EDGEWATER COMMONS II ■ 81 TWO BRIDGES ROAD ■ FAIRFIELD, NJ 07004 ■ 973-575-2555 ■ FAX: 973-575-6617 

■ www.enviroplan.com ■

Final Findings Report 

Golden Valley Electric Association (GVEA) 

Best Available Retrofit Technology (BART) Evaluation 

Prepared for 

State of Alaska 

Department of Environmental Conservation 

Division of Air Quality 

ADEC Contract No. 18-3001-17 

NTP No. 18-3001-17-8D 

Prepared by 

Enviroplan Consulting 

Edgewater Commons II 

81 Two Bridges Road 

Fairfield, NJ 07004 

Enviroplan Consulting Project No. 209928.15 

April 27, 2009 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

i 

EXECUTIVE SUMMARY 

Enviroplan Consulting (Enviroplan) was retained by the Alaska Department of Environmental 

Conservation (Department) to review a Best Available Retrofit Technology (BART) control 

analysis submitted on July 28, 2008 by Golden Valley Electric Association (GVEA), with 

supplemental information submitted on October 3, 2008, November 11, 2008 and December 10, 

2008; with a revised final BART analysis report submitted on January 2, 2009. Supplemental data 

also was submitted on March 18, 24 and 30, 2009. The BART control analysis was prepared by 

GVEA for the Healy Power Plant pursuant to the Federal Regional Haze Rule, 40 CFR Parts 

51.300 through 51.309, and 40 CFR Part 51, Appendix Y, Guidelines for BART Determinations 

Under the Regional Haze Rule; and the Department’s regulation relating to BART, 18 AAC 

50.260. 

Healy Unit 1 and Auxiliary Boiler #1 (also referred to as Auxiliary Heater #1 by GVEA) have 

been determined as BART-eligible units pursuant to the state and federal BART rules. An initial 

modeling analysis conducted by the Western Regional Air Partners (WRAP) – Regional Modeling 

Center (RMC) demonstration for the Healy power plant showed maximum visibility impact at the 

Tuxedni Wilderness Class I area less than the significant visibility impact threshold of 0.5 

deciview. The maximum visibility impact at the Denali National Park Class I area exceeded 0.5 

deciviews. The Department notified GVEA in December 2007 that they were subject to the 

BART requirements and that the affected Class I area was Denali National Park. GVEA submitted 

a BART control analysis in response to this notification on July 28, 2008. Since the Department 

has not exempted GVEA from the requirements of BART, pursuant to 18 AAC 50.260(b), GVEA 

must comply with paragraphs (d) through (h) and (l) through (o) of 18 AAC 50.260. GVEA has 

conducted the evaluations required pursuant to these rules. GVEA has opted to use WRAP’s 

modeling protocol for the visibility modeling analysis, as allowed under 18 AAC 50.260(h)(3)(A). 

By using WRAP’s protocol, they were not required to submit a new modeling protocol prior to 

conducting the visibility impact analysis. 

The purpose of this report is to document Enviroplan’s findings regarding GVEA’s BART 

control analysis in terms of compliance with 18 AAC 50.260(e) through (h). This report also 

proposes a preliminary BART determination for each BART-eligible source at this facility, 

pursuant to 18 AAC 50.260(j). Enviroplan submitted an initial draft findings report to the 

Department on January 27, 2009; however, with the receipt of preliminary comments from the 

National Park Service (NPS) on February 12, 2009 and supplemental information from GVEA 

during March 2009, the findings report is revised as presented herein. 

This findings report concludes that the GVEA BART control analysis complies with 18 AAC 

50.260(e) through (h). For Healy Unit 1, use of the existing dry sorbent injection system to control 

sulfur dioxide (SO2) emissions is considered BART; the addition of a selective catalytic reduction 

(SCR) unit to the existing low NOx burner (LNB) and over-fire air (OFA) system to control oxides 

of nitrogen (NOx) emissions is considered BART; and use of the existing reverse gas baghouse 

system for particulate control is considered BART. The existing configuration for Auxiliary 

Boiler #1, which has no air pollution control systems, is considered as BART since the predicted 

daily visibility impacts for this unit are well below the significant visibility impairment metric of 

0.5 daily deciviews. 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

ii 

TABLE OF CONTENTS 

EXECUTIVE SUMMARY ................................................................................................................. i 

1. INTRODUCTION.................................................................................................................. 1 

1.1 General Program Background .................................................................................... 1 

1.2 Source Description and Background .......................................................................... 3 

2 ELEMENTS OF THE BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS .... 4 

3 IDENTIFICATION OF ALL AVAILABLE RETROFIT EMISSION CONTROL 

TECHNOLOGIES (Step 1) .................................................................................................... 6 

3.1 NOx Control Technologies Considered ...................................................................... 6 

3.2 SO2 Control Technologies Considered ...................................................................... 9 

3.3 Particulate Control Technologies Considered .......................................................... 11 

4 TECHNICALLY FEASIBLE RETROFIT EMISSION CONTROL TECHNOLOGIES 

(Step 2) ................................................................................................................................. 12 

4.1 NOx Control Technologies ....................................................................................... 12

4.2 SO2 Control Technologies........................................................................................ 12 

5 EVALUATION OF TECHNICALLY FEASIBLE RETROFIT EMISSION CONTROL 

TECHNOLOGIES (Step 3) .................................................................................................. 13 

5.1 NOx Control Technologies ....................................................................................... 13

5.2 SO2 Control Technologies........................................................................................ 13 

6 COST-EFFECTIVENESS AND IMPACT ANALYSIS (Step 4) ...................................... 14 

6.1 NOx Control Technologies ....................................................................................... 15

6.1.1 Cost of Compliance..................................................................18 

6.1.2 Energy Impact........................................................................18 

6.1.3 Non-Air Quality Environmental Impacts.........................................18 

6.2 SO2 Control Technologies........................................................................................ 19

6.2.1 Cost of Compliance...................................................................21 

6.2.2 Energy Impact........................................................................21 

6.2.3 Non-Air Quality Environmental Impacts.........................................21 

6.3 Economic Impacts – Rate Payer Analysis.................................................21 

7 VISIBILITY IMPACTS EVALUATION (Step 5) .............................................................. 27 

7.1 CALPUFF Modeling Approach ............................................................................... 27 

7.2 Visibility Modeling Results ..................................................................................... 31 

7.3 Visibility Monitoring Program ................................................................................. 31 

7.4 Visibility Impacts Evaluation Conclusions .............................................................. 37 

8 PROPOSED BART FOR HEALY 1 ................................................................................... 40 

8.1 NOx Control at Healy Unit 1 .................................................................................... 40 

8.2 SO2 Control at Healy Unit 1..................................................................................... 41 

8.3 Particulate Control at Healy Unit 1 .......................................................................... 42 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

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9 GVEA BART CONTROL ANALYSIS REPORT FINDINGS AND CONCLUSIONS .... 43 

9.1 BART Emission Limits ............................................................................................ 43 

9.2 Compliance Demonstration ...................................................................................... 44 

List of Tables 

Table 4-1: Technically Feasible NOx Control Options for Healy 1. ......................................... 12 

Table 4-2: Technically Feasible SO2 Control Options for Healy 1. .......................................... 12 

Table 5-1: Control Effectiveness of the NOx Control Options for Healy 1. .............................. 13 

Table 5-2: Control Effectiveness of the SO2 Control Options for Healy 1. .............................. 13 

Table 6-1: NOx Cost Effectiveness Summary for Healy 1. ....................................................... 15 

Table 6-2: SO2 Cost Effectiveness Summary for Healy 1 ......................................................... 19 

Table 6-3-1: GVEA Estimated Operating Expenses with SCR .................................................... 23 

Table 6-3-2: Revised Operating Expenses with SCR ................................................................... 24 

Table 6-3-3: GVEA Estimated Operating Expenses with FGD Optimization ............................. 24 

Table 6-3-4: Revised Operating Expenses with FGD Optimization............................................. 25 

Table 9-1: Preliminary BART Emission Limits Proposed for Healy Unit 1 ............................. 43

List of Figures

Figure 6-1: Additional Annual Costs versus Additional Tons Removed Compared to Existing 

 Operations for NOx Options. ..................................................................................... 16 

Figure 6-2: Additional Annual Costs versus Additional Tons Removed Compared to Existing 

 Operations for SO2 Options. .................................................................................... 20 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

1 

1. INTRODUCTION 

1.1 General Program Background 

On July 6, 2005, the U.S. Environmental Protection Agency (EPA) published the final “Regional 

Haze Regulations and Guidelines for Best Available Retrofit Technology Determinations” (the 

“Regional Haze Rule” 70 FR 39104). The rule is codified at 40 CFR Parts 51.300 through 

51.309, and 40 CFR Part 51, Appendix Y. The Regional Haze Rule requires certain States, 

including Alaska, to develop programs to assure reasonable progress toward meeting the national 

goal of preventing any future, and remedying any existing, impairment of visibility in Class I 

Areas. The Regional Haze Rule requires states to submit a plan to implement the regional haze 

requirements (the Regional Haze SIP). The Regional Haze SIP must provide for a Best Available 

Retrofit Technology (BART) analysis of any existing stationary BART-eligible source that 

might cause or contribute to impairment of visibility in a Class I Area. BART-eligible sources 

include those sources that: 

1. have the potential to emit 250 tons or more of a visibility-impairing air pollutant; 

2. were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and 

3. whose operations fall within one or more of the specifically listed source categories in 

40 CFR 51.301. 

During 2007 the Department developed a list of Alaska BART-eligible sources based on the 

federal BART guidelines. GVEA’s power plant in Healy, Alaska has been identified by the 

Department as required to conduct BART assessments for its BART-eligible emission units, 

Healy Unit 1 and Auxiliary Boiler #1. The affected visibility impairing pollutants (VIP) are 

NOx, SO2 and particulate matter (conservatively as PM10). The requirements applicable to 

Alaska BART-eligible sources were published by the Department on December 30, 2007 under 

18 ACC 50.260. The Department’s BART regulation requires sources not exempt from 

applicability based on a visibility modeling analysis to submit a case-by-case BART proposal for 

each BART-eligible unit at the facility and for each VIP by July 28, 2008. 

A preliminary regional BART screening modeling analysis of all BART-eligible sources in Alaska 

was completed in 2007 by the Western Regional Air Partnership (WRAP) - Regional Modeling 

Center (RMC). The simulations were done using the CALPUFF modeling system and a single 

year, 2002, of processed MM5 CALMET data. The simulations were performed to evaluate 

predicted impacts of visibility in Alaska PSD Class I areas, including the Denali National Park and 

Preserve (DNPP) and Tuxedni Wilderness Area. BART-eligible sources are exempt from BART if 

the daily visible impacts at a Class I area are below the screening criteria set by the Department 

(ADEC), EPA, and the Federal Land Managers (FLMs). Pursuant to 18 AAC 50.260(q)(4), a 0.5 

or greater daily deciview change when compared against natural conditions is considered to 

“cause” visibility impairment. 

The initial modeling analysis conducted by WRAP - RMC indicated that the maximum visibility 

impact of GVEA’s facility at the DNPP Class I area was higher than the 0.5 daily deciview 

visibility screening threshold, while the impacts at Tuxedni were below this threshold. The 

Department notified GVEA in December 2007 that they were subject to the BART control 

analysis requirements for the affected equipment since the WRAP – RMC analysis was 

unsuccessful at providing a basis for exemption. The Department identified the DNPP as the 

affected Class I area. 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

2 

GVEA submitted the requisite BART control analysis and preliminary determinations on July 

28, 2008. GVEA provided supplemental information on October 3, 2008, November 11, 2008 

and December 10, 2008, in response to Enviroplan’s September 19, 2008 and October 16, 2008 

requests for clarification. After further discussions with the Department and Enviroplan, GVEA 

submitted a revised BART analysis report on January 2, 2009. Enviroplan reviewed this 

information and prepared a draft findings report on January 27, 2009. Teleconferences then 

occurred between the Department, GVEA, CH2M Hill (GVEA’s consultant) and Enviroplan on 

February 25 and 27, 2009 and March 2, 2009. As a follow-up to these teleconferences, GVEA 

submitted additional supplemental study information on March 18, 24 and 30, 2009. 

Pursuant to 40 CFR 51, Appendix A, a BART engineering analysis requires the use of six 

statutory factors for any BART-eligible source that is found to cause or contribute to atmospheric 

visibility impairment in any of 156 federal parks and wilderness areas protected under the 

regional haze rule (i.e., mandatory Class I areas). These factors include: 1) the available retrofit 

options, 2) any pollution control equipment in use at the source (which affects the availability of 

options and their impacts), 3) the costs of compliance with control options, 4) the remaining 

useful life of the facility, 5) the energy and non-air quality environmental impacts of control 

options, and 6) the visibility impacts analysis. 

GVEA conducted the BART control analysis utilizing the above referenced factors. GVEA 

concluded that the BART-eligible sources at the Healy Power Plant do not require additional 

retrofit controls because the potentially feasible control options are either not cost effective, the 

control options do not result in significant visibility benefit, and/or the cost of visibility 

improvement resulting from potentially installing these control options are highly cost 

prohibitive. GVEA considers the existing controls and operating practices on BART-eligible 

sources at the facility as BART. 

The following sections of this report present the review findings pertaining to both the GVEA 

control analysis and the related CALPUFF modeling files. Enviroplan performed the review to 

determine whether GVEA’s analysis conforms to the WRAP modeling protocol and the related 

rules and regulatory guidance, including: 18 AAC 50.260(e) - (h); Guidelines for best available 

retrofit technology under the regional haze rule; 40 CFR 51, Appendix Y; Guidelines for BART 

Determinations Under the Regional Haze Rule; and U.S. EPA’s Guidance for Estimating Natural 

Visibility Conditions Under the Regional Haze Rule (EPA-454/B-03-005, September 2003). 

The review also includes Enviroplan’s recommended preliminary BART determinations for each 

BART-eligible source at this facility, pursuant to 18 AAC 50.260(j). 

In addition to the above, the Department had a teleconference with the NPS on February 10, 

2009 to discuss preliminary BART control recommendations from Enviroplan’s January 27, 

2009 draft findings report. The NPS provided the Department with initial comments on 

February 10, 2009 (verbal) and February 12, 2009 (written as an email). This report is revised in 

response to the written NPS comments, except for comments already addressed by the 

Department on February 13, 2009. 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

3 

1.2 Source Description and Background 

Healy 1 is a nominal 25-MW unit located in Healy, Alaska, approximately 8 kilometers (5 miles) 

from DNPP. The unit is a wall-fired, wet bottom boiler manufactured by Foster Wheeler. Low 

NOx burners (LNB) and over-fired air (OFA) ports were installed in 1996. Particulate emissions 

are collected by a reverse gas baghouse installed in the early 1970s. Sulfur oxides are controlled 

by a dry sorbent injection system installed in 1999. At the present time sodium bicarbonate is the 

sorbent which is injected into the flue gas after the air heater. 

Auxiliary Boiler #1 is only used to supply heat to the Healy 1 building during shutdown periods 

or during emergency repairs to Healy 1. Auxiliary Boiler #1 also provides steam for water 

processing and hot potable water to the Healy Clean Coal Project (HCCP) if called for during 

periods when Healy 1 is not operating. The unit is also fired monthly for maintenance checks. 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

4 

2. ELEMENTS OF THE BEST AVAILABLE RETROFIT TECHNOLOGY 

ANALYSIS 

On July 1, 1999 (40 CFR Part 51), EPA published the Regional Haze Rule which provides the 

regulations to improve visibility in 156 national parks, wilderness areas, and international parks 

which were in existence in 1977. One of the key elements of the Regional Haze rule addresses the 

installation of BART for certain source categories that were built and in operation between 1962 

and 1977. 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 for each pollutant which is emitted by a 

BART-eligible source. The emissions limitation must be established on a case-by-case basis, 

taking into consideration the technology available, the cost 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 reasonably be anticipated to result from the use of such 

technology.” 

BART, also referred to as the “Clean Air Visibility Rule” (CAVR), requires states to identify 

“BART-eligible” sources. Sources need to meet all three criteria to be considered “BARTeligible” including: 

1. The source belongs to one of the 26 listed source categories; these categories are same as 

those for Prevention of Significant Deterioration (PSD) applicability analysis; 

2. The source was installed (constructed) and in operation between 1962 and 1977; and 

3. The source emits more than 250 tons per year of any one or all of the visibility impairing 

pollutants including sulfur dioxide (SO2), nitrogen oxide (NO2), or particulate matter 

(PM10). Volatile organic compounds (VOC) and ammonia (NH3) may be included 

depending on the state in which the source is located. 

The Alaska BART rule (18 AAC 50.260(f)) requires BART analysis to be conducted for NOx, 

SO2, and PM10 only (i.e., visibility impairing pollutants). The BART analysis identifies the best 

system of continuous emission reduction taking into account: 

1. The available retrofit control options, 

2. Any pollution control equipment in use at the source (which affects the availability of 

options and their impacts), 

3. The costs of compliance with control options 

4. The remaining useful life of the facility, 

5. The energy and non-air quality environmental impacts of control options, and 

6. The visibility impacts analysis. 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

5 

The five basic steps of Case-by-Case BART Analysis are: 

STEP 1—Identify All Available Retrofit Control Technologies. 

In identifying “all” options, you must identify the most stringent option and a reasonable 

set of options for analysis that reflects a comprehensive list of available technologies. It is 

not necessary to list all permutations of available control levels that exist for a given 

technology—the list is complete if it includes the maximum level of control each 

technology is capable of achieving. 

STEP 2—Eliminate Technically Infeasible Options. 

Technologies demonstrated to be infeasible based on chemical, physical, and engineering 

principles are excluded from further consideration.

STEP 3—Evaluate Control Effectiveness of Remaining Control Technologies. 

Technically feasible control technologies are ranked in the order of highest expected 

emission reduction to lowest expected emission reduction and are evaluated following a 

“top-down” approach similar to Best Available Control Technology (BACT) analyses. 

STEP 4—Evaluate Impacts and Document the Results, and 

Impacts that should be considered for each control technology include: cost of compliance, 

energy impacts, non-air quality environmental impacts and the remaining useful life of the 

unit to be controlled. 

STEP 5—Evaluate Visibility Impacts. 

Modeling should be preformed on the pre- and post-control emissions to determine the 

actual impact on visibility. This step does not need to be performed if the most stringent 

control technology is chosen. 

As discussed in Section 7 of this report, the predicted visibility impacts for Auxiliary Boiler #1 

are well below the 0.5 daily deciview metric established to determine if source emissions will 

cause or contribute to visibility impairment. Enviroplan agrees with GVEA that, pursuant to 40 

CFR 51, Appendix Y, this insignificant source is not subject to the above detailed analyses and 

the existing configuration is deemed as BART. The following sections of this report review the 

BART evaluation steps performed by GVEA for Healy Unit 1. 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

6 

3. IDENTIFICATION OF ALL AVAILABLE RETROFIT EMISSION CONTROL 

TECHNOLOGIES (Step 1) 

3.1 NOx Control Technologies Considered 

The following describes the NOx retrofit technologies deemed by GVEA as potentially feasible 

for Healy Unit 1. Although not specifically listed below, the existing low NOx burner/over fire 

air system is also a feasible NOx control technology. Enviroplan finds that GVEA has satisfied 

the BART step 1 requirement, with any additional finding(s) specific to a control option 

indicated as necessary below. 

Optimizing the Existing Low NOx Burner/Over-Fire Air System (LNB/OFA) 

The mechanism used to reduce NOx emissions with low NOx burners is to stage the combustion 

process and provide a fuel-rich condition initially; this is so oxygen needed for combustion is not 

diverted to combine with nitrogen and form NOx. Fuel-rich conditions favor the conversion of 

fuel nitrogen to N2 instead of NOx. Additional air (or OFA) is then introduced downstream in a 

lower temperature zone to burn out the char. 

Healy 1 currently has an LNB/OFA system which was installed in 1996. This system has been 

operating for an extended period of time, and, as indicated by GVEA, while plant personnel have 

exerted considerable effort to optimize performance (minimize CO within the existing permit 

NOx limits), it has not been optimized with the goal of minimizing NOx emissions. Optimization 

of the LNB/OFA system could be attempted by utilizing a boiler system consultant with the 

intent of reaching a guideline NOx target emissions of 0.23 lb/MMBtu (i.e., the 30-day rolling 

BART presumptive limit for a 200 MW unit). GVEA is uncertain whether such a limit would be 

achievable, and have indicated that minimizing NOx emissions will likely also impact other 

boiler operating parameters such as loss on ignition (LOI), carbon monoxide (CO), and excess 

air. GVEA further indicated that the 1994 PSD permit (for HCCP) resulted in extensive 

discussion between ADEC and GVEA in terms of the need to minimize CO emissions from 

Healy 1. Based on this indication, GVEA has indicated that BART control options must 

consider the impact on all emissions when attempting to reduce NOx. 

Relating to the above, Enviroplan requested on October 13, 2008 that GVEA provide additional 

information on the CO emissions minimization issue. GVEA provided a response on November 

11, 2008, which included correspondence letters from 2002 and 2005 between GVEA and 

ADEC. The correspondence indicated that CO emissions from Healy Unit 1 increased after the 

LNB/OFA installation was completed in 1998. ADEC indicated the need to minimize CO 

emissions from Healy Unit 1 through combustion system optimization without sacrificing the 

unit’s low NOx emissions. However, no permit limit was established for CO emissions from 

Healy Unit 1. 

In addition to the above, GVEA indicated in their November 11, 2008 response that the potential 

for CO emissions increases were associated not just with the LNB/OFA optimization retrofit 

scenario; but also with the use of ROFA (described below) since LNB modification would occur 

with a ROFA system. Overall, the information and correspondence pertaining to CO emissions 

as provided by GVEA is acknowledged. It is also understood that such collateral impacts can be 

considered as an additional environmental impact under the Energy, Environmental and 

Economic Impacts portion of the BART review process (i.e., Step 4). However, since visibility 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

7 

impairing pollutants are the focus of BART (i.e., NOx and not CO); and since there may not be 

an increase in CO emissions from improved LNB/OFA NOx control, Enviroplan finds that this is 

informational only and is not considered further in this review. 

Rotating Opposed Fire Air (ROFA) 

Mobotec markets ROFA as an improved second generation OFA system whereby the flue gas 

volume of the furnace is set in rotation by asymmetrically placed air nozzles. Rotation is reported 

to prevent laminar flow, so that the entire volume of the furnace can be used more effectively for 

the combustion process. In addition, the swirling action reduces the maximum temperature of the 

flames and increases heat absorption. The combustion air is also mixed more effectively. A 

typical ROFA installation would have a booster fan(s) to supply the high-velocity air to the 

ROFA boxes. GVEA noted that Mobotec proposed one 200 horsepower (hp) fan for Healy 1. 

Mobotec expects to achieve a NOx emission rate of 0.15 lb/MMBtu using ROFA technology. 

ROFA with Rotomix

The Rotamix system has been developed to optimize the reduction of unwanted substances, such 

as NOx. To optimize NOx reduction, an amine-based reagent such as ammonia is added. The 

ammonia is added using lances that are inserted in the ROFA/Rotomix nozzles. The highvelocity air in the ROFA system carries the chemicals into the center of the furnace. Mobotec 

expects to achieve a NOx emission rate of 0.11 lb/MMBtu using ROFA/Rotomix technology. 

Selective Non-Catalytic Reduction (SNCR)

Selective non-catalytic reduction (SNCR) is a post-combustion NOx control technology based on 

the reaction of NH3 and NOx. SNCR involves injecting urea/NH3 into the combustion gas path to 

reduce the NOx to nitrogen and water. SNCR is generally utilized to achieve modest NOx

reductions on smaller units. With SNCR, an amine-based reagent such as ammonia or more 

commonly urea is injected into the furnace within a temperature range of 1,600 degrees 

Fahrenheit (°F) to 2,100°F, where it reduces NOx to nitrogen and water. NOx reductions of up to 

60 percent have been achieved, although 20 to 40 percent is more realistic for most applications. 

Reagent utilization, which is a measure of the efficiency with which the reagent reduces NOx, 

can range from 20 to 60 percent, depending on the amount of reduction, unit size, operating 

conditions, and allowable ammonia slip. With low reagent utilization, low temperatures, or 

inadequate mixing, ammonia slip occurs, allowing unreacted ammonia to create problems 

downstream. The ammonia may render fly ash unmarketable, react with sulfur to foul heat 

exchange surfaces, and/or create a visible stack plume. Reagent utilization can have a significant 

impact on economics, with higher levels of NOx reduction generally resulting in lower reagent 

utilization and higher operating cost.

Selective Catalytic Reduction (SCR)

SCR is a process that involves post combustion removal of NOx from flue gas with a catalytic 

reactor. In the SCR process, ammonia injected into the exhaust gas reacts with nitrogen oxides 

and oxygen to form nitrogen and water. The reactions take place on the surface of a catalyst. The 

function of the catalyst is to effectively lower the activation energy of the NOx decomposition 

reaction. Technical factors related to this technology include the catalyst reactor design, optimum 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

8 

operating temperature, sulfur content of the fuel, catalyst de-activation due to aging, ammonia 

slip emissions, and design of the NH3 injection system. 

Reduction catalysts are divided into two groups: platinum and base metal (primarily vanadium or 

titanium). Both groups exhibit advantages and disadvantages in terms of operating temperature, 

reducing agent/NOx ratio, and optimum oxygen concentration. A disadvantage common to both 

platinum and base metal catalysts is the narrow range of temperatures in which the reactions will 

proceed. Platinum group catalysts have the advantage of requiring lower ignition temperature, 

but also have a lower maximum operating temperature. Operating above the maximum 

temperature results in oxidation of NH3 to either nitrogen oxides (thereby actually increasing 

NOx emissions) or ammonium nitrate. 

Sulfur content of the fuel can be a concern for systems that employ SCR. Catalyst systems 

promote partial oxidation of sulfur dioxide (from trace sulfur in gas and the mercaptans used as 

an odorant) to sulfur trioxide (SO3), which combines with water to form sulfuric acid. Sulfur 

trioxide and sulfuric acid reacts with excess ammonia to form ammonium salts. These 

ammonium salts may condense as the flue gases are cooled or may be emitted from the stack as 

increased emissions of PM10/ PM2.5. Fouling can eventually lead to increased system pressure 

drop over time and decreased heat transfer efficiencies. 

The SCR process is also subject to catalyst deactivation over time. Catalyst deactivation occurs 

through two primary mechanisms: physical deactivation and chemical poisoning. Physical 

deactivation is generally the result of either prolonged exposure to excessive temperatures, or 

masking of the catalyst due to entrainment of particulate from ambient air or internal 

contaminants. Chemical poisoning is caused by the irreversible reaction of the catalyst with a 

contaminant in the gas stream and is a permanent condition. Catalyst suppliers typically only 

guarantee a 3-year lifetime to achieve low emission levels for high performance catalyst systems. 

SCR manufacturers typically estimate 10 to 20 ppm of unreacted ammonia emissions (ammonia 

slip) when making guarantees at very high efficiency levels. To achieve high NOx reduction rates, 

SCR vendors suggest a higher ammonia injection rate than stoichiometrically required, which 

results in ammonia slip. Ammonia slip may increase atmospheric PM formation, which is a 

visibility impairing pollutant. Thus, an emissions trade off between NOx and ammonia occurs in 

high NOx reduction applications. While SCR may be considered potentially technically feasible 

for the boilers, there are various concerns with the technology, most notably the temperature 

required for the catalyst to activate and the unreacted ammonia introduced into the exhaust 

stream. 

SCR works on the same principle as SNCR, but a catalyst is used to promote the reaction. 

Ammonia is injected into the flue-gas stream, where it reduces NOx to nitrogen and water. 

Unlike the high temperatures required for SNCR, the reaction takes place on the surface of a 

vanadium/titanium-based catalyst at a temperature range between 580°F to 750°F. Due to the 

catalyst, the SCR process is more efficient than SNCR. The most common type of SCR is the 

high-dust configuration, where the catalyst is located upstream of the airheater and downstream 

from the economizer. 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

9 

3.2 SO2 Control Technologies Considered 

The following describes the SO2 retrofit technologies deemed by GVEA as potentially feasible 

for Healy Unit 1. Although not specifically listed below, the existing dry sorbent flue gas 

desulfurization (FGD) system is also a feasible SO2 control technology. Enviroplan finds that 

GVEA has satisfied the BART step 1 requirement, with any additional finding(s) specific to a 

control option indicated as necessary below. 

Increase sodium bicarbonate injection rate to improve SO2 removal utilizing the existing dry 

sorbent injection system

Healy 1 currently operates a dry sorbent injection system which injects sorbent into the flue gas 

after the air heater and upstream of the baghouse or fabric filter to control SO2 emissions. Since 

the system was installed in 1999, GVEA has used three different materials as sorbent in an 

attempt to maximize the efficiency of the system. When the system was first installed, calcium 

carbonate was used as the sorbent. Several years later GVEA began experimenting with trona (a 

sodium sesquicarbonate) and was able to increase SO2 capture significantly. In 2007, GVEA was 

able to optimize the system even further by using sodium bicarbonate. The SO2 in the flue gas 

reacts with the sodium bicarbonate to form dry particles, which are captured downstream in the 

existing fabric filter. Under current operation, the dry sodium bicarbonate system consistently 

achieves approximately 40 to 50 percent removal of SO2. An increase in the amount of sodium 

bicarbonate injected may have the potential to achieve SO2 removal of up to 70 percent. 

GVEA has indicated that there are several significant potential issues related to increasing 

sodium bicarbonate injection with the existing dry sorbent injection system: 

1. The existing sorbent injection system design and equipment may not be able to support 

the required sodium bicarbonate feed rate to remove SO2 continuously at 70 percent 

removal. While it may be possible to achieve 70 percent removal on a short-term basis, it 

is not feasible to operate the existing equipment at that rate continuously with no 

interruptions. 

2. From operational experience on other similar dry sodium injection systems, a brown NO2

plume may be visible at higher SO2 removal rates. It is uncertain whether a brown plume 

would be visible at a 70 percent removal rate. 

3. From previous testing at Healy 1 in March 2008, higher sodium bicarbonate injection 

rates corresponded with higher mercury emissions. 

GVEA has indicated that, while it may be possible to operate the current SO2 FGD system up to 

a 70 percent removal capability for some periods of time, consistently achieving this removal 

rate is not feasible when taking into account equipment capacities, SO2 removal performance, 

and other environmental impacts. While a new dry sodium bicarbonate injection system may be 

designed and installed with adequate capacity, concerns with the brown plume and potential 

higher mercury emission issues would remain. This notwithstanding, GVEA submitted 

additional information on March 18, 2009 pertaining to the optimization of their existing FGD 

system. The information included capital costs associated with the installation of new injectors 

needed to achieve the rate of injection consistent with an increased SO2 removal efficiency of 70 

percent. Additional discussion relating to the optimization of the existing FGD system is 

presented in Section 6.2 of this report. 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

10 

With respect to the brown plume issue, Enviroplan agrees with GVEA on the potential for an 

increased occurrence of visible plumes with increased sorbent usage. A brief literature review 

performed by Enviroplan identified one study report confirming that the use of sodium reagents 

in FGD systems can result in the production of a reddish-brown plume coloration in stack gases 

downstream of the particulate control device. It is believed that some step within the overall 

sulfation reaction (reaction of sodium reagent with SOx) initiates the oxidation of NO to NO2. It 

is the presence of the NO2 in the exiting flue gases which is the source of the plume coloration. 

GVEA provided similar additional information on the potential for a brown plume on December 

10, 2008. 

With respect to the increased mercury emissions issue, Enviroplan reviewed GVEA’s March 

2008 mercury test summary report and found that an increase in sodium bicarbonate sorbent 

injection rate corresponded to an increase in elemental mercury (Hg) emissions at the FGD 

system. 

While the current sodium bicarbonate feed rate is approximately 370 lb/hr, GVEA has indicated 

that the required feed rate to achieve a continuous 70 percent reduction is uncertain. For purposes 

of the BART analysis, GVEA used an estimated feed rate of 700 lb/hr to 1400 lb/hr. This would 

result in an additional $0.5 to $1.0 million in additional annual sorbent cost, and an estimated 

$750,000 was assumed for economic evaluation purposes. Sorbent injection rates also vary 

according to coal sulfur levels. As indicated above, additional cost information was submitted 

by GVEA on March 18, 2009 and further related discussion is presented in Section 6.2 of this 

report. 

Install lime spray dryer FGD system

The lime spray dryer typically injects lime slurry in the top of the absorber vessel with a rapidly 

rotating atomizer wheel. The rapid speed of the atomizer wheel causes the lime slurry to separate 

into very fine droplets that intermix with the flue gas. The SO2 in the flue gas reacts with the 

calcium in the lime slurry to form dry calcium sulfate particles. At Healy 1, this dry particulate 

matter would be captured downstream in the existing baghouse, along with the fly ash. It is 

assumed that a lime spray dryer system will produce a dry waste product suitable for landfill 

disposal. Operation of a lime spray dryer FGD system would result in a wet plume, reduced 

plume rise, and the potential for higher near field air quality impacts. 

Install wet limestone FGD system

Wet limestone FGD systems operate by treating the flue gas in large scrubber vessels with a 

limestone solution. Wet FGD scrubbers use an absorber tower in which flue gas is contacted by 

the limestone slurry, resulting in conversion of SO2, in the flue gas into calcium sulfate 

(gypsum), with carbon dioxide (CO2) going up the stack. The calcium sulfate is removed from 

the scrubber and disposed, and it is assumed that the waste product from a wet limestone 

scrubber system is suitable for landfill disposal. Operation of a wet limestone FGD system would 

result in a wet plume, reduced plume rise, and the potential for higher near field air quality 

impacts. 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

11 

3.3 Particulate Control Technologies Considered 

Healy 1 currently has a reverse gas baghouse installed for particulate control. The baghouse 

specifications include 12 compartments, each with 64 bags approximately 33 feet in length and 

11.5 inches in diameter, and a design air to cloth ratio of approximately 2.0 with all 

compartments in service. The baghouse used at Healy 1 achieves a control efficiency of 99.89%. 

This high efficiency baghouse is a state-of-the-art technology for particulate control for Healy 1. 

Other control technologies such as a mechanical collector, hot or cold electrostatic precipitators, 

or wet particulate scrubbers could be considered as additional feasible particulate control 

options. However, none of these alternative technologies are considered to have the potential of 

matching the consistent particulate removal performance of a baghouse. Therefore, the existing 

baghouse is considered BART for Healy 1, and completion of the five-step BART process is not 

required. 

Since GVEA currently uses a high efficiency baghouse for particulate control, Enviroplan agrees 

with GVEA in finding this control to be BART for this pollutant/emission unit. No additional 

detailed analyses (steps), including no the visibility modeling analyses, are required for 

particulate emitted from Healy 1, pursuant to 40 CFR 51, Appendix Y, Section IV.D - Step 1.9.
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

12 

4. TECHNICALLY FEASIBLE RETROFIT EMISSION CONTROL 

TECHNOLOGIES (Step 2) 

4.1 NOx Control Technologies 

GVEA based their technical feasibility on physical constraints, the current boiler configuration 

and size, and impact on boiler operation and efficiency for Healy 1. A summary showing the 

results of the evaluation process for the NOx technologies is provided in Table 4-1 below. 

Table 4-1: Technically Feasible NOx Control Options for Healy 1 

Control Technology Technically Feasible 

and Applicable? 

Reasons for Technical 

Infeasibility 

Current Operation Yes -- 

Optimize Existing LNB w/OFA Yes -- 

LNB w/OFA & SNCR Yes -- 

Replace OFA with ROFA Yes -- 

ROFA and Rotamix Yes -- 

LNB w/OFA & SCR Yes -- 

In their report, GVEA stated that each of the control methods identified above is considered 

technically feasible for controlling NOx emissions from Healy 1. GVEA did not consider 

potential space constraints in their analyses.

4.2 SO2 Control Technologies

GVEA based their technical feasibility on physical constraints, the current boiler configuration 

and size, and impact on boiler operation and efficiency for Healy 1. A summary showing the 

results of the evaluation process for the SO2 technologies is provided in Table 4-2 below. 

Table 4-2: Technically Feasible SO2 Control Options for Healy 1 

Control Technology Technically Feasible 

and Applicable? 

Reasons for Technical 

Infeasibility 

Current Operation Yes -- 

Increase sodium bicarbonate feed 

rate utilizing existing dry sorbent 

injection system 

Yes -- 

Lime Spray Dryer Yes -- 

Wet Limestone FGD System Yes -- 

In their report, GVEA stated that each of the control methods identified above is considered 

technically feasible for controlling SO2 emissions from Healy 1. GVEA did not consider 

potential space constraints in their analyses.
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

13 

5. EVALUATION OF TECHNICALLY FEASIBLE RETROFIT EMISSION 

CONTROL TECHNOLOGIES (Step 3) 

In this section, Tables 5-1 and 5-2 indicate the control effectiveness for each group of control 

technologies. The control efficiencies are relative to the current operation. The projected 

emission rates reflect a 30-day rolling average period, consistent with the BART program 

requirements for an electric generating unit (EGU). The emission limits are based on vendor 

information and professional engineering judgment, as provided by GVEA.

5.1 NOx Control Technologies 

The expected NOx emissions rate is summarized in Table 5-1 for each of the NOx removal 

technologies designated as feasible in Step 2.

Table 5-1: Control Effectiveness of the NOx Control Options for Healy 1 

Control Technology Control 

Efficiency (%)

Projected Emission 

Rate (lb/MMBtu) 

Current Operation (LNB w/OFA) - 0.25 

Optimize Existing LNB w/OFA 8.0 0.23a

LNB w/OFA & SNCR 25.0 0.19 

Replace OFA with ROFA 40.0 0.15 

ROFA and Rotamix 58.0 0.11 

LNB w/OFA & SCR 72.0 0.07 

a

 – Presumptive limit for > 200 MW wall fired boilers burning sub-bituminous coal 

5.2 SO2 Control Technologies 

Table 5-2 presents the control technologies being evaluated and the expected removal 

efficiencies and emission rates. The control efficiencies are relative to a no-control operating 

scenario. The projected emission rates reflect a 30-day rolling average period, consistent with the 

BART program requirements for an electric generating unit (EGU). The emission limits are 

based on vendor information and professional engineering judgment, as provided by GVEA. 

While the NPS suggested GVEA’s SO2 removal efficiencies have been understated for the lime 

spray dryer and wet limestone systems, Enviroplan believes the information provided by GVEA 

(and their consultant) reflect continuous operation of the systems in a relatively harsh climate. 

As such, the removal efficiencies and emission rates provided by GVEA are included in Table 5-

2 below. 

Table 5-2: Control Effectiveness of the SO2 Control Options for Healy 1 

Control Technology 

GVEA’s Projected 

Percent Removal 

Efficiency (%) 

Projected Emission Rate 

(lb/MMBtu) 

Current Operation (sorbent injection 

FGD system) 50 0.30 

Increase sodium bicarbonate feed rate 

utilizing existing dry sorbent injection 

system 

Up to 70 0.18 

Lime spray dryer 75 0.15 

Wet limestone 88 0.07 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

14 

6. COST-EFFECTIVENESS AND IMPACT ANALYSIS (Step 4) 

GVEA evaluated the cost of implementing each of the technically feasible control technology. 

The total capital investment for each control technology when applied specifically to the Healy 1

site and the annual operating and maintenance costs were calculated. These cost calculations 

were based on the following: 

• CUECost Workbook, Version 1.0. 

• CH2M HILL’s internal proprietary database. 

• Budgetary quotes from equipment vendors. 

• Quotes or cost estimation for previous design/build projects or in-house engineering 

estimates. 

GVEA calculated the cost-effectiveness of each control technology from the cost of 

implementation and the amount of pollutant reduced. Cost-effectiveness is defined as the cost of 

control per ton of pollutant removed, and it is determined on an annualized basis. The annual 

reduction in pollutant emission rate (tons/year) for each retrofit control option is determined 

relative to a baseline anticipated annual emission rate. As explained by GVEA in their January 

2009 final report submittal, the baseline anticipated annual emission rates for Healy 1 (NOx and 

SO2) are derived from the boiler heat input capacity of 340 MMBtu/hr and the average actual 

emission rates determined from 2008 CEMs data (i.e., (0.25 lb/MMBtu and 0.30 lb/MMBtu for 

NOx and SO2, respectively). The use of annual anticipated pollutant emission rates is consistent 

with 40 CFR 51, Appendix Y, Section IV.D, Step 4 for purposes of determining cost 

effectiveness. The current existing NOx and SO2 emissions control configurations for Healy Unit 

1 are reflected in these baseline emission rates. 

It is noted that the “baseline” emission rates used for cost effectiveness determination purposes, 

as described above, are not the same “baseline” emission rates used by GVEA in their 

CALPUFF visibility modeling assessment. For purposes of visibility modeling (Section 7 of this 

report), the BART rule requires an affected source to use “peak” 24-hour emission rates as the 

basis for modeling their pre-control (i.e., existing or baseline) configuration. Peak 24-hour 

emission rates, which were used by GVEA in their visibility modeling analysis, are higher than 

the annual anticipated pollutant emission rates described above.

One potential metric that can be used as a starting point in terms of deciding the acceptability of 

the cost effectiveness of a potential BART control is the BART rule itself. In its June 24, 2005 

Regional Haze Final Rule Preamble, EPA estimated ranges of cost effectiveness, as shown 

below, that were used to establish presumptive emission limits for NOx and SO2. It is noted that 

the Healy 1 unit does not fall in the category listed in 40 CFR 51, Appendix Y as a unit subject to 

the presumptive emission limits. Further, the costs presented below are not considered as ceiling 

values never to be exceeded, and they must be considered in combination with the findings of the 

other steps of the BART determination process. Nevertheless, these values are considered in this 

cost effectiveness evaluation process. 

• $400 to $2000 per ton of SO2 removed. 

• $100 to $1500 per ton of NOx removed.

GVEA’s cost impact data was used to produce graphical plots of the total annualized cost versus 

the expected emissions reduction for all control alternatives identified in the BART analysis 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

15 

(Figures 6-1 and 6-2). From the graphical plots, a “least-cost envelope” for each group of 

control technologies was identified. Control technologies that lie on this least-cost envelope are 

“dominant controls” that should be the focus for the BART determination. Dominant controls 

are the technologies that have the lowest cost for implementation per quantity of pollutant 

removed. Therefore, these technologies will be the top choice as the best method for emissions 

reduction, barring any additional factors or considerations. 

6.1 NOx Control Technologies 

Table 6-1 below provides a summary of the annual operating costs, the total tons of NOx 

removed, and the average annual cost effectiveness for each NOx retrofit control system. The 

information presented in Table 6-1 is reflective of costing provided by GVEA (applicant), as 

well as Enviroplan revised cost estimate that are discussed later in this section. 

A related graphical representation is presented on Figure 6-1 of the annual operating costs versus 

the total tons of NOx removed by each control system. 

Table 6-1: NOx Cost Effectiveness Summary for Healy 1* 

Control 

Technology 

Annualized 

Costs Control 

Efficiency 

(%) 

Total 

NOx 

Removed

(tpy) 

Average Cost $/ton 

Removed 

Applicant 

Estimate 

Revised 

Estimate 

Applicant 

Estimate 

Revised

Estimate

LNB w/OFA & 

SCR $1,263,251 $897,559 72.0 266 $4,748 $3,373 

ROFA and 

Rotamix $1,094,835 $1,094,835 58.0 214 $5,108 $5,108 

Replace OFA 

with ROFA $672,997 $672,997 40.0 148 $4,553 $4,553 

LNB w/OFA & 

SNCR $418,810 $418,810 25.0 92 $4,533 $4,533 

Optimize Existing 

LNB w/OFA $2,337 $2,337 8.0 30 $79 $79 

*Current operation (baseline) consists of the LNB/OFA system which has not been optimized for NOx

minimization (only CO emission minimization). Control efficiency values are relative to the current operation.
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

16 

Figure 6-1 

Additional Annual Cost versus Additional Tons Removed Compared to Existing Operations 

Healy 1 NOx

 Options

NOx Total 1st Year Annualized Cost w/ Tons Removed

$0

$200,000

$400,000

$600,000

$800,000

$1,000,000

$1,200,000

0 50 100 150 200 250 300

Tons NOx Removed

Total Annual Cost

Figure 6-1 shows the two dominant control options are the optimization of the current LNB and 

OFA system and the addition of a new SCR to the current LNB and OFA system as depicted on 

the least-cost envelope. All other options are to the left of the curve and therefore are inferior 

options. 

The most effective NOx retrofit control system, in terms of reduced emissions, that is considered 

to be technically feasible for Healy 1 includes combustion controls (LNB/OFA) with postcombustion SCR. This combination of controls should be capable of achieving the lowest 

controlled NOx emission rate on an on-going long-term basis. The effectiveness of the SCR 

system is dependent on several site-specific system variables, including the size of the SCR, 

catalyst layers, NH3/NOx stoichiometric ratio, NH3 slip, and catalyst deactivation rate; however, 

GVEA has indicated an emission limit of 0.07 lb NOx/MMBtu should be achievable for Unit 1. 

The second most effective NOx retrofit control system that is considered technically feasible for 

Healy 1 is the optimization of the current LNB/OFA system. This control option is expected to 

achieve an average control efficiency improvement of approximately 8% versus the current 

existing configuration at a relatively inexpensive annualized cost of approximately $2,337. 

In their July 2008 BART submittal, GVEA presented control system cost estimates for their SCR 

system option that were developed using the EPA CUECost model and CH2M HILL’s 

professional engineering judgment based on their proprietary control system database. As such, 

GVEA’s CUECost outputs could not be replicated using the inputs provided in the GVEA 

proposal. The primary reference document utilized by GVEA for developing the cost estimates 

was: “Multipollutant Emission Control Technology Options for Coal-fired Power Plants”; EPA600/R-05/034, March 2005. GVEA estimated the capital cost to install the SCR system to be 

$8.775 million and a total capital investment cost of $350/kW after considering two sources (1) 

the EPA Multipollutant report which provides a capital cost estimate range of $50-140/kW, and 

(2) a composite of EGU-specific BART determinations compiled by the NPS which show a 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

17 

range of approximately $80-400/kW. GVEA estimated the average cost effectiveness of the SCR 

control system on Healy Unit 1 to be $4,748/ton of NOx removed. 

An independent study on SCR retrofits and cost analyses for BART eligible boilers was prepared 

in January 2009 by the National Park Service (NPS), and updated in March 2009. The NPS 

study results estimated lower costs for SCR retrofits than predicted by GVEA. Specifically, the 

NPS analysis suggests SCR systems to have total capital investment costs in the range of 

$80/kW to $270/kW. The NPS, which estimated the SCR cost effectiveness values for affected 

EGUs using EPA’s Control Cost Manual, determined that the cost effectiveness of the SCR 

control system on Healy Unit 1 can be as low as $2,971/ton. The NPS also determined the total 

capital investment for the Healy Unit 1 SCR system to be $222/kW, instead of the total capital 

investment of $351/kW estimated by GVEA. This finding notwithstanding, the Department was 

not certain of the accuracy of the NPS cost estimates for SCR, as they may not reflect the 

relatively high cost of materials and services found in Alaska. As such, Enviroplan re-evaluated 

the SCR control costs reflected in the January 2009 draft findings report. Enviroplan’s reevaluation included review of both GVEA’s and the recent NPS SCR cost estimates, and the 

development of Enviroplan’s own cost estimates using the OAQPS Control Cost Manual - Fifth 

Edition, February 1996, EPA 453/B-96-001. 

Enviroplan calculated the cost of SCR on a dollar per ton ($/ton) of NOx removed basis, using 

the OAQPS Control Cost Manual, as follows: 

• The SCR cost estimates shown in Table 6-1 above have been revised as follows: 

o SCR Construction (Capital) Cost: $6,023,332. 

o Capital Recovery Factor: 0.1098. To calculate the capital recovery costs 

Enviroplan assumed a period of 15 years and interest rate of seven percent. The 

EPA Control Cost Manual cites an expected life of 20 years for a SCR system. 

Twenty years was thought to be too optimistic considering the harsh climate of 

the region. Recent cost analyses in Alaska have used life expectancies of 10 years 

for SCR. Therefore, Enviroplan believes the life expectancy of the SCR (and 

other capital) of 15 years used by GVEA is justified. 

o Annual Capital Cost: $661,329 ($6,023,332 * 0.1098 = $661,329) 

o Annual O&M Costs: $236,229 

o Total Annual Cost: $897,559 ($661,329 + $236,229 = $897,559) 

o Annual NOx removed (assuming 72 percent removal efficiency): 266 tons (370 

tons * 0.72 = 266 tons) 

o Cost in $ per ton removed: $3,373/ton ($897,559/266 tons = $3,373/ton) 

o The Total Capital Investment Cost: $241/kW ($6,023,332/ 25MW/1000kW/MW 

= $241/kW) 

• GVEA estimates a capital cost of $8.775 million for SCR (which Enviroplan cannot 

reproduce); this is at least 30 percent higher than the OAQPS Control Cost Manual 

estimate for SCR. 

• Enviroplan finds a cost of about $241/kW versus the GVEA estimate of $350/kW to be 

reasonable in view of recent similar installations and literature estimates. It is 

Enviroplan’s opinion, based on recent similar installations, literature estimates and the 

NPS studies discussed above, that the installed costs for retrofitting SCR on a plant the 

size of Healy Unit 1 ranges from $200/kW to $270/kW, exclusive of any extremely 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

18 

favorable or unfavorable site-specific conditions which have not been considered by 

GVEA in this study. In the case of GVEA, there are factors that would tend to push costs 

toward the high end of the range. Some of the factors that tend toward higher costs 

include: 

o The Healy Plant’s remote location and its impact on labor and transportation 

availability, and cost; and 

o Use of sub-bituminous coal (as compared to bituminous coal). 

In summary, Enviroplan finds that GVEA’s estimated installed cost for SCR is high by at least 

30 percent. 

6.1.1 Cost of Compliance 

The average annual cost effectiveness for NOx control on Healy 1 is approximately $79/ton for 

the optimization of the current LNB and OFA system. The average cost effectiveness for existing 

combustion controls plus SCR on Healy 1 is $3,373/ton and the total capital investment for the 

SCR is $241/kW, based on Enviroplan’s revised cost estimates. 

The annual cost effectiveness of the SCR system exceeds the presumptive EGU level for BART 

($1500/ton), as presented earlier in this Section 6. However, the total capital cost ($/kW) is 

within the range common to other BART-eligible units using SCR, as reported by the NPS. As 

already indicated herein, the presumptive costing information is not a ceiling value; instead, it is 

a guideline value that must be considered in combination with the findings of the other BART 

analyses (steps). 

6.1.2 Energy Impact

Evaluation of the energy factor indicates that there is no significant energy penalty associated 

with the optimization of the current LNB and OFA system. However, operation of an SCR 

system has certain collateral environmental consequences. In order to maintain low NOx

emissions some excess ammonia will pass through the SCR. Ammonia slip will increase with 

lower NOx emission limits, and will also tend to increase as the catalyst becomes deactivated. 

The application of an SCR system would also consume power and reduce efficiency, thereby 

decreasing energy available to consumers. The additional electrical demand will consume 

almost 0.5 percent of the total generating capacity of Healy Unit 1. These energy impacts are 

included in the operational costs as part of the economic impact analysis. 

6.1.3 Non-Air Quality Environmental Impacts

Evaluation of the non-air quality environmental impacts indicates that there are no non-air 

quality related impacts associated with the optimization of the current LNB and OFA system. 

However, SCR requires some form of ammonia (NH3) source for operation. This can be stored 

in liquid, solid or gas, and processed on site for use. Depending on quantities stored there will be 

risk management requirements associated with ammonia storage. Also, production of ammonia 

primarily uses a finite resource (natural gas), so use of ammonia could have long term 

consequences on fossil fuel supplies. In addition, SCR may cause enough ammonia 

accumulation in ash to make the ash not usable for cement and other beneficial uses. Currently, 

the plant sells much of its ash for such beneficial uses. If the ash is contaminated by ammonia, 

there will be associated environmental impacts in the form of additional land use requirements. 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

19 

6.2 SO2 Control Technologies 

Three control technologies are technically feasible and capable of achieving very low SO2

emission rates. An evaluation of the economic, energy and environmental impacts associated 

with each control system is provided below. 

Table 6-2 below provides a summary of the expected annual operating costs, the amount of SO2

removed, and the average annual cost effectiveness for each SO2 retrofit control system. The 

information presented in Table 6-2 is reflective of costing provided by GVEA (applicant), as 

well as Enviroplan revised cost estimate that are discussed later in this section. 

A related graphical representation is presented on Figure 6-2 of the annual operating costs 

associated with building and operating each control system versus the total tons of SO2 removed 

by each control system. 

Table 6-2: SO2 Cost Effectiveness Summary for Healy 1 

Control 

Technology 

Original 

Annualized 

Costs 

Revised 

Annualized

Costs 

Control 

Efficiency(1)

(%) 

Total 

SO2 

Removed

(tpy) 

Original 

Average 

Cost 

$/ton 

Removed 

Revised 

Average 

Cost $/ton 

Removed 

Wet limestone $2,659,104 $2,659,104 76.7 340 $7,821 $7,821 

Lime spray 

dryer $1,607,872 $1,607,872 50.0 222 $7,243 $7,243 

Increase 

sodium 

bicarbonate 

feed rate 

utilizing 

existing dry 

sorbent 

injection 

system 

$758,322 $1,656,590 40.0 177 $4,284 $9,359 

(1) Control efficiencies listed in Table 6-2 are expressed as control relative to current operation (baseline), 

which consists of the sorbent (sodium bicarbonate) injection FGD system. 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

20 

Figure 6-2 

Figure 6-2 shows the dominant control option to be the wet FGD system as depicted on the leastcost envelope. All other options are to the left of the curve and therefore are inferior options. 

Enviroplan has revised the January 27, 2009 draft findings report for the existing FGD system 

optimization option to increase the sorbent injection rate. This revision is in relation to GVEA’s 

submittal of revised cost information for this SO2 emissions control option. The following 

presents a summary of Enviroplan’s findings associated with review of related information 

provided by GVEA: 

• GVEA submitted revised cost estimates on 03/18/09: 

o The revised cost included a capital cost estimate of $2,000,000 or $80/kW, which 

was not included in GVEA’s original BART analysis report submitted on July 28, 

2008. The estimate utilized the EPA Multipollutant report (“Multipollutant 

Emission Control Technology Options for Coal-fired Power Plants”; EPA-600/R05/034, March 2005) capital cost range of $70 - $120/kW. The capital cost 

estimate is based on the required installation of a back-up sorbent injection system 

with a design sorbent injection rate of 1,200 lb/hr. GVEA estimated that up to an 

additional 830 lb/hr of reagent may be required to achieve 70% SO2 reduction 

(Healy is presently injecting sorbent at a rate of 370 lb/hr). 

o An updated first year reagent cost of $1,217,859 was determined based on a 

system design capacity of 1,200 lb/hr. 

o A current delivered cost of sodium bicarbonate of $335/ton, including surcharges 

for shipment to the Healy plant site, based on purchase receipts provided by 

GVEA. 

o Results showed: 

 Annual O&M Costs: $1,422,930 

 Total Annual Cost: $1,656,590 

 Annual SO2 removed (assuming 70 percent removal efficiency): 177 tons 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

21 

 Cost in $ per ton removed: $9,359/ton ($1,656,590/177 tons = $9,359/ton) 

In summary, Enviroplan finds that GVEA’s revised estimated cost for the optimization of the 

sorbent injection system for Healy Unit 1 SO2 emission control is justified. 

6.2.1 Cost of Compliance

$7,821/ton; the lime spray dryer to be $7,243; and optimizing the existing FGD system to be 

$9,359. EPA estimated that for a majority of BART eligible units greater than 200 MW, cost of 

control systems used to meet the presumptive SO2 emission limits is $400 to $2,000 per ton of 

SO2 removed (see, 70 FR 39133). Therefore, the average effectiveness of SO2 removal at Healy 

1 is more than triple the average cost effectiveness calculated by EPA for SO2 control on large 

EGUs. The wet limestone FGD system control option is expected to achieve an average control 

efficiency of approximately 76.7% from baseline at an annualized cost of $2.7 million; the lime 

spray dryer control option is expected to achieve 50% from baseline at an annualized cost of $1.6 

million; and optimizing the existing FGD system is expected to achieve 40% from baseline at an 

annualized cost of $1.7 million. 

6.2.2 Energy Impact

Evaluation of the energy factor indicates that the installation of a new wet limestone FGD system 

would require additional power. Auxiliary power is required for material handling, reactant 

preparation, pumps, mixers, and to overcome significant pressure drops through the reaction 

vessels. Based on the economic analysis performed, the auxiliary power requirement for wet 

FGD control system is approximately 0.94% of the gross energy output of the generating unit. 

Healy 1 has a gross rating of 25 MW; therefore, auxiliary power requirements for FGD control 

system would be approximately 240 kilowatts (kW). Energy impacts associated with each 

control technology were included in the BART economic impact evaluation as an auxiliary 

power cost. 

6.2.3 Non-Air Quality Environmental Impacts 

Evaluation of the non-air quality environmental impacts indicates that the installation of a new 

wet limestone FGD system will also result in the storage of new chemicals onsite and a new 

waste stream for the facility. The exit flue gas stack temperature with both of these technologies 

will be less than the current operation, thus flue gas buoyancy will be decreased. In addition, 

saturated flue gas would significantly increase the probability of creating fog during the summer 

and ice fog during the winter, in the area surrounding the plant. 

6.3 Economic Impacts – Rate Payer Analysis 

During February 2009 conversations with the Department, GVEA requested that rate payer cost 

considerations be included as part of the cost of compliance with the BART rule. Rate payer 

cost analysis information was not provided, nor considered, by GVEA in their July 2008 and 

January 2009 BART analysis submittals. However, 40 CFR 51, Appendix Y, Section IV.D, Step 

4, does allow for unusual circumstances that exist for a source that might lead to unreasonable 

cost-effectiveness estimates. Further, 40 CFR 51, Appendix Y, Section IV.E provides for 

summarization of costs of compliance using cost-effective measures relevant to the source. As 

such, the Department agreed to such considerations as applied only to the Healy Unit 1 BART 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

22 

control options of SCR for NOx control and increased FGD sorbent injection for SO2 control. 

GVEA provided rate payer cost data and analyses on March 18, 24 and 30, 2009. 

The BART rule provides that the energy impacts analysis may consider whether a particular 

control alternative would result in a significant economic disruption within the area or region of 

the affected source. As such, the unique geographic and economic characteristics affecting the 

business community within Alaska, including power producers, justify that the potential control 

costs consider the economic impact on each customer, expressed in units of cost per kilowatthour. Below is a list of attributes that describe the communities served by GVEA. 

• The community is not connected to a nationwide or outside electric grid or connected to 

other utilities; 

• The community does not have access to large scale alternative power generation options 

(continuous hydro-power, geothermal energy, and wind energy); 

• The stationary source is owned by a small publicly owned non-profit association and 

electricity rates would be adjusted to account for any increased facility costs; and 

• The stationary source is located in a remote area, which is not accessible year round for 

economical supply of fuel and reagent. 

The GVEA rate payer base is small relative to typical electric utilities within the continental 

United States. GVEA residential customers paid $0.17705/kWh in the year 2008. As established 

by the Department of Energy, the “Representative Average Unit Cost” of electricity for a 

residential user is $0.0973/kWh. So, a residential customer of GVEA pays 180 percent of the 

national average. Given this relatively high cost to GVEA residential rate payers, the costs of 

SCR and an optimized dry sorbent injection system have been evaluated by GVEA on a per rate 

payer basis. The following presents a summary of Enviroplan’s findings associated with our 

review of GVEA’s analysis: 

• GVEA submitted rate payer analysis on 03/18/09: 

o Initially, the rate payer analysis reflected combined costs for NOx and SO2 control 

systems only, and it did not include individual control system analyses 

o Rate payer analyses were presented for both GVEA (i.e., entire plant) and Healy Unit 

1, based on budget and electric output projections for 2009 

o Rate payer analysis based on non-fuel expenses only (did not include fuel costs) 

o Results showed an incremental rate payer increase due to BART controls of: 

 3.3% when compared to annual average rate payer costs for entire plant 

 36% when compared to annual average rate payer cost for Healy Unit 1 alone 

o GVEA specified a 25% increase in energy charge to rate payers since 2002 

o GVEA specified the 25% increase does not include rising fuel costs which are passed 

directly to their customers 

o GVEA expects in 2010 another 5.6% increase in energy charge, for a total increase 

since 2002 of 30.6% 

o GVEA notes the national average rate payer cost as of November 2008 to be 9.73 

cents/kW-hr (average Alaska cost for November 2008 was 14.28 cents/kW-hr), while 

GVEA’s rate payer cost for November 2008 was 19.502 cents/kW-hr 

o GVEA qualitatively indicates the rate payer costs to be proportionally higher than for 

utilities with a large rate base (GVEA residential rate base is 36,860 customers) 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

23 

• GVEA submitted additional rate payer analysis information on 3/29/09: 

o Rate payer analysis provided for individual NOx and SO2 control systems, with 

findings of: 

 1.86% rate payer increase for SO2 control system 

 1.41% rate payer increase for NOx control system 

o GVEA provided 2008 annual average residential customer energy charge of 17.705 

cents/kW-hr 

• Enviroplan reviewed GVEA increased rate payer estimates and determined slightly 

different percent increases to the rate payers as follows: 

o 0.70% rate payer increase for SO2 control system 

o 0.43% rate payer increase for NOx control system 

• Differences between Enviroplan and GVEA findings due to: 

o Revision to control system capital cost information; 

o Use of 2008 annual average residential rate (17.705 cents/kW-hr) as the basis for 

determining incremental increases to rate payers (not 2009 nonfuel costs, as used by 

GVEA), 

o Only rate payer costs associated with GVEA (entire plant) are considered, i.e., no 

consideration is given to an incremental cost increase to the ratepayer based solely on 

the operation of Healy Unit 1 since rate payer costs reflect entire plant operations 

Enviroplan has tabulated the results of the above described rate payer cost analysis. The results 

are summarized in following Tables 6-3-1 through 6-3-4. 

Table 6-3-1: GVEA Estimated Operating Expenses for the SCR NOx Control Option 

2009 Non-Fuel 

Cost ($) 

Post 

Control 

Non-Fuel 

Cost ($) 

2009 

Anticipated 

Total Sales 

(kWh) 

2009 NonFuel Cost per 

kWh 

($/kWh) 

Post Control 

Non-Fuel 

Cost pe kWh 

($/kWh) 

Percent 

Increase 

(%) 

89,299,216 90,562,467 1,380,383,090 0.06469 0.06561 1.41 

Notes: 

2009 non-fuel cost per kWh ($/kWh): $89,299,216 / 1,380,383,090 kWh = $0.06469/kWh 

Post controls non-fuel cost per kWh ($/kWh): $90,562,467 / 1,380,383,090 kWh = $0.06561/kWh
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

24 

Table 6-3-2: GVEA Estimated Operating Expenses for the SCR NOx Control 

Option as Revised by Enviroplan 

SCR Depreciationa$401,555 

Interestb$421,633 

O&M $236,229 

Total $1,059,417 

Cost Associated w/ SCR ($/kWh) $0.00077 

Avg Cost for 2008 ($/kWh) c$0.17705 

Increase due to SCR 0.43% 

@500 kWh/month $0.39/month 

$4.62/year 

@1000 kWh/month $0.77/month 

$9.24/year 

 Table Notes: 

 a SCR Depreciation over 15 years: $6,023,322/15 years = $401,555 

b Assuming 7.0 percent interest (capital cost times 7.0 percent) 

c

 Provided by GVEA

Table 6-3-3: GVEA Estimated Operating Expenses for the FGD Optimization SO2

Control Option 

2009 Non-Fuel 

Cost ($) 

Post 

Control 

Non-Fuel 

Cost ($) 

2009 

Anticipated 

Total Sales 

(kWh) 

2009 NonFuel Cost per 

kWh 

($/kWh) 

Post Control 

Non-Fuel 

Cost pe kWh 

($/kWh) 

Percent 

Increase 

(%) 

89,299,216 90,955,806 1,380,383,090 0.06469 0.06589 1.86 

Notes: 

2009 non-fuel cost per kWh ($/kWh): $89,299,216 / 1,380,383,090 kWh = $0.06469/kWh

Post controls non-fuel cost per kWh ($/kWh): $90,955,806 / 1,380,383,090 kWh = $0.06589/kWh
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

25 

Table 6-3-4: GVEA Estimated Operating Expenses for the FGD Optimization SO2

Control Option as Revised by Enviroplan 

2009 

Injection System Depreciationa$133,333 

Interestb$160,000 

O&M $1,422,930 

Total $1,716,263 

Cost Associated w/ FGD Optimization 

($/kWh) $0.00124 

Avg Cost for 2008 ($/kWh) c$0.17705 

Increase due to Injection System 0.70% 

@500 kWh/month $0.62/month 

$7.44/year 

@1000 kWh/month $1.24/month 

$14.88/year 

 Table Notes: 

 a Injection System Depreciation over 15 years: $2,000,000/15 years = $133,333 

b Assuming 7.0 percent interest (capital cost times 7.0 percent) 

c Provided by GVEA

Based on the information tabulated in Tables 6-3-1 through 6-3-4, the following findings are 

summarized: 

• Using GVEA’s rate payer cost estimates, the cost per kWh for SCR is $0.00092/kWh, 

which reflects an increase above the 2008 average rate payer cost of about 1.4 percent. 

For a family that uses 500 kWh/month, the addition of SCR would cost $0.46/month and 

$5.52/year. For a family that uses 1,000 kWh/month, the additional cost is $0.92/month 

and $11.04/year. 

• Using Enviroplan’s adjusted costs, the cost per kWh for SCR is $0.00077/kWh, which 

reflects an increase above the 2008 average rate payer cost of about 0.43 percent. For a 

family that uses 500 kWh/month, the addition of SCR would cost $0.39/month and 

$4.62/year. For a family that uses 1,000 kWh/month, the additional cost is $0.77/month 

and $9.24/year. 

• Using GVEA’s rate payer cost estimates, the cost per kWh for FGD sorbent rate increase 

is $0.0012/kWh, which reflects an increase above the 2008 average rate payer cost of 

about 1.8 percent. For a family that uses 500 kWh/month, the addition of SCR would 

cost $0.6/month and $7.20/year. For a family that uses 1,000 kWh/month, the additional 

cost is $1.20/month and $14.40/year. 

• Using Enviroplan’s adjusted costs, the cost per kWh for FGD sorbent rate increase is 

$0.00124/kWh, which reflects an increase above the 2008 average rate payer cost of 

about 0.70 percent. For a family that uses 500 kWh/month, the addition of SCR would 

cost $0.62/month and $7.44/year. For a family that uses 1,000 kWh/month, the 

additional cost is $1.24/month and $14.88/year. 

Enviroplan acknowledges the incremental costs associated with the individual installations of 

SCR and the optimized FGD system; however, we do not believe these costs to be prohibitive in 

terms of the assessing the viability of either emissions reduction system. It is noted that the 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

26 

increase in the cost to a residential rate payer is presented on a per control option basis (i.e., does 

not reflect the total combined costs of both the NOx and SO2 control system options). The 

BART rule requirements are specific in that the BART emission limitations (and possible retrofit 

control technologies) are to be determined on a per visibility impairing pollutant (VIP) basis, and 

not on a combined VIP basis. 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

27 

7 VISIBILITY IMPACTS EVALUATION (Step 5) 

Pursuant to 40 CFR 51, Appendix Y and 18 AAC 50.260, the BART determination must include 

an evaluation of the impacts associated with the installation of various control options regarding 

potential visibility benefits in Class I areas. As provided by 18 AAC 50.260(h)(3)(A), GVEA 

opted to conduct their visibility modeling analysis in accordance with the modeling protocol 

developed by the Western Regional Air Partners (WRAP) - Regional Modeling Center (RMC). 

The visibility modeling analysis conducted by GVEA and their consultant, CH2M Hill, is 

intended to comply with 40 CFR 51, Appendix Y, Section IV.D - Step 5, “How should I 

determine visibility impacts in the BART determination?”. GVEA conducted the analysis to 

support their control analysis and proposed BART determinations. Since GVEA currently uses a 

high efficiency baghouse for particulate control, which is considered BART for this 

pollutant/emission unit, no specific visibility modeling analyses are required for particulates 

pursuant to 40 CFR 51, Appendix Y, Section IV.D - Step 1.9. For the feasible NOx and SO2

retrofit control technology options presented in Section 4, GVEA estimated the visibility impacts 

according to the following sequence: 

• Model pre-control (i.e., existing baseline) emissions 

• Model individual post-control emissions scenarios 

• Determine degree of visibility improvement 

• Factor visibility modeling results into BART “five-step” evaluation, including a visibility 

cost effectiveness metric expressed as cost of control option per deciview improvement 

($/DV) 

The following sections provide the findings associated with the methods used by GVEA to 

evaluate the visibility impacts at the DNPP Class I area and the potential visibility improvements 

associated with the retrofit technologies evaluated by GVEA. 

7.1 CALPUFF Modeling Approach 

GVEA used the CALPUFF modeling system to estimate their visibility impacts. Their approach 

is described in Section 4 of their January 2009 BART control analysis report. However, 

Enviroplan also relied on the following information, as needed, as part of the review: 

• July 2008 BART analysis report and companion CALPUFF modeling files prepared by 

CH2M Hill, and submitted by GVEA on July 28, 2008; 

• October 16, 2008 letter prepared by Enviroplan requesting clarification and additional 

information pertaining to the CH2M Hill July 2008 study report; 

• November 11, 2008 submittal by GVEA of CH2M Hill responses to the October 16, 2008 

Enviroplan letter, along with revised CALPUFF modeling files; 

• December 4, 2008 letter prepared by Enviroplan requesting further clarification and 

additional information pertaining to the CH2M Hill November 11, 2008 letter; 

• December 11, 2008 Enviroplan, CH2M Hill, GVEA, Department conference call to discuss 

the December 4, 2008 Enviroplan letter and a draft response provided by GVEA on 

December 10, 2008; 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

28 

• Final revised January 2009 BART analysis report prepared by CH2M Hill; and a companion 

“GVEA Healy BART Response to 12/04/08 Comments from Enviroplan” document, 

submitted by GVEA on January 2, 2009. No further changes were made to the November, 

2008 CALPUFF modeling files. 

• Teleconferences between the Department, GVEA, CH2M Hill and Enviroplan on February 

25 and 27, 2009 and March 2, 2009; and related BART study information submitted on 

March 18, 2009 with additional clarifying information submitted on March 24 and 30, 2009. 

No further changes were made to the November, 2008 CALPUFF modeling files. 

The following discussion presents findings related to the GVEA CALPUFF visibility modeling 

analysis. 

BART-Eligible Source Emission Rates and Stack Parameters

Section 4.0 of the final GVEA BART study report presents the emissions inventory data used in 

the visibility modeling analysis. The following summarizes the information used in the 

CALPUFF input files, and any findings relating to review of this information: 

• Review of the CALPUFF input files provided by GVEA (November 2008) indicates that the 

stack parameters and emission rates shown in the final report Table 4-3 and 4-4 have been 

used in the CALPUFF visibility modeling.

• The NOx, SO2 and PM10 emission rates used in the CALPUFF modeling for Auxiliary Boiler 

#1 are consistent with the emission rates used by WRAP.

• The PM10 emission rate used in the modeling analysis for Unit 1 is based on a 2004 stack 

test. It is noted that a review of the WRAP-RMC CALPUFF input files for Unit 1 indicated 

that no particulate matter emission rate was used by WRAP for this unit. This 

notwithstanding, GVEA/CH2M Hill has correctly used the stated PM10 emission rate in their 

July 2008 visibility modeling, and their resubmitted November 11, 2008 visibility modeling. 

• Auxiliary Boiler #1 stack exit parameters used in the CALPUFF modeling are consistent 

with the same parameters used in the WRAP modeling. The modeled stack parameters used 

by GVEA for Unit 1 reflect more accurate information based on a reevaluation of the 

physical characteristics of the stack, as indicated by GVEA in their November 11, 2008 

response. 

• For each BART eligible source, all PM10 emitted has been assumed as PM2.5, which is 

consistent with the WRAP modeling. While GVEA correctly followed the protocol, it is 

noted that the NPS commented on February 12, 2009 that not modeling elemental carbon and 

organic aerosol emissions was an error in the WRAP modeling protocol. 

• Stack parameters for each control scenario have been provided by GVEA that reflect the 

anticipated changes associated with installation of each control technology alternative being 

evaluated. 

• The NOx and SO2 emission rates used in the CALPUFF modeling for Unit 1 are based on 

continuous emissions monitoring (CEM) data recorded by GVEA for the period May 1, 2007 

through April 30, 2008. 40 CFR 51, Appendix Y recommends that the pre-control emissions 

(i.e., existing configuration) be modeled using “the 24 hour average actual emission rate 

from the highest emitting day of the meteorological period modeled”. Calendar year 2002 is 

the meteorological period modeled by WRAP. CH2M Hill clarified on 11/11/08 that GVEA 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

29 

did not have readily available emissions information for 2002 due to a recent CEMs system 

upgrade; therefore, the most recent one-year period (5/1/07 - 4/20/08) was used as a 

surrogate data period. Section 4.3.3 of the GVEA final report indicates the CEM data 

represents a realistic depiction of anticipated annual emissions for the unit. Due to the lack 

of 2002 actual emissions information, Enviroplan believes the current CEM data to be an 

acceptable surrogate data set for this analysis. 

• GVEA modeled their current (existing) control configuration using two emission rate 

scenarios. GVEA used the “peak 24-hour” NOx and SO2 emission rates for their “baseline” 

scenario. GVEA also developed a “null” scenario wherein they used an “anticipated 24-

hour” emission rate for the “controlled” pollutant (e.g., SO2 when evaluating the existing dry 

FGD system), and the “peak” emission rate for the “other” pollutant (e.g., NOx when 

evaluating the existing dry FGD system). The “anticipated” emission rates reflect the 24-

hour emission rates averaged over a full-year of boiler operation. The 24-hour average NOx

and SO2 emission rates for the respective “baseline” and “anticipated” configurations, 

expressed as hourly emission rates, are summarized below: 

Scenario* NOx (lb/hr) SO2 (lb/hr) 

Baseline (“peak” 24hour average 

emission rates) 

151.0 182.2 

Null (“anticipated” 24hour 

average emission rates) 

85.0 102.0 

*Both scenarios reflect existing controls, i.e., low NOx burners/over-fire air and dry 

sodium bicarbonate flue gas desulfurization (FGD) system 

Enviroplan initially believed that GVEA used the “anticipated” emission rates to determine 

modeled emission rates for the other retrofit control scenarios. However, GVEA clarified 

during the February 25 and 27, 2009 teleconferences that the modeled “null” option was 

presented for informational purposes only, and that it was not used as the basis for 

establishing modeled emission rates for each retrofit control option. GVEA indicated that the 

emission rates used for each retrofit control option were based on vendor information and 

professional engineering judgment; and they did not multiply the retrofit control efficiencies 

presented in their report (e.g., Table 3-2) by the “null” 24-hour emission rates. Finally, 

GVEA clarified that the control efficiencies were used only for control cost determination 

purposes (in conjunction with “null” emission rates). This is acceptable for control cost 

purposes only, since 40 CFR 51, Appendix Y, Section IV.D., Step 4, suggests that a realistic 

depiction of anticipated annual emissions be used for cost estimation purposes. 

Based on the above, Enviroplan has determined that the NOx and SO2 emission rates used in 

the visibility modeling analysis for each retrofit scenario are correct; and the modeling results 

for the “null” configuration have been ignored. Likewise, the visibility modeling summary 

results presented in Tables 4-7 and 5-1 of the GVEA 2009 study report are correct. Findings 

associated with our review of these results tables are presented at the end of this section. 

CALMET Modeling Procedures

The CALMET modeling methods and input file have been compared for consistency with the 

recommendations of the WRAP protocol. GVEA’s CALMET modeling approach is summarized 

below: 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

30 

• CALMET version 6.211, level 060411; 

• CALMET modeling performed for one year (2002) as recommended in the protocol, using 

scripts and inputs to recreate the CALMET output for the study;

• 15-km resolution 2002 MM5 data taken from the WRAP website 

(http://pah.cert.ucr.edu/aqm/308/bart/calpuff/calmm5/ak/2002/); and 

• GVEA summarized the following information in their final report, which has been compared 

to the WRAP protocol and it was found to be consistent: 

o CALMET input parameters and options used by GVEA, as summarized in final report 

Table 4-1; 

o the meteorological surface stations, as specified in Table 4-2; and 

o the vertical layer resolution, and modeling domain extent and resolution, as specified in 

Section 4.2.1, 

The data described by GVEA in their final study report and used in the CALMET input files are 

consistent with the WRAP protocol. 

CALPUFF Modeling Procedures

The CALPUFF modeling methods and the related model input options selected for use in this 

study have been reviewed for consistency with the WRAP protocol and related BART guidance 

documents. Applied modeling procedures and any findings are summarized as follows: 

• CALPUFF version 6.112, level 060412; 

• CALPUFF modeling performed for one year (2002), consistent with WRAP modeling; 

• EPA CASTNET hourly ozone data from Denali, using 40 ppb default for missing hours; 

• A background ammonia concentration of 0.1 ppb (Note that this is consistent with the WRAP 

protocol which GVEA is using pursuant to 18 AAC 50.260(h)(3)(A), even though the U.S. 

Fish and Wildlife Service (FWS) has requested BART sources developing their own 

modeling protocols to assume a background concentration of 0.5 ppb); 

• Regulatory default model options when such options are specified; 

• National Park Service discrete receptor locations and elevations for DNPP 

(http://www2.nature.nps.gov/air/maps/Receptors/index.cfm); 

• Aerodynamic building downwash not used in the modeling analysis; and 

• CALPUFF computational domain consistent with the CALMET meteorological domain 

(NX=275, NY=325). 

The data described by GVEA in their final study report and used in the CALPUFF input files are 

consistent with the WRAP protocol. 

CALPOST Modeling Procedures

The CALPUFF post-processing methods of CALPOST and the related model input options 

selected for this study have been reviewed for consistency with the WRAP protocol and related 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

31 

BART guidance documents. Applied modeling procedures and any findings are summarized as 

follows: 

• CALPOST version 6.131, level 060410; 

• Particle growth curve f(RH) for hygroscopic species based on EPA (2003) f(RH) tabulation; 

• CALPOST default extinction efficiencies for PM fine (PMF), PM coarse (PMC), ammonium 

sulfate, ammonium nitrate, organic carbon (OC), and elemental carbon (EC); 

• Calculation of background extinction and change to extinction using the recommended 

CALPOST Method 6 (MVISBK=6); 

• Monthly relative humidity adjustment factors specific to the DNPP Class I area as taken from 

Table A-3 of Guidance for Estimating Natural Visibility Conditions Under the Regional 

Haze Rule, EPA-454/B03-005 (September 2003); and 

• Annual average natural background aerosol concentrations as taken from Table 2-1 of 

Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule, EPA454/B03-005 (September 2003). 

The data described by GVEA in their final study report and used in the CALPOST input files are 

consistent with the WRAP protocol. 

7.2 Visibility Modeling Results 

As supported in EPA’s BART rules and guidelines, when conducting visible impact modeling 

using only one year of meteorological data, source impacts should reflect the maximum change 

to the daily Haze Index (HI) as compared to a natural background, expressed in units of deltadeciviews (∆dV). In their July 2008 report, GVEA utilized 98th percentile delta-deciview 

visibility predictions; however, pursuant to the BART rules, this is permissible only when 

modeling multiple years of meteorology (e.g., 3-years). The final January 2009 report correctly 

presented modeling results as maximum values (Tables 4-7 and 5-1 of the final report). 

Additionally, the BART rules and 18 AAC 50.260 have established 0.5 daily deciviews (dV) as 

the metric against which predicted visibility impacts should be compared for purposes of 

establishing whether a source causes or contributes to impairment of visibility. 

Table 4-7 of GVEA’s final report presents a summary of the highest delta-deciview visibility 

predictions from the one year (2002) of modeling at the DNPP Class I area for each NOx and SO2

emissions control scenario. Table 4-7 also presents the number of days predicted to exceed the 

significance level of 0.5 dV for each scenario, along with related visible cost effectiveness values 

(e.g., $/deciview improvement). Table 5-1 of the final report presents the change (i.e., 

improvement) in model prediction results when comparing “baseline” visibility predictions to the 

alternate control scenarios. 

7.3 Visibility Monitoring Program 

In addition to performing the required retrofit scenario visibility impact analysis as part of the 

overall BART control determination analysis, GVEA indicated in the January 2009 final report 

that they previously conducted a visibility monitoring program (VMP). GVEA provided in 

Section 1.0 of their final report a summary of the VMP, which is abbreviated below. 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

32 

GVEA received a PSD permit in 1994 to expand the Healy power plant and construct the 

Healy Clean Coal Project (HCCP), a 50-megawatt (MW) coal-fired unit, adjacent to the 

existing 25 MW Unit 1. Condition 26 of the permit required GVEA to develop a VMP and 

operate visibility monitoring equipment for the period prior to the initial startup of the HCCP 

through the completion of 1 full year of commercial operation of HCCP. The VMP, which 

was public noticed and approved by EPA, ADEC and the National Park Service (NPS), had 

the objective of collecting sufficient visual and measurement data to: 

1. Provide reasonable assurance that NOx, SO2, and particle emissions from the HCCP and 

Healy Unit 1 sources were not adversely impairing visibility within the DNPP Class I area; 

and 

2. Evaluate any trained NPS observer’s reports of visibility impairment for their potential 

attribution to NOx, SO2, and particle emissions from operations of HCCP and Unit 1. 

Under the VMP, photographic and air quality instrumentation was established at three 

monitoring stations, i.e., Garner Hill site overlooking the plant; the DNPP visitor’s center, 

and the Bison Gulch ambient air monitoring station at the Park boundary. Continuous timelapse video of Healy was taken at Garner Hill and Nenana Valley north of the DNPP Visitor 

Access Center. Measurements of meteorological data, SO2 concentrations, and nephalometer 

readings of light scattering by sulfate particles were taken at Bison Gulch for use in 

estimating the contribution of the SO2 emissions from the Healy Power Plant (Healy 1 and 

HCCP) to light scattering by particles within DNPP.

The VMP commenced in late December 1997, just prior to HCCP beginning its first year of 

the demonstration period. During the VMP time period, Healy 1 was operating with the 

current NOx control configuration and the current baghouse, but the current FGD SO2

reduction system, which was installed during 1999, was not operating. Therefore, the VMP 

occurred when both units were operating and Healy 1 was emitting more SO2 than under the 

current configuration (with the FGD system). GVEA notes that HCCP had not been fully 

optimized during the VMP, resulting in emissions above normal operating conditions. 

By condition of the permit, the duration of the VMP was only to occur for 2 years (1 year of 

demonstration operation and 1 year of commercial operation). Quarterly reports were 

submitted to ADEC, EPA and the NPS during the program. In 2000, the ADEC, EPA and 

NPS agreed the VMP could be temporarily shut down as HCCP never reached full 

commercial operation. HCCP has not operated since that time. GVEA indicated the results 

of the program demonstrated that no visibility impairment was observed by trained NPS 

observers while Healy 1 was operating at full load; and that actual visibility impairment at 

DNPP from Healy was not detectable while both units (Healy 1 and HCCP) operated. 

Further, GVEA indicates there were occasions during the VMP when a slight plume was 

visible and recorded by video, but no correlation was reached between this slight plume and 

any visibility issues within DNPP. 

Coincident with the VMP, a three year study was conducted in which particles that cause or 

contribute to regional haze were measured and analyzed to determine if Healy was 

contributing to regional haze. The study was funded by GVEA, managed by the NPS, and 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

33 

conducted by Air Resource Specialists, Inc. and the University of Alaska –Fairbanks. Results 

of this study are summarized in a report entitled “Final Report on the Results from the Poker 

Flat, Denali National Park and Preserve, and Trapper Creek CASTNET Protocol Sites, July 

1998 through June 2001.” Per GVEA, the report concluded that there was no specific 

indication that operations from the Healy Power Plant contributed to regional haze. 

GVEA concluded that the Unit 1 existing control configuration for all pollutants is BART. This 

conclusion is based in part on GVEA’s assertion that no visibility impairment at DNPP, 

attributable to Healy, has been observed by trained NPS observers based on the previous 

visibility studies described above. GVEA further asserted during the February 27, 2009 

teleconference with the Department that no visibility impairment has occurred at DNPP. A 

response to this further assertion is provided later in this section. 

In considering the relevance of the prior VMP in making a preliminary determination of BART 

for Healy 1 (and Auxiliary Boiler #1), several VMP related documents were provided by both 

ADEC and GVEA for consideration as part of this review/findings report. However, ADEC 

noted that they could not find evidence as to whether the VMP documents had ever been 

approved, or even fully reviewed, by ADEC, EPA or the NPS. GVEA in their January 2009 

submittal concurred, indicating that they knew of no formal correspondence from ADEC, EPA 

or the NPS regarding the acceptability of the visibility monitoring program and studies. 

Enviroplan therefore conducted a limited review of the VMP related materials and 

correspondence as part of the BART review. Based on this limited review, Enviroplan notes the 

following: 

• The monitoring program would have occurred at a time of greater potential for plant 

emissions, given the operation of HCCP and no FGD system in place on Unit 1. 

• The above notwithstanding, correspondence from ADEC to GVEA on 12/14/99 expressed 

concern over whether both boilers were operating during the year at typical, full operating 

rates representative of normal maximum emission rates. It is known that HCCP did not reach 

full operational status. However, it is unclear whether Unit 1 was at full capacity during the 

VMP, although Section 1 of GVEA’s final report (summarized above) indicates this to be the 

case. 

• It is acknowledged that the NPS did not identify any visibility events during the 2-year 

monitoring period which would have required further investigation by GVEA. It is also 

acknowledged that the EPA/NPS/ADEC approved on May 1, 2000 the shutdown of the 

visibility monitors. However, it is unclear whether lack of correspondence from the NPS 

during the monitoring program is indicative of agency concurrence with GVEA that no 

instances of visible plume events occurred that would have required further investigation. 

• A very limited review of quarterly video monitoring program results has been conducted by 

Enviroplan. The quarterly data capture rates are generally high. While relatively few events 

(“anomalies”) are identified in the reports, events are nonetheless identified. For instance, 

the initial report submitted for the 1st quarter 1998 identifies several events wherein the

plant’s plume may have entered the Class I area. The same report also indicates the NPS 

observers did not report any events. It is unclear whether the lack of reporting by the NPS 

observer means there was no visible impact at DNPP from Healy during any of these events. 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

34 

Based on the above, Enviroplan recognizes the general findings of GVEA’s VMP and the actual 

monitored visibility impacts from Healy at the DNPP Class I area. However, Enviroplan 

believes these results, even if accurately summarized by GVEA in their final report, cannot be 

considered in terms of the BART control determination for Healy Unit 1 for the following 

reasons: 

• In a February 10, 2009 teleconference between the National Park Service (NPS) and the 

Department, the NPS noted that the VMP conducted by GVEA was a plume blight 

monitoring study (i.e., monitoring study focusing on the potential impact of a plume of 

specified emissions for specific transport and dispersion conditions), the results of which 

cannot be used to satisfy the requirements of the BART program which pertains to visibility 

impairment due to regional haze. 

• There is a lack of formal agency acknowledgement and approval of the results and findings 

of the VMP. 

• It is not clear whether the NPS agreed with the findings in the quarterly monitoring summary 

reports, and the conclusion by GVEA that no reporting by the NPS equates to no visible 

impacts by Healy at DNPP during an “anomalous” event. 

• The BART rule does not exempt a source from considering impacts associated with visibility 

modeling if a source has conducted visibility monitoring. 

• The BART rule does not indicate that all feasible retrofit technologies can be dismissed if a 

source has conducted visibility monitoring which suggests no or limited visible impacts at 

the nearest Class I area. 

• The VMP has limited application and is not completely relevant to the BART rule. 

Specifically, an air dispersion model (CALPUFF in this case) is a tool used to assess 

potential air quality impacts associated with emissions from a source (or sources). Typically, 

air modeling is conducted over a large geographic area to ensure air quality compliance. 

While an ambient monitoring program provides actual measurement and impact information, 

such data is limited to the specific location or area where the monitoring equipment is sited. 

As such, while air dispersion models tend to be conservative predictors of air quality versus 

similarly measured data, the BART rule requires a visibility assessment at the entire Class I 

area and not simply at select locations at or near the area (i.e., the three VMP locations). 

In addition to the above, during a February 27, 2009 teleconference with the Department, GVEA 

noted that use of a dispersion model, i.e., CALPUFF, is “theoretical” in its application. GVEA 

requested that greater consideration of real data, e.g., their VMP, be given by the Department 

when determining BART since no visibility impairment has been monitored at DNPP. In 

response to this request, Enviroplan has conducted an evaluation of potential impairment at 

DNPP and its relation to the current Alaska BART/SIP effort for reducing visibility impacts. 

This evaluation is based primarily on visibility monitoring data collected at the DNPP 

IMPROVE monitor site, plus other available information provided by the Department relating to 

regional haze studies at DNPP. As summary of our review and findings follows below. 

The Regional Haze Rule requires that states develop plans that include reasonable progress goals 

for improving visibility in Class I areas to natural conditions by 2064. Natural visibility 

conditions are intended to represent the long-term visibility in Class I areas without man-made 

impairment. Specifically, a state is required to set progress goals for Class I areas that: 1) 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

35 

provide for an improvement in visibility for the 20% most impaired (i.e., worst visibility) days 

and 2) ensure no degradation in visibility for the 20% least impaired (i.e., best visibility) days. 

Based on the U.S. EPA default approach for estimating natural visibility conditions, the 20% 

best visibility and 20% worst visibility days at the Denali National Park and Preserve have been 

estimated to be 2.30 and 7.42 deciviews (dv), respectively (U.S. EPA, “Guidance for Estimating 

Natural Visibility Conditions Under the Regional Haze Rule,” EPA-454/B-03-005, September 

2003). 

The 2000-2004 average, or baseline, visibility for Denali for the 20% worst days is 9.9 dv, based 

on data collected at the Denali IMPROVE monitor site. This baseline value, which is higher 

than the natural visibility deciview value of 7.42, indicates that a rate of progress of 0.04 dv per 

year is needed for the Class I area to meet natural conditions by 2064. The 2000-2004 baseline, 

as well as more recent IMPROVE data at Denali, clearly indicate that there is visibility 

impairment at the Class I area (i.e., the area is not currently at natural conditions). 

An inspection of the IMPROVE particulate matter chemical speciation data indicates the yearround presence of sulfates and nitrates, which are primarily derived from combustion sources. 

The acidic sulfate aerosols that comprise Arctic Haze are known to have a substantial impact on 

visibility at Denali primarily during November-May and are believed to originate mainly from 

industrial emissions in northern Europe and Asia. Local (i.e., Alaskan) industrial sources of 

sulfates and nitrates also exist, which may impact visibility within the Denali Class I area yearround. 

Further technical evidence suggests that emissions from the GVEA Healy Power Plant 

potentially contribute to visibility impairment within the Denali Class I area. An analysis of air 

trajectories using the National Oceanic and Atmospheric Administration Hybrid Single Particle 

Lagrangian Integrated Trajectory (HYSPLIT) model indicates that Denali is impacted to some 

degree by atmospheric transport from the northeast, which suggests that emissions from the 

GVEA Healy Power Plant potentially contribute to visibility impairment within the Class I area 

(Hafner, W.D., N.N. Solorzano, and D.A. Jaffe, “Analysis of Rainfall and Fine Aerosol Data 

Using Clustered trajectory Analysis for National Park Sites in the Western U.S.,” Atmospheric 

Environment (2007)). Furthermore, the CALPUFF modeling that was conducted by CH2M Hill 

in support of the GVEA Healy Power Plant BART Analysis (Final Report submitted January 2, 

2009) clearly indicates that emissions from the GVEA plant are expected to impact Denali. The 

CALPUFF Model simulates the influences of complex terrain on plume transport over local and 

regional scales. This modeling utilized one full year (2002) of 15-km resolution MM5 data, 

surface meteorological data from five sites, local terrain and land use data, and emissions and 

stack parameter data for the 25-MW boiler (Healy Unit #1). CALPUFF modeling results 

indicated that, under plant baseline (i.e., existing (pre-BART) control) operating conditions, the 

Denali Class I area was significantly impacted by the boiler emissions 136 days during the year, 

as defined by a deciview value of 0.5 or greater, and had a maximum delta-deciview value (i.e., 

above the natural background) of 3.359 dv. 

In summary, based on a review of IMPROVE and other relevant data, Enviroplan has determined 

that DNPP is not without visibility impairment, and it is likely that GVEA is a contributor to this 

impairment. With respect to GVEA’s statement regarding the “theoretical” nature of a 

dispersion model, it is emphasized that CALPUFF is the regulatory dispersion model 

recommended by EPA for application in the BART determination process (40 CFR 51, 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

36 

Appendix Y). The CALPUFF model has been utilized by WRAP - RMC in their visibility 

modeling analysis. The BART rule does not provide an exemption from visibility impact 

modeling if ambient monitoring data are available. Based on these regulatory provisions, as well 

as the IMPROVE and other data evaluations discussed above, it is determined that the GVEA 

visibility monitoring program does not otherwise replace the CALPUFF visibility modeling 

results considered in this BART determination process for GVEA.
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

37 

7.4 Visibility Impacts Evaluation Conclusions 

A detailed review of the GVEA BART-eligible source visibility modeling analysis has been 

conducted for the Healy power plant Unit 1 and Auxiliary Boiler #1. A limited review of 

materials pertaining to the 2-year visibility monitoring program performed by GVEA at the 

DNPP Class I area also has been conducted. Enviroplan presents the following conclusions 

pertaining to GVEA’s visibility impacts determination: 

• The CALPUFF visibility modeling analyses are in conformance with the protocol used by 

WRAP – RMC (“Draft Final Modeling Protocol CALMET/CALPUFF Protocol for BART 

Exemption Screening Analysis for Class I Areas in the Western United States”, August 15, 

2006), and WRAP’s, “Summary of WRAP RMC BART Modeling for Alaska” (Draft#7, 

April 6, 2007). 

• The CALPUFF visibility modeling analyses are generally in conformance with the Federal 

and State BART guidelines. While GVEA did consider two modeling scenarios for the 

current configuration, their use of peak 24-hour emission rates to reflect a “baseline” plant 

configuration is consistent with the BART rule. No consideration is given to their modeled 

“null” scenario. 

• Maximum predicted visibility impacts for Auxiliary Boiler #1 (0.067 dV) are well below the 

0.5 deciview significant visibility impairment metric. Consistent with the individual source 

attribution approach in Appendix Y, no additional controls are required for this unit. 

• Each NOx emissions control option considered for Unit 1 results in a greater than significant 

visibility improvement (i.e., greater than 0.5 dV) when compared against the maximum 

predicted daily visibility impact “baseline” scenario, with the low NOx burner/OFA plus SCR 

system showing the greatest visibility improvement (3.359 ∆dV versus 2.573 ∆dV, or a 0.786 

dV reduction). 

• For the SO2 emissions control options considered for Unit 1, the retrofit scenario of increased 

sorbent feed rate to the existing FGD results in only a 0.25 dV improvement versus the impacts 

associated with the baseline scenario (i.e., 1⁄2 of the significance level), and the visibility 

impacts associated with a lime spray dryer FGD system and wet limestone FGD system are 

worse than the current baseline configuration due to reduced plume height from a relatively 

colder, wetter plume. Coincidentally, the number of days exceeding the significance level (0.5 

dV) increases for each of these control options versus the current baseline configuration. 

• On February 12, 2009, the NPS commented on the predicted worsening of modeled visibility 

impacts attributable to the lime spray dryer FGD system and wet limestone FGD system. The 

NPS questioned the use of CALPUFF and GVEA’s receptor grid. The bases for these 

comments are unclear. GVEA used the WRAP – RMC modeling protocol, which was 

reviewed by the NPS and subsequently approved by the Department. In discussing this issue 

with the Department, the Department stated that they saw no merit in changing modeling 

approaches, and that it was too late in the SIP development process to make such a substantive 

change. Visibility-related cost effectiveness information is provided for each NOx emissions 

control scenario in terms of both deciviews and days above 0.5 dV reduced. This information 

is summarized below: 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

38 

Visibility Improvement and Annual Costs for NOx Control Options 

BART Controls 

Highest 

dV 

Reduction

(∆dV) 

Reduction in Avg. 

No. of Days Above 

0.5 dV 

(Days) 

Annualized 

Cost 

($/Year) 

Cost per dV 

Reduction 

($/dV 

Reduced) 

Cost per 

Reduction in 

No. of Days 

Above 0.5 dV 

($/Day Reduced) 

Optimizing 

Existing LNB w/ 

OFA 

0.560 43 $2,337 $4,173 $54 

Replace OFA w/ 

ROFA 0.671 56 $672,997 $1,002,976 $12,018 

Replace OFA w/ 

ROFA and 

Rotamix 

0.736 67 $1,094,835 $1,487,547 $16,341 

LNB/OFA/SNCR 0.620 51 $418,810 $675,500 $8,212 

LNB/OFA/SCR 0.786 71 $897,559 $1,141,933 $12,642 

Aside from the current baseline configuration, the most cost effective additional control is 

optimization of the existing configuration (low NOx burners/OFA). The most costly control 

expressed in dV and days above 0.5 dV is the replacement of the existing control configuration 

with ROFA and Rotamix. Similar cost effectiveness information is presented for the SO2

control scenarios; however, costing information for the lime spray dryer FGD system and wet 

limestone FGD systems expressed in terms of visibility metrics are not meaningful since the 

visibility impacts worsen under these control scenarios. 

Visibility Improvement and Annual Costs for SOx Control Options 

BART Controls 

Highest 

dV 

Reduction

(∆dV) 

Reduction in 

Avg. No. of Days 

Above 0.5 dV 

(Days) 

Annualized 

Cost 

($/Year) 

Cost per dV 

Reduction 

($/dV 

Reduced) 

Cost per 

Reduction in No. 

of Days Above 0.5 

dV 

($/Day Reduced) 

Increase Dry 

Sodium 

Bicarbonate FGD 

System (increase 

feed rate) 

0.250 39 $1,656,590 $6,626,360 $42,477 

Install Lime Spray 

Dryer FGD 

System 

-0.870 20 $1,607,872 -$1,848,129 -$7,767 

Install Lime Spray 

Dryer FGD 

System 

-1.160 18 $2,659,104 -$2,292,331 -$147,728 

Overall, the results of the modeling demonstrate that no controls are required for Auxiliary Boiler 

#1. Also, the lime spray dryer FGD system and wet limestone FGD system SO2 retrofit options for 

Unit 1 (i.e., Options 2 and 3 in Section 4 of the final report) show a worsening of visible impacts as

predicted at DNPP, and Enviroplan agrees with GVEA that these options are not considered viable 

as SO2 BART for Unit 1. Enviroplan also finds that the high cost effectiveness associated with an 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

39 

insignificant prediction of visibility improvement from increased sorbent injection at the existing 

FGD system, when combined with the findings associated with other steps in the BART analysis 

process, i.e., increased potential for visible impacts (brown plume), results in the sorbent injection

increase option not being viable as SO2 BART for Unit 1.
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

40 

8 PROPOSED BART FOR HEALY 1 

8.1 NOx Control at Healy Unit 1

GVEA has proposed the existing low NOx burner and over fire air NOx emissions control system 

as BART for Healy 1. However, upon consideration of the requirements of 40 CFR 51, 

Appendix Y, and 18 AAC 50.260; as well as the BART analysis information provided by GVEA 

in both their January 2009 final report and other supporting documentation provided during this 

review process, Enviroplan recommends the preliminary BART determination for Healy Unit 1 

for NOx emissions control to be the existing LNB and OFA system, with the addition of a 

selective catalytic reduction (SCR) system. This preliminary BART determination is proposed 

by Enviroplan for the Unit 1 BART-eligible source both pursuant to 18 AAC 50.260(j), and in 

accordance with the requirement under the contract to conduct this findings review. 

As indicated in 40 CFR 51, Appendix Y, the underlying goal of the BART rule relates to the 

Clean Air Act’s national goal of eliminating man-made visibility impairment from all Class I 

areas. As already stated herein, the BART rule, when applicable, requires a control technology 

determination based on multiple factors, including costs and visibility impacts and improvements 

associated with feasible retrofit options. Enviroplan believes the LNB/OFA+SCR NOx control 

retrofit option for Healy 1 represents the best combination of factors (steps evaluated) under the 

BART rule for the purpose of improving visibility impairment at DNPP Class I area. The basis 

for this determination is as follows: 

1. Healy 1 Power Plant is located in very close proximity (about 8 km) to the DNPP Class I 

area, with the potential for substantive visible impacts at the Class I area (as predicted with 

CALPUFF). 

2. The Healy 1 unit already utilizes the best system of particulate pollutant control (high 

efficiency baghouse), and the existing configuration for SO2 control (FGD system) is 

considered as BART (see below). However, various alternative retrofit NOx controls are 

potentially applicable to Healy 1 for substantive additional reduction in unit NOx emissions. 

3. The visibility impact modeling done for Healy 1 indicates that the existing LNB/OFA system 

results in 136 days per year when the visibility impacts attributable to Healy 1 exceed 0.5 

deciviews at DNPP. Employing the LNB/OFA+SCR NOx control option reduces the number 

of days with modeled impacts over 0.5 deciviews to 65. Utilizing the NOx control that 

incorporates SCR significantly reduces the predicted number of days with modeled impacts 

over 0.5 deciviews by an additional 71 days per year. 

4. The use of the NOx control option incorporating SCR will reduce the highest delta deciview 

impacts from 3.359 ∆dV to 2.573 ∆dV, which is the greatest reduction in visible impacts of 

all NOx retrofit control options considered and the relative change is greater than the 

significance metric 0.5 dV. 

5. The addition of the SCR system to the existing LNB and OFA system is expected to reduce 

NOx emissions by at least 72% from existing baseline emissions, which equates to 266 tons 

of additional NOx emissions removed from the Healy 1 exhaust gas stream. 

6. GVEA estimated the average cost effectiveness of the SCR control system on Healy Unit 1 

to be $4,748/ton of NOx removed. An independent study on SCR retrofits and cost analyses 

for BART eligible boilers prepared in January 2009 by the National Park Service (NPS) 

estimated lower costs for SCR retrofits. The NPS analysis suggests SCR systems typically 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

41 

have a total capital investment cost on the order of between $80/kw to $270/kw. The NPS 

estimated the cost effectiveness using EPA’s Control Cost Manual that the cost effectiveness 

of the SCR control system on Healy Unit 1 can be as low as $2,971/ton, with a total capital 

investment for the SCR of $222/kW, instead of the total capital investment of $351/kW 

estimated by GVEA. On March 23, 2009, Enviroplan re-evaluated the SCR control costs 

reflected in the January 2009 draft findings report. Enviroplan estimated the average cost 

effectiveness of the SCR control system on Healy Unit 1 to be $3,373/ton of NOx removed at 

a total capital investment cost of $241/kW. Although Enviroplan’s (and GVEA) cost 

effectiveness is greater than the $1500/ton cost effectiveness value cited in the preamble to 

the EPA’s BART Guideline (70 FR 39135), the $1500 effectiveness value is not a ceiling 

value, and it must be considered with all other BART review aspects and control cost 

effectiveness metrics.

7. The annualized cost per dV improvement is $1,141,933/dV. The NPS indicated during a 

February 2009 teleconference with the Department that values in this order of magnitude are 

much less than the cost per deciview accepted in other BART assessments, which have 

ranged on the order of $12 million/dV. 

8. GVEA estimated that the incremental ratepayer increase for the addition of the SCR is 

$0.00092/kWh, an increase of about 1.4 percent. For a family that uses 500 kWh/month, the 

addition of SCR would cost $0.46/month and $5.52/year. Using Enviroplan’s adjusted costs, 

the incremental ratepayer increase for the SCR is $0.00077/kWh, an average increase of 

about 0.43 percent. For a family that uses 500 kWh/month, the addition of SCR would cost 

$0.39/month and $4.62/year. 

9. The benefits of the addition of a SCR control system through NOx reductions and visibility 

improvements outweigh the possible environmental impact of the ammonia emissions 

associated with the SCR. In fact, only qualitative information has been provided by GVEA 

on the potential effect of SCR system ammonia slip at DNPP and this is not a deciding factor 

in this review. 

It is recognized that the cost effectiveness of the SCR system, when expressed in terms of 

visibility modeling results (i.e., cost per deciview reduction or cost per reduction in days above 

0.5 dV, as provided by GVEA in the final report), is generally the most expensive when 

compared to the other NOx retrofit options. It is also recognized that the addition of SCR results 

in the highest annualized costs among the NOx retrofit options. However, it is believed that for 

the multiple reasons indicated above, including the general cost acceptability ($/kW and $/dV), 

the proximity of Healy 1 to DNPP, the additional reduction in NOx emissions, and related 

predicted visibility improvement at DNPP necessary for the Department to meet the reasonably 

further progress and final BART compliance goals by 2064, the use of SCR outweighs these cost 

effectiveness metrics and meets the goals and objectives of the BART rule. 

8.2 SO2 Control at Healy Unit 1 

Due to the high cost effectiveness values presented in Table 6-2 herein, the installation of a wet 

limestone FGD on Healy 1 is not considered economically feasible. In addition, a new lime 

spray dryer FGD system also presents excessively high cost per ton values, including the 

incremental cost, plus both the wet and dry retrofits are predicted to increase visibility 

impairment at DNPP due to a cooler, reduced plume. Further, the cost for an insignificant 

improvement in visible impacts due to increased sorbent injection at the existing FGD is cost 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

42 

prohibitive. This, along with the increased potential for visibility impairing brown plume make 

the increased sorbent injection option unviable. Therefore, no additional controls are 

recommended for the Healy 1 boiler to reduce SO2 emissions. The use of the existing dry 

sorbent injection system to control SO2 emissions is considered BART for Healy Unit 1. 

8.3 Particulate Control at Healy Unit 1 

A baghouse is considered the state-of-the-art particulate emissions control technology for utility 

boiler applications. Therefore, the existing high-efficiency reverse gas baghouse installed on 

Healy Unit 1 is considered BART. 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

43 

9 GVEA BART CONTROL ANALYSIS REPORT FINDINGS AND 

CONCLUSIONS 

The objective of this review has been to document Enviroplan’s findings regarding GVEA’s July 

2008 BART control analysis in terms of compliance with 18 AAC 50.260(e) through (h). The 

July 2008 report was revised and resubmitted by GVEA in January 2009; as such Enviroplan’s 

review has considered both the initial GVEA report and their revised report. Further, GVEA 

provided relevant supplemental information on March 18, 24 and 30, 2009. Proposal of a 

preliminary BART determination for each BART-eligible source at this facility, consistent with 

18 AAC 50.260(j), is also an objective of this review. This findings report concludes that the 

GVEA BART control analysis complies with 18 AAC 50.260(e) through (h). For Healy Unit 1, 

use of the existing dry sorbent injection system to control SO2 emissions is considered as BART; 

the addition of a SCR system to the existing LNB and OFA system to control NOx emissions is 

considered as BART; and use of the existing reverse gas baghouse system for particulate control 

is considered as BART. For Auxiliary Boiler #1, the existing configuration which is no air 

pollution control systems, is considered as BART. 

9.1 BART Emission Limits 

The preliminary BART emission limits proposed for Healy Unit 1 are summarized in Table 9-1 

below. The emission limits are compared to current permitted pollutant emission limits. 

Table 9-1: Preliminary BART Emission Limits Proposed for Healy 1

Particulate SO2 NOx 

 Current 1 Proposed 2 Current 1 Proposed 2 Current 1 Proposed 2

Healy 

Unit 1 

0.05 gr/dscf 

36.7 lb/hr 

(hourly average 

at full load) 

161 ton/yr 

0.015 

lb/MMBtu 

(30-day 

rolling 

period) 

258 lb/hr 

(24-hour 

average, 

calendar 

day) 

367 lb/hr (3-

hour 

average) 

472 ton/yr 

0.30 lb/MMBtu 

(30-day rolling 

period) 

429 ton/yr 0.07 lb/MMBtu 

(30-day rolling 

period) 

1. Taken from Permit No. 173TVP01, Table 2. 

2. Proposed BART emission limits are in addition to the current (existing) emission limits. 

The preliminary BART emission limits of Table 9-1 are reflective of the vendor/engineering 

judgment-based limits provided by GVEA. This notwithstanding, GVEA requested on March 

18, 2009 that their preliminary BART emission limits be revised to account for potential 

operating variability. GVEA conducted an analysis of 2003-2008 (5 years) 30-day rolling NOx

and SO2 emissions from Healy Unit 1. GVEA applied three standard deviations to the mean, and 

requested that their BART emission limits reflect the resultant rates (i.e., 0.09 lb/MMBtu for 

NOx (with SCR) and 0.27 lb/MMBtu for SO2 (with an optimized FGD system, if determined by 

the Department as BART; or 0.49 lb/MMBtu for SO2 with the current FGD configuration, if 

determined by the Department as BART). Given the long-term nature of the emissions 

averaging period (30-days); and the fact that the emission limits provided by GVEA are mean 

values which inherently account for variability, Enviroplan believes that the Table 9-1 emission 
Final Findings Report– April 27, 2009 

BART Determination: GVEA Healy Power Plant 

44 

limits will adequately account for any short-term upset or malfunction conditions. Therefore, no 

change has been made to the GVEA emission limits. 

The existing (current) emission limits shown in Table 9-1 were established pursuant to 

regulatory requirements other than the BART rule. For example, the SO2 limits of 258 lb/hr (24-

hour average) and 367 lb/hr (3-hour average) were established to protect the short-term SO2 air 

quality standards. Part 71 permit No. 173TVP01 provides the basis for each of the existing 

emission limits. While the existing short-term emission limits for PM10 and SO2 are larger than 

the 24-hour average emission rates used by GVEA in the visibility impact modeling (i.e., 6.29 

and 182.2 lb/hr, respectively), BART emission limits are prescribed on a 30-day rolling basis per 

40 CFR 51, Appendix Y, Section V. Therefore, the proposed preliminary BART emission limits 

presented in Table 9-1 are not intended to replace the existing pollutant emission limits. 

9.2 Compliance Demonstration 

Consistent with 18 AAC 50.260(j), monitoring, record-keeping, and reporting conditions are 

proposed in order to demonstrate compliance with the BART emission limits. This is consistent 

with 40 CFR 71.6(a)(3). The existing Title V operating permit for the Healy Power Plant (No. 

173TVP01) contains PM, NOx and SO2 emission limits established from prior BACT and Owner 

Requested Limit (ORL) determinations. Related monitoring, record keeping and reporting 

(MR&R) conditions are also contained within the permit. It is expected that the conditions 

needed for BART emissions compliance would be very similar or identical to many of the 

existing permit conditions, as summarized below: 

1. Compliance with the existing NOx and SO2 limits contained in the BACT and ORL section 

of the permit requires compliance be demonstrated using continuous emissions monitoring 

systems for NOx and SO2; and stack testing for PM. Proposed BART emission limits for 

Unit 1 will be demonstrated through the continued use of existing CEM systems for NOx and 

SO2; and continued stack testing for PM. 

2. Preliminary BART recommended for Auxiliary Boiler #1, and Healy 1 for particulate and 

SO2 emissions, is the current configuration for these units. Except for revising the permit to 

include the BART rule citation and expressing the Unit 1 particulate and SO2 emission limits 

in Table 9-1 above, the existing Title V permit MR&R conditions, including the CEM and 

stack testing requirements, shall demonstrate compliance with the BART emission limits for 

these units and pollutants. 

3. The new NOx emission limit and BART rule citations will need to be added to the Title V 

permit for Unit 1. Other existing MR&R conditions, including use of CEM data for 

emissions compliance and related existing CEM operating conditions in the existing Title V 

permit would continue to apply to Unit 1. Operating parameter conditions for the SCR 

system would need to be included in the Title V permit, including continuous monitoring and 

recording of an ammonia injection rate and/or gas pressure drop, whose range would be 

established during initial and periodic compliance source testing at the time of catalyst bed 

replacement; and the catalyst bed outlet ammonia concentration.