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) Evaluatio n

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, 2009Final 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 Availabl e Retrofit Technology (BART) control analysis submitted on July 28, 2008 by Golden Valle y Electric Association (GVEA), with supplemental information submitted on October 3, 20 08, November 11, 2008 and December 10, 2008; with a revised final BART analysis report sub mitted on January 2, 2009. Supplemental data also was submitted on March 18, 24 and 30, 2009. T he BART control analysis was prepared by GVEA for the Healy Power Plant pursuant to the Fede ral 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 plan t showed maximum visibility impact at the Tuxedni Wilderness Class I area less than the signi ficant visibility impact threshold of 0.5 deciview. The maximum visibility impact at the Den ali 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 are a was Denali National Park. GVEA submitted a BART control analysis in response to this notific ation 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 thes e rules. GVEA has opted to use WRAP’s modeling protocol for the visibility modeling analy sis, 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 Enviropla n’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 r eceipt of preliminary comments from the National Park Service (NPS) on February 12, 2009 an d supplemental information from GVEA during March 2009, the findings report is revised a s presented herein.

This findings report concludes that the GVEA BART c ontrol 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 (SO 2 ) emissions is considered BART; the addition of a s elective catalytic reduction (SCR) unit to the existing low NOx burner (LNB) and over-fire air (OFA) system to control oxides of nitrogen (NO x ) emissions is considered BART; and use of the exis ting reverse gas baghouse system for particulate control is considered BART. The existing configuration for Auxiliary Boiler #1, which has no air pollution control syste ms, is considered as BART since the predicted daily visibility impacts for this unit are well bel ow 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 EMISSIO N CONTROL TECHNOLOGIES (Step 1) .............................

................................................... .................... 6 3.1 NO x Control Technologies Considered ..................

................................................... . 6 3.2 SO 2 Control Technologies Considered ..................

................................................... . 9 3.3 Particulate Control Technologies Considered ...

................................................... .... 11

4 TECHNICALLY FEASIBLE RETROFIT EMISSION CONTROL TE CHNOLOGIES (Step 2) ..........................................

................................................... .................................... 12 4.1 NO x Control Technologies .............................

................................................... ....... 12 4.2 SO 2 Control Technologies..............................

................................................... ....... 12

5 EVALUATION OF TECHNICALLY FEASIBLE RETROFIT EMISS ION CONTROL TECHNOLOGIES (Step 3) .............................

................................................... .................. 13 5.1 NO x Control Technologies .............................

................................................... ....... 13 5.2 SO 2 Control Technologies..............................

................................................... ....... 13

6 COST-EFFECTIVENESS AND IMPACT ANALYSIS (Step 4) ...................................... 14 6.1 NO x 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 SO 2 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 NO x Control at Healy Unit 1 ..........................

................................................... ....... 40 8.2 SO 2 Control at Healy Unit 1...........................

................................................... ....... 41 8.3 Particulate Control at Healy Unit 1 ...........

................................................... ............ 42Final Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

iii 9 GVEA BART CONTROL ANALYSIS REPORT FINDINGS AND CO NCLUSIONS .... 43 9.1 BART Emission Limits ..........................

................................................... ............... 43 9.2 Compliance Demonstration ......................

................................................... ............. 44

List of Tables

Table 4-1: Technically Feasible NO x Control Options for Healy 1. ..................... .................... 12 Table 4-2: Technically Feasible SO 2 Control Options for Healy 1. ..................... ..................... 12 Table 5-1: Control Effectiveness of the NO x Control Options for Healy 1. ..................... ......... 13 Table 5-2: Control Effectiveness of the SO 2 Control Options for Healy 1. ..................... ......... 13 Table 6-1: NO x Cost Effectiveness Summary for Healy 1. .......... ............................................. 15 Table 6-2: SO 2 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 Op timization......................................... .... 25 Table 9-1: Preliminary BART Emission Limits Propose d for Healy Unit 1 ............................. 43

List of Figures

Figure 6-1: Additional Annual Costs versus Addition al Tons Removed Compared to Existing Operations for NO x Options. ......................................... ............................................ 16 Figure 6-2: Additional Annual Costs versus Addition al Tons Removed Compared to Existing Operations for SO 2 Options. ......................................... ........................................... 20Final 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 codi fied at 40 CFR Parts 51.300 through 51.309, and 40 CFR Part 51, Appendix Y. The Region al Haze Rule requires certain States, including Alaska, to develop programs to assure rea sonable progress toward meeting the national goal of preventing any future, and remedying any ex isting, impairment of visibility in Class I Areas. The Regional Haze Rule requires states to s ubmit 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 visibili ty in a Class I Area. BART-eligible sources include those sources that:

1. have the potential to emit 250 tons or more of a vi sibility-impairing air pollutant; 2. were in existence on August 7, 1977 but not in oper ation prior to August 7, 1962; and 3. whose operations fall within one or more of the spe cifically listed source categories in 40 CFR 51.301.

During 2007 the Department developed a list of Alas ka BART-eligible sources based on the federal BART guidelines. GVEA’s power plant in Hea ly, 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 NO x , SO 2 and particulate matter (conservatively as PM 10 ). 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 req uires sources not exempt from applicability based on a visibility modeling analys is to submit a case-by-case BART proposal for each BART-eligible unit at the facility and for eac h VIP by July 28, 2008.

A preliminary regional BART screening modeling anal ysis of all BART-eligible sources in Alaska was completed in 2007 by the Western Regional Air P artnership (WRAP) - Regional Modeling Center (RMC). The simulations were done using the C ALPUFF modeling system and a single year, 2002, of processed MM5 CALMET data. The simul ations 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-e ligible sources are exempt from BART if the daily visible impacts at a Class I area are bel ow 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 agai nst natural conditions is considered to “cause” visibility impairment.

The initial modeling analysis conducted by WRAP - R MC 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 a t 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 si nce the WRAP – RMC analysis was unsuccessful at providing a basis for exemption. T he 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 o n 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 discussi ons 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 (G VEA’s consultant) and Enviroplan on February 25 and 27, 2009 and March 2, 2009. As a f ollow-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 engineeri ng 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 a nd 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 complia nce 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 Hea ly 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 visibi lity benefit, and/or the cost of visibility improvement resulting from potentially installing t hese control options are highly cost prohibitive. GVEA considers the existing controls a nd operating practices on BART-eligible sources at the facility as BART.

The following sections of this report present the r eview findings pertaining to both the GVEA control analysis and the related CALPUFF modeling f iles. Enviroplan performed the review to determine whether GVEA’s analysis conforms to the W RAP 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; 4 0 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 p reliminary 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 tele conference with the NPS on February 10, 2009 to discuss preliminary BART control recommenda tions from Enviroplan’s January 27, 2009 draft findings report. The NPS provided the D epartment with initial comments on February 10, 2009 (verbal) and February 12, 2009 (w ritten as an email). This report is revised in response to the written NPS comments, except for co mments 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, A laska, approximately 8 kilometers (5 miles) from DNPP. The unit is a wall-fired, wet bottom boi ler manufactured by Foster Wheeler. Low NO x burners (LNB) and over-fired air (OFA) ports were installed in 1996. Particulate emissions are collected by a reverse gas baghouse installed i n 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 t he 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 B oiler #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 p arks, wilderness areas, and international parks which were in existence in 1977. One of the key ele ments 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 red uction 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 a nticipated 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 t hree criteria to be considered “BARTeligible” including:

1. The source belongs to one of the 26 listed source c ategories; these categories are same as those for Prevention of Significant Deterioration ( PSD) applicability analysis;

2. The source was installed (constructed) and in opera tion 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 (SO 2 ), nitrogen oxide (NO 2 ), or particulate matter (PM 10 ). Volatile organic compounds (VOC) and ammonia (NH 3 ) may be included depending on the state in which the source is locat ed.

The Alaska BART rule (18 AAC 50.260(f)) requires BA RT analysis to be conducted for NO x , SO 2 , and PM 10 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 sourc e (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 impact s 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 Technologi es. In identifying “all” options, you must identify the most stringent option and a reasonable set of options for analysis that reflects a compreh ensive 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 Contro l Technologies. Technically feasible control technologies are ranke d in the order of highest expected emission reduction to lowest expected emission redu ction and are evaluated following a “top-down” approach similar to Best Available Contr ol 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 impac ts 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-c ontrol emissions to determine the actual impact on visibility. This step does not nee d to be performed if the most stringent control technology is chosen.

As discussed in Section 7 of this report, the predi cted visibility impacts for Auxiliary Boiler #1 are well below the 0.5 daily deciview metric establ ished to determine if source emissions will cause or contribute to visibility impairment. Envi roplan agrees with GVEA that, pursuant to 40 CFR 51, Appendix Y, this insignificant source is no t 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 U nit 1.Final Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

6 3. IDENTIFICATION OF ALL AVAILABLE RETROFIT EMISSIO N CONTROL TECHNOLOGIES (Step 1)

3.1 NO x Control Technologies Considered

The following describes the NO x retrofit technologies deemed by GVEA as potentiall y feasible for Healy Unit 1. Although not specifically listed below, the existing low NO x burner/over fire air system is also a feasible NO x control technology. Enviroplan finds that GVEA ha s satisfied the BART step 1 requirement, with any additional fi nding(s) specific to a control option indicated as necessary below.

Optimizing the Existing Low NO x Burner/Over-Fire Air System (LNB/OFA)

The mechanism used to reduce NO x emissions with low NO x 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 NO x . Fuel-rich conditions favor the conversion of fuel nitrogen to N 2 instead of NO x . Additional air (or OFA) is then introduced downst ream in a lower temperature zone to burn out the char.

Healy 1 currently has an LNB/OFA system which was i nstalled in 1996. This system has been operating for an extended period of time, and, as i ndicated by GVEA, while plant personnel have exerted considerable effort to optimize performance (minimize CO within the existing permit NO x limits), it has not been optimized with the goal o f minimizing NO x emissions. Optimization of the LNB/OFA system could be attempted by utilizi ng a boiler system consultant with the intent of reaching a guideline NO x target emissions of 0.23 lb/MMBtu (i.e., the 30-da y rolling BART presumptive limit for a 200 MW unit). GVEA is uncertain whether such a limit would be achievable, and have indicated that minimizing NO x emissions will likely also impact other boiler operating parameters such as loss on ignitio n (LOI), carbon monoxide (CO), and excess air. GVEA further indicated that the 1994 PSD permi t (for HCCP) resulted in extensive discussion between ADEC and GVEA in terms of the ne ed to minimize CO emissions from Healy 1. Based on this indication, GVEA has indica ted that BART control options must consider the impact on all emissions when attemptin g to reduce NO x . Relating to the above, Enviroplan requested on Octo ber 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 fro m 2002 and 2005 between GVEA and ADEC. The correspondence indicated that CO emissio ns from Healy Unit 1 increased after the LNB/OFA installation was completed in 1998. ADEC in dicated the need to minimize CO emissions from Healy Unit 1 through combustion syst em optimization without sacrificing the unit’s low NO x emissions. However, no permit limit was establish ed for CO emissions from Healy Unit 1.

In addition to the above, GVEA indicated in their N ovember 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 c orrespondence pertaining to CO emissions as provided by GVEA is acknowledged. It is also un derstood that such collateral impacts can be considered as an additional environmental impact un der the Energy, Environmental and Economic Impacts portion of the BART review process (i.e., Step 4). However, since visibilityFinal Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

7 impairing pollutants are the focus of BART (i.e., N O x and not CO); and since there may not be an increase in CO emissions from improved LNB/OFA N O x 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 generati on OFA system whereby the flue gas volume of the furnace is set in rotation by asymmet rically 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 a ction reduces the maximum temperature of the flames and increases heat absorption. The combustio n 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 2 00 horsepower (hp) fan for Healy 1. Mobotec expects to achieve a NO x emission rate of 0.15 lb/MMBtu using ROFA technolo gy.

ROFA with Rotomix The Rotamix system has been developed to optimize t he reduction of unwanted substances, such as NO x . To optimize NO x 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 chemica ls into the center of the furnace. Mobotec expects to achieve a NO x 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 NO x control technology based on the reaction of NH 3 and NO x . SNCR involves injecting urea/NH 3 into the combustion gas path to reduce the NO x to nitrogen and water. SNCR is generally utilized to achieve modest NO x reductions on smaller units. With SNCR, an amine-ba sed 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 NO x to nitrogen and water. NO x reductions of up to 60 percent have been achieved, although 20 to 40 pe rcent is more realistic for most applications.

Reagent utilization, which is a measure of the effi ciency with which the reagent reduces NO x , can range from 20 to 60 percent, depending on the a mount of reduction, unit size, operating conditions, and allowable ammonia slip. With low re agent utilization, low temperatures, or inadequate mixing, ammonia slip occurs, allowing un reacted ammonia to create problems downstream. The ammonia may render fly ash unmarket able, react with sulfur to foul heat exchange surfaces, and/or create a visible stack pl ume. Reagent utilization can have a significant impact on economics, with higher levels of NO x reduction generally resulting in lower reagent utilization and higher operating cost.

Selective Catalytic Reduction (SCR) SCR is a process that involves post combustion remo val of NO x 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 reaction s take place on the surface of a catalyst. The function of the catalyst is to effectively lower th e activation energy of the NO x decomposition reaction. Technical factors related to this technol ogy include the catalyst reactor design, optimumFinal 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 NH 3 injection system.

Reduction catalysts are divided into two groups: pl atinum and base metal (primarily vanadium or titanium). Both groups exhibit advantages and disad vantages in terms of operating temperature, reducing agent/NO x ratio, and optimum oxygen concentration. A disadva ntage common to both platinum and base metal catalysts is the narrow ran ge of temperatures in which the reactions will proceed. Platinum group catalysts have the advantag e of requiring lower ignition temperature, but also have a lower maximum operating temperature . Operating above the maximum temperature results in oxidation of NH 3 to either nitrogen oxides (thereby actually increa sing NO x emissions) or ammonium nitrate.

Sulfur content of the fuel can be a concern for sys tems that employ SCR. Catalyst systems promote partial oxidation of sulfur dioxide (from t race sulfur in gas and the mercaptans used as an odorant) to sulfur trioxide (SO 3 ), which combines with water to form sulfuric acid. Sulfur trioxide and sulfuric acid reacts with excess ammon ia to form ammonium salts. These ammonium salts may condense as the flue gases are c ooled or may be emitted from the stack as increased emissions of PM 10 / PM 2.5 . Fouling can eventually lead to increased system p ressure drop over time and decreased heat transfer efficien cies.

The SCR process is also subject to catalyst deactiv ation over time. Catalyst deactivation occurs through two primary mechanisms: physical deactivati on and chemical poisoning. Physical deactivation is generally the result of either prol onged exposure to excessive temperatures, or masking of the catalyst due to entrainment of parti culate from ambient air or internal contaminants. Chemical poisoning is caused by the i rreversible reaction of the catalyst with a contaminant in the gas stream and is a permanent co ndition. 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 o f unreacted ammonia emissions (ammonia slip) when making guarantees at very high efficienc y levels. To achieve high NO x 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 NO x and ammonia occurs in high NO x reduction applications. While SCR may be considered potentially technically feasible for the boilers, there are various concerns with th e technology, most notably the temperature required for the catalyst to activate and the unrea cted ammonia introduced into the exhaust
stream.

SCR works on the same principle as SNCR, but a cata lyst is used to promote the reaction. Ammonia is injected into the flue-gas stream, where it reduces NO x 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 r ange between 580°F to 750°F. Due to the catalyst, the SCR process is more efficient than SN CR. The most common type of SCR is the high-dust configuration, where the catalyst is loca ted upstream of the airheater and downstream from the economizer.Final Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

9 3.2 SO 2 Control Technologies Considered The following describes the SO 2 retrofit technologies deemed by GVEA as potentiall y feasible for Healy Unit 1. Although not specifically listed below, the existing dry sorbent flue gas desulfurization (FGD) system is also a feasible SO 2 control technology. Enviroplan finds that GVEA has satisfied the BART step 1 requirement, wit h any additional finding(s) specific to a control option indicated as necessary below.

Increase sodium bicarbonate injection rate to impro ve SO 2 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 o r fabric filter to control SO 2 emissions. Since the system was installed in 1999, GVEA has used thr ee different materials as sorbent in an attempt to maximize the efficiency of the system. W hen the system was first installed, calcium carbonate was used as the sorbent. Several years la ter GVEA began experimenting with trona (a sodium sesquicarbonate) and was able to increase SO 2 capture significantly. In 2007, GVEA was able to optimize the system even further by using s odium bicarbonate. The SO 2 in the flue gas reacts with the sodium bicarbonate to form dry part icles, which are captured downstream in the existing fabric filter. Under current operation, th e dry sodium bicarbonate system consistently achieves approximately 40 to 50 percent removal of SO 2 . An increase in the amount of sodium bicarbonate injected may have the potential to achi eve SO 2 removal of up to 70 percent.

GVEA has indicated that there are several significa nt potential issues related to increasing sodium bicarbonate injection with the existing dry sorbent injection system:

1. The existing sorbent injection system design and eq uipment may not be able to support the required sodium bicarbonate feed rate to remove SO 2 continuously at 70 percent removal. While it may be possible to achieve 70 per cent removal on a short-term basis, it is not feasible to operate the existing equipment a t that rate continuously with no interruptions.

2. From operational experience on other similar dry so dium injection systems, a brown NO 2 plume may be visible at higher SO 2 removal rates. It is uncertain whether a brown plu me would be visible at a 70 percent removal rate.

3. From previous testing at Healy 1 in March 2008, hig her sodium bicarbonate injection rates corresponded with higher mercury emissions.

GVEA has indicated that, while it may be possible t o operate the current SO 2 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 equip ment capacities, SO 2 removal performance, and other environmental impacts. While a new dry so dium bicarbonate injection system may be designed and installed with adequate capacity, conc erns with the brown plume and potential higher mercury emission issues would remain. This n otwithstanding, GVEA submitted additional information on March 18, 2009 pertaining to the optimization of their existing FGD system. The information included capital costs asso ciated with the installation of new injectors needed to achieve the rate of injection consistent with an increased SO 2 removal efficiency of 70 percent. Additional discussion relating to the opti mization 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 a grees with GVEA on the potential for an increased occurrence of visible plumes with increas ed 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 re ddish-brown plume coloration in stack gases downstream of the particulate control device. It i s believed that some step within the overall sulfation reaction (reaction of sodium reagent with SO x ) initiates the oxidation of NO to NO 2 . It is the presence of the NO 2 in the exiting flue gases which is the source of t he 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 iss ue, 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 eleme ntal mercury (Hg) emissions at the FGD system.

While the current sodium bicarbonate feed rate is a pproximately 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 r ate of 700 lb/hr to 1400 lb/hr. This would result in an additional $0.5 to $1.0 million in add itional annual sorbent cost, and an estimated $750,000 was assumed for economic evaluation purpos es. Sorbent injection rates also vary according to coal sulfur levels. As indicated abov e, additional cost information was submitted by GVEA on March 18, 2009 and further related discu ssion 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 ato mizer wheel causes the lime slurry to separate into very fine droplets that intermix with the flue gas. The SO 2 in the flue gas reacts with the calcium in the lime slurry to form dry calcium sulf ate 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 syste m 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 f lue gas in large scrubber vessels with a limestone solution. Wet FGD scrubbers use an absorb er tower in which flue gas is contacted by the limestone slurry, resulting in conversion of SO 2 , in the flue gas into calcium sulfate (gypsum), with carbon dioxide (CO 2 ) going up the stack. The calcium sulfate is remove d from the scrubber and disposed, and it is assumed that t he 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 instal led for particulate control. The baghouse specifications include 12 compartments, each with 6 4 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 Heal y 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 col lector, hot or cold electrostatic precipitators, or wet particulate scrubbers could be considered as additional feasible particulate control options. However, none of these alternative technol ogies are considered to have the potential of matching the consistent particulate removal perform ance of a baghouse. Therefore, the existing baghouse is considered BART for Healy 1, and comple tion of the five-step BART process is not required.

Since GVEA currently uses a high efficiency baghous e for particulate control, Enviroplan agrees with GVEA in finding this control to be BART for th is pollutant/emission unit. No additional detailed analyses (steps), including no the visibil ity modeling analyses, are required for particulate emitted from Healy 1, pursuant to 40 CF R 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 NO x Control Technologies

GVEA based their technical feasibility on physical constraints, the current boiler configuration and size, and impact on boiler operation and effici ency for Healy 1. A summary showing the results of the evaluation process for the NO x technologies is provided in Table 4-1 below.

Table 4-1: Technically Feasible NO x 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 contr ol methods identified above is considered technically feasible for controlling NO x emissions from Healy 1. GVEA did not consider potential space constraints in their analyses.

4.2 SO 2 Control Technologies GVEA based their technical feasibility on physical constraints, the current boiler configuration and size, and impact on boiler operation and effici ency for Healy 1. A summary showing the results of the evaluation process for the SO 2 technologies is provided in Table 4-2 below.

Table 4-2: Technically Feasible SO 2 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 contr ol methods identified above is considered technically feasible for controlling SO 2 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 EMIS SION CONTROL TECHNOLOGIES (Step 3)

In this section, Tables 5-1 and 5-2 indicate the co ntrol 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 per iod, 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 NO x Control Technologies The expected NO x emissions rate is summarized in Table 5-1 for each of the NO x removal technologies designated as feasible in Step 2.

Table 5-1: Control Effectiveness of the NO x 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 0.23 a 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 boiler s burning sub-bituminous coal

5.2 SO 2 Control Technologies Table 5-2 presents the control technologies being e valuated and the expected removal efficiencies and emission rates. The control effici encies 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 generatin g unit (EGU). The emission limits are based on vendor information and professional engine ering judgment, as provided by GVEA. While the NPS suggested GVEA’s SO 2 removal efficiencies have been understated for the lime spray dryer and wet limestone systems, Enviroplan b elieves 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 rate s provided by GVEA are included in Table 5- 2 below.

Table 5-2: Control Effectiveness of the SO 2 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 0.07Final 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 techn ology 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 cont rol 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 det ermined on an annualized basis. The annual reduction in pollutant emission rate (tons/year) fo r 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 anticipat ed annual emission rates for Healy 1 (NO x and SO 2 ) are derived from the boiler heat input capacity o f 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 NO x and SO 2 , respectively). The use of annual anticipated pol lutant emission rates is consistent with 40 CFR 51, Appendix Y, Section IV.D, Step 4 fo r purposes of determining cost effectiveness. The current existing NO x and SO 2 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” emi ssion rates used by GVEA in their CALPUFF visibility modeling assessment. For purpos es 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., existin g or baseline) configuration. Peak 24-hour emission rates, which were used by GVEA in their vi sibility modeling analysis, are higher than the annual anticipated pollutant emission rates des cribed 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 ra nges of cost effectiveness, as shown below, that were used to establish presumptive emis sion limits for NO x and SO 2 . It is noted that the Healy 1 unit does not fall in the category list ed in 40 CFR 51, Appendix Y as a unit subject to the presumptive emission limits. Further, the cost s presented below are not considered as ceiling values never to be exceeded, and they must be consi dered in combination with the findings of the other steps of the BART determination process. Nev ertheless, these values are considered in this cost effectiveness evaluation process.

• $400 to $2000 per ton of SO 2 removed.

• $100 to $1500 per ton of NO x removed.

GVEA’s cost impact data was used to produce graphic al plots of the total annualized cost versus the expected emissions reduction for all control al ternatives identified in the BART analysisFinal 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 techn ologies that lie on this least-cost envelope are “dominant controls” that should be the focus for th e 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 consid erations.

6.1 NO x Control Technologies

Table 6-1 below provides a summary of the annual op erating costs, the total tons of NOx removed, and the average annual cost effectiveness for each NO x 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 d iscussed 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 syste m.
Table 6-1: NO x Cost Effectiveness Summary for Healy 1*

Control Technology Annualized Costs Control

Efficiency (%) Total

NO x 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/O FA system which has not been optimized for NO x minimization (only CO emission minimization). Cont rol efficiency values are relative to the current o peration.Final Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

16 Figure 6-1 Additional Annual Cost versus Additional Tons Remov ed Compared to Existing Operations Healy 1 NO x

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 RemovedTotal Annual Cost

Figure 6-1 shows the two dominant control options a re the optimization of the current LNB and OFA system and the addition of a new SCR to the cur rent 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 NO x retrofit control system, in terms of reduced emiss ions, that is considered to be technically feasible for Healy 1 includes com bustion controls (LNB/OFA) with postcombustion SCR. This combination of controls shoul d be capable of achieving the lowest controlled NO x 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, NH 3 /NO x stoichiometric ratio, NH 3 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 NO x retrofit control system that is considered technic ally 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 o f 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 c ontrol system cost estimates for their SCR system option that were developed using the EPA CUE Cost model and CH2M HILL’s professional engineering judgment based on their pr oprietary control system database. As such, GVEA’s CUECost outputs could not be replicated usin g the inputs provided in the GVEA proposal. The primary reference document utilized b y GVEA for developing the cost estimates was: “Multipollutant Emission Control Technology Op tions for Coal-fired Power Plants”; EPA600/R-05/034, March 2005. GVEA estimated the capita l 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 capi tal cost estimate range of $50-140/kW, and (2) a composite of EGU-specific BART determinations compiled by the NPS which show aFinal Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

17 range of approximately $80-400/kW. GVEA estimated t he average cost effectiveness of the SCR control system on Healy Unit 1 to be $4,748/ton of NO x removed.

An independent study on SCR retrofits and cost anal yses 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 retrofi ts than predicted by GVEA. Specifically, the NPS analysis suggests SCR systems to have total cap ital investment costs in the range of $80/kW to $270/kW. The NPS, which estimated the SC R cost effectiveness values for affected EGUs using EPA’s Control Cost Manual, determined th at 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 findi ng notwithstanding, the Department was not certain of the accuracy of the NPS cost estimat es for SCR, as they may not reflect the relatively high cost of materials and services foun d 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 r ecent NPS SCR cost estimates, and the development of Enviroplan’s own cost estimates usin g the OAQPS Control Cost Manual - Fifth Edition, February 1996, EPA 453/B-96-001.

Enviroplan calculated the cost of SCR on a dollar p er ton ($/ton) of NO x removed basis, using the OAQPS Control Cost Manual, as follows:

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

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

o Capital Recovery Factor: 0.1098. To calculate the c apital recovery costs Enviroplan assumed a period of 15 years and interes t rate of seven percent. The EPA Control Cost Manual cites an expected life of 2 0 years for a SCR system. Twenty years was thought to be too optimistic consi dering the harsh climate of the region. Recent cost analyses in Alaska have use d life expectancies of 10 years for SCR. Therefore, Enviroplan believes the life ex pectancy of the SCR (and other capital) of 15 years used by GVEA is justifie d.

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 eff iciency): 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 insta llations, literature estimates and the NPS studies discussed above, that the installed cos ts for retrofitting SCR on a plant the size of Healy Unit 1 ranges from $200/kW to $270/kW , exclusive of any extremelyFinal Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

18 favorable or unfavorable site-specific conditions w hich 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 facto rs 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 bitumino us 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 NO x 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/t on 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 exc eeds 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 unit s using SCR, as reported by the NPS. As already indicated herein, the presumptive costing i nformation is not a ceiling value; instead, it is a guideline value that must be considered in combin ation with the findings of the other BART analyses (steps).

6.1.2 Energy Impact Evaluation of the energy factor indicates that ther e is no significant energy penalty associated with the optimization of the current LNB and OFA sy stem. However, operation of an SCR system has certain collateral environmental consequ ences. In order to maintain low NO x emissions some excess ammonia will pass through the SCR. Ammonia slip will increase with lower NO x 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 addi tional 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 ec onomic impact analysis.

6.1.3 Non-Air Quality Environmental Impacts Evaluation of the non-air quality environmental imp acts indicates that there are no non-air quality related impacts associated with the optimiz ation of the current LNB and OFA system. However, SCR requires some form of ammonia (NH 3 ) 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 ammoni a 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 t he form of additional land use requirements.Final Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

19 6.2 SO 2 Control Technologies

Three control technologies are technically feasible and capable of achieving very low SO 2 emission rates. An evaluation of the economic, ene rgy 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 SO 2 removed, and the average annual cost effectiveness for each SO 2 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 d iscussed 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 SO 2 removed by each control system.

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

Control Technology Original

Annualized Costs Revised

Annualized Costs Control

Efficiency (1) (%) Total

SO 2 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 ex pressed as control relative to current operation (b aseline), 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 f indings report for the existing FGD system optimization option to increase the sorbent injecti on rate. This revision is in relation to GVEA’s submittal of revised cost information for this SO 2 emissions control option. The following presents a summary of Enviroplan’s findings associa ted 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 o f $2,000,000 or $80/kW, which was not included in GVEA’s original BART analysis r eport 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 - $12 0/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% SO 2 reduction (Healy is presently injecting sorbent at a rate of 370 lb/hr).

o An updated first year reagent cost of $1,217,859 wa s 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 purc hase receipts provided by GVEA.

o Results showed:

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

 Total Annual Cost: $1,656,590

 Annual SO 2 removed (assuming 70 percent removal efficiency): 177 tonsFinal Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

21  Cost in $ per ton removed: $9,359/ton ($1,656,590/1 77 tons = $9,359/ton)

In summary, Enviroplan finds that GVEA’s revised es timated cost for the optimization of the sorbent injection system for Healy Unit 1 SO 2 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 e ligible units greater than 200 MW, cost of control systems used to meet the presumptive SO 2 emission limits is $400 to $2,000 per ton of SO 2 removed (see, 70 FR 39133). Therefore, the averag e effectiveness of SO 2 removal at Healy 1 is more than triple the average cost effectivenes s calculated by EPA for SO 2 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 5 0% 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 signifi cant 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 gr oss energy output of the generating unit. Healy 1 has a gross rating of 25 MW; therefore, aux iliary power requirements for FGD control system would be approximately 240 kilowatts (kW). Energy impacts associated with each control technology were included in the BART econom ic impact evaluation as an auxiliary power cost.

6.2.3 Non-Air Quality Environmental Impacts Evaluation of the non-air quality environmental imp acts indicates that the installation of a new wet limestone FGD system will also result in the st orage of new chemicals onsite and a new waste stream for the facility. The exit flue gas s tack 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 surround ing the plant.

6.3 Economic Impacts – Rate Payer Analysis

During February 2009 conversations with the Departm ent, GVEA requested that rate payer cost considerations be included as part of the cost of c ompliance with the BART rule. Rate payer cost analysis information was not provided, nor con sidered, 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-eff ective measures relevant to the source. As such, the Department agreed to such considerations as applied only to the Healy Unit 1 BARTFinal Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

22 control options of SCR for NO x control and increased FGD sorbent injection for SO 2 control. GVEA provided rate payer cost data and analyses on March 18, 24 and 30, 2009.

The BART rule provides that the energy impacts anal ysis may consider whether a particular control alternative would result in a significant e conomic disruption within the area or region of the affected source. As such, the unique geographi c and economic characteristics affecting the business community within Alaska, including power p roducers, 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 o utside electric grid or connected to other utilities;

• The community does not have access to large scale a lternative power generation options (continuous hydro-power, geothermal energy, and win d 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 typic al electric utilities within the continental United States. GVEA residential customers paid $0.1 7705/kWh in the year 2008. As established by the Department of Energy, the “Representative Av erage 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 t o GVEA residential rate payers, the costs of SCR and an optimized dry sorbent injection system h ave been evaluated by GVEA on a per rate payer basis. The following presents a summary of E nviroplan’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 combin ed costs for NOx and SO 2 control systems only, and it did not include individual con trol 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 d ue to BART controls of:

 3.3% when compared to annual average rate payer cos ts 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 r ate payers since 2002

o GVEA specified the 25% increase does not include ri sing fuel costs which are passed directly to their customers

o GVEA expects in 2010 another 5.6% increase in energ y 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 t o 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 infor mation on 3/29/09:

o Rate payer analysis provided for individual NOx and SO 2 control systems, with findings of:

 1.86% rate payer increase for SO 2 control system

 1.41% rate payer increase for NO x control system

o GVEA provided 2008 annual average residential custo mer energy charge of 17.705 cents/kW-hr

• Enviroplan reviewed GVEA increased rate payer estim ates and determined slightly different percent increases to the rate payers as f ollows:

o 0.70% rate payer increase for SO 2 control system

o 0.43% rate payer increase for NO x control system

• Differences between Enviroplan and GVEA findings du e 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 (n ot 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 incre ase to the ratepayer based solely on the operation of Healy Unit 1 since rate payer cost s reflect entire plant operations

Enviroplan has tabulated the results of the above d escribed 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): $90,5 62,467 / 1,380,383,090 kWh = $0.06561/kWhFinal 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 Depreciation a $401,555 Interest b $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 yea rs = $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 SO 2

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): $90,9 55,806 / 1,380,383,090 kWh = $0.06589/kWhFinal Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

25 Table 6-3-4: GVEA Estimated Operating Expenses for the FGD Optimization SO 2

Control Option as Revised by Enviroplan

2009 Injection System Depreciation a $133,333

Interest b $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: $2,0 00,000/15 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 pe r kWh for SCR is $0.00092/kWh, which reflects an increase above the 2008 average r ate 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 pa yer 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 pe r kWh for FGD sorbent rate increase is $0.0012/kWh, which reflects an increase above th e 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 assoc iated with the individual installations of SCR and the optimized FGD system; however, we do no t believe these costs to be prohibitive in terms of the assessing the viability of either emis sions reduction system. It is noted that theFinal 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., doe s not reflect the total combined costs of both the NO x and SO 2 control system options). The BART rule requirements are specific in that the BAR T 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 in stallation 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 (WRA P) - 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, Sect ion IV.D - Step 5, “ How should I determine visibility impacts in the BART determinat ion?”. GVEA conducted the analysis to support their control analysis and proposed BART de terminations. Since GVEA currently uses a high efficiency baghouse for particulate control, w hich is considered BART for this pollutant/emission unit, no specific visibility mod eling analyses are required for particulates pursuant to 40 CFR 51, Appendix Y, Section IV.D - S tep 1.9. For the feasible NO x and SO 2 retrofit control technology options presented in Se ction 4, GVEA estimated the visibility impacts according to the following sequence:

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

• 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 cont rol option per deciview improvement ($/DV)

The following sections provide the findings associa ted 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 t heir visibility impacts. Their approach is described in Section 4 of their January 2009 BAR T 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 CALPUF F modeling files prepared by CH2M Hill, and submitted by GVEA on July 28, 2008;

• October 16, 2008 letter prepared by Enviroplan requ esting clarification and additional information pertaining to the CH2M Hill July 2008 s tudy report;

• November 11, 2008 submittal by GVEA of CH2M Hill re sponses to the October 16, 2008 Enviroplan letter, along with revised CALPUFF model ing files;

• December 4, 2008 letter prepared by Enviroplan requ esting further clarification and additional information pertaining to the CH2M Hill November 11, 2008 letter;

• December 11, 2008 Enviroplan, CH2M Hill, GVEA, Depa rtment 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 pre pared 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 c hanges 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 informati on 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 Param eters

Section 4.0 of the final GVEA BART study report pre sents the emissions inventory data used in the visibility modeling analysis. The following su mmarizes the information used in the CALPUFF input files, and any findings relating to r eview 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 fi nal report Table 4-3 and 4-4 have been used in the CALPUFF visibility modeling.

• The NO x , SO 2 and PM 10 emission rates used in the CALPUFF modeling for Au xiliary Boiler #1 are consistent with the emission rates used by W RAP.

• The PM 10 emission rate used in the modeling analysis for Un it 1 is based on a 2004 stack test. It is noted that a review of the WRAP-RMC CA LPUFF input files for Unit 1 indicated that no particulate matter emission rate was used b y WRAP for this unit. This notwithstanding, GVEA/CH2M Hill has correctly used the stated PM 10 emission rate in their July 2008 visibility modeling, and their resubmitte d November 11, 2008 visibility modeling.

• Auxiliary Boiler #1 stack exit parameters used in t he 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 informatio n 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 PM 10 emitted has been assumed as PM 2.5 , which is consistent with the WRAP modeling. While GVEA corr ectly followed the protocol, it is noted that the NPS commented on February 12, 2009 t hat not modeling elemental carbon and organic aerosol emissions was an error in the WRAP modeling protocol.

• Stack parameters for each control scenario have bee n provided by GVEA that reflect the anticipated changes associated with installation of each control technology alternative being evaluated.

• The NO x and SO 2 emission rates used in the CALPUFF modeling for Un it 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 reco mmends 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 Hi ll clarified on 11/11/08 that GVEAFinal Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

29 did not have readily available emissions informatio n 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 f inal report indicates the CEM data represents a realistic depiction of anticipated ann ual emissions for the unit. Due to the lack of 2002 actual emissions information, Enviroplan be lieves the current CEM data to be an acceptable surrogate data set for this analysis.

• GVEA modeled their current (existing) control confi guration using two emission rate scenarios. GVEA used the “peak 24-hour” NO x and SO 2 emission rates for their “baseline” scenario. GVEA also developed a “null” scenario wh erein they used an “anticipated 24- hour” emission rate for the “controlled” pollutant (e.g., SO 2 when evaluating the existing dry FGD system), and the “peak” emission rate for the “ other” pollutant (e.g., NO x when evaluating the existing dry FGD system). The “anti cipated” emission rates reflect the 24- hour emission rates averaged over a full-year of bo iler operation. The 24-hour average NO x and SO 2 emission rates for the respective “baseline” and “ anticipated” configurations, expressed as hourly emission rates, are summarized below:

Scenario* NO x (lb/hr) SO 2 (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., lo w NOx burners/over-fire air and dry sodium bicarbonate flue gas desulfurization (FGD) s ystem

Enviroplan initially believed that GVEA used the “a nticipated” emission rates to determine modeled emission rates for the other retrofit contr ol 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 retrof it control option. GVEA indicated that the emission rates used for each retrofit control optio n 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 u sed 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 f or cost estimation purposes.

Based on the above, Enviroplan has determined that the NO x and SO 2 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. Li kewise, 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 bee n compared for consistency with the recommendations of the WRAP protocol. GVEA’s CALME T 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 re commended in the protocol, using scripts and inputs to recreate the CALMET output fo r 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 consist ent:

o CALMET input parameters and options used by GVEA, a s summarized in final report Table 4-1;

o the meteorological surface stations, as specified i n 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 rep ort 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 W RAP protocol and related BART guidance documents. Applied modeling procedures and any fin dings are summarized as follows:

• CALPUFF version 6.112, level 060412;

• CALPUFF modeling performed for one year (2002), con sistent 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 concentra tion of 0.5 ppb);

• Regulatory default model options when such options are specified;

• National Park Service discrete receptor locations a nd elevations for DNPP (http://www2.nature.nps.gov/air/maps/Receptors/inde x.cfm);

• Aerodynamic building downwash not used in the model ing analysis; and

• CALPUFF computational domain consistent with the CA LMET meteorological domain (NX=275, NY=325).

The data described by GVEA in their final study rep ort 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 cons istency with the WRAP protocol and relatedFinal Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

31 BART guidance documents. Applied modeling procedur es 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 specif ic to the DNPP Class I area as taken from Table A-3 of Guidance for Estimating Natural Visibility Conditio ns Under the Regional Haze Rule , EPA-454/B03-005 (September 2003); and

• Annual average natural background aerosol concentra tions as taken from Table 2-1 of Guidance for Estimating Natural Visibility Conditio ns Under the Regional Haze Rule , EPA454/B03-005 (September 2003).

The data described by GVEA in their final study rep ort 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, wh en 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 natur al background, expressed in units of deltadeciviews ( ∆ dV). In their July 2008 report, GVEA utilized 98 th percentile delta-deciview visibility predictions; however, pursuant to the BA RT rules, this is permissible only when modeling multiple years of meteorology (e.g., 3-yea rs). The final January 2009 report correctly presented modeling results as maximum values (Table s 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 impac ts 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 NO x and SO 2 emissions control scenario. Table 4-7 also present s the number of days predicted to exceed the significance level of 0.5 dV for each scenario, alo ng with related visible cost effectiveness values (e.g., $/deciview improvement). Table 5-1 of the f inal report presents the change (i.e., improvement) in model prediction results when compa ring “baseline” visibility predictions to the alternate control scenarios.

7.3 Visibility Monitoring Program

In addition to performing the required retrofit sce nario visibility impact analysis as part of the overall BART control determination analysis, GVEA i ndicated in the January 2009 final report that they previously conducted a visibility monitor ing 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 He aly 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 r equired GVEA to develop a VMP and operate visibility monitoring equipment for the per iod 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 th e National Park Service (NPS), had the objective of collecting sufficient visual and m easurement data to:

1. Provide reasonable assurance that NO x , SO 2 , and particle emissions from the HCCP and Healy Unit 1 sources were not adversely impairing v isibility within the DNPP Class I area; and

2. Evaluate any trained NPS observer’s reports of v isibility impairment for their potential attribution to NO x , SO 2 , and particle emissions from operations of HCCP an d Unit 1.

Under the VMP, photographic and air quality instrum entation was established at three monitoring stations, i.e., Garner Hill site overloo king 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 N enana Valley north of the DNPP Visitor Access Center. Measurements of meteorological data , SO 2 concentrations, and nephalometer readings of light scattering by sulfate particles w ere taken at Bison Gulch for use in estimating the contribution of the SO 2 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 peri od, Healy 1 was operating with the current NO x control configuration and the current baghouse, bu t the current FGD SO 2 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 SO 2 than under the current configuration (with the FGD system). GVEA notes that HCCP had not been fully optimized during the VMP, resulting in emissions ab ove 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 op eration). Quarterly reports were submitted to ADEC, EPA and the NPS during the progr am. In 2000, the ADEC, EPA and NPS agreed the VMP could be temporarily shut down a s HCCP never reached full commercial operation. HCCP has not operated since that time. GVEA indicated the results of the program demonstrated that no visibility impa irment 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 w as reached between this slight plume and any visibility issues within DNPP.

Coincident with the VMP, a three year study was con ducted in which particles that cause or contribute to regional haze were measured and analy zed to determine if Healy was contributing to regional haze. The study was funded by GVEA, managed by the NPS, andFinal 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 Trappe r Creek CASTNET Protocol Sites, July 1998 through June 2001.” Per GVEA, the report concl uded that there was no specific indication that operations from the Healy Power Pla nt contributed to regional haze.

GVEA concluded that the Unit 1 existing control con figuration for all pollutants is BART. This conclusion is based in part on GVEA’s assertion tha t 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 a sserted during the February 27, 2009 teleconference with the Department that no visibili ty impairment has occurred at DNPP. A response to this further assertion is provided late r in this section.

In considering the relevance of the prior VMP in ma king 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 rev iew/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 t he NPS. GVEA in their January 2009 submittal concurred, indicating that they knew of n o formal correspondence from ADEC, EPA or the NPS regarding the acceptability of the visib ility monitoring program and studies.

Enviroplan therefore conducted a limited review of the VMP related materials and correspondence as part of the BART review. Based o n this limited review, Enviroplan notes the following:

• The monitoring program would have occurred at a tim e of greater potential for plant emissions, given the operation of HCCP and no FGD s ystem 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 du ring the year at typical, full operating rates representative of normal maximum emission rat es. It is known that HCCP did not reach full operational status. However, it is unclear wh ether Unit 1 was at full capacity during the VMP, although Section 1 of GVEA’s final report (sum marized above) indicates this to be the

case.

• It is acknowledged that the NPS did not identify an y 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 whethe r lack of correspondence from the NPS during the monitoring program is indicative of agen cy concurrence with GVEA that no instances of visible plume events occurred that wou ld 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 g enerally high. While relatively few events (“anomalies”) are identified in the reports, events are nonetheless identified. For instance, the initial report submitted for the 1 st quarter 1998 identifies several events wherein the plant’s plume may have entered the Class I area. T he 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 gener al 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 summariz ed by GVEA in their final report, cannot be considered in terms of the BART control determinati on for Healy Unit 1 for the following

reasons:

• In a February 10, 2009 teleconference between the N ational 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 o n the potential impact of a plume of specified emissions for specific transport and disp ersion conditions), the results of which cannot be used to satisfy the requirements of the B ART program which pertains to visibility impairment due to regional haze.

• There is a lack of formal agency acknowledgement an d approval of the results and findings of the VMP.

• It is not clear whether the NPS agreed with the fin dings in the quarterly monitoring summary reports, and the conclusion by GVEA that no reporti ng by the NPS equates to no visible impacts by Healy at DNPP during an “anomalous” even t.

• The BART rule does not exempt a source from conside ring impacts associated with visibility modeling if a source has conducted visibility monit oring.

• The BART rule does not indicate that all feasible r etrofit technologies can be dismissed if a source has conducted visibility monitoring which su ggests no or limited visible impacts at the nearest Class I area.

• The VMP has limited application and is not complete ly relevant to the BART rule. Specifically, an air dispersion model (CALPUFF in t his case) is a tool used to assess potential air quality impacts associated with emiss ions from a source (or sources). Typically, air modeling is conducted over a large geographic a rea 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 ar ea where the monitoring equipment is sited. As such, while air dispersion models tend to be con servative predictors of air quality versus similarly measured data, the BART rule requires a v isibility 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, 200 9 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 impairmen t 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/SI P effort for reducing visibility impacts. This evaluation is based primarily on visibility mo nitoring data collected at the DNPP IMPROVE monitor site, plus other available informat ion provided by the Department relating to regional haze studies at DNPP. As summary of our r eview 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 natura l 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 s et 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 estimati ng natural visibility conditions, the 20% best visibility and 20% worst visibility days at th e Denali National Park and Preserve have been estimated to be 2.30 and 7.42 deciviews (dv), respe ctively (U.S. EPA, “Guidance for Estimating Natural Visibility Conditions Under the Regional Ha ze 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 sit e. 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, clea rly indicate that there is visibility impairment at the Class I area (i.e., the area is n ot currently at natural conditions).

An inspection of the IMPROVE particulate matter che mical speciation data indicates the yearround presence of sulfates and nitrates, which are primarily derived from combustion sources. The acidic sulfate aerosols that comprise Arctic Ha ze 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 wit hin the Denali Class I area. An analysis of air trajectories using the National Oceanic and Atmosph eric Administration Hybrid Single Particle Lagrangian Integrated Trajectory (HYSPLIT) model in dicates 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 vi sibility impairment within the Class I area (Hafner, W.D., N.N. Solorzano, and D.A. Jaffe, “Ana lysis of Rainfall and Fine Aerosol Data Using Clustered trajectory Analysis for National Pa rk Sites in the Western U.S.,” Atmospheric Environment

(2007)). Furthermore, the CALPUFF modeling that w as conducted by CH2M Hill in support of the GVEA Healy Power Plant BART Analy sis (Final Report submitted January 2, 2009) clearly indicates that emissions from the GVE A plant are expected to impact Denali. The CALPUFF Model simulates the influences of complex t errain on plume transport over local and regional scales. This modeling utilized one full y ear (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 Un it #1). CALPUFF modeling results indicated that, under plant baseline (i.e., existin g (pre-BART) control) operating conditions, the Denali Class I area was significantly impacted by t he boiler emissions 136 days during the year, as defined by a deciview value of 0.5 or greater, a nd 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 regar ding 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 dete rmination 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 b y 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 re place the CALPUFF visibility modeling results considered in this BART determination proce ss 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 Auxi liary Boiler #1. A limited review of materials pertaining to the 2-year visibility monit oring program performed by GVEA at the DNPP Class I area also has been conducted. Envirop lan presents the following conclusions pertaining to GVEA’s visibility impacts determinati on:

• The CALPUFF visibility modeling analyses are in con formance with the protocol used by WRAP – RMC (“Draft Final Modeling Protocol CALMET/C ALPUFF Protocol for BART Exemption Screening Analysis for Class I Areas in t he Western United States”, August 15, 2006), and WRAP’s, “Summary of WRAP RMC BART Modeli ng for Alaska” (Draft#7, April 6, 2007).

• The CALPUFF visibility modeling analyses are genera lly 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 em ission 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 metr ic. Consistent with the individual source attribution approach in Appendix Y, no additional c ontrols are required for this unit.

• Each NO x

emissions control option considered for Unit 1 res ults in a greater than significant visibility improvement (i.e., greater than 0.5 dV) when compared against the maximum predicted daily visibility impact “baseline” scenar io, with the low NO x 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 SO 2 emissions control options considered for Unit 1, t he retrofit scenario of increased sorbent feed rate to the existing FGD results in on ly a 0.25 dV improvement versus the impacts associated with the baseline scenario (i.e., 1⁄2 of t he significance level), and the visibility impacts associated with a lime spray dryer FGD syst em and wet limestone FGD system are worse than the current baseline configuration due t o reduced plume height from a relatively colder, wetter plume. Coincidentally, the number o f days exceeding the significance level (0.5 dV) increases for each of these control options ver sus the current baseline configuration.

• On February 12, 2009, the NPS commented on the pred icted worsening of modeled visibility impacts attributable to the lime spray dryer FGD sy stem and wet limestone FGD system. The NPS questioned the use of CALPUFF and GVEA’s recept or grid. The bases for these comments are unclear. GVEA used the WRAP – RMC mod eling protocol, which was reviewed by the NPS and subsequently approved by th e Department. In discussing this issue with the Department, the Department stated that the y saw no merit in changing modeling approaches, and that it was too late in the SIP dev elopment process to make such a substantive change. Visibility-related cost effectiveness info rmation is provided for each NO x emissions control scenario in terms of both deciviews and day s 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 NO x 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 NO x burners/OFA). The most costly control expressed in dV and days above 0.5 dV is the replac ement of the existing control configuration with ROFA and Rotamix. Similar cost effectiveness information is presented for the SO 2 control scenarios; however, costing information for the lime spray dryer FGD system and wet limestone FGD systems expressed in terms of visibil ity metrics are not meaningful since the visibility impacts worsen under these control scena rios.

Visibility Improvement and Annual Costs for SO x 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 th at no controls are required for Auxiliary Boiler #1. Also, the lime spray dryer FGD system and wet limestone FGD system SO 2 retrofit options for Unit 1 (i.e., Options 2 and 3 in Section 4 of the f inal report) show a worsening of visible impacts as predicted at DNPP, and Enviroplan agrees with GVEA that these options are not considered viable as SO 2 BART for Unit 1. Enviroplan also finds that the h igh cost effectiveness associated with anFinal 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 associa ted with other steps in the BART analysis process, i.e., increased potential for visible impa cts (brown plume), results in the sorbent injection increase option not being viable as SO 2 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 NO x Control at Healy Unit 1 GVEA has proposed the existing low NO x burner and over fire air NO x emissions control system as BART for Healy 1. However, upon consideration o f 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 s upporting documentation provided during this review process, Enviroplan recommends the prelimina ry BART determination for Healy Unit 1 for NO x emissions control to be the existing LNB and OFA s ystem, with the addition of a selective catalytic reduction (SCR) system. This p reliminary BART determination is proposed by Enviroplan for the Unit 1 BART-eligible source b oth 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 underlyi ng goal of the BART rule relates to the Clean Air Act’s national goal of eliminating man-ma de visibility impairment from all Class I areas. As already stated herein, the BART rule, wh en applicable, requires a control technology determination based on multiple factors, including costs and visibility impacts and improvements associated with feasible retrofit options. Enviropl an believes the LNB/OFA+SCR NO x control retrofit option for Healy 1 represents the best com bination of factors (steps evaluated) under the BART rule for the purpose of improving visibility i mpairment at DNPP Class I area. The basis for this determination is as follows:

1. Healy 1 Power Plant is located in very close proxim ity (about 8 km) to the DNPP Class I area, with the potential for substantive visible im pacts at the Class I area (as predicted with CALPUFF).

2. The Healy 1 unit already utilizes the best system o f particulate pollutant control (high efficiency baghouse), and the existing configuratio n for SO 2 control (FGD system) is considered as BART (see below). However, various a lternative retrofit NO x controls are potentially applicable to Healy 1 for substantive a dditional reduction in unit NO x emissions.

3. The visibility impact modeling done for Healy 1 ind icates that the existing LNB/OFA system results in 136 days per year when the visibility im pacts attributable to Healy 1 exceed 0.5 deciviews at DNPP. Employing the LNB/OFA+SCR NO x control option reduces the number of days with modeled impacts over 0.5 deciviews to 65. Utilizing the NO x control that incorporates SCR significantly reduces the predicte d number of days with modeled impacts over 0.5 deciviews by an additional 71 days per yea r.
4. The use of the NO x control option incorporating SCR will reduce the h ighest delta deciview impacts from 3.359 ∆ dV to 2.573 ∆ dV, which is the greatest reduction in visible impa cts of all NO x retrofit control options considered and the relati ve 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 NO x emissions by at least 72% from existing baseline e missions, which equates to 266 tons of additional NO x emissions removed from the Healy 1 exhaust gas str eam.
6. GVEA estimated the average cost effectiveness of th e SCR control system on Healy Unit 1 to be $4,748/ton of NO x removed. An independent study on SCR retrofits an d cost analyses for BART eligible boilers prepared in January 2009 by the National Park Service (NPS) estimated lower costs for SCR retrofits. The NPS a nalysis suggests SCR systems typicallyFinal Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

41 have a total capital investment cost on the order o f between $80/kw to $270/kw. The NPS estimated the cost effectiveness using EPA’s Contro l 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 t otal 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 Un it 1 to be $3,373/ton of NO x removed at a total capital investment cost of $241/kW. Althoug h Enviroplan’s (and GVEA) cost effectiveness is greater than the $1500/ton cost ef fectiveness value cited in the preamble to the EPA’s BART Guideline (70 FR 39135), the $1500 e ffectiveness value is not a ceiling value, and it must be considered with all other BAR T review aspects and control cost effectiveness metrics.

7. The annualized cost per dV improvement is $1,141,93 3/dV. The NPS indicated during a February 2009 teleconference with the Department th at values in this order of magnitude are much less than the cost per deciview accepted in ot her BART assessments, which have ranged on the order of $12 million/dV.

8. GVEA estimated that the incremental ratepayer incre ase for the addition of the SCR is $0.00092/kWh, an increase of about 1.4 percent. Fo r a family that uses 500 kWh/month, the addition of SCR would cost $0.46/month and $5.52/ye ar. 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 syste m through NO x reductions and visibility improvements outweigh the possible environmental im pact 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 decivie w reduction or cost per reduction in days above 0.5 dV, as provided by GVEA in the final report), i s generally the most expensive when compared to the other NO x retrofit options. It is also recognized that the addition of SCR results in the highest annualized costs among the NO x retrofit options. However, it is believed that fo r the multiple reasons indicated above, including the general cost acceptability ($/kW and $/dV), the proximity of Healy 1 to DNPP, the additional re duction in NO x 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 objec tives of the BART rule.

8.2 SO 2 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 economic ally feasible. In addition, a new lime spray dryer FGD system also presents excessively hi gh cost per ton values, including the incremental cost, plus both the wet and dry retrofi ts 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 sor bent injection at the existing FGD is costFinal Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

42 prohibitive. This, along with the increased potent ial for visibility impairing brown plume make the increased sorbent injection option unviable. T herefore, no additional controls are recommended for the Healy 1 boiler to reduce SO 2 emissions. The use of the existing dry sorbent injection system to control SO 2 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 parti culate 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 E nviroplan’s findings regarding GVEA’s July 2008 BART control analysis in terms of compliance w ith 18 AAC 50.260(e) through (h). The July 2008 report was revised and resubmitted by GVE A 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-eligib le source at this facility, consistent with 18 AAC 50.260(j), is also an objective of this revi ew. 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 SO 2 emissions is considered as BART; the addition of a SCR system to the existing LNB an d OFA system to control NO x 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, th e 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 H ealy 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 Propos ed for Healy 1

Particulate SO 2 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 a re reflective of the vendor/engineering judgment-based limits provided by GVEA. This notwi thstanding, GVEA requested on March 18, 2009 that their preliminary BART emission limit s be revised to account for potential operating variability. GVEA conducted an analysis of 2003-2008 (5 years) 30-day rolling NO x and SO 2 emissions from Healy Unit 1. GVEA applied three s tandard deviations to the mean, and requested that their BART emission limits reflect t he resultant rates (i.e., 0.09 lb/MMBtu for NO x (with SCR) and 0.27 lb/MMBtu for SO 2 (with an optimized FGD system, if determined by the Department as BART; or 0.49 lb/MMBtu for SO 2 with the current FGD configuration, if determined by the Department as BART). Given the l ong-term nature of the emissions averaging period (30-days); and the fact that the e mission limits provided by GVEA are mean values which inherently account for variability, En viroplan believes that the Table 9-1 emissionFinal Findings Report– April 27, 2009 BART Determination: GVEA Healy Power Plant

44 limits will adequately account for any short-term u pset or malfunction conditions. Therefore, no change has been made to the GVEA emission limits.

The existing (current) emission limits shown in Tab le 9-1 were established pursuant to regulatory requirements other than the BART rule. For example, the SO 2 limits of 258 lb/hr (24- hour average) and 367 lb/hr (3-hour average) were e stablished to protect the short-term SO 2 air quality standards. Part 71 permit No. 173TVP01 pro vides the basis for each of the existing emission limits. While the existing short-term emi ssion limits for PM 10 and SO 2 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 limit s are prescribed on a 30-day rolling basis per 40 CFR 51, Appendix Y, Section V. Therefore, the p roposed 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, recor d-keeping, and reporting conditions are proposed in order to demonstrate compliance with th e BART emission limits. This is consistent with 40 CFR 71.6(a)(3). The existing Title V opera ting permit for the Healy Power Plant (No. 173TVP01) contains PM, NO x and SO 2 emission limits established from prior BACT and Ow ner Requested Limit (ORL) determinations. Related moni toring, record keeping and reporting (MR&R) conditions are also contained within the per mit. 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 NO x and SO 2 limits contained in the BACT and ORL section of the permit requires compliance be demonstrated u sing continuous emissions monitoring systems for NO x and SO 2 ; and stack testing for PM. Proposed BART emission limits for Unit 1 will be demonstrated through the continued u se of existing CEM systems for NO x and SO 2 ; and continued stack testing for PM. 2. Preliminary BART recommended for Auxiliary Boiler # 1, and Healy 1 for particulate and SO 2 emissions, is the current configuration for these units. Except for revising the permit to include the BART rule citation and expressing the U nit 1 particulate and SO 2 emission limits in Table 9-1 above, the existing Title V permit MR& R conditions, including the CEM and stack testing requirements, shall demonstrate compl iance with the BART emission limits for these units and pollutants. 3. The new NO x emission limit and BART rule citations will need t o 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 opera ting conditions in the existing Title V permit would continue to apply to Unit 1. Operatin g parameter conditions for the SCR system would need to be included in the Title V per mit, including continuous monitoring and recording of an ammonia injection rate and/or gas p ressure 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 co ncentration.