### Technical Support Document **Nebraska Regional Haze Submittal** 

**Prepared by:** Chrissy Wolfersberger Environmental Protection Specialist U. S. Environmental Protection Agency Region 7 **February 2012**



### Table of Contents I. Summary

of Environmental Protection Agency (EPA) action Page 3 II. State regional haze rulemaking Page 3 III. EPA’s evaluation of Nebraska’s State Implementation Plan (SIP) Page 3 a. Id entification of areas Page 3 b. Baseline and natural visibility conditions Page 6 c. Reasonable progress goals (RPG) Page 7 d. Long

- term strategy

(LTS) Page 7 i. Consultation with other States Page 8 1. South Dakota

– Badlands and Wind Cave 2. Colorado

– Rocky

Mountain and Great Sand Dunes 3. Minnesota

– Voyageurs and Boundary Waters 4. Oklahoma

– Wichita Mountains 5. Missouri

– Mingo and Hercules Glades e. Best Available Retrofit Technology (BART) Page 11 i. BART

- eligible sources Page 11 ii. BART

- subject sources Page 13 iii. P articulate M atter (PM) evaluation Page 14 iv. BART determinations Page 14 1. Omaha Public Power District (OPPD)

– Nebraska City Station 2. Nebraska Public Power District (NPPD)

– Gerald Gentleman Station v. BART summary

and enforceability Page 28 f. Monitoring strategy Page 28 g. Emissions inventory Page 29 h. Federal Land Manager (FLM) consultation Page 30 i. SIP revisions and five year progress reports Page 322



### Tables Table 1 State of Nebraska’s contributions to visibility impairment at Class I areas Table 2 South Dakota Uniform Rate of Progress (URP) and RPGs Table 3 Facilities with BART

- eligible units in Nebraska Table 4 BART

- eligible facilities determined not to be subject to BART Table 5 BART

- subject facilities in Nebraska Table 6 NO x control technology effectiveness, NCS Unit 1 Table 7 Cost of NO x control options, NCS Unit 1 Table 8 Visibility

improvement analysis, NCS Unit 1 Table 9 Costs for visibility improvement, NCS Unit 1 Table 10 SO 2 control technology effectiveness, NCS Unit 1 Table 11 Cost of SO 2 control options, NCS Unit 1 Table 12 NO x control technology effectiveness, GGS Units 1 and 2 Table 13 Cost of NO x control options, GGS Units 1 and 2 Table 14 Visibility

analysis, NPPD GGS Units 1 and 2 Table 15 Costs for visibility improvement, GGS Units 1 and 2 Table 16 SO 2 control technology effectiveness, GGS Units 1 and 2 Table 17 Cost of SO 2 c ontrol options, GGS Units 1 and 2 Table 18 Cost of SO 2 control and visibility benefit, GGS Units 1 and 2 Table 19 Range of GGS dry scrubber cost e ffectiveness Table 20 Summary

of BART determinations Table 21 2002 Nebraska emissions Table 22 2018 Nebraska projected emissions 

### Figures Figure 1 Ma

p of the 156 mandatory Class I F ederal areas Figure 2 Geographic area of Regional Planning Organizations 

### Appendices Appendix A EPA’s anal ys is of cost estimates for flue gas desulfurization ( FGD ) at GGS Appendix B GGS emissions Appendix C GGS FGD cost anal ys is spreadsheet3

**I. Summary of EPA’s action**  EPA is proposing a partial approval and a partial disapproval of Nebraska’s S t ate Implementation Plan (SIP) for Regional Haze, received b y EPA on July 13, 2011

. Specifically , we are proposing to disapprove the sulfur dioxide (SO 2 ) best available retrofit t echnology ( BART) determination for Nebraska Public Power Station (NPPD), Gerald Gentleman Station (GGS) , Units 1 and 2. We are proposing to disapprove this BART determination because it do es not comply with our regional haze regulations and guidance . We are al so proposing to disapprove the long term s trategy (LTS) , insofar as i t relies on this deficient BART determination. To correct the deficiencies identified in these proposed disapprovals, we are also proposing a partial Federal Implementation Plan (FIP), relying on the Transport Rule as an alternative to BART for SO 2 emissions from the GGS units. This limited FIP would satisfy the SO 2 BART requirement for these units and remedy the deficiency

in Nebraska’s LTS. EPA is proposing a partial approval on the remaining elements of Nebraska’ regional haze plan, including the BART determinations for Omaha Public Pow er District (OPPD), the NO x BART determination for Gerald G entleman Station Units 1 and 2, emissions inventory , and monitoring strategy , as describe d below.
**II. State regional haze rulemaking**  The Nebraska Department of Environmental Quality (NDEQ) provided public notice of the opportunity

to comment on the regional haze SIP on December 6, 2010, via notice in the Omaha World Herald and on NDEQ’s website. Nebraska also notified the FLMs, and the S tates of Colorado, South Dakota, Missouri, Minnesota, and Oklahoma of the opportunity for comment on the draft SIP

. Nebraska held a public hearing regarding the SIP on January 21, 2011. Comments were received from the State of Colorado, the National Parks Conservation Association (NPCA), EPA Region 7, the FLMs (National Park Service, Fish and Wildlife Service, Forest Service), and the Twin Platte Natural Resource District. These comments and Nebraska’s responses are available in Appendix 3 of the SIP. Specific comments are mentioned throughout this technical support document ( TSD )

. **III. EPA’s evaluation of Nebraska’s**  **State Implementation Plan**

**a. Identification of**  **affected Class I areas**  States are required to identify each Class I area located within the State and each Class I area located outside the State which is affected b y emissions from within the State. Although there are no Class I areas hosted b y the State of Nebraska , the State is still required to identify those Class I areas which may be affected by

emission s from Nebraska sources.4 Figure 1: Map of the 156 mandatory Class I F ederal areas Because the pollutants that lead to regional haze can originate from sources located across broad geographic areas, EPA encouraged the States and Tribes to address visibility impairment from a regional perspective. Five regional planning organizations (RPO s) were developed to address regional haze and related issues. These organizations evaluated technical information to better understand how their States and Tribes impact visibility at Class I areas across the country , and pursued the development of region al strategies to reduce emissions of pollutants leading to regional haze issues. Nebraska participated in the planning efforts of the Central Regional Air Planning Association (CENRAP) . This RPO includes nine states

- Nebraska, Iowa, Oklahoma, Texas, Minnesota, I owa, Missouri, Arkansas, and Louisiana. CENRAP and its contractors provided air quality modeling to the States to help them determine whether sources located within the State can be reasonably expected to cause or contribute to visibility impairment in a Class Iarea. 1 The modeling conducted relied on baseline year (2002) and future planning year (2018) emissions inventories that were prepared with participation from each of the CENRAP states. States relied on these inventories to develop control strategies to meet the visibility improvement goals of the regional haze rule and to develop their SIPs

.

1 A contractor to CENRAP, ENVIRON, completed the data analysis.5 Figure 2 : Geographical area of Regional Planning Organizations The State of Nebraska relied upon the regional modeling work provided by CENRAP for determining the impact that sources within the State might have on Class I areas in the region and beyond. The modeling was based on PM Source Apportionment Technology (PSAT) for the Comprehensive Air Quality Model with extensions (CAMx) photochemical model. A detailed description of this modeling can be found in Chapter 9 and appendix 9.1 and 9.2 of the SIP. This tool was used to estimate Nebraska’s contribution to visibility impairment at the Class I areas in Arkansas, Colorado, Minnesota, Missouri, Oklahoma, Texas, and South Dakota. In EPA’s review of Nebraska’s SIP, we accessed the PSAT tool from the CENRAP website. In attempting to recreate the charts that Nebraska presented in its SIP using the PSAT tool, we came up wi th slightly

different results. The results presented below are from the August 27, 2007 version of th e tool, which are similar, but not identical, to the results presented in the Nebraska SIP. 2 2002 and 2018 figures presented below are PSAT projected results for Nebraska , in terms of absolute extinction

. According to the PSAT modeling, contributions from Nebraska sources for the worst 20% day s were highest at the South Dakota Class I areas. For the 2002 baseline ye ar, Nebraska sources were projected to contribute 7.81% of visibility impairment at Badlands, and 7% at Wind Cave. In 2018, the projected contribution was reduced to 5.89% and 5.24%, respectively

. However, it is critical to understand that the 2018 projections were developed assuming presumptive levels of control on Nebraska BART sources, which ultimately the S tate did not require. For that reason, it

2 The information presented in the SIP was in graphical rather than numerical form, which was difficult to read; in order to evaluate the information, we accessed the PSAT modeling directly.6

is likely that Nebraska sources would have a larger contribution to 2018 visibility impairment than what is presented in table 1

. Nebraska’s contribution to all oth er Class Iareas was considerabl y less, and in no case greater than 1.9%. **Table 1: State of Nebraska’s contribution to visibility impairment at Class I areas**

**State Class I area**  **Class I area total extinction (20%**  **worst days) (1/Mm)**  **Nebraska**

**source contribution**  **(1/Mm) Per**  **centage**

**contribution to visibility**  **impairment from NE sources**  **2002 2018**  **2002 2018**  **2002 2018**  South Dakota Badlands National

Park 44.87 41.20 3.51 2.42 7.81% 5.89% South Dakota Wind Cave National

Park 40.71 37.16 2.85 1.95 7.00% 5.24% Colorado Great Sand Dunes

National Park 27.88 26.77 0.52 0.39 1.87% 1.46% Colorado Rocky

Mountain National Park 32.13 29.41 0.57 0.40 1.76% 1.35% Minnesota Boundary

Waters Wilderness Area 61.33 53.32 1.04 0.79 1.70% 1.49%
Texas Guadalupe Mountains

National Park 47.80 44.43 0.72 0.62 1.51% 1.40% Minnesota Voyagers National

Park 59.50 52.10 0.86 0.64 1.45% 1.24% Oklahoma Wichita Mountains

Wilderness Area 100.03 75.56 1.11 0.81 1.11% 1.08% Missouri Hercules

- Glades

Wilderness Area 140.05 92.49 1.34 0.99 0.95% 1.07% Missouri Mingo Wilderness

Area 159.83 99.24 1.26 0.85 0.79% 0.86% Arkansas Caney

Creek Wilderness Area 133.93 85.84 1.06 0.71 0.79% 0.83%
Texas Big Bend National

Park 47.79 44.23 0.29 0.24 0.61% 0.55% Arkansas Upper Buffalo

Wilderness Area 131.79 86.16 0.66 0.44 0.50% 0.51%

**b. Baseline and natural visibility conditions**  **: 40 CFR 51.308(d)(2)**  States that host Class Iareas are required to estimate the baseline, natural and current visibility conditions of those Class Iareas. Nebraska does not host a Class I area, therefore, it is not required to estimate these metrics.7

**c. Reasonable Progress Goals**  **: 40**  **CFR 51.308(d)(1)** The RHR requires St ates and Tribes to establish a reasonable progress g oal (RPG) for each Class I area within the state. The RPG is measured in deciviews and is to provide for reasonable progress towards achieving natural visibility conditions during the first implementation period (through 2018). RPGs should represent an imp rovement in visibility for the most impaired days, and ensure no degradation in visibility on the least impaired days. Nebraska does not have a Class Iarea within the state and therefore is not required to establish a RPG. States hosting Class Iareas have established RPGs, and have made assessments regarding whether emission reductions are needed from sources in Nebraska in order to meet their RPG. Specific State goals and Nebraska’s effect on meeting them are describe d in further detail in the LTS consultation section, below. **d. Long** 
**- Term Strategy:**  **40 CFR 51.308(d)(3)** States must submit a long

- term strategy that addresses regional haze visibility impairment for each Class Iarea within the State and for each Class I area located outside the State which may be affected b y emissions from the State . The long

- term strategy must include enforceable emissions limitations, compliance schedules, and other measures as necessary to achieve the reasonable progress goals established by States having Class I areas. States must consider, at a minimum, the following factors in developing their long

- term strategy :
 Emission reductions due to ongoing air pollution control programs, including measures to address reasonabl y attributable visibility impairment;

 Measure s to mitigate the impacts of construction activities;
 Emissions limitations and schedules for compliance to achieve the reasonable progress goal;

 Source retirement and replacement schedules;
 Smoke management techniques for agricultural and forestry managem ent purposes , including plans as currently exist within the State for these purposes;

 Enforceability

of emissions limitations and control measures; and
 The anticipated net effect on visibility due to projected changes in point, area, and mobile source emissions over the period addressed by the long

- term strategy

. Nebraska’s LTS for the first implementation period addresses the emis sions reductions from Federal, S tate, and local controls that take effect in the state from the end of the baseline period through 2018. As described elsewhere in this document, the changes in point, area, and mobile source emissions over the first implementation period (through 2018) were taken into account b y CENRAP and the State in developing the emission inventory for 2018

. Specificall y, Nebraska considered the following Federal and State control measures when developing its LT S:
 Clean Air Interstate Rule (CAIR). Although Nebraska was not included in the original CAIR rulemaking, the rule was a major component in the underlying assumptions used to determine source apportionment because of the reductions expected in neighboring states with Class Iareas.
 Federal mobile s ource s tandards
 Tier 2 vehicle and low sulfur fuels8

 Locomotive and Marine engine rules
 Small spark

- ignition engine rules
 National Emission Standards for Hazardous Air Pollutants (NESHAP ) and associated Maximum Achievable Control Technology ( MACT ) s tandards
 Nebraska’s Prevention of Significant Deterioration (PSD) co nstruction permitting program. Nebraska notes that the visibility protection provisions of PSD found at 40 CFR 52.21(o) have been incorporated into Title 129

-Nebraska Air Quality Regulations at Chapter 19 Se ction 022. Section 40 CFR 52.21(p) requires notification and consultation with federal land managers (FLMs) of Class Iareas which may be affected by

emissions from a new source; these requirements under have been incorporated b y reference into Title 129 at Chapter 19 Section 001. Nebraska has fugitive dust regulations in Nebraska Title 129

- Chapter 32, which includes a provision applicable to construction activities. The rule requires the use of reasonable measures such as paving, cleaning, application o f water, planting and maintenance of ground cover, and/or application of dust

- free surfactants to prevent dust from becoming airborne such that it remains visible beyond the property boundary

. Nebraska contends that construction activities are not expected to cause a significant impact to visibility , and did not require any additional measures to mitigate the impacts of construction activities for purposes of visibility improvement

. Nebraska also has regulations that address smoke management for agricultural and forestry management burns. Title 129

- Chapter 30 is a ban on open burning with some direct exceptions that include agriculture operations and parks management, and fires set for training purposes. Other ty pes of exceptions are subject to approval by the NDEQ and the local fire authority. For purposes of forestry

or land management, such burning is allowed provided it is conducted by a limited set of organizations approved b y NDEQ

. Nebraska contends that, based on the minimal impacts from burning, a more stringent smoke management plan is not needed for purposes of visibility protection at this time. The above programs are fully enforceable, provide for the mitigation of new source impacts through new source permitting programs, and reflect appropriate consideration of current programs and prospective changes in emissions. Enforceability of Nebraska’s BART control measures are more fully

described in section III ( e ) (v) of this TSD.
**i. Consultation**  **on other States**  **’ RPGs** Where Nebraska has emissions that are reasonably anticipated to contribute to visibility impairment in any

mandatory

Class I Federal area located in another State or States, it must consult with the other State(s) in order to develop co ordinated emission management strategies. If Nebraska causes or contributes to impairment in a Class Iarea, it must demonstrate that it has included in its SIP all measures necessary to obtain its share of the emission reductions needed to meet the progre ss goal for the area. As mentioned previously , Nebraska participated in the CENRAP planning process, which provided the primary

venue for State consultation and coordination on emission management strategies . Nebraska also say s in the SIP that it notified the states of South Dakota, Oklahoma , Missouri and Colorado while its draft BART permits were open for public comment, proposing onl y control for NO x at the three BART

- subject units in the9

State. It should be noted that although Nebraska participated as a member State in CENRAP, the greatest impacts from Nebraska sources occur in a Western Regional Area Partnership (WRAP) State

– South Dakota

. 1. South Dakota Nebraska asserts that is has a “minimal” impact on all Class I areas, and points out in its SIP that no State asked Nebraska for reductions in order to meet its RPGs. We disagree with the characterization of Nebraska’s contribution as minimal , as PSAT modeling shows Nebraska sources contribute 7

- 8% of the total visibility impairment at the South Dako ta Class Iareas, and source

- specific CALPUFF modeling shows that GGS has a maximum baseline impact at Badlands of 3.12 dv in 2003, and 2.59 dv at Wind Cave in 2002. 3 South Dakota’s reasonable progress goals, which are proposed for approval by EPA at the time of this writing, achieve less visibility improvement than the uniform rate of progress for the first implementation period. The reasonable progress goals for the 20% worst day s fall short of the uniform rate of progress b y 1.28 deciviews (dv) for Badlands and 1.34 dv at Wind Cave

. 4 **Table 2: South Dakota Uniform Rate of Progress (URP) and RPGs (deciviews)** 
**South Dakota**  **Class I areas**  **2000**

**–**

**2004 baseline**  **20% worst**  **days 2018**  **URP 2064**  **natural conditions**  **2018**

**reductions needed**  **RPG Deficit** 

**Badlands** 17.14 15.02 8.06 2.18 16.30 1.28 **Wind Cave** 15.84 13.94 7.71 1.89 15.28 1.34 Furthermore, the modeling used to estimate achievement of these goals assumed that a presumptive level of BART SO 2 controls would be installed on Nebraska sources. Nebraska did not go on to require that level of control, and in fact required no SO2 controls, therefore, South Dakota may be even further away from meeting its RPGs than wh at the modeling predicted. As described in detail in section III (e) (iv) (2) of this TSD, we propose to disapprove Nebraska’s SO 2 BART determination for GGS, and also propose to disapprove Nebraska’s LTS insofar as it relied on this deficient BART determination.

3 Source

- specific CALPUFF modeling for Nebraska City Station and G erald Gentleman Station is in appendix 10.5 of the SIP. 4 76646 Federal Register / Vol. 76, No. 236 / Thursday, December 8, 201110 2. Colorado In a comment letter dated January 21, 2011, the Colorado Department of Public Health and Environment (CDPHE) notes that Gerald Gentleman Station has a visibility impact of greater than one deciview on Rocky Mountain National Park (RMNP). CDPHE reviewed the CALPUFF modeling, and noted that controls at Gerald Gentleman Station would provide visibility improvement at both RMNP and Great Sand Dunes National Park. They note that both NO x and SO 2 controls appear to be cost effective

. In comments dated June 23, 2009, CDPHE points out that GGS is the largest EGU in Nebraska at 1,365 MW, and has average SO 2 emissions (31,135 tpy) that are more than half as much as all of the EGUs in Colorado combined. CDPHE questions why Nebraska would propose no SO 2 controls, since such controls are regularl y available, common controls for EGUs. CDPHE encourages Nebraska to take another look at the cost assumptions used for Flue Gas Desulfurization (FGD ) controls. They express that $2,700 per ton is reasonable, and that the cost is likely even lower. CDPHE comments that it understands the significance of water shortages in western Nebraska, as the state of Colorado is also in an arid region. They state that all large EGUs in Colorado have instal led (or are in the process of installing) FGD controls to reduce SO 2 emissions. CDPHE goes on to say

that the most recent WRAP modeling, which used the CMAQ model, predicts that RMNP is far short of its URP. CDPHE asked that Nebraska reconsider SO 2 controls at GGS under the RHR to help Colorado make progress at RMNP. Nebraska denies this request in their SIP on the basis that WRAP’s modeling did not distinguish Nebraska’s impact from the other CENRAP states. Nebraska also makes the argument that a wind rose from RMNP indicates that the wind pattern is rarel y from the direction of Nebraska. We share Colorado’s concerns about the SO 2 BART determination for GG S , and as described above, we are proposing to disapprove this deficient BART determination and Nebraska’s LTS insofar as the State relied on it to meet the LTS requirements.
3. Minnesota B oundary Waters, Voyageurs, Seney , and Isle Ro yale are referred to as the Northern Midwest Class Iareas. As identified in the document, “Reasonable Progress for Class I Areas in the Northern Midwest

– Factor Anal ys is,” the Lake Michigan Air Directors Consortium (LADCO) identified the following states contributing to Class I area visibility impairment in the LADCO region: Michigan, Minnesota, and Wisconsin, as well as surrounding states, such as the Dakotas, Iowa, Missouri, I llinois, and Indiana. 5 Nebraska does not significantly contribute to visibility

impairment at the Minnesota Class Iareas according to PSAT modeling. Through RPO consultation, Minnesota

5 Appendix 11.1 of the SIP11 determined that no additional emissions reductions from Nebraska sources were needed to meet Class Iarea visibility improvement goals at this point in time. EPA believes that this satisfies the requirement for consultation between these States.
4. Oklahoma As identified in the document titled, “Oklahoma‘s Wichita Mountains Wilderness Area Region al Haze Planning,” Oklahoma identified Nebraska in its area of influence for NO x . 6 Nebraska was initially invited to participate in the Oklahoma consultation process. Nebraska states that it provided copies of the draft BART permit packages to the State o f Oklahoma while on public notice, which only proposed NOx controls on OPPD and NPPD. Oklahoma did not provide any comment, or request additional controls for the initial planning period. EPA believes that the consultation requirement between these states has been satisfied.
5. Missouri and Arkansas Caney Creek, Upper Buffalo, Hercules Glades, an d Mingo are referred to as the central C lass I areas. As identified in the document, “Central Class I Areas Consultation Plan,” CENRAP identified Nebraska in the area of influence for nitrogen oxides at the c entral Class Iareas. 7 The central states determined whether a state was a major contributor based on an anal ys is of four approaches: trajectories, areas of influence, PSAT, and Q/d. If a state was found to be a m ajor contributor in at least 3 of the 4 approaches, the central states concluded it was appropriate to include that state as a major contributor. Nebraska was found to be a contributor based upon the area of influence onl y, therefore it was excluded as a m ajor contributing state to visibility impairment in Class Iareas in Missouri and Arkansas. EPA believes that Nebraska’s consultation requirement with these states was satisfied.

**e. Best Available Retrofit Technology (BART)**  **: 40 CFR 51.308(e)**  States must submit an implementation plan containing emission limitations representing BART and schedules for compliance with BART for each BART

- eligible source that may reasonabl y be anticipated to cause or contribute to any impairment of visibility

in any mandatory Class I Federal area. **i. BART eligible sources:**  **40 CFR 51.308(e)(1)(i)** States must identify

all BART

- eligible sources in their SIP. Sources are subject to BART if: 1. One or more emissions units at the facility b elong to one of the twenty- six BART source categories; 8 2. The unit did not operate before 7 August 1962 but was in existence on 7 August 1977; and 3. The unit has the potential to emit 250 tons per year or more of any visibility

impairing pollutant , which Nebraska determined to be SO2, NO x , and PM 10 .

6 Appendix 11.3 of the SIP 7 Appendix 11.2 of the SIP 8 BART guidelines, 40 CFR Part 51 Appendix Y12

The BART Guidelines direct states to exercise judgment in deciding whether VOCs and NH 3 impair visibility

in their Class I area(s). 70 FR 391160. CENRAP performed anal ys es which demonstrated that anthropogenic emissions of VOC and NH 3 do not significantl y impair visibility

in the CENRAP region. Therefore, Nebraska did not consider ammonia among visibility

- impairing pollutants and did not further evaluate NH 3 and VOC emissions sources for potential controls under BART or reasonable progress. Nebraska used its database to identify potential BART

- eligible units and facilities with emission units in one or more of the 26 BART categories

. Nebraska then conducted a survey to identify

facilities within these source categories with potential emissions of 250 tons per year or more for any visibility

- impairing pollutant from any unit that was in existence on August 7, 1977 and began operation after August 7, 1962. More detailed information regarding each facility‘s BART

- eligible units may be found in Appendix 10.2. EPA proposes to find that Nebraska adequatel y identified all BART

- eligible sources within the State.
**Table 3: Facilities with BART**
**- eligible units in Nebraska** 

**Source category Facility**  **Location Number**  **of emission**  **units identified**  **by date Potential to emit**  **(date**
 

** eligible units, tons per** **year)**
**PM 10**  **NO x**  **SO 2** 

Fossil

- fuel fired steam electric plants of more than 250 million BTU per hour heat input NPPD Gerald Gentlemen Station Sutherland 2 4,460 46,200 79,200 OPPD Nebraska City Nebraska

City 1 43,792 19,040 45,696 OPPD North Omaha Station Omaha 2 910 14,420 34,283 NPPD Sheldon Station Hallam 2 908 6,020 15,100 CW Burdick Generating Station Grand

Island 2 997 1,923 10,304 Lon D. Wright Power Plant Fremont 2 97 3,784 3,035 Don Henry Power Center Hastings 1 19 1,360 780 North Denver Station Hastings 1 14 426 853 Portland cement plants Ash Grove Cement Louisville 7 528 2,373 3,182 Chemical process plant; fossil

- fuel boilers; hydrofluoric, sulfuric, and nitric acid plant Beatrice Nitrogen Plant Beatrice 18 48 924 513 **ii. BART subject sources**  Nebraska then screen ed out some BART

- eligible sources from being subject to BART on the basis that they

do not cause or contribute to visibility impairment in a Class I area. A contribution threshold of 0.5 deciviews based on the 98th percentile of daily modeled visibility impact over an annual period was used by Nebraska

. The BART Guidelines provide States the discretion to set a lower deciview threshold than 0.5 deciviews if the location of a large number o f BART

- eligible sources within the State and in proximity to a Class I area justifies this approach. The nearest Class Iarea from any BART

- eligible source in Nebraska is over 300 km away , and the State did not have any significant clusters of BART

- eligibl e sources, therefore, the State determined the 0.5 dv threshold was appropriate. Nebraska required the owner of each BART

- eligible source to conduct dispersion modeling using the CALPUFF model and submit the results to NDEQ . (One exception

- NDEQ conduct ed modeling for the Lon D. Wright Power Plant). The CALPUFF modeling protocol is included in Appendix 10.3. Nebraska identified eight sources with impacts less than 0.5 deciviews, which were therefore determined not to be BART

- subject:
**Table 4: BART**
**- eligible facilities determined not to be subject to BART based on**  **< 0.5 dv impact** Beatrice Nitrogen Plant (Koch Nitrogen) CW Burdick Generating Station Ash Grove Cement North Denver Station Don Henry

Power Center NPPD Sheldon Station Lon D. Wright Power Plant OPPD North Omaha Station
Two facilities had impacts greater than 0.5 deciviews, and were therefore determined to be BART

- subject: OPPD Nebraska City Station Unit 1 and NPPD Gerald Gentleman Station Units 1 and 2. EPA proposes to find that Neb raska adequatel y determined which sources in the State were subject to BART.

**Table 5: BART subject facilities in Nebraska Facility**  **Units Class I area**  **CALPUFF modeled impacts >**  **0.5 dv 2001**  **2002 2003**  OPPD Nebraska City Station 1 Hercules Glades 0.933 0.556 < 0.05 Wichita Mountains < 0.05 < 0.05 0.686

NPPD Gerald Gentleman Station 1 & 2 Badlands 2.845 2.828 3.121 Wind Cave 2.452 2.591 2.127 Wichita Mountains 1.032 1.206 1.392 Rocky Mountain 1.136 1.246 1.053 Hercules Glades 0.826 0.616 0.594 Mingo 0.615 < 0.05 < 0.0514 **iii. PM evaluation**  Nebraska used source

- specific CALPUFF modeling to examine the relative contribution of PM, NO x , and SO 2 emissions to visibility impairment. For Nebraska City

Unit 1, direct PM emissions only accounted for 0.32% of impairment on the most impaired year, 2001, at the closest Class I area, Hercules Glades. Nebraska concluded that direct PM emissions from NCS do not significantly contribute to visibility

impairment , and therefore, a full five factor BART analy sis for PM was not needed. For Gerald Gentleman Station, direct PM emissions only accounted fo r 0.69 % of impairment on the most impaired year, 2003 , at the closest Class I area, Badlands. Nebraska concluded that direct PM emissions from GGS do not significantly contribute to visibility

impairment, and therefore, a full five factor BART analysis for PM was not needed. EPA agrees with these conclusions.
**iv. BART determinations**  The five basic steps of a case

- by

- case BART analy sis are: 1. Identify All Available Retrofit Control Technologies. Control technologies should include pollution prevention, use of add

- on controls and combinations of the two. 2. Eliminate Technically Infeasible Options. Technologies demonstrated to be infeasible based on chemical, phy sical, and engineering principles are excluded from further consideration. 3. Evaluate Control Effectiveness of Remaining Control Technologies. Technically feasible control technologies are ranked in the order of highest expected emission red uction to lowest expected emission reduction

. 4. Evaluate Impacts and Document Results. Impacts that should be considered for each control technology

include: cost of compliance, energy impacts, non

- air quality environmental impacts, and the remaining useful life of the unit to be controlled. 5. Evaluate Visibility Impacts. Modeling should be performed on the pre

- and post

control emissions to determine the actual impact on visibility and assess the visibility improvement achieved and at what cost. This step does not need to be performed if the most stringent control technolo gy is chosen.
**1. Omaha Public Power District (OPPD)** 

**– Nebraska City Station (NCS)**  **Unit 1** Nebraska and EPA have reached different conclusions as to whether NCS Unit 1 is located at a power plant with a generating capacity in excess of 750 megawatts (MW), or not. If NCS falls within this category of sources, then the BART Guidelines must be foll owed in determining BART limits and the presumptive limits in the Guidelines would apply . See CAA § 169A (b). In September 2008, Nebraska asked EPA for clarification on whether recently permitted units, such as NCS Unit 2, should be included in the total p lant capacity for purposes of applying presumptive BART. In a response dated15 November 7, 2008, we indicated it is reasonable to interpret the RHR to mean that if the plant capacity

is greater than 750 MW at the time the BART determination is made b y the s tate (i.e., at the time the state places the BART determination on public notice), then the power plant is a facility “having a total generating capacity in excess of 750 [MW]” and any unit at the plant greater than 200 MW is subject to presumptive BART. The groundbreaking for construction of NCS Unit 2 was September 13, 2005. Nebraska put the NCS Unit 1 BART permit on public notice on December 12, 2008. Unit 2 was operational on May 1, 2009. 9 Nebraska concluded that because NCS Unit 2 was not operational at the time of the BART determination for Unit 1, its capacity did not count towards the 750 MW threshold, and therefore, it was not mandatory for Nebraska to follow 40 CFR 51 Appendix Y in making the BART determination. We concede that there is some question as to whether the NCS Unit 1 is a presumptive unit, requiring use of the BART Guidelines, or not. Regardless, Nebraska did proceed through a basic step

- wise analysis of the costs and visibility impacts of available co ntrols. The BART evaluation for OPPD NCS Unit 1 was conducted b y contractors hired by OPPD, and then submitted to Nebraska for review and use

. The full anal ys is may

be found in appendix 10.6 of the SIP.

**a. BART for NO**  **x -**  **NCS Unit 1** Step one of a BART analysis is to identify all available retrofit control t echnologies. Nebraska identified SCONO x , 10 the Pahlman process, selective catal ytic reduction (SCR), selective non

- catal ytic reduction (SNCR), flue gas recirculation (FGR), reducing air preheat temperature (RAP), ox ygen trim (OT), low excess air (LEA), over

- fire air (OFA), staged combustion air (SCA), and low NOx burners (LNB) as available retrofit controls for NO x at NCS Unit 1. NCS Unit 1 has existing has overfire air, which provide s a modest level of NO x control. Step two is to eliminate technicall y infeasible options. SNCR was eliminated because the furnace exit temperatures are too high ; SCONO x and the Pahlman p rocess were determined to be infeasible as they have not been demonstrated on large coal

- fired boilers

. Step three is to evaluate the control effectiveness of the technologies that were deemed feasible.

9 http://www.powermag.com/coal/Top

- Plants

-Nebraska

- City

- Station

- Unit

- 2

-Nebraska

- City

-Nebraska_2179_p4.html , accessed February 7, 2012. 10 SCONO x is a proprietary catalytic oxidation and absorption technology that uses a single catalyst for the removal of NO x , CO, and VOC.16 **Table 6: NO x**  **control technology effectiveness, NCS Unit 1 Control**  **technology Emission**  **rate**

**(lb s**  **/MMBtu) Potential** 

**emissions (tpy)**  **Tons**

**NO x**  **removed Control** 

**efficiency** Baseline 0.57 17,008 N/A N/A LNB/OFA 0.23 6,827 10,181 60% LNB/OFA+SCR 0.08 2,375 14,633 86%
St ep four is to consider the costs, energy impacts, non

- air quality environmental impacts, and the remaining useful life of the unit to be controlled. These factors are full y described in the OPPD BART anal ys is; only the cost of the various options is presented here.
**Table 7 :**  **Cost of NO x**  **control options, NCS Unit 1 Technology Options**  **LNB/OFA+ SCR**  **LNB/OFA Emission Rate (lb/MMBtu)**  0.08 0.23 **Emission Reduction (tpy)** 14,633 10,181 **Percentage Reduction** 86% 60% **Capital Cost** $265,455,000 $21,050,000 **Annualized Capital Cost** $21,300,000 $1,690,000 **Annual Operating Cost** $16,910,000 $0 **Total Annualized Cost** $38,210,000 $1,690,000 **Total Cost Effectiveness ($/ton)** $2,611 $166 Step five is to evaluate the visibility impacts. Results of this analysis are presented in table 8 for the two most impacted Class I areas for NCS Unit 1 (impacts > 0.5 dv)

. Note that the SO 2 control options are also pres ented in this table; other parts of the SO 2 BART anal ys is are described in the next sectio n
. **Table 8**  **: Visibility improvement analysis, OPPD NCS**  **Unit 1 Class I area**  **Technology Options Deciview impact, 8**  **th high values**  **Improvement (Average)**  **2001 2002**  **2003 Average** 

**Hercules Glades**  **(Missouri)** Baseline 0.933 0.556 0.473 0.65

LNB/OFA 0.621 0.358 0.324 0.43 0.22 LNB/OFA +SCR 0.45 0 0.284 0.252 0.3 3 0.3 3 FGD

– 0.15 lb s /MMBtu 0.530 0.355 0.308 0.40 0.25 FGD

– 0.10 lb s /MMBtu 11 0.493

- - - 0.44 12 LNB/OFA+FGD 0.233 0.159 0.140 0.18 0.47 LNB/OFA+FGD+SCR 0.140 0.084 0.072 0.10 0.55

11 Besides these rows, all other references to FGD in this table are modeled at a rate of 0.15 lbs/MMBtu. 12 Nebraska onl y presented modeling information for FGD at 0.10 lbs/MMBtu in its SIP for the most impacted year, 2001 at Hercules Glades.17 **Wichita Mountains**  **(Oklahoma)** Baseline 0.306 0.381 0.686 0.46

LNB/OFA 0.233 0.275 0.524 0.34 0.12 LNB/OFA +SCR 0.228 0.258 0.445 0.31 0.1 5 FGD

– 0.15 lb s /MMBtu 0.153 0.205 0.331 0.23 0.23 FGD

– 0.10 lb s /MMBtu 13

- - 0.311

- 0.38 14 LNB/OFA+FGD 0.069 0.109 0.165 0.11 0.35 LNB/OFA+FGD+SCR 0.053 0.063 0.112 0.08 0.38 **2 Class I areas (Cumulative)**  Baseline 1.11

Table 9 combines the average visibility improvement with the costs of control. Again, the two most impacted Class Iareas are presented, as well as a cumulative result combining the visibility benefit at both areas. **Table 9: Costs for visibility improvement, NC S Unit 1** 
**Class I area Control Options**  **Average dv improvement**  **(2001**
**- 03)**  **Total annualized**

**cost $/dv**  **15**

**Hercules Glades** LNB/OFA 0.22 $1,690,000 $7,681,818

LNB/OFA+SCR 0.33 $38,210,000 $115,787,879 FGD

– 0.15 lb s /MMBtu 0.25 $34,720,000 $138,880,000 FGD

– 0.10 lb s /MMBtu 16 0.44 17 $34,720,000 18 $78,909,091 LNB/OFA+FGD 0.47 $36,410,000 $77,468,085 LNB/OFA+FGD+SCR 0.55 $72,930,000 $132,600,000

**Wichita Mountains** LNB/OFA 0.12 $1,690,000 $14,083,333

LNB/OFA +SCR 0.15 $38,210,000 $254,733,333 FGD

– 0.15 lb s /MMBtu 0.23 $34,720,000 $150,956,522 FGD

– 0.10 lb s /MMBtu 19 0.38 20 $34,720,000 $91,368,421 LNB/OFA+FGD 0.35 $36,410,000 $104,028,571 LNB/OFA+FGD+SCR 0.38 $72,930,000 $191,921,053

**2 Class I areas (Cumulative)**  LNB/OFA 0.34 $1,690,000 $4,970,588

LNB/OFA +SCR 0.48 $38,210,000 $ 79,604,167 FGD

– 0.15 lb s /MMBtu 0.48 $34,720,000 $72,333,333 FGD

– 0.10 lb s /MMBtu 0.82 21 $34,720,000 $42,341,463 LNB/OFA+FGD 0.82 $36,410,000 $44,402,439 LNB/OFA+FGD+SCR 0.93 $72,930,000 $78,419,355

13 Besides these rows, all other references to FGD in this table are modeled at a rate of 0.15 lbs/MMBtu. 14 Nebraska only presented mo deling information for FGD at 0.10 lbs/MMBtu in its SIP for the most impacted year, 2003 at Wichita Mountains. 15 Note that in its SIP, Nebraska calculated the dollars per deciview based on the year of maximum impact, rather than a three year average as presented here. 16 Besides these rows, all other references to FGD in this table are modeled at a rate of 0.15 lbs/MMBtu. 17 This is maximum improvement, not a three year average. 18 In Nebraska’s SIP, they appear to have assumed the same cost regardless of the level of control (0.15 or 0.10 lbs/MMBtu); however, a higher level of control would likely have a slightly higher cost. 19 Besides these rows, all other references to FGD in this table are modeled at a rate of 0.15 lbs/MMBtu. 20 This is maximum improvement, not a three year average. 21 This is maximum improvement, not a three year average.18 Nebraska concluded that based on the high incremental cost of $8,203 22 per ton for the low incremental visibility improvement of 0.11 dv at Hercules Glades, requiring SCR was not warranted. BART for OPPD NCS Unit 1 was determined to be the installation of L

NB/OFA wi th an emission limitation of 0. 23 lbs /MMBtu. EPA agrees that the State’s determination is reasonable given the relativel y insignificant additional visibility

improvement associated with SCR for the additional cost.
**b. BART for**  **SO 2**  **- NCS Unit 1**  Step one is to identify

all available retrofit control technologies. Nebraska identified FGD , both throwaway sy stems (wet and dry FGD ) and regenerative processes, as possibilities for SO 2 control. Step two is to eliminate technically infeasible options. Coal desulfurization was determined to be infeasible because it has not been demonstrated for low

- sulfur coal, as is used at NCS; the Pahlman process and other regenerative processes were determined to be infeasible because they have not been demonstrated on large coal

- fired boilers. Therefore, only dry and wet FGD were deemed feasible and subject to further anal ys is. We note that Nebraska did not evaluate Dry Sorbent Injection (DSI) as a potential SO 2 control for NCS Unit 1. Since DSIcan generally achieve the same control efficiency as FGD, we believe that the State has appropriatel y evaluated the level of controls in its analysis. Step three is to evaluate the control effectiveness of the technologies that were deemed feasible. These r esults are presented in table 10.
**Table 10: SO 2**  **control technology effectiveness, NCS Unit 1 Control**  **Technology Emission** 

**rate (lb**  **s /MMBtu)**  **Potential**

**emissions (tpy)**  **Tons SO 2** 

**removed (tpy)**  **Control**

**efficiency** Baseline 0.815 24,191 N/A N/A Wet FGD 0.15 4,452 19,739 82% Dry FGD 0.15 4,452 19,739 82% Dry FGD 23 0.10 2,969 21,222 88% Step four is to consider the costs, energy impacts, non

- air quality environmental impacts, and the remaining useful life of the unit to be controlled. These factors are fully described in the OPPD BART anal ys is; only the cost of the various options is presented here. Nebraska concluded that dry FGD (spray

dryer absorber ( SDA ) ) has lower ca pital and operating costs than wet FGD and can achieve the same control efficiency ; it thu s focused its cost analysis on dry FGD

.

22 ($38,210,000

- $1,690,000) / (14,633

- 10,181) = $8,203

23 Figures in this row

were calculated by EPA; they were not provided in the SIP or in the BART appendices.19 **Table 11: Cost of SO**  **2 control options, NCS Unit 1**  **Technology Options Dry FGD (SDA)**  0.15 lb s /MMBtu **Dry FGD (SDA)**

0.10 lb s /MMBtu **Emission Reduction (tpy)** 19,739 21,222 24 **Percentage Reduction** 82% 88% **Capital Cost** $201,660,000 unknown **Annualized Capital Cost** $16,180,000 unknown **Annual Operating Cost** $18,540,000 unknown **Total Annualized Cost** $34,720,000 $34,720,000 25 **Total Cost Effectiveness ($/ton)** $1,759 $1,636 Step five is to evaluate the visibility impacts. These are presented in table 8 , in the NO x section above. Nebraska concludes that the costs of installing FGD ( $34,720,000) are too high for the small amount of visibility improvement (0.44 dv maximum improvement at Hercules Glades) , and therefore proposes no SO 2 controls as BART for NCS Unit 1. Based on the minimal visibility improvement, EPA agrees that the State’s SO 2 BART determination for NCS Unit 1 is reasonable

. **2. Nebraska Public Power District (NPPD)** 

**– Gerald Gentleman Station (GGS)**  **Units 1 and 2**  Like the BART anal ys is for OPPD, NPPD hired a contractor to conduct a BART anal ys is, which was then submitted to NDEQ for review and use . Information presented here is from the March 2 008 revised NPPD BART anal ys is and Nebraska’s SIP.

**a. BART for NOx** 
**- GGS Units 1 and 2**  Step one is to identify

available NO x control technologies. NPPD identified LNB/OFA, SCR, SNCR, SCONO x , and the Palman Process as available technologies for NO x control. In2006, NPPD installed L NB and OFA for NOx control. Note that this is after the 2001

- 2003 baseline modeling period used in the CALPUFF modeling. Therefore, LNB/OFA is still examined in this BART anal ys is. Step two is to eliminate technicall y infeasible options. LN B/OFA and SCR were determined to be technically feasible based on demonstrated performance on many similar units
**.** Nebraska eliminated the following technologies from further consideration:

 SNCR

- In feasible due to high furnace exit temperatures

 SCONO x - not demonstrated on large coal

- fired boilers
 Pahlman Process

- not demonstrated on large coal

- fired boilers

24 The tons of emission reduction and percentage reduction were back calculated by EPA based on other numbers provided in the SIP narrative. Nebraska did not provide these numbers directly. 25 In Nebraska’s SIP, they appear to have assumed the same cost regardless of the level of control (0.15 or 0.10 lbs/MMBtu); however, a higher level of control would likely have a slightly higher cost.20 The third step in the BART analysis is to examine the effectiveness of the feasible control technologies. **Table 12: NOx control technology effectiveness, GGS Units 1 and 2 Control**  **technology Emission rate** 

**(lb s**  **/MMBtu) Potential** 

**emissions (tpy)**  **Tons NO x** 

**removed Control** 

**efficiency** Baseline 0.455 30,243 N/A N/A LNB/OFA 0.23 15,287 14,956 49% LNB/OFA+SCR 0.08 5,317 24,926 82% The fourth step of the BART anal ys is is to consider the cost of compliance, energy , non - air quality environmental impacts, and remaining useful life. These factors are described in detail in the BART analysis; only the costs are presented here.
**Table 13 : Cost of NOx control options,**  **GGS Units 1 and 2 Technology Options**  **LNB/OFA+ SCR**  **LNB/OFA Emission Rate (lb/MMBtu)**  0.08 0.23 **Emission Reduction (tpy)** 24,926 14,956 **Percentage Reduction** 82% 49% **Capital Cost** $515,081,000 $36,930,000 **Annualized Capital Cost** $41,715,000 $2,960,000 **Annual Operating Cost** $14,515,000 $0 **Annualized Outage Cost** $1,021,000 $0 **Total Annualized Cost**  $57,251,000 $2,960,000 **Total Cost Effectiveness ($/ton)** $2,297 $198 The fifth and final step in a BART anal ys is is to examine the visibility improvements of various control options. Results presented in table 14 are for the six Class Iareas which were modeled to be impaired by GGS > 0.5 dv. Both NO x and SO 2 controls are presented. Note that although both GGS units have an individual stack, they

were modeled as a single stack , so modeling results presented here are for the two units combined

. **Table 14 :**  **Visibility analysis, NPPD GGS Units 1 and 2**
**Class I area Control technology**  **options Deciview impact, 8**  **th high**  **values Improvement** 

**(Average) 2001**  **2002 2003**  **Average Badlands**  **(South Dakota)** Baseline 2.845 2.828 3.121 2.93

FGD (0.15 lb s /MMBtu) 26 1.836 2.125 2.478 2.15 0.78 FGD (0.10 lb s /MMBtu) 1.790 2.026 2.443 2.09 0.85

26 Note that FGD wa s modeled at 0.15 lb s SO 2/MMBtu in this analysis, except where expressly noted

.21 LNB/OFA 2.224 2.162 2.419 2.27 0.66 LNB/OFA+SCR 1.732 1.728 1.879 1.78 1.15 LNB/OFA+FGD 1.107 1.275 1.537 1.31 1.62 LNB/OFA+FGD+SCR 0.62 0.692 0.757 0.69 2.24 DSI 27 1.755 2.147 2.31 2.07 0.86

**Wind Cave (South Dakota)**  Baseline 2.452 2.591 2.127 2.39

FGD 1.61 1.415 1.437 1.49 0.90 LNB/OFA 1.902 2.051 1.586 1.85 0.54 LNB/OFA+SCR 1.565 1.659 1.273 1.5 0 0.89 LNB/OFA+FGD 1.008 0.856 0.82 0.89 1.50 LNB/OFA+FGD+SCR 0.586 0.47 0.465 0.51 1.88

**Wichita Mountains**  **(Oklahoma)** Baseline 1.032 1.206 1.392 1.21

FGD 0.67 0.734 0.82 0.74 0.47 LNB/OFA 0.846 0.948 1.086 0.96 0.25 LNB/OFA+SCR 0.681 0.82 1.02 0.84 0.37 LNB/OFA+FGD 0.415 0.423 0.504 0.45 0.76 LNB/OFA+FGD+SCR 0.244 0.245 0.294 0.26 0.95
**Rocky Mountain**  **(Colorado)** Baseline 1.136 1.246 1.053 1.15

FGD 0.607 0.822 0.646 0.69 0.46 LNB/OFA 0.927 0.956 0.807 0.9 0 0.25 LNB/OFA+SCR 0.788 0.777 0.628 0.73 0.42 LNB/OFA+FGD 0.38 0.478 0.376 0.41 0.74 LNB/OFA+FGD+SCR 0.23 0.263 0.205 0.23 0.92

**Hercules Glades (Missouri)**  Baseline 0.826 0.616 0.594 0.68

FGD 0.538 0.327 0.307 0.39 0.29 LNB/OFA 0.64 0.508 0.46 0.54 0.14 LNB/OFA+SCR 0.527 0.456 0.4 0 0.46 0.22 LNB/OFA+FGD 0.319 0.207 0.201 0.24 0.44 LNB/OFA+FGD+SCR 0.179 0.122 0.115 0.14 0.54

**Mingo (Missouri)**  Baseline 0.615 0.432 0.438 0.5

FGD 0.299 0.168 0.213 0.23 0.27 LNB/OFA 0.495 0.365 0.332 0.4 0.10 LNB/OFA+SCR 0.423 0.308 0.28 0.34 0.16 LNB/OFA+FGD 0.174 0.11 0.13 0.14 0.36 LNB/OFA+FGD+SCR 0.108 0.07 0.077 0.09 0.41 **6 Class I areas (cumulative)**  Baseline 8.86

27 Nebraska only presented visibility results for DSI at Badlands.22 The visibility

r esults presented in table 15 are for the closest and most impacted Class Iarea, Badlands; cumulative results include all 6 Class Iareas shown to be impacted b y GGS > 0.5 dv. **Table 15: Costs for visibility improvement, GGS Units 1 and 2 Control Options**  **Average dv**

**improvement (2001** 
**- 03)**  **Total**

**annualized cost $/dv** 

**Badlands** DSI 0.86 $81,958,000 $95,300,000

FGD (0.15 lb s /MMBtu) 0.78 $108,517,000 $139,124,359 FGD (0.10 lb s /MMBtu) 28 0.85 $108,517,000 29 $127,667,059 LNB/OFA 0.66 $2,960,000 $4,484,848 LNB/OFA+SCR 1.15 $57,251,000 $49,783,478 LNB/OFA+FGD 1.62 $114,410,000 $70,623,457 LNB/OFA+FGD+SCR 2.24 $168,701,000 $75,312,946

**Cumulative, 6 Class I areas**  **30** DSI unknown 31 $81,958,000 $47,650,000

FGD 3.17 $108,517,000 $34,232,492 LNB/OFA 1.94 $2,960,000 $1,525,773 LNB/OFA+SCR 3.21 $57,251,000 $17,835,202 LNB/OFA+FGD 5.42 $114,410,000 $21,108,856 LNB/OFA+FGD+SCR 5.56 $168,701,000 $30,341,906
Nebraska concluded that based on the relativel y low incremental visibility improvement of adding SCR to the LNB/OFA s ys tem (0.49 dv, Badlands) for the additional cost ($5,445 incremental cost per ton 32 ) , requiring SCR as BART was not warranted. BART for OPPD NCS Unit 1 was determined to be the installation of LNB/OFA with an emis sion limitation of 0.23 lbs /MMBtu, averaged across the two units. EPA agrees that the State’s NO x BART determination is reasonable.
**b. BART for SO**  **2 -**  **GGS Units 1 and 2** Step one is to identify

the available control technologies for SO 2 . Nebraska identified wet and dry

FGD, coal desulfurization, the Pahlman process, and other regenerative processes as potential controls. Step two is to eliminate the technically infeasible controls. NPPD eliminated the following controls from further consideration:

 Coal desulfurization

- not demonstrated for low

- sulfur PRB coal
 Pahlman Process

- not demonstrated on large coal

- fired boilers

28 Unless expressly noted, FGD visibility results in this table were modeled at 0.15 lbs/MMBtu. 29 In Neb raska’s SIP, they appear to have assumed the same cost regardless of the level of control (0.15 or 0.10 lb/MMBtu); however, a higher level of control would likely have a slightly higher cost. 30 In calculating cumulative visibility improvement, NDEQ only co nsidered the two closest Class I areas, Badlands and South Dakota. We believe that it is more appropriate to calculate cumulative improvement from all the Class I areas which are impacted greater than 0.5 dv from GGS Units 1 and 2. 31 Visibility improvement for DSI was only evaluated at Badlands; because of the proximity and similarity of impacts between Badlands and Wind Cave, we believe it is reasonable to assume similar visibility improvement would be seen at Wind Cave from the installation of DSI. 32 Incremental cost per ton: ( $57,251,000

- $2,960,000 ) / ( 24,926

- 14,956 ) = $5,44523  Other regenerative p rocesses

– none have been demonstrated on large coal

- fired boilers In response to comments on the original BART analy sis, Nebraska requested that NPPD also evaluate Dry

Sorbent Injection ( DSI) for SO 2 control. Nebraska determined that DSI is a technicall y feasible control for GGS Units 1 and 2. Step three is to examine the effectiveness of the feasible control technologies. These results are presented on table 16.
**Table 16: SO 2**  **control technology effectiveness, GGS Un its 1 and 2**  **Control technology**  **Emission rate**

**(lb/MMBtu) Potential** 

**emissions (tpy)**  **Tons SO2**

**removed Control** 

**efficiency** Baseline 0.749 49,785 N/A N/A Wet FGD 0.15 9,970 39,815 80% Dry FGD 0.15 9,970 39,815 80% DSI 0.15 9,970 39,815 80% FGD 33 0.10 6,647 43,138 87% Step four is to consider the cost of compliance, energy , non - air quality environmental impacts, and remaining useful life. These factors are described in detail in the BART analysis; the costs are presented here, as well as a significant non - air quality environmental issue (water availability ) raised b y Nebraska

. **Table 17: Cost of SO 2**  **control options, GGS Units 1 and 2**  34 **Technology Options Dry FGD**  **Wet FGD DSI**  **FGD Emission Rate (lb/MMBtu)**  0.15 0.15 0.15 0.10 **Emission Reduction (tpy)** 39,815 39,815 39,815 43,138 **Percentage Reduction** 80% 80% 80% 87% **Capital Cost** $981,592,000 $1,029,819,000 $208,330, 0 00 unknown **Annualized Capital Cost** $80,013,000 $83,965,000 $17,500,0 0 0 unknown **Annual Operating Cost** $27,806,000 $24,485,000 $64,458,0 0 0 unknown **Annualized Outage Cost** $698,000 $0 $0 unknown **Total Annualized Cost** $108,517,000 $108,450,000 $81,958,000 35 $123,933,694 36 **Total Cost Effectiveness ($/ton)**  $2,726 $2,724 $2,058 $2,873

33 Figures in this row

were calculated by EPA; they were not provided in the SIP or in the BART appendices. 34 T he co sts presented in Table 17 include the total cost for controlling SO 2 emissions from both units at GGS. 35 Nebraska adjusted the costs for DSI to 2016 dollars, because they say that’s the likely time when installation would occur. Note that the other figures in this table were not adjusted to future years. 36 In Nebraska’s analysis of costs and visibility improvement of FGD at 0.10 lb/MMBtu, they used the total annualized cost of $123,933,694. This is the same cost at 0.15 lb/MMBtu, but with costs to purchase water rights and costs of loss of agricultural revenue added in. The cost does not, however, include increased costs for operating at a more stringent level of control, which presumably would be slightly higher. EPA believes that it is appropriate to include the costs of obtaining water rights, but not costs for loss of agricultural value for purposes of a BART analysis.24 Costs per ton for wet and dry FGD at a rate of 0. 15 lb s /MMBtu were nearly identical, and Nebraska concluded that these costs were reasonable on a cost per ton basis ( $ 2,726/ton). Nebraska found DSI to be more cost effective, at $ 2,058 per ton. Nebraska raises water use of wet and dry FGD as a significant non

- air environmental impact. Inits SIP, Nebraska presents a description of the over

appropriation of water resources in the w estern part of the State , where GGS is located

. Th e State described that over- appropriation means that any new use of water requires an offset in water consumption in the same area. To do this, NPPD would have to purchase the ground water rights from surrounding landowners
. Nebraska did not include the cost of obtaining these water rights in the original BART analy sis costs; however, in the narrative portion of the SIP, Nebraska describes both the costs of obtaining water, and the loss of agricultural revenue due to taking land out of agricultural production :

“ For purposes of the cost effectiveness analysis, only the loss of revenue (2007 figures) was added to the annualized costs, which increased the total annualized costs to $123,933,694. Approximately 5.7% of the costs are associated with the loss of crop value. Overall, the impact as a result due to water

- related issues increased the annualized costs from $108,450,000 [to operate FGD] to $123,933,694, a 14.3% increase. The NDEQ concluded this is a significant economic impact.”
If the costs to obtain water rights were added into the BART analy sis, the FGD costs would increase to $117,776,000. (EPA is not including the loss of crop value in its analysis). As seen in table 18 , adding in the costs of water rights only increa ses the cost of control by $234 per ton. This brings the cost per ton to $2,958, which EPA believes is still a reasonable cost of control.
**Table 18 : Cost of SO2 control and visibility benefit,**  **GGS Units 1 and 2 Technology Options**  **Wet FGD (original**  **BART analysis)**  **Wet FGD**

**(revised with water**  **offset costs) Wet FGD** 

**(with water offset costs)**  **DSI**

**Emission Rate (lb/MMBtu)** 0.15 0.15 0.10 0.15 **Total Annualized Cost** $108,450,000 $117,776,000 $123,933,694 37 $81,958,000 **Total Cost Effectiveness ($/ton)** $2,724 $2,958 $2,873 $2,058 **Average visibility improvement (Badlands)**  0.78 0.78 0.85 0.86

37 In Nebraska’s analysis of costs and visibility improvement of FGD at 0.10 lbs/MMBtu, they used the total annualized cost of $123,933,694. This is the same cost at 0.15 lbs/MMBtu, but with costs to purchase water rights and costs of loss of agricultural revenue added in. EPA believes that it is appropriate to include the costs of obtaining water rights, but not costs for loss of crop value for purposes of a BART analysis.25

**Average visibility improvement (Cumulative)**  3.17 3.17 unknown 38 unknown 39 **$/dv (Badlands)** $139,124,359 $150,994,872 $145,804,346 40 $95,300,000 **$/dv (Cumulative)** $34,232,492 $37,153,312 unknown unknown

Step five is to examine the visibility improvements of various control options. Results are presented in table 14 and 15, above. Significant visibility improvement is seen from all of the control options, ranging from 0.78 dv average improvement at Badland s from installation of FGD, to 1.62 average dv improvement at Badlands from installation of L

NB/OFA plus FGD. If considered on a cumulative basis, GGS has a baseline impact on 6 Class Iareas of 8.86 dv. Installation of FGD would offer an average of 3.17 dv cumulative improvement, and in combination with LNB/OFA, 5.42 dv cumulative improvement. 41 In the SIP, Nebraska says that i t used a $40,000,000/yr/dv threshold for determining what would be considered reasonable investment for visibility improvement. They concluded that the costs of FGD control were reasonable on a cost per ton basis, but not on a dollars per deciview basis. Furthermore, Nebraska sees the water consumption of FGD controls as significant, and concludes that because of this unique situation, FGD controls are unreasonable for GGS Units 1 and 2. EPA disagrees with this conclusion. Using Nebraska’s costs, w e agree that the cost per ton for FGD control is reasonable, and also see the visibility improvement, both at Badlands and on a cumulative basis, as significant. We believe that Nebraska also inappropriately ruled out DSI

. Costs for the control are reasonable at $2,058 per ton an d visibility improvement at Badlands is significant at 0.86 dv. If considered cumulatively , visibility improvement would be even more significant, although as mentioned previously , Nebraska did not provide that anal ys is in their SIP. Furthermore, DSI doe s not present the same water consumption issues as FGD

. Finally , a s described in detail in appendix A , B , and C of this TSD, we believe that Nebraska’s costs of FGD control are overestimated . EPA conducted an independent anal ys is of the cost information presented by Nebraska in its BART anal ys is for dry scrubbers. Although we did not review the BART cost anal ys is for wet scrubbers, many of the same issues likely appl y. Note that our anal ys is of the cost elements

38 Nebraska only provided visibility improvement information for FGD at 0.10 lbs/MMBtu for Badlands, so the cumulative benefit is unknown. 39 Nebraska only evaluated visibility improvement for DSI at Badlands, so the cumulative benefit is unknown. 40 In Nebraska’s analysis of costs and visibility improvement of FGD at 0.10 lbs/MMBtu, they used the total annualized cost of $123,933,694. This is the same cost at 0.15 lbs/MMBtu, but with costs to purchase water rights and costs of loss of cro p value added in. EPA believes that it is appropriate to include the costs of obtaining water rights, but not costs for loss of crop value for purposes of a BART analysis. 41 These figures all assume FGD at the presumptive rate. At the rate of 0.10 lbs/MMBtu, average visibility im provement at Badlands would be 0.85 dv. Cumulative improvement is unknown.26 was not comprehensive, but only addresses what we see as some of the most significant errors and deviations from EPA’s Cost Control Manual

. 42 Categories which we found significant overestimations include:

 Engineering Procurement and Co nstruction
 Bond Fees
 Escalation
 Contingency

 Allowance for Funds Used During Construction
 Capital Recovery

Factor
 Operation and Maintenance We also found that Nebraska incorrectl y calculated the SO 2 emission rates. On page 15 of its BART anal ys is, NPPD calculates its SO 2 emission baseline based on applying a 24 hour maximum emission rate of 0.749 lbs/MMBtu (2001

- 2003) to a maximum heat input of 15,175.5 MMBtu/hr, ba sed on a 100% capacity factor. This results in an emissions baseline of 49,785 tons/y r. 43 We believe this calculation does not appropriatel y represent GGS’s SO 2 emission baseline, and is in fact too high. The Regional Haze Rule provides the following regarding the calculation of the BART emissions baseline:

“ The baseline emissions rate should rep resent a realistic depiction of anticipated annual emissions for the source. In general, for the existing sources subject to BART, you will estimate the anticipated annual emissions based upon actual emissions from a baseline period. W hen you project that future operating parameters (e.g., limited hours of operation or capacity utilization, type of fuel, raw materials or product mix or type) will differ from past practice, and if this projection has a deciding effect in the BART determination, then you must make these parameters or assumptions into enforceable limitations. In the absence of enforceable limitations, you calculate baseline emissions based upon continuation of past practice. ”
We see no indications that NPPD’s future operating practices are proje cted to deviate from the past. GGS states on page 2 of its BART analy sis that it used a baseline period of 2001

- 2003, which was the baseline emission rate period for BART modeling in Nebraska. We have downloaded emissions data for GGS from our Cl ean Air Markets web site 44 and have calculated the average total station SO 2 emissions for GGS Units 1 and 2 to be 31,513 tons/y r for the three year period of 2001

- 2003. We note that based on GGS’s stated capacity of Units 1 and 2 (665 and 700 MW, respectiv ely), we calculate capacity factors for Units 1 and 2 to range from 89% to 94% and 77% to 85%, respectivel y, from 2001

- 2003. Our analy sis assumes this historic usage is not significantl y altered in the future. A summary of this data appears in a

ppendix B to the TSD.

42 EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/452/B

- 02

- 00 1, January 2002 43 (0.749 lbs/MMBtu) * (15,175 MMBtu/hr) * (8,760 hrs/yr) * (ton/2,000 lbs) = 49,785 tons/yr. 44 http://camddataandmaps.epa.gov/gdm/index.cfm? fuseaction=emissions.wizard27 Using the same emissions data from the three ye ar averaging period of 2001

- 2003, we have calculated the three ye ar average annual SO 2 emissions for units 1 and 2 of the GGS to be 0.565 lbs/MMBtu. 45 Reducing this to a controlled SO 2 emissions level of 0.15 lbs/MMBtu results in a scrubber efficiency of approximately

73.5%. Applying this level of control to our adjusted GGS SO 2 emission baseline of 31,513 tons/y r would reduce it to 8,366 tons/y r, resulting in a reduction of 23,147 ton s of SO 2 annually

. Appl ying the same approximate 80% level of reduction GGS assumes to our adjusted GGS SO 2 emission baseline of 31,513 tons/yr would reduce it to 6,311 tons/y

r, resulting in a reduction of 25,202 tons of SO 2 annually

. 46
However , dry

scrubb ers are capable of much greater control efficiencies than the 80% level that Nebraska assumes. 47 Therefore, for the purpose of calculating the cost effectiveness of dry

scrubbers at the GGS, we have assumed an SO 2 emission limit of 0.06 lbs/MMBtu, which res ults in a scrubber efficiency of approximately 89.4%. Applying this level of control to our adjusted GGS baseline of 31,513 tons/y r would reduce it to 3,347 tons/y r, resulting in a reduction of 28,166 tons of SO 2 annually

. Table 19 summarizes EPA’s adjustments to the NPPD cost estimates for dry FGD control

. **Table 19 : Range of GGS Dry Scrubber Cost Effectiveness**  **Dry FGD (original NPPD**  **BART analysis) Dry FGD**  **EPA’s estimate**
**SO 2**  **Baseline** 49,785 31,513 **Uncontrolled Emission Level (lbs/MMBtu)**  0.749 0.565
**Controlled Emission Rate (lb**  **s /MMBtu)**  0.15 0.15 0.11 0.06
**Percent Reduction** 80% 73.5% 80% 89.4% **SO 2**  **Emission Reduction (tons)** 39,815 23,147 25,202 28,166 **Total Annualized Cost** $108,535,690 $53,469,570 $54,335,512 $55,543,352 **Total Cost Effectiveness ($/ton)** $2,726 $2,310 $2,156 $1,972

In summary , we believe that Nebraska overestimated the costs of FGD controls; did not do a full evaluation of the potential visibility benefits from levels of control that FGD is capable of achieving; and improperly rejected DSI . We believe that the cost

45 See Attachment B to our TSD. Based on adding the station total pounds of SO 2 emissions from 2001

- 2003 and dividing by the station total heat input from 2001

- 2003. 46 (39,815/49,785)*31,513 = 25,202. 47 Response to Technical Comments for Sections E. thro ugh H. of the Federal Register Notice for the Oklahoma Regional Haze and Visibility Transport Federal Implementation Plan, Docket No. EPA

- R06

- OAR

- 2010

- 0190 , 12/13/2011, Section II. , Comments Relating to Our SO 2 BART Emission Limit , and elsewhere.28 per ton of SO 2 controls ranging from $1,972 (our anal ys is) to $2,958 (Nebraska’s anal ys is, plus water) is reasonable; and that the visibility benefits, whether considered just at Badlands or cumulatively , are significant. Therefore, EPA proposes to disapprove Nebraska’s BART determination for SO 2 at Gerald Gentleman Station.

**v. BART summary and enforceability**  **: 40 CFR 51.308(e)(1)(iv)** 

**– (v)**  Table 20 is a summary

of the BART determinations made by Nebraska for BART

subject units.
**Table 20 : Summary of BART determinations**  **Facility, Units Pollutant**  **BART controls determined by**  **Nebraska EPA’s**  **proposed determination**  **OPPD Nebraska City Station, Unit 1**  NO x Install LNB with OFA, meet level of 0.23 lb s /MMBtu. Approval SO 2 No additional controls. Approval **NPPD Gerald Gentleman Station,**  **Units 1 and 2** NO x Install LNB with OFA . Meet level of 0.23 lb s /MMBtu. Approval SO 2 No additional controls

. Disapproval Each source subject to BART must install and operate BART as expeditiously as practicable, but in no event later than 5 years after approval of the SIP revision; and include monitoring, recordkeeping and reporting requirements to ensure the BART limits are enforceable

. Nebraska chose to incorporate BART requirements into PSD permits issued pursuant to Title 129 of the Nebraska Air Quality Regulations, Chapter 19

. The se limits will be incorporated into the facility ’s Title V permits after SIP approval. The permits require that the limits be met within 5 years of approval of Nebrask a’s regional haze SIP . The limits must be met on a 30

- day rolling average basis at all times, including periods of startup, shutdown, and malfunction. The permits require the use of a NO x continuous emission monitoring system (CEMS) on each unit to demonstrate compliance with the BART NO x limits. Each CEMS is required to be operated and certified in accordance with 40 CFR Part 75. Recordkeeping and reporting is also required to be in accordance with 40 CFR Part 75. We have reviewed these requirements and propose to find them adequate as th ey relate to the BART limits we are proposing to approve.
**f. Monitoring strategy**  **: 40 CFR 51.308(d)(4)**  Because it does not host a Class Iarea, Nebraska is not required to develop a monitoring strategy

for measuring, characterizing, and reporting regional h aze impairment that is representative of C lass I areas within the State. However, the State is required to establish procedures b y which monitoring data and other information is used to determine the contribution of emissions from within the State to regio nal haze impairment at Class Iareas outside of the State.29 Compliance with this requirement is met by participation in the Interagency Monitoring of Protected Visual Environments (IMPROVE) 48 network. Nebraska installed one IMPROVE protocol sampler at Nebraska National Forest County near Halsey , NE in the central part of the State, and another at Crescent Lake National Wild Life Refuge in the p anhandle of the state. A third IMPROVE Protocol sampler in Nebraska is operated independentl y in Thurston County , by the Omaha Tribe of Nebraska, although EPA notes that this monitor is not currentl y operating. EPA believes the State’s commitment to utilize data from these sites, or any other EPA

- approved monitoring network location, to characterize and model conditions within the state and to compare visibility conditions in the state to visibility impairment at Class Iareas hosted by other states, and proposes that Nebraska has satisfied the monitoring requirements of 40 CF R 51.308(d)(4).
**g. Emissions inventory: 40 CFR 51.308 (d)(4)(v)**  States are required to develop a s tatewide inventory of emissions of pollutants that are reasonabl y anticipated to cause or contribute to visibility i mpairment in any Class Iarea. The inventory must include emissions for a baseline year, emissions for the most recent year with available data, and future projected emissions. As mentioned previously , Nebraska worked with CENRAP and its contractors to develop statewide emission inventories for 2002 and 2018. Detailed m ethodologies are documented in appendices 8.3 and 9.1. The 2018 emissions inventory was developed b y projecting 2002 emissions and applying reductions expected from federal and state re gulations affecting the emissions of the visibility

- impairing pollutants NO x , PM, SO 2 , and VOCs. The 2002 emissions were grown to year 2018 primarily using the Economic Growth Anal ys is Sy stem (EGAS6), MOBILE 6.2 vehicle emission modeling software, and the Integrated Planning Model (IPM) version 2.93 for EGUs . The 2018 emissions f or EGUs were based on simulations of the IPM that took into the account the effects of CAIR on emissions. At the time modeling was conducted, BART decisions had not been made by many states, including Nebraska . Presumptive levels of BART control were assumed in projections of 2018 emissions

. The 2018 inventory was then update d to account for Nebraska’s BART decisions. **Table 21: 2002 Nebraska Emissions Summary (tons per year )**  **VOC NO**  **x SO**  **2 PM**  **10 PM**  **2.5 Point**  7,274 58,619 73,487 13,105 4,638 **Area** 66,769 15,023 7,748 447,703 83,852 **On**
**- Road**  43,113 61,850 1,822 1,277 930 **Non**
**- Road**  24,882 119,568 11,011 7,491 6,785 **Fire** 3,204 679 268 5,057 3,956 **Biogenic** 533,705 39,446 0 0 0 **Total 678,947**  **295,185 94,336**  **474,633 100,161** 

48 http://vista.cira.colostate.edu/improve30 **Table 22: 2018 Nebraska Projected Emissions Summary**

**(tons per year) VOC**  **NO x**  **SO 2**  **PM 10**  **PM 2.5**  **Point** 13,344 56,190 82,193 18,654 8,596 **Area** 78,417 17,737 9,793 303,578 56,193 **On**
**- Road**  18,862 19,702 236 432 432 **Non**
**- Road**  14,611 50,972 226 3,269 2,974 **Fire** 3,204 679 268 5,057 3,956 **Biogenic** 533,705 39,446 0 0 0 **Total 660,868**  **185,040 92,716**  **335,012 76,610**  The EPA believes the 2002 and 2018 statewide emissions inventories and the State’s method for developing the 2018 emissions inventory for Nebraska meets the requirements of the RHR . Nebraska has also committed to update inventory periodicall y, therefore, w e propose that Nebraska has met the requirements of 40 CFR § 51.308(d)(4)(v).
**h. Federal Land Manager (FLM) consultation:**  **40 CFR 51.308(i)** By November 29, 1999, Nebraska was required to identify in writing to the FLMs the title of the official to which the FLM of any Class I area can submit recommendations. Nebraska has satisfied this requirement by identifying the Air Division Administrator at the Nebraska Department of Environmental Quality as this official. States are required to provide the FLMs an opp ortunity for consultation, in person and at least 60 days prior to holding any public hearing on the SIP (or its revision). Consultations should include the opportunity for the FLMs to discuss their assessment of impairment of visibility in any Class Iare a; and recommendations on the development of the RPG and on the development and implementation of strategies to address visibility impairment. Nebraska provided several opportunities for the FLMs to comment on Nebraska’s regional haze plan. Nebraska sent the draft BART permits for NPPD and OPPD to the FLMs in mid

- 2008, and again prior to public notice. Nebraska provided the FLMs with a draft of the Nebraska regional haze SIP on November 16, 2010, and received formal comments from the National Park Service (NPS), the US Fish and Wildlife Service (USFWS), and the US Forest Service (USFS) in January 2011. In developing any S IP (or plan revision), States must include a description of how it addressed any comments provided b y the FLMs. The FLM comments and Neb raska’s responses are provided in appendix 3 of the SIP, and are summarized below. The FLMs believe that Nebraska did not met the requirement to include the measures necessary to achieve the reasonable progress goals established by States31 having mandatory Class I Federal areas in its draft SIP . They note that, “the goals established by

South Dakota for Badlands and Wind Cave National Parks, by Colorado for Rocky Mountain National Park, b y Oklahoma for Wichita Mountains, and by Missouri for Mingo Wildlife Refuge and Hercules Glade Wilderness Area, as well as other Class I areas, assume that Nebraska will require presumptive BART controls for the Gerald Gentleman and Nebraska City p ower plants as modeled by WRAP and CENRAP

. Nebraska proposes not to require c ontrols of SO 2 for any of the BART units. Nebraska’s long term strategy does not include the controls required to meet its contribution to the reasonable progress goals established by its neighboring states through the RPO process.” The FLMs also have expressed concerns with Nebraska’s BART anal ys es at Nebraska City

Station (NCS) Unit 1 and Gerald Gentleman Station (GGS) Units 1 and 2. For NCS, the FLMs ask Nebraska to seriously consider all feasible SO 2 control options, including DSI, and NO x controls, including SNCR, as part of the five factor anal ys is. They state that $1,636 per ton for SDA with a fabric filter is reasonable and should b e considered as BART for Unit 1 . They disagree with ruling out SCR for NO x control, as it is cost effective . The FLM s also questioned whether the cost estimates were developed consistent with the EPA Control Cost Manual. They also ask Nebraska to consider upgrade of the existing PM control as a BART alternative. The FLMs go on to say

that the BART determination for GG S is not acceptable as written, disagreeing with Nebraska’s BART determination of no SO 2 controls for Gerald Gentleman. They

point out that the visibility impact of these units is significant at more than just the closest Class Iarea (Badlands); they also take issue with several aspects of the cost estimation, such as escalation, contingencies, allowance for funds during construction, overestimation of direct annual costs. The FLMs did an anal ys is of what they believe a more appropriate cost estimation w ould be, and found that costs for a dry FGD s ys tem should be $87,101,902 in annualized cost, or $2,155 per ton. This is 20% lower than NPPD’s estimates. For a wet FGD s ys tem, annualized costs were estimated to be $85,696,911, or a cost of $2,073/ton. This is 21% lower than NPPD’s estimates. Regarding Nebraska’s argument about the significance of water availability, the United S tates F ish and W ildlife S ervice Air Branch asked the USFWS’s Nebraska Field Office to review Nebraska’s Draft Regional Haze SIP and comment on the merits of the arguments on water and endangered species protection. In a memo dated December 22, 2010, the USFWS Nebraska Field Office respo nded that, “the arguments given b y NDEQ have some merit. However, the Platte River Recovery Implementation Program (PRRIP) inherentl y provides options to offset consumptive use that results in depletions to the river and jeopardizes endangered species. Additionally , it appears much of the information provided in Nebraska’s plan represents a worst

- case scenario when describing offsets to water used by the NPPD . While not inaccurate, the information tends to overstate implications of any new water use b y NPPD ....in summary , there is no question any new depletions to32 central Platte River flows would require offsets. Because of this, there is the possibility

that accelerating actions to achieve air quality improvements would weaken Nebraska’s ability to meet its P RRIP obligations to improve Platte River flows on schedule. But we do not believe that it **automatically** follows that air quality improvements cannot be pursued because Nebraska simply could not do both.” Finally , regional haze SIPs must provide procedures for continuing consultation between the State and FLMs on the implementation of 51.308, including development and review of SIP revisions and 5

- ye ar progress reports, and on the implementation of other programs having the potential to contribute to impairment of visibility

in Class I areas. Nebraska has committed to continuing to coordinate and consult with the FLMs during the development of future progress reports and plan revisions, as well as during the implementation of programs having the potential to contribute to visibility impairment in Class Iareas. We propose that Nebraska has satisfied the FLM consultation requirements of 40 CFR 51.308 (i).
**i. Periodic SIP revisions and five year progress report**  **: 40 CFR 51.308 (f)**
**- (h)**  Nebraska acknowledged the req uirement to submit periodic progress reports and regional haze SIP revisions, with the first report due by July 31, 2018, and revisions due every ten years thereafter. Nebraska committed to meeting this requirement. Nebraska also acknowledged the requirement to submit periodic reports evaluating progress towards the reasonable progress goals established for each mandatory Class Iarea. Nebraska committed to complete the first five

- ye ar progress report by December 31, 2016. The report will evaluate the progress made towards the reasonable progress goal for each mandatory Class Iarea located outside Nebraska, which may

be affected by

emissions from within Nebraska
**.** Using the findings of this first report, Nebraska committed to determining whether the adequacy of the plan is sufficient and taking appropriate action to revise the SIP as needed. We propose to find that Nebraska has satisfied the requirements to commit to periodic SIP revisions and progress reports as required by 40 CFR 51.308(f)

- (h).