DEPARTMENT OF ENV IRONMENTAL CONSERVATION 

AIR QUALITY OPERATING PERMIT 

RESPONSE TO COMMENTS 

Operator Name: Golden Valley Electric Association Permit No. AQ0173TVP02 

Owner Name: Alaska Industrial Development 

 and Export Authority 

Public Comment Closing Date: August 29, 2011 

Stationary Source Name: Healy Power Plant

 

The public comment period for the Golden Valley Electric Association, and Alaska Industrial 

Development and Export Authority, Healy Power Plant operating permit closed on August 

29, 2011. 

GVEA applied for the permit renewal on June 16, 2008, with amendments and additional 

information received by the Department prior to the comment period through August 25, 2009. 

A previous comment period was held in the Fall of 2009. Further information was received from 

GVEA February 14, 2011 and July 19, 2011. 

The Department revised the draft permit before the second comment period, based on review of the 

application, comments and testimony received during the 2009 public comment period, and 

subsequent changes in currently applicable Clean Air Act requirements. In response to additional 

issues raised through the first public comment process, the Department supplemented the PSD 

applicability review by a) enhancing its basis for concluding that the project is not a modification; b) 

examining the commercial start-up project affiliated physical changes in their totality; and c) 

evaluating net emissions increase of the project to conclude that PSD does not apply. See Statement 

of Basis Appendix C.

This document evaluates the comments received during the second comment period that ended 

August 29, 2011. 

Some comments appear here exactly as written. Comments are paraphrased where numerous 

commentators repeated the same comment, not always in the same words. This paper provides 

ADEC’s responses to the comments. 

 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

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Table of Contents

1. GENERAL COMMENTS IN SUPPORT OF ISSUING THE RENEWAL PERMIT ...............4 

Cost of Power, Security, Effect on the Economy, and Jobs ...........................................7 

Power Cost ..................................................................................................................7 

Role of HCCP in Reducing Costs, Creating Jobs, and Providing Security .................9 

Investments Made in HCCP ......................................................................................10

Other Power Options ......................................................................................................10 

Coal Resources ..................................................................................................................................... 12

Comments Suggesting Reasons for Delay in HCCP Startup ............................................. 12

2. GENERAL COMMENTS IN SUPPORT - ENVIRONMENTAL AND REGULATORY 

ISSUES .........................................................................................................................................13 

 Plant Emissions and Area-wide Air Quality .............................................................13 

 Ash .............................................................................................................................14 

 Greenhouse Gas Emissions .......................................................................................14

3. COMMENTS IN SUPPORT - PERMITTING AND EMISSIONS .........................................15 

 Environmental Performance Standards .....................................................................15 

 Additional Regulatory Review ..................................................................................15 

 To Strike Down the Project Wrong ...........................................................................16 

 Mercury .....................................................................................................................16 

 Lower Emissions .......................................................................................................16 

4. TECHNICAL COMMENTS FROM GVEA ........................................................................17

5. GENERAL COMMENTS IN OPPOSITION TO PROPOSED PERMIT ........................18 

6. LOCAL AIR QUALITY AND REGIONAL HAZE ............................................................19 

7. PSD APPLICABILITY ..........................................................................................................20 

PSD Comments from Denali Citizens Council .............................................................20 

PSD Comments from National Park Service ................................................................21 

PSD Comments from Trustees for Alaska ....................................................................23 

Reactivation Policy ....................................................................................................23 

Major Modification - Routine Maintenance ..............................................................25 

Major Modification - Emissions Increase .................................................................41 

8. COMMITMENTS IN THE 1993 MEMORANDUM OF AGREEMENT .......................43 

9. COMMENTS RECOMMENDING CO2, MERCURY, AND COAL ASH EMISSION 

LIMITS, AND MONITORING ..................................................................................................43

BACT and Monitoring ...................................................................................................44

Health Standards ............................................................................................................45 

Mercury Control Provisions ..........................................................................................46
Golden Valley Electric Association Response to Comments 

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Abbreviations and Acronyms 

ADEC....................... Alaska Department of Environmental Conservation 

AQRV ....................... Air Quality Related Value 

BACT ...................... Best Available Control Technology 

Btu ........................... British thermal unit 

CAA ........................ Clean Air Act 

CFR. ........................ Code of Federal Regulations 

CO ........................... Carbon Monoxide 

CO2 ......................... Carbon Dioxide 

CO2e ....................... Carbon Dioxide Equivalent 

DNPP ....................... Denali National Park and Preserve 

EPA.......................... United States Environmental Protection Agency 

Fed. Reg. ................. Federal Register 

GHG or GHGs......... Greenhouse Gas or Greenhouse Gases 

km............................ Kilometers 

kW-h ...................... KiloWatt Hours 

lb/MMBtu ................ pound per million Btu 

MOA ....................... memorandum of agreement 

μg/m3....................... Microgram per Cubic Meter 

NAAQS .................... National Ambient Air Quality Standards 

NEPA........................ National Environmental Policy Act 

NO2 .......................... Nitrogen Dioxide 

NOX.......................... Oxides of Nitrogen 

NPS ....................... National Park Service 

OxyCat...................... Oxidation Catalyst 

PM ........................... Particulate Matter 

PM2.5 ....................... PM with an Aerodynamic Diameter less than 2.5 Microns 

PM10......................... PM with an Aerodynamic Diameter less than 10 Microns 

ppm........................... Parts Per Million 

PTE............................ Potential to Emit 

PSD .......................... Prevention of Significant Deterioration 

SCR .......................... Selective Catalytic Reduction 

SIL ........................... Significant Impact Level 

SO2 ........................... Sulfur Dioxide 

tpy............................. Tons per Year 

VOC.......................... Volatile Organic Compound 
Golden Valley Electric Association Response to Comments 

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1. GENERAL COMMENTS IN SUPPORT OF ISSUING THE RENEWAL PERMIT 

A large number of commentators submitted written comments requesting the Department to 

issue the renewal permit without addressing specific permit conditions or regulatory authority for 

making a decision. Most of the following commentators included one or more comments also 

made by others. Many of the comments contained a statement agreeing with the Department's 

decision to issue the permit without additional regulatory review and urging EPA to honor 

delegation of authority by accepting the permit. 

These comments are paraphrased and grouped together, sometimes in the same paragraph, 

because many commentators made the same point, sometimes using differing language, 

sometimes sending the same letter. 

From: 

Julie Abegg 

Frank Abegg 

Mark Anderson, Construction Operations Manager, CCI Automated Technologies

Anna C. Atchison, Board Member, Greater Fairbanks Chamber of Commerce

Gregory A. Beischer, President & CEO, Millrock Resources Inc. 

Robert Bell 

Steve Borrell, Executive Director, Alaska Miners Association, Inc. 

Deryl A. Box 

Randy Brand 

Bill Brophy 

Jerry Cleworth, Mayor, City of Fairbanks 

Steve & Carol Connelly 

John Coghill, Senator, Senate District F 

Dayn Cooper, President, Complete Service Company, Inc. 

Bryan Davis, Director of Business Development, North Star Equipment Services 

Steve Denton 

Mike Desmond 

Alan Dick, Representative, House District 6 

Linda Dingbaum 

Jim Dodson, President & CEO, Fairbanks Economic Development Corporation 

Sandi Doyle, Administrator, Caring Bridges ALH Inc. 

James P. Duffield,II, CPA, Resource Accountant, NANA Development Corporation 

Bruce Dunkle 

Dr. David Eichler, dentist 

Eric Feige, Representative, House District 12, Co-Chair, House Resources 

Committee 

Siegfried Fink 
Golden Valley Electric Association Response to Comments 

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Will Finley 

Thomas Fisher 

Rebecca Galasso 

Rajive Ganguli 

Becky Gay 

Rich Giessel 

Cathy Giessel, Senator, Senate District P 

Stephanie Gohlke 

Karl. I Gohlke 

Claudio Gomes and Theresa Gomes 

Daniel Graham, PE, President, Alaska Coal Association 

Randy S. Griffin 

Ken Hall 

Laren Haskin 

William T. Hawley 

 Richard Heieren Board of Directors, Chair; Lisa Herbert, Executive Director, 

Greater Fairbanks Chamber of Commerce 

Luke Hopkins, Mayor, Fairbanks Northstar Borough 

Rich & Virginia Hughes 

Todd Hume 

Garry Hutchison 

Douglas W. Isaacson, Mayor, City of North Pole 

Carole Jaffa, President, Jaffa Construction Inc. (comments received late but 

duplicated by others) 

Guy Jeske, VP – US Operations, Coeur d’Alene Mines Corp. 

Anton K. Johansen 

Colin C. Keith 

Samantha Kirstein 

Jo A. Kuchle 

Mark S. Kulstad (comments received late but duplicated by others) 

Ken D. Lambertsen 

Bart LeBon 

Steven R. Lundgren 

Peter Lundquist 

Denise Lundquist 

Jim L. Lynch 

Ladd McBride 

Glenn M. Prax 

Michael D. Miller 

Audrey Murphy 

Bob Musgrove 

Jerry Mustard 

Kurt W. Newman 

Buzz Otis, Executive Director, North Pole Economic Development Corporation 

Mike Powers, CEO, Fairbanks Memorial Hospital / Denali Center 
Golden Valley Electric Association Response to Comments 

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Dan Rees, District Treasurer, Fairbanks Soil and Water Conservation District 

Board of Supervisors 

Alan Renshaw 

Brent Richey 

Ann Roberts 

Lance Roberts

Glenn Ross 

Mark Schimscheimer, P.E., HCCP Project Manager, Alaska Industrial 

Development and Export Authority 

Lorna Shaw, Community & Government Relations Manager, Fairbanks Gold 

Mining, Inc. 

Diane Shoemaker 

Teri Simmons 

Karm Singh 

Dan Snodgress, Vice President and General Manager, Kinross Fort Knox Mine 

Jeanine St. John, Vice President, Lynden Incorporated 

Renee Staley 

Nannette Stone 

Suzanne Summerville 

Gary Swoffer, President, Denali Industrial Supply, Inc. 

David Szumigala 

David M. Talerico, Mayor, Denali Borough 

Patricia F. Thayer 

Donna Therriault 

Coleen Thompson 

Jack Van Alstine P.E. 

Joseph E. Usibelli, Jr., President , Usibelli Coal Mine, Inc. 

Marilyn Usibelli 

Timothy S, Venechuk 

Bill Vivlamore 

Glen Weaver 

Jason Wells 

Charles Wiegers 

Jack B. Wilbur, Jr. 

David L. Williams 

Tammie Wilson, Representative, House District 11 

One additional commentator whose signature was not completely legible. 

75 public comment cards supporting issuance of the permit were received from Local 375 

in Fairbanks. Comments on each card are identical, and are included in the comments 

below. Signers were: 

David Hughes Kirk Culver Tyra Gelinas 

Jerry C. Freel Linda Buechler Brett G. Smith 

Rick Kimberlin Dennis Dooley Rick Lord 

Ihor Bashchuk Jeremy Holan Joseph Hoegerl 
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Michelle Morgan Kim Brandenburg Michael R. Sexton 

Kei M. Church John Ferree Steve Harvey 

Daniel D. Davis Daniel Huerd Tim Olsen 

Dean Bean Jacob Wright, Sr. Maril Garner 

Rose Todd Cindy L. Gray Jeff Mabin 

Jason Stewart Christine Rae Litsch Michael Arron Adams 

David S Dever Paul Johnson Michael Downs 

John Guichici Bret Helms Michael Beans 

Jake Furtak Max Sprott Luke Pearson 

L. Wayne Roberts Jeramie Ubben Brandon Burnett 

Josh McKay Chad Gudschinsky John T. Wing 

Robert Knight Samuel Dordile Kirk Jackson 

John Plutt Karm Singh Rodney Brown 

Jenn Dayan Doug Tansy Eileen Laiti 

Jay Quakenbush Kim Brown Mary Springer 

Dale Springer Mike Laiti John Baker 

Jim Laiti Janet Baker James McMilon 

Dale L. Welty Charles W. Young Laird Grantham 

Josef Schruf, Jr. Kevili M. Ginley Alex Innes 

Jonna Weed Maryann Keane Ed Flanagan 

Carol L. Heiter Scott C. Eickholt Kevin Pomeroy 

Note: The Department apologizes for any misspellings where signatures were not 

completely legible. 

Cost of Power, Security, Effect on the Economy, and Jobs 

There were many commentators who stated that HCCP is needed because it will ease the 

high price of energy in the Interior. Many identified themselves as GVEA members, lifelong or long-term Alaskans, homeowners, or businessmen and women. Comments on 

cost, security, the economy, and jobs are the following. 

Power Cost

Interior residents are bracing for another season of crushing energy costs. 

Limited access to natural gas results in reliance on diesel fuel for heat and 

electricity. There are seven or eight months with limited daylight. Temperatures 

often dip to minus 20° to 50° Fahrenheit and can remain there for weeks. Nearly 

50% percent of our electric needs are currently met by oil-fired generation. Our 

economy is being choked out by energy prices too high to attract growth or even 

sustain a reasonable standard of living. Thousands of homeowners in the interior 

pay more than $1,000 (ONE THOUSAND DOLLARS MONTHLY) to electric 

and heat bills combined per month in the winter. 

It is not fair to suffer in the winter because GVEA can't get the permit. 
Golden Valley Electric Association Response to Comments 

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Depending on the price of oil, upwards of $600 Million dollars are drained from 

our Community’s economy yearly and residents who might normally spend 

10‐15% of their income on energy, spend upwards of 25‐30% or more. 

The [City of North Pole] Council has passed resolutions to help improve the 

energy efficiency of the City, to exchange out the sodium street lights for LEDs, 

make improvements in the Utilities which have greatly reduced electrical 

consumption, and other actions, yet have watched with growing concern as the 

City's energy costs have doubled since 2008. 

As the single largest ratepayer at GVEA, and a consistent consumer of 32 

megawatts of power, [Kinross Fort Know Mine has] a keen interest in both the 

source and the cost of power for GVEA. 

Because of high energy costs, profit margin continues to get pressed lower and 

lower, which results in inability to expand, hire and grow businesses. 

One small business owner reported paying, as of August, over $19,000 for heat, 

electricity, and water/sewer, including over $11,000 to GVEA. 

As retired folks, we find that living in Alaska is becoming an intolerably costly 

situation. 

Too often, residents are delaying or forgoing the kind of investments they'd 

normally make towards their mid- to long-term prosperity for fear the "last" 

dollar, might be the only thing which allows them to hold onto the little they have. 

GVEA’s turn off notice’s are at a summer time high never before seen in summer 

months.

Heavily reliant on oil for all three of our major energy requirements – 

transportation, space‐heating and electrification – we have watched as 

ever‐increasing petroleum costs have eroded the underpinnings of our economy. 

I believe that the cost of energy has a massive trickle-down effect, and could be 

considered an important part of money-multiplying behavior within our local 

economy. I also perceive a trade-off between quality of life (especially for the 

poor) and the price of energy. When local energy costs decrease, production costs 

will decrease for everyone relying on the grid. One way or another, these savings 

are likely to be passed on in "quality-of-life" purchases, regardless of whether the 

purchases are for luxuries or essentials. The more times money changes hands, 

the more jobs tend to be involved. In any case, you can bet the folks on 

the thinner parts of this money-multiplying tree need the trickle-down benefits of 

lower energy prices more than others. 

The need for relief is urgent. 
Golden Valley Electric Association Response to Comments 

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Role of HCCP in Reducing Costs, Creating Jobs, and Providing Security

Taking current oil prices into consideration, HCCP has the ability to reduce 

GVEA members’ electricity bills by 20%. It is estimated that GVEA members 

are purchasing power at three times the cost of the national average. 

Rate payers will save $24 million per year. 

We desperately need the HCCP to resume full power production. HCCP would 

produce power at a much lower cost than oil-fired generation and would eliminate 

a great deal of the uncertainty in cost of electricity caused by extreme fluctuations 

in price of oil. 

Disagrees with assertions that imply the HCCP is an outdated coal plant or that 

investments in other available alternatives would be better for GVEA members. 

HCCP won't solve our energy crisis but is part of a larger energy plan. 

To stand in the way of reasonable efforts to alleviate this burden would be 

criminal. 

It is a travesty that it is not already operating in these days of extremely high oil 

and natural gas prices. 

Allowing the plant to resume operations will help to stabilize and lower the cost 

of electricity, create a number of new, good‐paying jobs, demonstrate 

technologies which may be replicable across Alaska and the nation, and help 

Interior Alaska build expertise which may be likewise marketable across the state 

and nation. 

Starting HCCP up (clean coal) is good for Alaska, the country and potentially the 

world. 

Alaska must maintain and further develop a diverse energy base to ensure cost 

stability and energy security. Electrical power, however generated, will be crucial 

for the future development of Alaska. Accessibility to power makes other mining 

ventures and other businesses possible. This will become increasingly important 

as Alaska’s petroleum industry declines. Local coal is a more secure fuel source 

that something that has to be transported longer distances. 

If we are to prosper, we need to pursue all feasible avenues to obtain inexpensive 

energy. The HCCP is a facility that can help provide some of that capacity while 

at the same time reducing the overall pollution generated by GVEA through 

reducing demand on other facilities that are less environmentally friendly. 
Golden Valley Electric Association Response to Comments 

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HCCP will provide added security for the power requirements of Interior Alaska 

during the winter when failures of some segment of the power generation system 

or the electrical grid can leave families and businesses in grave danger. 

Investments Made in HCCP

HCCP was constructed using hundreds of millions of dollars of federal and state 

money; however to date, Interior Alaska has not received the benefit from this 

public spending. 

To withhold the permit renewal will cause harm to the State and waste the 

money already invested in this plant. 

Residents were promised this additional energy. GVEA's members and the other 

government entities, who have all invested hundreds of millions of dollars to 

build HCCP, need to see a tangible return on their investment. 

The power plant, environmental controls, nearby fuel supply, and operator are all 

ready. Legal challenges since the 1990's have been resolved. 

Response from ADEC: 

Power Cost

The Department fully appreciates the importance of stable lower cost power to Alaskans living 

and working in the Interior. The Department must use specific criteria for permitting which 

comply with state and federal air pollution laws. 

Role of HCCP in Reducing Costs, Creating Jobs, and Providing Security

Since these issues are not within the scope of operating permit review criteria, the Department 

has not verified any of the projections regarding the effect of HCCP on utility rates. Therefore, 

in issuing this permit, the Department is also not making any finding on the effect that operation 

of HCCP will have on jobs or energy security. 

Investments Made in HCCP

The Department can consider the investments made in HCCP to decide on issuing this permit 

only to the extent that they relate to PSD permitting criteria, as discussed under Comment 7. 

Other Power Options 

Hydro-electric energy is years away. 

Natural gas [for the City of North Pole] is still an unknown number of years away. 

I represent Rural Interior Villages - places where the cost of energy far exceeds what the 

bureaucrats in Washington, DC can even imagine. Alaska must be able to use our 
Golden Valley Electric Association Response to Comments 

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resources for the good of our citizens. We have oil, coal, natural gas, hydro power and in 

some places, even solar power. We don't have it all in every region. Where we have an 

abundance of water, we use it to offset the high cost of diesel fuel, as in Southeast 

Alaska. Where we have an abundance of coal, it should be used similarly. 

I attended a presentation through UAF as part of an energy alternatives symposium a year 

or so ago. A graph was presented addressing various energy options. Working hard to 

incorporate "social costs" they managed to make "greener" options ie: wind, solar, hydro, 

almost as cost effective as the Healy Clean Coal plant. The major difference was that the 

benefits for coal were shown in 2 colors, representing infrastructure and employment. 

Their more socially acceptable alternatives traded Alaskan jobs for a third color 

representing societal benefits. As the group leader was assuming the listeners agreed on 

their pet "green" alternative I spoke out in favor of the coal plant option. I continue to 

feel it is our best option for Alaskans. 

We're using up our precious gas reserves when we should be using plentiful coal. 

Our energy needs have to be met in diversified ways. Gas, oil, wind, geothermal, 

biomass, and coal. 

After reviewing the proposals for alternate energy sources including the Susitna 

hydroelectric project, and gas pipeline, and liquid natural gas, and wind power and 

geothermal power, and tidal energy, and solar panels, nuclear power, et. al.; the studies I 

have reviewed still have an energy shortfall that is only practicably filled with coal 

energy. 

I disagree with assertions that investments in other available alternatives would cause less 

aggregate environmental impact in light of the fact that the HCCP is already in existence 

and has been operated according to the conditions of the permit. 

I support reasonable energy conservation efforts as an alternative to increasing electricity 

generating capacity, but the practical steps that can be taken to reduce electrical power 

consumption will be insufficient to avoid the need for the electricity that will be 

generated by this facility. We should not view bringing the HCCP back on line and 

energy conservation as mutually exclusive strategies. We should pursue them both. 

GVEA could cut back on the burning of expensive fuel oil to the tune of 25 million 

gallons per year according to an article on the GVEA website by Brian Newton. 

Coal-fired electricity seems less risky than nuclear power. 

I continue to be impressed by GVEA's steps to try to reduce our electric rates while 

taking steps to safeguard our environment. Eva Creek Wind is a major positive step in 

this direction. Anything we can do to reduce our reliance on ..oil.., to generate electricity 

is a good thing. 
Golden Valley Electric Association Response to Comments 

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Response from ADEC: 

Each energy alternative has both direct and indirect costs and benefits associated with it. 

However, the Department's review authority does not extend to choosing between one project 

and another - for example, evaluating the relative benefits of a plant in one location using local 

coal, to an oil fired plant in another, to wind turbines in another location where wind resources 

are available. 

Coal Resources 

HCCP was designed to burn low-grade coal that is currently being removed at the area 

mine to access higher-grade coal required by other coal consumers in Alaska. Having 

HCCP sit dormant is a waste of these coal resources. 

Significant infrastructure, including a coal mine in the proximity, the existing power 

plant, and distribution lines is already in place. This project is ready to move forward 

with no additional environmental impact. 

Response from ADEC: 

The Department's air permitting authority does not extend to favoring a particular project 

because coal resources are locally available. 

Comments Suggesting Reasons for Delay in HCCP Startup 

What is disconcerting is that those with an extreme anti-coal agenda can hold our 

communities hostage, while not providing any significant relief to us from their 

organizations. The environmental community, through Trustees for Alaska, agreed, in 

writing, at the issuance of the original permit not to launch further challenges to operation 

of the plant under the terms of that permit; those promises should be honored. 

There are some within the environmental community who just don't want to see the plant 

in operation. We are being put in a terrible circumstance in the Fairbanks/North Pole 

area with costs rising and EPA requirements clamping down. 

I ... have grave concerns about high officials in the EPA and our President who have 

embraced very questionable conclusions about Carbon Dioxide from Coal-fired power 

plants and stated that all such plants should be shut down. The current administration 

seems bent on regulating capitalism into extinction. I urge you to resist this federal 

pressure and stand up for our 10th Amendment State rights to regulate our own business. 

There have been numerous studies regarding the plant and there is nothing other than 

emotion over the use of coal as a fuel that has caused the delay in the plant's startup. 

It was internal legal challenges that held up the project - not its viability. 
Golden Valley Electric Association Response to Comments 

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We must work together and show the country that government is flexible and not 

wasteful if this plant is not started it’s another black eye for government that swing’s in 

the wind of what political party that is in charge and not what makes sense for the people 

it serves. Please issue this permit for the 100,000+ people and businesses that are being 

hung out their due to bad decisions of past CEO’s of GVEA. 

I'm surprised that a coal plant, with a nearby Alaska-sourced fuel source isn't getting 

used, especially with consideration of the following: 

 The fallout from the CRU scandal. 

 The rate at which other countries (China in particular) are presently expanding 

their coal-fired generation. 

 The lull in the economy. 

Response from ADEC: 

The above comments do not relate to the ability of the Department to issue or deny this 

permit. 

The Department is not a party to statements made by third parties. There have been 

ongoing negotiations between some members of the environmental community and 

GVEA. The Department is not a party in those negotiations. The Department is 

proposing this permit rather than continuing to await agreement between those parties. 

The Department is unaware of any action or intent by the federal government to the effect 

that all coal fired power plants should be shut down. 

The delay in permitting operating HCCP since 1999 has numerous causes. The 

Department finds it inappropriate to apportion blame or responsibility, but is taking 

reasonable steps to permit it's operation. 

2. GENERAL COMMENTS IN SUPPORT - ENVIRONMENTAL AND REGULATORY 

ISSUES 

Statements by many of the commentators listed under Comment 1 included the following 

comments which do deal with environmental and regulatory issues, buy do not address permit 

conditions or the authority the Department must use in issuing or denying the air quality permit. 

Plant Emissions and Area-wide Air Quality

We have access to the newest technologies to make this operation environmentally sound 

and a boon to the economic wellbeing of our community. 

HCCP has the ability to be one of the cleanest burning power plants in the State, and one 

of the cleanest coal fired power plants of its size in the country. It will likely be subject 
Golden Valley Electric Association Response to Comments 

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to even further emission requirements, given the regulatory requirements being 

developed by EPA. 

The plant is designed to burn the fuel close at hand cleanly. 

The HCCP is a total coal combustion system that addresses all objections to coal 

combustion except carbon emissions and the state of the science is that carbon is unlikely 

a significant climate driver anyway. The HCCP should be operated to complete the 

demonstration of a truly integrated approach to clean coal power generation. 

Fairbanks North Star Borough is facing issues with the non-attainment for PM-2.5, and 

the expectation of even a higher standard next year. Reducing the need to run generators 

within the borough will improve our air quality and help us attain the PM 2.5 pollution 

standards. If HCCP is even partially successful, immediate effects would not only be 

economic but would contribute to the health of all the residents of the Interior. 

In desperation, many have turned to wood burning: an act which might be 

environmentally laudable but, as seen in its negative impacts to the Community’s PM2.5 

compliance and, frankly, neighbor relations, can also be problematic. In a real sense, the 

rise in both the cost of oil and oil price volatility are forcing many of our residents – too 

many – to choose between financial survival and their healthful well‐being. 

For minimal impact on the environment, distribution of power via an electrical grid that 

serves the state over its vast geographical expanse seems the most reasonable plan. In that 

context, the Healy Clean Coal Power Plant is a viable source of power that overall will 

reduce pollutants from carbon sources and reduce energy costs. Using the cleanest coal 

from Usibelli Mine, I believe, will produce cleaner air with fewer contaminants than most 

existing coal plants in the States. 

With a reduction of costs, I’m sure people in the Fairbanks and North Pole areas will 

reduce the amount of wood they burn to heat their homes. This pollution truly is the 

worst I’ve seen in all of my 55 years plus as an Alaskan residence. 

Ash

HCCP produces a glass like ash product which effectively encapsulates the trace metals 

in the ash. The ash is totally benign, addressing objections to disposal of conventional 

coal ash products, and can be used in many beneficial ways. 

Greenhouse Gas Emissions 

I recognize that the startup of HCCP will increase the CO2 entering the atmosphere; 

however, any potential detriment resulting from the miniscule increase in the 

atmosphere's CO2 levels stemming from HCCP will be more than offset by the economic 

benefits afforded Interior Alaskans. 
Golden Valley Electric Association Response to Comments 

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One commentator quoted President Obama: "Rapid commercial development and 

deployment of clean coal technologies, particularly carbon capture and storage, will help 

position the United States as a leader in the global clean energy race."

Response from ADEC: 

Plant Emissions and Area-wide Air Quality

To operate cleanly, HCCP will be required to meet the standards incorporated in the Title V 

permit. 

The Department recognizes that there are potential air quality benefits to the Fairbanks and 

North Pole areas from generating power farther from the population centers. The Department 

does not have information on how many people in Fairbanks have the ability to heat with 

electricity, or would choose to if HCCP is built. So the Department cannot project whether 

operating HCCP would significantly reduce wood smoke impacts during the winter months. 

Moreover, this permit is not linked to any regional air quality plan in a way that could affect the 

Department's decision on this permit. 

Ash

The Air Permits Program has not analyzed the properties of HCCP fly or bottom ash. The 

Department's solid waste program does have the responsibility for safe ash disposal. 

Greenhouse Gas Emissions

In issuing this permit the Department will not evaluate the relative value of tradeoffs between 

greenhouse gas emissions and economic benefits because the maximum emission increase in 

greenhouse gas emissions do not exceed the threshold which would make them subject to PSD 

permitting. 

HCCP does incorporate clean coal technology, but it does not incorporate carbon capture or 

storage.

3. COMMENTS IN SUPPORT - PERMITTING AND EMISSIONS 

Many of the above commentators also made comments which were directed to the Department's 

regulatory authority. These comments included the following: 

Environmental Performance Standards

The plant met or exceeded all environmental performance standards during start up 

operations in 1998. 

Additional Regulatory Review

HCCP has already undergone an extensive regulatory and environmental review process, 

including an EIS that was conducted under NEPA. DEC has determined that no 

additional regulatory review is necessary prior to the HCCP restart. All criteria pollutants 

are controlled by the HCCP. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

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This permit renewal addresses only issues relevant to changes in DEC’s air regulatory 

program since the original permit was issued. 

This is a viable plant and should be grandfathered under older permits. 

To Strike Down the Project Wrong

To strike down this project based on arbitrary, political rule-changing (i.e. the permitting 

process) is simply wrong. 

Mercury

This second ADEC permitting action continues to require all current emission levels, plus 

the newer mercury levels. 

Lower Emissions

The HCCP has the technology to burn coal and make low cost electricity with emissions 

that reduce air quality impacts to a negligible level. Any claim to needing lower 

emissions is totally unreasonable. 

Response from ADEC: 

Environmental Performance Standards

During the demonstration phase, HCCP did meet emission standards most, but not 100% of the 

time. Violations occurred during shutdown and during change out of spray dryer absorber 

atomizers. 

 The Department does not find that the periods where the SO2 emission limit was not met 

provides a basis to deny the permit.more discussion 

Additional Regulatory Review

For discussion of additional regulatory review, please see Comment 7 on PSD applicability. 

The question of PSD applicability does not arise only from changes to the Department's 

regulatory program since the original permit was issued. It arises from whether HCCP needs 

such a permit under EPA PSD regulation and guidance. Much of the regulation and guidance is 

long standing. 

To Strike Down the Project Wrong

If the Department had found that additional PSD permitting was necessary, it would not have 

struck down the project. It would, however, have required additional permitting work based on 

established rules that would have delayed the project, and may or may not have found that 

additional emission control was necessary. 

Mercury

The applicable requirements included in the proposed permit do not include emission limitations 

for greenhouse gasses or mercury. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

17 

Lower Emissions

HCCP needs to maintain consistent compliance with emission standards. 

If PSD were required, GVEA would need to show whether additional control were technically 

and economically feasible. The economic feasibility analysis could include the effect on 

ratepayers. 

The Memorandum of Agreement (MOA) between GVEA and the National Park Service, which 

formed part of the original basis for preconstruction permitting, deals in part with GVEA's 

commitment to decrease emission limits based on emission levels achieved during the 

demonstration phase. Please see Comment 8 for the discussion of the MOA.

4. TECHNICAL COMMENTS FROM GVEA 

From: Kristen DuBois, Environmental Officer 

 Golden Valley Electric Association Inc. (GVEA) would like to take this opportunity to submit 

brief comments to the Alaska Department of Environmental Conservation (ADEC) on the draft 

revised renewal permit for the Healy Power Plant Title V Air Quality Operating Permit No. 

AQ0173TVP02). 

1. Condition 15.1.d -The EU identifier is missing from the modified condition. Please correct to 

state: Use AP-42 emission factors, along with the hours of operation and/or amount of fuel 

used to calculate the emissions of CO for EU 10 4, and continuous emission monitor to 

determine emissions from EU ID 2. 

2. Statement of Basis, Page 5, Greenhouse Gas Prevention of Significant Deterioration (GHG 

PSD) applicability discussion: We believe methane should be included in ADEC's PSD 

applicability determination calculation. Both AP-42 and the GHG Reporting Rule (40 CFR 

98 Subpart C Table C-2) provide emission factors for C02, methane and nitrous oxide. 

Attached are two sets of calculations for ADEC to consider. The first calculation uses AP-42 

factors, the second uses 40 CFR 98 emission factors. Regardless of method, the increase in 

C02e emissions from an annual coal consumption change of 34,465 tons/yr still results in an 

emission increase well below the significance threshold of 75,000 tons/yr. 

3. Statement of Basis, Appendix C, page 26, item 7 -Greenhouse Gases, second paragraph: 

please correct HCCP BAE at 41.1 tons per day to tons per hour. 

[The comments included an attachment showing equipment ratings, emission factors, and the 

results of their greenhouse gas calculations.] 

Response from ADEC: 

1. The Department made the appropriate correction to Condition 15.1d. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

18 

2. The Department agrees with the comment and has verified the calculation method for the 

greenhouse gas increase which the commentator provided, including CO2, methane, and N2O for 

a total of 53,474 tons per year CO2e. 

3. The Department has made the minor correction to Appendix C, and has also clarified that all 

three greenhouse gasses are in included. 

5. GENERAL COMMENTS IN OPPOSITION TO PROPOSED PERMIT. 

The following comments oppose the renewal permit without addressing specific permit 

conditions or regulatory authority for making a decision. 

 

From: Carter Crawford 

I agree we must reduce our carbon print and seek alternative energies to both improve air 

quality and reduce energy costs. 

We can do that and rely on diesel and oil only. 

But I find the state in a difficult position. It wants to sell HCCP but your Department is 

no doubt receiving pressure from the administration while charged with being absolutely 

objective about environmental conservation. 

HCCP did not prove to be the solution approximately 15 years ago and we have no 

evidence this aged plant can today. Multiple efforts by the state proved unsuccessful and 

nothing has changed. Coal by its very nature is not clean. It is an improvement over 

diesel and oil, but it cannot begin to compare to solar and wind. And this plant by no 

means provided consistent energy either. 

GVEA has just committed almost,and probably actually $100 Million to build the Eva 

Creek Wind Farm for the Interior. If they need to produce more clean energy before Eva 

is ready, they can buy wind power from the Delta Wind Farm, guaranteed clean, 

operating turbines today in several communities, and a guaranteed reduction in diesel and 

oil. And GVEA can give the Interior electricity without multimillion investments since 

Delta is privately funded. 

I do not like the risks and potential additional costs than HCCP will surely have. 

Response from ADEC: 

None of the comments directly relate to the criteria the Department must use to make this 

decision. The Department's operating permit authority does not extend to choosing between one 

project and another - for example, evaluating the relative benefits of a coal plant in one location 

to an oil fired plant in another to wind turbines in another location where wind resources are 

available. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

19 

6. LOCAL AIR QUALITY AND REGIONAL HAZE 

From: Nancy Bale, Director, Denali Citizens Council 

Local air quality should be a consideration in this permit

Because the Denali Borough has no role in regulating local air quality, there is no legal 

framework, at present, for monitoring particulate matter and other pollutants in the air around 

Healy. The community deserves a commitment by the state and the developer to improving its 

near-ground air quality. This could be done, as an amendment to this permit, in two ways: 

1. ADEC, for its part, should commit to ongoing monitoring for particulates and key coal-based 

pollutants not only at the plant but in the local community, and should take a more proactive role 

in protecting the overall air quality in an area, where cheap coal contributes to its unregulated use 

in home heaters. Currently, the availability of inexpensive coal leads to periods of extremely 

poor air quality in Healy during winter. 

2. GVEA, partnering with Usibelli Coal Mine, Inc., should conduct public education projects 

and installation incentive programs to assist locals in the cleanup of local air by burning it 

more efficiently in better heaters. 

The regional haze state implementation plan (SIP) provides important confirmation that starting 

Healy 2, after all these years of shut-down, will create a point source of significantly increased 

pollution in Alaska’s Interior

 "These forecasts do not account for the emissions from the HCCP at the GVEA facility in 

Healy (i.e., unit # 2). That facility did not operate in 2002 and is not currently operating, but is 

permitted to operate. If brought on line, the point source NOX emitted within the Denali Borough 

would increase by a factor of 4.0 and the SOx would increase by a factor of 2.8 (based on 

permitted not actual emissions). This increase would make the Denali Borough the largest source 

of anthropogenic emissions and the second largest source of all emissions impacting Denali 

monitors." (III.K.7-16, III.K.9-35, III.K.9-40, weighted emission potential-WEP-by borough) 

While reasonable people may disagree regarding the air quality impacts from re-opening Healy 

2, it is certain that impacts will occur, and the state of Alaska would do well to ensure that they 

are minimal. The companies that most benefit from the issuance of this permit should recognize 

their financial and ethical obligation to the local community in reducing the impacts of coal 

burning, and improving the quality of local air and regional air. Please take seriously the 

suggestions above.

Response from ADEC: 

The Department does not have a regulatory basis to require the community improvement 

projects the commentator requests as part of an operating permit. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

20 

The operating permit does include all applicable requirements from the original PSD permit. 

Ambient analysis for that permit were sufficient for the Department to find that ambient air 

standards and increments and air quality related values would be protected from plant 

emissions. 

Further, as part of the effort to get HCCP permitted, GVEA agreed to reduce emissions from 

Unit 1 so that emissions from both units combined would be less than the original emissions 

from Unit 1 alone. 

The Department is not able to establish ambient monitoring requirements through a Title V 

operating permit. Ambient monitoring was required by the Title I permit for HCCP. Monitoring 

was conducted for several years, including during the 90 day test, and has been completed as 

required 

7. PSD APPLICABILITY 

From: Nancy Bale, Director, Denali Citizens Council 

PSD Comments from Denali Citizens Council 

The Denali Citizens Council, a local non-profit education and community advocacy 

organization, has been involved in the decision process around this plant since the early 1990s. 

We are not in complete opposition to the Healy 2 coal-fired power plant, despite its obvious 

negative contributions to air quality and carbon pollution world-wide. Instead, we support the 

most up-to-date and inclusive permitting, taking into account more modern notions of what 

constitutes pollution, including more newly recognized pollutants such as carbon and mercury. 

The PSD process would have been ideal for reviewing the technology and determining its 

efficacy in addressing current standards. We are disappointed that a complete review under PSD 

has not been conducted. 

There are retrofit technology options now available to GVEA that surpass designs used in the 

original clean coal plant. GVEA should be required to consider and install such options in order 

to satisfy Clean Air Act mandates for new plants. I can tell you unequivocally that GVEA closed 

Healy 2 and it has been closed for 11 years. GVEA indicated that they had no intention of 

running this plant and described it as unworkable. Such closure is, to our way of thinking, an 

automatic PSD trigger. We have signed on to more detailed comments on this issue elsewhere, 

and we intend to maintain our place at the table as a local organization concerned with the air 

quality in Healy and in the wider region, which includes the Class 1 Airshed of Denali National 

Park. 

It is patently clear to us that putting Healy 2 into operation will cause an increase in total 

emissions for the area around Healy. As such, GVEA takes on the responsibility of legally and 

appropriately reducing those emissions with the most up-to-date equipment. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

21 

Response from ADEC: 

Please see the response to the Comments from Trustees for Alaska, below.

From: John Bunyak, Chief, Policy, Planning and Permit Review Branch, National Park 

Service 

PSD Comments from National Park Service 

The NPS has been involved in subsequent discussions between GVEA, the Sierra Club, the 

Trustees for Alaska, the Environmental Protection Agency (Region 10) and ADEC regarding the 

HCCP restart. These discussions were initiated due primarily to concerns raised by the involved 

parties during the 2009 public comment period for the draft Title V permit. Notably, ADEC 

concluded that PSD does not apply to the restart of the HCCP. Given disagreements over this 

issue, parties began an "outcomes" driven negotiation that focused on environmental protection 

measures GVEA could implement that would satisfy stakeholder concerns in the absence of an 

agreement on whether the PSD process would achieve those same outcomes. We are aware that 

GVEA has provided a settlement proposal to the Sierra Club and the Trustees for Alaska 

regarding the HCCP restart. In this July 8, 2011, proposal, which was submitted to the NPS via 

email by Kate Lamal, vice president of GVEA, the electric association offers to: 

1. Install a selective catalyst reduction (SCR) technology system to control emissions of 

nitrogen oxides (NOX) from HCCP prior to start up. 

2. Install mercury emission controls on HCCP prior to start up. 

3. Reduce its reliance on coal and oil-fired systems and replace them with renewable 

energy sources. Specifically, GVEA would commit to construction the 25 MW Eva 

Creek wind farm by December 31, 2014; a shutdown of Unit 1 no later than December 

31, 2024, and a conditional shutdown of HCCP 30 years after its startup. 

While the NPS is not a current party to this proposal, we have been involved in various 

discussions, because it relates specifically to many NPS concerns over reactivation of HCCP. 

The specific details of any agreement would need to be identified prior to final NPS evaluation, 

but we believe that the installation of SCR post-combustion controls (with a corresponding 

emission limit) and installation of mercury emission controls at HCCP would address many of 

our previous concerns. SCR represents top-of-the-line NOX controls that would need to be 

addressed in a top-down Best Available Control Technology (BACT) analysis if the source were 

required to obtain a PSD permit prior to restart. Additionally, it is anticipated that the NOX

reductions achieved under the installation of SCR would exceed the permitted NOX emission 

limit reductions achieved under implementation of permit condition 25. Therefore, we commend 

the proposal to install SCR on HCCP (with a "BACT-like" enforceable emission limit) prior to 

startup, and encourage GVEA to continue pursuing this option. However, to fully satisfy NPS 

concerns, any final agreement between parties would need to be reflected in the permit and the 

permitted emission limitations, as was specified in our 1993 MOA. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

22 

Installing mercury controls prior to federal requirements imposed under the proposed Toxics 

Rule and the associated Utility Maximum Achievable Control Technology (MACT) standards 

for mercury may also address NPS concerns related to mercury. Again, we commend the 

proposal and encourage GVEA to continue pursuing this option. However, to fully address the 

concern, we believe the agreement should specify the type of control technology to be installed, 

anticipated control efficiencies and a commitment to continuously operate the technology and 

monitor effluent mercury emissions. Again, specific information identified in the agreement 

should be reflected in the associated permits. 

The proposal also identifies a shutdown date for Healy Unit 1. The date referenced in the 

settlement proposal, December 31, 2024, reflects the date identified in the BART proposal for 

Unit 1 and referenced in Alaska's Regional Haze State Implementation Plan (RH SIP). This time 

period was used when considering the remaining useful life of the facility in assessing the cost of 

various BART control options. The NPS remains convinced that the final BART determination 

for Unit 1 must include an enforceable shutdown date in the Alaska RH SIP. This commitment 

should be made regardless of any agreement reached through the current negotiations, as it 

pertains to the BART requirements for this source. Additionally, ADEC concluded in its RH SIP 

that in light of the remaining useful life of the facility, Selective Non-Catalytic Reduction 

(SNCR) technology represents BART for Unit 1; however, the settlement proposal is silent 

regarding this requirement. It is assumed that GVEA will comply with ADEC's BART decision 

to install SNCR on Unit 1. 

In all, the NPS would be pleased to see several of these options pursued, as it will alleviate many 

of our concerns with the reactivation of HCCP. However, the Title V permit has been revised 

and re-issued for public comment prior to the parties reaching a negotiated agreement. In the 

absence of such an agreement, the NPS is commenting on the draft permit as written. 

Accordingly, most of our previous concerns have been reiterated below. 

The restart of HCCP is complex in terms of determining PSD applicability requirements. In 

Appendix C to its Statement of Basis, ADEC provided a revised PSD Applicability 

determination for the restart of HCCP. The April 26, 2011, re-evaluation relies on an alternative 

analysis approach and provides additional supporting documentation, but ultimately arrives at the 

same conclusion as the October 12, 2009, analysis; i.e., PSD does not apply to the HCCP restart. 

In the new analysis, ADEC highlights the unique factors that differentiate the Healy restart from 

other similar cases; however, it appears the analysis continues to depart from long-standing EPA 

reactivation policy in several areas. 

We recognize that there are circumstances unique to the restart of the HCCP facility. However, 

there are also a significant number of similarities between the HCCP case and other reactivation 

policy determinations. These nuanced and extenuating details highlight the necessity for EPA to 

traditionally make these determinations on a case-by-case basis. EPA expressed concerns 

regarding ADEC's 2009 analysis. We have not seen EPA's response to this most recent analysis; 

however, we understand that the issue has not been fully resolved. As expressed in our 

December 4, 2009, comments, we believe this issue warrants additional discussion, and 

ultimately, resolution between ADEC, EPA and potentially GVEA. We again stress this in light 

of NPS's "affirmative responsibility" to protect Air Quality Related Values (AQRVs) in DNPP. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

23 

PSD is one process that allows the NPS to meet our responsibility to protect AQRVs, as it may 

result in more stringent emission controls or other mitigation to protect AQRVs in DNPP. 

However, as expressed previously, we believe a negotiated agreement to install additional 

controls at HCCP outside of the PSD process may achieve a similar outcome. Considering the 

high public and tourism value of Alaska's only Class I national park, we strongly urge ADEC 

and EPA to err on the side of protecting AQRVs when resolving this issue. 

Response from ADEC: 

Because the Department has an approved program, it is the Department's responsibility to make 

the determination. We understand that EPA has the ability to reverse the Department's decision. 

The Department has met with EPA to attempt to reach resolution. However, given that EPA has 

not conveyed a finding to the Department, the Department is sending the proposed permit to 

EPA for their review in the interest of keeping the process moving. 

The Department is also not currently a party to the third party negotiations referred to in the 

comment. The Department has gone ahead with the new comment period because the parties 

involved have not reached agreement. 

From: Brian Litmans, Staff Attorney, Trustees for Alaska; Sanjay Narayan, Sierra Club 

Environmental Law Program 

PSD Comments from Trustees for Alaska 

Comments submitted by Trustees for Alaska on behalf of the Northern Alaska Environmental 

Center, Denali Citizens Council, National Parks Conservation Association, Alaska Community 

Action on Toxics and the Sierra Club

We previously corresponded with ADEC regarding this proposed renewal (in a letter to Debra 

Dalcher dated December 9, 2009). That letter referred to an earlier letter to Brian Newton, Chief 

Executive Officer, Golden Valley Electric Assoc., Inc. (April 29, 2009). Those two letters, which 

focused, in part, on whether the restart of Healy Power Plant Unit 2 (hereinafter Unit 2) will trigger 

Prevention of Significant Deterioration (“PSD”) applicability, are incorporated by reference. 

We have now carefully studied ADEC’s revised preliminary decision to issue the permit, including 

the Statement of Basis dated July 26, 2011, and in particular, Appendix C to that Statement of Basis. 

As discussed below, our review shows that ADEC has made some clearly erroneous factual findings 

and a number of errors of law in order to conclude that the restart of Unit 2 does not require a PSD 

permit. When these errors are corrected, the inevitable conclusion is that Unit 2 cannot be restarted 

without obtaining a PSD permit. 

Reactivation Policy

Unit 2 Must Be Considered a New Source Under EPA’s Reactivation Policy. 

In Appendix C, ADEC correctly notes that: “reactivation of a major stationary source that 

has been permanently shut down, will be treated as construction of a new stationary 

source for PSD review.” ADEC then walks through some of the factors used by EPA in 

its Reactivation Policy as part of its analysis. Appendix C, however, does not discuss a 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

24 

critical aspect of the Reactivation Policy, which is discussed in the Monroe Electric 

Order.1 In that Order, EPA notes the following: 

EPA believes owners and operators of shutdown facilities must continuously 

demonstrate concrete plans to restart the facility sometime in the reasonably 

foreseeable future. If they cannot make such a demonstration, it suggests that for 

at least some period of the shutdown, the shutdown was intended to be permanent. 

Once it is found that an owner or operator has no real plan to restart a particular 

facility, such owner or operator cannot overcome this suggestion that the 

shutdown was intended to be permanent by later pointing to the most recent 

efforts to reopen the facility. . . . This approach for assessing the intent of the 

owner or operator is consistent with the general notion that a company cannot sit 

indefinitely on a governmental permission to emit air pollution without showing 

some definite intention to use it. 

Id. at pp. 9-10 & n. 11 (emphasis added). 

Review of the record in this matter unequivocally shows that at times since 1999, the 

owners and operators of Unit 2 intended to shut down the facility permanently. First, an 

independent audit of the 90-day test conducted in 1998 and 1999 concluded that if Unit 2 

were operated on design coal, “in its present configuration [it] will not perform 

acceptably for 30 years, even if operated and maintained in accordance with standard 

utility practices.”2 By the end of 1999, AIDEA had spent all of the project funds 

(including the retrofit budget), yet Unit 2 still required millions of dollars worth of work.3

In one document, GVEA described the facility as “shuttered,” id., and in 2003, GVEA 

referred to the facility as “mothballed.”4

In 2006, AIDEA retained Shaw, Stone & Webster to evaluate what it would take to 

restart the facility. Shaw personnel started visiting the site that year. An April 16, 2008 

trip report filed by Gene Scott of Shaw observed that the areas inside of the facility: “are 

cluttered with materials, spare parts, tools, equipment work tables, debris, empty pallets; 

etc, and the ash loading facility and intake structure are being used for storage of heavy 

equipment and emergency vehicles. It will take considerable time and effort to sort 

through all the materials and determine ownership and proper storage of anything 

salvageable.” References to “salvag[ing]” parts fails to meet the Monroe requirement of 

“continuously demonstrate[ing] concrete plans to restart the facility sometime in the 

 

1 Order Responding to Petitioner’s Request... Carol Browner, EPA Administrator. In the Matter of 

Monroe Electric Generating Plant Entergy Louisiana, Inc. Proposed Operating Permit. Petition No. 6-99- 

2. 

2

 1299 Harris Group Inc., Independent Engineer’s Review of HCCP 90 Day Test and 

Determination of Sustained Operations, December 1999 (“12/99 Harris Group”), available at: 

http://www.netl.doe.gov/technologies/coalpower/cctc/cctdp/bibliography/demonstration/pdfs/healy/90544R 

10.pdf (Attachment 1). 3

 GVEA, Narrative Statement of Facts, available at 

http://www.gvea.com/about/hccp/HCCP_Statement_Facts.pdf , at ¶ 31 (Attachment 2). 4

 GVEA, Improving on a Classic, 2003 Annual Report, 

http://www.gvea.com/about/annualreport/2003annrep.php (Attachment 3). 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

25 

reasonably foreseeable future.”5 Accompanying photographs further demonstrate that the 

facility was not in “hot standby” in 2006.6

Given these observations and the facts pointed out in our April 29, 2009 letter to 

Brian Newton, one can only conclude that during the last decade, there were certainly 

periods when no real plan existed to restart Unit 2. Consequently, restart of the facility 

now must be considered the construction of a new source for PSD purposes. 

Response from ADEC: 

Reactivation Policy.

While it is true that AIDEA's plan to get HCCP running changed as circumstances changed, the 

Department believes that it is beyond question that AIDEA never stopped trying to get that result 

at the earliest possible date. AIDEA used cooperative agreements with GVEA, lawsuit, and the 

attempt to bring in another operator -- essentially, whatever it takes to get it going. Please see 

the chronology of events in the Statement of Basis, Appendix B. 

For a period of time, it was prudent for AIDEA to stop providing more money for the project 

while they attempted to resolve their dispute with GVEA. 

This is a very different circumstance from a plant that has operated for years, recovered its 

initial investment and has become obsolete or has worn out, and the owner needs to decide 

whether to rejuvenate it. The suggestion that AIDEA ever intended to simply walk away from 

their very substantial investment without seeing benefits from it, especially considering their 

persistent efforts to see it operate, is not credible. 

Major Modification - Routine Maintenance

Unit 2’s Restart Would Be a Major Modification. 

A. The Physical and Operational Changes Necessary to Make Unit 2 Operational Again 

Would Not Be Routine Maintenance. 

ADEC’s finding that the physical and operational changes necessary to make Unit 2 

capable of long-term operation is incorrect. Part of the problem is that although ADEC 

properly recites the five WEPCO factors cited by EPA in making case-by-case routine 

maintenance evaluations, ADEC fails to focus on a fundamental aspect relating to such 

evaluations, and that is that only de minimis activity can qualify for the exemption. As 

EPA recently put it in responding to a Title V petition: 

Importantly, in undertaking the RMRR [“routine maintenance, repair, and 

replacement”] analysis, it is critical not to focus inappropriately on any one factor 

 

5 See infra Footnote 1 at pp. 9-10 & n. 11 (emphasis added). 6

 Trip Report filed by Gene Scott, Shaw Power Group, April 16, 2008, Re: HCCP Construction 

Site Visit Report (Attachment 4). 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

26 

such that the fundamental purpose of the narrow exclusion is forgotten. In New 

York II. 443 F.3d at 883-84, the D.C. Circuit Court underscored that, “EPA has 

for over two decades defined the [routine maintenance] exclusion as limited to ‘de 

minimis circumstances.’” 

In the Matter of Tennessee Valley Authority, Paradise Fossil Fuel Plant Drakesboro, 

Kentucky Title V Air Quality Permit # V-07-018 RI , Petition No. IV-2010-1 (U.S. E.P.A. 

May 2, 2011) (Attachment 8). 

A thorough examination of the facts here shows that all of the activity to bring Unit 2 back to 

life after a decade of inactivity can neither be considered de minimis nor routine. 

First, ADEC should take a hard look at GVEA’s cost assertions, over which there are serious 

questions. In June 2008, AIDEA’s startup engineers estimated it would take 19 months to 

startup HCCP at a cost of $62 million,7 or about a quarter of the original cost of the plant. 

The GVEA assumed ownership of the shuttered HCCP in January 2009 and is proposing 

to start up the facility. In February 2009, GVEA advised its members that startup would 

take 18 to 24 months and that AIDEA would loan GVEA up to $45 million “to fix known 

deficiencies, to startup up the plant...”8 In contrast, in May 2009, when GVEA petitioned 

the ADEC to determine that it did not have to go through PSD review again,9 GVEA’s 

petition and revisions thereto identified 105 separate activities that had to be completed to 

startup Unit 2, costing a total of $16.2 million (“Project List).10 This Project List excludes 

many of the activities that AIDEA’s startup engineers concluded were required to startup 

and successfully operate Unit 2 in June 2008. Costs for many individual activities 

reported to ADEC are substantially lower than the costs estimated by AIDEA’s 

engineers. Indeed, the total cost to startup Unit 2 reported to ADEC, $16.2 million, is 

nearly four times lower than that estimated by AIDEA’s startup engineers.11

Furthermore, a close examination of the Project List shows that much of the activity here 

is not maintenance at all. In the 90’s, this plant was brought to the point where it could 

produce power, but it was never put into a state where it could do so on a continuing, 

long-term basis. Many of the physical alterations now proposed are essential to complete 

construction. 

It must be remembered that in the late 90’s, the project ran out of money. As a 

consequence, the facility, as it was tested in 1998 and 1999, was considered to be unsafe 

 

7

 Shaw, Stone & Webster, HCCP Condition and Restart Study, HCCP/Unit 1 Independent 

Operations, Volume 1 of 2, March 28, 2006 (“3/28/06 Shaw Report”), Sec. 7.0 (Attachment 5); 10/14/08 Shaw 

Closeout Report, Section 10.0 Project Cost Estimate, Section 10.1 Capital Cost Estimate, Cost 

Estimate Summary, June 2008. 

8

 Letter from Bill Nordmark GVEA Board Chairman and Brian Newton, GVEA President & CEO, 

to GVEA Members, February 12, 2009. 

9

 Letter from Kristen DuBois, GVEA, to Alice Edwards and John Kuterback, ADEC, May 26, 

2009, Re: Request for Confirmation of PSD Non-Applicability (“5/26/09 DuBois Letter”). 10 Letter from Kristen DuBois, GVEA, to Sally Ryan, ADEC, August 17, 2009, Re: Response to 

ADEC Request for Further Analysis, August 17, 2009. 

11 12/18/08 Shaw Closeout Report, Section 10.0 Project Cost Estimate, Section 10.1 Capital Cost 

Estimate, Cost Estimate Summary, June 2008. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

27 

and uneconomical to operate. Things were patched together using riveted steel plates and 

unusual interventions that could not be sustained in the long run. During the 90-day test 

period, for example, rapid deterioration of equipment forced workers to weld and 

reinforce equipment while it was running.12 At other times, coal silos to the coal feeder 

plugged and “maintenance workers used sledge hammers throughout the night in an 

effort to keep the coal flowing.”13 Common operating practices during the 90-day test 

included patching leaking equipment with bolted steel plates, manual clearing of slag that 

appeared in places it was not supposed to be, manually cleaning screens that should not 

plug, and banging on hoppers and chutes to maintain coal flow.14 Further, during the first 

year of operation, Unit 2 tripped offline 78 times, unacceptable for a commercial 

facility.15 The results of the 90-day test were inconclusive as the test was performed with 

coal having a heating value slightly above the design specification, resulting in 23% less 

ash than design. Further, excess staffing was on site during the test to make real time 

repairs while the facility was operating. The excess staffing, equivalent to 15 full time 

maintenance people on a 40-hour week basis, did emergency work to the keep the facility 

running, tasks that would not be required in a commercial facility. These tasks included 

clinker breaking, atomizer replacement, pyrites hopper cleaning, repairing the head 

pulley on the ash bucket conveyor and silo discharge chute battering to clear plugging, 

and repairing the mill and surrounding equipment.16

An engineering assessment of the 90-day test run and plant equipment in December 1999 

prepared for GVEA concluded: “Overall, DE&S [Duke Engineering & Services] found 

during the 90-Day Test, the subsequent equipment inspections, the performance tests, and 

the turbine test, that [Unit 2] has several serious deficiencies. These deficiencies need to 

be resolved before [Unit 2] can operate reliably as a cost competitive power plant for 

extended periods of time.”17 Duke opined: 

[C]ertain systems and equipment failed to meet an acceptable level of reliability. 

The coal feed system has both reliability and safety concerns. The pulverizer 

explosion is an obvious example that additional instrumentation and/or controls 

work needs to be done to assure that a similar incident does not happen again. The 

reliability and safety of the existing pulverizer exhauster fans and the variable 

coal splitter is unsatisfactory. The 90-Day Test proved that these components will 

require frequent repair to stop pulverized coal leakage and are not capable of 

sustained operation in their current state.”18

Construction work to complete Unit 2 was discontinued at the end of 1999 after 

the initial 90-day test (8/17/99 – 11/15/99) and has not yet resumed, over a decade 

 

12 Narrative Statement of Facts, p. 13 (Attachment 2). 13 Duke Engineering & Services, 90-Day Test Run Systems Evaluation & Plant Assessment, 

Prepared for GVEA, December 1999 (“12/99 Duke Report”), p. 6-12 (Attachment 6). 14 12/99 Duke Report, pp. 6-24 to 6-24 (Attachment 6). 

15 Narrative Statement of Facts, pp. 5, 14. (Attachment 2). 16 AIDEA, Healy Clean Coal Project Performance and Economics Report, Final Report: Volume 2 

(April 2001, pp. 1-4 (hereinafter AIDEA 4/01) (Attachment 7); Harris Group 12/99, pdf 89-90 (excess 

staffing) (Attachment 1). 

17 12/99 Duke Report, p. 1-3 (Attachment 6). 

18 Id, p. 6-27. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

28 

later. In fact, the Long-Term Commercial Operation Demonstration beyond the 

initial 90-day, required by the DOE contract, was never performed.19 The patches 

made to get through the test phase were never made permanent. 

GVEA chronicles the history of this facility in its annual reports, posted on its website. In 

1998, the first year of attempted operation, GVEA wrote: 

Though HCCP generated power during 1998, the 54-megawatt plant was not 

commercially reliable or dispatchable and it is still not ready to provide 

competitively-priced electric power. GVEA has a number of significant 

unresolved issues relating to design, operating efficiency and safety with the 

owners of the project, Alaska Industrial Development and Export Authority 

(AIDEA).20

In its 1999 annual report, during experimental testing, GVEA wrote: 

HCCP began burning coal in 1998 and generated power intermittently through 

1999, but the nominal 50-megawatt plant was not commercially reliable and it 

produced very expensive power. Late in 1999, the plant failed to pass a 90-day 

operating test designed to test reliability and economics resulting in the automatic 

termination of the contract between AIDEA and GVEA. The plant was shut down 

on December 31, 1999 until new agreements can be made for the operation of the 

plant and for power sales.21

Many of the projects now proposed for restart thus involve either completing construction 

activity that was abandoned22 when the owners ran out of money or fixing major 

problems to allow the Unit to operate. Furthermore, the original facility was designed to 

test an experimental combustor, the TRW slagging bed combustor, and a new SO2 control 

technology, the Joy/Niro spray drier absorber. The focus of the work was to scale up a 

pilot version of the combustor, which necessarily involves a lot of trial and error. The 

numerous design errors and scaleup problems are catalogued in engineering studies.23The 

startup Project List includes many modifications to correct design errors, reduce 

maintenance costs, and improve safety so that HCPP can operate commercially. 

 

19 AIDEA 4/01, p. 4-3 (Attachment 7). 

20 GVEA 1998 Annual Report at http://www.gvea.com/about/annualreport/1998annrep.php. 21 GVEA 1999 Annual Report at 1, http://www.gvea.com/about/annualreport/1999annrep.php. 22 “As-built” drawings of the entire plant have never been found. Closeout Report , Section 3.1, 

Bid Package (Disc 1), Volume 2 – Tech Spec, Attachment A: Technical Specification for Design, Supply 

Installation and Startup of Indoor Systems for Healy Clean Coal Restart Project, October 23, 2008, p. 3 of 

364 (“Complete and accurate “As-Built” drawings of the entire plant are not available, therefore it is the 

Contractor’s responsibility to verify the accuracy of the existing plant drawings and documents including 

all Owner and Contractor supplied new designs prior to start of construction for all items of work related to 

the Contractor’s scope.”). “As-built” drawings are submitted by a contractor upon completion of a project. 

They reflect all changes made in the specifications and working drawings during the construction process 

and reflect actual existing condition as opposed to designs or proposed changes. They show the exact 

dimensions, geometry, and location of all elements of the work completed under the contract. The absence 

of a complete set of these drawings for HCCP is strong evidence that construction was never completed 

properly. 

23 See, e.g., 2/99 Duke Report; 12/99 Harris Report. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

29 

Addressing these “modifications” through “redesign” indicates that the type of work 

necessary to get the Unit up and running is not routine. Some of these are discussed 

below to illustrate the fact that what is now contemplated at the site cannot be considered 

routine maintenance. 

1. Access Platforms 

The facility tested in 1998-1999 was not designed for commercial operation because it 

excluded many features that would be required for safe routine operation, such as access 

platforms, walkways, heat tracing of piping and valves (critical given the local weather), 

and adequate ventilation. Similarly, piping blocked access required for routine 

maintenance. The access modifications include adding the following: 

 Task F.4.e: Precombustor access platform stairs, south end 

 Task F.6: Mill tensioners access platforms 

 Task F.7: Walkway from floor 3 to top of mills 

 Task F.8: Relocate air piping to resolve interferences around mills 

 Task G.4: Stairway to access boiler manway 

 Task Q.4: SDA access platform 

 Task Q.6: Walkway from upper DA platform to 6th floor 

 Task R.2: Heat trace ash piping and valves 

 Task AC.1: Battery room ventilation improvements 

 Task AD.1: Install CO2 monitor in Unit 2 relay room per regulations 

 Task AH.1 Reroute seal air piping that blocks pulverizer maintenance door 

 Task AL.1: Reroute deaerator overflow piping to improve efficiency 

 Task AP.1: Reroute sample lines to eliminate blocking ventilation hood door 

2. Tagging and Labeling 

During initial construction and startup, all equipment, piping systems, and valves are 

commonly labeled to facilitate operator training and safety. Tagging and labeling was not 

completed at Unit 2. Task AV.1 finishes this job for $80,000.24

3. Electrical Breakers 

Several plant electrical breakers may have been designed and/or installed with the wrong 

cable size. Task K.2 would confirm that suitable service is installed and replace as 

necessary.25

4. HCP Dry Ash Transfer System 

This system transfers dry ash between Unit 1 and Unit 2. “This system is part of the 

original design, but was never fully commissioned in 1998 and 1999.”26 Task V.1 would 

commission this system, evaluate its operability, and make repairs as necessary for 

$32,500.27 It is not clear whether repairs are included in the task cost. 

 

24 Project List, p. 11, Task AV.1. 

25 Project List, p. 5, Task K.2. 

26 Project List, p. 21, Task V.1 (emphasis added). 

27 Id.
Golden Valley Electric Association Response to Comments 

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30 

5. Unit #1 Wet Ash Transfer System 

This system transfers wet ash between Units 1 and 2. “This system is part of the original 

design, but was never fully commissioned in 1998 and 1999.”28 Task W.1 would evaluate 

the performance of this system and make repairs as necessary for $8,000.29 It is not clear 

whether repairs are included in the task cost. 

6. Second Coal Bucket Elevator 

The original HCCP design made provisions for the addition of a second coal bucket 

elevator. However, this system was not installed. A second coal bucket elevator will 

provide a redundant system, allowing coal loading to the silos when the primary bucket 

elevator is down for repairs. Task AG.2 evaluates the cost and benefits of this second 

elevator for $678,000. It is unclear whether this cost includes the second elevator or just 

the study. 

7. September 1999 Explosion 

A large explosion occurred on September 6, 1999, on the 20th day of the 90-day test 

during plant shutdown, originating in Pulverizer B. Considerable damage was done to the 

area around the pulverizer.30 The explosion was caused by faulty equipment and extended 

operation at low load.31 This explosion damaged a section of the primary air duct to the B 

Pulverizer. The damage from this explosion was never repaired. The Project List includes 

modifications to repair this damage. These repairs include inspecting and repairing 

damaged parts including the pulverizer primary air ducts and transport tubes and the coal 

feeder system both upstream and downstream from where the explosion occurred. 

Such explosions are not routine and are attributed to the experimental nature of the Unit 

2. These are more properly considered development costs because this is first generation 

technology. The costs should have been incurred during the demonstration period to 

facilitate commercial operation. They are just one of many indications that the Unit 2 

cannot be operated in its current state and never could have been commercially operated 

at the time it was shutdown. Further, the fact that the Unit was never repaired after the 

explosion indicates that there was no intention of re-starting the facility at some later 

time. Some of the modifications to repair the damage are discussed below. 

(a) Coal Silos 

The fires that occurred in coal silo B in September 1999 damaged several coal silo 

liners.32 This damage was never repaired. Task M.1 would repair the damage to 

the silo and install new liners for $300,000. 

(b) Coal Feeder System 

 

28 Project List, p. 21, Task W.1 (emphasis added). 

29 Id. 30 12/99 Duke Report, pp. 1-2., 6-11 (Attachment 6). 

31 3/28/06 Shaw Report, p. 21. (Attachment 5). 

32 3/28/06 Shaw Report, pp. 19-20. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

31 

The TRW coal feed system is a new process. Two pulverizer explosions occurred 

that may result in premature failure and safety issues.33 The explosion damaged a 

section of the primary air duct to the B Pulverizer. The modifications include 

Task F.1.b, which will evaluate the ductwork and if necessary, replace it, for 

$310,000.34 

(c) Transport Tubes 

The explosion may have damaged some of the ceramic tiles lining the coal 

transport tubes. The modifications include Task F.1.c, which will inspect these 

tubes and replace any tiles, as necessary, at a cost of $24,000.35 It is unclear 

whether this cost includes replacing the tubes, or just the study to inspect them. 

8. November 1999 Explosion 

A duct explosion occurred in November 1999 during the shutdown of the coal feed 

system, while the unit was decreasing load. In the lead-up to this explosion, coal being 

fed from the coal silo to the coal feeders plugged in the downspouts. Maintenance 

workers used sledge hammers throughout the night in an effort to keep the coal flowing. 

In spite of these efforts, a duct explosion occurred, causing Pulverizer A to trip.36

This explosion was attributed to the elevated temperatures of the air exiting the pulverizer 

and reduction in air flow through the pulverizer and exhaust fan. Shaw recommended a 

number of measures to prevent the recurrence of these conditions, including replacing the 

mill exhaust fans with new smaller fans, revising the operation of the capacity dampers, 

modifying the control logic, and repairing or replacing the leaking automatic valves.37 

The Project List only identifies one of these recommendations, new mill exhaust fans. 

(a) Mill Exhaust Fans 

The mill exhaust fans pull hot air and pulverized coal out of the pulverizers and 

transport it to the pre-combustor and slagging combustor via a splitter system with 

cyclones. Task F.2.a will replace the exhauster fans in the coal feed system for 

$2,000,000. This change is required to correct an original design error discovered 

during the 90-day trial period. The mill exhauster fan blades and scrolls eroded 

faster than expected due to the high ash content and abrasive properties of the 

Usibelli coal, requiring an unacceptable amount of repair.38 Numerous 

unsuccessful attempts were made during plant operation to correct this problem.39

The problem was not corrected. 

As explained by Shaw: “There is general agreement between the information 

sources and SSW [Shaw, Stone & Webster] that the demonstrated service life of 

 

33 12/99 Duke Report, p. 8-4. 

34 Project List, p. 12, Task F.1.b. 

35 Project List, p. 12, Task F.1.c 

36 12/99 Duke Report, p. 6-12 

37 12/18/08 Shaw Closeout Report, Section 9.0 Studies & Reports, Coal Feed and Mill Exhaust 

Fan Analysis, October 16, 2008. 

38 12/99 Duke Report”, p. 1-2. 

39 3/28/06 Shaw Report, p. 2. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

32 

90 days resulting from operation of this equipment under the conditions of the 

demonstration test was unusually low and not acceptable for a typical power plant 

application.”40 Thus, these fans are not capable of commercial operation. This task 

will evaluate installation of new mill exhauster fans lined with a more erosion 

resistant material and possibly include variable frequency drives to control fan 

speed.41

The Shaw Closeout Report indicates that the new mill exhaust fans, equipped 

with smaller diameter rotors, would increase pulverizer inlet coal flow from 

44,827 lb/hr in August 1999 to a design level of 48,842 lb/hr.42 This increase in 

coal flow rate could lead to an increase in emissions. 

9. Redesign Swirl Dampers 

The demonstration showed that it may be beneficial to use a fixed cross sectional area in 

the swirl dampers, rather than an adjustable cross sectional area, as in the original design. 

Task F.4.g will evaluate the cost and feasibility of changing the design of the swirl 

dampers from adjustable to fixed for $99,000. It is unclear whether this cost includes the 

cost to make the design change, but design changes cannot be considered routine 

maintenance. 

10. Slag Ash Clinker Grinder 

During operation of Unit 2, staff reported numerous occurrences of large pieces of slag 

ash accumulating on the oversize grate upstream of the slag ash bucket elevator that loads 

ash into trucks. This material had to be manually removed from the grates and reduced in 

size using rods, water spray, and air-powered tools, a situation that would never be 

tolerated in a commercial facility due to labor costs.43 Task H.1 is a study to evaluate the 

need for a slag ash clinker grinder at a cost of $205,000 to automate this process. The 

Shaw Closeout Report estimated the cost of the new grinder at about $303,000.44

The Project List claims that clinker grinding would not increase emissions because the 

clinker would be wet when they enter the grinder and would thus produce no dust.45

However, grinding produces some dust, regardless of the moisture content. A related 

study, in Task AM.1, would consider an alternate design to bypass the bucket elevator 

when it is out of service. The clinker grinder would alleviate the need for this bypass 

system.46

11. Bottom Ash Bucket Elevator Conveyor Bypass 

During 1998 – 1999 testing, slag ash could not be handled by the ash loadout bucket 

elevator feeding material to the bottom ash silo (while burning a coal with less ash than 

 

40 3/28/06 Shaw Report, p. 44. 

41 Project List, p. 18, Task F.2.a. 

42 12/18/08 Shaw Closeout Report, Section 9.0 Studies & Reports, Coal Feed and Mill Exhaust 

Analysis, October 16, 2008. 

43 3/28/06 Shaw Report, pp. 3, 27; 12/99 Duke Report, p. 6-12. 44 12/18/08 Shaw Closeout Report, Section 10.0 Project Cost Estimate, Section 10.1 Capital Cost 

Estimate, Estimate Download, June 9, 2008 

45 Project List, p. 20, Task H.1. 

46 Project List, p. 23, Task AM.1. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

33 

design basis). A temporary conveyor was installed to bypass the bucket elevator and load 

ash directly into trucks.47 Task M.1 installs a dedicated slag ash bypass for $90,000. The 

Shaw Closeout Report estimates the cost for this bypass as $281,770.48

12. Combustor Flame Scanners 

The original purge air flame scanners have inadequate purge air flow. Task F.4.b will 

modify them to increase air pressure and air flow to the scanners.49

13. Coal Bucket Elevator Chute 

Task E.2 will add vibrators and modify the coal bucket elevator inlet chute for $282,000. 

These changes are required because the 90-day trial showed plugging problems existed at 

the coal bucket elevator inlet chute. This task redesigns the inlet chute and adds vibrators 

to prevent plugging the bucket elevator with coal.50 Unit 2 will not be able to operate 

commercially without this modification. 

14. Bottom Ash Conveyor 

Operating reports indicated the bottom ash bucket elevator periodically plugged. Task 

R.1 will inspect and review this elevator and modify as appropriate. The stated cost of 

$4,000 is not adequate to cover any modifications. 

15. Coal Handling System 

The automated coal blending system never worked properly and did not meet project 

design requirements.51 Rather, the run-of-mine coal and waste coal were blended in the 

yard by operators using wheeled loaders. This is a very inaccurate method to maintain a 

uniform coal supply, which is required for commercial operation. The 12/99 Harris 

Report recommended an automated coal blending system to address this situation. 

Similarly, the 3/28/06 Shaw Report opined: “Numerous operating problems encountered 

during initial plant startup and subsequent operation demonstrates that the combined coal 

handling system as currently configured, is limited in its ability to ensure reliable delivery 

of coal to both plants.”52

The modifications include Task AG.3, which would study coal pile management for 

$400,000. The 12/18/08 Shaw Closeout Report contemplates far more than a study, 

specifying design for a new coal handling system.53 A new coal handling system was 

estimated to cost about $16 million in the Closeout Report.54

 

47 3/28/06 Shaw Report, p. 27. 

48 48 12/18/08 Shaw Closeout Report, Section 10.0 Project Cost Estimate, Section 10.1 Capital Cost 

Estimate, Estimate Download, June 9, 2008. 

49 Project List, pp. 2-3, Task F.4.b. 

50 Project List, p. 17, Task E.2. 

51 12/99 Duke Report, p. 1-2 (“The coal blending system does not operate as designed. The coal 

feed system exhibits high rates of wear of various components, in particular the exhauster fans and 

cyclones. The existing exhauster fans are unsuitable for long term operation due to the unacceptable 

amount of repairs required.”) and 8-4 (“The automated HCCP coal blending system is not working properly 

and does not meet project design requirements.”). 52 3/28/06 Shaw Report, p. 61. 

53 12/18/08 Shaw Closeout Report, Section 4.0 Coal Handling, Section 4.1 Bid Package, 

Engineering, Design and Supply of Coal Handling System, October 14, 2008, Document No. 128569-S-M- 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

34 

16. Replace Worn Air Nozzles 

Air is injected into the precombustor. During testing, the Precombustor B staged air 

annulus was completely blocked by slag and the majority of the radial startup air nozzles 

was covered with slag. As this precombustor was designed to be non-slagging, this 

precombustor did not operate per design.55 Task F.4.a would replace several air nozzles 

for $100,000. The Project List fails to mention slagging or include any design changes to 

mitigate it. 

17. Limestone Feeder/Control 

During the test period, the response time between changes in limestone feed rate to the 

furnace and resulting changes in SO2 at the inlet to the scrubber were much longer than 

required to adequately control SO2 emissions.56 The test data indicate a five-day lag 

between the addition of limestone to the furnace and the time it significantly changes the 

composition of the slurry fed to the SDA.57 This is too long to effectively control SO2

emissions. Thirty-five hours of SO2 violations were recorded during the 90-day test.58

The startup modifications include Task U.1, a $53,000 study to resolve this issue.59 

The only other modifications to the SDA identified in the Project List are Task Q.4, SDA 

access platforms ($37,000), and Task Q.5, replace SO2 process monitors and probe at 

SDA inlet ($20,000). The Closeout Report cost estimate includes: “SDA & Flue Gas 

System Inspection & Refurb” for $463,261.60

18. Turbine Efficiency 

At the conclusion of the test period, the steam turbine was reported to have a 2% loss in 

efficiency compared to the original guarantee. The restart projects include $600,000 to 

disassemble the turbine to investigate the cause of this loss and to perform minor turbine 

refurbishment to mitigate the loss.61 The Shaw Closeout Report estimated the cost at 

$690,734.62 The Project List, however, fails to disclose this intent, instead containing only 

generic Task J.1, to inspect the steam turbine and generator, claiming it as RMRR,63

when, in fact, its purpose is to correct design error(s). 

19. Waste Water Treatment System 

 

00002-0. 

54 12/18/08 Shaw Closeout Report, Section 10.0 Project Cost Estimate, Section 10.1 Capital Cost 

Estimate, Estimate Download, June 9, 2008. 

55 12/99 Duke Report, pp. 7-2 to 7-3. 

56 3/28/06 Shaw Report, p. 12; Project Performance and Economics Report, Volume 2, April 2001, 

pp. D-6 to D-7. 

57 12/99 Duke Report, p. 6-28. 

58 12/99 Duke Report, p. 6-23. 

59 Project List, p. 20, Task U.1 

60 10/14/08 Shaw Closeout Report, Section 10.0 Project Cost Estimate, Section 10.1 Capital Cost 

Estimate, Estimate Download, June 9, 2008. 

61 3/26/06 Shaw Report, p. 3. 

62 12/18/08 Shaw Closeout Report, Section 10.0 Project Cost Estimate, Section 10.1 Capital Cost 

Estimate, Estimate Download, June 9, 2008. 

63 Project List, p. 4, Task J.1. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

35 

The original installation injected acid and caustic into the top of the neutralization tank. 

The 90-day test demonstrated this design resulted in substandard mixing of chemical and 

thus slow neutralization of tank contents. Task Z.2 will move the injection points to the 

suction line of the neutralization pumps to improve mixing of acids and caustic for 

$37,000.64

Routine Maintenance Summary 

It is important in analyzing the “routine” maintenance issue in this matter not to lose sight 

of the numerous design changes being made to facility. Design changes do not qualify as 

routine maintenance. See Detroit Edison Applicability Determination, Attachment 9. 

Furthermore, the changes discussed above are not “regular, customary, or standard 

undertaking for the purpose of maintaining the plant in its present condition.” TVA Order, 

Attachment 8, at p. 10. The “present condition” of the plant is not operable on a long-term 

basis. Thus routine maintenance would consist of doing whatever is necessary to keep the 

plant in its non-operational mode. In contrast, the purpose of the proposed changes is to take 

a plant which is incapable of long-term commercial operation and make it viable; in other 

words, the changes are designed to improve the plant – not keep it in its current condition. 

Therefore, the “purpose” factor weighs strongly in favor of a finding that the proposed 

changes are not routine. 

As for the “nature” and “extent” factors, as catalogued above, the changes being made at the 

plant comprehensive, and many of them cannot be made while the plant is in operation. Thus, 

these factors also indicate that the proposed changes are not “routine.” As for the “frequency” 

factor, as mentioned above, many of the changes being made at this facility are the result of a 

situation where the facility started up in test phase and operated even though construction 

was never fully completed. Thus, many of these changes are not those that would be either 

regular or customary, but rather are actions more properly associated with initial 

construction. Consequently, analysis of the “frequency” factor also leads one to conclude that 

the type of maintenance activities taking place to “re-start” the facility are not routine. 

Finally, as mentioned above, serious questions need to be asked about the cost figure being 

used in the current analysis, but even with the conservative cost estimate used by ADEC, the 

cost of the changes approaches the unit’s annual maintenance budget. Therefore, the physical 

changes simply cannot be considered de minimis. 

For all these reasons, a finding that the planned changes here constitute routine maintenance 

is simply not credible. 

Response from ADEC: 

Major Modification - Routine Maintenance

First, a response related to the various costs mentioned in the comment. These costs do not 

relate directly to each other in the way that would be assumed without further evaluation. The 

 

64 Project List, p. 7, Task Z.2. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

36 

$62 million from The Shaw Group was prepared for AIDEA under the assumption at the time 

that HCCP would be operated for AIDEA by Homer Electric. That would have required 

complete separation between HCCP and Unit 1. GVEA reports that there are 97 points of 

connection between the plant that would have to be severed and replaced.65 Separation would 

require major new investments including a coal handling system and new fuel storage tanks. 

Thus, The Shaw Group's cost estimate is of necessity far higher than that prepared by GVEA for 

their operation of HCCP. 

The $45 million is a revolving loan fund offered to GVEA by AIDEA. It is the Department's 

understanding that much of the $45 million was not intended for physical changes. Of those 

physical changes that were contemplated, many are not to air pollutant emitting activities at 

Unit 2. Some of the funds, while related to HCCP may be for activities at other locations, such as 

spinning reserves as backup to HCCP. The Department does not have available information to 

do a detailed comparison between GVEA's current task list and activities originally 

contemplated for funding under this loan. The Department is instead relying on GVEA's current 

certified list of planned tasks 

$16.2 million was derived by a GVEA consultant as a collection of possible tasks from all 

reports from engineering firms that have studied HCCP. It intentionally included all aspects 

including those not related to air pollutant emitting activities such as water treatment, lighting, 

signage, HVAC air balance, and bathroom fans. This possible task list was reviewed by GVEA 

for decisions on which tasks would be done before commercial startup. The current estimated 

cost is $11 million. This is less than the estimated annual O & M budget, but would come from 

the revolving loan fund because, until HCCP operates there is no O&M budget. The $11 million 

includes numerous tasks that are not changes to pollutant emitting activities. 

After construction is complete, every new large industrial facility will go through a shakedown 

period to make sure it is in proper working order, and to change things that are not working 

properly. When the facility is made up of off the shelf components, standard in how they are 

configured, this is a much simpler process, the manufacturer having made changes to equipment 

and recommended procedures based on previous experience. HCCP is one of a kind. 

Shakedown after construction has turned out to be much more difficult than could have been 

envisioned. But the changes GVEA plans are in their nature post construction changes based on 

difficulties encountered during shakedown. 

The Commentator states, "The results of the 90-day test were inconclusive as the test was 

performed with coal having a heating value slightly above the design specification, resulting in 

23% less ash than design." GVEA has informed the Department66 that based on the experience 

during testing, they plan during normal operation to use a blend of coal and waste coal with a 

minimum heat content of 7,200 Btu/lb. This differs from that originally planned, being higher in 

Btu and lower in ash in order to better manage the abrasive quality of the coal and avoid a high 

level of abrasion damage. This is not a modification because the equipment was always more 

 

65 Ex Parte teleconference between GVEA and the Department, 10/27/11. Kris DuBois, GVEA; Flint Goodrich, 

consultant for GVEA; Jim Baumgartner, ADEC; Jim Plosay, ADEC, Bill Walker, Blue Creek Consulting, consultant 

for the Department. Teleconference was requested by Department to obtain information related to comments. 

66 Ex Parte teleconference between GVEA and the Department, 10/27/11. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

37 

able to use such a blend, and did so during the 90 day test phase. The original Department of 

Energy intent to use a large percentage of waste coal has been abandoned. 

Clarifications are in order regarding task by task evaluations. 

For some of the tasks listed by the commentator above, the Department relied primarily on 

factors other than routine maintenance in the task by task evaluation to determine that they are 

not modifications with respect to the PSD thresholds. 

While the Department did list access improvements and tagging and labeling also as routine 

maintenance, the Department primarily categorized them as not being modifications because 

they are not physical changes to pollutant emitting activities. 

The Department categorized the dry ash and wet ash transfer systems, and relocation of 

injection points for the waste water treatment system as not being modifications because they do 

not increase emissions, and are not necessary for commercial startup. The dry ash and wet ash 

conveyor systems are not for HCCP at all. The systems move Unit 1 ash to Unit 2 to avoid 

running redundant systems and because HCCP ash handling is better environmentally than the 

Unit 1 ash pond. The change to the waste water treatment system is not essential because the 

change is not necessary to meet water quality standards. 

The coal pile management task is a study, not a modification. GVEA reports that their method of 

using wheeled equipment to blend coal is workable, and is currently being used for Unit 1. 

Three of the tasks listed are no longer on the list GVEA intends to perform before startup: AG.2,

the second coal bucket elevator; F.4.g, redesign of swirl dampers; and AM.1., bottom ash bucket 

elevator conveyor bypass. 

Those remaining tasks from the commentator's list are: 

3 Electrical Breakers 

7a Coal Silos 

7b Coal Feeder System 

7c Transport Tubes 

8a Mill Exhaust Fans 

10 Slag Ash Clinker Grinder 

12 Combustion Flame Scanners 

13 Coal Bucket Elevator Chute 

14 Bottom Ash Elevator 

16 Worn Air Nozzles 

17 Limestone Feeder 

18 Steam Turbine Inspection and Repair 

Remaining planned tasks
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

38 

Electrical Breakers. It is uncertain from the Duke Energy assessment whether or what 

cables may have been the wrong size, so it is uncertain whether any replacements are 

necessary. If cables need replacing, it is unclear whether any changes would be to 

pollutant emitting activities or equipment. The Department considers complying with 

electrical codes to be routine for such a stationary source. 

Coal Silos, Coal Feeder System, and Transport Tubes 

The Department believes that repair of any accidental damage at a stationary source is 

routine industry practice. The Department does not believe that plant accidents requiring 

repair before continued operation are of themselves PSD triggering events. The tasks 

are to inspect and, if needed, repair the coal feeder system and transport tubes, and to 

repair the coal silos. Repairs would not involve redesign of the damaged equipment. 

Mill exhaust fans 

The comment states "The Shaw Closeout Report indicates that the new mill exhaust fans, 

equipped with smaller diameter rotors, would increase pulverizer inlet coal flow from 

44,827 lb/hr in August 1999 to a design level of 48,842 lb/hr.67 This increase in coal flow 

rate could lead to an increase in emissions." 

The fan replacement task described by GVEA only includes replacement with fans that 

have a more abrasion resistant coating, not changing the size of the fan blades. As 

mentioned above, the Shaw Closeout Report was not prepared for GVEA. GVEA reports 

that to date they have not considered changing fan size. Smaller diameter blades may not 

be able to reach the design pressure. The existing fans are capable of supplying coal at 

least up to the heat input and steam output capacities of the boiler using 7,200 Btu/lb 

coal.68

In the task list GVEA states "Fans are typically replaced while the plant is running or 

during normal scheduled outages. Length of outages will not change whether using the 

chromium carbide liner or tungsten-carbide liner fans." So the task would not change 

anticipated down time. In any event, any increase in utilization that may result from this 

or other tasks is accounted for by the use of a 95% utilization factor in the calculation of 

projected actual emissions. (See Major Modification - Emission Increase below). 

GVEA indicates that the existing fan can be operated without replacement. However, it 

makes sense to change it out now so that it can be operated for an estimated two years 

before being replaced again.

 

Slag Ash Clinker Grinder 

Because the EPA emission factor is a non-detect, any emission increase from this task is 

not quantifiable, and could not cause an increase to exceed the PSD modification 

threshold for PM-10. 

 

67 12/18/08 Shaw Closeout Report, Section 9.0 Studies & Reports, Coal Feed and Mill Exhaust 

Analysis, October 16, 2008. 

68 68 Ex Parte teleconference between GVEA and the Department, 10/27/11. 
Golden Valley Electric Association Response to Comments 

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39 

The Department concurs that manual removal of clinkers is labor intensive. The task 

would reduce labor costs.

Combustor Flame Scanners 

GVEA reports that flame scanners are replaced at about six year intervals. They also 

report that purge air is adjusted at the same time after the scanner is replaced. Incorrect 

adjustment could lead to either less efficient combustion from introduction of more purge 

air than necessary, or more frequent replacement of the scanner. Because this adjustment 

must occur at predictable intervals, the Department considers it routine. Rather than 

being a physical change to the emissions unit, it is an adjustment within its existing 

capabilities. 

Coal Bucket Elevator Chute 

The task would decrease down time and reduce labor costs. The Department does not 

find that Trustees has supported the statement that Unit 2 will not be able to operate 

commercially with the change. 

Bottom Ash Elevator 

The comment does not provide new information which would lead the Department to 

revise its evaluation of this task. 

Worn Air Nozzles 

Regardless of whether a better design would decrease the wear, simply replacing worn 

parts is clearly a routine maintenance item. 

Limestone Feeder/Control 

The comment does not address the actual intent of the task. The comment deals with the 

very long time lag between addition of limestone and changes in the slurry composition 

fed to the SDA, concluding that the lag is too long to effectively control SO2 emissions. 

The comment then points out that there were thirty five hours of SO2 violations during the 

90 day test, implying that they may have been caused by the time lag. 

However, the Duke Report indicates that the result of the time lag is that automatic 

limestone feed control is not feasible and that limestone feed rate must be set manually at 

a rate that is high enough to insure compliance.69

The report also describes a second reason for higher than design limestone feed rates-- 

that the feeder motor is oversized and does not perform well at small percentages of its 

full flow design.70 Task U.1 is related to this second concern - physical difficulties in 

using lower limestone rates. GVEA states that the reason for the task is that the 

operating range of the existing system is too broad, making it difficult to control the feed 

at lower rates. 

 

69 12/99 Duke Report, p. 5-31. 

70 12/99 Duke Report, p. 5-6. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

40 

In any event, the result of not doing the task is using more limestone than otherwise 

would be necessary to assure compliance with SO2 emission limits. 

The thirty-five hours of SO2 violations during the 90 day test did not result from the time 

lag mentioned above or from control difficulties at lower limestone feed rates - and 

therefore do not relate to this task. The Duke Report identifies each occurrence as being 

cause by either startup, shutdown, or operation while changing out Spray Dryer 

Absorber (SDA) atomizers. It is the nature of the atomizers to plug and need to be 

swapped out routinely or after the fact, every month or two, taking the SDA off line. This 

causes elevated SO2 emissions during change out. During startup and shutdown, there 

are periods when furnace temperatures are too cool for the SDA to function. Emission 

standards still apply during these periods. Among the ways to manage these situations 

are reducing the time the SDA is off line, and switching to very low sulfur fuel oil at times 

when the SDA is off line. 

The permit does not contain a compliance plan because HCCP was in compliance when 

it discontinued operation.

Steam Turbine Inspection and Repair 

The Shaw Report71 cited by the commentator describes the task as: "to disassemble the 

turbine to investigate the cause of this loss in efficiency and to perform minor turbine 

refurbishment to mitigate this apparent loss." (emphasis added) It further reports, 

"Turbo-Dyne Electric...found the generator capable of immediate start-up."72 The report 

does not mention design flaws. This task is apparently similar to maintenance which 

EPA in Detroit Edison describes as routine.73

With the possible exception of the electrical breakers (for which it is uncertain whether any work 

is needed) and the repair of accidental damage, which the Department finds to be routine in any 

event, HCCP is capable of operating without these changes. While the rated capacity of HCCP 

will not be increased, operation will make far more efficient use of manpower if the changes are 

made. For each task it is not the Department's responsibility to determine how the change 

affects the profits or consumer power costs from the operation in order to issue the permit. 

 

The commentator goes to considerable length to argue that GVEA's proposed physical changes 

are not routine and would therefore trigger PSD review. As the Department stated in 3bii. of 

Appendix to the Statement of Basis, even if none of the proposed physical changes were 

considered routine, those changes taken as a whole would not cause emission increases that 

would exceed the PSD significance threshold, and would therefore not trigger PSD review. 

In Detroit Edison,

74 EPA states, "nonroutine changes of any type, purpose, or magnitude at an 

electric utility steam generating unit --ranging from projects to increase production efficiency to 

 

71 3/26/06 Shaw Report, p. 3. 

72 3/26/06 Shaw Report, pp. 26, 50. 

73 Letter from Francis Lyons, EPA Regional Administrator, to Henry Nickel, Counsel for Detroit Edison Company, 

Unton & Williams, May 23, 2000. The letter and attachment contain the Detroit Edison Dense Pack applicability 

determination. 

74 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

41 

even the complete replacement of entire major components -- are excluded from PSD coverage 

as long as they do not significantly increase emissions from the source." 

Major Modification - Emissions Increase

B. The Physical and Operational Changes Necessary to Make Unit 2 Operational Again 

Would Cause an Emissions Increase. 

ADEC’s emissions increase analysis is legally erroneous. In its analysis, ADEC first 

concedes that Unit 2 is not a “new emissions unit.” Appendix C, at 20-21. ADEC then 

examines the definition of “baseline actual emissions,” 40 C.F.R. 52.21 (b)(48)(i), and 

concludes that the first two years of operation, rather than any time within the past five 

years , is representative of normal operation. ADEC then takes two approaches to the 

emissions increase issue. 

In the first approach, ADEC concludes that during that initial two-year period, Unit 2 was 

“new,” and therefore, under 40 C.F.R. 52.21 (b)(48)(iii), baseline actual emissions equals 

the unit’s potential to emit. In the second approach, ADEC derives a value for baseline 

actual emission based on the 90 days of operation that occurred during the first two years. 

Both of these approaches are legally flawed. 

The first approach is flawed for the following reason. ADEC concedes that Unit 2 cannot 

be treated as a “new emissions unit” as defined in 40 C.F.R. 52.21(b)(7). Nevertheless, 

ADEC awards Unit 2 the baseline of a new emissions unit by arguing that the unit should 

be awarded the baseline set aside for new units that have commenced operation. Thus, 

ADEC is simultaneously treating Unit 2 as new and existing at the same time. The 

facility is either new or it is not. Legally, it cannot be both. Since ADEC concedes that 

Unit 2 is existing, ADEC must rely on the regulations that apply to existing emissions 

units. Under those regulations, “baseline actual emissions” equals: 

the average rate, in tons per year, at which the unit actually emitted the pollutant 

during any consecutive 24-month period selected by the owner or operator within 

the 5- year period. 

40 C.F.R. 52.21(b)(48)(i) (emphasis added). Accordingly, baseline emissions must be 

based on what the unit actually emitted, regardless of the 24-month period selected. Thus 

if the state selects the first 24-months as the representative period, then it must use values 

for what was actually emitted during that period. 

Section 52.21(b)(48)(i) also dooms ADEC’s second approach, where ADEC calculates 

emission factors based on the ninety-day test, and then extrapolates to determine what 

emissions would have been during the first 24-months of operation had Unit 2 run at a 

95% capacity factor. This approach is legally barred because as mentioned above, 

subparagraph 52.21(b)(48)(i) requires that the baseline must be based on what a unit 

“actually emitted” over a 24-month period. The regulations do not authorize baseline 

actual emissions to be based on extrapolations. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

42 

Fundamentally, over the life of this plant, the facility’s most “representative” mode is 

when it is not operating. Not surprisingly then, the most appropriate baseline for this 

facility is one based on no emissions at all. Legally, ADEC must use zero for baseline 

actual emissions from this facility. When the proper baseline is used, ADEC must 

conclude that a significant emissions increase will occur here. 

Response from ADEC: 

Major Modification - Emissions Increase

The Department can choose of a time period not within the preceding five years. 40 C.F.R. 

52.21(b)(48)(i) says 

"The Administrator shall allow the use of a different time period upon a determination 

that it is more representative of normal source operation." 

Under 18 AAC 50.306(b)(1)(A) and 18 AAC 50.990(28), for the purposes of 40 C.F.R. 

52.21(b)(48)(i), “administrator” means the Alaska Department of Environmental Conservation. 

Because EPA has approved the state PSD program this is also true under federal law. 

Since the first two years of operation were the only years in which HCCP Unit 2 operated, they 

are more representative of normal operation – that was and still is intended but has still has not 

been achieved – than no operation at all. Choosing the earlier period is supported by HCCP 

Unit 2 circumstances – the delays to enter commercial operations due to the difficulty of the 

negotiations between the owner and intended operator. These circumstances are unique, and 

are not comparable to any other case for which EPA has formulated guidance on choosing an 

alternative baseline period. This interpretation is especially appropriate for HCCP Unit 2 

because the PSD rules for baseline actual emissions and projected actual emissions simply do 

not address the case where an existing emissions unit went through PSD, but has yet to achieve 

any period representing normal operation. 

The Department's first interpretation of how to calculate the resulting baseline actual emissions 

is further reasonable because HCCP did not operate during any two year period during which it 

was an existing unit. 

Under the commentator's interpretation, if a permitting agency were to receive an application 

during the first two years of a new unit's operation, it could force the applicant to change its 

baseline actual emissions calculation from potential to emit to the more restrictive calculation in 

40 C.F.R. 52.21(b)(48)(ii) simply by waiting to act on the application until the emissions unit 

had existed for more than two years after initial operation. 

The Department stands with its analysis in Statement of Basis Appendix C, 5c as adequate. 

Regarding baseline actual emissions calculated from the 90 day demonstration phase, the 

Department does not concur with the comment. The commentator is ignores a relevant clause in 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

43 

the Baseline Actual Emissions definition. The statement above in 40 C.F.R. 52.21(b)(48)(i) 

about the Administrator allowing the use of a different time period does not restrict that 

different time period to a two year period. 

The calculation of baseline actual emissions did not use a 95% capacity factor. It used the 

actual emission rate for the 90 day test. The 95% capacity factor was used for calculating 

projected actual emissions. The Department finds that factor acceptable. Very few coal fired 

power plants have capacity factors higher than 95%.75 Considering the past operational 

problems at HCCP, the Department finds it highly likely that 95% is sufficient.

8. COMMITMENTS IN THE 1993 MEMORANDUM OF AGREEMENT 

From: John Bunyak, Chief, Policy, Planning and Permit Review Branch, National Park 

Service 

The requirement outlined in the 1993 MOA were negotiated based on significant concerns the 

NPS raised during, and after, the HCCP PSD permitting process over anticipated adverse effects 

to AQRVs in DNPP. As required by the 1993 MOA, ADEC has continued to include specific 

language from the MOA provisions in the permit conditions. In our December 4, 2009, 

comments, we stated that GVEA has not yet fulfilled its commitment to implement MOA 

provision III.A.4 (permit condition 25) by requesting lower SO2 and NOX limits. In response to 

NPS comments, GVEA submitted an owner-requested short-term NOX emission limit reduction 

from 0.350 lb/MMBtu to 0.325 lb/MMBtu (based on a 30-day rolling average). This ownerrequested reduction is reflected in the July 26, 2011, draft permit. We recognize, and commend 

GVEA's efforts to demonstrate their commitment toward fulfilling this provision. However, this 

revised rate is significantly higher than the rates achieved during the demonstration period to 

which the provision is initially tied. The demonstration phase was completed over ten years ago, 

and a Department of Energy assessment of the project concluded that HCCP was able to achieve 

a NOX rate of 0.275 lb/MMBtu; again, this is much lower than the 0.325 lb/MMBtu rate that 

GVEA recently requested. Therefore, we would like to reinstate our previous comments 

regarding this matter for the record (please reference our December 4, 2009, comment letter). 

In the response to comments document, ADEC points out that they are not a party to the 1993 

MOA, and that affected parties may seek relief or settlement under the terms of the MOA if they 

believe a breach in the agreement has occurred. We concur that this is one avenue for the NPS to 

seek implementation of provision III.A.4, but the provision is tied to seeking emission reductions 

through the Title V permit renewal process. Accordingly, we believe that the Title V renewal 

process is the appropriate first step in seeking fulfillment of this provision. While ADEC is not a 

party to this agreement, they are inherently involved in the process through which the agreement 

is fulfilled. We request that ADEC reconsider its conclusion and work with the NPS and GVEA 

to resolve this issue. 

 

75. Summary from DOE data prepared by Energy Venture Analysis and provided by GVEA shows only three of the 

top 20 CFB plants above 95% in 2009. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

44 

Finally, we believe this issue is more pertinent in light of ADEC's revised PSD applicability 

analysis, which utilized emissions data from the 1999 test period to conclude PSD does not 

apply. GVEA has long disputed the commercial viability of the test phase, and does not feel it 

reflected normal source operations or emission limits the facility would be able to achieve longterm. However, we continue to question why emissions information from this time period are 

not deemed adequate for fulfilling the MOA provisions, particularly when the agreement GVEA 

made with NPS was tied to the demonstration phase. Additionally, we now question why 

emissions information from the demonstration phase is considered adequate for calculating 

"baseline emissions" used in ADEC's PSD netting analysis. The netting analysis was not the 

only analysis ADEC relied on to determine that PSD does not apply to the restart. However, it 

was included as one analysis in what can be described as ADEC's "weight of evidence" approach 

to support their conclusion. As such, there appears to be a discrepancy in determining the 

validity of the 1999 emissions data: it is deemed adequate for accepting a permitted emission 

limitation required under the MOA and under associated provisions in the current Title V permit. 

We request that ADEC resolve this issue with GVEA and the NPS. 

Response from ADEC: 

The Department does not believe that GVEA's owner requested limit of 0.325 lb/MMBtu fulfilled 

the provisions of Condition 25 (or therefore the MOA) because more time is needed, and at 

normal operating conditions to determine if the unit can achieve a rate of 0.275 lb/MMBtu. 

Further, GVEA did not represent the owner requested limit as fulfilling that condition. 

Therefore, the Department has left that condition unchanged from its original form in a Title I 

permit. 

In its netting analysis, the Department recognized that emissions from the demonstration phase 

were not completely representative of normal operation. But they are the closest to being 

representative of any to date. 

The Department cannot establish new emission limits through Title V permitting, unless 

requested by the applicant. The Title V permit can only include applicable requirements that are 

otherwise established through law, regulation or Title I permit. 

9. COMMENTS RECOMMENDING CO2, MERCURY, AND COAL ASH EMISSION 

LIMITS AND MONITORING 

From: Gary Newman 

BACT and Monitoring 

As one who has been involved in this project since 1990 and a party to the settlement in 1994 to 

allow the experimental project to move forward, there were a lot of unknowns then that, due to 

the failure of the plant to operate, were never answered. Required monitoring adjacent to the 

Class 1 air shed of Denali National Park was an important factor in that settlement. 

Nearly 2 decades later, the proposal to retrofit this plant with conventional technology I find 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

45 

unsatisfactory. Improved technology as well as awareness of additional pollutants such as coal 

ash, mercury, and CO2 must require more attention to this permit vs. what was approved in 

1994. While such pollutants aren’t currently being regulated, the U.S. Supreme Court has 

mandated that CO2 be regulated. Mercury and coal ash are also on the table with the EPA. Since 

this plant is anticipated to be at least a 20 year investment by GVEA, one would think it be a 

wise move to consider methodologies to both monitor and mitigate. 

It would be my recommendation regarding any issuance of a new permit that the above items be 

included as well as the Best Available Control Technology (BACT) that was not available when 

the air quality permit was granted for the experimental coal plant in 1994. If these are not 

required with this permit, the permit should be denied. 

Response from ADEC: 

The proposal by GVEA to change to emission limits based on switching to conventional 

technology was denied by the Department on April 11, 2002. GVEA subsequently abandoned 

plans to retrofit with conventional technology. The emission limits in the permit presume use of 

the original technology. A physical change to a conventional plant would need a construction 

permit under PSD. 

While there is increased awareness of additional pollutants including CO2, mercury, and coal 

ash, if the PSD process were repeated today, the Department would still not have a regulatory 

basis for BACT analysis or monitoring to include mercury or CO2 (the increase in greenhouse 

gas emissions is not a major modification.) Ambient analysis was done for PM-10, which 

included combustion emissions. EPA is considering coal ash in regard to proper disposal rather 

than air emissions. If handled wet during disposal, coal ash should not result air emissions. 

From: Tom Paragi 

Health Standards 

The Healy Clean Coal Plant (HCCP) should meet the current Title V Air Permit requirements. 

I am a GVEA member who thinks factors other than simply cost of produced power are 

important for our future. We can continue to operate the existing permitted coal fired plants until 

natural gas or various renewable sources (including hydro) come online for electricity 

production. Regarding HCCP, we should strive to bring any new coal plant emissions into 

compliance for health standards regarding particulate size, mercury, sulfur dioxide, and various 

nitrogen oxides. 

Response from ADEC: 

HCCP will only be permitted to operate in compliance with ambient air quality standards, and 

maximum allowable increases, as well as emission standards. Ambient impacts were 

demonstrated to be in compliance with standards in 1994, and again during post construction 

monitoring during the test phase. 
Golden Valley Electric Association Response to Comments 

AQ0173TVP02 Healy Power Plant February 3, 2012 

46 

However, there has been no preconstruction review and ambient analysis for the new PM-2.5 or 

1-hour SO2 standards. 

Please see also the responses to Comment 1. and to Comment 9. BACT and Monitoring. 

From: John Bunyak, Chief, Policy, Planning and Permit Review Branch, National Park 

Service 

Mercury Control Provisions 

The draft permit does not include mercury control provisions, or mercury monitoring 

requirements. GVEA has proposed in their July 8, 2011, letter to install mercury control 

equipment earlier than may be required by federal regulations at the facility. As expressed 

previously, we support this proposal, with the caveats discussed above. However, in the absence 

of this agreement, at a minimum, we believe the draft permit should include mercury monitoring 

provision for the Healy plant. Potential mercury monitoring was verbally discussed between the 

NPS and GVEA during a January 28, 2010, meeting. This will assist in establishing baseline 

mercury emissions prior to federal regulations taking effect. 

Response from ADEC: 

In the absence of an owner request from the applicant to the Department to add such monitoring 

conditions, the Department does not have a regulatory basis to add such requirements. The CAA 

and regulations under the CAA, and similarly, Alaska statutes and regulations do not require 

mercury monitoring.