NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

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# FACT SHEET

BART & PSD Analysis

For the

Nebraska Public Power District

Gerald Gentleman Station

6089 South Highway 25 Sutherland, Nebraska 69165

May 11, 2010NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 2 of 53 

## Table of Contents

Executive Summary................................... ............................................................................................................................... 4

1.0 Introduction and Purpose ............................................................................................................................................ 4

1.1 Nebraska Regional Haze Program .......................................................................................................................... 4

1.2 Source Description and Permitting Background ..................................................................................................... 5

1.3 Gerald Gentleman Station BART Eligibility Analysis............................................................................................ 6

1.4 BART Analysis Methodology................................................................................................................................. 7

1.5 Consideration of Presumptive BART Limitations .................................................................................................. 8

1.6 Averaging Emission Limitations............................................................................................................................. 9

2.0 BART Analysis for Particulate Matter (both fine and coarse fractions)...................................................................... 9

2.1 Particulate Matter (PM) Formation......................................................................................................................... 9

2.2 BART for PM ....................................................................................................................................................... 10

3.0 BART Analysis for SO 2 ............................................................................................................................................ 11

3.1 SO 2 Formation ...................................................................................................................................................... 11

3.2 Identification of SO 2 Control Technologies and Technical Feasibility................................................................. 11

3.2.1 Sulfur Removal from Fuel ................................................................................................................................ 11

3.2.2 Flue Gas Desulfurization (FGD)....................................................................................................................... 11

3.3 Ranking of Technologically Feasible SO 2 Controls based on Effectiveness......................................................... 12

3.4 Evaluation of Effective SO 2 Controls ................................................................................................................... 13

3.4.1 Cost of Compliance .......................................................................................................................................... 13

3.4.2 Energy Impacts ................................................................................................................................................. 14

3.4.3 Other (Non-Air Quality) Environmental Impacts ............................................................................................. 14

3.4.4 Remaining Useful Life...................................................................................................................................... 19

3.5 Visibility Impacts.................................................................................................................................................. 19

4.0 BART Analysis for NO

x ............................................................................................................................................ 20

4.1 NO

x Formation...................................................................................................................................................... 20

4.2 Identification of NO

x Control Technologies and Technical Feasibility ................................................................ 21

4.2.1 Combustion Controls........................................................................................................................................ 21

4.2.2 Post Combustion Control Technologies ........................................................................................................... 21

4.3 Ranking of Technologically Feasible NO

x Controls based on Effectiveness........................................................ 22

4.4 Evaluation of Effective NO

x Controls................................................................................................................... 22

4.4.1 Cost of Compliance .......................................................................................................................................... 22

4.4.2 Energy Impacts ................................................................................................................................................. 22

4.4.3 Non-Air Quality Environmental Impacts.......................................................................................................... 23

4.4.4 Remaining Useful Life...................................................................................................................................... 23

4.5 Visibility Impacts.................................................................................................................................................. 23

5.0 BART Determination for SO 2 and NO

x ..................................................................................................................... 24

5.1 Comments & Response to Comments Received regarding BART............................................................................ 26

6.0 Prevention of Significant Deterioration (PSD).......................................................................................................... 43

6.1 Summary............................................................................................................................................................... 43

6.2 Best Available Control Technology (BACT) Analysis Methodology................................................................... 44

6.3 BACT Analysis for Carbon Monoxide (CO) ........................................................................................................ 44

6.4 Ranking of Technologically Feasible CO Controls based on Effectiveness ......................................................... 46

6.5 BACT for CO........................................................................................................................................................ 46

7.0 Air Dispersion Modeling Analysis ............................................................................................................................ 46

7.1 Model Information................................................................................................................................................ 47

7.1.1 Facility Location and Site Description ............................................................................................................. 47

7.1.2 Model Selection................................................................................................................................................ 47

7.1.3 Source Parameters ............................................................................................................................................ 47

7.2 Preliminary Modeling Analysis............................................................................................................................. 47

7.3 Additional Impacts Analysis ................................................................................................................................. 48

7.3.1 Pollutant Effects on Soil and Vegetation .......................................................................................................... 48

8.0 Type and Quantity of Air Contaminant Emissions Anticipated................................................................................. 48

9.0 Applicable Requirements, Variances or Alternatives to Required Standards............................................................ 49NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 3 of 53 9.1 Nebraska State Construction Permit Requirements............................................................................................... 49

9.2 New Source Performance Standards (NSPS)........................................................................................................ 50

9.3 Particulate Matter Emissions................................................................................................................................. 50

9.4 Sulfur Compound Emissions................................................................................................................................. 51

9.5 Acid Rain .............................................................................................................................................................. 51

9.6 Hazardous Air Pollutants ...................................................................................................................................... 51

9.7 Visibility Protection.............................................................................................................................................. 52

10.0 Discussion of Specific Permit Conditions ................................................................................................................. 52NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 4 of 53 Executive Summary

The Nebraska Department of Environmental Quality (NDEQ) identified the Nebraska Public Power District (NPPD) Gerald Gentleman Station Units 1 and 2 as Best Available Retrofit Technology (BART) eligible and subject sources under the U.S. EPA Regional Haze Program. The Units at Gerald Gentleman Station were identified as either contributing or causing visibility impairment to Class I areas in South Dakota (Badlands and Wind Cave National Parks), Colorado (Rocky Mountain National Park), Oklahoma (Wichita Mountains National Wildlife Refuge), and Missouri (Mingo National Wildlife Refuge and Hercules Glades Wilderness Area). In August 2007, NPPD submitted a BART analysis and permit application to NDEQ. A new, revised analysis, was submitted in March 2008. Since the application of controls was going to result in the increase in other pollutants above the Prevention of Significant Deterioration (PSD) thresholds, a PSD application was submitted. This fact sheet provides a summary of the NDEQ’s evaluation and proposed decision on both BART and Best Available Control Technology (BACT).

This analysis concludes that BART should be the installation and optimization of low-NOx burners with overfire air technology as necessary to meet a limit of 0.23 lb/MMBtu. This analysis also concludes that BART is existing control equipment along with existing limits for particulates (0.1 lb/MMBtu) and that no additional SO 2 controls are warranted due to other environmental impacts and the low benefit to cost ratio.

1.0 Introduction and Purpose

The Clean Air Act (CAA) Amendments of 1990 (Title I, Sections 169A and 169B) declared it a national goal to prevent any future, and to remedy any existing, impairment of visibility in mandatory Class I Federal areas in which impairment results from manmade air pollution. In 1999, the United States Environmental Protection Agency (EPA) issued rules for the protection of visibility in Class I National Parks and Wilderness Areas. Revisions to the regional haze rules were promulgated on July 6, 2005, and October 13, 2006. These rules require states to establish goals for improving visibility by developing long-term strategies for reducing emissions of air pollutants that cause or contribute to visibility impairment. These pollutants include Particulate Matter (PM, both fine and coarse fractions), Sulfur Dioxide (SO 2 ), Nitrogen Oxides (NO

x ), Volatile Organic Compounds (VOC), and Ammonia (NH 3 ). The overall goal of the regional haze program is to achieve natural background visibility conditions in all Class I areas by the year 2064.

1.1 Nebraska Regional Haze Program

Nebraska does not have any Class I National Parks or Scenic areas. However, in accordance with the Regional Haze rules, Nebraska has an obligation to address visibility protection through the application of Best Available Retrofit Technology (BART) on BART subject sources; and promote reasonable further progress if Nebraska source emissions are identified in another State’s Regional Haze State Implementation Plan (SIP). Additionally, Nebraska belongs to and participates in the Central Regional Air Planning Association (CENRAP). Nebraska was asked, and participated in a central-states consultation process for Missouri and

Oklahoma. 1 No other states have asked Nebraska to participate in a collaborative consultation process. No states have yet identified a need for reasonable further progress reductions from Nebraska sources at this time. Therefore, the application of BART is the primary element of the Nebraska Regional Haze program. In the

1 See Missouri’s regional haze plan at http://www.dnr.mo.gov/env/apcp/sips.htm . Missouri named Missouri, Arkansas,

K entucky, Illinois, Indiana, Ohio, Oklahoma, Tennessee and Texas as contributing to visibility impairment at Class I areas in Missouri. Missouri’s analysis indicates that reductions from these states are sufficient to meet reasonable progress goals. Oklahoma’s plan is still under development, but their consultation plan which includes expected reductions may be found at: http://www.deq.state.ok.us/aQDnew/RulesAndPlanning/R egional_Haze/index.htm

.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 5 of 53 future, additional requirements on sources through the application of reasonable further progress may be required for Class I areas to achieve natural background conditions by 2064.

On February 16, 2008, Title 129-Nebraska Air Quality Regulations, of the Nebraska Administrative Code, were revised in order to incorporate numerous changes; including the establishment of Chapter 43: Visibility Protection. This chapter incorporated portions of the federal Regional Haze Rule, including 40 CFR 51.301 and 40 CFR 51 Appendix Y by reference. It also requires owners or operators of stationary sources subject to BART to prepare and submit a BART determination in accordance with the Regional Haze Rule. The rules also require the issuance of a construction permit to the source in accordance with Title 129, Chapter 17. Since the application of BART is required, the BART decisions (i.e. the BART permits) will be explicitly included in Nebraska’s Regional Haze SIP.

On August 8, 2007, the Department received a BART analysis for Nebraska Public Power District (NPPD) Gerald Gentleman Station (GGS), Units 1 and 2. This analysis indicated that Units 1 and 2 would be capable of attaining presumptive BART emissions limitations with the operation of the recently-installed low NO

x burners and over-fire air on Unit 1 and with the proposed addition of low NO

x burners and over-fire air on Unit 2. A revised BART analysis was provided to NDEQ by NPPD on March 3, 2008.

The purpose of this permitting action is to require emission controls in accordance with NDEQ and BART regulations and to permit the increase in other pollutant emissions that result from the installation of the BART controls. To make the BART limitations enforceable, the NDEQ incorporated the BART requirements in a construction permit. The NDEQ has evaluated the following visibility impairing pollutants for purposes of BART: PM (both fine and coarse fractions), SO 2 , and NO

x .

This fact sheet provides a summary of information submitted by NPPD and provides the basis for the Department’s permit decision based on such information and applicable law and regulations. Detailed information can be found in the revised BART analysis received by the Department on March 3, 2008, and subsequent submittals.

1.2 Source Description and Permitting Background

In accordance with state law, Nebraska’s utility structure is currently 100% consumer-owned, also known as “public power.” NPPD is Nebraska’s largest electric utility, serving part or all of 91 of Nebraska’s 93 counties. It was organized as a political subdivision of the State of Nebraska in 1970. Policies and rates are set by an eleven-member Board of Directors elected by the people in the areas served. NPPD provides wholesale power to 52 towns and 25 public power districts, as well as providing retail power to about 80 communities. In all, about 1 million Nebraskans rely on NPPD to supply electricity.

NPPD owns and operates Gerald Gentleman Station (GGS) which is located near Sutherland, Lincoln County, Nebraska, approximately thirty (30) kilometers west of North Platte, Nebraska. The station consists of two pulverized coal-fired boilers that are referred to as Unit 1 and Unit 2. Both units combust sub-bituminous coal with a typical heat content of 8,400 Btu/lb. Construction of the station began in 1973. Unit 1 went into commercial service in 1979 and Unit 2 went into service in 1982. GGS is currently a major source of air emissions under both the Prevention of Significant Deterioration (PSD) program and the Title V operating permits program. Its Standard Industrial Classification (SIC) code is 4911 and North American Industry Classification System (NAICS) code is 221112 for fossil fueled electric generators.

On September 16, 1974 the Department issued an Order (case # 24) to NPPD allowing the construction of Unit 1. Because this boiler pre-dated the PSD program, a PSD construction permit was not issued. On February 9, 1977 the United States Environmental Protection Agency issued a PSD permit to NPPD for construction of Unit 2. As stated in the PSD permit, Best Available Control Technology (BACT) wasNPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 6 of 53 determined to be those limits established in New Source Performance Standard (NSPS) Subpart D. The Department issued an Order (case # 201) to NPPD on March 22, 1977 allowing the construction of Unit 2. The orders issued to NPPD (case # 24 and 201) were modified on February 28, 1979, February 20, 1981, March 12, 1981, March 18, 1985, and April 1, 1985. These Orders and Modified Orders dealt mainly with the

construction of the two units.

GGS is currently operating under a Class I operating permit issued on August 26, 2002, and a Phase II Acid Rain permit effective January 26, 2005. An operating permit renewal application was received by the Department on February 26, 2007.

On January 4, 2006, the Department received a PSD Construction Permit application for the replacement of Unit 1’s burner equipment system including an overfire air port system. NPPD installed new Low NO

x Burners (LNB) on Unit 1 because the existing burners were near the end of their useful life and to be pro-active in installing expected Best Available Retrofit Technology (BART) controls. A PSD construction permit was issued to GGS for the installation of the LNB on Unit 1 on August 18, 2006. A PSD permit was required for the modification due to the expected increase in carbon monoxide emissions as a result of the LNB installation. The August 18, 2006, permit will be superseded as a result of this permitting action once Unit 2 BART controls are operational and Units 1 and 2 demonstrate compliance with the NOx limits. Condition V of the permit establishes a timeframe for achieving this demonstration. Until such time, the CO BACT limits and other conditions of the August 18, 2006 permit remain in effect. Additionally, both Units 1 and 2 will be required to have CO CEMs installed to demonstrate compliance with BACT.

1.3 Gerald Gentleman Station BART Eligibility Analysis

Gerald Gentleman Station Units 1 and 2 were determined to be subject to BART using the criteria outlined in the Clean Air Act and the Regional Haze Rules. The applicability criteria for determining if a unit is eligible for being required to install BART controls are:

1) The facility in which the unit is located contains emissions units in one or more of 26 source categories. One of the listed source categories is fossil-fuel fired steam electric plants of more than 250 million British thermal units per hour (MMBtu/hr) heat input.

 GGS is a fossil-fuel fired steam electric plant of more than 250 MMBtu/hr. Both Units 1 and 2 are each rated at approximately 7,538 MMBtu/hr. Therefore the total heat input capacity at the facility is 15,076 MMBtu/hr. 2) BART eligible units were in existence on August 7, 1977, and began operating after August 7, 1962.

 In existence means “the owner or operator obtained all necessary approvals/permits and has either begun, or caused to begin on-site construction of the facility, or executed binding agreements/contracts for construction.”

 Unit 1 was approved in 1974 and began construction in 1973. Commercial operation began in

1979.

 Unit 2 was permitted/approved by March 1977 and began construction in June 1977. 2
Commercial operation began in 1982. 3) The total potential emissions of visibility impairing pollutant(s) summed across all units that meet the date criteria in item 2 is greater than or equal to 250 tons/year.

 Table 1 presents the baseline actual 24-hour maximum emissions and equivalent maximum annual (365 days of operation at the maximum actual 24-hour rate) emissions from the source prior to requiring BART controls. This shows that the potential emissions from

2 Per Brochure on Gerald Gentleman Station found on NPPD’s GGS website at: http://www.nppd.com/About_Us/Energy_Facilities/facil ities/ggs.aspNPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

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both units (based on maximum 24-hour actual emissions) of particulate matter (coarse and fine), nitrogen oxides (NO

x ), and sulfur dioxide (SO 2 ), all visibility impairing pollutants, are greater than 250 tons/year for each pollutant.

Since all of the three criteria presented above were met, GGS Units 1 and 2 were considered to be BART eligible. In order to determine if GGS Units 1 and 2 are subject to BART requirements, it must be demonstrated that emissions are anticipated to cause or contribute to visibility impairment in one or more Class I areas. This was done by conducting long range transport air dispersion modeling using CALPUFF. If emissions from the BART eligible units at a source will impair visibility in any Class I area more than 0.5 deciview (a measurement of visibility impairment based on extinction of light), then the unit becomes subject to BART.

NPPD conducted air dispersion modeling in accordance with a modeling protocol approved by the Department. The modeling was based on maximum 24-hour emissions for each pollutant, as summarized in the table below. Note that the annual emissions listed are values equivalent to the 24-hour maximum emissions, and do not necessarily represent “potential to emit” values.

Table 1: GGS Units 1 and 2 Emissions Used for Modeling (Baseline Scenario)

PM – Fine PM – Coarse SO 2 NO

x Lb/day Tons/year Lb/day Tons/year Lb/day Tons/year Lb/day Tons/year
6,688 1,221.4 1,170 213.7 272,795 49,785 165,716 30,263.9

The modeling protocol and the modeling results may be obtained from the Department’s website: www.deq.state.ne.us , under the “Regional Haze Program” link under the “Focus on Air” link. The refined CALPUFF modeling analysis concluded that the Pre-BART emissions from GGS Units 1 and 2, before requiring BART controls, cause or contribute to visibility impairment (contributions exceed 0.5 deciview) on eight or more days (98 th

percentile) in a year, at one or more Class I areas, in one or more of the three years (2001-2003) of meteorology evaluated. (See Table 2.) Therefore, GGS Units 1 and 2 were determined to be subject to BART requirements.

Table 2: GGS Visibility Impact (Baseline Scenario)

2001 2002 2003

Days

> 0.5 dV 98 th

Percentile

dV Days

> 0.5 dV 98 th

Percentile

dV Days

> 0.5 dV 98 th

Percentile

dV Badlands (SD) 54 2.845 55 2.828 60 3.121 Great Sand Dunes (CO) 3 0.295 6 0.48 6 0.42 Hercules Glades (MO) 24 0.826 10 0.616 11 0.594 Mingo (MO) 10 0.615 5 0.432 5 0.438 Rocky Mountain (CO) 13 1.136 16 1.246 13 1.053 Wichita Mountains (OK) 28 1.032 27 1.206 29 1.392 Wind Cave (SD) 34 2.452 33 2.591 41 2.217

1.4 BART Analysis Methodology

BART is defined as “...an emissions limitation based on the degree of reduction achievable through the application of the best system of continuous emission reduction of each pollutant which is emitted by an existing stationary source. The emission limitation must be established on a case-by-case basis, taking 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 or in existence at the source, the remainingNPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 8 of 53 useful life of the source, and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology ” (40 CFR Part 51.301).

On July 6, 2005, the US EPA issued guidelines on conducting a BART determination, which are contained in Appendix Y of 40 CFR Part 51. States must follow these guidelines in making BART determinations on a source-by-source basis for 750 megawatt (MW) and larger power plants but are not required to use the process in the guidelines when making BART determinations for other types of BART sources, including those with a total plant capacity less than 750 MW. Therefore Appendix Y has been followed when making the BART determination for GGS in accordance with federal and state regulations.

A BART analysis is comprised of the following basic steps:

Step 1: Identify all retrofit control technologies: All control technologies for similar processes, as well as Best Available Control Technology (BACT) and Lowest Achievable Emission Rate (LAER) technologies must be considered. Control technologies should include pollution prevention, use of add-on controls, and combinations of the two. The owner/operator is not expected to purchase or construct a process or control device that has not already been demonstrated in practice.

Step 2: Eliminate technically infeasible options: Technologies demonstrated to be technically infeasible based on physical, chemical, and engineering principles are excluded from further consideration. Physical modifications needed to resolve technical obstacles do not, by themselves, provide justification to eliminate a technology.

Step 3: Rank remaining technologies by control effectiveness: Technically feasible control technologies are ranked in the order of highest expected emission reduction to lowest expected emission reduction. The ranking also includes expected emission rate, control effectiveness, energy impacts, environmental impacts (including toxic and hazardous air emissions), economic impacts, and visibility impacts.

Step 4: Evaluate most effective controls and document results: The technology ranking is evaluated and case-by-case consideration is given to costs of compliance, energy impacts, non-air quality and other environmental impacts, and remaining useful life of the unit.

Step 5: Evaluate Visibility Impacts: Modeling analyses are performed on the pre- and post-control emissions to determine impact on visibility for each control alternative. Appendix Y states that the visibility improvement for the source as part of the BART determination “must be weighed among the five factors, and you [the state] are free to determine the weight and the significance assigned to each factor.” The NDEQ has evaluated visibility improvement balanced with the cost of compliance in determining the best, most appropriate option for BART as allowed under Appendix Y. This was done through a cost per deciview of visibility improvement factor, which is similar to the cost per ton of pollutant removed from the atmosphere that is used in the BACT process.

1.5 Consideration of Presumptive BART Limitations

Appendix Y also gives consideration to presumptive limitations for SO 2 and NO

x established by EPA. When discussing the presumptive sulfur dioxide limits for utility boilers, Appendix Y states “You [the state] must require 750 MW power plants to meet specific control levels for SO 2 of either 95 percent control or 0.15 lbs/MMBtu, for each EGU [Electric Generating Unit] greater than 200 MW that is currently uncontrolled unless you determine that an alternative control level is justified based on a careful consideration of theNPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 9 of 53 statutory factors...For a currently uncontrolled EGU greater than 200 MW in size, but located at a power plant smaller than 750 MW in size, such controls are generally cost-effective and could be used in your BART determination considering the five factors...” EPA has provided guidance to NDEQ indicating that the five

factors must be evaluated in all cases.

The preamble to the final rule also states {70 FR pg. 39131} “Although we believe that these requirements [presumptive BART levels] are extremely likely to be appropriate for all greater than 750 MW power plants subject to BART, a State may establish different requirements based on a consideration of the five statutory

factors.”

It is clear in 40 CFR 51 Appendix Y that States are afforded the discretion to set limits different than the presumptive levels for NO

x and SO 2 , if careful consideration is given to the statutory factors. Based on the controlling Appendix Y language and preamble guidance, the State of Nebraska will consider the five statutory factors when establishing BART controls and may not require the presumptive BART limitations if an alternative level of control is justified.

1.6 Averaging Emission Limitations

Appendix Y allows averaging of emissions across any set of BART emission units within a fence line. Appendix Y states, “You [the state] should consider allowing sources to ‘‘average’’ emissions across any set of BART-eligible emission units within a fence line, so long as the emission reductions from each pollutant being controlled for BART would be equal to those reductions that would be obtained by simply controlling each of the BART-eligible units that constitute BART-eligible source” {40 CFR Appendix Y, V. Enforceable Limits/Compliance Date}

2.0 BART Analysis for Particulate Matter (both fine and coarse fractions)

The objective of this analysis is to determine BART for PM emissions from the GGS Units 1 and 2.

2.1 Particulate Matter (PM) Formation

PM emissions from utility boilers are a function of the boiler burner configuration, operation practices, coalproperties, and pollution control equipment. Uncontrolled PM emissions include ash from the noncombustibles in coal as well as unburned carbon resulting from incomplete combustion. When combusting pulverized coal, PM emissions are primarily composed of inorganic ash residue because combustion is nearly complete, resulting in minimal unburned carbon.

PM emissions are classified as filterable and condensable. Filterable PM is the portion of total PM present in the exhaust stream as a solid or liquid, which is typically measured on an EPA Method 5 filter (40 CFR Part 60, Appendix A). Condensable PM is the portion of PM that is initially present as a gas in the exhaust stream, but condenses to a liquid or solid state when cooled to ambient temperatures.

For purposes of BART, coarse PM (PMC) and fine PM (PMF) are analyzed in the visibility impact modeling. PMF is defined as having an aerodynamic diameter of less than or equal to 2.5 microns (PM 2.5 ). PMC has an aerodynamic diameter greater than PM 2.5 but less than or equal to 10 microns.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 10 of 53 2.2 BART for PM

Step 1: Identify all retrofit control technologies: Control of PM emissions can be achieved by application of good combustion practices (i.e. complete combustion) or by treatment of the flue gas after combustion. GGS Units 1 and 2 currently utilize fabric filters (baghouses) to control PM emissions.

Step 2: Eliminate technically infeasible options: Additional baghouses could be added, but would be redundant.

Step 3 through 5: Rank remaining technologies by control effectiveness; Evaluate most effective controls and document results; and Evaluate Visibility Impacts: Step 5, Evaluate Visibility Impacts was done first to see at what level PM was contributing to visibility. If PM was found to be a significant portion of the contribution, then further ranking of technologies would be warranted. If PM was found to be a very small or insignificant portion of the overall visibility contribution from GGS, then further evaluation of control technology would not be warranted at this time.

The maximum 24-hour emission rates of PMF and PMC from GGS Units 1 and 2 are presented below. These baseline emission rates were utilized in the visibility modeling conducted.

Table 3: Particulate Matter Emissions

PM – Fine PM – Coarse Lb/day Tons/year Lb/day Tons/year
6,688 1,221.4 1,170 213.7

The baseline case model indicated that the direct particulate emissions (PMF + PMC) were responsible for well under 1% of the total predicted change in deciview impact from GGS Units 1 and 2 (See Table 4). A deciview is a haze index derived from calculated light extinction, such that uniform changes in haziness correspond to uniform incremental changes in perception across the entire range of conditions, from pristine to impaired. This would indicate that the predicted deciview impact is from a pollutant or pollutants other than PM, specifically NOx and/or SO 2 . The results for each year, by Class I area, are presented below. The 98% percentile value is presented for each year. The results below confirm that GGS Units 1 and 2 are subject to BART due to their deciview impact, but the direct particulate matter emissions do not significantly contribute to visibility impairment in the Class I areas analyzed.

Table 4: Particulate Matter Contribution of GGS Predicted Visibility Impairment

2001 2002 2003

dV % PM PM

dV impact dV % PM PM

dV impact dV % PM PM

dV impact Badlands (SD) 2.845 0.66% 0.0188 2.828 0.47% 0.0133 3.121 0.69% 0.0215

Great Sand Dunes (CO) 0.295 0.56% 0.0017 0.480 0.26% 0.0012 0.420 0.27% 0.0011

Hercules Glades (MO) 0.826 0.33% 0.0027 0.616 0.43% 0.0026 0.594 0.40% 0.0024

Mingo (MO) 0.615 0.19% 0.0012 0.432 0.22% 0.0095 0.438 0.36% 0.0016 Rocky Mtn (CO) 1.136 0.48% 0.0055 1.246 0.42% 0.0052 1.053 0.22% 0.0023 Wichita Mtns (OK) 1.032 0.58% 0.0060 1.206 0.48% 0.0058 1.392 0.43% 0.0060 Wind Cave (SD) 2.452 0.67% 0.0164 2.591 0.68% 0.0176 2.127 0.41% 0.0087NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 11 of 53 Based on the fact that GGS Units 1 & 2 are currently adequately controlled by baghouses, are subject to an emissions limitation of 0.1 lb/MMBtu (Title V OP), and the modeling results indicate that direct particulate emissions do not significantly contribute to visibility impairment in Class I areas, the NDEQ has determined that BART for PM shall be existing controls and requirements.

3.0 BART Analysis for SO 2

The objective of this analysis is to determine BART for SO 2 emissions from GGS Units 1 and 2. Generally there are two approaches to controlling SO 2 emissions: removal of elemental sulfur from the fuel prior to combustion, and flue gas desulfurization (FGD). FGD consists of removal of SO 2 from the flue gases after

combustion.

3.1 SO 2 Formation

SO 2 emissions are formed from the oxidation of organic and pyritic sulfur in the coal during the combustion process. The majority of sulfur is oxidized to SO 2 ; however a small quantity is further oxidized to form sulfur trioxide (SO 3 ). Approximately 90% of the sulfur present in the subbituminous coal will be emitted as SO

x compounds. Alkaline ash from some coals (including Powder River Basin coals) may cause some of the sulfur to react in the furnace to form various sulfate salts that are then retained in the fly ash or bottom ash. Sulfuric acid mist (H 2 SO 4 ) forms when SO 3 emissions combine with combustion-related moisture, or when SO 2 is

oxidized to SO 3 in the atmosphere. This SO 3 will also combine with water in the atmosphere to form H 2 SO 4 , which typically reacts further with ammonia in the air to form fine particulate matter in the form of ammonium

sulfates.

3.2 Identification of SO 2 Control Technologies and Technical Feasibility

3.2.1 Sulfur Removal from Fuel

A significant fraction of the sulfur in coal is in the form of pyrite (FeS 2 ) or some other mineral sulfates. Mineral sulfates can be removed through washing or other physical cleaning; however organic sulfur cannot be removed by physical cleaning. Sulfur removal from low-sulfur Powder River Basin (PRB) coal has not been demonstrated. NPPD uses PRB coal at GGS. Since this technology has not been demonstrated and it would not be cost effective to attempt a form of physical cleaning or chemical desulfurization, coal sulfur removal is

considered to be infeasible at this time.

3.2.2 Flue Gas Desulfurization (FGD)

FGD consists of removal of SO 2 from the flue gases after combustion. FGD technologies can be divided into two main categories, regenerative and throwaway processes. Regenerative processes recover sulfur in a usable form that can be sold as a reusable sulfur product. Throwaway processes remove sulfur from the flue gas and the byproducts are discarded. The FGD technologies considered may be able to achieve SO 2 removal efficiencies up to 90 to 95%, depending on the amount of sulfur in the coal. For relatively high sulfur coals (such as eastern bituminous coal), removal efficiencies of over 95% can be reached, while for lower sulfur coals (such as PRB), the achievable removal efficiency is typically less than 95%.

3.2.2.1 Regenerative Processes Regenerative processes, by nature, contain a regeneration step in the FGD process that results in higher costs than throwaway processes due to equipment and operational expenses. However, in instances where disposal options are limited and markets for recovered sulfur products are readily available, regenerative processes might be cost effective. Potential regenerative processes include the Wellman-Lord (W-L) process, magnesiumNPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 12 of 53 oxide process, citrate scrubbing process, Flakt-Boliden process, aqueous carbonate process, Sulf-X process, Conosox process, Westvaco process, and adsorption of SO 2 by a bed of copper oxide.

A new regenerative process that was developed as an indirect result of collaborative research with the former U.S. Bureau of Mines and the University of Minnesota is the Pahlman process. The Pahlman process is a dry removal technology that can remove multiple pollutants (NO

x and SO 2 ) at efficiencies greater than 99%. As a regenerative process, the Pahlman process purportedly reduces problems associated with waste disposal and creates a commercially valuable byproduct. In the closed-loop process, the Pahlmanite sorbent repeatedly captures NO

x and SO 2 , which upon regeneration, yields raw sulfates and nitrates. The Pahlman process is new technology that has been pilot tested at several industrial sites, including smaller coal-fired electrical generating plants.

None of the regenerative processes identified above have been demonstrated on large coal-fired boilers and for long enough periods to allow estimates of annualized costs. Therefore, it is not possible to demonstrate cost effectiveness for a regenerative process on GGS at this time. Therefore, all regenerative technologies have

been determined to be infeasible at this time.

3.2.2.2 Throwaway Processes - Wet and Dry FGD Throwaway process have become widely accepted by the coal-fired power industry for FGD because they have lower overall costs and are simpler to operate than regenerative processes. Throwaway processes can achieve the same removal efficiencies as regenerative processes and cost less. Throwaway processes can be divided into two categories, wet or dry. Wet or dry refers to the state of the waste by-products. Both wet and dry technologies have advantages and disadvantages with respect to initial capital and operational expenses.

Wet FGD Wet scrubbing systems used for SO 2 reduction typically consist of the following operations: scrubbing or absorption, lime handling and slurry preparation, sludge processing, and flue gas handling. Wet FGD technology is a well established process for removing SO 2 from flue gas. Many utilities can also offset operating costs of wet FGD by selling one of the by-products, calcium sulfate (gypsum), to wallboard manufacturing facilities. Although gypsum can be sold, due to the rural and remote location of GGS, there is little local demand for it near GGS, so NPPD could not take advantage of the cost offset. However, wet scrubbing is a feasible technology for SO 2 control from GGS Units 1 and 2.

Dry FGD Dry FGD is a well established process for removing SO 2 from flue gas. Many modern dry FGD systems include a loop to recycle a portion of the baghouse-collected material for re-use in the FGD module because this material contains a relatively high amount of unreacted lime. If NPPD would be required to install dry FGD, the existing baghouses would require significant augmentation. However, dry scrubbing is a feasible

t echnology for SO 2 control from GGS Units 1 and 2.

3.3 Ranking of Technologically Feasible SO 2 Controls based on Effectiveness

Wet and dry scrubbing are feasible technologies for SO 2 control. Effectiveness is measured by the amount of

SO 2 removed by each control technology based on a comparison of the controlled emission rates to the uncontrolled baseline emission rate of GGS Units 1 and 2. In this case, it is anticipated that the same level of

SO 2 control can be achieved by the use of either wet or dry FGD. The presumptive BART limit in 40 CFR Appendix Y for electrical generation units above 200 MW at plants greater than 750 MW in capacity is 0.15 lb/MMBtu. However, the NDEQ estimated that both technologies could achieve a lower emissions rate of 0.1

lb/MMBtu on a consistent basis.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 13 of 53 Based on the maximum actual 24-hr SO 2 emissions over a three year baseline period (2001-2003) of 0.749 lb/MMBtu, together with assumed continuous, maximum operation at 15,175.5 MMBtu/hr, the potential maximum annual emissions would be equal to 49,785 tons/year. At the presumptive BART level (0.15 lb/MMBtu) it is estimated that up to 39,815 tons/year would be removed from the flue gas and not emitted into the atmosphere if either dry or wet scrubbing was employed. At an emissions rate of 0.1 lb/MMBtu, it is estimated up to 43,138 tons/year would be removed from the flue gas and not emitted into the atmosphere if wet or dry scrubbing was employed.

3.4 Evaluation of Effective SO 2 Controls

In order to evaluate the effectiveness of the SO 2 control options, NDEQ considered: cost of compliance, energy impacts, non-air quality environmental impacts, and the remaining useful life of the units.

3.4.1 Cost of Compliance

NPPD provided detailed cost information associated with the installation of both a wet FGD and a dry FGD system. The costs utilized in the analyses were based on a site-specific engineering analysis of how much it would cost to retrofit GGS. NPPD used vendor quotes for the majority of the analysis. This approach is allowed by Appendix Y and supplements the guidance contained in the EPA’s OAQPS Control Cost Manual. Appendix Y states that in evaluating cost effectiveness, both the average cost effectiveness (total annualized costs of control divided by annual emissions reductions) and incremental cost effectiveness (dollars per incremental ton) should be evaluated.

The evaluated costs associated with wet FGD installation included, but are not limited to, installing a wet limestone forced oxidation FGD system on both Units 1 & 2, Units 1 & 2 common equipment (reagent preparation and handling, solids dewatering and handling), auxiliary power system, ID Booster fan equipment, and operating costs. Detailed information may be found in the supporting materials provided by NPPD.

The total annualized cost associated with the installation of Wet FGD at GGS is $108,450,000. The average cost effectiveness of this control technology is $2,724 per ton SO 2 removed ($108,450,000 / 39,815 tons SO 2 removed) based on an emissions rate of 0.15 lb/MMBtu. The average cost effectiveness of this control technology at an emissions rate of 0.1 lb/MMBtu is approximately $2,514 per ton SO 2 removed ($108,450,000/43,138 tons SO 2 removed). The annualized cost for this alternative may be slightly higher than stated here, due to slightly more reagent usage as compared to the 0.15 lb/MMBtu control level.

The costs evaluated associated with dry FGD installation included, but are not limit ed to, installing a spray dryer absorber FGD system on both Units 1 & 2, Units 1 & 2 common equipment (reagent preparation and handling, solids dewatering and handling), auxiliary power system, ID Booster fan equipment, and operating costs. The total annualized cost associated with the installation of Dry FGD is $108,517,000. The cost effectiveness of this control technology is $2,726 per ton SO 2 removed ($108,517,000 / 39,815 tons SO 2 removed) based on an emissions rate of 0.15 lb/MMBtu. The average cost effectiveness of this control technology at an emissions rate of 0.1 lb/MMBtu is approximately $2,516 per ton SO 2 removed ($108,517,000/43,138 tons SO 2 removed). As with wet FGD, meeting the lower emission rate may cost slightly more than stated here due to higher reagent usage.

The cost per ton removal estimated is in line with what EPA estimated for GGS. S ince additional control options are not feasible, analyzing the incremental cost effectiveness for SO2 controls is not necessary.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 14 of 53 3.4.2 Energy Impacts

If Wet FDG was employed, 2.7% (36 MW) of the units’ generating capacity would be utilized to operate the control equipment. Thirty-six megawatts is equivalent to the power utilized by approximately 36,000 homes.

If Dry FDG was employed, 1.9% (26 MW) of the units’ generating capacity would be utilized to operate the control equipment. Twenty-six megawatts is equivalent to the power utilized by approximately 26,000 homes.

The energy costs were included in the BART analysis costs above.

3.4.3 Other (Non-Air Quality) Environmental Impacts

N on-air quality environmental impacts associated with the installation of a Wet FGD include disposal of a solid waste in the form of gypsum and a liquid waste stream which must be disposed of via an evaporator system or in a disposal pond. O&M costs for wet FGD waste disposal were included in the cost analysis, but given uncertainties in costs, capital costs for permitting, possible land acquisition, and construction of pond and landfill disposal units were not included in the BART cost analysis at this time, making the cost estimates conservatively low.

Non-air quality environmental impacts associated with the installation of a Dry FGD include disposal of solid waste in the form of fly ash. The fly ash will be intermixed with lime and be unsuitable for third party use and will have to be landfilled, or otherwise appropriately disposed. In 2008, NPPD marketed over 75,000 tons of fly ash from GGS. O&M costs for dry FGD waste disposal were included in the cost analysis, but given uncertainties in costs; capital costs for permitting, possible land acquisition, and construction of a separate landfill disposal unit were not included in the BART cost analysis at this time, making the cost estimates conservatively low.

A significant non-air quality environmental impact for NPPD, if either control technology is required, regards water use and impacts on the habitats of endangered species.

3.4.3.1 Potential Impacts on Water In 2004, the Nebraska Legislature enacted LB 962, which went into effect in July 2004. This law required the Department of Natural Resources (DNR) to identify geographic areas where surface water and ground water are hydrologically connected. The law was designed to manage water resources through the identification of riverbasins where water resources were already fully-appropriated and other areas where the basins were overappropriated. Once a river basin has been designated, each Natural Resource District (NRD) must work in conjunction with the Nebraska DNR to develop an Integrated Management Plan (IMP) to either make certain the basin does not become over-appropriated or recharge the water resources in a manner such that the basin is no longer over-appropriated. The concept is analogous to the air quality state implementation planning process for non-attainment or attainment areas. The development of the basin IMP may take three to five years. The GGS Station is located within the Twin Platte NRD area. Below are maps detailing the relationship between the surface water and ground water in the area, the areas that have been identified as being fully-appropriated or over-appropriated, and the areas within the Twin Platte NRD that are currently under a stay for the construction of new high capacity (> 50 gallons/min) water wells and increasing irrigated acres (effective June 18, 2007).NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 15 of 53NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 16 of 53NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 17 of 53NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 18 of 53 It is clear from these maps that GGS is located in the affected areas. Both scrubbing technologies require a significant amount of consumptive water use in order to operate. A wet FGD would require approximately 1,200 gallons/min and a dry FGD would require 1,000 gallons/min for each unit to operate. Being that GGS is located in an area currently designated as over-appropriated for water usage by the Twin Platte NRD, it would be difficult to acquire the water rights necessary to operate either type of control and the costs would be substantial. The cost estimates below are provided in 2009 actual dollars.

Wet FGD If wet FGD systems were installed on both units, the estimated consumption of 2,400 gallons/min would require approximately 3,881 acre feet of water per year. Retiring irrigated corn ground would offset about 12 inches of water per acre, or 1 acre foot/acre, resulting in the need to acquire 3,881 acres. In order to obtain the acres needed, rights would have to be acquired for parcels of land somewhat larger than the actual irrigated acres, so it is assumed that 4,000 acres would be needed. Cost estimates to purchase irrigated crop ground in the North Platte area are based on recent purchases and appraisals. For this analysis, $3,000 per acre is the price assumed for purchasing irrigated land. The total cost for acquiring 4,000 acres of land at $3,000 per acre would be $12

million.

An impact to the local area would be the lost crop production from the land. Based on a 200 bushel/acre loss in corn production and assuming a price of $4 per bushel, the impact would be about $3.2 million per year, or $64 million over 20 years. This is assuming no escalation in corn prices over the next 20 years.

Loss of property tax revenue would also impact the county. If NPPD were to purchase 3,881 acres, taxes would be reduced by an estimated $100,000 per year or $2 million over 20 years. This is assuming no escalation in taxes over the next 20 years.

Dry FGD If dry FGD systems were installed on both units, the estimated consumption of 2,000 gallons/min would require approximately 3,226 acre feet of water or offset from 3,226 acres per year. In order to obtain the acres needed, rights would have to be acquired for parcels of land somewhat larger than the actual irrigated acres. Assuming that 3,300 irrigated acres would need to be purchased at $3,000 per acre, the total cost would be $9.9 million.

Lost crop production from the land would be about $2.6 million per year, or $52.8 million over 20 years, assuming a price of $4 per bushel. This is assuming no escalation in corn prices over the next 20 years.

Loss of property tax revenue would also impact the county. If NPPD were to purchase 3,300 acres, taxes would be reduced by an estimated $82,500 per year or $1.7 million over 20 years. This is assuming no escalation in taxes over the next 20 years.

3.4.3.2 Potential Impacts to Endangered Species: In July 1997, the State of Nebraska entered into an agreement with neighboring states, Colorado and Wyoming, and the Department of Interior to conduct research and other efforts related to the habitats of threatened and endangered species within the Platte Rivers area. This agreement was recently succeeded with another cooperative agreement in October 2006 called “The Platte River Recovery Implementation Program.” 3 The purpose of this second cooperative agreement is to implement certain aspects of the U.S. Fish and Wildlife Service’s (FWS’) recovery plans for the target species, including the Piping Plover, Whooping Crane, Least Tern, and Pallid Sturgeon. The program involves basin-wide cooperative approaches including, but not limited

3 More information about the Platte River Recovery Implementation Program may be found at: http://platteriverprogram.org/default.aspx

.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 19 of 53 to mitigating adverse impacts of new water related activities. New water related activities are those new surface water or hydrologically connected groundwater activities, implemented after July 1, 1997, which may affect the quantity or timing of water reaching the associated habitats. Drilling of new water wells for purposes of consumptive use, such as those needed for FGD, appear to be a new water related activity. The NDEQ has considered the potential non-air quality environmental impacts and the importance of protecting the habitats of endangered and threatened species along the Platte River Basin in its decision whether to require FGD. Any costs associated with mitigating or offsetting additional GGS water use to protect threatened and endangered species are unknown at this time, and therefore have not been factored into the BART analysis.

3.4.4 Remaining Useful Life

The useful remaining life of GGS Units 1 and 2 is greater than 20 years under the current NPPD energy resource plan. Therefore the remaining useful life has no impact on the annualized estimated control technology cost at this time.

3.5 Visibility Impacts

Air dispersion modeling using CALPUFF was conducted to determine the impact on visibility from GGS Units 1 and 2 at several Class I areas. The highest impacts were observed at Badlands in South Dakota. The second highest were in Wind Cave in South Dakota, which is just west of the Badlands. Badlands is the Class I area closest to GGS at approximately 300 km. Improvements seen at the Badlands are expected to be seen at Wind Cave as well. 40 CFR Appendix Y says that if the highest modeled effects are at the nearest Class I area, states may choose not to analyze the other Class I areas any further. Additional analyses beyond the Badlands are unwarranted because controls on the GGS Units 1 and 2 will not likely exhibit greater visibility improvement than what is predicted in the Badlands. Furthermore, model accuracy is highly uncertain at distances greater than 200 km. Table 5 shows the modeled incremental visibility effectiveness of SO 2 control options, based on the estimated impacts at the Badlands.

Included in the analysis is an evaluation of putting the control cost into perspective as they relate to visibility impairment. Two metrics were used, cost per deciview of improvement ($/yr/dV) and cost per days of deciview improvement.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 20 of 53 Table 5: Incremental Visibility Effectiveness ( SO 2 Controls)

2001 2002 2003

Control Option Class I Area with Greatest Impact from GGS Badlands Badlands Badlands

SO 2 Modeled Emission Rate (lb/MMBtu) 0.749 0.749 0.749

Modeled 98 th

Percentile Value (dV) 2.845 2.828 3.121Baseline(no SO2Control)

Number of Days Exceeding 0.5 dV 54 55 60

Modeled 98 th

Percentile Value (dV) 1.836 2.125 2.478

Incremental Visibility Impairment Improvement ( ∆ dV) 1.009 0.703 0.643

Number of Days Exceeding 0.5 dV 36 35 39

Incremental Impairment Improvement Cost ($/yr/ ∆ dV) [1] $107,482,656 $154,267,425 $168,662,519FGD Control Added(0.15 lb/MMBtu)

Incremental Cost per Day of Improvement $6,025,000 $5,422,500 $5,164,286

Modeled 98 th

Percentile Value (dV) 1.790 2.026 2.443

Incremental Visibility Impairment Improvement ( ∆ dV) 1.055 0.802 0.678

Number of Days Exceeding 0.5 dV 33 33 36

Incremental Impairment Improvement Cost ($/yr/ ∆ dV) [1] $102,796,208 $135,224,439 $160,428,994FGD Control Added(0.10 lb/MMBtu)

Incremental Cost per Day of Improvement $5,164,286 $4,929,545 $4,518,750

[1] Total annualized cost / Incremental visibility impairment improvement

4.0 BART Analysis for NO

x

T he objective of this analysis is to determine BART for NO

x emissions from GGS Units 1 and 2. Generally there are two approaches to controlling NO

x emissions: combustion controls and/or flue gas treatment (postcombustion) technologies. Combustion control processes can reduce the quantity of NO

x formed during the combustion process. Post-combustion technologies reduce the NO

x concentrations in the flue gas stream after

the NO

x has been formed in the combustion process. These methods may be used alone or in combination to achieve various degrees of NO

x emission reductions.

4.1 NO

x

F ormation

There are two primary mechanisms of NO

x formation in coal-fired utility boilers: thermal production of NO

x from atmospheric nitrogen and oxygen and oxidation of nitrogen bound in the fuel. High combustion temperatures cause the nitrogen (N 2 ) and oxygen (O 2 ) molecules in the combustion air to react and form NO

x . Because the thermal NO

x production is primarily a function of combustion temperature and residence time, NO

x emission rates vary greatly with burner design. Experimental measurements of thermal NO

x formation haveNPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 21 of 53 shown that the NO

x concentration is exponentially dependent on temperature and is proportional to nitrogen concentration in the flame, the square root of oxygen concentration in the flame, and the gas residence time.

The formation of fuel NO

x from reactions of fuel bound nitrogen and air, can account for up to 80% of the total

NO

x from coal combustion. Subbituminous coals contain from 0.5% -2% percent by weight fuel-bound nitrogen.

4.2 Identification of NO

x C ontrol Technologies and Technical Feasibility

4.2.1 Combustion Controls

Combustion controls such as Flue Gas Recirculation (FGR), Reducing Air Preheat temperature (RAP), Oxygen Trim (OT), Low Excess Air (LEA), Over-Fire Air (OFA), Staged Combustion Air (SCA), and Low NO

x Burners (LNB), can be used to reduce NO

x emissions depending on the type of boiler, characteristics of fuel, and method of firing. New developments in LNB technologies have demonstrated substantial reductions in

NO

x formation. GGS Unit 1 was recently permitted to install LNB/OFA. This project has been completed;

however a lower NO

x limit was not required by that permitting action. Combustion controls are able to be used on industrial and utility boilers and are considered to be feasible technologies for NO

x control from GGS Units

1 and 2.

4.2.2 Post Combustion Control Technologies

4.2.2.1 Selective Catalytic Reduction Selective Catalytic Reduction (SCR) systems are an add-on flue gas treatment to control NO

x emissions. The SCR process involves the injection of a nitrogen-based reducing agent such as ammonia (NH 3 ) or urea (CON 2 H 4 ) to reduce the NO

x in the flue gas to N 2 and H 2 O. The reagent is injected into the flue gas prior to passage through a catalyst bed which accelerates the NO

x reduction reaction rate. Use of SCR results in small

levels of NH 3 emissions, and as the catalyst degrades, the NH 3 emissions will increase. This phenomenon is

known as the NH 3 slip. SCR is a proven technology and is a feasible NO

x control technology for GGS Units 1 and 2. Although SCR is a feasible control technology, it would be most practical to install SCR in combination

with combustion controls. This is because if NO

x formation was not reduced upstream of the SCR system, the amount of catalyst required would be higher, subjecting more catalyst to degradation. The amount of ammonia required would also be higher, increasing the capital and O&M costs of SCR significantly. Also, reagent costs would be significantly higher if LNB/OFA were not used to minimize NO

x emissions before treatment with the SCR system. Therefore, the cost associated with installing LNB/OFA is linked to this control technology throughout the analysis.

4.2.2.2 Selective Non-Catalytic Reduction The Selective Non-Catalytic Reduction (SNCR) process involves the injection of a nitrogen-based reducing agent such as NH 3 or urea to reduce the NO

x in the flue gas; however a catalyst is not used. Instead the SNCR process occurs within the upper reaches of a combustion unit, which acts as the reaction chamber. Flue gas temperatures in the range of 1,500 to 1,900 degrees Fahrenheit, along with adequate reaction time within this temperature range, are required for this technology. SNCR is a proven technology and is in commercial use on utility boilers, and therefore, is generally considered a feasible NO

x control technology for these types of emissions sources. However, there are situations where SNCR has limited applicability, such as in the case of GGS Units 1 and 2. Due to the high temperatures experienced at the furnace exit, ammonia injection would have to occur far down stream in the convection section when combustion gases have cooled more. In addition, the location of the appropriate temperature zone would fluctuate with levels of fouling, unit load, and other conditions, requiring multiple injection points with a dynamic determination of the appropriate injection point. This would mean significantly lower residence time in the appropriate temperature window, high ammonia “slip,” and non-sufficient NO

x control by this method. Due to the reasons discussed above, SNCR has been

determined to be infeasible at this time.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 22 of 53 4.3 Ranking of Technologically Feasible NO

x Controls based on Effectiveness

Combustion controls and SCR are feasible technologies for NO

x control. Effectiveness is measured by the

amount of NO

x removed by each control technology based on a comparison of the controlled emission rates to the uncontrolled baseline emission rate of GGS Units 1 and 2. It is generally not practical to install higher efficiency NO

x control technologies without first optimizing combustion controls. Reducing the concentration

of NO

x to be controlled provides the benefit of longer catalyst life and less reagent usage for add-on NO

x control technologies. LNB/OFA will be evaluated as the first level of NO

x control, and then SCR with the LNB/OFA system as the second level of NO

x control.

Based on the maximum actual 24-hr NO

x e missions over a three year baseline period (2001-2003), together with assumed continuous operation, the maximum annual emissions would be equal to 30,243 tons/year. If LNB/OFA was employed, the NO

x emissions limitation would be established at 0.23 lb/MMBtu which is the presumptive BART limitation in Appendix Y for this source type. If only LNB/OFA were required for BART, it is estimated that reduction of 14,956 tons/year of NOx emissions would be realized. If SCR and LNB/OFA was installed, an emissions limitation of 0.08 lb/MMBtu would be established, equating to 24,926 tons/year of

NO

x reductions from GGS Units 1 and 2. By installing both an SCR system in conjunction with LNB/OFA,

NO

x would be controlled more efficiently than with a stand-alone SCR system.

4.4 Evaluation of Effective NO

x C ontrols

The cost of compliance, energy impacts, non-air quality impacts, and remaining useful life of the unit were all evaluated for purposes of determining if either, both, or none of the feasible control options should be required

for BART.

4.4.1 Cost of Compliance

NPPD provided detailed site-specific cost information associated with the installation of LNB/OFA with and without the installation of an SCR system. The costs utilized in the analyses were based on site-specific engineering analysis (based mainly upon data supplied by equipment vendors) of how much it would cost to retrofit GGS. This approach is allowed by 40 CFR Appendix Y and supplements the guidance contained in the EPA’s OAQPS Control Cost Manual. Appendix Y states that in evaluating cost effectiveness, both the average

cost effectiveness and incremental cost effectiveness should be evaluated.

The capital cost included the costs associated with the burner modification (installation of LNB/OFA and over fire air modification), SCR equipment, ID Booster fan equipment, air heaters, and electrical modifications. Operating costs were also considered.

The total annualized cost associated with the installation of LNB/OFA is $2,960,000. The cost effectiveness of LNB/OFA is $198 per ton NO

x removed ($2,960,000 / 14,956 tons NO

x removed).

The total annualized cost associated with the installation of LNB/OFA and SCR is $57,251,000. The cost effectiveness of LNB/OFA and SCR is $2,297 per ton NO

x removed ($57,251,000 / 24,926 tons NO

x removed).

The incremental cost effectiveness calculation compares the costs and perform ance level of a control option to those of the next most stringent option. The incremental cost analysis of installing LNB/OFA and SCR as opposed to LNB/OFA alone is $5,445 ([$57,251,000 - $2,960,000] / [24,926 – 14,956]).

4.4.2 Energy Impacts

T here is no significant energy penalty associated with the use of modern LNB/OFA.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 23 of 53 If SCR was employed, 0.7% (10 MW) of the units’ generating capacity would be utilized to operate the control equipment. Ten megawatts is equivalent to the power utilized by approximately 10,000 homes. The energy impacts have been included in the BART analysis costs.

4.4.3 Non-Air Quality Environmental Impacts

There are no non-air quality related impacts associated with the use of modern LNB/OFA.

Non-air quality environmental impacts associated with the installation of an SCR include disposal of solid waste in the form of fly ash. The fly ash will be intermixed with ammonia and be unsuitable for third party use and would have to be landfilled. The potential risk of a hazardous spill due to transport and storage of ammonia

would also be created if an SCR was installed.

4.4.4 Remaining Useful Life

The useful remaining lives of GGS Units 1 and 2 are greater than 20 years under the current NPPD energy resource plan. Therefore the remaining useful life has no impact of the annualized estimated control technology

cost at this time.

4.5 Visibility Impacts

Air dispersion modeling using CALPUFF was conducted to determine the impact on visibility from GGS Units 1 and 2 at several Class I areas (See Table 6). The highest impacts were observed at Badlands in South Dakota. The second highest were in Wind Cave in South Dakota, which is adjacent to the Badlands. Badlands is the Class I area closest to GGS at approximately 300 km. Improvements seen at the Badlands are expected to be seen at Wind Cave as well. 40 CFR Appendix Y says that if the highest modeled effects are at the nearest Class I area, states may choose not to analyze the other Class I areas any further. Additional analyses beyond the Badlands are unwarranted because controls on the GGS Units 1 and 2 will most likely not exhibit greater visibility improvement than what is predicted in the Badlands. Furthermore, model performance is highly uncertain at distances greater than 200 km.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 24 of 53 Table 6: Incremental Visibility Effectiveness (NOx C ontrols)

2001 2002 2003

Control Option Class I Area with Greatest Impact from GGS Badlands Badlands Badlands

Modeled 98 th

Percentile Value (dV) 2.845 2.828 3.121Baseline0.458 lb/MMBtu

Number of Days Exceeding 0.5 dV 54 55 60

Modeled 98 th

Percentile Value (dV) 2.224 2.162 2.419

Incremental Visibility Impairment Improvement ( ∆ dV) 0.621 0.666 0.702

Number of Days Exceeding 0.5 dV 49 52 54

Incremental Impairment Improvement Cost ($/yr/ ∆ dV) [1] $4,766,506 $4,444,444 $4,216,524LNB/OFA Control Added(0.23 lb/MMBtu)

Incremental Cost per Day of Improvement $592,000 $986,667 $493,333

Modeled 98th Percentile Value (dV) 1.732 1.728 1.879

Incremental Visibility Impairment Improvement ( ∆ dV) 0.492 0.434 0.540

Number of Days Exceeding 0.5 dV 44 41 48

Incremental Impairment Improvement Cost ($/yr/ ∆ dV) [1] $110,347,561 $125,094,470 $100,538,889LNB/OFA and SCRControls Added (0.08lb/MMBtu)

Incremental Cost per Day of Improvement $10,858,200 $4,935,545 $9,048,500

[1] Total annualized cost / Incremental visibility impairment improvement

5.0 BART Determination for SO 2 an d NO

x

Scrubber technology is a technically feasible SO 2 r etrofit technology that could be implemented on GGS Units 1 and 2. Not taking the other environmental effects, except energy, into account, the average cost effectiveness of using scrubbing control technology is approximately $2,500 – $2,700 per ton SO 2 removed. The cost per ton removed seems reasonable. When evaluating the cost effectiveness in terms of the visibility benefit derived from scrubbing, the NDEQ assessed the average incremental visibility impairment improvement. The NDEQ also calculated the incremental cost per day of visibility improvement.

Over the three years of meteorology modeled, at 0.10 lb SO 2 /MMBtu, the average incremental visibility impairment improvement cost is $132,816,547 per year per change in deciview impact. The average number of

da ys the Badlands would expect to experience a contribution from GGS of greater than 0.5 dV would be 22 per year. This is a 39% reduction in the 56 days per year that the units contribute more than 0.5 dV. The average incremental cost per day of visibility improvement calculates to be $4,870,860 per day ($2,435,430 per unit). Again, these values do not account for the added costs that would be incurred from other environmental impacts, except energy. These values are of the same magnitude as the OPPD Nebraska City Unit #1 BARTNPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 25 of 53 evaluation. There, NDEQ determined that additional SO 2 controls were not reasonable, in part due to the excessive cost per benefit in terms of visibility improvement (i.e., $/yr/dV).

Here in the case of NPPD GGS Units #1 and #2, NDEQ has serious concerns over the current availability of water to supply the scrubber and the potential affects the depletion of water on threatened and endangered species in the Platte River Valley area. Since the incremental visibility impairment improvement cost is so large compared to similar improvements in visibility using LNB/OFA technology and most importantly, the potential for other serious environmental impacts, the NDEQ has determined that it is inappropriate to require

the installation of SO 2 scrubbing technology as BART at this time. NPPD shall instead continue to utilize low sulfur coal. However, additional SO 2 controls may be required in the future for purposes of “reasonable further progress.” At that time, available control technologies would be evaluated, as well as water availability, whether water availability can reasonably be resolved, and the ability to mitigate potential threats to endangered species in the Platte River Valley area.

LNB/OFA technology is a feasible NO

x retrofit technology that could be implemented on GGS Units 1 and 2. The average cost effectiveness of this control technology is $198 per ton NO

x removed. Over the three years of meteorology modeled, the average incremental visibility impairment improvement cost is $4,475,825 per year per change in deciview impact.

Utilizing SCR technology is also feasible only if LNB/OFA is utilized. The i ncremental cost effectiveness (incremental cost SCR) is $5,445 per ton NO

x removed, over 25 times the amount of LNB/OFA alone. Over the

t hree years of meteorology modeled, the incremental visibility impairment improvement cost of adding SCR is $111,993,640 per year per change in deciview impact. The average incremental improvement in visibility for

t he addition of SCR is less than 0.5 dV and improvement would be seen on an average of 7.3 days per year. The NDEQ determined that the incremental cost for the addition of SCR is excessive and that LNB/OFA would be required for BART.

Therefore BART for GGS Units #1 and #2 shall be the installation of LNB/OFA with an emi ssion limitation of

0.23 lb NOx/MMBtu.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 26 of 53

Table 7: BART Determination Comparison Summary

B ART Proposal EPA Presumptive

NO

x Control Technology LNB/OFA LNB/OFA

NO

x Emission Limitation 0.23 lb/MMBtu 0.23 lb/MMBtu

SO 2 Control Technology Low sulfur coal FGD

SO 2 Emission Limitation Acid Rain limits 0.15 lb/MMBtu

Ave # of Days/Yr of Improvement to below

0.5 dV 5 20

Annualized Cost $2,960,000 $111,410,000

Ave. Incremental Visibility Impairment Improvement ( ∆ dV) 0.663 1.775

Ave. Incremental Impairment Improvement Cost ($/yr/ ∆ dV) $4,475,825 $62,766,197

Ave. Increment Cost per Day of Improvement $592,000 $5,570,500

5.1 Comments & Response to Comments Received regarding BART

T he draft permit and materials were made available on the NDEQ website. Nearby states with Class I areas, federal land managers, EPA Region 7 and other interested parties were notified of the availability of the draft permit.

The following individuals submitted written comments:

• Paul Tourangeau, Director of the Air Pollution Control Division for the Colorado Department of Public Health and Environment (CDPHE) submitted comments on June 23, 2009.

• John Bunyak Chief of the Policy, Planning and Permit Review Branch for the National Park Service in Denver, CO submitted comments in his capacity as a Federal Land Manager (FLM) on June 24, 2009.

• Becky Weber, Division Director of the Air & Waste Management Division of the U.S. Environmental Protection Agency Region VII (EPA R7) Office in Kansas City, KS submitted comments on June 26,

2009.

No other comments were received. A summary of the comments as well as the NDEQ responses are provided below and in a separate Responsiveness Summary document. Where appropriate, similar comments from different persons were consolidated and summarized. The responses to the comments serve to complete the public record on the decision to issue the permit. Only where noted were changes made to the permit.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 27 of 53 COMMENT #1: The Colorado Department of Public Health and Environment (CDPHE) suggested that NDEQ closely evaluate the costs for dry flue gas desulfurization (FGD) to determine whether economies of scale were taken into account and whether EPA may have any recent information on the actual versus projected costs of retrofitting units like those at GGS with dry FGD. CDPHE still recognized that the costs identified in the public notice materials were

considered to be sensible.

RESPONSE AND RATIONALE: NDEQ has closely evaluated the cost estimates provided by NPPD and discussed the on-site modifications that would be necessary in order to physically accommodate the retrofits described. Much of the information used to develop the cost estimates was based upon vendor information. NPPD does not benefit from economies of scale that some companies across the country can, because NPPD has just the two units in western NE subject to BART evaluation. Wherever appropriate, costs and benefits for controlling both units were considered. NDEQ could not locate any actual cost information on retrofitting a system similar to GGS.

COMMENT #2: The CDPHE expressed concern over their ability to meet visibility improvement goals for Rocky Mountain National Park. They pointed NDEQ to a website where baseline, modeling projections and source apportionment information could be found. The CDPHE noted that the modeling conducted shows the Central Regional Air Partnership (CENRAP) states predicted to be contributing 7.2% of sulfates in 2018 on the 20% worst days. They conclude because of proximity to Colorado, that since Nebraska is one of nine CENRAP states, and that GGS is among the largest sources of sulfur dioxide (SO2) in the CENRAP region, it is reasonable to attribute some portion of the CENRAP contribution to GGS. Therefore, CDPHE requests that NDEQ reconsider SO2 controls at GGS under the Regional Haze rule.

RESPONSE AND RATIONALE: NDEQ reviewed the website information provided by CDPHE. There, NDEQ found a “Causes of Haze Assessment” (COHA) that maybe found at http://www.coha.dri.edu/ as well as information on contribution for Rocky Mountain National Park, CO. The COHA included information regarding meteorological conditions. Below is an annualized wind rose for the Rocky Mountain National Park using the data collected from the station at the Class I area. As NDEQ expected, the patterns indicate the wind rarely comes from the east or northeast, directions that would have indicated a potential for impacts from sources in the state of Nebraska.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 28 of 53 The contribution assessment did not distinguish Nebraska from the other eight CENRAP states. CENRAP includes Minnesota, Iowa, Kansas, Missouri, Oklahoma, Arkansas, Louisiana, and Texas. Overall, CENRAP’s contribution was significantly smaller than that of Colorado as shown in the graphs below. Taking into consideration the wind patterns it is most likely that contributions from the CENRAP region are not from Nebraska, but are from sources in states located southeast of Rocky Mountain National Park.

Bec

ause othe

r Clas

s I

area

s coul

d be imp

acte d by emissions from Nebraska, NDEQ reviewed the COHA for other nearby Class I areas, specifically the Badlands Wilderness Area. The wind patterns (wind roses) for the Badlands indicate a high frequency of flow from the north-northwest year round, with an additional high frequency component of southeasterly flow during the warm months (June – August).NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 29 of 53

August 2002 Wind Rose for Rapid City (station #24090- Rapid City, SD Regional Airport)

The contribution analysis for the Badlands Wilderness Area did indicate a relatively high contribution from CENRAP. Given the wind pattern, location of GGS, it is possible that a portion of this contribution is attributable to GGS. However, the information did not distinguish Nebraska and its sources from the other CENRAP states. NDEQ provided a draft of the BART permit to the State of South Dakota Department of Environment and Natural Resources (DENR) to seek their input and feedback on the proposed BART package. Although in section 10.2 of the South Dakota Regional Haze State Implementation Plan, the South Dakota DENR states “...emissions from Nebraska are reasonably anticipated to contribute to visibility impairment in

South Dakota’s two Class I areas. South Dakota and Nebraska consulted each other outside of WRAP as Nebraska developed BART requirements for sources in Nebraska that are impacting our Class I areas,” however, no comments were received from the State of South Dakota.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 30 of 53 COMMENT #3: Like many parts of Nebraska, parts of Colorado are experiencing shortages of water. The CDPHE stated despite this obstacle, they have required dry or wet FGD on all electric generation units (EGUs) greater than 250 MW in capacity. The majority of the units have installed dry FGDs, commonly referred to as lime spray dryers. The CDPHE claimed that dry FGD units have lower water demands, better waste stream characteristics and similar control efficiencies to wet FGD systems.

EPA Region 7 also expressed concerns regarding the discussion on water shortages. EPA believes the crop revenue and property tax losses may be overstated. They further question whether the cost of lost crops plays any role in the BART analysis. EPA states that unless water is unobtainable as a result of a moratorium, water is not a significant factor in the BART analysis.

EPA also believes the portion of the water discussion related to endangered species evaluation is inconclusive. EPA suggests that the reduction of SO2 and mercury could have a positive effect on endangered species. EPA suggests that US Fish & Wildlife and other Federal agencies with oversight responsibility for endangered species be consulted.

RESPONSE AND RATIONALE:

BART is defined as: an emission limitation based on the degree of reduction achievable through the application of the best system of continuous emission reduction for each pollutant which is emitted by a BART eligible source. The emission limitation must be established, on a case-by-case basis, taking 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 or in existence at the source, the remaining useful life of the source, and the degree of improvement in visibility which may be reasonably be anticipated to result from the use of such technology.

Appendix Y to Part 51 – Guidelines for BART Determinations under the Regional Haze Rule provides guidance on evaluation of the “costs of compliance” and “non-air quality environmental impacts.” One of the factors is taking into consideration the extent of the short term environmental gains at the expense of long term environmental losses and the extent to which there may be an irreversible or irretrievable commitment of resources. The water demands of scrubber systems (wet or dry) relate to a commitment of scarce water resources, costs of compliance, and non-air quality environmental impacts. NDEQ conducted further analysis into the available water resources in Nebraska and discussed the impact with the agencies and persons responsible for the management of water quantity in the state. The results of that analysis are summarized in the paragraphs below.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 31 of 53 NDEQ searched for information on the water demands of dry FGDs to determine whether the estimates provided by NPPD were reasonable. Actual water usage information for comparable operating existing facilities that had been retrofitted was difficult to locate, but information on proposed units was found, and is

summarized in the table below:

Facility Name State MW GPM/MW (dry) GPM/MW

(wet) Round Up Montana 780 0.743 1.03 Dave Johnston (existing) Wyoming 360 0.689 0.917

Noborne Missouri 680 0.912 1.22 Dry Fork Montana 590 0.578 0.723 Dry Fork Texas 920 0.707 0.891 Paradise (existing) Kentucky 1150 1.47 1.92

NPPD Nebraska 1365 1.47 1.76

Average 0.938 1.21

NPPD projected water usage at 1.47 GPM/MW of generation for dry FGD and 1.76 GPM/MW for wet FGD. While, it would appear that the water usage estimates submitted by NPPD are higher than the average, NPPD stated during a meeting that their estimates were for total water consumption for the project, not just for the scrubbers. Information relating to water quality, additives, pH, and other parameters, was not available to the NDEQ for analysis. Quality of water available to a source could have an impact on the efficiency of the device, how it is designed and ultimately how much water must be used to achieve the desired level of control. The water values provided by NPPD are within the range of other facilities currently in operation, particularly the one of a similar size in Kentucky as noted in the table above. Based on the information available, NDEQ concluded that NPPD’s water consumption estimates for wet and dry scrubbers were not unreasonable. To be conservative, NDEQ used both the average and NPPD’s values for analyzing NPPD’s water demands against water availability in Nebraska.

Potential Scrubber water requirements for NPPD - GGS

GPM/MW

(dry) GPM/MW

(wet) MW GPM

(dry) GPM (wet) Acre-Feet per

Year (dry) Acre-Feet per

Year (wet)

NPPD 1.47 1.76 1365 2007 2402 3238 3877 Average 0.938 1.21 1365 1280 1652 2065 2666
1 million gallons = 3.07 acre-feet 525,600 minutes per year

Given that relatively large amounts of water needed for either a wet or dry scrubbing system, NDEQ consulted with the Nebraska Department of Natural Resources (NDNR) about the availability of water for future uses in the Sutherland, Nebraska area and to determine the feasibility of requiring a control technology based on what may be an unreliable water supply. If a reliable water supply cannot be ensured, scrubbing may not be a practical technology for GGS.

GGS is located in an over-appropriated river basin GGS is located in a semi-arid region of Nebraska in a portion of the Twin Platte NRD that has been designated by the Department of Natural Resources Director as over-appropriated. Nearby river basins from which water might be transferred have also been designated as either over-appropriated or fully-appropriated. The significance of these river basin designations is explained below.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 32 of 53 In 2004, the Nebraska Legislature enacted a law that mandated the NDNR make a determination of which river basins, sub-basins or reaches are considered to be fully-appropriated or over-appropriated . The decision that a basin was fully-appropriated or over-appropriated would trigger a moratorium on new surface water and ground water uses and initiates a process with the affected natural resources districts (NRDs) to develop an integrated management plan (IMP) to govern the apportionment of water resources in these basins. On September 15, 2004, the Director of NDNR issued an order designating portions of the North Platte NRD, South Platte NRD, Twin Platte NRD, Central Platte NRD and Tri-Basin NRD as over-appropriated. The GGS facility is located in the Twin Platte NRD within the area designated as over-appropriated. Most of these areas had already been determined to be fully-appropriated for surface water under the Nebraska system of prior appropriation of surface water rights and not available for new surface water appropriations. The new law mandated moratoriums on new water uses to remain in effect unless removed as a result of implementation of an approved integrated management plan.

A basin is considered fully-appropriated if the current uses of hydrologically connected surface water and groundwater in a basin cause, or will cause in the reasonably foreseeable future, (a) the surface water to be insufficient to sustain over the long term the beneficial purposes for which the existing surface water appropriations were granted, (b) the stream flow to be insufficient to sustain over the long term the beneficial uses from wells constructed in aquifers dependent on recharge from the basin’s river or stream, or (c) reduction in stream flow sufficient to cause Nebraska to be in noncompliance with an interstate compact or decree, formal state contract, or state or federal laws. Therefore, in fully-appropriated and over-appropriated basins, a plan for future water use must be put in place. The statutory definition of an over-appropriated basin is very precise and related to conditions at a single point in time, July 16, 2004. Areas that were designated as over-appropriatedwere required to develop a plan to reduce water use to the 1997 level of use within the next 10 years. In overappropriated areas, the water demand already exceeds the current availability of water and the law requires steps be taken to mitigate the situation.

The NDNR and the local NRDs involved are required to jointly develop and implement an integrated management plan within three to five years of a fully or over-appropriated designation. An Integrated Management Plan (IMP) for the Twin Platte NRD has been approved and took effect September 15, 2009. The purpose of the IMP is to manage all hydrologically connected groundwater and surface water for the purpose of sustaining a balance between demand and availability so that the economic viability, social and environmental health, safety, and welfare of the basin can be achieved and maintained for both the near and long-term.

The IMP contains specific depletion rates that must be offset in the area in order to begin to return the basin to a fully-appropriated status. The current information indicates that 7,700 acre-feet on average per year must be offset. The plan contains both non-regulatory and regulatory actions. Some of the non-regulatory programs include incentive programs and education programs. Regulatory actions are those measures the NDNR and the Twin Platte NRD would put into place should the non-regulatory programs and retirement of irrigated acres not meet the specific annual reduction in depletion targets. Such actions could include: requiring alternative crop mixes for certified irrigated land, reducing a set percentage of irrigated farmland and allocating water to irrigators uniformly and likely in declining quantities.

While the total reduction in consumptive use that will be required to reach a fully-appropriated status is not currently known, initial estimates indicate it may be several hundred thousand acre-feet per year.

When a basin is determined to be fully-appropriated or over-appropriated, moratoriums on new or expanded consumptive uses of groundwater and surface water are automatically imposed. A moratorium on new water use exists in the basins surrounding GGS. The basin in which GGS is located remains in an over-appropriated status and the prospects for any less restrictive designation, even to fully-appropriated status, are extremely unlikely in the foreseeable future. Since there is no “new” water available, GGS would have to find and retireNPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 33 of 53 existing water uses to meet scrubber needs and accomplish this at a time when the NDNR and local NRDs must

seek to reduce water uses overall.

The following moratoriums and restrictions on new water uses exist in Nebraska:

Platte River Recovery and Implementation Program As is evident with the over-appropriated status designation, the demand for beneficial uses of water in the area where GGS is located is considerable. In 1997, the Governors of Nebraska, Colorado, and Wyoming, and the U.S. Secretary of the Interior signed a cooperative agreement outlining a proposed basin-wide recovery implementation program for endangered species in the Central and Lower Platte river basins. In 2007, the Department of Interior, Colorado, Wyoming and Nebraska entered into an agreement called the Platte River Recovery and Implementation Program (PRRIP) to restore shortages to U.S. Fish and Wildlife Service (USFWS) target flows in the Platte River, thereby protecting endangered and/or threatened species whose habitat is the Platte River. The species identified for protection include the threatened piping plover and the endangered pallid sturgeon, least tern, and whooping crane. Substantial offsets to current water use are required in order to meet the PRRIP needs as well as the required IMP reductions. While the total potential water needs for both the PRRIP and IMP may not necessarily be mutually exclusive, they are substantial over the near and long term.

PRRIP is also set up to restore the shortages to USFWS target flows in an incremental fashion. During the first increment, the goal is to restore between 130,000 and 150,000 acre-feet per year. Of this, 80,000 acre-feet per year has already been obtained through project commitments from the three states, for a remaining requirementNPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 34 of 53 of 50,000 to 70,000 acre-feet per year. While additional increments have not yet been agreed to by the PRRIP states, the ultimate requirements of PRRIP may be as much as 417,000 acre-feet per year. For more information

about the PRRIP see http://platteriverprogram.org/default.aspx

.

The outstanding existing commitments and obligations will total up approximately 100,000 acre-feet per year and the ultimate requirements may be several times greater than that. The expected demands of scrubbing at the NPPD GGS facility is 2,000 to 3,900 acre-feet per year, or 2 to 4 percent of the initial increment required for the basin. The NDNR has informed the NDEQ that this additional demand represents a significant amount of the overall initial increment required for the basin, and that placing this additional demand on the basin jeopardizes Nebraska’s ability to meet commitments made to other states and the federal government, as well as the requirements of State Law relating to over-appropriated basins described above.

Acquisition of Allocations and Offsets (Costs of Water) In order for NPPD to obtain sufficient water for the scrubbers, they would need to acquire water from somewhere or someone else. There are two options for this: 1) transport the water from a location that has a suitable water supply, or 2) purchase existing water rights owned by someone else, retire the wells to ensure the offset is permanent.

Costs of Transporting Water In a study conducted by the State of Nebraska Water Management Board, the Report on Water Rights Transfer Study (1988), the writers found that since water rights were not traded routinely in a market situation, there was no demand curve for determining a cost schedule. Instead, economics rely on willingness or ability to pay and the least cost alternatives. For industries, water is relatively hard to transfer compared to other inputs, so typically a site is chosen where there is an adequate supply of water. Over the years, many transfers have been under consideration in Nebraska. Several factors go into the costs of transferring water: well construction, pipeline construction, pumping plants, land, energy, operation and maintenance. Pipeline costs are the most significant fixed cost. Energy is the largest part of operations.

In a study conducted by the High Plains Study Council, “A Summary of Results of the Ogallala Aquifer Regional Study, With Recommendations to the Secretary of Commerce and Congress” (1982), an evaluation of transferring water within the High Plains area was conducted. Four routes were evaluated, including one that started at Fort Randall, South Dakota, moved southwesterly across Nebraska (nearing the Sutherland, Nebraska area) to storage near Bonny Reservoir in Eastern Colorado. In 1977 dollars the average costs for this project

were:

Water

Studied for

Transfer Route

Length Elevation

Change #

Pumping

Stations Total Energy

Requirements (Million KWHr/yr) Total

Construction Costs (1977 $) Average

Annual

Cost ($/acre-ft)

1.91 – 3.4

million

acre-ft 813

miles 0 ft 18 6,600 – 14,300 5.4 – 8.9

billion 291

Colorado is planning to build a pipeline to comply with the Republican River Basin Compact. The costs associated with that are: $5,263 an acre for the water rights ($50 million); $1,400 per acre-foot to build pipeline ($21 million).NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 35 of 53 Costs of Obtaining Water Rights and Retiring Wells According to the 1988 Water Management Board report, the cost of obtaining water will be different for every situation. It would be most likely that NPPD would need to seek out water rights from irrigators and retire irrigation wells. For agricultural uses of water, the decision to sell a water right would be made only when/if the irrigator felt it would be advantageous to sell than continue to operate. If the irrigator were willing to forego the use of this resource, the price for that water right must sufficiently compensate for decreased net returns over a period of years. The irrigator relies on that well for livelihood in times when sufficient rain is unavailable. The long-term value of irrigation water to a farmer is based on the expected return over a number of years discounted into present values, i.e. the opportunity cost. If one thought that it would be to their advantage, the irrigator may be willing to trade water for potential farm income and related risks for less water, a smaller yield or operation, and secure dollars in the bank.

In 2008, 30 square miles of a Lincoln County irrigated farm near North Platte sold for about $3,000 per acre. In 2009, Lincoln County irrigated farmland sold for about $3,200 - $3,500 per acre. NPPD assumed that approximately 3,000 acres of land would be needed to be purchased. Costs for obtaining water rights could be between $9,600,000 and $10,500,000 or more, depending upon the willingness of potential sellers.

Any offsets would be subject to approval from the local NRD through issuance of a variance.

In conclusion, as indicated in the discussion above, the water resources in the river basin in which GGS is located and in surrounding river basins are scarce. A moratorium has been placed on new consumptive uses. Offsets of existing uses are difficult to find and economically prohibitive given the distances and infrastructure needed to transport water from a reliable supply location. The unusual circumstances related to the scarce water resources in this region of the state and the State of Nebraska’s commitments to other states and the federal government under the PRRIP when compared to the very limited visibility improvement that might result from the additional control justifies not requiring GGS to install scrubbing technology at this time.

Agricultural Taxes and Crop Income Agriculture is the main economy of Nebraska. Whenever cropland is taken out of service, it is appropriate to evaluate that impact to the state. Lincoln County was ranked in the top five counties for agriculture sales in 2007. Nebraska’s leading commodities accounting for 98% of the state’s total cash receipts are: cattle, corn, soybeans, hogs, wheat, chicken eggs, dairy products, hay, dry beans, and sorghum. Nebraska has been 1 st in red meat production, cattle slaughter, great northern beans production, irrigated land and popcorn production. When cropland is permanently taken out of service, wealth is being removed from the state. The effect of this is direct on the farmer, the employees, and their families, but there is also an indirect effect that trickles out from reductions in crop income. Reduced crops in an agricultural state result in fewer grains for livestock and for export out of the state. This reduction impacts more people and their jobs, including grain elevators and slaughter houses. According to the USDA, for every $1 in agricultural exports another $1.40 is generated in transportation, financing, warehousing and production. It follows that for every $1 reduced in agricultural exports, another $1.40 is reduced in those areas as well. When the foundational industries to our economic structure begin to weaken, the service sectors start to suffer as well.

COMMENT #4: The FLM resubmitted comments previously provided on August 29, 2008. The letter, at the time, dealt with both OPPD and NPPD facilities, however, only the comments regarding the NPPD action are germane to this

action and are summarized below.

The FLM states that the draft permit requires the presumptive NOx limit for Unit 1 and slightly above presumptive for Unit 2. In the attachment to the August 29, 2008 letter, the FLM outlines several otherNPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 36 of 53 concerns regarding the BART analysis for NOx. The FLM contends that selective non-catalytic reduction (SNCR) was eliminated from consideration without sufficient technical justification. They question whether, based upon the NOx emissions from the two boilers at GGS, make the boilers similar enough to be evaluated in combination instead of individually. They also question the logic of whether temperature is a factor for the boilers, making SNCR technically infeasible.

The FLM believes that the ability of SCR systems to control NOx has been underestimated in the BART analysis. To support their presumption, the FLM provided information from EGUs with SCR systems that are used during the ozone season.

Lastly, the FLM believes that NPPD has overestimated the costs associated with SCRs. They conclude and recommend that the SCR analysis be redone and that the modeled effects should be conducted at all Class I areas at a level no greater than 0.07 lb/MMBtu.

RESPONSE AND RATIONALE: The draft permit package that was public noticed did not contain limits above the presumptive levels as indicated in the comment. The presumptive level is 0.23 lb/MMBtu. The limits in Condition XIV.(A)(1)(a) states: “Emissions from both units shall be averaged together and shall meet a NOx emissions limitation of 0.23 lb/MMBtu (30-day rolling average).”

The temperature issue was discussed with NPPD. The two units are different and could not be evaluated in

combination.

SCR controls were evaluated down to a level of 0.08 lb/MMBtu, a level deemed appropriate by NDEQ and supported by the record. This analysis was contained the application materials and in the proposed permit package that was public noticed on May 28, 2009.

Please also refer to the response and rationale to comments #6 and #8.

COMMENT #5: The FLM made several comments concerning the SO2 BART analysis. First, they believe that SO2 controls can do better than the presumptive level established in the rule. The FLM stated that SO2 controls could be added and would act as if they were at a newly constructed facility. The FLM supported their claim that SO2 controls could achieve better than the 0.15 lb/MMBtu level by providing a table summarizing systems that are either achieving or proposed to achieve levels between 0.04 and – 0.09 lb/MMBtu. They propose that GGS should be able to achieve 0.04 lb/MMBtu (wet) or 0.06 lb/MMBtu (semi-dry) on a 30-day rolling average.

The FLM expressed concern that the cost figures were overestimated compared to other similar retrofits. They also expressed a lack of sufficient detail in the operating costs figures developed by NPPD to understand the annualized costs and the cost-per-ton figures.

EPA also made comments about Flue Gas Desulfurization (FGD) control technology being able to operate at emission levels lower than the presumptive levels (0.15 lb of SO2/MMBtu) in the Regional Haze Rule. EPA suggested levels as low as 0.02 lb of SO2/MMBtu could be achieved. They suggest that it is important to consider the maximum efficiency a technology could achieve in order to avoid over-inflating cost effectiveness figures. EPA did concur with the NDEQ that, at the presumptive level, $2,700 per ton of SO2 removed is a

reasonable cost.

Please also refer to the response and rationale to comment #8.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 37 of 53 RESPONSE AND RATIONALE: It is difficult to ascertain the maximum efficiency the technology could achieve at the source until it is installed and optimized. However, the point is to have the State consider other possible efficiencies the technology could achieve when determining whether something is cost effective. NDEQ did consider a lower lb/MMBtu than the presumptive level.

NDEQ did a data pull of EPA’s database to determine how existing FGD systems performed at existing subbituminous coal fired EGUs. While units were found that performed below 0.1 lb/MMBtu, NDEQ did not find where levels as low as 0.02 lb/MMBtu, and several did not meet the 0.15 lb/MMBtu presumptive level. This is a summary of the results:

State Plant Name MMBtu/Yr SO2 Tons/Yr lb/MMbtu Controls

MN Sherburne 54,081,049 7,863.09 0.290 DL FGD

WY Wyodak 32,852,075 7,732.07 0.470 DL FGD

AZ Springerville 32,800,868 5,331.17 0.325 DL FGD

AZ Springerville 27,474,762 4,548.64 0.331 DL FGD

OK GRDA 41,980,796 4,113.71 0.196 DL FGD

MO Hawthorn 41,523,208 2,140.86 0.103 DL FGD

CO Craig 31,899,039 2,010.18 0.126 DL FGD

KS Holcomb 27,332,412 1,772.24 0.130 DL FGD

CO Rawhide 22,783,530 875.5 0.077 DL FGD

WY Wygen 1 10,142,973 538.38 0.106 DL FGD

WY Neil Simpson II 8,119,461 498.4 0.123 DL FGD

MI Shiras 3,500,784 225.9 0.129 DL FGD

ND Stanton 5,344,399 139.15 0.052 DL FGD

NE NPPD GGS 110,115,509 28,171.44 0.512

Note: The lbs/MMBTU was figured by dividing the annual SO 2 tons values by the annual MMBTU values. NDEQ recognizes that short term periods (30 day) may show lower or high values.

COMMENT #6: The FLM believes that it is appropriate to consider cumulative, not average effects of improving visibility across all of the Class I areas affected. They believe that if emissions from GGS are reduced, the benefits will be wide-spread, well beyond one Class I area. The FLM referenced work that the Oregon Department of Environmental Quality conducted on the Boardman power plant where the cumulative impact across 14 Class I areas was 29.7 dV with a total of 2,367 impaired visibility days across the 14 Class I areas. It is the FLM opinion that the other Class I areas where GGS caused or contributed to visibility impairment were ignored.

RESPONSE AND RATIONALE: Other areas where NPPD GGS affected visibility were not ignored. NDEQ summarized the greatest impacts because that is where the most benefit from control would be seen. The law of diminishing returns is experienced when one looks at all the potential Class I areas. NPPD GGS is located approximately 300 km from it’s nearest Class I area (Badlands). Models that are used as tools to help make decisions on control strategies and determine the perceived benefits become less reliable when the receptor (Class I area) is more than 200 km away from the BART source.

Appendix Y to Part 51 – Guidelines for BART Determinations under the Regional Haze Rule provides under STEP 5: Determining Visibility Impacts: “If the highest modeled effects are observed at the nearest Class INPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 38 of 53 area, you may choose not to analyze the other Class I areas any further...” Given the guidance in Appendix Y and the uncertainties of the model beyond 200km, the analysis conducted is appropriate. However, there is another Class I area close to Badlands Wilderness Area, Wind Cave National Park. The next highest impacts

were seen there.

The total baseline impact from NPPD GGS is shown in Table 2 of the Fact Sheet. The number of days above 0.5 dV for the 7 Class I areas analyzed ranged from 10 – 60 days. The area with the greatest impact was Badlands in all 3 years analyzed. There were 54 days above 0.5 dV in 2001, 55 in 2002 and 60 in 2003. Since Wind Cave is close to the Badlands, we will assume that improvements seen at the Badlands will be seen at

Wind Cave as well.

The following table shows what the cumulative improvements in visibility from SO2 and NOx controls would be, roughly, assuming that SO2 controls could be implemented, and the corresponding cost effectiveness:

Badlands –

2001 Badlands –

2002 Badlands -

2003 Average

Baseline – dV 2.845 2.828 3.121 2.931

LNB/OFA- ∆ dV 0.621 0.666 0.702 0.663

Cost/ ∆ dV $4,766,506 $4,444,444 $4,216,524 $4,464,555

Cost/ ∆ dV/days improvement $953,301 $1,481,481 $702,754 $1,045,845

LNB/OFA + SCR -

∆ dV 0.492 0.434 0.540 0.489

Cost/ ∆ dV $110,347,561 $125,094,470 $100,538,889 $111,993,640

Cost/ ∆ dV/days improvement $10,858,200 $4,935,545 $9,048,500 $8,280,748

FGD (0.1 lb/MMbtu) - ∆ dV 1.055 0.802 0.678 0.845

Cost/ ∆ dV $102,796,208 $135,224,439 $160,428,994 $132,816,547

Cost/ ∆ dV/days improvement $5,164,286 $4,929,545 $4,518,750 $4,870,860

LNB + FGD- ∆ dV 1.676 1.468 1.380 1.508

Cost/ ∆ dV $107,562,714 $139,668,883 $164,645,518 $137,281,102

Cost/ ∆ dV/days improvement $6,117,587 $6,411,026 $5,221,504 $4,870,860

Costs do not include costs of obtaining water

Even assuming that Wind Cave would have the same level of benefit, the incremental cost effectiveness would be half of what is shown above: LNB + FGD = $137,281,102/ ∆ dV / 2 = $68,640,551/ ∆ dV. This is still significantly higher than the incremental cost effectiveness value under consideration in Wyoming at the Wyodak facility ($16.3 million/dV). In Wyoming, an additional metric was used to put the visibility improvement into perspective. The incremental reduction in days above 0.5 dV in each Class I area was evaluated. Using that metric for NPPD, assuming Wind Cave has the same level of benefit as Badlands, and using an average of days over 0.5 dV during 2001 – 2003 annually:

NOx BART Controls Alone: $522,922/day Incremental Cost of adding SO2 Controls with NOx Controls: $2,435,430/day Cumulative Cost of NOx and SO2 Controls: $2,958,352/day

The rule does not provide a level to which individual sources must reduce their visibility impact, leaving it up to the state’s judgment. All things considered, the moratorium on new consumptive uses of water, wind patterns, costs of compliance, visibility improvement that is expected from the additional NOx controls versusNPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 39 of 53 NOx and SO2 controls, the irreversible or irretrievable commitment of water resources requiring scrubbers would cause on an already water-stressed area and the excessive costs for the amount of visibility improvement due to additional SO2 controls even if water were available, NDEQ has concluded it is most appropriate to implement only additional NOx controls as BART for NPPD GGS.

COMMENT #7: EPA raised concerns regarding whether Nebraska was fulfilling its obligations under the Regional Haze Rule. EPA noted that 40 CFR 51.308(d)(3) requires all states to submit a long-term strategy for addressing visibility impairment for each Class I area located outside the state that may be affected by emissions from within the state. EPA also referenced the regional planning process that NDEQ participated in which was facilitated by the Central Regional Air Planning Association (CENRAP). EPA held that work done by the CENRAP formed the basis for regional haze SIPs submitted by states such as Missouri, Oklahoma and Louisiana. EPA believes that the modeling was based on emissions reduction information for installations that were ‘on the books’ and ‘on the way’ and that presumptive BART was an ‘on the way’ assumption for GGS in the modeling analysis. EPA notes that under 40 CFR 51.308(d)(3)(ii), the State must ensure that it has included all measures needed to achieve its apportionment of emissions reduction obligations agreed upon through the regional planning process. Furthermore, EPA believes Missouri, Oklahoma, and Colorado relied upon IPM modeling conducted by EPA, which included presumptive levels for BART on GGS.

RESPONSE AND RATIONALE: The regional haze process has been a difficult one. It is problematic to set a presumptive level, assume that all facilities will be able to comply with it regardless of the situation, but also allow for a case-by-case analysis in

the rule.

Areas of influence and apportionment of Nebraska’s SO2 emissions were evaluated in the August 31, 2005, Causes of Haze Study conducted by Sonoma Technology, Inc. This study may be found on CENRAP’s website ( www.cenrap.org ). Sonoma concluded that because the emission impact potentials (EIPs) of potentially BARTeligible sources are relatively small, the enforcement of BART requirements will produce limited improvement in visibility conditions and require the need for additional emission reduction strategies. Emission impact potentials relate the probability of transport of SO2 and NOx pollution from an area such as a state to a Class I area and the scale of emissions in that given area (State). In Figures 4-8 and 4-9 of the study, Nebraska BART sources have an insignificant EIP, specifically for the Hercules Glades Class I area.

In a paper written by Sonoma Technology and Brett Anderson (EPA) (see Appendix D of the paper), the composition of particles were studied in an effort to better understand how to improve the visibility for the

Hercules Glades Class I area. The results showed that sulfate accounted for 65% of the mass at Hercules Glades and most of the sulfate was in the form of ammonium sulfate. The paper reported that it “was highest on days with transport from the Ohio River area, where many coal-fired power plants are located and which has been identified as a significant area for the origin of sulfate transport.” Nebraska does not lie within the Ohio River Area. Sonoma and Anderson went on to say that the EIP analysis corroborated this, showing that more than half of the SO2 came from that particular area, and that when looking at the county-level, it was clear that a handful of sources in a few counties were responsible for most of the SO2 emissions impacting Hercules Glades. However, the study revealed that ammonium nitrate showed strong seasonal tendencies. It was highest during the winter, and was highest under conditions of slow moving cool air masses from northwest Missouri, Iowa, Nebraska, and Kansas.

Nebraska participated in the CENRAP regional planning process. However, it is important to note that CENRAP recognizes the authority and jurisdiction of each state and tribal member. Nebraska also was invited to participate in a limited capacity in a consultation process with Missouri and Oklahoma, which is a part of the regional planning process. Please refer to the response to Comment #3 for information about Class I areas inNPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 40 of 53 Colorado and South Dakota. We did not receive any comments from any states. We have concluded that by controlling NOx emissions, Nebraska is ensuring that it is including all measures needed to achieve its apportionment of emissions reduction obligations identified through the regional planning process. Additionally, we have concluded that controlling SO2 is not reasonable given, among the other reasons stated in this response, the unique circumstances regarding water availability in that area of the state.

COMMENT #8: EPA expressed concern that NDEQ is using solely dollars per deciview ($/dV) as a decision-making metric for BART. They list four concerns: 1) they believe that although the EPA BART guidelines allow for its use, there are significant difficulties in developing a meaningful method for calculating $/dV; 2) they believe it should only be used as a supplement to $/ton, in evaluating cost effectiveness; 3) they believe cost estimates must be reasonable, and recommends that cost estimates be based upon the OAQPS Cost Manual; and 4) they believe that even when used as a supplement to $/ton, the $/dV analysis would be meaningless if it does not take into account visibility impacts at multiple Class I areas or ignores the total improvement (frequency, magnitude, and duration of the modeled changes in visibility).

RESPONSE AND RATIONALE: NDEQ would like to clearly state that it did not rely solely on one factor in making its SO 2 BART determination for GGS, but rather, considered all factors. Furthermore, the EPA’s citation of the $/dV metric as only one factor is mistaken, since by definition, this calculated ratio includes both the cost and the benefit (degree of visibility improvement). The other three factors (the energy and non-air quality environmental impacts of compliance, any existing pollution control technology in use at the source, the remaining useful life of the source) were also considered in the five-factor analysis. Therefore, Nebraska has indeed considered all five factors and has not relied on a single factor in its SO 2 BART determination.

The Clean Air Act, Section 169A (g) (2) states:

“in determining best available retrofit technology the State (or the Administrator in determining emission limitations which reflect such technology) shall take into consideration the costs of compliance, the energy and non-air quality environmental impacts of compliance, any existing pollution control technology in use at the source, the remaining useful life of the source, and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology”

EPA’s initial Regional Haze rules had directed states to set BART emissions limits based on only the first four factors listed in the above statutory language, after determining that a given source was “subject” to BART. Thus, EPA had initially left the visibility improvement factor out the BART determination step. In the case of American Corn Growers Assn v. EPA (291 F.3d 1; D.C. Cir., 2002), the court sided with the American Corn Growers Association, and ruled that all five factors, including the “degree of visibility improvement” needed to be considered in the BART determination. EPA subsequently revised the Regional Haze rules accordingly, on July 6, 2005.

The cost analysis for the GGS BART analysis was prepared by Sargent and Lundy, LLC (S&L), a well recognized and experienced design engineering firm in the power industry, under contract with NPPD in 2008 (referred to as the “2008 S&L NPPD Study”). When S&L prepared the 2008 cost analysis, the January 2002 OAQPS Control Cost Manual was generally followed. In addition, S&L also provided certain cost information supplied to S&L by vendors. NDEQ met with NPPD, S&L and EPA Region 7 and discussed the cost analysis, and supporting vendor information, used by S&L in the 2008 S&L NPPD Study.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 41 of 53 Costs to retrofit are unique to the specific unit, its current design, and site layout, making retrofit costs exceed those of building a new unit. There may be significant mechanical, structural, and electrical changes and upgrades needed to accommodate a retrofit. S&L also evaluated FGD technology and costs on electric generating units as part of a study for the National Lime Association in March 2007. The study is titled “Flue Gas Desulfurization Technology Evaluation: Dry Lime vs. Wet Limestone FGD” (and is referred to as the “2007 S&L Industry Study”). In the 2007 S&L Industry Study, S&L evaluated 36 cases, including retrofits. While the authors caution against using the information for planning the cost of an FGD project, NDEQ used this information for comparison purposes. Overall, the capital costs provided in the 2008 S&L NPPD Study for GGS were higher than those in the industry-generic 2007 S&L Industry Study. There appear to be several reasonable explanations for why this is the case: 1) the 2008 S&L NPPD Study provided costs for control of a 2 units (1365 MW) whereas the 2007 S&L Industry Study only provided retrofit information on 400MW and 500MW units; 2) the 2008 S&L NPPD Study added 10% for “turnkey services” for purposes of engineering, procurement, and construction management services; and 3) as stated in both S&L studies, FGD equipment, material and installation labor prices have been subject to significant inflation since 2006. Some recent contracts have been signed at prices over 300% higher than the market of 5 years ago. Therefore, the statements made by EPA that the costs of FGD have gone down are not supported by recent market trends. Also, while the 2008 S&L Study costs for GGS are higher than those contained in the industry-generic 2007 S&L Industry Study, the $/ton SO2 removed was about the same as in both studies.

All of the above considered, the NDEQ determined that the costs presented by NPPD were reasonable.

The Appendix Y BART Guidelines provide for in the “Costs of Compliance” provide for several cost effectiveness measures including incremental cost effectiveness in $/ton and other measures like $/dV. In the BART program, Appendix Y is putting the cost of the control into perspective by allowing for consideration of the goal of the program, which is visibility improvement. Sources with a significant baseline impact to a Class I area will likely have much lower cost per deciview of visibility improvement when controls are employed provided significant improvements are realized. Using a $/dV metric also indirectly takes into consideration the distance a source is from the Class I area. Assuming a source is upwind from a class I area, similar size emission sources located different distances away from a given Class I area would be expected to have different impacts on that Class I area.

COMMENT #9: EPA commented that GGS was not compared to other facilities within the same power pool, but instead

facilities that were not similar to GGS.

RESPONSE AND RATIONALE: Prior to public notice and again before issuance of the permit, NDEQ conducted a review of the BACT/LAER Clearinghouse for retrofit projects to compare to NPPD GGS, and to determine whether NPPD had adequately supplied all information about such projects in its submittal. Mid-Continent Area Power Pool (MAPP) includes the states of Nebraska, Iowa, North and South Dakota, Minnesota, and portions of Wisconsin and

Montana. Information from the states of Minnesota and North Dakota were reflected in the Fact Sheet. Information was listed on the WRAP’s website in the MAPP; however, the facilities listed utilize lignite and

not subbituminous coal similar to NPPD.

EPA pointed to two facilities in Kansas. They said the visibility impacts from GGS were greater than Kansas City Power and Light (KCP&L) La Cygne and Westar Jeffery facilities. NDEQ does not agree with this statement. Looking at Table 9.2 of the Kansas draft SIP reveals these facilities have many more days of impact on many more Class I areas than NPPD GGS does.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 42 of 53 COMMENT #10: EPA commented that while the use of a construction permit may provide for adequate enforceability of the BART emission limits, it is recognized that minor changes to permits often occur during construction and operation of the units. EPA stated that if changes were made to the construction permit which effects, in any manner, the permit requirements related to the BART emission limits, the source could not rely on such changes until NDEQ requested and EPA approved them into the SIP. They also state that this restriction applies even if the primary purpose of the permit revision is not to change BART obligations. Since there is no discretion to change the limits without a corresponding SIP change, EPA suggests that NDEQ may wish to consider utilizing a rulemaking or state enforceable agreement, incorporated into and approved as part of the SIP, to ensure the BART emission limits are enforceable.

RESPONSE AND RATIONALE: NDEQ appreciates the suggestion made by EPA; however, as EPA Region 7 is aware, the NDEQ has already adopted into Title 129 NAQR Chapter 43 the construction permit program as the mechanism for making theBART requirements enforceable. At the time this was done, R7 had an opportunity to participate in the rulemaking. As with the current construction permit program, the provisions of Chapter 43 will be submitted as a part of the State Implementation Plan. The current construction permit program (Chapter 17) is a part of the State Implementation Plan; therefore any permits that are issued in accordance with it should be enforceable. Nebraska will include in its SIP submittal, information about the BART permits issued.

COMMENT #11: EPA expressed concern about the differences in the timing between the BART rule provisions and the PSD permit requirements for purposes of commencing construction. EPA is concerned that NPPD may choose to delay construction and suggests that NDEQ require commencing construction within 18 months of the issuance of the PSD construction permit.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 43 of 53 RESPONSE AND RATIONALE: NDEQ understands EPA’s concern. There is the unique situation where the control technology determined to be BART requires a PSD permit due to the projected increase in carbon monoxide emissions. The BART provisions promulgated by EPA allow sources up to 5 years after SIP approval to make BART controls operational and in compliance. While NPPD assures NDEQ their intent is to commence construction as soon as practicable after the Nebraska Regional Haze SIP has been approved by the EPA, however, unforeseen circumstances could change those plans. The PSD rules (52.21(r)(3)) and Title 129 NAQR Chapter 17, Section 012, allow the NDEQ to grant extensions of the 18 months timeframe under certain circumstances.

COMMENT #12: EPA noted that Condition XIV.(B)(1)(a)(i) on page 6 has sampling and recordkeeping conditions for Unit 1 that need to be duplicated for Unit 2.

RESPONSE AND RATIONALE: NDEQ agrees with the comment.

CHANGES: The language was revised to read: “The average CO emissions for each GGS unit, for each hour, shall be recorded by sampling the lb/MMBtu value by completing a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period Unit 1is for Unit 1 anytime it is combusting fuel and its monitor is in service and is not malfunctioning or being calibrated, and for Unit 2 anytime it is combusting fuel and its monitor is in service and is not malfunctioning or being calibrated. Data for startup and shutdown shall not be used to calculate the average CO emissions. All data shall be reduced as specified in 40 CFR 60.13(h).”

6.0 Prevention of Significant Deterioration (PSD)

6.1 Summary

BART for GGS Units 1 and 2 has been determined to be the installation of low NO

x burners supported by an existing, modified, or replacement overfire air port system as needed to meet a NO

x limit of 0.23 lb/MMBtu. Although NO

x emissions would decrease, carbon monoxide (CO) emissions are expected to increase in emissions above the PSD significance threshold (100 tons/year for CO). Title 129, Chapter 1, Section 076 defines a “major modification” as any physical change in or change in the method of operation of a major stationary source that would result in a significant emissions increase of a regulated New Source Review (NSR) pollutant and a significant net emissions increase of that pollutant from the major stationary source. Therefore, the installation of LNB/OFA is a major modification and NSR regulations are applicable. Lincoln County is in attainment for all National Ambient Air Quality Standards (NAAQS) so the Prevention of Significant Deterioration (PSD) regulations apply to this source. The PSD regulations state that the application of best available control technology (BACT) is required for each new or modified emission unit and each regulated air pollutant for which the project emissions exceed the established PSD significance thresholds. Unit 1 previously received a PSD permit and a BACT analysis was done for CO when the LNB/OFA were permitted in August 2006, therefore, Unit 2 is the only unit which needs to apply BACT for the increase in CO with this permitting action. However, in order for the requirements for both units to be contained in a single permitting document, the permit issued for Unit 1 on 8/18/2006 will be superseded by the PSD portion of this permit.

BACT is defined as an emissions limitation established based on the maximum degree of pollutant reduction for each pollutant subject to regulation under the Clean Air Act which would be emitted from any proposed major stationary source or major modification which the Administrator, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable. However,NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 44 of 53 BACT cannot be less stringent than emission limits established by an applicable NSPS. Since it would not be appropriate to require GGS to install LNB/OFA without addressing the increase in CO emissions expected, the Department has decided to address the BART requirements and PSD requirements in a single permitting action. As documented below, it has been determined that BACT for this unit should be a specific 30-day rolling average CO emissions limitation of 0.50 lb/MMBtu, with the control being good combustion practices.

6.2 Best Available Control Technology (BACT) Analysis Methodology

I n a memorandum dated December 1, 1987, the EPA stated its preference for a “top-down” analysis regarding BACT determinations. The first step in a top-down BACT analysis is to determine, for the emissions unit and pollutant in question, the most stringent control technology and emissions limit available for a similar or identical source or source category. If it can be shown that this level of control is infeasible on the basis of technical, economic, energy, and environmental impacts for the source in question, then the next most stringent level of control is identified and similarly evaluated. This process continues until the BACT level under consideration cannot be eliminated by any technical, economic, energy or environmental consideration.

A “Top-Down” BACT analysis is comprised of the following five basic steps:

6.2.1 Step 1: Identify all potentially applicable control technologies: All control technologies for similar processes, as well as Lowest Achievable Emission Rate (LAER) technologies are included.

6.2.2 Step 2: Eliminate technically infeasible options: Technologies demonstrated to be infeasible based on physical, chemical, and engineering principles are

excluded from further consideration.

6.2.3 Step 3: Rank remaining technologies by control effectiveness: Technically feasible control technologies are ranked in the order of highest expected emission reduction to lowest expected emission reduction. The ranking also includes expected emission rate, control effectiveness, energy impacts, environmental impacts (including toxic and hazardous air emissions), and economic impacts.

6.2.4 Step 4: Evaluate most effective controls and document results: The technology ranking is evaluated and case-by-case consideration is given to energy, environmental, and economic impacts. The most effective option not rejected is chosen as BACT and is used to express an

enforceable emission limitation for the affected emission unit.

6.2.5 Step 5: Propose BACT

6.3 BACT Analysis for Carbon Monoxide (CO)

The objective of this analysis is to determine BACT for CO emissions from the GGS Unit 2 LNB/OFA system. Generally there are two approaches to controlling CO emissions: combustion controls and/or flue gas treatment (post-combustion) technologies. The rate of CO emissions from combustion sources is dependent upon the combustion efficiency of the source. Combustion control processes can reduce the quantity of CO formed during the combustion process. Post-combustion technologies reduce the CO concentrations in the flue gas stream after the CO has been formed in the combustion process. These methods may be used alone or in combination to achieve various degrees of CO emission reductions. High combustion temperatures , adequate excess air, and good air/fuel mixing during combustion can minimize CO emissions.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 45 of 53 6.3.1 CO Formation CO formation occurs primarily through incomplete combustion. The oxidation of CO to carbon dioxide (CO 2 ) is dependent on temperature, residence time during the combustion process, and the amount of excess O 2 present. Since temperature and residence time are critical factors in formation of CO, smaller boilers often emit more CO than larger combustion units, because these units have less high-temperature residence time to achieve complete combustion. Often, measures used to minimize or control emissions of NO

x can result in incomplete combustion and increased CO emissions. Therefore, an acceptable compromise is necessary to achieve the

lowest NO

x emission rate possible while still keeping CO emissions as low as possible.

6.3.2 Identification of CO Control Technologies and Technical Feasibility

6.3.2.1 Combustion Controls

Combustion controls generally include staged combustion to minimize NO

x formation, high temperatures and low oxygen levels in the primary combustion zone, sufficient excess air to complete combustion, sufficient residence times, and good air/fuel mixing. Combustion efficiency is often related to the three “T’s” of combustion: time, temperature, and turbulence. These components of combustion efficiency are designed into pulverized coal (PC) boilers in order to maximize fuel efficiency and reduce operating costs in terms of fuel consumption. Therefore, combustion control is accomplished primarily through burner/furnace design and operation. The primary combustion control methods used, once the burner/furnace design is set, are adjustments in the amount of air and the ratio of primary air to secondary air. These adjustments significantly affect combustion efficiency and CO levels in the combustion flue gases.

LNB/OFA systems for PC boilers are designed to burn the coal in a slow, controlled manner, which results in the minimum possible quantity of combustion air in the primary combustion zone. This initial combustion zone helps reduce NO

x formation; however, it increases the amount of incomplete combustion that increases CO emissions. CO emissions can be minimized by injecting air through over-fire air ports located in the upper furnace section. The injected air brings the total amount of combustion air up to the level needed to achieve complete combustion, thereby minimizing CO emissions. It is technically feasible and economically desirable to minimize CO emissions; therefore, good combustion practices are considered to be feasible technologies for

CO control from GGS Unit 2.

6.3.3 Post Combustion Control Technologies

6.3.3.1 Oxidation Catalysts

There are a variety of manufacturers who offer oxidation catalysts to control CO emissions. The catalysts are a flue gas treatment technology with a typically honeycomb type of arrangement to allow the maximum surface area exposure to a given gas flow. The typical oxidation catalyst for CO is a rhodium or platinum (noble metal) catalyst on an alumina support material. Acceptable catalyst operating temperatures range from 400 – 1250 o F, with optimum temperature range being 850 – 1,100 o F. Below 600 o F, a greater catalyst volume would be required to achieve the same reduction.

Catalytic oxidation has never been applied to a coal-fired unit because of several problems due to the solid fuel use, temperature requirements, and sulfur dioxide present in the flue gas. Catalyst plugging, fouling and poisoning by fuel sulfur and fly ash cause the catalyst to be ineffective. In order for the ideal temperature to be applied to the catalyst, the catalyst would need to be installed before the boiler economizer, which is ahead of the unit’s particulate controls (fabric filters). Installation of the catalyst in this section of the boiler would result in rapid poisoning and deactivation of the catalyst by sulfur and metal compounds, and plugging and fouling of the active catalyst sites with particulates due to the high dust loading. Additionally, significant costNPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 46 of 53 would be incurred for retrofitting this technology to an existing boiler. In addition, because the catalyst would oxidize a high percentage of the flue-gas sulfur dioxide (SO 2 ) to sulfur trioxide (SO 3 ), the oxidation catalyst would result in significantly increased sulfuric acid mist formation and condensable particulate. High levels of sulfuric acid would lead to rapid and destructive corrosion of ducts and equipment downstream of the catalyst and higher fine particulate and opacity levels, which would result in a visible plume from the stack. Current oxidation catalyst technology has not been designed for the higher particulate and sulfur dioxide levels found in coal-fired applications. Therefore, catalytic oxidation is not considered technically feasible for PC boilers like

GGS Unit 2.

6.4 Ranking of Technologically Feasible CO Controls based on Effectiveness

B ased on the CO control technologies presented above, the only feasible BACT technology for this source is good combustion practices (GCP). Catalytic oxidizers have not been proposed or demonstrated for use on a pulverized coal-fired boiler and therefore are technically infeasible for GGS Unit 2.

6.5 BACT for CO

A t the time this permit was issued, the highest CO BACT emission limit that had been permitted on a retrofitted unit in US EPA Region 7, is 1.63 lb/MMBtu (3-hr average) for the Mid American Energy Company, Neal – North, Unit 2 Boiler (2007). A search of the RACT/BACT/LAER Clearinghouse (RBLC) database revealed that the lowest such limit for a retrofitted unit was in 2005 at the Mid-American Energy, Neal – South, Unit 4 Boiler (0.42 lb/MMBtu, calendar day average.) OPPD’s Nebraska City Unit 1 was recently permitted with an emissions limit of 0.50 lb/MMBtu (30-day rolling average) for BACT, which is consistent with the proposed NPPD emission limit. A 30-day rolling average is appropriate because GGS Unit 2 does not have a neural net system installed. This computer automated system measures certain operating parameters associated with combustion, and based on the parameters, automatically adjusts the combustion system to achieve an optimal operating scenario. Since GGS Unit 2 does not have a neural net system, any “tweaks” in operation must be made by the operators manually. Furthermore, even if GGS had a neural net system, if such a system automatically adjusted the combustion system to minimize CO emissions, this would tend to increase NO

x emissions, as there is a tradeoff between CO and NO

x emissions. Because NO

x emissions control is deemed much more important than minimizing CO emissions, the NDEQ agrees that the 0.5 lb/MMBtu (30-day rolling average) is an acceptable CO BACT limit for GGS Unit 2. NPPD’s Unit 1 went through BACT in August 2006 and CO BACT was set at 0.5, which isn’t changing in this permit even though it supersedes the Unit 1 permit.

7.0 Air Dispersion Modeling Analysis

A ll projects that are subject to NSR review are required to be accompanied by an air quality analysis of the ambient impacts associated with the project. This analysis includes an assessment of existing air quality, an air dispersion modeling analysis, an additional impact analysis, and an evaluation of any adverse impacts to Class I areas. The air dispersion modeling analysis is required to demonstrate that new emissions from the source or due to the major modification, in conjunction with applicable emissions from other existing sources, will not cause or contribute to a violation of any applicable National Ambient Air Quality Standards (NAAQS) or PSD increment. Depending on the modeling results, pre-application monitoring or more thorough analyses may be required. Although a significant modeling analysis was conducted in conjunction with the BART analysis, CO is not a visibility impairing pollutant and therefore was not addressed. Below is a summary of the modeling analysis conducted for CO as part of the PSD permitting process. More information can be obtained in the materials submitted by the source.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 47 of 53 7.1 Model Information

7.1.1 Facility Location and Site Description

The NPPD Gerald Gentleman Station is located approximately 30 kilometers (km) west of North Platte and 12 km south of Sutherland in Lincoln County. The terrain in the vicinity of the NPPD facility is essentially flat to gently rolling terrain, with no terrain elevation in excess of 50% of the NPPD boiler stack heights. Lincoln County is currently classified as in attainment or unclassifiable for all NAAQS pollutants.

7.1.2 Model Selection

The air quality impact analysis of CO emissions was performed using the EPA SCREEN3 dispersion model. The emission rate input into SCREEN3 was equivalent to 3,769 lb/hr, which is based on the maximum heat input rate of 7,538 MMBtu/hr of Unit 2 and the BACT emissions limit of 0.5 lb/MMBtu.

The SCREEN3 model was executed for a maximum (100%) load condition, because this load produces higher impacts than when the unit operates at partial loads. The “simple terrain” option was used and the maximum terrain elevation difference of 98.66 meters was input into the model. This is a very conservative procedure in that the model assumes that the terrain rise of 98.66 meters above the stack base occurs at every receptor distance input to the model.

7.1.3 Source Parameters

One emission source, GGS Unit 2, was evaluated for purposes of PSD screening modeling. It is the only unit at the NPPD facility for which a change is proposed. The results of the screening modeling indicated that impacts from the potential emission increases resulting from the changes to GGS are insignificant. The following table presents the source stack parameters. In addition to these parameters, building downwash dimensions were input to SCREEN3 as follows: building height= 81.69 meters, minimum building width = 82.03 meters, maximum building width (both boiler buildings combined) = 180.26 meters.

Table 7: Modeled Source Parameters

S ource Type Emission

Rate (g/sec) Stack

Height (m) Inside

Diameter (m) Exit

Velocity (m/s) Exit

Temperature (K) Ambient

Air Temp. (K)

Point 474.89 167.6 8.53 22.3 417.0 293.0

7.2 Preliminary Modeling Analysis

The preliminary modeling analysis evaluates potential emissions from the PSD project alone. The results of the preliminary analysis determine whether or not a full impact analysis is required. For this project the preliminary modeling analysis was also used to determine whether or not pre-application monitoring needed to be required from the source.

The following table shows the results of the modeling analysis conducted. The results indicate that the modification of Unit 2 will not cause a significant impact in the surrounding area for the 1-hour or 8-houraveraging periods for CO. Therefore no refined modeling analysis needs to be completed and no preapplication monitoring was necessary.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 48 of 53 Table 8: Maximum Modeled GGS Unit 2 Concentrations, Significant Impact Levels (SIL),

And Pre-application Monitoring Thresholds

Pollutant Averaging

Period Modeled

Concentration ( u g/m 3 ) SIL

( u g/m 3 ) Pre-application Monitoring

Threshold ( u g/m 3 )

1-hr 315.9 2,000 N/A CO 8-hr 221.1 500 575

7.3 Additional Impacts Analysis

A n Additional Impacts Analysis, as required by Title 129, Chapter 19, Section 022, and the PSD regulations 40 CFR 52.21(o), describes air quality and related impacts due to associated growth and construction, as well as potential impacts of atmospheric emissions on soils, vegetation, and visibility impairment. This analysis was provided in the materials submitted by the source.

Visibility analyses were not conducted since the burner modification will not result in an increase of emissions of any visibility impairing pollutant.

7.3.1 Pollutant Effects on Soil and Vegetation

Current literature contains little information on air pollutant effects on soil and no specific studies could be identified where potential pollutant effects on the soils specific to the project area were evaluated. One study was found concerning CO effects on vegetation. The study indicated that natural background concentration of CO has no detrimental effects on green plants, and adverse effects are only seen at extremely high CO concentrations that occur primarily in urban areas due to high traffic density. Because the modeled CO impacts are insignificant compared to the NAAQS, the CO emissions are not expected to negatively impact vegetation. NAAQS are not expected to be exceeded as a result of this project. Since NAAQS were designed to protect the public health and welfare from known or anticipated adverse pollutant impacts, it can be concluded that there will not be any adverse effects on the soil or vegetation.

8.0 Type and Quantity of Air Contaminant Emissions Anticipated

A s a result of the LNB installation supported by an Overfire Air Port System on GGS Unit 2, NO

x and CO are the only pollutants expected to change. NO

x emissions should decrease, while CO emissions may increase. Since CO is the only pollutant that may increase; it is the only pollutant subject to PSD review.

CO PTE after LNB/OFA Project Emission Calculation:

7,538 MMBtu/hr x 0.50 lb CO/MMBtu = 3,769 lb CO/hr x 8,760 hr/yr / 2,000 lb/ton = 16,508 ton CO/yr

The current potential emissions of Unit 2 were calculated by using a CO emission factor of 0.5 lb/ton of coal from AP-42, Chapter 1, Table 1.1-3 (9/1998) and the maximum amount of coal that could be combusted in Unit 2 assuming a Btu content of coal of 8,400 Btu/lb.

CO PTE prior to LNB/OFA Project Emission Calculation:

7,538 MMBtu/hr / 0.0084 MMBtu/lb x 8,760 hr/yr/ 2,000 lb/ton = 3,930,529 ton coal/year 3,930,529 ton coal/year x 0.5 lb CO/ton coal = 1,965,264 lb CO/yr / 2,000 lb/ton = 983 ton CO/yrNPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 49 of 53 Change in PTE Emission Calculation:

(Future Potential minus Current Potential) 16,508 ton CO/yr – 983 ton CO/yr = 15,525 ton CO/yr

This project is also expected to reduce the amount of permitted and actual NO

x emissions for GGS Units 1 and 2. Currently, GGS Units 1 and 2 must comply with NO

x emissions limits of 0.2 lbs/MMBtu derived from gaseous fuel, 0.3 lbs/MMBtu derived from liquid fuel, 0.7 lbs/MMBtu derived from solid fossil fuel, or the prorated equation contained in 40 CFR 60.44(b) when a combination of fuels is burned, based on an arithmetic average of three contiguous one-hour periods (40 CFR 60.44(a) and (b), and 60.45(g)) in order to be in compliance with the applicable New Source Performance Standard (NSPS), Subpart D, for Fossil-Fuel-Fired Steam Generators. In addition, GGS Unit 1 must comply with a NO

x emission limit of 0.46 lb/MMBtu on an

annual basis. The NO

x limit of 0.46 lb/MMBtu for dry bottom wall-fired boilers is found in 40 CFR 76.7(a)(2) and became effective 1/1/2008. Although GGS Unit 1 was retrofitted with a LNB/OFA system in 2006, the allowable (permitted) emissions did not change. GGS Units 1 and 2 have a heat input rating of 15,076 MMBtu/hr and by using the highest possible emission factor of 0.46 lbs/MMBtu, maximum potential NO

x emissions are currently 30,375 tons/year.

15,076 MMBtu/hr x 0.46 lb NO

x /MMBtu = 6,935 lb NO

x /hr x 8,760 hr/yr / 2,000 lb/ton = 30,375 ton NO

x /yr

By establishing a NO

x emissions limitation of 0.23 lb/MMBtu for BART, the new allowable emissions of NO

x from GGS Units 1 and 2 will be approximately 15,188 tons/year once the LNB/OFA project has been completed for Unit 2.

15,076 MMBtu/hr x 0.23 lb NO

x /MMBtu = 3,467 lb NO

x /hr x 8,760 hr/yr / 2,000 lb/ton = 15,188 ton NO

x /yr

Change in PTE Emission Calculation:

(Future Potential minus Current Potential) 15,188 ton NO

x

/yr – 30,375 ton NO

x

/yr = - 15,187 tons NO

x

/yr

Therefore, once the LNB/OFA project has been completed, maximum potential CO emissions would increase by 15,525 tons/year while maximum potential NO

x emissions would decrease by 15,188 tons/year.

9.0 Applicable Requirements, Variances or Alternatives to Required Stan dards

9.1 Nebraska State Construction Permit Requirements

A state construction permit is required for this facility because this construction project has a net increase in emissions at the site greater than one or more of the threshold levels identified in Title 129, Chapter 17, Section

001.01 for PM 10 , SO

x (SO 2 and/or SO 3 ), NO

x , CO, VOC and HAPs. Specifically, CO emissions are expected to increase greater than 50 tons/year.

The facility-wide potential emissions from the facility after the issuance of this permit falls into the following
category:

100 tons or more per year of any air pollutant; or

10 tons or more per year of any single HAP; or 25 tons or more per year of any combination of HAPs.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 50 of 53 Therefore, the facility submitted a $3,000.00 fee in order to obtain this Air Quality Construction Permit, in accordance with Title 129, Chapter 17, Section 003.01

.

Section 014.04 of this chapter states that a source may request a state construction permit when establishing a Best Available Retrofit Technology (BART) permit or other permit required to reduce visibility impairment in a Class I Federal area pursuant to the provisions of Chapter 43.

9.2 New Source Performance Standards (NSPS)

The proposed project will not trigger the applicability of any new NSPS requirements to GGS Unit 2.

Subpart A – General Provisions : NSPS Subpart A, adopted by reference in Title 129, Chapter 18, Section

001.01 , applies to those units covered by the specific NSPS as discussed below. The permittee is required to submit notification of the date construction commenced postmarked no later than 30 days after such date (40 CFR 60.7(a)(1)), notification of the anticipated date of initial startup of the equipment postmarked not more than 60 days nor less than 30 days prior to such date (40 CFR 60.7(a)(2)), and notification of the actual date of initial start up of the equipment postmarked within 15 days after such date (40 CFR 60.7(a)(3)). Unit 2 at GGS is currently subject to this subpart and the proposed project does not affect the applicability of this regulation or the compliance status of the unit.

Subpart D – Standards of Performance for Fossil-Fuel-Fired Steam Generators : This subpart, adopted by reference in Title 129, Chapter 18, Section 001.17 , is for steam generating units with a design rate greater than 250 MMBtu/hr, installed after August 17, 1971. GGS Unit 2 is currently subject to this subpart and the proposed project does not affect the applicability of this regulation or the compliance status of the unit.

Subpart Da – Standards of Performance for Electric Utility Steam Generating Units : This subpart, adopted by reference in Title 129, Chapter 18, Section 001.11 , is for steam generating units with a design rate greater than 250 MMBtu/hr, installed after September 18, 1978. The installation of LNB will not constitute a modification or reconstruction of the existing facility as specified in provisions under 40 CFR 60.14 and 40 CFR 60.15. Therefore, Unit 2 will continue to be an existing unit under NSPS Subpart D and will not be subject to any requirements under NSPS Subpart Da.

Subpart HHHH - Emission Guidelines and Compliance Times for Coal-Fired Electric Steam Generating Units : This subpart established a model cap and trade program as a means of reducing national Hg emissions from coal fired electric utilities. GGS Unit 2 would have been subject to Subpart HHHH, however the subpart was vacated in its entirety by the Court of Appeals for the District of Columbia Circuit on February 8, 2008 (State of New Jersey, ET AL.v. EPA).

9.3 Particulate Matter Emissions

Title 129, Chapter 20, Section 002 -Particulate Emissions from Combustion Sources

GGS Unit 2 will continue to comply with the emission limits for fuel combustion located in this chapter. For units with heat input capacities between 10 MMBtu/hr and 10,000 MMBtu/hr, the following formula is used to

determine the Maximum Allowable Emissions of Particulate Matter in lb/MMBtu:

Lb/MMBtu = 1.026/I 0.233 where I is the total heat input in MMBtu/hr.

1.026/(7,538 MMBtu/hr) 0.233 = 0.128 lb/MMBtuNPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 51 of 53 Title 129, Chapter 20, Section 004 - Opacity

All of the equipment at the facility is subject to the opacity standard (20% opacity limit) specified in Title 129, Chapter 20, Section 004 . Although coal is combusted at the facility, control equipment has been installed in the past to control particulate emissions that contribute to opacity.

9.4 Sulfur Compound Emissions

No fossil fuel burning equipment at the facility may emit sulfur oxides greater than two and one half (2.5) pounds per million BTU input. GGS Unit 2 will comply with this emission limit by complying with requirements that are contained within NSPS Subpart D for SO 2 emissions. This limit is currently specified and contained within the facility’s Class I Operating Permit issued April 28, 2004.

9.5 Acid Rain

T he federal acid rain program requirements (40 CFR Part 72) have been incorporated by reference in this chapter. Unit 2 will continue to be considered an affected unit for purposes of the Acid Rain Rule because it is a utility unit that will generate more than 25 MW of electricity. The Acid Rain Rule requires a facility to monitor opacity, and all sulfur dioxide, nitrogen oxides, and carbon dioxide emissions for each affected unit. The proposed project does not affect any requirements of this rule. GGS is currently oper ating under an Acid Rain Permit that was issued on January 26, 2005.

9.6 Hazardous Air Pollutants

Title 129, Chapter 27, Section 002 - Best Available Control Technology (BACT)

Title 129, Chapter 27, Section 002 requires a BACT determination for any source with net emissions increase of HAP in excess of 2.5 tons/year of any single HAP, or combined emissions of 10 tons/year of any group of HAPs. The proposed project will not result in net increases in potential emissions of HAPs that equals or exceeds the BACT thresholds. Therefore, requirements of this section do not apply to the proposed project.

Title 129, Chapter 27, Section 003 - Maximum Achievable Control Technology (MACT)

This section requires that MACT be installed on any source with a net emissions increase of HAP in excess of 10 tons/year of any single HAP, or combined emissions of 25 tons/year of any group of HAPs. The proposed project will not result in net increases in potential emissions of HAPs that equal or exceed the MACT thresholds. Therefore, requirements of this section do not apply to the proposed project.

Subpart A – General Provision: This subpart, adopted by reference in Title 129, Chapter 28, Section 001.01

, applies to the owner or operator of any stationary source that emits or has the potential to emit any hazardous air pollutant listed in or pursuant to section 112(b) of the Act; and is subject to any standard, limitation, prohibition, or federally enforceable requirement established pursuant to Part 63.

Subpart DDDDD – Industrial, Commercial, and Institutional Boilers and Process Heaters: This subpart, adopted by reference in Title 129, Chapter 28, Section 001.90 , applies to certain boilers and process heaters that are located at major HAP sources ( ≥ 10 tons/year of individual HAP or ≥ 25 tons/year of combined HAPs).NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 52 of 53 9.7 Visibility Protection

Title 129, Chapter 43 incorporates 40 CFR 51.301 and Appendix Y of 40 CFR 51 by reference. It requires that BART analyses be submitted by sources determined to be subject to the requirement and establishes the construction permit as the mechanism for making the BART requirements federally enforceable. NPPD submitted a BART analysis for GGS Units 1 and 2 on August 7, 2007.

10.0 Discussion of Specific Permit Conditions

G eneral Condition V. General Condition V. requires the low NO

x Burners supported by an over-fire air port system on Unit 2 to be operational and demonstrate compliance with the BART and BACT limitations as expeditiously as practicable, but no later than five years after the approval by EPA of the Regional Haze State Implementation Plan (SIP). Forty CFR Part 51, Section 51.302(c)(4)(iv) states:

“The plan [State Implementation Plan] must require that each existing stationary facility required to install and operate BART do so as expeditiously as practicable but in no case later than five years after plan approval.”

Although the completion of the LNB/OFA project need not be completed until five years after the SIP approval, construction must commence on the project within 18 months of SIP approval in order for the Department to ensure that the project has undergone some progress in a reasonable timeframe. NPPD submitted additional timeline information regarding the time necessary to install the LNB/OFA to the Department on April 30, 2008. The Department will notify NPPD within 15 days of SIP approval that the approval has occurred.

The requirements for EPA for approving SIP submissions are contained in the Clean Air Act, Section 110(k). Section 110(k)(1)(B) states that within 60 days of receipt of a State's plan or plan revision submission, but no later than 6 months after the date by which a State is required to submit the plan or revision, the Administrator must determine whether the minimum criteria for the plan have been met. If the Administrator does not inform the State of the determination within 6 months of receipt of the submission, the plan or revision is deemed to

meet the minimum criteria.

Section 110(k)(2) also states that within 12 months of a determination that a plan submission meets the minimum criteria, the Administrator must act on the plan, making a determination of full and partial approval/disapproval or conditional approval.

No other general conditions have been adjusted for this permitting action.

Specific Conditions

(A) Establishes a NO

x emissions limit and Department determined BART control, low NO

x Burners supported by an overfire air port system, for GGS Units 1 and 2. The 30-day rolling emissions limit of 0.23 lb/MMBtu must be complied with at all times including times of startup, shutdown, or malfunction. All malfunctions shall be addressed in accordance with Nebraska Title 129, Chapter 35.

A discussion of how this limit was chosen can be found under the BART discussion located in this

document. The NO

x emissions data is required to be collected in accordance with 40 CFR Part 75 for Acid Rain, which incorporates requirements the source is currently subject to.NPPD-Gerald Gentleman Station Fact Sheet: CP07-0050

Filename: 34385f02.doc Page 53 of 53 (B) Establishes a CO emissions limit and Department determined BACT control, combustion controls, for GGS Units 1 and 2. The 30-day rolling emissions limit of 0.50 lb/MMBtu must be complied with at all times excluding startups and shutdowns. All malfunctions shall be addressed in accordance with Nebraska Title 129, Chapter 35. A discussion of how this limit was chosen can be found under the PSD discussion located in this document. NPPD is required to install a CO CEMs on each unit.

(C) Requires that records be kept documenting all notifications, reports, test results, and plans submitted to the Department. The owner or operator is also required to maintain appropriate CEMS information, which is required in XIII.(A)(2)(d) and XIII.(B)(1)(c). These records must be maintained on-site for a minimum period of five (5) years and be clear and readily accessible to Department representatives.

STATUTORY OR REGULATORY PROVISIONS ON WHICH PERMIT REQUIREMENTS ARE

BASED:

Applicable regulations: Title 129 - Nebraska Air Quality Regulations as amended May 17, 2009.

PROCEDURES FOR FINAL DETERMINATION WITH RESPECT TO THE PROPOSED

CONSTRUCTION PERMIT:

The public notice, as required under Title 129, NAQR Chapter 14, shall be published on May 28, 2009, in the North Platte Telegraph newspaper. Persons or groups shall have 30 days from that issuance of public notice (June 26, 2009) to provide the NDEQ with any written comments concerning the proposed permit action and/or to request a public hearing, in accordance with NAQR Chapter 14. If a public hearing is granted by the Director, there will be a notice of that meeting published at least 30 days prior to the hearing. Persons having comments or requesting a public hearing may contact:

W. Clark Smith-Permitting Section Supervisor

Air Quality Division Nebraska Department of Environmental Quality

PO Box 98922 Lincoln, Nebraska 68509-8922

If no public hearing is requested, the permit may be granted at the close of the 30-day comment period. If a public hearing is requested, the Director of the NDEQ may choose to extend the date on which the permit is to be granted until after that public hearing has been held. Additional public information is available on the agency’s website and by request at ndeq_records@nebraska.gov. During the 30-day comment period, persons requiring further information should contact:

Beverly Kellison-Program Planning & Development Unit Supervisor

Air Quality Division Nebraska Department of Environmental Quality

PO Box 98922 Lincoln, Nebraska 68509-8922

Telephone inquiries may be made at:

(402) 471-2189

TDD users please call 711 and ask the relay operator to call us at (402) 471-2186.