 2 Budget Assurance Level Total New Unit

Set

- Aside *

% of Budget Tons % of Budget Tons

2012 Before Direct Final Revisions Rule 65,052

- - 4% 2,602

2012 After Direct Final Revisions Rule 68,162

- - 4% 2,726

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

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

*Approximate set

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

3)

EPA is finalizing, based on comments, an increase to Indiana ’s 2012 and 2014 SO 2 budget s to cor rect for the assumption that FGD technology is

curr ently installed at Gallagher Units 2 and 4. There is no FGD existing, planned, or under construction at the u n it s

. These units do, however, have DSI technology installed with a n SO 2 r emoval rate that achieves approximately 6 0% sulfur removal according to data reported by the sources on EIA form 860

. Therefore, EPA is finalizing a revision to the state’s 2012 and 2014 SO 2 emission budgets to refl ect this unit operating with DSI instead of FGD. As noted by the commenter, the units are also subject to a NSR settlement agreement that imposes a .8 lbs/ MMBtu limit for SO 2 at the units. Therefore, EPA revised its assumption to ensure that with the adjustment from FGD to DSI, that the source still honored its emission rate limits. T his results in a 3,465 ton increase

to the state’s 2012 and 2014 SO 2 budget s . The calculations to quantify this revision are shown in the table below. Indiana56 Table C. 3

. a. : Calculation to Determine Indiana SO 2 Budget Adjustment

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

A B C D

Emissions

from TR_Remedy Final_2012 (86% removal) HI from TR_Remedy_Final_2012 (TBtu) Emissions assuming

.8

lbs/MMBtu

Emission

Rate Emission Adjustment

Calculation B*.8 C

- A

Gallagher 2 1.066211595 6.957289314 2.783 1.717

Gallagher 4 1.08608673 7.08697939 2.835 1.749

Total 2.152 14.044 5.618 3.465

Column A shows the units’ projected emissions with the 86% removal rate assumed in the TR_Remedy_Final. Column B shows the heat input projected for each unit in the TR remedy. This heat input is multiplied by the .8 lbs/mmbtu emission rate allowed under the settlement to arrive at the

emissions value in column C

– which reflects the DSI technology rather than FGD technology. The difference between this revised emission projection
( DSI assumed, column C ) and the remedy emission projection ( FGD assumed, co lumn A ) determines the amoun t of the increase to the state’s 2012 and 2014

SO 2 b udget (column D ). The combined impact of the se two budget adjustments is a 3 ,46 5 tons increase to the state’s 2012 and 2014 SO 2 budgets.

EPA is also finalizing, based on comme nts, an adjustment to the 2012 and 2014 SO 2 budget for Indiana based on the amount of flue gas that passes through the FGD at Gibson Unit 5

. The c ommenter noted that because of this scrubber’s design limitation, the facility may be limited in the amount of flue

gas that can be passed through the existing FGD. The Gibson unit in Indiana report s less than 100% pass

- through of flue gas on EIA form 860. Consequently, at this unit, the effective removal rate of the FGD as applied to tot al SO 2 emissions would be lower than the reported removal rate would

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

scrubber. Consistent wi th the approach EPA used to finalize similar revisions, EPA is finalizing this revision based on the SO 2 removal efficiency and flue gas treatment data reported for these scrubbers by the facility operators to the EIA on form 860

. The approach results in a final 2012 and 2014 SO 2 budget
increase of 1,873 tons.57 Table C. 3.b.: Calculation to Determine Indiana SO 2 Budget Adjustment

– Assuming Revised SO 2 removal Rates at
FGD

A B C D E F G

Plant

Name Unit

ID Total SO 2 Emissions from TR_Remedy_Final (1000 tons) EIA 860
Removal Rate (used in budget determination) EIA 860

Percent
of Flue

Gas Entering

FGD Calculated
Removal Rate (used for budget

revision estimate) Uncontrolled

Emissions (assuming

no FGD)(1000 tons) Revised

Emissions (assuming
FGD with

r evised
removal rate) (1000 tons) Net Budget
Revision (1000 tons)

Calculation B*C A/(1

- B) E*(1

- D) F

- A

Gibson 5 4.928346201 0.95 98% 0.931 98.566924 6.8011178 1.873

Column A shows the projected emissions at the unit as originally modeled in the final Transport Rule remedy for 2012 . Column B shows the SO 2 removal rate that the 2012 emission projections are based on. Column C shows the source reported percent of flue gas entering FGD. Column D shows the

effective removal rate based on multiplying the removal rate by the percent of flue gas entering FGD

. Column E shows a calculation of projected emissions at each unit if the previously assumed FGD removal hadn’t occurred at all; these “uncontrolled emissions” are calculated in o rder to allow application of the revised FGD removal rate shown in column D to these uncontrolled emissions, which yields the revised emission projection for each unit in column F. The

difference between this revised emission projection ( lower FGD capture assumed , column F ) and the remedy emission projection ( higher FGD capture assumed, column A ) determines the amount of the increase to the state’s SO 2 budget (column G ).

The combined impact of these two changes to Indiana ’s 2012 and 2014 budget is 5,338 tons. T his budget change will not result in any impact to the percent of the budget set aside for new units. Under the methodology in the final Transport Rule , the NUSA for SO 2 in Indiana remain s at 3 %. The original

and revised values for the state SO 2 budget, assurance level, and new unit set

- aside are described in the table below.58 Table C. 3

. c : Impact of Indiana's 2012 and 2014 SO 2 Budget Revision

SO 2 Budget Assurance Level Total New Unit

Set

- Aside *

% of Budget Tons % of Budget Tons

2012 Before Direct Final Revisions Rule 285,424

- - 3% 8,563

2012 After Direct Final Revisions Rule 290,762

- - 3% 8,723

2014 Before Direct Final Revisions Rule 161,111 118% 190,111 3% 4,833

2014 After Direct Final Revisions Rule 166,449 118% 196,410 3% 4,993

*Approximate set

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

4)

EPA is finalizing, based on comments, an increase to Ohio ’s 2012 and 2014 annual NO X and ozone

- season NO X budget s to correct for the assumption that Selective Catalytic Reduction (SCR) technology is currently installed at Bay Shore Unit 4 in 2012. There is no SCR planned or under

construction at the unit. Therefore, EPA is finalizing an increase to the state’s 2012 and 2014 annual NO X and ozone

- season NO X emissi on budget s to reflect projected emissions without this unit operating a SCR. This results in a 2,218 ton increase to the state’s annual NO X budget s in 2012 and 2014, and a 964

ton increase in the state’ s ozone

- season NO X budget s in 2012 and 2014. Ohio

Table C. 4.a. : Calculation to Determine Ohio Budget Adjustment

- Assuming no SCR at Bay Shore 4

A B C D E F

Plant Unit Emissions

from TR_Remedy Final_2012 (1000 tons) HI from TR_Remedy_Final_2012 ( TBtu ) Remedy Emission Rate

from from TR_Remedy_Final_2012 (lbs/ MMBtu ) Adjusted

Emission

Rate (lbs/ MMBtu ) Adjusted

Emissions Budget Adjustment (1000 tons)

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

- A
Bay Shore 4 0.468366563 13.4995095 0.069 0.398 2.686 2.218
Bay Shore 4 0.203626114 5.86901984 0.069 0.398 1.168 0.96459 Columns A, B, and C show the NO X emissions, heat input, and emission rate from the TR_Remedy_Final_2012 modeling when a SCR is assumed to be present the unit . Because no SCR is present, EPA modified the emission rate to reflect the “controlled NO X policy rate” in the NEEDS version from the September 1, 2010 TR Notice of Data Availability (NODA) (column D). 43

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

Rule , the NUSA s for annual NO X and ozone

- season NO X in Ohio remain at 2%. Along with revisions accounting for out

- of

- m erit order dispatch at units in Ohio presented below , the original and revised values for the state budget s , assurance level s , and new unit set

- aside s are described in T able C.18.g. This value reflects the NO X emission rate assumed in EPA’s modeling of the Transport Rule as originally proposed , when EPA did not assume a SCR to be present at the unit. This value approximates the emission rate expected at the

unit at a cost threshold of $500/ton when no SCR is present at the unit. EPA multiplied this NO X rate by the remedy he at input shown in column B to obtain

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

Rule remedy analysis emission projection (SCR assumed) determines the amount of the increase to the state’s annual NO X and ozone

- season NO X b udget
(column F). The first row shows the calculation for the annual NOx budget adjustment and the second row shows the calculation for ozone s eason NOx adjustment.

5)

EPA is finalizing, based on comments, an increase to New York ’s 2012 and 2014 SO 2 budget s to cor rect for the removal rate assumption regarding DSI technology at the Dunkirk and Huntley facilities. As noted in the “Significant Contribution and State Emissions Budgets Final Rule TSD" for t he final Transport Rule, EPA had received comment during the rule proposal noting that these facilities had DSI in place of the FGD assumed in the modeling. EPA adjusted the state budgets before finalizing the Transport Rule to reflect DSI t echnology . Because no verifiable removal rate was submitted for the technologies in the comment at this time , EPA assumed the default 70% removal rate used for new DSI. However, during the comment period for the
Revisions Rule, a commenter noted that these units’ existing DSI systems are not cap able of achieving such a rate. The commenter’s claim is corroborated by newly available 2010 EIA 860 data provid ing a reported SO 2 removal rate of 53% for the units. EPA has calculated a budget adjustment to New York’s

SO 2 budget s in 2012 and 2014 assumi ng a n SO 2 removal rate of 53% as opposed to the 70% rate previously assumed in the final Transport Rule at these

units

. New York

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

- ipm/BaseCasev410.html60 Table C.5.a.: Calculation to Determine New York Budget Adjustment

- Correcting for DSI Removal Rates

A B C D E

Unit Removal Rate Assumed

in TR_Remedy_Final_2012 Emissions from TR_Remedy Final_2012 (1000 tons) Emissions assuming 70%

removal (1000 tons) Emissions Assuming 53%

removal (1000 tons) Net Budget Adjustment (1000 tons)

Calculation B/(1

- A)*.3 B/(1

- A)*.47 D

- C

C R Huntley Generating

Station 67 92.3% 0.340946408 1.328362629 2.081101451 0.752738823 C R Huntley Generating

Station 68 92.3% 0.340946408 1.328362629 2.081101451 0.752738823

Dunkirk Generating Station 3 95.9% 0.383454384 2.805763788 4.3956966 1.589932813

Dunkirk Generating Station 4 95.9% 0.38488252 2.81621356 4.41206791 1.59585435

Dunkirk Generating Station 1 70.0% 0.623572839 0.623572839 0.976930781 0.353357942

Dunkirk Generating Station 2 70.0% 0.55670215 0.55670215 0.872166702 0.315464552

Total 2.63050471 9.458977594 14.8190649 5.360

Column A and B show the removal rate and corresponding emissions assumed in the initial TR_Final_Rule modeling. Column C shows the adjusted emissions assuming 70% removal efficiency that was assumed for the Final Transport Rule Budget determination. Colum n D shows the emission for these units assuming a 53% removal rate (as reported in the EIA 860 form for the units). Column E shows the net budget adjustment necessary to correct the 70% removal efficiency with a 53% removal efficiency for the DSI present at the facilities. This results in a 5, 360 ton increase to the state’s SO 2 budget

for 2012 and 2014

.

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

Rule , the NUSA for SO 2 in New York remain s at 2%. Along with revisions accounting for out

- of

- merit ord er dispatch at units in New York presented

below , the original and revised values for the state budget s , assurance level s , and new unit set

- aside s are described in T able C.19.g.

6)

EPA is finalizing, based on comment, an update to Kansas’s 2014 annual NO X budget to correct for the assumption that particular Westar consent

decree emission rate and tonnage cap requirements begin in 2015, not 2014 as assumed in the final rule analysis. The final 2014 Transport Rule modeling applied SCR retrofit technology to some capacity at the Jeffrey Energy Center to comply with the 0 .1 lb/ MMBtu rate requirement of the Westar consent Kansas61 decree; h owever, because this rate requirement does not begin until 2015 , EPA is assuming that the emission rate requirements of the consent decree do not result in any new controls until 2015 at the Jeffrey Energy Center. Th is revised assumption would, if examined in isolation, yield an increase of 6,465 tons in project ed annual NO X emissions in Kansas in 201 4, which would bring total projected NO X emissions from covered EGUs in Kansas to a level that

exceeds the st ate’s 2012 budget

. However, a s explained in the final Transport Rule, “ for any covered state whose emissions of a relevant pollutant are projected to increase from 2012 to 2014 under the relevant cost thresholds

... EPA is finalizing that state’s 2014 emission budget to maintain the same level of the 2012 emission budget ” ( 76 FR 48261 ). Therefore, EPA is increasing the 2014 Kansas NO X budget by 5,154 tons so that it matches , not exceeds, the

state’s 2012 budget following the methodology and rationale laid out in the final Transport Rule

.

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

Rule , the NUSA for annual NOX in Kansas remain s at 2%. Along with revisions accounting for out

- of

- merit order dispatch at units i n Kansas presented

below , the original and revised values for the state budget s , assurance level s , and new unit set

- aside s are described in T able C.14.f.

7)

EPA is finalizing, based on comment, an update to Georgia’s 2014 SO 2 , annual NO X , and ozone

- season NO X state budgets to correct for the assumption in the final Transport Rule analysis that particular Georgia Multi

- Pollutant State Rule control deadlines for FGD/SCR retrofits at Branch,
Scherer, and Yates facilities would deliver emissi on reductions in 2014, whereas those reductions are in fact not required to occur until 12/31/2014 or later.

Because these controls are not required by that state rule to operate in 2014 , EPA is adjusting the 2014 budgets upwards to reflect the non

- operat ion of the

controls at these units. Georgia

44

44 EPA based these revisions on the schedule of retrofit deadlines that is most consistent with comments provided, which gener ally reflected the requirements of the Georgia Multi

- Pollutant State Rule as it existed when EPA finalized the Transport Rule in July of 2011.62 Table C.7.a. : Calculation to Determine Georgia SO 2 Budget Adjustments

- Assuming Revised Control Start

Dates

SO 2
A B C D E

2012 Emission Rate from TR_Remedy_Final (lbs/ MMBtu) 2014 Heat Input (TBtu) 2014 Revised

Emissions (1000 tons) 2014 TR_Remedy_Final

Emissions (1000 tons) Net Budget Adjustment (1000 tons)

Calculation A x B C

- D

Branch 1 0.92 16.50 7.60 1.85 5.74

Branch 2 0.92 20.06 9.24 2.25 6.99

Scherer 1 0.57 57.61 16.49 6.43 10.06

Yates 6 0.91 21.23 9.70 0.86 8.84

Yates 7 0.91 20.89 9.55 0.85 8.70

Total 40.334

Table C.7.b. : Calculation to Determine Georgia NO X Budget Adjustments

- Assuming Revised Control Start

Dates

Annual NO X
A B C D E

2012 Emission Rate from TR_Remedy_Final (lbs/ MMBtu) 2014 Heat Input (TBtu) 2014 Revised

Emissions (1000 tons) 2014 TR_Remedy_Final

Emissions (1000 tons) Net Budget Adjustment (1000 tons)

Calculation A x B C

- D

Branch 1 0.45 16.50 3.75 0.60 3.15

Branch 2 0.43 20.06 4.36 0.69 3.67

Scherer 1 0.15 57.61 4.20 2.02 2.18

Yates 6 0.26 21.23 2.80 0.73 2.07

Yates 7 0.28 20.89 2.88 0.75 2.13

Total 13.19863 Table C.7.c.: Calculation to Determine Georgia Ozone

- Season NO X Budget Adjustments

- Assuming Revised
Control Start Dates

Ozone

- Season NO X
A B C D E

2012 Emission Rate from TR_Remedy_Final (lbs/ MMBtu ) 2014 Heat Input (TBtu) 2014 Revised

Emissions (1000 tons) 2014 TR_Remedy_Final

Emissions (1000 tons) Net Budget Adjustment (1000 tons)

Calculation A x B C

- D

Branch 1 0.45 7.19 1.63 0.26 1.37

Branch 2 0.43 8.74 1.90 0.30 1.60

Scherer 1 0.15 25.29 1.84 0.89 0.96

Yates 6 0.26 9.27 1.22 0.32 0.91

Yates 7 0.28 9.12 1.26 0.33 0.93

Total 5.762

In each of the above tables, column A reflects the emission rate observed for that unit in the 2012 TR_Remedy_Final when no F GD or SCR is present. Column B reflects the heat input assumed in the 2014 TR_Remedy_Final analysis when a FGD or SCR was assumed to be present. Column C multiplies the heat input by the uncontrolled emission rate to get the uncontrolled emission rate assumption for 2014. The d ifference between this
uncontrolled emissions values (column C) and the controlled emissions value originally assumed (column D) results in the amount of the budget increase
(column E).

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

Rule , the NUSA for SO 2 in Georgia remain s at 2%. The original and revised values for the state budget s , assurance level s , and new unit set

- aside s are
described in the table below.64 Table C. 7

. d. : Impact of Georgia's Budget Revisions

- Assuming Revised Control Start Dates

Program Budget Assurance Level Total New Unit

Set

- Aside *

% of Budget Tons % of Budget Tons

2012 Before Direct Final Revisions Rule SO 2 158,527

- - 2% 3,171

2012 After Direct Final Revisions Rule SO 2 158,527

- - 2% 3,171

2014 Before Direct Final Revisions Rule SO 2 95,231 118% 112,373 2% 1,905

2014 After Direct Final Revisions Rule SO 2 135,565 118% 159,967 2% 2,711

2012 Before Direct Final Revisions Rule Annual NO X 62,010

- - 2% 1,240

2012 After Direct Final Revisions Rule Annual NO X 62,010

- - 2% 1,240

2014 Before Direct Final Revisions Rule Annual NO X 40,540 118% 47,837 2% 811

2014 After Direct Final Revisions Rule Annual NO X 53,738 118% 63,411 2% 1,075

2012 Before Direct Final Revisions Rule Ozone

- Season NO X 27,944

- - 2% 559

2012 After Direct Final Revisions Rule Ozone

- Season NO X 27,944

- - 2% 559

2014 Before Direct Final Revisions Rule Ozone

- Season NO X 18,279 121% 22,118 2% 366

2014 After Direct Final Revisions Rule Ozone

- Season NO X 24,041 121% 29,090 2% 481

*Approximate set

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

Turk Unit 1 in Arkansas commences commercial operation on or after January 1, 2010. Such a date qualifies Turk Unit 1 as a “planned” new unit by the definition of that category described in the “Allowance Allocation Final Rule TSD” for the final Transport Rule. Howe ver, in the final Transport Rule, EPA did not recognize Turk Unit 1 as a new unit and therefore omitted its proj ected emissions in the determination of the ozone

- season NO X new unit

set

- aside for Arkansas. Prior to this revision, in keeping with a revision demonstrated above and effected in the final revisions rule, that state’s NUSA was set at 5%, including the mi nimum 2% NUSA percentage plus a 3% state

- specific percentage to account for other planned units. 8 ) Arkansas (NUSA)

45

45 As explained in the final Transport Rule, the minimum size of any state’s new unit set

- aside is this “base perc entage” amount, to which “state

- specific” percentages are added if the given state has projected emissions from “planned” new units (76 FR 48291). EPA is now revising the

calculation of the Arkansas ozone

- season NO X new unit set

- aside to reflect the “new unit” status of Turk Unit 1. Following the sched ule established in the65 final Transport Rule, EPA has already recorded (i.e., distributed) allowances under the Federal Implementation Plan (FIP) for Arkansas for 2012 and 2013. Therefore, this revision to the NUSA will be implemented beginning in 2014.

Th e calculations to estimate 2020 ozone

- s eason NO X Emissions from Turk Unit 1 are shown in the table below:

Table C.8.a. : Calculation for Arkansas' Total Ozone

- Season

NO X Emissions from Turk Unit 1 46

A Capacity (MW) 600

B Heat Rate (Btu/kWh) 8980

C NO X Emissions Rate (lbs/ MMBtu ) 0.05

D Capacity Factor 85%

E Ozone

- Season Hours 3672

Total Ozone

- Season NO X Emissions (tons) ( A * D * B /1000* E * C/ 2000) 420

The calculations to quantify this revision are shown in the table below :

Table C.8.b. : Calculation for Arkansas' NUSA

A Projected 2020 Ozone

- Season NO X Emissions from Turk Unit

1 (tons) 420

B Arkansas 2014 Ozone

- Season NO X State Budget (tons) 15, 110

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

D Previous P ercentage for N ew U nit Set

- A side 5 %

E Total New Unit Set

- Aside ( C + D ) 8 %

EPA divided Turk Unit 1’s projected emissions into the state budget to derive the state

- specific percentage increase for the new unit set

- aside in
Arkansas, which rounds to 3 % . This value was added to the new unit set

- aside percentage previously calculated for the final revisions rule (5%) found

46 Projected 2020 o zone

- s eason NO X e missions were estimated and the new unit set

- aside was calculated using th e method outlined in the final Transport Rule (76 FR 48291) and the Technical Revisions to State Budgets and New Unit Set

- Asides associated with the Final Rule. EPA used data provided by the commenter and IPM model plant assumptions.66 earlier in this document . The resulting new unit set

- aside percentage for ozone

- season NO X in Arkansas is 8%. This change does not impact the state budget or assurance level in any way. However, the new unit set

- aside would change by the levels shown below. 47

Table C.8.c: Impact of 2014 Ozone Season NO X NUSA revision for Arkansas

New Unit Set

Aside Existing

Unit

Allocation Total

2014 As Finalized in Final Revisions Rule % 5% 95% 100%

2014 With Direct Final Rule Revision % 8% 92% 100%

2014 As Finalized in Final Revisions Rule tons 752 14,285 15,037

2014 With Direct Final Rule Revision tons* 1

, 209 13,901 15,110

*Approximate set

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

9 )

Washington Parish Energy Center Units CTG1, CTG2 and ST1 were included in the f inal Transport Rule NUSA calculations as planned units to commence commercial operation on or after January 1, 2010. However, these units were never completed and will not be operati ng. Therefore, EPA is removing their projected emissions from calcul atio ns for the Louisiana ozone

- s eason NO X NUSA. Prior to this revision, that state’s NUSA was set at 3%, including the minimum 2% NUSA percentage plus a 1% state

- specific percentage to account for planned units. Louisiana (NUSA)

48 EPA is now revis ing the calculation of the

Lo uisiana ozone

- season NO X new unit set

- aside to remove the projected emissions of these units that will not be commencing operation. This change will

take effect for Louisiana’s NUSA in 2012 and beyond

. 49

47 The increase to the new unit set

- aside would necessarily change existing unit allowance allocations in order to maintain the state budget. To review the existing unit

allowance allocations associated with this revision, please see the document entitled “ Final Revisions Rule Unit

- Level Allocations under the FIPs ” found in the docket to this rulemaking.

48 As explained in the final Transport Rule, the minimum size of any state’s new unit set

- aside is this “base percentage” amount, to which “state

- specific” percentages are

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

49 The originally projected emissions from Washington Parish Energy Center are no longer relevant to any of EPA’s emission proje ctions for the state of Louisiana pertinent

t o the Transport Rule, as all of its projected generation was offset in the final revisions rule by revised assumptions of inc reased generation from other Louisiana units due to

near

- term out

- of

- merit

- order dispatch conditions.67 EPA subtracted the Washington Parish units’ projected emissions from the projected planned unit emissions for Louisiana. The remaining planned emissions were divided into the state budget to derive the revised state

- specific percentage for the new unit set

- aside in Louisiana, which rounds to 0%.

T herefore, the new unit set

- aside percentage for ozone

- season NO X in Louisiana is 2%, the base percentage for the new unit set

- aside.

Table C.9 .a

. : Calculation for Louisiana's NUSA

A Previously Calculated Total Planned Emissions (tons) 126

B Projected 2020 Ozone

- Season NO X Emissions from Washington Parish (tons) 68

C Remaining Planned Emissions (A

- B) 58

D Louisiana Ozone Season NO X State Budget (tons) 18,136

E Remaining Committed Emissions as a % of Arkansas State Budget ( C/D ) 0%

F Base percentage for new unit set

- aside 2%

G Total New Unit Set

- Aside ( E + F \ ) 2%

This change does not impact the state budget or assurance level in any way. However, the new unit set

- aside would change by the levels shown

below. 50 EPA intends to record any additional 2012 and 2013 allocations to existing units due to this revision once this rule, and the underlying final Transport Rule, are legally effective.

50 The proposed de crease to th e 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 revision , please see the document entitled “ Final Revisions Rule Unit

- Level Allocations under the FIPs ” found in the docket

to this rulemaking.68 Table C.9.b: Impact of 2012 Ozone Season NO X NUSA revision for Louisiana

New Unit Set

Aside Existing Unit

Allocation Total

2012 As Finalized in Final Revisions Rule % 3% 97% 100%

2012 With Direct Final Rule Revision % 2% 98% 100%

2012 As Finalized in Final Revisions Rule tons 523 17,503 18,026

2012 With Direct Final Rule Revision tons* 344 17,771 18,115

2014 As Finalized in Final Revisions Rule % 3% 97% 100%

2014 With Direct Final Rule Revision % 2% 98% 100%

2014 As Finalized in Final Revisions Rule tons 523 17,503 18,026

2014 With Direct Final Rule Revision tons* 344 17,771 18,115

*Approximate set

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

10 )

Iatan Unit 2 in Missouri commenced commercial operation on or after January 1, 2010. Such a date qualifies Iatan Unit 2 as a “plan ned” new unit by the definition of that category described in the “Allowance Allocation Final Rule TSD” for the final Transport Ru le. However, in the final Transport Rule, EPA did not recognize Iatan Unit 2 as a new unit and therefore omitted its projected emissions in the determination of the SO 2 , annual NO X and ozone

season NO X new unit set

- asides for Missouri. For the final Tran sport Rule and the Transport Rule Supplemental Notice of Final Rulemaking , the state’s

NUSAs were set at 2% for SO 2 , 3% for annual NO X and 3% for ozone

- season NO X , including the minimum 2% NUSA percentage plus a state

- specific percentage for each budget. Missouri (NUSA)

51

51 As explained in the final Transport Rule, the minimum size of any state’s new unit set

- aside is this “base percentage” amount, to which “state

- specific” percentages are

a dded if the given state has projected emissions from “planned” new units (76 FR 48291). EPA is now revising the calculations of the Missouri new unit set

- asides to reflect the “new unit” status of Iatan Unit 2. Following the schedule established in the final Transport Rule, EPA has already recorded (i.e., distributed) allowances under the FIPs for Missouri for 2012

. Therefore, this revision to the NUSAs will be implemented beginning in 2013.69 The calculations to quantify Projected 2020 Emissions from Turk Unit 1 are shown in the table below 52 :

Table C.10.a. : Calculation for Missouri 's NUSA

SO 2 NO X Ozone

Season NO X
A Capacity (MW) 850 850 850

B Heat Rate (Btu/kWh) 9000 9000 9000

C Emissions Rate (lbs/ MMBtu ) 0.06 0.05 0.05

D Capacity Factor 85% 85% 85%

E Ozone Season Hours 8760 8760 3672
Total Emissions (tons) ( A * D * B /1000* E * C/ 2000) 1709 1424 598

EPA divided Iatan Unit 2’s projected emissions into the state budgets to derive the increases to the state

- specific percentages for the new unit set

asides in Missouri, which round to 1% for SO 2 , 3% for annual NO X and 3% for o z one

- s eason NO X . These values were added to the existing percentage s for

new unit set

- asides from the final Transport Rule and the Transport Rule Supplemental Notice of Final Rulemaking

. The resulting new unit set

- aside percentages in Missouri are 3% for SO 2 , 6% for annual NO X and 6% for ozone

- s eason NO X . This change does not impact the state budget or assurance level in any way. However, the NUSA s would change by the levels shown belo w. 53

52 Projected 2020 o zone

- s eason NO X e missions were calculated using the method outlined in the final Transport Rule (76 FR 48291) and the Technical Revisions to State

Bud gets and New Unit Set

- Asides associated with the Final Rule. EPA used data provided by the commenter, IPM model plant assumptions and plant data p ublished in the following: Robert Peltier, Plant of the Year: KCP&L’s Iatan 2 Earn’s POWER’s Highest Honor, P ower Magazine, August 1, 2011, available on the internet at

< http://www.powermag.com/environmental/3882.html >.

53 The increase to the new unit set

- aside would necessarily change existing unit allowance allocations in order to maintain the state budget. To review the existing unit
allowance allocations associated with this revision , please see the document entitled “ Final Revisions Rule Unit

- Level Allocations under the FIPs ” found in the docket to this rulemaking.70 Table C.10.b: Impact of 2013 NUSA revisions for Missouri (tons)

SO 2 New

Unit Set

Aside SO 2 Existing

Unit

Allocation SO 2 Total Annual NO X New Unit

Set

- Aside Annual NO X Existing Unit

Allocation Annual NO X Total OS NO X New
Unit Set

- Aside OS NO X Existing Unit

Allocation OS NO X Total

% As Finalized in Final

Revisions Rule 2% 98% 100% 3% 97% 100% 3% 97% 100%

% With Direct Final Rule

Revisio n 3% 97% 100% 6% 94% 100% 6% 94% 100%

2013 As Finalized in Final

Revisions Rule tons 4,149 203,317 207,466 1,571 50,803 52,374 683 22,079 22,762

2013 With Direct Final

Rule Revision tons* 6,224 201,242 207,466 3,144 49,256 52,400 1,367 21,421 22,788

2014 As Finalized in Final
Revisions Rule tons 3,319 162,622 165,941 1,462 47,255 48,717 632 20,441 21,073

2014 With Direct Final

Rule Revision tons* 4,978 160,963 165,941 2,925 45,818 48,743 1,266 19,833 21,099 *Approximate set

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

11 )

EPA is finalizing, based on comments, an increase to Mississippi’s ozone season NO X budget in 2012 and 2014 to reflect the assumption of near

term operational constraints affecting a unit at the Moselle plant , based on information provided by the system operator demonstrating that the plant is

located in an out

- of

- merit

- order dispatch area

. EPA's analysis in the final Transport Rule did not incorporate the immediate

- term local conditions described in recently submitted documentation that appear likely to necessitate non

- economic generation at the units displayed below during the implementation of the Transport Rule programs. Specifically, EPA is assuming additional generation will be dispatched at Moselle based on the need to provide voltage support

and regulation in the load pocket and the minimum operating constraint of a unit at Moselle. Mississippi

54

54 EPA

- HQ

- OAR

- 2009

- 0491

- 4763 and EPA

- HQ

- OAR

- 2009

- 0491

- 4746 As discussed later in this section, EPA assumes that the additional generation dispatched from this facility would offset generation that would otherwise come from combined cycle units within the state, and the71 revision to Mississippi’s state budget is based on the net change to projected emissions tak ing that offsetting factor into account. The net impact of these changes on the state’s ozone season NO X budget is a 115 ton increase

.

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

- of

- merit

- order dispatch at Moselle is shown in Table C.11 .a. For the unit, the capacity, 2012 emissions from TR_Remedy Final_2012 , heat rate, generation from TR_Rem edy Final_2012 , and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out

- of

- merit

- order capacity factor is shown in column H. The additional generation for out

- of

- merit

order dispatch was calculated by multiplying the capacity, the average out

- of

- merit

- order capacity factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the incremental generation by the unit’s heat ra te (column J). Finally, the

additional emissions a ssociated with the out

- of

- merit

- order generation was calculated by multiplying the additional heat input by the unit’s NO X emission

rate.

Table C.11 .a

. : Calculation to Determine Mississippi Ozone Season NO X Budget Revisions

- Assuming out

- of

- merit

- order dispatch at plant

Moselle

A B C D E F G H I J K

Plant Name Unique

Id Capacity (MW) 2012 Ozone
Season NO X Emission s 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

Moselle 2070_B_2 59 0 12878 0 0.258 34% 73.66 948,598 122.5

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

As calculated in Table C.11 .b, EPA is assuming that the increase in generation reflecting out

- of

- merit

- order dispatch would be offset by decreasing generation at Mississippi combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) equal to the generation

- weighted average of Mississippi combined cycle units. 55

55 These generation

- weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission rate averages used in Revisions Rule Part II” found in the docket for this rulemaking. The ozone season 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 representative combined cycle unit

.72 Table C.11

. b

. : Calculation of Emissions from Displaced Generation at Mississippi Combined Cycle Units

A B C D Program
Period Displaced Generation (GWh) Heat Rate (BTU/kWh) NO X Emission Rate (lbs/MMBTU) Displaced NO X Emissions (tons)

Calculation A*B*C/2000

Ozone Season 74 7,570 0.026054137 7

The total revision t o Mississippi’s state budget due to the out

- of

- merit

- order dispatch is calculated in Table C.11 .c. The emissions associated with the generation displaced by the out

- of

- merit

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

- of

- merit

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

Table C.11.c

. : Calculation to Determine Net Mississippi
Ozone Season NO X Budget Revisions

A Additional Emissions Due to

Out

- Of

- Order

- Merit Dispatch 123

B Displaced Emissions From

Out

- Of

- Order

- Merit Dispatch 7

C Net Change in Emission budget For Mississippi ( A

- B) 11573 The original and revised values for the state ozone season NO X budget, assurance level, and new unit set

- aside are described in Table C.11 .d.

Table C.11 .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 Before Direct Final Revisions Rule 12,314

- - 2% 246

2012 After Direct Final Revisions Rule 12,429

- - 2% 249

2014 Before Direct Final Revisions Rule 12,314 12,314 151,634,596 2% 246

2014 After Direct Final Revisions Rule 12,429 12,429 154,480,041 2% 249

*Approximate set

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

allocations

12 )

EPA is finalizing, based on comments, an increase to Arkansas’s ozone season NO X budget in 2012 and 2014 to reflect the assumption of near

- term operational constraints affecting units at the McClellan plant , based on information provided by the system operator demonstrating that the South Arkansas Region is an out

- of

- merit

- order dispatch area. EPA's analysis in the final Transport Rule did not incorporate the immediate

- term local conditions described in recently submitted documentation that appear likely to necessitate non

- economic generation at the units displayed below during the implementation of the
Transpor t Rule programs. Specifically, EPA is assuming additional generation will be dispatched the McClellan plant based on the ave rage capacity factor representing the frequency the unit is projected to be called to operate out

- of

- merit

- order, derived from imme diate

- term dispatch modeling projections provided by Entergy. Arkansas

56

56 EPA

- HQ

- OAR

- 2009

- 0491

- 4820 and Correspondence from Entergy to EPA, September 29, 2011. Please see the document “Transmission System Considerations

– Entergy” in the docket for this rule making. As discussed later in this section, EPA assumes that th e additional generation dispatched from this facility would offset generation

that would otherwise come from combined cycle units within the state, and the revision to Arkansas’s state budget is based on the net change to projected emissions taking that offsetting factor into account. The net impact of these changes on the state’s ozone season NO X budget is a 73 ton increase

.74 The calculati ons of the increase in ozone season NO X emissions due to out

- of

- merit

- order dispatch at McClellan is shown in Table C.12 .a. For the unit, the capacity, 2012 emissions from TR_Remedy Final_2012 , heat rate, generation from TR_Remedy Final_2012 , and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out

- of

- merit

- order capacity factor is shown in column H. The additional generation for out

- of

- merit

order dispatch was calculated by multiplying the capacity, the average out

- of

- merit

- order capacity factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the incremental generation by the unit’s heat ra te (column J). Finally, the

additional emissions a ssociated with the out

- of

- merit

- order generation was calculated by multiplying the additional heat input by the unit’s NO X emission

rate.

Table C. 12 .a

. : Calculation to Determine Arkansas Ozone Season NO X Budget Revisions

- Assuming out

- of

- merit

- order dispatch at McClellan

A B C D E F G H I J K

Plant Name Unique

Id Capacity (MW) 2012 Ozone
Season 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 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

McClellan 203_B_01 134 0 10901 0 0.2022989 3 16% 78.73 858,210 86.8

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

As calculated in Table C.12 .b

. , EPA is assuming that the increase in generation reflecting out

- of

- merit

- order dispatch would be offset by decreasing generation at Arkansas combined cycle units, shown in these calculations as a representative unit with a he at rate (column B) and emission rate (column C) equal to the generation

- weighted average of Arkansas combined cycle units. 57 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 esentative combined cycle unit.

57 These generation

- weighted ave rage heat rates and emission rates are derived using calculations found in the Excel workbook titled “ Calculation of heat rate and emission rate averages used in Revisions Rule Part II ” found i n the docket for this rulemaking.75 Table C.12

. b

. : Calculation of Emissions fro m Displ aced Generation at Arkansas 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

Ozone Season 79 7,549 0.044891435 13

The total revision to Arkansas’s state budget due to the out

- of

- merit

- order dispatch is calculated in Table C.12 .c. The emissions associated with the generation displaced by the out

- of

- merit

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

- of

- merit

- order generation (row A) to determine the net emission budget changes for Arkansas (row C).

Table C.12 .c

. : Calculation to Determine Net Arkansas
Ozone Season NO X Budget Revisions (tons)

A Additional Emissions Due to

Out

- Of

- Order

- Merit Dispatch 87

B Displaced Emissions From

Out

- Of

- Order

- Merit Dispatch 13

C Net Change in Emission budget For Arkansas (A

- B) 7376 The original and revised values for the state ozone season NO X budget, assurance level, and new unit set

- aside are described in Table C.12 .d.

Table C.12 .d.: Impact of Arkansas Ozone

- Season NO X Budget Revisions

– Assuming Out

- of

- Merit

- Order Dispatch at McClellan (tons)

Budget Assurance
Level Total New

Unit Set

Aside*

% of Budget Tons % of Budget Tons

2012 Before Direct Final Revisions Rule 15,037

- - 5% 752

2012 After Direct Final Revisions Rule 15,110

- - 5% 756

2014 Before Direct Final Revisions Rule 15,037 121% 18,195 5% 752

2014 After Direct Final Revisions Rule 15,110 121% 18,283 8% 1,209

*Approximate set

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

allocations

13 )

EPA is finalizing, based on comments, an increase to Texas’s annual and ozone season NO X budget in 2012 and 2014 to reflect the assumption of

near

- term operational constraints affecting units at seven plants, based on information provided by the system operator demonstrating these plants are in an

out

- of

- merit

- order dispatch area

. EPA's anal ysis in the final Transport Rule did not incorporate the immediate

- term local conditions described in recently submitted documentation that appear likely to necessitate non

- economic generation at the units displayed below during the implementation of the T ransport Rule programs. Specifically, EPA is assuming additional generation will be dispatched at seven plants (Jones, Moore County, Nichols, Plant X, Wilkes,
Lone Star, and Knox Lee ) based on the average capacity factor representing the frequency the un it is projected to be called to operate out

- of

- merit

- order,

derived from immediate

- term dispatch modeling projections provided by SPS Texas

58 and AEP

. 59

58 EPA

- HQ

- OAR

- 2009

- 0491

- 4752 a nd the document “Clarification of comments originally filed on the TR Revisions Rule by SPS” found in the docket for this rulemaking. As discussed later in this section, EPA assumes that th e

59 EPA

- HQ

- OAR

- 2009

- 0491

- 4737, EPA

- HQ

- OAR

- 2009

- 0491

- 4801, and the document “Clarification of comments originally filed on the TR Revisions Rule by AEP” found in the docket for this rulemaking.77 additional generation dispatched from these seven facilities would offset generation that would otherwise come from combined cycle units within the state,

and the revision to Texas’s state budget is based on the net change to projected emissions taking that offsetting factor into account . The net impact of these changes on the state’s annual NO X and ozone season NO X budget s are 2,731 and 1,142 ton increase s, respectively.

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

- of

- merit

- order dispatch at the seven plants is shown in

Tables C.13.a

. and C.13 .b. For each unit with out

- of

- merit

- order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012 , heat rate, generation from TR_Remedy Final_2012 , and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out

- of

- merit

- order capacity factor is shown in column H. The additional generation for out

- of

- merit

- order dispatch was calculated by multiplying the capacity, the average out

- of

- merit

- order capacity factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the incremental generation by the unit’s heat rate (column J). Finally, the additional emissions a ssociated with the out

- of

- merit

- order generation was calculated by multiplying the additional heat input by the unit’s NO X emission rate.

Table C.13 .a

. : Calculation to Determine Texas Annual NO X Budget Revisions

- Assuming out

- of

- merit

- order dispatch at seven plants

A B C D E F G H I J K

Plant Name Unique

Id Capacity (MW) 2012 Annual
NO X Emission s from TR_Remedy Final_2012 (1000 tons) Heat Rate (BTU/kW h) Annual
Generation
from TR_Remedy Final_2012 (GWh) Annual NO X Rate (lbs/ MMBtu ) Annual Average Out

Of

- Merit

Order Capacity

Factor Additional
Annual
Generation * Additional

Annual Heat Input ( MMBtu ) Additional

Annual
NO X Emissions (tons)
Calculation C*H* 8.760 E*I G*J/2000

Jones 3482_B
_151B 243 0.17811372 11109 283.774892 0.11 41% 881.00 9,787,029 550.7

Jones 3482_B
_152B 243 0.119198228 10245 283.774892 0.08 50% 1069.00 10,951,905 449.5

Moore County 3483_B
_3 48 0 14075 0 0.12 20% 82.00 1,154,150 69.4

Nichols 3484_B 107 0.074400425 9983 125.7370 30 0.12 29% 276.00 2,755,308 162.878 _141B

Nichols 3484_B
_142B 106 0.07774879 10450 124.561917 0.12 32% 296.00 3,093,200 184.2

Nichols 3484_B
_143B 244 0 11682 0 0.16 27% 572.00 6,682,104 548.8

Plant X 3485_B

_111B 48 0 16243 0 0.32 23% 98.00 1,591,814 252.5

Plant X 3485_B

_112B 102 0 13226 0 0.08 18% 162.00 2,142,612 89.8

Plant X 3485_B

_113B 103 0 11484 0 0.17 20% 182.00 2,090,088 173.7

Plant X 3485_B

_114B 189 0 10841 0 0.10 53% 881.00 9,550,921 487.0

Knox Lee 3476_B
_2 25.0 0 14500 0 0.102 2% 4.80 69,588 3.5

Knox Lee 3476_B
_3 25.0 0 14500 0 0.123 3% 6.68 96,879 6.0

Knox Lee 3476_B
_4 77.0 0 14933 0 0.311 1% 9.84 146,910 22.9

Knox Lee 3476_B
_5 343 0 11669 0 0.174 4% 105.53 1,231,465 107.2

Wilkes 3478_B
_1 175 0 12904 0 0.136 11% 176.01 2,271,239 154.579 Lone Star 3477_B
_1 50.0 0 14546 0 0.230 5% 22.70 330,223 37.9

Total 4,824.56 53,945,435 3,300.56

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

Table C.13

. b

. : Calculation to Determine Texas Ozone

- Season NO X Budget Revisions

- Assuming out

- of

- merit

- order dispatch at seven plants

A B C D E F G H I J K

Plant Name Unique

Id Capacity (MW) 2012 Ozone
Season 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 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

Jones 3482_B
_151B 243 0.17811372 11109 283.774892 0.11 31% 273.00 3,032,757 170.6

Jones 3482_B
_152B 243 0.119198228 10245 283.774892 0.08 26% 228.00 2,335,860 95.9

Moore County 3483_B
_3 48 0 14075 0 0.12 47% 82.00 1,154,150 69.4

Nichols 3484_B
_141B 107 0.074400425 9983 125.737030 0.12 17% 65.00 648,895 38.3

Nichols 3484_B
_142B 106 0.07774879 10450 124.561918 0.12 17% 68.00 710,600 42.3

Nichols 3484_B
_143B 244 0 11682 0 0.16 32% 288.00 3,364,416 276.380 Plant X 3485_B

_111B 48 0 16243 0 0.32 30% 52.00 844,636 134.0

Plant X 3485_B

_112B 102 0 13226 0 0.08 23% 85.00 1,124,210 47.1

Plant X 3485_B

_113B 103 0 11484 0 0.17 30% 112.00 1,286,208 106.9

Plant X 3485_B

_114B 189 0 10841 0 0.10 55% 384.00 4,162,944 212.3

Knox Lee 3476_B
_2 25.0 0 14500 0 0.102 5% 4.80 69,589 3.5

Knox Lee 3476_B
_3 25.0 0 14500 0 0.123 7% 6.68 96,879 6.0

Knox Lee 3476_B
_4 77.0 0 14933 0 0.311 3% 7.73 115,448 18.0

Knox Lee 3476_B
_5 343 0 11669 0 0.174 4% 46.31 540,447 47.1

Wilkes 3478_B
_1 175 0 12904 0 0.136 10% 66.21 854,348 58.1

Lone Star 3477_B

_1 50.0 0 14546 0 0.230 12% 22.70 330,223 37.9

Total 1,791.44 20,671,611 1,363.79

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.81 As calculated in Table C.13 .c

. , EPA is assuming that the increase in generation reflecting out

- of

- merit

- order dispatch would be offset by decreasing generation at Texas combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) equal to the generation

- weighted average of Texas combined cycle units. 60

Table C. 13. c

. : Calculation of Emissions from Displaced Generation at Texas Combined Cycle Units The ozone season NO X emissions associated with the displaced generation (column D) were calculated by multiplying that generation by the a verage heat rate and the relevant emission rate at the representative combined cycle unit.

A B C D

Program Period Displaced
Generation (GWh) Heat Rate (BTU/kWh) NO X Emission

Rate (lbs/MMBTU) Displaced

NO X Emissions (tons)

Calculation A*B*C/2000

Annual NO X 4, 825 7,405 0.031895983 5 70

Ozone Season NO X 1, 791 7,464 0.033113058 2 21

The total revision to Texas’s state budget due to the out

- of

- merit

- order dispatch is calculated in Table C.13 .d. The emissions associated with the generation displaced by the out

- of

- merit

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

- of

- merit

- o rder generation (row A) to determine the net emission budget changes for Texas (row C).

Table C.13

. d

. : Calculation to Determine Net Texas Annual and Ozone Season NO X Budget Revisions (tons)

Annual NO X Ozone Season NO X

A Additional Emissions Due to

Out

- Of

- Order

- Merit Dispatch 3,301 1364

B Displaced Emissions From

Out

- Of

- Order

- Merit Dispatch 570 221

C Net Change in Emission budget For Texas (A

- B) 2,731 1,142

60 These generation

- weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission
rate averages used in Revisions Rule Part II” found in the docket for this rulemaking.82 T he original and revised values for the state ozone season NO X budget, assurance level, and new unit set

- aside are described in Table C.13 .e.

Table C. 13.e.: Impact of Texas Budget Revisions

– Assuming Removed FGDs and Revised FGD Capture at Certain Units, Revised NUSAs for Oak Grove 2, and Out

- of

- Merit

- Order Dispatch at Two Facilities (tons)

Program Budget Assurance Level Total New Unit

Set

- Aside*

% of Budget Tons % of Budget Tons

2012 Before Direct Final Revisions Rule SO 2 294,471

- - 5% 14,724

2012 After Direct Final Revisions Rule SO 2 294,471

- - 5% 14,724

2014 Before Direct Final Revisions Rule SO 2 294,471 118% 347,476 5% 14,724

2014 After Direct Final Revisions Rule SO 2 294,471 118% 347,476 5% 14,724

2012 Before Direct Final Revisions Rule Annual NO X 134,970

- - 4% 5,399

2012 After Direct Final Revisions Rule Annual NO X 137,701

- - 4% 5,508

2014 Before Direct Final Revisions Rule Annual NO X 134,970 118% 159,265 4% 5,399

2014 After Direct Final Revisions Rule Annual NO X 137,701 118% 162,487 4% 5,508

2012 Before Direct Final Revisions Rule Ozone

- Season NO X 64,418

- - 4% 2,577

2012 After Direct Final Revisions Rule Ozone

- Season NO X 65,560

- - 4% 2,622

2014 Before Direct Final Revisions Rule Ozone

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

2014 After Direct Final Revisions Rule Ozone

- Season NO X 65,560 121% 79,328 4% 2,622

*Approximate set

- aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations83 14 )

EPA is finalizing, based on comments, an increase to Kansas’s SO 2 and NO X budgets in 2012 and 2014 to reflect the assumption of near

- term operational constraints affecting a unit at the Quindaro plant , based on information provided by the system operator demonstrating that the unit serves is an

out

- of

- merit

- order dispatch area

. EPA's analysis in the final Transport Rule did not incorporate the immediate

- term local conditions described in recently submitted documentation that appear likely to necessitate non

- economic generation at the units displayed below during the implementat ion of the Transport Rule programs. Specifically, EPA is assuming additional generation will be dispatched Quindaro unit 1 based on the annual minimum capacity factor representing the frequency the unit is projected to be called to operate out

- of

- merit

- or der, provided in comments from Kansas City Board of Public

Utilities. Kansas

61

The calculations o f the increase in SO 2 and annual NO X emissions due to out

- of

- merit

- order dispatch at Quindaro unit 1 is shown in Tables C.14 .a

. and C.14 .b. For the unit, the capacity, 2012 emissions from TR_Remedy Final_2012 , heat rate, generation from TR_Remedy Final_2012 , and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out

- of

- merit

- order capacity factor is shown in column H. The additional generation

for out

- of

- merit

- order dispatch was calculated by multiplying the capacity, the average out

- of

- merit

- order capacity factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the incremental generation by the u nit’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. In the m odel run TR_Remedy Final_2012

, this unit ran at approximately a 55% annual capacity factor. KCBPU’s comments showed that the unit must operate at an average annual capacity fac tor of 75% to serve its load. Therefore, the difference of 20% is being considered out

- of

- merit

- order dispatch

in this case. As discussed later in this section, EPA assumes that th e additional generation dispatched from this facility would offset generat ion that would

otherwise come from similarly

- positioned coal

- fired units within the state, and the revision to Kansas’s state budget is based on the net change to projected emissions taking that offsetting factor into account. The net impact of these changes on the state’s SO 2 and annual NO X budgets are 452 and 640 ton increases, respectively.

61 EPA

- HQ

- OAR

- 2009

- 0491

- 4779 and the document “Clarification of comments originally filed on the TR Revisions Rule by KC BPU” found in the docket for this rulemaking.84 Table C.14 .a

. : Calculation to Determine Kansas SO 2 Budget Revisions

- Assuming out

- of

- merit

- order dispatch at Quindaro unit 1

A B C D E F G H I J K

Plant Name Unique

Id Capacity (MW) 2012 Annual
SO 2 Emission s from TR_Remedy Final_2012 (1000 tons) Heat Rate (BTU/kW h) Annual
Generation
from TR_Remedy Final_2012 (GWh) Annual SO 2 Rate (lbs/ MMBtu ) Annual Average Out

Of

- Merit

Order Capacity

Factor Additional

Annual
Generation * Additional
Annual Heat Input ( MMBtu ) Additional
Annual
SO 2 Emissions (tons)
Calculation C*H* 8.760 E*I G*J/2000 Quindaro 1295_B_1 72 1.170152332 11673 345.6701925 0.579999983 33.8% 212.87 2,484,808 720.6

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

Table C.14

. b

. : Calculation to Determine Kansas Annual NO X Budget Revisions

- Assuming out

- of

- merit

- order dispatch at Quindaro unit 1

A B C D E F G H I J K

Plant Name Unique

Id Capacity (MW) 2012 Annual
NO X Emission s from TR_Remedy Final_2012 (1000 tons) Heat Rate (BTU/kW h) Annual
Generation
from TR_Remedy Final_2012 (GWh) Annual NO X Rate (lbs/ MMBtu ) Annual Average Out

Of

- Merit

Order Capacity

Factor Additional
Annual
Generation * Additional
Annual Heat Input ( MMBtu ) Additional
Annual
NO X Emissions (tons)
Calculation C*H*3.672 E*I G*J/2000

Quindaro 1295_B_

1 72 1.355762723 11673 345.670193 0.67182472 33.8% 212.87 2,484,808 834.7

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

As calculated in Table C.14 .c

. , EPA is assuming that the in crease in generation reflecting out

- of

- merit

- order dispatch would be offset by decreasing generation at other Kansas coal units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) equal to the generation

- weighted average of Kansas coal units. 62

62 These generation

- weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission rate averages used in Revisions Rule Part II” found in the docket for this rulemaking. The ozone season NO X emissions associated with the displaced generation (c olumn D) were calculated by multiplying that generation by the average heat rate and the relevant emission rate at the representative coal unit. EPA used representative85 coal

- fired generation to offset the additional generation assumed now to occur at Quin daro unit 1 because it is reasonable to assume that increased baseload generation at Quindaro unit 1 would displace similarly

- positioned baseload coal

- fired generation previously projected to meet electricity demand. 63

Table C.14

. c

. : Calculation of Emission s from Displaced Generation at Kansas Coal Units

A B C D

Program Period Displaced
Generation (GWh) Heat Rate (BTU/kWh) Displaced
Generation
Emission Rate (lbs/MMBTU) Displaced
Emissions (tons)

Calculation A*B*C/2000

SO 2 213 10,707 0.23598 269

Annual NO X 213 10,707 0.170752 195

The total revision to Kansas’s state budget due to the out

- of

- merit

- order dispatch is calculated in Table C.14 .d. The emissions associated with the generation displaced by the out

- of

- merit

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

- of

- merit

- order generation (row A) to determine the net emission budget changes for Kansas (row C).

Table C.14

. d

. : Calculation to Determine Net Kansas SO 2 and Annual NO X NO X Budget Revisions (tons)

2012 2014

SO 2 Annual

NO X SO 2 Annual

NO X

A Emissions Due to Out

- Of

- Merit

Order Generation 721 835 721 835

B Displaced Emissions from Out

- Of

Merit

- Order Generation at Quindaro 269 195 269 195

C Net Budget Revisions for Kansas (A

- B) 452 640 452 640

63 In a ddition, whereas EPA has made similar revisions affecting oil/gas steam units to other state budgets by offsetting previously projected natural gas

- fired combined cycle generation, there are no gas

- fired combined cycles in the state of Kansas that could se rve as candidates for this calculation. EPA believes the calculation as demonstrated above, using representative coal

- fired generation as a broad match for the dispatch characteristics of the assumed increase in out

- of

- merit

- order dispatch
at Quindaro uni t 1, maintains a consistent approach with the other revisions of this type made to Transport Rule state budgets.86 The total budget revisions for Kansas are summarized below in T able C.14 .e

.

Table C.14 .e .: Total Budget Revisions for Kansas

Budget Year Revisions due to
Out

- of

- Merit

Order Dispatch Revisions due to
Unit Controls Total Change

SO 2 2012 452

-- 452

SO 2 2014 452

-- 452

Annual NO X 2012 640

-- 640

Annual NO X 2014 640 5,154 5, 794

The original and revised values for the state budget s , assurance level s , and new unit set

- aside s are described in Table C.14

. f

.

Table C.14.f.: Impact of Kansas Budget Revisions

– for Out

- Of

- Merit

- Order Dispatch and Unit
Controls

Program Budget Assurance Level Total New Unit

Set

- Aside*

% of Budget Tons % of Budget Tons

2012 Before Direct Final Revisions Rule SO 2 41,528

- - 2% 831

2012 After Direct Final Revisions Rule SO 2 41,980

- - 2% 840

2014 Before Direct Final Revisions Rule SO 2 41,528 118% 49,003 2% 831

2014 After Direct Final Revisions Rule SO 2 41,980 118% 49,536 2% 840

2012 Before Direct Final Revisions Rule Annual NO X 30,714

- - 2% 614

2012 After Direct Final Revisions Rule Annual NO X 31,354

- - 2% 627

2014 Before Direct Final Revisions Rule Annual NO X 25,560 118% 30,161 2% 511

2014 After Direct Final Revisions Rule Annual NO X 31,354 118% 36,998 2% 627

*Approximate set

- aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations87 15 )

EPA is finalizing, based on comments, an increase to Missouri’s annual and ozone season NO X budget in 2012 and 2014 to reflect the assumption of near

term operational constraints affecting units at four plants, based on information provided by the system operator demonstrating that these units are called to dispatch out

- of

- merit

- order to provide voltage support and regulation. EPA's analysis in the final Transport Rule did not incorporate the immediate

- term local conditions described in recently submitted documentation that appear likely to necessitate non

- economic generation at the units displa yed below during the implementation of the Transport Rule programs. Specifically, EPA is assuming additional generation will be dispatched at four plants (Hawthorn, Greenwood, Ralph Green, and South Harper) based on the average capacity factor representi ng the frequency the unit has recently been called on to operate out of merit order, calculated from dispatch logbook data provided by KCPL. Missouri

64

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

- of

- merit

- order dispatch at the four facilities is shown in

Tables C.15 .a . and C.15 .b. For each unit with out

- of

- merit

- order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012 , heat rate, generation from TR_Remedy Final_2012 , and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out

- of

- mer it

- order capacity factor is shown in column H. The additional generation for out

- of

- merit

- order dispatch was calculated by multiplying the capacity, the average out

- of

- merit

- order capacity factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the incremental generation by the unit’s heat rate (column J). Finally, the additional emissions associated with the out

- of

- merit

- order generation was calculated by multiplying the additional he at input by the unit’s NO X emission rate. As discussed later in this section, EPA assumes that the additional generation dispatched from these four facili ties would offset generation that would otherwise come from combined cycle units within the state, and the

revision to Missouri’s state budget is based on the net change to projected emissions taking that offsetting factor into account . The net impact of t hese changes on the state’s annual and ozone season NO X budget are 26 ton increase s each.

64 EPA

- HQ

- OAR

- 2009

- 0491

- 4826 and the document “Clarification of comments originally filed on the TR Revisions Rule by KCPL” found in the docket for this rulemaking.88 Table C.15 .a

. : Calculation to Determine Missouri Annual NO X Budget Revisions

- Assuming out

- of

- merit

- order dispatch at four plants

A B C D E F G H I J K

Plant Name Unique Id Capacity (MW) 2012 Annual
NO X Emission s from TR_Remedy Final_2012 (1000 tons) Heat Rate (BTU/kW h) Annual
Generation
from TR_Remedy Final_2012 (GWh) Annual NO X Rate (lbs/ MMBtu ) Annual Average Out

Of

- Merit

Order Capacity

Factor Additional
Annual
Generation * Additional
Annual

Heat Input ( MMBtu ) Additional
Annual
NO X Emissions (tons)
Calculation C*H*8.760 E*I G*J/2000

Hawthorn 2079_G_7 77 0 13180 0 0.03072543 0.06% 0.39 5,074 0.1

Hawthorn 2079_G_8 77 0 16770 0 0.03190992 0.14% 0.97 16,233 0.3

Greenwood 6074_G_1 58 0 13300 0 0.50105250 0.31% 1.55 20,615 5.2

Greenwood 6074_G_2 58 0 13300 0 0.50105250 0.23% 1.16 15,388 3.9

Greenwood 6 074_G_3 58 0 13300 0 0.50105250 0.35% 1.77 23,541 5.9

Greenwood 6074_G_4 58 0 13300 0 0.50105250 0.28% 1.40 18,673 4.7

Ralph Green 2092_G_3 71 0 14322 0 0.50105250 0.02% 0.14 2,048 0.5

South Harper 56151_G_

GT1 105 0 15250 0 0.05518069 0.54% 4.99 76,159 2.1

South Harper 56151_G_

GT2 105 0 15082 0 0.05490044 0.81% 7.47 112,632 3.1

South Harper 56151_G_

GT3 105 0 15250 0 0.05578315 0.48% 4.39 66,871 1.9

Total 24.22 357,235 27.5

*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8.760 hours of possible operation in year ; that factor is divided by 1,000 to yield units in GWh.89 Table C.15

. b

. : Calculation to Determine Missouri Ozone Season NO X Budget Revisions

- Assuming out

- of

- merit

- order dispatch at four plants

A B C D E F G H I J K

Plant Name Unique Id Capacity (MW) 2012 Ozone
Season 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 Additional
Ozone
Season
Generation * Additional
Ozone
Season Heat Input ( MM Btu ) Additional
Ozone
Season
NO X Emissions (tons)
Calculation C*H* 3

. 762 E*I G*J/2000

Hawthorn 2079_G_7 77 0 13180 0 0.03072543 0.14% 0.39 5,074 0.1

Hawthorn 2079_G_8 77 0 16770 0 0.03190992 0.34% 0.97 16,233 0.3

Greenwood 6074_G_1 58 0 13300 0 0.50105250 0.73% 1.55 20,615 5.2

Greenwood 6074_G_2 58 0 13300 0 0.50105250 0.54% 1.16 15,388 3.9

Greenwood 6074_G_3 58 0 13300 0 0.50105250 0.83% 1.77 23,541 5.9

Greenwood 6074_G_4 58 0 13300 0 0.50105250 0.66% 1.40 18,673 4.7 Ralph Green 2092_G_3 71 0 14322 0 0.50105250 0.05% 0.14 2,048 0.5

South Harper 56151_G_

GT1 105 0 15250 0 0.05518069 1.30% 4.99 76,159 2.1

South Harper 56151_G_

GT2 105 0 15082 0 0.05490044 1.94% 7.47 112,632 3.1

South Harper 56151_G_

GT3 105 0 15250 0 0.05578315 1.14% 4.39 66,871 1.9

Total 24.22 357,235 27.5

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

.

As calculated in Table C.15 .c

. , EPA is assuming that the increase in generation reflecting out

- of

- merit

- order dispatch would be offset by decreasing generation at Missouri combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) equal to the generation

- weighted average of Missouri combined cycle units. 65

65 These generation

- weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission rate averages used in Revisions Rule Part II” found in the docke t for this rulemaking. 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 esentative combined cycle unit.90 Table C.15

. c

. : Calculation of Emissions from D isplaced Generation at
Missouri 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 24 8,049 0.018330584 2

Ozone Season 24 8,079 0.018315387 2

The total revision to Missouri’ s state budget due to the out

- of

- merit

- order dispatch is calculated in Table C.15 .d. The emissions associated with the generation displaced by the out

- of

- merit

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

- of

- merit

- order generation (row A) to determine the net emission budget changes for Missour i (row C).

Table C.15.d. : Calculation to Determine Net Missouri and Ozone Season NO X Budget Revisions (tons)

2012 2014

Annual

NO X Ozone
Season

NO X Annual

NO X Ozone
Season

NO X

A Emissions Due to Out

- Of

- Merit

Order Generation 28 28 28 28

B Displaced Emissions from Out

- Of

Merit

- Order Generation 2 2 2 2

C Net Budget Revisions for Missouri (A

- B) 26 26 26 2691 The original and revised values for the state ozone season NO X budget, assurance level, and new unit set

- aside are described in Table C.15.e. ,which

includes the adjustments to Missouri’s new unit set aside described in section 10

.

Table C.15.e .: Impact of Missouri Budget Revisions for Out

- Of

- Merit

- Order Dispatch and New Unit Set

- Aside

Program Budget Assurance Level Total New Unit Set

- Aside*

% of Budget Tons % of Budget Tons

2012 Before Direct Final Revisions Rule SO 2 207,466

- - 2% 4,149

2012 After Direct Final Revisions Rule SO 2 207,466

- - 2% 4,149

2013 Before Direct Final Revisions Rule SO 2 207,466

- - 2% 4,149

2013 After Direct Final Revisions Rule SO 2 207,466

- - 3% 6,224

2014 Before Direct Final Revisions Rule SO 2 165,941 118% 195,810 2% 3,319

2014 After Direct Final Revisions Rule SO 2 165,941 118% 195,810 3% 4,978

2012 Before Direct Final Revisions Rule Annual NO X 52,374

- - 3% 1,571

2012 After Direct Final Revisions Rule Annual NO X 52,400

- - 3% 1,572

201 3 Before Direct Final Revisions Rule Annual NO X 52,374

- - 3% 1,571

201 3 After Direct Final Revisions Rule Annual NO X 52,400

- - 6% 3,144

2014 Before Direct Final Revisions Rule Annual NO X 48,717 118% 57,486 3% 1,462

2014 After Direct Final Revisions Rule Annual NO X 48,743 118% 57,517 6% 2,925

2012 Before Direct Final Revisions Rule Ozone

- Season NO X 22,762

- - 3% 683

2012 After Direct Final Revisions Rule Ozone

- Season NO X 22,788

- - 3% 684

201 3 Before Direct Final Revisions Rule Ozone

- Season NO X 22,762

- - 3% 683

201 3 After Direct Final Revisions Rule Ozone

- Season NO X 22,788

- - 6% 1,367

2014 Before Direct Final Revisions Rule Ozone

- Season NO X 21,073 121% 25,498 3% 632

2014 After Direct Final Revisions Rule Ozone

- Season NO X 21,099 121% 25,530 6% 1,266

*Approximate set

- aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations92 16 ) Oklahoma

EPA is finalizing, based on comments, an increase to Oklahoma’s ozone season NO X budget in 201 3 and 2014 to reflect the assumption of near

- term operational constraints affecting units at four plants, based on information provided by the system operator dem onstrating these plants are in an out

- of

- merit

order dispatch area

. These changes do not apply to Oklahoma’s 2012 budget because similar changes were already made to the affected units’ operati on in 2012, as described in the Technical Support Document “ Determination of State Budgets for the Final Ozone Supplemental of the Transport Rule .” 66 EPA's analysis in the final Transport Rule did not incorporate the immediate

- term local conditions described in recently submitted documentation that appear likely

to necessitate non

- economic generation at the units displayed below during the implementation of the Transport Rule programs. Specifically, EPA is assuming additional generation will be dispatched at four plants (Northeastern, Riverside , Southwestern, and T ulsa) based on the average capacity factor representing the frequency the unit is projected to be called to operate out

- of

- merit

- order, derived from immediate

- term dispatch modeling projections provided by AEP. 67

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

- of

- merit

- order dispatch at these facilities is shown in Table C.16 .a. For

each unit with out

- of

- merit

- order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012 , heat rate, generation from TR_Remedy Final_2012

, and emission rate from EPA’s NEEDS database are shown (columns A t o G). The average out

- of

- merit

- order capacity factor is shown in column H. The additional generation for out

- of

- merit

- order dispatch was calculated by multiplying the capacity, the average out

- of

- merit

- order capacity factor, and the

number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the incremental generation by the u nit’s heat rate (column J). Finally, the additional emissions associated with the out

- of

- merit

- order generation was calculated by m ultiplying the additional heat input by the unit’s NO X emission rate. As discussed later in this section, EPA as sumes that the additional generation dispatched from th ese facilit ies would offset g eneration

that would otherwise come from combined cycle units within the state, and the revision to Oklahoma’s state budget is based on the net change to projected emissions taking that offsetting factor into account. The net impact of these changes on the state’s ozone season NO X budget is a n 859 ton increase

.

66 EPA

- HQ

- OAR

- 2009

- 0491

- 485, pg 5

- 7.

67 EPA

- HQ

- OAR

- 2009

- 0491

- 4737, EPA

- HQ

- OAR

- 2009

- 0491

- 4801, and the document “Clarification of comments originally filed on the TR Revisions Rule by AEP” found in the docket for this rulemaking.93 Table C.16 .a

. : Calculation to Determine Oklahoma Ozone Season NO X Budget Revisions

- Assuming Out

- of

- Merit

- Order Dispatch at Four Plants

A B C D E F G H I J K

Plant Name Unique Id Capacity (MW) 2012
Ozone
Season
NO X Emissions from TR_ Remedy Final_ 2012 (1000 tons) Heat Rate (BTU/ kWh) Ozone
Season
Generatio
n 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

Northeastern 2963_B_3302 480 0 10442 0 0.396 17.1% 301.00 3,143,054 622.6

Riverside 4940_B_1502 459 0 11094 0 0.226 8.2% 137.75 1,528,240 172.8

Southwestern 2964_B_801

N 40.0 0 20500 0 0.251 0.7% 1.02 20,862 2.6

Sout hwestern 2964_B_801S 40.0 0 20500 0 0.206 0.7% 1.02 20,862 2.1

Sout hwestern 2964_B_8002 80.0 0 11900 0 0.326 2.1% 6.26 74,476 12.1

Southwestern 2964_B_8003 311 0 11611 0 0.436 1.6% 17.75 206,123 45.0

Tuls a 2965_B_1402 165 0 14213 0 0.182 1.7% 10.33 146,755 13.4

Tulsa 2965_B_1403 85.0 0 11163 0 0.276 1.6% 4.89 54,611 7.5

Tuls a 2965_B_1404 165 0 13144 0 0.188 5.8% 35.06 460,825 43.3

Total 515.08 5,655,808 921.42

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

As calculated in Table C.16 .b

. , EPA is assuming that the in crease in generation reflecting out

- of

- merit

- order dispatch would be offset by decreasing generation at Oklahoma combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C)94 equal to th e generation

- weighted average of Oklahoma combined cycle units. 68

Table C.16

. b

. : Calculation of Emissions from Displaced Generation at Oklahoma Combined Cycle Units The ozone season 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 th e representative combined cycle unit.

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 515 7,713 0.031566434 63

The total revision to Oklahoma’s state budget due to the out

- of

- merit

- order dispatch is calculated in Table C.16 .c. The emissions associated with the generation displaced by the out

- of

- merit

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

- of

- merit

- order generation (row A) to determine the net emission budget changes for Oklahom a (row C).

Table C.16

. c

. : Calculation to Determine Net Oklahoma
Ozone Season NO X Budget Revisions (tons)

A Additional Emissions Due to

Out

- Of

- Order

- Merit Dispatch 921

B Displaced Emissions From

Out

- Of

- Order

- Merit Dispatch 63

C Net Change in Emission budget For Oklahoma (A

- B) 859

68 These generation

- weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission rate averages used in Revisions Rule Part II” found in the docket for this rulemaking.95 The original and revised values for the state ozone season NO X budget, assurance level, and new unit set

- aside are described in Table C.16 .d.

Table C.16.d.: Impact of Oklahoma 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 Before Direct Final Revisions Rule 36,567

- - 2% 731

2012 After Direct Final Revisions Rule 36,567

- - 2% 73 1

2013 Before Direct Final Revisions Rule 21,835

- - 2% 437

2013 After Direct Final Revisions Rule 22,694

- - 2% 454

2014 Before Direct Final Revisions Rule 21,835 121% 26,420 2% 437

2014 After Direct Final Revisions Rule 22,694 121% 27,460 2% 454

*Approximate set

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

allocations

17 ) Louisiana

EPA is finalizing, based on comments, an increase to Louisiana ’s ozone season NO X budget in 2012 and 2014 to reflect the assumption of near

- term operational constraints affecting units at two plants, based on information provided by the system operator demonstrating these plants are in an out

- of

- merit

order dispatch area

. EPA's analys is in the final Transport Rule did not incorporate the immediate

- term local conditions described in recently submitted documentation that appear likely to necessitate non

- economic generation at the units displayed below during the implementation of the Tra nsport Rule

programs. Specifically, EPA is assuming additional generation will be dispatched at two plant s based on the average capacity factor representing the frequency the unit is projected to be called to operate out

- of

- merit

- order, derived from immed iate

- term dispatch modeling projections provided by AEP. 69

69 EPA

- HQ

- OAR

- 2009

- 0491

- 4737, EPA

- HQ

- OAR

- 2009

- 0491

- 4801, and the document “Clarification of comments originally filed on the TR Revisions Rule by AEP” found in the docket for this rulemaking. As discussed later in this section, EPA assumes that the additional generation dispatched from these facilities would offset generation that would otherwise96 come from combined cycle units within t he state, and the revision to Louisiana ’s state budget is based on the net change to projected emissions taking that offsetting factor into account . The net impact of these changes on the state’s ozone season NO X budget is a 89 ton increase

.

The calculations o f the increase in ozone season NO X emissions due to out

- of

- merit

- order dispatch at these facilities is shown in Table C.17 .a. For

each unit with out

- of

- merit

- order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012 , heat rate, g eneration 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 mu ltiplying the capacity, the average out

- of

- merit

- order capacity factor, and the number of hours in the ozone season (column I). The additional heat input required was calculated by multiplying the incremen tal 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.

Table C.17 .a

. : Calculation to Determine Louisiana Ozone Season NO X Budget Revisions

- Assuming out

- of

- merit

- order dispatch at two plants

A B C D E F G H I J K

Plant Name Unique

Id Capacity (MW) 2012 Ozone
Season 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 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

J. Lamar
Stall Unit at

Arsenal Hill 1416_B _5A 110 0 15,702 0 0.092 3% 11.82 185,573 8.6

Lieberman 1417_B _1 25.0 0 14,983 0 0.420 5% 4.20 63,002 13.2

Lieberman 1417_B _2 25.0 0 14,546 0 0.420 6% 5.41 78,671 16.5

Lieberman 1417_B _3 111 0 12,334 0 0.124 11% 46.52 573,748 35.6

Lieberman 1417_B _4 109 0 12,791 0 0.132 8% 32.14 411,051 27.1

Total 100.09 1312044. 7 100.98

*The formula used to calculate Column I uses a multiplier of 3.672 because there are 3,672 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.97 As calculated in Table C.17 .b

. , EPA is assuming that the i ncrease in generation reflecting out

- of

- merit

- order dispatch would be offset by decreasing generation at Louisiana combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) equal to the generation

- weighted average of Louisiana combined cycle units. 70

Table C.17

. b

. : Calculation of Emissions from Displaced Generation at Louisiana Combined Cycle Units The ozone season 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 representative combined cycle unit.

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 100 7,480 0.031765081 12

The total revision to Louisiana ’s state budget due to the out

- of

- merit

- order dispatch is calculated in Table C.17 .c. The emissions associated with the generation displaced by the out

- of

- merit

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

- of

- merit

- order generation (row A) to determine the net emission budget changes for Louisia na (row C).

Table C.17

. c

. : Calculation to Determine Net Louisiana
Ozone Season NO X Budget Revisions (tons)

A Additional Emissions Due to

Out

- Of

- Order

- Merit Dispatch 101

B Displaced Emissions From

Out

- Of

- Order

- Merit Dispatch 12

C Net Change in Emission budget For Louisiana (A

- B) 89

70 These generation

- weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission rate averages used in Revisions Rule Part II” found in the docket for this rulemaking.98 The original and revised values for the state ozone season NO X budget, assurance level, and new unit set

- aside are described in Table C.17 .d.

Table C.17 .d.: Impact of Louisiana 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 Before Direct Final Revisions Rule 18,026

- - 3% 541

2012 After Direct Final Revisions Rule 18,115

- - 2% 362

2014 Before Direct Final Revisions Rule 18,026 121% 21,811 3% 541

2014 After Direct Final Revisions Rule 18,115 121% 21,919 2% 362

*Approximate set

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

allocations

18 )

EPA is finalizing, based on comments, an increase to Ohio’s SO 2 , annual NO X , and ozone season NO X budget in 2012 and 2014 to reflect the assumption of near

- term operational constraints affecting Muskingum River unit 1 , based on information provided by the system operator demonstrating the plant operates out

- of

- merit

- order. EPA's analysis in the final Transport Rule did not incorporate the immediate

- term local conditions described in recently

submitted docu mentation that appear likely to necessitate non

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

Rule programs. EPA is assuming additional generation will be dispatched from Muskingum River unit 1 based on operat ional constraints provided by

AEP. Ohio

71

71 EPA

- HQ

- OAR

- 2009

- 0491

- 4737, EPA

- HQ

- OAR

- 2009

- 0491

- 4801, and the document “Clarification of comments originally filed on the TR Revisions Rule by AEP” found in the docket for this rulemaking. As discussed later in this section, EPA assumes that th e additional generation dispatched from this facilities would offset generation that would

otherwise come from combined cycle units within the state, and the revisi on to Ohio’s state budget is based on the net change to projected emissions taking that offsetting factor into account. The net impact of these changes on the st ate’s SO 2 , annual NOX, and ozone season NO X budget are 5,163 ton, 528 ton,

and 247 ton inc rease s, respectively.99 The calculations of the increase in SO 2 , annual NO X , and ozone season NO X emissions due to out

- of

- merit

- order dispatch at this facilit y are shown in

Tables C.18 .a

. , C.18 .b

. , and C.18 .c. For each unit with out

- of

- merit

- order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012 , heat rate, generation from TR_Remedy Final_2012 , and emission rate from EPA’s NEEDS database are shown (columns A to G). The average out

- of

- merit

- order capacity factor is shown in column H. The additional generation for out

- of

- merit

- order dispatch was calculated by multiplying the capacity, the average out

of

- merit

- order capacity factor, and the number of hours in the ozone season (column I). The additio nal heat input required was calculated by multiplying the incremental generation by the unit’s heat rate (column J). Finally, the additional emissions associated with the out

- of

- merit

- order generation was calculated by multiplying the additional heat input by the unit’s NO X emission rate.

Table C.18 .a

. : Calculation to Determine Ohio SO 2 Budget Revisions

- Assuming out

- of

- merit

- order dispatch at Muskingum River

A B C D E F G H I J K

Plant Name Unique

Id Capacity (MW) 2012 Annual
SO 2 Emission s from TR_Remedy Final_2012 (1000 tons) Heat Rate (BTU/kW h) Annual
Generation
from TR_Remedy Final_2012 (GWh) Annual SO 2 Rate (lbs/ MMBtu ) Annual Average Out

Of

- Merit

Order Capacity

Factor Additional
Annual
Generation * Additional
Annual Heat Input ( MMBtu ) Additional

Annual
SO 2 Emissions (tons)
Calculation C*H* 8.760 E*I G*J/2000 Muskingum
River 2872_B _1 190 0 10416 0 4.36 14% 227.39 2,368,533 5163.4

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

** SO 2 rates were derived assuming a similar grade of coal as was used by comparable units in IPM in that region of Ohio and the SO 2 content of coal in chapter 8 of the documentation for IPM. The resulting

SO 2 rates are similar to historic rates at these units.100 Table C.18

. b

. : Calculation to Determine Ohio Annual NO X Budget Revisions

- Assuming out

- of

- merit

- order dispatch at Muskingum River plants

A B C D E F G H I J K

Plant Name Unique

Id Capacity (MW) 2012 Annual
NO X Emission s from TR_Remedy Final_2012 (1000 tons) Heat Rate (BTU/kW h) Annual
Generation
from TR_Remedy Final_2012 (GWh) Annual NO X Rate (lbs/ MMBtu ) Annual Average Out

Of

- Merit

Order Capacity

Factor Additional
Annual
Generation * Additional
Annual Heat Input ( MMBtu ) Additional
Annual
NO X Emissions (tons)
Calculation C*H* 8.760 E*I G*J/2000 Muskingum

River 2872_B _1 190 0 10416 0 0.46 14% 227.39 2,368,533 547.1

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

Table C.18

. c

. : Calculation to Determine Ohio Ozone

- Season NO X Budget Revisions

- Assuming out

- of

- merit

- order dispatch at Muskingum River plants

A B C D E F G H I J K

Plant Name Unique

Id Capacity (MW) 2012 Ozone
Season 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 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 Muskingum
River 2872_B _1 190 0 10416 0 0.46 15% 106.71 1,111,521 256.8

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

As calculated in Table C.18 .d

. , EPA is assuming that the in crease in generation reflecting out

- of

- merit

- order dispatch would be offset by decreasing generation at Ohio combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emission rate (column C) eq ual101 to the ge neration

- weighted average of Ohio combined cycle units. 72

Table C.18

. d

. : Calculation of Emissions from Displaced Generation at Ohio Combined Cycle Units

The ozone season 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 repres entative combined cycle unit.

A B C D

Program Period Displaced
Generation (GWh) Heat Rate (BTU/kWh) Emission

Rate (lbs/MMBTU) Displaced
Emissions (tons)

Calculation A*B*C/2000

SO 2 227 7,191 0 0

Annual NO X 227 7,191 0.023597394 19

Ozone Season NO X 107 7,265 0.026009641 10

The total revision to Ohio’s state budget due to the out

- of

- merit

- order dispatch is calculated in Table C.18 .e. The emissions associated with the generation displaced by the out

- of

- merit

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

- of

- merit

- order generation (row A) to determine the net emission budget changes for Ohio (row C).

72 These generation

- weighted average heat rates and emission rates are derived using calculations found in the Excel workbook tit led “Calculation of heat rate and emission rate averages used in Revisions Rule Part II” found in the docket for this rulemaking.102 Table C.18

. e

. : Calculation to Determine Net Ohio SO 2 , Annual NO X , and Ozone
Season NO X Budget Revisions (tons)

2012 2014

SO 2 Annual

NO X Ozone
Season

NO X SO 2 Annual

NO X Ozone
Season

NO X

A Additional Emissions

Due to Out

- Of

- Merit

Order Generation 5,163 547 257 5,163 547 257

B Displaced Emissions
from Out

- Of

- Merit

Order Generation 0 19 10 0 19 10

C Net Budget Revisions for Ohio (A

- B) 5,163 528 247 5,163 528 247

The total revisions to Ohio’s budgets as a result of control and out

- of

- merit

- order dispatch rev isions are summarized below in Table C.18 .f

.

Table C.18

. f .: Total Budget Revisions for Ohio (tons)

Budget Year Revisions due to
Out

- of

- Merit

Order Dispatch Revisions Due to
Unit Controls Total Change

SO 2 2012 5,163 5,163

SO 2 2014 5,163 5,163

Annual NOX 2012 547 2,218 2,765

Annual NOX 2014 547 2,218 2,765

Ozone Season NOX 2012 257 964 1,221

Ozone Season NOX 2014 257 964 1,221103 The original and revised values for the state SO 2 , annual NOX, and ozone season NO X budget s , assurance level s , and new unit set

- aside s are
described in Table C.18

. g

.

Table C. 18

. g. : Impact of Ohio Budget Revisions for Out

- Of

- Merit

- Order Dispatch and Control Revisions

Program Budget Assurance Level Total New
Unit Set

Aside*

% of Budget Tons % of Budget Tons

2012 Before Direct Final Revisions Rule SO 2 310,230

- - 2% 6,205

2012 After Direct Final Revisions Rule SO 2 315,393

- - 2% 6,308

2014 Before Direct Final Revisions Rule SO 2 137,077 118% 161,751 2% 2,742

2014 After Direct Final Revisions Rule SO 2 142,240 118% 167,843 2% 2,845

2012 Before Direct Final Revisions Rule Annual NO X 92,703

- - 2% 1,854

2012 After Direct Final Revisions Rule Annual NO X 95,468

- - 2% 1,909

2014 Before Direct Final Revisions Rule Annual NO X 87,493 118% 103,242 2% 1,750

2014 After Direct Final Revisions Rule Annual NO X 90,258 118% 106,504 2% 1,805

2012 Before Direct Final Revisions Rule Ozone

- Season NO X 40,063

- - 2% 801

2012 After Direct Final Revisions Rule Ozone

- Season NO X 41,284

- - 2% 826

2014 Before Direct Final Revisions Rule Ozone

- Season NO X 37,792 121% 45,728 2% 756

2014 After Direct Final Revisions Rule Ozone

- Season NO X 39,013 121% 47,206 2% 780

*Approximate set

- aside amounts, may be adjusted upwards or downwards slightly following rounding of existing unit allocations104 19 )

EPA is finalizing, based on comments, an increase to New York’s SO 2 , annual NO X , and ozone season NO X budget in 2012 and 2014 to reflect the assumption of near

- term operational constraints affecting units at the East River plant, based on information provided by the facility operator demonstrating that the plant is required to run for non

- economic r easons. EPA's analysis in the final Transport Rule did not incorporate the immediate

- term local

conditi ons described in recently submitted documentation that appear likely to necessitate non

- economic generation at the units displayed below during the implementation of the Transport Rule programs. EPA is assuming additional generation will be dispatched fro m units at the East River plant based on

immediate

- term operational constraints provided by Con

- Ed. New York

73

The calculations of the increase in SO 2 , annual NO X , and ozone season NO X emissions due to out

- of

- merit

- order dispatch at the East River plant is
shown in Tables C.19.a., C.19.b., and C.19.c. For each unit with out

- of

- merit

- order dispatch, the capacity, 2012 emissions from TR_Remedy Final_2012, heat rate, generation from TR_Remedy Final_2012, and emission rate from EPA’s NEEDS database are shown (c olumns 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 hou rs in the ozone season (column I). The additional heat input required was calculated by multiplying the incremental generation by the unit’s heat rate (column J). Finally, the additional emissions associated with the out

- of

- merit

- order generation

were calc ulated by multiplying the additional heat input by the unit’s NO X emission rate. As discussed later in this section, EPA assumes that th e additional generation dispatched

from East River would offset generation that would otherwise com e from combined cycle units within the state, and the revision to New York’s state budget is based on the net change to projected emissions taking that offsetting factor into account . The net impact of these changes on the state’s SO 2 , annual NOX,

and ozon e season NO X budget are 84 ton, 694 ton, and 127 ton increases, respectively.

The East River units are part of the Manhattan District Heating System such that their emissions are driven by complex intera ctions of local electricity and steam demand, and all of these emissions are relevant to the state’s Transport Rule budgets. The emissions adjustments calculated in these tables affect the two steam units (Units 60 and 70) that did not operate in the EPA projections, but are required to run to s upport t he district heating system and also provide electricity. The remaining two units (Units 1 and 2) did operate in the EPA projections at reasonable level s and are not included in the adjustments. In addition, since Unit 70 operates as a electricity

- only un it during in ozone season so that there is no ozone

- season steam requirement for non

economic operation, Unit 70 is not included in the revisions for the ozone season. In calculating the net impact on the stat e budgets, only the increased electricity gene ration would affect EPA’s prior projected emissions, as such generation is assumed to offset generation at other units in the state in order to maintain the balance between modeled electricity supply and demand. Therefore, the heat input for each output i s displayed separately to make clear the generation that needs to be offset, which in this particular case represents only a fraction of the revised incremental heat input.

73 EPA

- HQ

- OAR

- 2009

- 0491

- 4761 and the document “Clarification of comments originally filed on the TR Revisions Rule by Con

- Ed” f ound in the docket for this rulemaking.105 Table C.19.a.: Calculation to Determine New York SO 2 Budget Revisions

- Assuming out

- of

- merit

- order dispatch at East River

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

Plant

Name Unique

Id Capacity (MW) 2012
Annual SO 2 Emissions from TR_ Remedy Final_2012 (1000 tons) Heat

Rate (BTU/ kWh) Annual
Generation from TR_ Remedy Final_2012 (GWh) Annual SO 2 Rate (lbs/

MMBtu ) Annual Average
Out

- Of

Merit

Order Capacity

Factor For Electricity Additional
Annual
Generation* Additional
Annual Elec Heat Input ( MMBtu ) Additional

Annual
Steam Heat Input ( MMBtu ) Percent
of Heat Input
from
Oil** Additional
Annual Heat Input
from Oil Addi tional
Annual SO 2 Emissions

Total (tons)

Calcula

tion C*H*8.760 E*I (J+K)*L G*M/200

0

East
River 2493_ B_60 134 0 12,830 0 0.31 36.1% 423.8 5,436,793 499,577 5.3% 316,408.5 49

East
River 2493_ B_70 180 0 11,980 0 0.31 15.4% 242.8 2,909,070 1,372,350 5.3% 228,199.7 35

Total 666.6 8,345,862 1,871,927 544,608.2 84.4

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

** Average percentag e of oil btu input at East River units 60 and 70 from 2010 EIA 923 data.106 Table C.19.b.: Calculation to Determine New York Annual NO X Budget Revisions

- Assuming out

- of

- merit

- order dispatch at East River

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

Plant

Name Unique

Id Capacity (MW) 2012 Annual
NO X Emissions
from TR_Remedy Final_2012 (1000 tons) Heat Rate (BTU/kWh) Annual
Generation
from TR_Remedy Final_2012 (GWh) Annual NO X Rate (lbs/ MMBtu ) Annual Average
Out

- Of

Merit

- Order Capacity

Factor For Electricity Additional

Annual
Generation* Additional
Annual

Elec Heat Input ( MMBtu ) Additional
Annual
Steam Heat Input ( MMBtu ) Additional

Annual
NO X Emissions

Total (tons)
Calcu

lation C*H*8.760 E*I G*(J+K)/

2000

East
River 2493_ B_60 134 0 12,830 0 0.13 36.1% 423.8 5,436,793 499,577 394.1

East
River 2493_ B_70 180 0 11,980 0 0.15 15.4% 242.8 2,909,070 1,372,350 328.3

Total 666.6 8,345,862 722.4

*The formula used to calculate Column I uses a multiplier of 8.760 because there are 8.760 hours of possible operation in the ozone season; that factor is divided by 1,000 to yield units in GWh.107 Table C.19.c.: Calculation to Determine New York Ozone

- S eason NO X Budget Revisions

- Assuming out

- of

- merit

- order dispatch at East River

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

Plant

Name Unique

Id Capacity (MW) 2012 Ozone
Season NO X Emissions
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 for Electricity Additional
Ozone
Season
Generation* Additional
Ozone
Season

Elec Heat Input ( MMBtu ) Additional
Ozone
Season
Steam Heat Input ( MMBtu ) Additional
Ozone
Season
NO X Emissions

Total (tons)
Calcu

lation C*H*3.672 E*I G*(J+K)/

2000

East
River 60 134 0 12

, 830 0 0.13 29.3% 144.2 1,849,702 160,106 133

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

As calculated in Table C.1 9 .d

. , EPA is assuming that the increase in generation reflecting out

- of

- merit

- order dispatch would be offset by decreasing generation at New York combined cycle units, shown in these calculations as a representative unit with a heat rate (column B) and emissio n rate (column C) equal to the generation

- weighted average of New York combined cycle units. 74 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 representative combined cycle unit.

74 These generation

- weighted average heat rates and emission rates are derived using calculations found in the Excel workbook titled “Calculation of heat rate and emission rate averages used in Revisions Rule Part II” found in the docket for this rulemaking.108 Table C.19.d.: Calculation of Emissions from Displaced Generation at New York Combined Cycle Units

A B C D

Program Period Displaced
Generation (GWh) Heat Rate (BTU/kWh) Emission

Rate (lbs/MMBTU) Displaced NO X Emissions (tons)

Calculation A*B*C/2000

SO 2 667 7,236 0 0

Annual NO X 667 7,236 0.011824358 29

Ozone Season NO X 144 7,244 0.012305053 6

The total revision to New York ’s state budget due to the out

- of

- merit

- order dispatch is calculated in Table C.1 9 .e. The emissions associated with the generation displaced by the out

- of

- merit

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

- of

- merit

- o rder generation (row A) to determine the net emission budget changes for New York (row C).

Table C.19.e.: Calculation to Determine Net New York SO 2 , Annual NO X and Ozone Season NO X Budget Revisions (tons)

2012 2014

SO 2 Annual

NO X Ozone
Season

NO X SO 2 Annual

NO X Ozone
Season NO X

A Additional Emissions Due to

Out

- Of

- Merit

- Order

Generation 84 722 133 84 722 133

B Displaced Emissions from

Out

- Of

- Merit

- Order
Generation 0 29 6 0 29 6

C Net Budget Revisions for New York (A

- B) 84 694 127 84 694 127109 The total sum of changes to New York emission budgets in these revisions are shown in T able C.19 .f

. below.

Table C.19. f .: Total Budget Revisions for New York (tons)

Budget Year Revisions due to
Out

- of

- Merit

Order Dispatch Revisions Due to
Unit Controls Total Change

SO 2 2012 84 5,360 5,444

SO 2 2014 84 5,360 5,444

Annual NOX 2012 694

-- 694

Annual NOX 2014 694

-- 694

Ozone Season NOX 2012 127

-- 127

Ozone Season NOX 2014 127

-- 127110 The original and revised values for the state ozone season NO X budget, assurance level, and new unit set

- aside are described in Table C.1 9 .g

.

Table C.19.g.: Impact of New York Budget Revisions for Controls and Out

- Of

- Merit

- Order Dispatch
Revisions

Program Budget Assurance
Level Total New
Unit Set

Aside*

% of Budget Tons % of Budget Tons

2012 Before Direct Final Revisions Rule SO 2 30,852

- - 2% 617

2012 After Direct Final Revisions Rule SO 2 36,296

- - 2% 726

2014 Before Direct Final Revisions Rule SO 2 22,112 118% 26,092 2% 442

2014 After Direct Final Revisions Rule SO 2 27,556 118% 32,516 2% 551

2012 Before Direct Final Revisions Rule Annual NO X 21,028

- - 2% 421

2012 After Direct Final Revisions Rule Annual NO X 21,722

- - 2% 434

2014 Before Direct Final Revisions Rule Annual NO X 21,028 118% 24,813 2% 421

2014 After Direct Final Revisions Rule Annual NO X 21,722 118% 25,632 2% 434

2012 Before Direct Final Revisions Rule Ozone

- Season NO X 10,242

- - 2% 205

2012 After Direct Final Revisions Rule Ozone

- Season NO X 10,369

- - 2% 207

2014 Before Direct Final Revisions Rule Ozone

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

2014 After Direct Final Revisions Rule Ozone

- Season NO X 10,369 121% 12,546 2% 207

*Approximate set

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