### T e chnical S up p o rt Doc u me n t

f

o r the



### AEP/PSO BART Revision to the Okla h o m a R e gi o n al H a z e S tate

I m ple m entati o n Pl a n a n d Fede r al I mpl e men t a t i on P l an

P rep a red a nd R e vi e w ed b y :

Jo e K o r d zi

E r i k S n y d er

Terry Johnson

July 2 01 3i Contents

I. R e latio n s h ip o f t h is T S D t o o u r P r o p osal

................................ ................................ ................................ . 1

II. Ba c k g r o un d to Re gio n al H a z e

................................ ................................ ................................ ................. 2

III. Eval u a t ion o f S ta t e Sub m it t al

................................ ................................ ................................ ................ 5

A . Best Availa b le Re t r o f it Te c hn ology (BART) R e qu ir e m e n ts: 40 C F R 51.308 (e )

............................... 5

A.1. S O 2 BART

................................ ................................ ................................ ................................ .... 5

A.2. NOx BART

................................ ................................ ................................ ................................ 25

B. F e de r al L a n d M a n ag e r Coo r d i n a t ion 40 C F R 51.308 ( i)

................................ ................................ ... 25

Tables

Table 1: Revised Dry Scrubber Cost Effectiveness

................................ ................................ ....... 15

Table 2: Summary of Revised DSI & Dry Scrubber Cost Effectiveness

................................ ...... 17

Table 3: ODEQ’s Baseline Minus the FIP SO 2 Control Benefit

................................ ................... 18

Table 4: ODEQ’s Baseline Minus ODEQ’s Revised BART

................................ ......................... 18

Table 5: Estimated Alternate Baseline Impairment for 0.6 lb/MMBtu for Units 3 & 4

................ 20

Table 6: Revised Baseline Minus the FIP SO 2 Control Benefit

................................ .................... 20

Table 7: Revised Baseline Minus OD EQ’s Revised BART

................................ .......................... 21

Table 8: Summary of Results with Revised Baseline

................................ ................................ .... 22

Figures

Figure 1: Map of Class I Areas

................................ ................................ ................................ ........ 3

Figure 2: Location of the Class I Area in Oklahoma

................................ ................................ ....... 3

Figure 3: Map of Regional Planning Organization Boundaries

................................ ....................... 41 

### O k la h o m a R e gi o n a l Haze T e chn i c a l S u p p o rt Do cu m ent ( T S D )

I. R e latio n s h ip o f t h is T S D t o o u r P r o p osal

W e a re pro p osi n g to a p p rove a revision to the Okl a hom a ’ s R e g ional H a z e ( RH) State

Implementation Plan ( S I P ) submi t ted on June 20, 2013 . In our previous regional haze action for

Oklahoma 1 , (our “prior Oklahoma SIP/FIP action”), we partially approved, partially disapproved

and took no action on various portions of Oklahoma’s RH SIP revision submitted to us on

February 19, 2010. We disapproved the S O 2 BART determinations for Units 4 and 5 of the

Oklahoma Gas and Electric ( OG&E ) Muskogee plant; Units 1 and 2 of the OG&E Sooner plant;

and Units 3 and 4 of the A m e ri ca n E le c tric Pow e r/Publ i c S e r v ice Compa n y o f Okl a homa

( AEP/PSO ) Northeastern plant. We also disapproved the LTS under section 51.308(d)(3). We

finalized a FIP that imposed SO 2 BART emission limits on these six sources at three facilities

. In that FIP, w e found that SO 2 BART for each of these units was an S O 2 emission limit of 0.06

lb/MMBtu on a 30 boiler operating day average.

Our current proposal is in response to a settlement agreement reached between us, the U. S.

Department of Justice, AEP/PSO, the State of Oklahoma, ODEQ, and the Sierra Club (the

“settlement agreement”), attached as Appendix I to the SIP.

In this action, we are pro p os i ng the following:

• Replacement of our SO 2 BART determination for Units 3 and 4 of the AEP/ PS O

N o r the a ste r n plant with ODEQ’s revised S O 2 BART determination for these units

• Approval of an accelerated NOx BART compliance date for these same units

• Approval of mon i to r in g

, r e c o r d

- k ee pi n g

, a nd r e porti n g r e quir e ments to e nsure

c o mp l ian c e with t h e se e m i s sion l i m i t a t i ons

• 51.308(i)

- Fe deral Land Manager coordination

We are not proposing any other changes to o ur prior Oklahoma SIP/FIP action

.

Oklahoma has proposed to amend its l ong t erm s trategy, as described in Chapter VII of its

original RH SIP. Specifically, a s required by subparagraph 26(E) of the First Amended Regional

Haze Agreement, AEP/PSO will develop and propose a monitoring program to test various

operating profiles and other measures required under subparagraph 26(D) to determine whether

increased SO 2 removal efficiencies can be achieved during normal operations. If the SO 2 emission rate for the remaining coal

- fired unit ( either No rtheastern Unit 3 or 4 ) is not reduced to

0.30 lb/ MM Btu after the implementation of the control requirements set forth in this revision and

the incorporated First Amended Regional Haze Agreement, then O DEQ commits to obtain

and/or identify additional SO 2 r eductions within the State of Oklahoma to the extent necessary to

achieve the anticipated visibility benefits estimated in the CENRAP Base G 2018 regional haze

modeling and attributable to reductions in SO 2 emissions after installation of presumptive

contr ols on AEP/PSO Northeastern Units 3 and 4. Additional details can be found in pages 8 to

1 76 FR 81728.2 9 of the revised SIP.

However, because we have not yet acted on Oklahoma’s long term strategy, which includes

proposed reductions from more than the AEP/PSO Northe astern plant, we cannot propose to

amend the long term strategy at this time.

We note that AEP/PSO remains bound to the terms of the settlement agreement (unless it is

amended), regardless of our proposed action. That settlement does require a monitori ng program

to test various operating profiles and other parameters to determine whether increased DSI SO 2 removal efficiencies can be achieved during normal operations. We acknowledge that DSI

performance is somewhat dependent on the particulars of the plant in question. As an aid to this

analysis, we are pla cing a number of documents in the docket that attest to DSI control

efficiencies at different plants and test envi ronments.

This T S D is not me a nt t o be a c om p lete r a t i on a le f or our dec is i on. I t m e r e l y p r ovides a ddi t ional

info r mation for some of t he te c hni c a l asp ec ts of t h e b a sis f or th i s a c t i on w h e n n ee d e d. I n some

of the no n

- te c hn i ca l a r e a s, our F e d e r a l Re g is t e r n ot i ce (s) pro v ides mo r e d e tail t h a n do e s th i s

TSD. L a st l y , the T S D a t t e mp t s to r e fer the r e a d e r to the spe c i fic por t ions of the Okl a homa ’ s

r e g io n a l ha z e S I P that w e r e l i e d upon f or o u r a n a l y sis o f p a rticul a r po r t i ons of se c t i on 51.308.

Th r ou g hout t his do c um e nt, we may use la n g u a g e such a s, “ w e f ind ” or ot h e r sim i lar phr a s e s that

on the su r f a c e would sug g e st a fin a l det e rmin a t i on h a s be e n ma d e . H o w e v e r, a ll a spe c ts of our

T S D should be c onsid e r e d to be p a rt of our p r opos a l and a r e subj ec t t o c h a n g e b a s e d on

c om m e nts and other inf o rm a t i on we m a y r ece i v e during our p ubl i c c om me nt pe r iod.

II. Ba c k g r o un d to Re gio n al H a z e

I n Se c t i on 169A of the 1 977 Am e ndments to the Cle a n Air A c t (CA A ), Con g r e ss set fo r th a

p r ogr a m for p rot ec t i n g v i sib i l i t y in F e d e r a l C lass I a r e a s whi c h c a l l s for the “ p re v e nt i on of a n y

futu re

, a nd the r e me d y i n g of a n y e x is t in g , i m p a irme n t of vis i bi l i t y in ma n d a to r y F e d e r a l C lass I

a r e a s whi c h i m p a irme n t r e sul t s f r om m a nmade a ir pol l ut i on.” Con g r e ss ad o pted the vis i bi l i t y

p r ovis i ons to pr o te c t v i sib i l i t y in 156 Fe d e r a l C la s s I a re a s, which in c lude c e rt a in national p a r ks,

memo r ial p a rks, a nd wil d e rn e ss a r e as o v e r a ce r t a in s iz e

, a nd a ll in t e rn a t i on a l pa r ks. Th e s e a r ea s

a re d e fin e d a t 40 C F R 8 1 .400, a re l i sted b y S tate a t 40 C F R 81.40 1

- 81.437, a nd a re d e pict e d in

F i g u re 1, with t he Class I a r e a with i n Okl a homa, the W ichita Mountains N a t i on a l W i l dl i fe

R e fug e , d e pic t e d in F i g u r e 2 :3 F ig u r e 1. M ap of Class I A re as

F ig u r e 2. Loc a tion of t h e Class I A re a in O k la h o m a4 On De c e mber 2, 1980, w e p r omu l g a ted re g ulations to add re ss v i sib i l i t y i m p a irme n t t h a t i s

“ r e a so n a b l y a t t ribut a ble ” to a sin g le sou r c e or sm a ll g roup of sou r ce s. (45 F R 80084)

. Th e se

re g ulations re p r e s e nted t he f irst phase in ad d r e ss i ng vis i bi l i t y i m p a irme n t a nd d e fer re d ac t i on o n

re g ional h a z e that e ma n a tes f rom a v a ri e t y of sou r ce s until mon i torin g , modeling a nd s c ientific

knowl e dge a bout t he r e l a t i onships b e tw ee n pol l utants a nd visib i l i t y i m p a i r ment i m p r ov e d.

I n the 1 9 90 Am e ndments to t he CA A , Con g r e ss a dd e d S ec t i on 169B a nd c a l l e d on us to i ssue

R e g ional H a z e r ules. T h e RH r ule th a t we p romul g a t e d on J u l y 1, 1999 (64 F R 35713) re vised

the e x is t ing vis i bi l i t y r e gulations to i nte g r a te p ro v is i ons a ddr e ss i ng re g ion a l ha z e vis i bi l i t y

i m p a irme n t and e stablish a c ompr e h e nsive vis i b i l i t y prot e c t i on p r o g r a m f o r Fe d e r a l C lass I a r e a s.

T h e se re g ulations r e p re s e nted the s e c ond p h a se in add r e ss i ng vis i bi l i t y i m p a irme n t. S tat e s w e re

r e quir e d to s ubm i t s t a te imp l e ment a t i on plans ( S I P s) to us that set out e a c h st a t e ’s plan f or

c omp l y i n g w i th t he RH Rul e , including c o nsultation and c oordin a t i on with o t h e r st a tes a nd with

Fe d e r a l L a nd Mana g e rs (F L M s ). S tat e s w e re r e quir e d to submit a R e g ional H a z e S I P to us

with i n thr e e y e a rs a ft e r the d a t e of d e s i g n a t i o n of a re a s und e r t h e N a t i on a l Amb i e nt Air Qu a l i t y

S tand a rd (N A A QS) f or f ine p a rticul a te matter ( P M2.5). W e p r o mu l g a ted PM2.5 d e si g n a t i ons on

D ece m b e r 17, 2004, a nd thus, re gional h a z e S I P s w e re to b e submi t ted to us b y D ece m b e r 17,

2007, wh i c h is also specified a t 40 C F R 51.308 ( b )

.

The R H rule a d d r e ssed t h e c omb i n e d vis i bi l i t y e f f

ec ts of v a rious pol l ut i on sour ce s ov e r a wide

g e o g ra phic re g ion. Conse q u e nt l y

, a ll 50 stat e s, including those w i t hout C lass I a r ea s

, W a shin g ton, D.C., a nd the V i r g in I slands, w er e re quir e d to subm i t R e g ion a l H a z e S I P s (40 C F R

51.300 ( b ) (3 ) ). W e d e signat e d five R e g ional P la n ning O r g a ni z a t i ons (R P Os) to assist wi t h the

c oordin a t i on a nd c oo p e rat i on n ee d e d to add r e ss t he vis i bi l i t y is s u e

, a s sh o w n b y F i g u re 3.

F ig u r e 3. M ap of R e gio n al P la nn i n g Organ i z a t ion Bo u nd a r ies5 Okl a homa, th r o u g h the O DEQ jo i n e d st a te a ir a g e n c ies f rom A r k a nsas, I o w a , K a n s a s, L ouis i a n a

, Minn e sota, Missouri, N e b ra ska, a nd T e x a s in fo r m i ng CENRA P , in 1999. CENRAP also

includ e s f e d e r a l l y re c o g n i z e d I ndian t r ibes lo c a ted with i n the g e o g r a phic b o und a ri e s of its

memb e r st a tes. The S ta t e of O klahoma a nd i t ’s a g e n c y , the O klaho m a D e p a rtme n t of

Environm e ntal Qu a l i t y

, c hose to pa r t i c ipate in C E NRAP to dev e lop t he te c hnic a l an a l y s e s

n ee d e d to fulfill the r e quir e ments of the RH Rul e

.

III. Eval u a t ion o f S ta t e Sub m it t al

I n e v a luati n g the O klah o ma RH S I P

, we r e vie w e d a ll the p a rts of the do c u ment, including the

bo d y of t h e S I P i t s e lf, a n d a ll a pp e ndic e s (including the modeling files)

. I n a dd i t i on, we d re w

upon the f ol l owing a ddi t ional do c uments that m a y not h a ve b e e n sp ec if i ca l l y discuss e d in our

TSD a nd / or the F e d e r a l R e g is te r publ i ca t i on(s) of o u r de c i sio n :

1. 40 C F R P a rt 51.

2. App e ndix V to 40 C F R Pa rt 5 1

. 3. The “ B ART Guid e l i n e s” i n App e ndix Y to P a rt 5 1

— Guid e l i n e s for B ART D e te r m i n a t i ons

Und e r t h e R e g io n a l H a z e Rule, 7 0 F R 39104, J u l y 6, 200 5

. 4. Guid a n c e f o r T r ac ki n g P rog re ss Und e r the R e g i o n a l H a z e Rule, E P A

- 454/ B

- 03

- 004,

S e ptemb e r, 20 0 3.

5. Guid a n c e f o r De monst r a t i ng Attainment of A ir Q u a l i t y Go a ls f o r PM2.5 a n d Re g ional H a z e

, J a nu a r y 2, 2001.

6. Guid a n c e f o r E st i mating N a tur a l Vis i bi l i t y Condi t ions Und e r the R e g ional H a z e Rule, EPA

454/ B

- 0 3

- 005, S e p t e mber 2003.

7. The “ B a s e l i ne M e m o ,” w hich is e nt i t l e d

, “ 2002 B a se Y e a r E m i ss i on I n v e nto r y S I P

P lannin g : 8

- Hour O z on e

, P M2.5 and R e g ional H az e P ro g r a ms, d a ted 11/18/2002, f r om

L y d ia We g man to the R e g ional Air Dir e c tors .”

8. Guid a n c e f o r Setting R ea sona b le Prog re ss G o a ls Und e r the R e g ional H a z e P ro g r a m, d a ted

J une 1, 200 7

. 9. Visibi l i t y Monitoring G u idan ce , EP A

- 454/ R

- 99

- 0 03, J une 1999.

10. Emis s ions I nv e nto r y Gu i d a n c e f o r I mp l e ment a t i o n of O z one a nd P a rticul a t e Matter N a t i on a l

Amb i e nt Air Q u a l i t y S tand a rds ( N A A QS ) a nd Re g io n a l H a z e R e g ulations, EPA

- 454/ R

- 0 5

- 001, d a t e d Au g ust, 2005.

11. I nt e rim Air Q u a l i t y P ol i c y on W i l dland a nd P r e s c r ibed F ir e s, A p r i l 23, 1998.

A . Best Availa b le Re t r o f it Te c hn ology (BART) R e qu ir e m e n ts: 40 C F R 51.308 (e )

A.1. S O 2 BART

Herein, we review the SO 2 BART determinations for Units 3 and 4 of the AEP/PSO Northeastern

plant. We are not reviewing any other portions of our prior Oklahoma SIP/FIP action . Specifically,

this proposal addresses Oklahoma’s duty to address the following sections of the RH rule:

• 51.308(e)(1)(ii)(A)

- BART five factor determination

• 51.308(e)( 1)(ii)(B)

- BART for larger fossil fuel p ower plants

• 51.308(e)( 1)(iv)

- (v)

– install ation of BART6 Section 51.308(e) addresses the B e st Av a i l a b l e R e tro f it T ec hnol o g y ( B ART) r e quir e ments for

re g ional h a z e vis i bi l i t y i m p a irme n t. Okl a homa must submit a S I P c onta i ning e m i ss i on

l i m i tations re p re s e nt i ng B ART a nd s c h e dules for c omp l i a n c e with B ART f or ea c h B ART

e l i g ib l e sour c e that m a y r e a s o n a b l y be a nt i c ipat e d to c a u s e or c o ntribute to a n y i m p a irm e nt of

vis i bi l i t y in a n y m a nd a to r y Class I Fe d e r a l a r e a , un l e ss it d e monstr a tes th a t an e m i ss i ons tr a ding

p r o g r a m or o t h e r a l t e r n a t i ve will ac hieve g rea t e r r ea sona b l e pr o g r e ss t o w a rd n a tu r a l vis i b i l i t y

c ondi t ions.

A.1 .1 BART Five Factor Determination : 40 CFR 51.308(e)(1)(ii)(A)

ODEQ must make a determination of BART for each BART

- eligible source in Oklahoma that emits

any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of

visibility in any mandatory Class I Federal area. All such sources are subject to BART. The

determination of BART must be based on an analysis of the best system of continuous emission

control technology available and associated emission reductions achievable for each BART

- eligible

source that is subject to BART within the State. In this analysis, Oklahoma must take into

consideration the technology available, the costs of compliance, the energy and non

- air quality

environmental impacts of compliance, any pollution control equipment in use at the source, the

remaining useful life of the source, and the degree of improvement in visibility wh ich may

reasonably be anticipated to result from the use of such technology.

State Submittal

Pages, 5

- 10 , Appendix II

.

The AEP/PSO Northeastern Power Station is located in Rogers County, Oklahoma. Units 3 and 4

are each 490 MW coal

- fired steam electric generating units.

ODEQ’s Five Factor S O 2 BART Analysis

In assessing BART, ODEQ used the BART determination process described in the BART Guidelines

in Appendix Y of 40 CFR Part 51, which are required to be followed for fossil

- fuel

- fired generating

plants having a total generating capacity in excess of 750 MW. The BART determination process

described in Appendix Y includes the following steps:

• Step 1. Identify All Available Retrofit Control Technologies.

• Step 2. Elimi nate Technically Infeasible Options.

• Step 3. Evaluate Control Effectiveness of Remaining Control Technologies.

• Step 4. Evaluate Impacts and Document the Results.

• Step 5. Evaluate Visibility Impacts.

ODEQ summarizes the baseline control technologies and emissions for Units 3 and 4 as Table

II

- 1 of its SIP, which is reproduced below:7 Baseline Emissions (2004

- 2006)

Unit 3 Unit 4

Design Heat Input to Boiler 4,775 MMBtu/hr 4,775 MMBtu/hr

SO 2 Control Low

- Sulfur Coal Low

- Sulfur Coal

Emission Rate (lb/MMBtu) 0.9 lb/MMBtu 0.9 lb/MMBtu

Combined Annual Emission Rate 1 31,999 TPY

NOx Control 1st Generation LNB w/ OFA 2 1st Generation LNB w/ OFA 2

Emission Rate (lb/MMBtu) 0.40 lb/MMBtu 0.40 lb/MMBtu

Combined Annual Emission Rate 1 14,222 TPY

PM10 Control Electrostatic precipitator Electrostatic precipitator

Emission Rate (lb/MMBtu) 0.10 lb/MMBtu 0.10 lb/MMBtu

Combined Annual Emission Rate 1 3,555 TPY

1 85% Capacity Factor

2 LNB = Low NOx Burners

OFA = Over

- fired Air

In Step 1, ODEQ reviewed all S O 2 control technologies in its original BART determination and

did not repeat that exercise in this revision

. Regarding Step 2, ODEQ did not identify any

additional technically infeasible options from those it identified in its initial BART evaluati on.

However, ODEQ noted , “ EPA concluded in the FIP that DFGD/SDA satisfied the BART review

requirements; therefore, no further analysis of Wet Flue Gas Desulfurization is necessary. ” 2 In

Step 3, ODEQ then analyzed Dry Sorbent Injection (DSI) and Dry Flue Gas Desulfurization

Spray Dryer Absorber (DFGD/SDA , or “dry scrubber” ) technolog ies

. ODEQ concluded

assuming a baseline emission rate of 0.9 lb/MMBtu on a rolling 30

- day average basis that DSI

and DFGD/SDA were capable of achieving S O 2 emission rates of 0.40 and 0.06 lb/MMBtu (as

rolling 30

- day averages) , respectively. Under Step 4, ODEQ did not identify any significant

economic, environmental, and energy impacts associated with t he two proposed control options.

In evaluating cost, OD EQ stated that in general it followed EPA Air Pollution Control Cost

Manual, Sixth Edition (“the Manual”). ODEQ based t he capital and operating costs of the DSI

control option on the Manual except as listed below:

• Purchased Equipment Costs

, Site Preparat ion Costs , and Building Costs were based on an

approximate six

- month, site

- specific, feasibility and conceptual engineering and design effort

that resulted in a Class 4 AACE category budgetary estimate.

• Operating Labor Costs

, Maintenance Labor Costs , and Other Direct Operating Costs (e.g.,

for sorbent usage, electricity, and bag and cage replacement) were based on an evaluation of

annual operating and maintenance cost project impact as part of the above

- mentioned

feasibility and conceptual design effort.

• The Indirect Operating Costs of Overhead

, Property Tax , and Insurance were based on the

same calculation methodologies presented in our Technical Support Document (TSD)

published with the RH FIP. These methodologies deviate from the Manual but were used for

the purpose of consistency with the FIP 3

.

2 Although we agree with the end result of this statement, some clarification is in order. In our FIP we analyzed

both dry and wet scrubbers. We determined that SO 2 emission rates of 0.06 and 0.04 lb /MMBtu , based on a

rolling boiler

- operating

- day average, were appropriate for dry and wet scrubbers, respectively. We concluded that

the additional cost of wet scrubbers was not worth the additional visibility benefit f rom them, so based our FIP

emission rate of 0.06 lb /MMBtu on dry scrubbers.

3 In our FIP, as directed by the RH rule, we took into account, “ any site

- specific design or other conditions8 The capital recovery factor used to estimate the annual cost of control of the DFGD/SDA option

was based on a 7% interest rate and a control life of 30 years. Annual operating costs and annual

emission reduc tions were calculated assuming a capacity factor of 85%

. The capital costs for the

DSI option were annualized over a 10

- year period and then added to the annual operating costs to

obtain the total annualized costs. ODEQ used a n equipment life of 10 years because the controls

will only be in operation from 2016 to 2026, when the unit will be shut down. ODEQ notes the

capacity factor will decrease over the 10 year period , beginning in 2021 . However, the cost

analyses are based on an 85% capacity factor to be consistent with baseline actual capacity usage

and with all previous evaluations. ODEQ summarizes the cost effectiveness of the DSI and

DFGD/SDA in Table 8 of Appendix II, which is reproduced below:

Baseline DSI DFGD/SDA

SO 2 Emission Rate (lb/MMBtu) 0.9 0.4 0.06

Annual SO 2 Emission (TPY) 1 31,999 7,111 2,880

Annual SO 2 Reduction (TPY) 24,888 29,119

Total Annual Cost ($) $25,008,306 $44,969,595

Cost per Ton of Reduction $1,005/ton $1,544/ton

1 Baseline annual emissions were averaged based on annual emissions from

2004

- 2006. Projected annual emissions for DFGD/SDA option were

calculated based on the controlled SO 2 emissions rate (a 91% reduction from

the baseline). Projected annual emissions for DSI option were calcul ated

based on the controlled SO 2 emissions rate, full load heat input of 4,775

MMBtu/hr (30

- day rolling average) , and assuming a 85% capacity factor.

Having calculated the cost effectiveness of installing DSI versus dry scrubbers, ODEQ contrasts it

with AEP/PSO’s proposed S O 2 BART determination as reflected in the settlement agreement. The

settlement agreement requires the following for S O 2 control :

• Beginning on January 31, 2014, Units 3 and 4 will achieve a S O 2 emission rate of 0.65

lb/MMBtu on a 30

- day rolling average, and beginning on December 31, 2014, Units 3 and

4 will achieve a S O 2 emission limit of 0.60 lb/MMBtu on a 12

- month rolling average.

• Either Unit 3 or 4 will be shut down by April 16, 2016.

• DSI will be installed and operated on the remaining unit to meet an emission rate of 0.40

lb/MMB tu or less from April 16, 2016 to December 31, 2026

.

• During the first year of operation of the controls, AEP/PSO will develop and propose a

monitoring program to determine if additional S O 2 reductions can be achieved.

• Beginning in calendar year 20 2 1, the a nnual c apacity f actor for the remaining unit will be

reduced to no more than 70 percent in 2021 and 2022; 60 percent in 2023 and 2024; and 50

percent in 2025 and 2026.

• The remaining unit will be shut down no later than December 31, 2026.

ODEQ analyzed the fifth step in the BART analysis using the C ALPUFF modeling system.

identified above that affect the cost of a par ticular BART technology option.” 70 FR 39166.9 ODEQ’s S O 2 BART Modeling Analysis

The fifth step for a BART determination analysis, as required by 40 C.F.R. Part 51, Appendix Y, is

to evaluate the degree of Class I area visibility improvement that would result from the installation

of the various options for control technology. AEP/PSO submitted a modeling protocol to ODEQ

October 3, 2012 and a modeling analysis , in November 2012, for the Northeastern Units 3 and 4

that used the CALPUFF modeling system to predict the change s in Class I area visibility due to the

different control levels evaluated in November 2012

. The updated modeling analyses report and

modeling protocol are included in Oklahoma Regional Haze SIP as Appendices 5A&5B and 5C

respectively. The modeling files supporting the updated mode ling analyses are also include in the

available materials upon request from ODEQ or EPA Region 6 (The files are too large to post on a

website or on EPA’s Federal Docket Management System ) . We are providing a real brief summary

of pertinent information fo r our review.

The modeling analysis evaluated impacts at four Class I areas ( Wichita Mountain Wildlife Refuge,

Caney Creek, Upper Buffalo and Hercules Glade s)

. AEP/PSO evaluated three SO 2 scenarios. They

modeled Baseline emissions, the proposed SO 2 limit of 0.4 lb/MMB tu with one unit shutdown, and

the DFGD FIP SO 2 emission level of 0.06 lb/MMB tu

. They also included the pre

- BART level NOx

emission rates in the baseline and did a scenario based on the original RH sip assumptions of 0.15

lb/ MM Btu for NOx and SO 2 emission rates for AEP’s boilers #3 and #4. AEP/PSO modeled NOx

and SOx species but did not model PM2.5 species (primary PM2.5, VOCs, elemental Carbon, etc.).

The emission rates and the lb/ MM Btu were summarized by ODEQ in Table 9 of A ppendix II , which

is reproduced on the next page :10 Parameter Northeastern Unit 3 Northeastern Unit 4

Plant Configuration Coal

- Fired Boiler Coal

- Fired Boiler

Firing Configuration Tangentially

- fired Tangentially

- fired

Gross Output (nominal) 490 MW 490 MW

Design Input to Boiler 4,775 MM Btu/hr 4,775 MM Btu/hr

Maximum 24

- hour Average Input 5,812 MM Btu/hr 5,594 MM Btu/hr

Primary Fuel Sub

- bituminous coal Sub

- bituminous coal

Existing NO X Controls 1 st Generation LNB/OFA 1 st Generation LNB/OFA

Existing PM 10 Controls Electrostatic precipitator Electrostatic precipitator

Existing SO 2 Controls Low

- sulfur coal Low

- sulfur coal

Baseline Emissions

Unit 3 Unit 4

lb/hr lb/ MM Btu lb/hr lb/ MM Btu

NO X 3,116 0.536 2,747 0.491

SO 2 6,126 1.054 5,930 1.06

SIP Approved Emissions (Max 24

- hour)

lb/hr lb/ MM Btu lb/hr lb/ MM Btu

NO X 872 0.15 839 0. 15

Unit 4 Shut Down/Unit 3 NO X Controlled, SO 2 Baseline (Max 24

- hour)

lb/hr lb/ MM Btu lb/hr lb/ MM Btu

NO X 872 0. 15

- -

SO 2 6,126 1.054

- -

Unit 4 Shut Down/Unit 3 NO X Controlled, SO 2 DSI Control (Max 24

- hour)

NO X 872 0.15

- -

SO 2 2,325 0.4

- -11 AEP/PSO performed the CALPUFF modeling with the following versions of programs that make up

the CALPUFF System:

P ro g r a m V e rsion L e v e l

C A L MET 5.53a 040716

C A L P UFF 5.8 070623

POSTUTIL 1.52 060412

C A L P OST 6.221 080724

AEP/PSO used the same CALMET files that were previously used in the earlier Oklahoma Regional

Haze SIPs and our FIP . AEP/PSO did perform additional CALPUFF, POSTUTIL, and CALPOST

modeling in performing the new modeling analysis. The source parameters were summarized by

ODEQ in Table 11 of A ppendix II , which is reproduced below:

Parameter Baseline 1

Coal

- Fired

Unit 3 Coal

- Fired

Unit 4

Heat Input ( MM Btu/hr) 5,812 5,594

Stack Height (m) 183 183

Stack Diameter (m) 8.23 8.23

Stack Temperature (K) 424 415

Exit Velocity (m/s) 18.97 17.46

Baseline SO 2 Emissions (lb/ MM Btu) 1.054 1.060

Dry Sorbent Injection 0.4

-

Baseline NO X Emissions (lb/ MM Btu) 0.536 0.491

LNB/OFA NO X Emissions (lb/ MM Btu) 0.15

-

1 Baseline emissions data were provided by AEP/PSO . Baseline emission rates (lb/ MM Btu) were calculated by dividing the

maximum 24

- hr lb/hr emission rate by the maximum heat input to the boiler at that emission rate.12 AEP/PSO calculated visibility impacts using Method 8 in the CALPOST processing. ODEQ

summarized the final visibility modeling results in Table s 12 and 13 of A ppendix II , which is

reproduced below:

Class I Area 2001 2002 2003 3

- Year Average

98 th

Percentile Value

(Δdv) 98 th

Percentile Value

(Δdv) 98 th

Percentile Value

(Δdv) 98 th

Percentile Value

(Δdv)

Baseline

Wichita Mountains 1.228 1.339 1.937 1.501

Caney Creek 1.927 1.290 1.664 1.627

Upper Buffalo 1.389 0.938 1.180 1.169

Hercules Glade 1.179 0.867 1.291 1.112

Unit 4 Shut Down and DSI on Unit 3 (NO X Baseline)

Wichita Mountains 0.417 0.356 0.618 0.464

Caney Creek 0.637 0.439 0.584 0.553

Upper Buffalo 0.534 0.293 0.379 0.402

Hercules Glade 0.408 0.291 0.298 0.332

Unit 4 Shut Down and DSI/LNB/OFA on Unit 3

Wichita Mountains 0.241 0.271 0.372 0.295

Caney Creek 0.346 0.240 0.297 0.294

Upper Buffalo 0.247 0.172 0.231 0.216

Hercules Glade 0.213 0.170 0.246 0.20913 Class I Area 2001 2002 2003 3

- Year Average

98 th

Percentile Value

(Δdv) 98 th

Percentile Value

(Δdv) 98 th

Percentile Value

(Δdv) 98 th

Percentile Value

(Δdv)

EPA FIP

– DFGD/SDA Units 3 and 4

Wichita Mountains 0.187 0.163 0.257 0.202

Caney Creek 0.227 0.196 0.252 0.225

Upper Buffalo 0.238 0.129 0.139 0.169

Hercules Glade 0.197 0.129 0.119 0.148

ODEQ indicated that a DFGD/SDA solution would provide improvements in visibility above that

achieved with a DSI system. ODEQ summarized the results that t he FIP scenario would result in

improvements of approximately 0.1dv over individual Class I areas and an average total

improvement of 0.27 across the four nearest Class I areas during the time of control implementation

(by end of 2017)

. ODEQ concluded that factoring in the fu ll settlement agreement, these

incremental reductions in emissions of SO 2 do not result in a perceptible improvement in visibility

either on an individual Class I area basis or a cumulative Class I area basis.

ODEQ’s S O 2 BART Determination

ODEQ notes that i n general, BART is considered to be a unit

- by

- unit evaluation. However, in

order to more accurately compare the environmental benefits of one solution versus another,

ODEQ contrasts the settlement agreement control strategy through the BART timeframe against the

FIP scenario through the same time period.

As noted above, ODEQ calculated t he cost effectiveness in dollars per ton of SO 2 removed for DSI

as used in the settlement agreement to be $1,005 per ton, and for the level of S O 2 control required

in our FIP to be $1,544 per ton , with projected level s of emission reductions of 24,888 tons per year

and 29,119 tons per year, respectively . Therefore , the incremental cost effectiveness of the FIP

scenario is $4,718 per ton in the first year . ODEQ notes that this incremental cost effectiveness will

worsen with decreased capacity utilization under the settlement agreement

. ODEQ states that in

comparison to the settlement agreement, t he FIP would result in imperceptibly greater

improvements of approximately 0.1 dv over individual Class I areas and an average total

improvement of 0.27 dv across the four nearest Class I areas during the time of control

implementation.

In addition, ODEQ notes t hat t he settlement agreement requires the shutdown of either

Northeastern Unit 3 or 4, and therefore the removal of NO x

, SO 2 , PM, and CO 2 e emissions from

that unit. These reductions will help to address local formation and interstate transport of ozone

and reduce the contribution to greenhouse gases and mercury deposition from electricity generation

in Oklahoma. In contrast, t he FIP scenario provides no further impro vement in ozone and ODEQ

projects it would likely assure continued use of coal

- fired electricity generation for an additional 20

years beyond the settlement agreement scenario. ODEQ also states that the settlement agreement14 scenario, while achieving perce ptively equivalent visibility improvements at the Class I areas, will

not require water usage and in shutting down one of the two Northeastern Unit s rather than

installing additional controls, energy consumption is half that of the control solution establi shed by

the FIP.

ODEQ concludes that g iven the comparable visibility improvement, lower costs, and overall

reduced environmental impact, the scenario described in the settlement agreement constitutes

BART.

EPA Findings

Additional EPA Cost Effectiveness Analyses

We note that in performing its S O 2 BART analysis, ODEQ assumes a S O 2 baseline that is

constructed on the basis of an emission limit of 0.9 lb/MMBtu. Although we believe that baseline

was appropriate at the time ODEQ submitted its SIP and during our analysis and FIP, we believe it

is no longer representative . Since the FI P, additional monitoring data has been acquired that

indicates Units 3 and 4 are emitting well below this level 4

. In fact, the annual S O 2 emission

averages for units 3 and 4 have been well below 0.60 lb/MMBtu in both 2011 and 2012. Also, as

described elsewhere, AEP/PSO has entered into a settlement agreement with us and ODEQ that

requires that b eginning on January 31, 2014, Units 3 and 4 will achieve a SO 2 emission rate of 0.65

lb/MMBtu on a 30

- day rolling average, and beginning on Decembe r 31, 2014, Units 3 and 4 will

achieve a SO 2 emission limit of 0.60 lb/MMBtu on a 12

- month rolling average. We therefore

propose that it is appropriate the S O 2 baseline be based on an emission limit of 0.60 lb/MMBtu.

In addition, although we believe th at ODEQ makes several good points regarding some potential

advantages of the settlement, ODEQ’s basic approach consist s of comparing the cost effectiveness

of the DSI based settlement control to the dry scrubber based FIP control. We believe it is more

appropriate to approach the analysis by using the settlement shut down schedules for Units 3 and 4

as the starting point, and then analyzing whether DSI or dry scrubbers are the more cost effective

interim S O 2 control. In other words, we believe it is appropriate to analyze both potential S O 2

control s for the remaining unit on the basis of a 10 year life ( approximated on the basis of the April

16, 2016 to December 31, 2026 DSI installation and shut down schedules), in order to determine

whether the incremental cost increase of dry scrubbers over DSI is cost effective in relation to the

additional visibility improvement.

We have therefore revised our FIP cost evaluation f or dry scrubbing to incorporate a revised S O 2

baseline based on an emission rate of 0.60 lb/MMBtu for one unit and a 10 year life. In so doing,

we have retained the same heat input of 4,775 MMBtu/hr and 85% capacity factor as ODEQ. 5 Th e

revised spreadsheet containing this analysis is contained in the docket and a summary of th is

information is presented be l ow in Table 1 :

4 See file, “AEP

- PSO Monthly Emissions Units 3

- 4.xlsx,” which was downloaded from the CAMD Air Markets

Program Data website, available at: http://ampd.epa.gov/ampd/

5 Baseline = (0.60 lb /MMBtu X 4,775 MMBtu/hr X 8760 hrs/yr X 0.85 capacity / 2000 lb /ton) X 2 units = 21,333

tons S O 2 /yr.

Note that in ODEQ’s cost effectiveness analyses, the baseline and the capital costs for both DSI and dry scrubbers

are based on the totals for two units. This is fine, as the calculation of the cost per ton removed divides the total

annual cost for both units by the total tons removed for both units, making the resulting figure applicable to either

unit singly. We used the same approach to allow for an e asier comparison.15 Table 1

– Revised Dry Scrubber Cost Effectiveness

Revised Cost Effectiveness Analysis for

Flue Gas Desulfurization at

Northeastern Units 3 & 4

FIP EPA Notes

CAPITAL COST SUMMARY

Purchased Equipment Cost (PEC) 547,080,000 249,100,000 These costs are for both units

Landfill Construction 25,000,000 25,000,000

TOTAL CAPITAL INVESTMENT (TCI) 572,080,000 274,100,000

ANNUAL COST SUMMARY

DIRECT OPERATING COST

Lime Injection 6,178,600 6,178,600

Operating Electricity 3,022,200 3,022,200

Water 423,100

FGD Waste Disposal 479,988

Bag & Cage Replacement 572,000

Fixed O&M 4,116,350

TOTAL DIRECT COST (DC) 9,200,800 14,792,238

INDIRECT OPERATING COSTS

Administrative Charges (2% TCI) 11,441,600 5,482,000

Insurance (1% TCI) 5,720,800 28,781

Property Taxes (1% TCI) 5,720,800 2,329,850

Capital Recovery (CRF X TCI) 58,267,612 39,025,673

TOTAL INDIRECT COST (IC) 81,150,812 46,866,304

TOTAL ANNUALIZED COST (DC+IC) 90,351,612 61,658,542

COST EFFECTIVENESS SUMMARY

Annual Control Cost 90,351,612 61,658,542

SO 2 to be Removed (ton/yr) 26,559 19,200 Tonnage removed is for both units

COST EFFECTIVENESS ($/ton) 3,402 3,211 Cost effectiveness applies to both

units or either unit16 INPUTS

DFGD Capital Cost ($/kW) 582 265

Net Rating (MW) 940 940

Landfill costs estimated by AEP ($) 25,000,000 25,000,000

Estimated Lime Usage (ton/yr) 30,893 30,893

Lime Cost ($/ton) 200 200

Estimated Electricity Usage (kW/hr) 6,900 6,900

Cost of Electricity ($/kW) 0.05 0.05

SO 2 Removal Rate 0.83 0.90 Changed from 91% control to 90%

control (0.6 to 0.06 lb/MMBtu)

Water (gal/MMBtu) 4.25

Water Cost ($1.40/1000 gal) 1.40

Solids Generated (lb solids/lb SO 2 ) 5

Solids Disposal Cost ($/ton) 5

Baseline emissions (lb SO 2 /MMBtu) 0.90 0.60 Baseline emissions changed from

0.90 to 0.60 lb/MMBtu to reflect

current data and settlement

agreement

Annual Average Firing Rate (MMBtu/hr) 4,775 4,775

Capacity Factor 0.85 0.85

Capital Recovery Factor 0.1019 0.1424

Interest Rate 0.08 0.07

Scrubber Lifetime (yr) 20 10.00 Revised to 10 years

In addition to revising the scrubber lifetime and the SO 2 baseline , we also revised the S O 2 removal

rate

. At the time we constructed our FIP, we noted that dry scrubber s were capable of 95% control.

However, we also noted that in the SIP t he capital and O&M costs for the Northeastern units were

scaled from capital costs and utility demands for the OG&E Sooner and Muskogee scrubbers, which

were based on 91% S O 2 control. We chose to carry that 91% control forward in our FIP cost

evaluation for the AEP/PSO facility as it did not alter our conclusion regarding cost effectiveness

and was expedient to do so . Here, realizing that 91% control from a baseline emission rate of 0.60

would result in a controlled level below what we found to be achievable in our FIP (0.06

lb/MMBtu), we reduce the level of control to 90% , which results in a controlled emis sion rate of

0.06 lb/MMBtu.

W e therefore propose to find that recalculating as described above

, a more appropriate cost

effectiveness calculation for dry scrubbers is $3,211/ton, as opposed to t he $1,544/ton ODEQ

calculated.

We have found the capital cos ts for DSI to be acceptable. However, because ODEQ used the same

S O 2 baseline in its DSI cost analysis, we must similarly adjust ODEQ’s DSI cost per ton calculation

to compensate for the revised S O 2 baseline. We therefore accept ODEQ’s DSI total annual cost of

$25,008,306 and annual S O 2 emissions of 7,111 tons, but recalculate the tons removed to be 21,333

– 7,111 = 14,222 . This results in a revised cost effectiveness calculation of $25,008,306 / 14,222 = $1,758/ton. Table 2 summarizes this information below:17 Table 2

– Summary of R evised DSI and Dry Scrubber Cost Effectiveness

ODEQ EPA

S O 2 Baseline (tons/yr) 31,999 21,333

Dry Scrubber Tons Removed 29,119 19,200

Dry Scrubber cost effectiveness $1,544/ton $3,211/ton

DSI Tons Removed 24,888 14,222

DSI cost effectiveness $1,005/ton $1,758/ton

As shown above, when the cost effectiveness is re calculated based on a 10 year operating life for

both DSI and dry scrubbers, the cost effectiveness of dry scrubbers becomes less attractive. The

incremental cost effectiveness of dry scrubbers is $ 7

, 362 /ton when compared to DSI based on

EPA’s recalculation.

We note this analysis assumes a SO 2 emission rate for DSI of 0.40 lb/MMBtu, based on a 30 day

average. The settlement agreement requires that AEP/PSO “develop and propose a monitoring

program to test various operating profiles and other measures, to determine whether increased SO 2

removal efficiencies can be achieved during normal operations.”

Additional EPA Modeling Analyses

AEP/PSO’s modeling did not include PM or VOC species in any of the runs. While we would have

typically included these species, they end up having a similar add

- on to the estimated visibility

impairment on all the modeling scenarios if they were modeled. Therefore, for the purpose of

evaluating potential visibility improvements due to the different SO 2 control levels, the change in

impact is expected to be the same in magnitude as would be observed with these pollutants added to

the CALPUFF modeling. Our review of the modeling information did not raise any other concerns

with the actual modeling.

ODEQ’s analysis of modeling included data on the different scenarios (baseline, DSI and shutdown,

and FIP). To assist in evaluating the analysis we created the following Tables that indicate the

difference due to SO 2 control in the FIP and due to the new BART determination utilizing DSI on

Unit#3 and Shutdown of Unit #4 (for the sake of this exercise, we assumed that Unit #4 would be

shut down and that Unit #3 would receive the additional DSI controls; because the two units are

identical, the decision on which unit to shut down in 2016 will be left to AEP/PSO)

.18 Table 3

– ODEQ’s Baseline M inus the FIP SO 2 Control B enefit

Class I

Area 2001 2002 2003 3

- Year

Average

98 th 98 th 98 th 98 th

Percentile

Value Percentile

Value Percentile

Value Percentile

Value

(Δdv) (Δdv) (Δdv) (Δdv)

ODEQ

- AEP/PSO Baseline

- FIP (DSGD w/SDA)

Wichita

Mountains

1.041 1.176 1.68 1.299

Caney

Creek 1.7 1.094 1.412 1.402

Upper

Buffalo 1.151 0.809 1.041 1

Hercules

Glade 0.982 0.738 1.172 0.964

TOTAL 4.874 3.817 5.305 4.665

Ta ble 4

– ODEQ’s Baseline M inus ODEQ's R evi sed BART (Unit #3 DSI, Unit #4 Shutd own)

Class I

Area 2001 2002 2003 3

- Year

Average

98 th 98 th 98 th 98 th

Percentile

Value Percentile

Value Percentile

Value Percentile

Value

(Δdv) (Δdv) (Δdv) (Δdv)

ODEQ

- AEP/PSO Baseline

- ODEQ's revised BART (Unit #3

DSI, Unit #4 shut down)

Wichita

Mountains

0.987 1.068 1.565 1.206

Caney

Creek 1.581 1.05 1.367 1.333

Upper

Buffalo 1.142 0.766 0.949 0.953

Hercules

Glade 0.966 0.697 1.045 0.903

TOTAL 4.676 3.581 4.926 4.39519 ODEQ indicated that the FIP scenario would result in trivial visibility improvements of

approximately 0.1 dv above that of the proposed strategy over individual Class I areas and an

average total improvement of 0.27 dv across the four nearest Class I areas during the time of c ontrol

implementation. The difference between the 3 year average values for the sum of the four Class I

area impacts is 4.665 dv

– 4.395 dv, which confirms the 0.27 dv value ODEQ indicated.

ODEQ discussed this difference between DFGD controls and DSI cont rols (approx. 0.1 dv at a

Class I area and 0.27 dv average cumulative difference) as not perceptible or significant and

elsewhere as trivial. While less than 1 deciview may be referred to as ‘not perceptible’ in general,

smaller differences are still important to estimate and can be weighed considering other pertinent

issues. We agree that the levels are small and below the ‘cause’ or ‘contrib ute’ levels, but we do not

consider them ‘trivial’. In the preamble to EPA’s BART Guidelines, “ [e]ven though the visibility

improvement from an individual source may not be perceptible, it should still be considered in

setting BART because the contributi ons to haze may be significant relative to other source

contr ibutions in the Class I areas.” Overall, the Regional Haze process envisions reductions that are

both ‘perceptible’ and ‘not perceptible’ will be necessary as part of the overall path to obtain the

necessary reductions to meet the Regional Haze goals.

We note that for baseline NOx emissions the maximum 24

- hour lb/MMBtu emission rate was used

and for the controlled levels a 30

- day average emission rate level was used. This mix of 24

- Hour

maximum emission rate for the baseline and the 30

- day average emission rate level tends to slightly

overestimate the actual baseline to controlled level benefits. This does give a relative analysis as the

same baseline is used in both NOx control levels of 0.23 lb/MMBtu and 0.15 lb/MMBtu emission

rates.

We note that for baseline SO 2 emissions the maximum 24

- Hour lb/MMBtu emission rate was used

and for the controlled levels a 30

- day average emission rate level was used. This mix of 24

- Hour

maximum emission rate for the baseline and the 30

- day average emission rate level tends to slightly

overestimate the actual baseline to controlled level benefits. This does give a relative analysis as the

baseline is used in both SO 2 control levels of 0.4 lb/MMBtu and 0.06 lb/ MMBtu emission rates. In

the case of the SO 2 baseline, the maximum emission rates were based on 1.054 and 1.06 lb/MMBtu

for Units #3 and #4 respectively. This is higher than the 0.9 lb/MMBtu used in the cost analysis

calculations for baseline. Furthermor e, as discussed in the cost analysis section, an alternate

baseline using 0.6 lb/MMBtu for SO 2 emissions would also be appropriate for consideration.

Utilizing the existing modeling and assuming a linear nature to the benefits of SO 2 reduction we can

esti mate a revised baseline using the 0.6 lb/MMBtu SO 2 emission rate for Units #3 and #4. Based

on some of the modeling included in previous Oklahoma and EPA actions this appears to be a

reasonable assumption. In this analysis, we are using the baseline mode ling that used the higher

emission rates (1.054 and 1.06 lb of SO 2 /MMBtu) and the FIP modeling with 0.06 lb of

SO 2 /MMBtu for Units #3 and #4 and extrapolating the amount of visibility impairment for the

alternate baseline scenario.20 Table 5

– Estimated A lternate Baseline Impairment for 0.6 lb of SO 2 /MMBtu for Units #3 and #4.

Class I

Area 2001 2002 2003 3

- Year

Average

98 th 98 th 98 th 98 th

Percentile

Value Percentile

Value Percentile

Value Percentile

Value

(Δdv) (Δdv) (Δdv) (Δdv)

Alternate Baseline (0.6 lb/MMBtu SO 2 )

Wichita

Mountains 0.56 0.64 0.91 0.70

Caney

Creek 0.92 0.59 0.76 0.76

Upper

Buffalo 0.62 0.44 0.56 0.54

Hercules

Glade 0.42 0.31 0.54 0.42

TOTAL 2.53 1.98 2.78 2.43

Based on this alternate baseline we can now estimate the difference between the alternate baseline

and the two options of FIP and Revised BART.

Table 6

- Revised Baseline M inus the FIP SO 2 Control B enefit

Class I

Area 2001 2002 2003 3

- Year

Average

98th 98th 98th 98th

Percentile

Value Percentile

Value Percentile

Value Percentile

Value

(Δdv) (Δdv) (Δdv) (Δdv)

Alternate Baseline (0.6 lb/MMBtu SO 2 )

- FIP (DSGD w/SDA)

Wichita

Mountains 0.38 0.47 0.65 0.50

Caney

Creek 0.69 0.40 0.51 0.53

Upper

Buffalo 0.39 0.31 0.42 0.37

Hercules

Glade 0.22 0.18 0.42 0.27

TOTAL 1.68 1.36 2.01 1.6821 Table 7

- Revised Baseline M inus ODEQ's R evi sed BART (Unit #3 DSI, Unit #4 Shut down)

Class I

Area 2001 2002 2003 3

- Year

Average

98th 98th 98th 98th

Percentile

Value Percentile

Value Percentile

Value Percentile

Value

(Δdv) (Δdv) (Δdv) (Δdv)

Alternate Baseline (0.6 lb/MMBtu SO 2 )

- ODEQ's revised

BART (Unit #3 DSI, Unit #4 shut down)

Wichita

Mountains 0.32 0.37 0.54 0.41

Caney

Creek 0.57 0.35 0.47 0.47

Upper

Buffalo 0.38 0.27 0.33 0.33

Hercules

Glade 0.20 0.14 0.29 0.21

TOTAL 1.48 1.13 1.63 1.41

Both of these comparisons also include the benefits of the NOx controls and the respective SO 2 controls. As can be seen in comparing Tables 6 and 7, the differences in the average impacts at

each Class I are still 0.1 or less and the cumulative average is 0.27 dv (1.68 dv

- 1.41 dv). The

additional controls from the FIP only net approximately 20% more net visibility impairment benefit

for a much larger cost and do not consider the other benefits of the limited life with shutdown in

2026 which should net more overall benefit on the Reasonable Progress Goals at the four Class I

areas eventually.

O DEQ assessed the cost effectiveness of the two scenarios in the Revised BART determination.

They concluded that these small improvements would be achieved at a much greater cost.

In Table 8 below the results are summarized and improvement results from the new baseline are

also included for a scenario estimated for one unit operating with a Dry Scrubber and one unit

shutdown . This is included for comparison purposes with the one unit operating with DSI. It is

based on the one unit having half the impairment of the FIP scenario. This scenario shows that

there are somewhat significant visibility improvements over one unit operating with DSI. The

maximum visibility benefit is 0.19 at Wichita Mountains and 0.6 4 cumulatively. It should be noted

that this scenario was not presented by the State and if the company were to invest in a Dry

Scrubber, it likely would want to operate the scrubber much longer than 10 years and the visibility

benefits of the second unit shutdown would not be realized.22 Ta ble 8

– Summary of Results with Revised Baseline

Baseline

Average

Impairment Improvement

Shutdown

and DSI 2 Dry

Scrubber

Improvement Shutdown

and Scrubber

Improvement

(Δdv) (Δdv) (Δdv) (Δdv)

Wichita

Mountains 0.70 0.41 0.50 0.6

Caney

Creek 0.76 0.47 0.53 0.6 5

Upper

Buffalo 0.54 0.33 0.37 0.4 6

Hercules

Glade 0.42 0.27 0.27 0.3 5

TOTAL 2.43 1.41 1.68 2.0 6

Overall, in looking both at ODEQ’s analysis and the alternate baseline analysis, it can be

determined that only a small percentage improvement in visibility impairment (compared to

DSI/Shutdown option) would be gained by the FIP but the costs are significantly higher and would

also result in more impairment in the long run

. Furthermore, a Dry Scrubber on the remaining unit

would cost significantly more and while it would achieve somewhat more visibility benefit, we

would agree that the State’s decision not to require it is reasonable considering the long term

benefits of the Regional Haze Agreement.

We note that the modeling files sup porting this analysis and SIP submittal are very large (over 1

Terabyte). EPA is not able to load these on an ftp or web site due to their size, but we will copy

the files onto a hard drive if someone would like the files to review. Please contact either Erik

Snyder ( snyder.erik@epa.gov or 214

- 665

- 7305) or Michael Feldman ( feldman.michael@epa.gov

or 214

- 665

- 9793) for arrangements on what size portable hard drive t h e r e q u e s t o r will nee d to

provide, where to ship the drive and what files are desired.

EPA Cost Effectiveness Conclusions

We propose to find that our revised cost analysis has confirmed that ODEQ has adequately

addressed the requirements in section 51.308(e)(1)(ii)(A)

.

A.1.2. BART for Larger Fossil Fuel Power Plants: 40 CFR 51.308(e)(1)(ii)(B )

A d e te r m i n a t i on of B A R T is r e quir e d f o r e a c h BA RT

- e l i g ib l e sou r c e in O klahoma that e m i ts

a n y a ir pollutant whi c h m a y r ea sona b l y be a nt i c ipat e d to c a use o r c ontribute to a n y i m p a ir m e nt

of vis i bi li t y in a n y mand a t o r y Class I Fe d e r a l a re a

. All su c h sour ce s a re sub j ec t t o B ART. T h e

d e te r m i n a t i on of BART f or f oss i l

- fu e l fi r e d pow e r plants h a ving a to t a l g e n e r a t i n g ca p ac i t y

g r ea t e r th a n 750 m e g a w a t t s mu s t be m a de pursu a n t t o the g uidelines in ap p e ndix Y of th i s pa r t

( G uidelines f or B ART D e te r m i n a t i ons und e r the R e g ional H a z e Rule )

.23 S ta t e Sub m it t al

Appendix II

The AEP/PSO Northeastern Units 3 and 4 are located at a fos s i l

- fuel f i r e d steam e le c tr i c

g e n e rat i ng plan t s wi t h h e at i npu t s g r e ater than 25 0

- MM Btu/ h r, and w i t h a to t al g e n e rat i ng

c apa c i t y in e x ce ss of 750 M W

. O D EQ has s t ated it f ol l o w e d the r e quire me nts i n S ec t i on

51.30 8 ( e ) ( 1 ) ( i i ) ( B) in pr e paring the BA R T d e ter m ina t ions f or the s e facil i t i e s

.

EPA Findings

We propose to find that ODEQ made its determination of S O 2 BART for Units 3 and 4 pursuant to

the guidelines in appendix Y , as required by 51.308(e)(1)(ii)(B)

. ODEQ evaluated the visibility

impacts and the costs of controls. As described above, we believe the costs of controls w ere not

estimated as we believe is most appropriate and th ere were difference s in the visibility modeling

from how we believe the modeling w ould best be performed

. However , we believe these difference s

do not change the overall outcome that Oklahoma reached a reasonable conclusion regarding BART

for SO 2 and the FIP is no longer appropriate

.

A.1.3. Installation of BART: 40 CFR 51.308(e)(1)(iv)

– (v)

Each source subject to BART must (1) install and operate BART as expeditiously as practicable, but

in no event later than 5 years after approval of the SIP revision, and (2) maintain the control

equipment required by this subpart and establish procedures to ensure such equipment is

properly operated and maintained.

State Submittal

ODEQ summarizes the implementation of the BART determination as Table II

- 2 of its SIP, which is

reproduced below:24 Preliminary/BART Control Steps (Prior to Unit 4 Shutdown 1 )

By December 31, 2013 Unit 3 Unit 4

NO X Control LNB w/ Separated OFA 2 LNB w/ Separated OFA 2

Emission Rate (lb/MMBtu) 0.23 lb/MMBtu

(30

- day rolling average) 0.23 lb/MMBtu

(30

- day rolling average)

Hourly Emission Rate 1,098 lb/hr

(30

- day rolling average) 1,098 lb/hr

(30

- day rolling average)

Combined Annual Emission Rate 9,620 TPY (12

- month rolling)

By January 31, 2014 Unit 3 Unit 4

SO 2 Control Low Sulfur Coal Low Sulfur Coal

Emission Rate (lb/MMBtu) 0.65 lb/MMBtu 3

(30

- day rolling average) 0.65 lb/MMBtu

(30

- day rolling average)

Hourly Emission Rate 3,104 lb/hr

(30

- day rolling average) 3,104 lb/hr

(30

- day rolling average)

By December 31, 2014 Unit3 Unit 4

SO 2 Control Low Sulfur Coal Low Sulfur Coal

Emission Rate (lb/MMBtu) 0.60 lb/MMBtu

(12

- month rolling average) 0.60 lb/MMBtu

(12

- month rolling average)

Combined Annual Emission Rate 25,097 TPY (12

- month rolling)

BART Control (with Unit 4 Shutdown 1 )

By April 16, 2016 Unit 3 1

SO 2 Control Dry Sorbent Injection (DSI) with Activated Carbon Injection

Emission Rate (lb/MMBtu) 0.4 lb/MMBtu (30

- day rolling average)

Hourly Emission Rate 1,910 lb/hr (30

- day rolling average)

Annual Emission Rate 8,366 TPY

NOx Control LNB w/ Separated OFA (and Further Control System Tuning)

Emission Rate (lb/MMBtu) 0.15 lb/MMBtu (30

- day rolling average)

Hourly Emission Rate 716 lb/hr (30

- day rolling average)

Annual Emission Rate 3,137 TPY

1 For simplicity, the table reflects AEP/PSO’s indication that Unit 4 is the likely unit to be shut down in 2016, but

there is no requirement as to which of the two units is shut down first.

2 LNB = Low NOx Burners

OFA = Over

- fired Air

3 An alternative operating scenario is provided in paragraph 12 of the First Amended Regional Haze Agreeme nt,

Case No. 10

- 025, that addresses potential disruption of coal supplies during the time period from January 31, 2014

through April 16, 2016.

EPA Findings

We propose to find that ODEQ h as d e monstra t e d it has the authori t y and e nforc e able m ec hanisms

in pla c e to ensure e a c h sour c e s u bje c t t o BA R T wi l l ( 1 ) ins t all and op e rate B A RT as

ex p e di t ious l y as practicabl e , but i n no ev e nt l ater than 5 y e ars a f ter appro v al of the S I P r e v is i on,

and ( 2 ) mainta i n the c ontrol equipm e nt required by th i s s u bpart and e stab l ish p r o ce dures to

e nsure su c h e quipm e nt i s properly o p e rated and m ain t aine d

.25 A.2. NOx BART

We previous ly approved ODEQ’s NOx BART emission limit applicable to Units 3 and 4 as 0.15

lb/ MM Btu , based on a 30

- day rolling average

, in our prior Oklahoma SIP/FIP action

. This

determination required compliance within 5 years of the SIP approval , or by January 27, 2017

. In

this action, we are not proposing to re

- evaluate ODEQ’s NO x BART technology determination for

these units. However, we are proposing to approve ODEQ’s determination, as reflected in the

settlement agreement, that an earlier compliance schedule is appropriate

. We propose the

following:

• Units 3 and 4 are required to comply with an initial emission limit of 0.23 lb/MMBtu , based

on a 30

- day rolling average

, beginning on December 31, 2013 until April 16, 2016

. These

NOx reductions will occur earlier than required by our prior Oklahoma SIP/FIP action.

• After April 16, 2016

, either Unit 3 or 4 will be shut down and the remaining unit must

comply with an emission limit of 0.15 lb/MMBtu , based on a 30

- day rolling average. This

is also earlier than required by our prior Oklahoma SIP/FIP action.

Although not modeled, we anticipate t his early implementation schedule will provide additional

improvements in visibility , and will reduce the local formation and transport of ozone.

B

. F e de r al L a n d M a n ag e r Coo r d i n a t ion 40 C F R 51.308 ( i)

Okl a homa must pro v ide the Fe d e r a l L a nd Manag e r w i t h a n oppo r tun i t y f o r c onsultation, in

pe r son a nd a t le a st 60 d a y s p rior to ho l ding a n y publ i c h ea ri n g on a S I P ( or plan r e vis i on) f or

re g ional h a z e re qui r e d b y th i s subpa r t. This co n sul t a t i on must include the oppo r tun i t y f or the

a f

f

e c t e d Fe d e r a l L a nd Manag e rs to dis c uss t h e ir:

(i) Ass e ss m e nt of imp a irm e nt of vis i bi l i t y in a n y m a nd a to r y Class I F e d e r a l a r e a ; and

(ii) R ec om m e nd a t i ons on the d e v e lop m e nt of the r ea s on a ble p r o g r e ss g o a l and on the

d e v e lop m e nt and imp l e ment a t i on of str a t e g ies to a ddr e ss v i sib i l i t y i m p a ir m e nt.

I n d e v e lop i n g a n y S I P ( o r pl a n r e vis i on), Okl a h o ma must include a d e s c r i pt i on of how it

a ddr e ssed a n y c om m e nts pro v ided b y the Fed e r a l L a nd M a n a g e rs.

The S I P ( o r S I P r e vis i on) must pro v ide p r o ce du r e s f or c ont i nuing c onsultation betw ee n

Okl a homa a nd Fe d e r a l L a nd Mana g er (s) on t h e i m plem e ntation of the vis i bi l i t y p r ote c t i on

p r o g r a m r e qu i r e d b y th i s subpa r t, i n c l u ding d e v e lop m e nt and r e view of S I P r e vis i ons a nd 5

- y e a r

p r o g re ss r e p o rts, a nd on the i mp l e ment a t i on of other p rog ra ms h a ving the po t e nt i a l t o c ontribute

to i mpai r ment of vis i bi l i t y in m a nd a to r y Class I Fe d e r a l a r e a s.26 S ta t e Sub m it t al

Pag e s 117

- 119, App e nd ix 1 0

- 2.

Und e r Se c t i on 51.30 8 ( i ) ( 2 ) , the O k lahoma was o b l i gated to pro v ide the Fish and W i l dl i fe

S e r v ice wi t h an opportuni t y for consul t at i on, in p e rson and at least 60 days prior t o hold i ng a

publ i c h e aring on it RH S I

P . In p racti ce , sta t e e n v ironm e ntal ag e n c ies h a v e usually pro v ided all

FLMs

– the F or e st Ser v i c e , the P ark Se r v ic e , and t he Fish and W i l dl i fe S e r v ic e

, c opies of th e ir

RH S I

P

, as the FLMs c o l le c t i ve ly ha v e r e v iewed t h e se RH S I

P s. O D EQ f o l l owed this practice

and s e nt i ts d raft of t h is i mpl e m e nta t ion p l an r ev i s ion t o the f e d e ral l and manag e r sta f f on

March 20

, 2013 and notif i e d the f e d e ral l and manag e r s t aff of t he publ i c h e aring h e ld on May

20

, 2013 . In i ts l e t t e r dat e d April 15, 2013 , transmitt i ng i t s c om me nts, t he Fish and W i l dl i fe

S e r v i c e a ck now l e dg e d ha v ing re c e i v e d O k lahoma ’ s d raft RH S I

P . Likewise, The U.S. Forest

Service acknowledged receiving the draft RH SIP in its letter dated April 30, 2013, transmitting

its comments.

S ec t i on 51.30 8 ( i ) ( 3 ) r e q u ires that O D EQ p rovide i n i ts RH S I

P a d e s c rip t ion of how it addr e ssed

any c om m e nts p r o v ided by the F L

M s. O D EQ h as pro v ided that i nformati o n in App e ndix VII of

i t s RH S I

P.

L ast l y , S ec t i on 51.308 ( i ) ( 4) s p ec i f

ies the RH S I

P must provide pro ce dures for continuing

c onsulta t ion betw ee n the State and Fe d e ral L and M anag e r on the imple me nta t ion of the v is i bi l i ty

prot ec t i on program r e quired by se c t i on 51.308, i n c lud i ng d eve lop m e nt and r ev iew of

imple me nta t ion p l an r ev is i ons and 5

- ye ar progr e s s reports, and on t he imple me nta t ion of other

programs ha v ing t he potential to contribute to i m pairm e nt of v is i bi l i t y in t he mandatory Class I

F

e d e ral a r e as. O D E Q h as s t ipu l ated in i ts RH S I P it wi l l continue to c oo r d i nate and c onsult

wi t h the F L

M s as r e quired by se c t i on 51.30 8 ( i ) ( 4 ). O D EQ states it in t e nds to c onsult t he FLMs

in t he d eve lop m e nt and r ev iew of imple me nta t ion plan r ev is i ons; r ev iew of progress r e ports; and

d eve lop m e nt and i mpl e m e nta t ion of other programs that may c ontr i bute to impairm e nt of

v is i bi l i t y at t he W ichita Mountains and other C l a ss I ar e as.

E P A F i nd i n gs

W e f i nd that O D EQ h as sa t is f ied s ec t i on 51.30 8 ( i )

.