U.S. GOVERNMENT PRINTING OFFICE

66–380 CC WASHINGTON : 2001

S. HRG. 106–944

CLEAN AIR ACT: NEW SOURCE REVIEW

REGULATORY PROGRAM

HEARING

BEFORE THE

SUBCOMMITTEE ON

CLEAN AIR, WETLANDS, PRIVATE PROPERTY AND

NUCLEAR SAFETY

OF THE

COMMITTEE ON

ENVIRONMENT AND PUBLIC WORKS

UNITED STATES SENATE

ONE HUNDRED SIXTH CONGRESS

SECOND SESSION

FEBRUARY 28, 2000—CINCINNATI, OHIO

Printed for the use of the Committee on Environment and Public Works

(

For sale by the U.S. Government Printing Office

Superintendent of Documents, Congressional Sales Office, Washington DC 20402
COMMITTEE ON ENVIRONMENT AND PUBLIC WORKS

ONE HUNDRED SIXTH CONGRESS, SECOND SESSION

BOB SMITH, New Hampshire, Chairman

JOHN W. WARNER, Virginia

JAMES M. INHOFE, Oklahoma

CRAIG THOMAS, Wyoming

CHRISTOPHER S. BOND, Missouri

GEORGE V. VOINOVICH, Ohio

MICHAEL D. CRAPO, Idaho

ROBERT F. BENNETT, Utah

KAY BAILEY HUTCHISON, Texas

LINCOLN CHAFEE, Rhode Island

MAX BAUCUS, Montana

DANIEL PATRICK MOYNIHAN, New York

FRANK R. LAUTENBERG, New Jersey

HARRY REID, Nevada

BOB GRAHAM, Florida

JOSEPH I. LIEBERMAN, Connecticut

BARBARA BOXER, California

RON WYDEN, Oregon

DAVE CONOVER, Staff Director

TOM SLITER, Minority Staff Director

SUBCOMMITTEE ON CLEAN AIR, WETLANDS, PRIVATE PROPERTY, AND

NUCLEAR SAFETY

JAMES M. INHOFE, North Carolina, Chairman

GEORGE V. VOINOVICH, Ohio

ROBERT E. BENNETT, Utah

KAY BAILEY HUTCHISON, Texas

BOB GRAHAM, Florida

JOSEPH I. LIEBERMAN, Connecticut

BARBARA BOXER, California

(II)
CONTENTS

Page

FEBRUARY MARCH 28, 2000—CINCINNATI, OHIO

OPENING STATEMENTS

Inhofe, Hon. James M., U.S. Senator from the State of Oklahoma .................... 1

Voinovich, Hon. George V., U.S. Senator from the State of Ohio ........................ 2

WITNESSES

Bynum, Joe, executive vice president, Fossil Power Group, Tennessee Valley

Authority ............................................................................................................... 16

Prepared statement .......................................................................................... 82

Report, Routine Maintenance of Electric Generating Stations ..................... 17–42

Hawkins, David, Natural Resources Defense Council .......................................... 51

Prepared statement .......................................................................................... 94

Report, Plant Life Extension............................................................................ 58–63

Survey, Plant Life Extension Conference........................................................ 52–58

Moore, W. Henson, President and Chief Executive Officer, American Forest

and Paper Association ......................................................................................... 48

Prepared statement .......................................................................................... 90

Statement, Forest Products Industry, Michael Draper ................................. 50

Seitz, John S., Director, Office of Air Quality Planning and Standards, Environmental Protection Agency .............................................................................. 9

Prepared statement .......................................................................................... 80

Slaughter, Bob, director, Public Policy National Petrochemical and Refiners

Association ............................................................................................................ 46

Prepared statement .......................................................................................... 83

Strickland, Hon. Ted, U.S. Representative from the State of Ohio ..................... 5

Prepared statement .......................................................................................... 78

Tyndall, Bill, vice president of environmental services, Cinergy Corporation ... 63

Prepared statement .......................................................................................... 100

(1)

CLEAN AIR ACT: NEW SOURCE REVIEW

REGULATORY PROGRAM

MONDAY, FEBRUARY 28, 2000

U.S. SENATE,

COMMITTEE ON ENVIRONMENT AND PUBLIC WORKS,

SUBCOMMITTEE ON CLEAN AIR, WETLANDS, PRIVATE

PROPERTY,

AND NUCLEAR SAFETY,

Cincinnati, Ohio.

The subcommittee met, pursuant to notice, at 2:30 p.m. at the

Hamilton County Administration Building, 138 East Court Street,

6th Floor, Cincinnati, Ohio, Hon. James M. Inhofe (chairman of the

subcommittee) presiding.

Present: Senators Inhofe and Voinovich.

OPENING STATEMENT OF HON. JAMES M. INHOFE,

U.S. SENATOR FROM THE STATE OF OKLAHOMA

Senator INHOFE. The meeting will come to order. I apologize, but

it seems like we had our news conference before instead of after

the meeting, which is fine with me.

Today’s hearing is on the reform of the New Source Review Regulatory Program. This is a highly complicated issue and hopefully

we can shed some light on it today. This hearing is not about recent enforcement actions taken by the EPA against the electric

utilities, although those actions were filed using the existing regulations.

For those people in the audience who are not familiar with the

way the EPA works, let me explain. The Air Program Office writes

the regulations and the Enforcement Office polices the compliance

of those regulations that have been written.

What I would like to do now is briefly layout where we are today

and invite some of the witnesses to comment. The New Source Review Program dates back to the Clean Air Act of 1977. The Act required sources built after 1977 to have state-of-the-art emissions

control devices. Congress did not believe this was fair and equitable

and financially feasible to require all existing facilities to install

new equipment.

Instead, Congress required existing large facilities to undergo a

New Source Review before they make major expansions or modifications in order to prevent significant new air emissions. These

facilities have been referred to as grandfathered facilities, meaning

that they are originally exempted from the new provision controls.
2

Although, of course, they have had to install other control devices

over the years.

This program started a confusion and debate, which has lasted

for almost 25 years now. I am told that over the years the EPA has

issued more than 4,000 pages of guidance documents, which sometimes contradict each other, in order to explain the original 20-

page, 1980 regulations.

In the late 1980’s the Wisconsin Electric Power Company, called

WEPCO, challenged a determination by the EPA that they had violated the NSR regulations. The lawsuit resulted in a new regulation governing the NSR for utilities in 1992 called the WEPCO

rule. Then in 1994 the EPA issued a new proposed rule for all industries and after 6 years in debate the EPA has indicated that

they may go final with their new rule later this year.

In my opinion, the major question is: when do modifications or

changes to a facility or plant trigger the New Source Review Program. This involves a number of issues, such as whether you measure actual releases or just potential to release; whether you look at

the dollar amount of the modifications and compare it with the

value of the facility; or whether the modifications are just routine

maintenance which is also hard to define. Considering the amount

of debate over the last 25 years, the number of guidance documents

and regulations issued by the EPA, and the number of lawsuits, I

don’t expect that we’re going to be able to answer all the questions

that exist today.

I would like to publicly thank Bob Perciasepe, EPA’s Clean Air

Director, for working these issues out. He couldn’t be here with us

today. He sent a very capable person to represent him.

Senator Voinovich?

OPENING STATEMENT OF HON. GEORGE V. VOINOVICH,

U.S. SENATOR FROM THE STATE OF OHIO

Senator VOINOVICH. Thank you, Mr. Chairman. First of all, I

would like to thank the county commissioners, John Dowling, Tom

Neyer, and Bob Bedinghaus, for allowing us to use this fine facility

here in Cincinnati; and I would like to welcome you here, Mr.

Chairman. The chairman and I have known each other since his

days when he was the Mayor of the City of Tulsa, Oklahoma, and

I was the Mayor of the City of Cleveland and we’ve worked together in the Senate; and I consider him a true champion of responsible environmental policy.

I don’t know whether you know this or not, Mr. Chairman, but

this is the home of Ken Griffey, Jr., and he’s coming home to play

and join his dad on the Reds team, and we’re expecting some great

things from him.

Senator INHOFE. Sure, yes. Is that an invitation to come up

and——

Senator VOINOVICH. Come up for the I–71 World Series.

Cincinnati is our queen city and it has a wonderful public partnership and a community that really cares about the environment

and public health.

I’d also like to welcome Congressman Ted Strickland. Ted is testifying today, and Ted and I have worked together in a bipartisan

manner on a range of issues including the post ambient air stand-
3

ards for a particulate ozone; proposed NAAQS standards. Right

now we’re working on the Portsmouth gas infusion plant to try and

predict in the interest of the workers, and I’m glad you’re here

today, Ted.

I’d also like to extend a warm welcome to Bill Tyndall, Vice

President of Environmental Services and Federal Affairs at

Cinergy Corporation in Cincinnati. Cinergy is a responsible corporate citizen in the environmental arena and I am pleased that

Mr. Tyndall is here today and he’s testified before our committee

before, Mr. Chairman.

As I said, Southwest Ohio cares a great deal about clean air and

the environment. I think it’s appropriate that Cincinnati was chosen as the location for this hearing today. Just last month the U.S.

EPA issued a proposed rule to redesignate Cincinnati as in attainment of the 1-hour ozone rule. I want to congratulate the greater

Cincinnati community for working on that through a variety of coordinated programs to improve the quality of Ohio’s air. And we’re

very hopeful that Administrator Browner will quickly act to finalize

the rule following the close of the public comment period.

Incidentally, Mr. Chairman, when I first entered office in 1991

as Governor of the State of Ohio, most of Ohio’s urban areas were

not attaining the 1-hour ozone standard. By the time I left in 1998

all but Cincinnati were in attainment. So we’re very, very proud of

the fact that we’ve achieved that standard. And as you know, I

have been very concerned about the new proposed standards for

ambient air particulate matter and part of the reason is because

we worked so doggoned hard to reach the 1-hour ozone standard.

And as many people in this room know, I testified in your committee. The chairman helped us with that, and finally had to go to

court over those regulations. A U.S. Appeals Court several weeks

ago remanded EPA’s ozone and PM2.5 standards ruling that the

EPA did not justify its decision with sound scientific evidence. So

that we want a clean environment, but we want reasonable rules.

Now, we’re here today to talk about the New Source Review Program and the proposed changes to the program. I think the chairman has done a good job explaining the history of it.

We have a clean air statute. While I have some concerns about

the law, it has done a great deal to clean up the nation’s air and

has improved public health and the environment. We need clear

guidelines on how EPA will enforce provisions of that law and we

need clear rules for industry to play by.

I think you are going to be having a series of hearings, Mr.

Chairman? Perhaps next year, we’ll look at reauthorizing the Clean

Air Act?

Senator INHOFE. Yes. We have two more this year. We’ve already

had one. Then we’ll start the process, and we set a rather ambitious schedule for completing it.

Senator VOINOVICH. I think it’s important to look into the problems created by the New Source Review Program and look for the

solutions needed to clarify the rules, and I commend U.S. EPA for

taking on that task. Whether we’re talking about the electrical utility, pulp and paper, or refining industries, one thing is clear: it is

important for them to know the rules of the game. It should be

clear to them what kinds of repairs can be made before triggering
4

New Source Review, because repairs need to be made in a timely

manner to insure worker safety and reliability of service, particularly electricity. So I urge the EPA to take into consideration the

unintended consequences that are associated with this issue. We

need to insure that this rule will help maintain air quality standards, but we also need to insure that needed maintenance repairs

can be made so as not to jeopardize worker safety or the reliability

of needed services.

I also want to raise concern about the length of time it takes to

receive a New Source Review permit, either to build a new facility

or to make changes in an existing facility. I’ve been told that the

standard timeframe is between one and 2 years. I also understand

that even getting a determination on whether a New Source Review permit is needed is also a timely process. I’m not sure that

most industries can withstand that kind of timeframe without suffering serious consequences. A plant operator needs to make a decision much earlier than that to insure worker safety and, particularly, reliability of service.

In addition, competitiveness is called into question. For instance,

if a computer chip manufacturer wants to build a new plant it is

likely that the technology will have changed during the time it

takes to get an NSR permit and build the facility. I just think there

needs to be some balance here.

So, again, I commend the agency for moving forward to reform

the program and I hope that it will keep those issues in mind as

it proceeds forward. I am pleased that the EPA has worked with

various stakeholders during the rulemaking process, and I strongly

encourage them to do the same with the electric utilities. You learn

more through communication, and that’s what I hope will be

achieved today through this hearing and will be achieved as the

EPA continues the stakeholder discussions.

Mr. Chairman, I ask that my statement be made a part of the

record.

Senator INHOFE. Without objection.

Thank you, Senator Voinovich. I sometimes find that people in

the local community are not as aware as they are in Washington

in certain areas of expertise as the people who represent them. I

was very pleased to have had one of the toughest jobs in the world,

that is to be the mayor of a major city, when we were mayors together. And way back at that time and up to the present, Senator

Voinovich has been one of those individuals who has been an expert in the field of clean air. And as he mentioned, he actually

came as Governor of Ohio and testified before the committee that

I chaired, the committee that we’re in right now.

I’m very happy to have Ted Strickland here, who I served with

in the House. And while you’re coming up, Congressman

Strickland, let me just kind of give you an overview of what we’re

going do today. We’ve got a lot of people here. We’ve got four panels

and then one panel has several on it. So with all seven witnesses

we’re going to have to keep moving along.

I also mentioned that some of the Senators who are not here

today, their staff is here; and they’re going to be taking information

back to their Senators in Washington but some of them could not

be here today.
5

Each witness will be allocated 5 minutes to give his opening

statement. They’ll be lights. And I see Andrew Wheeler brought his

lights from Washington here. It’s red and yellow and green. I think

we all know what that means. So with that we will go ahead and

begin.

And, Congressman Strickland, it’s a pleasure having you here

with us today in your district.

STATEMENT OF HON. TED STRICKLAND, U.S.

REPRESENTATIVE FROM THE STATE OF OHIO

Representative STRICKLAND. Thank you. Thank you, Mr. Chairman. Thank you for your coming to Ohio. And Senator Voinovich,

I especially want to thank you for the fact that you have shown

leadership in supporting one of Ohio’s great resources, and that is

the use of and continued use of coal. That’s certainly very important to my district.

I do represent the Sixth District. It’s a 14-county, sprawling district, from Warren County in the west to Washington County in the

east. This part of the State offers beautiful natural forest land,

some of the most pristine farmland in Ohio, and many unique historic sites.

Briefly, I just would like to share this morning some troubling

statistics from my district and my concerns about EPA’s New

Source Review Program. I think together this information demonstrates the need for meaningful reform of the NSR program so

that we can strike a better balance between the pace of desired environmental benefits and the increased productivity anticipated

through economic development initiatives.

As Senator Voinovich knows, the Sixth Congressional District is

one of the poorest in Ohio and even the country. It has the lowest

per capita income and the highest poverty rate of any district in

Ohio. Unfortunately, southern Ohioans have not experienced the

full economic recovery that most of the U.S. has enjoyed. The Sixth

District includes Meigs and Vinton Counties, which have among

the highest unemployment rates of any of Ohio’s 88 counties, 11.1

percent and 13.8 percent, respectively, compared to a statewide average of 4.3 percent. These statistics clearly underscore the region’s

enthusiasm for economic development opportunities and its fear of

regulations which may hamper job creation. Without a doubt, low

cost energy and high quality manufacturing labor are vital to the

economic prospects of the region.

A substantial number of the labor force, more than 25 percent,

is employed in the manufacturing sector. And this region provides

a significant number of jobs in the utility, mining, and refining sectors. Southern Ohio cannot withstand the loss of these jobs and it

certainly cannot afford to overlook any opportunity for job creation.

I have heard from the International Brotherhood of Electrical

Workers, who raised specific issues about EPA’s New Source Review proposed rule, and it should come as no surprise that one

such concern is job loss. Under the current NSR program, decisions

could be made to shut down utilities rather than venture into the

confusing NSR permitting program to undertake what could be

considered routine maintenance activities. Obviously this would result in layoffs.
6

As you know, the New Source Review was first introduced as

part of the 1977 Clean Air Amendment. The program was designed

to insure that newly constructed facilities and substantial modifications of existing facilities do not result in the violation of applicable

air quality standards. The New Source Review Program is acknowledged to be a very complicated program and a potential bottleneck

to many positive community development projects, including

brownfields redevelopment and the manufacturing facility improvements and modernization.

For example, the specific requirements dictated by the New

Source Review Program depend on the location of the facility. If a

plant is cited in a part of the country that fails to meet the national ambient air quality standards for a pollutant, one set of requirements apply. If a plant is in a max attainment area, another

set of rules apply. As you can imagine, some facilities may rest in

a region that is considered in attainment for some criteria pollutants but not others, complicating the requirements even further.

Let me quickly describe some frustrations my constituents and

others have shared with me concerning this program. I’ve learned

that merely determining whether the program applies to a project

depends on complicated rules and guidelines which have been subject to 20 years of EPA’s interpretation. I’ve also been told that

EPA could require a preconstruction permit under NSR for the replacement of worn equipment parts even though the replacements

are only modifications and not new construction.

I know the EPA claims many successes under the NSR program,

and I applaud the reduction or prevention of pollutant emissions.

The environmental protections afforded under the NSR program

should not be minimized here today; however, the EPA’s most recent proposed changes to the NSR lead to considerable controversy

and the agency acknowledges the need to build a more flexible program and streamline the permitting process. I would suggest that

a truly meaningful reform of the NSR program can actually lead

to even greater environmental benefits in the future.

And in closing, let me say that this past fall I raised the concern

that the EPA should not short-change the discussion on meaningful

NSR reform. I am pleased to hear that a full review of approaches

to NSR reform is ongoing. Without sufficient dialog among the interested parties, I have little confidence that a workable solution

can be reached.

Therefore, I would like to state very clearly that congressional

oversight of this process does not stop here in Cincinnati. Indeed

I think today’s hearing demonstrates that both senators and representatives will continue to monitor the progress made to reform

this program. With hard work and cooperation I believe an equitable proposal can be crafted that creates an efficient NSR rule

without unnecessary pitfalls and establishes a proper balance between environmental benefits and economic progress.

Mr. Chairman, in closing let me thank you once again for holding

this hearing and Senator Voinovich for bringing it to Ohio. Thank

you very much.

Senator INHOFE. Thank you, Congressman Strickland. I hope it’s

obvious to everyone that this is not a partisan thing. We are all

concerned. First of all, Democrats and Republicans alike want
7

clean air. Democrats and Republicans also want fair treatment.

During the course of our little news conference out here I told them

the major concern I had is the unpredictability. People don’t know,

and that’s what we’re here to find out today, if they know what

they can properly plan for in advance, how much time it’s going to

take to comply.

I guess you would agree, Congressman Strickland, that both

Democrats and Republicans feel that the dialog between the EPA

and the stakeholders should continue?

Representative STRICKLAND. I think it’s essential. And I think, as

I said near the close of my statement, that it’s incumbent upon

those of us who are in the House and those of you who are in the

Senate to make sure that this process proceeds in a manner that

involves meaningful dialog and input from all stakeholders.

Senator INHOFE. I’m sure this will be a surprise to you when I

say it, but we have witnesses today who are testifying that the

EPA has issued conflicting guidance on this program over the last

20 years or so. I know my constituents are concerned with that

back in Oklahoma, and you have some that are concerned with

that here.

Representative STRICKLAND. Well, they absolutely are, and it’s

important for a Federal agency to proceed in a fair manner. And

I am troubled by some of the actions which seem to reach back to

apply rules or interpretation of rules retroactively. That troubles

me greatly. I see no fairness to that, and I think it’s our responsibility as elected officials to make sure that what happens is done

in a fair and a justifiable manner, and that’s why I’m here today.

Senator INHOFE. Because of the time constraints and the number

of witnesses, we had to restrict the opening statements. You were

talking about the frustrations of your constituents. Did you get a

chance to complete that thought?

Representative STRICKLAND. Well, I did not but I’ll submit it for

the record. So many of my constituents representing both working

folks, members of the work force, as well as the management of

some of these facilities, are terribly concerned and justifiably so.

And that’s why I am so pleased that you’re holding this hearing.

Senator INHOFE. I think that’s one of the issues here, Representative Strickland, that we have. Both labor and management are

the big losers if we become noncompetitive. And I know—I can’t

speak for Ohio, but I can in Oklahoma. We’ve had some businesses

actually have to leave and go across the border. And, of course,

we’re a little closer to Mexico, and we’ve lost a ton of jobs in Oklahoma as a result of this. And I assume that you have some examples here in Ohio, also.

Representative STRICKLAND. Well, I think there is great fear, as

Senator Voinovich said a little earlier, the concern about the lack

of predictability and not knowing what interpretations are going to

be made regarding which regulations and how they are going to be

applied. It seems to be one of the most troublesome aspects of this

situation.

Senator INHOFE. Senator Voinovich?

Senator VOINOVICH. I’m interested in reading the letter from

the—was it the president of the IBEW?

Representative STRICKLAND. Yes.
8

Senator VOINOVICH. Are you aware of the fact of whether or not

that organization is participating at all in the negotiations that are

going on in terms of the rulemaking?

Representative STRICKLAND. I am not aware as to whether or not

that particular organization is, but it’s a good question. I certainly

will talk with him. It seems important to me, Senator, that all

stakeholders be given a voice in this process and be listened to.

And that’s the only way I think we can come to a consensus that

is going to be widely embraced by all parties.

Senator VOINOVICH. Well, I’m a big believer in quality management. I think so often when we talk about these things that we

don’t really bring in the people that are actually doing the work

and have the insight into what some of this means. So often you

get an engineer from some company that says, well, this is the way

it is, and the other person on the other side says what he has to

say. And if you had somebody that was really doing the work at

the table with them, they’d have a much better understanding of

what it’s about. And I would hope that representatives here from

the EPA make sure that some of those people are involved who are

actually out there getting the job done in terms of——

Representative STRICKLAND. Absolutely. If I can just say as a

concluding statement here, my district is a unique district but it

is also a district not unlike other districts across the country in

terms of its economic needs and in terms of its past history of having heavy manufacturing jobs and so on. And it is really troubling

to me that a district like mine, and districts like mine across this

country, could find themselves in an ever more difficult set of economic circumstances at a time when they really need to be able to

make economic progress and to attract industry and create jobs

and so on.

And quite frankly, in perhaps a selfish way, that is the primary

motivation behind my speaking out on this issue, and I think it’s

very important. It’s important to my constituents and to the industries which serve my constituents. Thank you very much.

Senator INHOFE. Well, let me just—I think what Senator

Voinovich is suggesting is something that is a very good idea, to

bring them in, the labor force in. They have just as much to be concerned with as anybody else. So I would like to ask you specifically

to encourage them to do that, maybe today, to make some calls and

get an involvement.

I would also like to say that Senator Voinovich mentioned the

ambient air proposed rules that we went through for about 2 years.

And we held a field hearing out in Oklahoma. We had your Lieutenant Governor and several people from Ohio out there, and it

seems like Oklahoma and Ohio have a lot of things in common in

terms of regulations. So it’s nice to have you here to testify. Thank

you very much.

Representative STRICKLAND. Thank you, Senator.

Senator INHOFE. Now, I’d like to ask our second panel, Mr. John

Seitz, Director of Office of Air Quality Planning and Standards. Mr.

Seitz is a regular here and we always are able to get a lot of

healthy compromises and communications, and I appreciate very

much your coming today.

Mr. SEITZ. Thank you, Senator.
9

STATEMENT OF JOHN S. SEITZ, DIRECTOR, OFFICE OF AIR

QUALITY PLANNING AND STANDARDS, ENVIRONMENTAL

PROTECTION AGENCY

Mr. SEITZ. Good afternoon, Mr. Chairman and Senator Voinovich.

I thank you for the opportunity to be here today on behalf of the

administration to talk to you about the New Source Review Program. Enacted in Congress in 1977, the program’s goal was to minimize air pollution from large, newly built, and modified industrial facilities. Recent figures suggest that over the life of the program NSR

has prevented move than 100 million tons of pollution from getting

into the air. The NSR program insures that when companies upgrade their facilities in a way that increases air pollution that they

also take specific measures to minimize those increases. Upgrading

pollution controls in the industrial infrastructure simultaneously

make good economic and environmental sense. It’s a simple concept

that has been working in the NSR program for almost a quarter

century, protecting our nation’s air resources and makeing a critical part of the air quality program. The NSR provisions of the Clean Air Act combine air quality planning, air pollution technology requirements, and stakeholder

participation. The only time NSR applies is when a facility makes

a change that could significantly increase air pollution. This means

a facility can make any change it wants so long as emissions could

not increase. If a facility is unsure whether a change will trigger

NSR review, there are many resources available to help them answer that question, most notably the State and local agencies.

States are key partners in this program. Under the Act generally

the States have the primary responsibility for issuing permits and

they can customize their NSR program within the bounds of the

EPA regulations.

The NSR permit program for major sources has two different

components: one for areas where the air is dirty or unhealthy, and

the other for areas where the air is cleaner. In areas with

unhealthy air, NSR assures that the sources do not impede

progress toward cleaner air. In areas with clean air, especially pristine areas like national parks and wilderness areas, the program

assures that emissions from new and modified sources do not significantly degrade the air quality. The program assures citizens

that if any large industrial source being built or modified in their

neighborhood, then the pollution aspects are addressed.

Permits for sources located in attainment areas are known as

prevention or significant deterioration—or PSD—permits. Permits

for sources located in areas not meeting the National Ambient Air

Quality Program are known as NSR permits. A major difference in

the two programs is that the control technology requirement is

more stringent in the nonattainment areas.

Let me give you a few statistics about the NSR program. Our

most recent data indicate that approximately 1 percent of large facilities or roughly about 250 facilities of 20,000 industrial facilities

in this country are going through the NSR program annually. Recent data also show that these permits have prevented about a half

a million tons per year of pollution from entering the environment.

It’s remarkable that annually less than 1 percent of these large
10

sources are involved in the program, yet so much pollution is averted. These emission reductions are being achieved at the same time

as the unprecedented economic expansion. We believe the program

is achieving its goal.

In addition to the emission reductions, the NSR program has

sparked improvement in pollution control and pollution prevention

technology. This technology forcing aspect of the program is an important reason why it has been so successful in allowing for continued economic growth while insuring environmental protection. It

also helps the United States to be a leader in the export of pollution control technology.

Despite the success of the NSR program, we have been actively

working with many different stakeholders on all sides of the equation to help find ways to make the program work more effectively.

I described some of those in my written statement which has been

submitted for the record. We have worked very hard to be inclusive

and comprehensive in our analysis of the stakeholder concerns.

Since 1992 we have held hundreds of hours of meetings actively

seeking comments and recommendations from various stakeholders. We formed the NSR Reform Subcommittee of the Clean Air Act

Advisory Committee, a group of experts from industry, environmental groups, and State and local governments, brought together

for the purpose of making recommendations for improving the NSR

program. We listened to the analysis and debate from a wide variety of often opposing viewpoints. We issued a proposed rule in

1996, took comments, and held a public hearing on that rule. Since

then we have continued to have meetings with stakeholders. As recently as last week we held another meeting with an industrial

group.

Our fundamental principle during this reform effort has been to

promote more certainty and flexibility in the permitting process

while maintaining at least the same level of environmental protection. We are examining the idea of promoting flexible plant-wide

caps that would enable sources to make changes at their plant

without meeting NSR’s program so as long as the overall environmental cap is met. More examples are included in my written

statement.

We are also considering other options to provide flexibility for a

specific industry while protecting the environment. For example,

we recently held meetings with our stakeholders to obtain views on

the concept of a sector-based approach for utilities. This would tailor the NSR regulations in such a way as to address issues unique

to the utilities while still providing the overall environmental protection envisioned by the NSR program.

We continue to discuss several issues with stakeholders and have

not reached final decisions on the reform rule. However, we hope

to complete the NSR rulemaking, as you indicated, later this year.

Mr. Chairman, this concludes my statement. I appreciate the opportunity to be here today and I would be happy to answer any

questions you have.

Senator INHOFE. Thank you, Mr. Seitz. Mr. Seitz, I get conflicting

reports as to the length of time it takes to apply for and to receive

a permit under the NSR program. I know you keep records of

these. Can you give us what your records show?
11

Mr. SEITZ. Yes. I’d be pleased to give that to you for the record,

Senator.

Senator INHOFE. No, just for today’s oral testimony, I’m sure

you’ve looked at this before.

Mr. SEITZ. I was a little surprised by the comment of one to 2

years. I acknowledge that there are some permits that take over

that period of time after completing the application, but we believe

that the majority of those are issued within the timeframe of 12

months, as set forth in the statute. However, industry has brought

to the table in the reform effort—I think the microchip, the computer chip was a good example you brought out—that they need

the ability to make changes quickly in the permitting process. They

need more certainty, more speed in the permitting process. So we

are currently looking at that and hope some of the efforts in terms

of PALS and the technology clearinghouse can address some of

that.

Senator INHOFE. I’d like to have kind of an average just off the

top of your head, 6 months, a year, 2 years?

Mr. SEITZ. I’d say it’s probably from 9 to 12 months at this point

in time.

Senator INHOFE. Nine to 12 months would be somewhat of an average?

Mr. SEITZ. Right.

Senator INHOFE. Now, who issues——

Mr. SEITZ. That’s from the complete application. Sometimes there

are problems getting a complete application. But once the application is in the hands of the States, I’d say 9 to 12 months.

Senator INHOFE. First of all, who receives the permit applications, the EPA or the States?

Mr. SEITZ. The States.

Senator INHOFE. The States. And then who reviews them at

EPA?

Mr. SEITZ. Well, it depends on the program, sir. If it is a SIPapproved program such as in Oklahoma, the State is the primary

reviewer during the public comment period on the permit. The EPA

regional office provides comments on some permits, but not necessarily all permits.

Senator INHOFE. In planning new regulations which will result in

the increase of permit applications, something that hasn’t been

talked about very much is who is going to pay for this? How much

additional work load is going to be incurred in terms of the EPA,

in terms of the State? Have you done a study of that, on work load,

how we’re going to accommodate that?

Mr. SEITZ. No, sir, I have not. We have not completed a study

on that, yet. It’s unclear to me at this point in time that as a result

of the final reform package that we will have an increased number

of permits that will actually go through the system. It is hoped that

with some of the innovations such as plant-wide applicability limits, the process would actually, narrow that some. When we do the

final rulemaking, we will have to put forward an analysis as to

what the total cost and burden would be, which we have not done

as of yet.

Senator INHOFE. Prior to the rulemaking?

Mr. SEITZ. Prior to the final rulemaking.
12

Senator INHOFE. Oh, OK, yes.

Mr. SEITZ. Yes.

Senator INHOFE. The other witnesses, Henson and others, I’ll

probably be asking you the same question, but I’d be interested in

knowing how this—at our news conference, and I think Ted

Strickland mentioned this too, what this does to our competitiveness if we have these lengthy permit periods of time, how do you

think that would affect our competitiveness compared to other

countries?

Mr. SEITZ. Again, planning is the cornerstone of this program, as

I said. The intent of the program when Congress put it together is

that as a plant expands and plans on increasing its capacity, the

environmental protection is protection addressed as a critical component of that. So I would hope that in the permit process the industrial sector would consider environmental protection as essential to the permitting application, and we need to preserve that aspect of the program along with the reforms to expedite the permitting process. Again, that is part of the effort of the reform process

we have underway.

Senator INHOFE. This is a concern to me because in Oklahoma

we have some specific examples that I talked about the last time

we had a hearing in Washington.

It’s been suggested that the New Source Review reform process

is being steered in the direction of trying to get the same emissions

reductions from the same sources as the 8-hour ozone and fine particulates and NAAQS set aside—they’ve been set aside by the D.C.

Circuit Court of Appeals. And the NOx SIP call and Section 126,

we’re talking about three different things which are pending before

that same court. Now, you’ve heard this and you’ve talked about

this before. What is the agency’s response to that notion?

Mr. SEITZ. I don’t quite even understand how one could say that

the NSR program is supplementing the NOx SIP call under section

110 of the Act. NSR is a source-specific facility, case-by-case decision. As you know, the NOx SIP call was across a given region

based on a nitrogen budget for each State.

Some of the alternative approaches we are examining in NSR reform voluntary approaches such as PAL or the sector-based approach for utilities. They clearly are voluntary programs and have

nothing to do with the NOx SIP call.

Since it would be a voluntary offering, I don’t know how it could

be something that supplements the NOx SIP call.

Senator INHOFE. Yes, I’m running out of time here. Just one last

question. In the January 3, 2000 issue of the well-known trade

journal Electric Utility Week, Administrator Browner is quoted as

saying in reference to a just announced final ruling granting the

Clean Air Act, Section 126, petitions filed by the northeastern

States asking for NOx emissions reductions from midwestern and

southeastern States, ‘‘we’re going to get there one way or another.’’

What do you think she meant by that?

Mr. SEITZ. I think the Administrator’s position is that we are

going to get the clean air. Every American is deserves clean air,

and she meant that we have to work together to achieve that.

Senator INHOFE. Not to get to those standards that are under

court review one way or another?
13

Mr. SEITZ. I didn’t read it that way.

Senator INHOFE. OK, Senator Voinovich?

Senator VOINOVICH. When Administrator Browner appeared before our committee last week on her budget, she talked about overall reduction in the budget but an increase of 11 percent in the administrative part of the budget.

Are you aware of any additional money that’s going to be made

available for this procedure, the people that handle this New

Source Review?

Mr. SEITZ. Senator, at this current time I am unaware of that.

I’m not aware of what the final pass-back numbers would be.

Senator VOINOVICH. Well, I’m interested with talking about the

timing though. The real decision on this, the application is submitted to the State agency and they go through it. But is it in Washington that that decision is made or is it made in the regional office

in terms of this particular review?

Mr. SEITZ. In terms of the review and who conducts the review,

that decision is in terms of the delegation. For instance, Ohio and

Oklahoma have different types of programs. Maybe it would be

helpful to describe them. The Oklahoma program is administered

by the State under a State-approved regulatory program that was

adopted in the Federal rulemaking. The State of Oklahoma issues

the NSR permits.

The State of Ohio’s program is delegated program. The State did

not choose to get a federally approved program so, therefore, the

State is acting as an agent for EPA. In Ohio when a permit is issued by the State it is actually a federally issued permit, and Ohio

acts as the agent for EPA. So the regional office—it is in Chicago

for Ohio—would be more closely involved. An appeal of that permit

goes straight to the EPA.

It’s my understanding the State of Ohio is working to change

that now. This process contrasts with the appeals in Oklahoma,

which go to the State.

So the decision on where the permit goes and how it is reviewed

depends on that State’s structure. In Ohio, the regional office is

more involved. In Oklahoma, the permits would be decided on a

case-by-case decision. The funding of the program is an overall

budget decision that is made out of Washington.

Senator VOINOVICH. I’m interested in that. As I say, I’m a big fan

of quality. And I know that as Governor of the State we had a lot

of agencies that did a lousy job of permitting, and we made a real

issue of that. We instituted quality management in our State agencies. I recall underground storage tanks. Ninety percent of the applications that used to be submitted were rejected because the people didn’t understand the form. They spent a couple of months

working on that issue, the people that actually issued the permits.

They spent time with their customers, revised the application.

Today there is only a 5 percent rejection. So that speeded up the

process right off the bat, because people didn’t understand the

process.

Maybe it’s a governmental thing, but I really want to know how

you handle this. I want to kow what the manpower is and is it——

Mr. SEITZ. Well, in light of what you just said, particularly in

terms of total quality and what you might do in the State of Ohio
14

or Oklahoma, the internal timeframe is governed by the State. EPA

does not set that. The statute says 12 months. The period of time

the State agency chooses to, say, take phase one or phase two, is

totally within their discretion. So to the extent that some States

have, as you said, maybe in Ohio with the total quality aspect of

it, have implemented processing changes that make it more efficient, that is totally within the State’s capability right now. I think

through STAPPA/ALAPCO, which are the State and local air associations, share those experiences.

So within that timeframe the only thing we govern is the 12

months.

Senator VOINOVICH. Well, I’d like you to get back to me on that.

I’d also like to know how much of EPA’s new budget are they putting into the program.

Mr. SEITZ. I’d be glad to answer that for you.

Senator VOINOVICH. You’re going to hear testimony today that

will surprise you. People have been doing things according to the

rules and all of a sudden they are finding out that they are supposed to have violated a process. They should have been able to get

the permits reviewed and issued. Just what is the attitude of the

agency toward those kinds of claims?

Mr. SEITZ. Well, most frequently, in the examples you’ve given I

was actually sort of surprised at some of it. And you referenced

some of it in your statement, Senator Inhofe. As mentioned, these

rules were put out in 1980. Routine maintenance, or that issue of

maintaining, was put in in 1988 and 1989, put out as guidance,

and that was upheld in the courts. And since that time we, EPA,

has received very few written requests for an interpretation of that

definition. So I am somewhat surprised that if it is so confusing

and confounded why we have heard so little? There are questions

about the other programs I administer; and Senator Inhofe has had

the opportunity to quiz me on some of them in the past. I get hundreds of requests for interpretation, whether it is a MACT program

or Title I program.

So with respect to this issue, I receive relatively few questions

in that area. In contrast, I receive lots of requests for information

on modeling: how you do attribution, etc. On the issue of what is

and is not routine—very few. I think we have to look closely at that

as we go forward. I’m hearing that today.

Senator VOINOVICH. There is a question about whether or not

when you’re coming up with the final rules on this whether you’re

going to be concerned about electricity reliability. One of the things

that is a big issue now with the proposed 85 percent on the NOx

that the agency is requiring, is that many of the utilities are complaining about the fact that if they would go forward with that that

they would have a real reliability problem. And there also is some

real concern about ordinary maintenance of facilities that involve

the well-being of people who are working for those agencies. And

in terms of just providing reliable electricity for people that are—

you know, the benefits of the company. What comment do you have

about that?

Mr. SEITZ. Senator, as mentioned last summer when this first

came up in connection with the SIP call, the Administrator said at

that point in time if anyone is concerned about their ability to
15

produce electricity because of either brown outs or shortage contact

us because we do not believe this program will jeopardize the

power supply of this country.

With respect to the issue of whether or not routine maintenance

can go on at a facility, as I said in my statement, the test here is

really simple. I know there’s a lot of debate around it, but the test

here is really quite simple: Are there going to be emission increases

as a result of what you’re doing?

Senator VOINOVICH. May I ask one last question? I know I’m out

of time here.

Senator INHOFE. Sure.

Senator VOINOVICH. The issue of cost benefit in making a decision, and based on the technology that’s available, does that ever

get into the decisionmaking process?

Mr. SEITZ. Specifically you’re referring to the decision of whether

to apply back the Best Available Control Technology—BACT. One

of the factors in that decision is cost, like the age of equipment. So,

yes, cost benefit is looked at in making decisions.

Senator VOINOVICH. Good.

Mr. SEITZ. We take a look at the incremental costs, the marginal

costs, social impacts, cost of energy. Those are specific criteria that

are set forth in the statute.

Senator INHOFE. Let me ask you one followup question and feel

free to do the same thing.

Mr. Seitz, I understand that part of your proposed rule would require facilities to look at what they actually emit today and then

compare that to what they potentially could emit after equipment

changes. And it seems to me this is kind of apples and oranges,

that any facility could potentially emit more than they actually

emit without making any equipment changes. All they have to do

is run at full speed or increase the number of hours that they’re

emitting more pollutants. Would it make more sense to compare

the actual emissions before an equipment change to the actual

emissions after an equipment change. It seems like you anticipate

that everyone runs at full capacity a hundred percent of the time.

Mr. SEITZ. Well, again, Senator, I think you have to go back to

another provision in the Clean Air Act about the contemporaneous

period in which you determine what the actual is. So when you

make a change you assess the last 5 years of emissions data. Then

you project forward to see, based on the proposed changes, what

you could do in the way of production. If, based on the proposed

changes, you have the ability to produce 100 products an hour, instead of 10 products an hour, there could be more pollution. Granted you’re not at that level yet. A source has the ability to say, ‘‘We

never plan to emit. We want to address the technology issue now

and put the technology on.’’ They would have, through the State

permitting program, the ability to take on an enforceable cap to address that.

But the basic concept is if there is a potential to increase the

emissions, then the impact on the environment has to be addressed.

Senator INHOFE. But why couldn’t you just compare the present

potential to future potential? Then at least you’re comparing the

same things.
16

Mr. SEITZ. Let’s say that a facility in the last 5 years has only

produced 10 units. However, when the plant was built 30 years

ago, it was designed to produce 100 units. Is it fair to say that the

design capability should meet an environmental permit that is

based on 30 units 20 years ago should be the design criteria now,

even though the standard has not been achieved in 30 years? We

think that that’s not what the statute——

Senator INHOFE. OK, I understand your answer. I disagree with

it, and I’m going to be asking some of the—Panel 3 and 4 the same

question.

Do you have any further questions of Mr. Seitz?

Senator VOINOVICH. No, I haven’t.

Senator INHOFE. Thank you very much, Mr. Seitz. I appreciate

your being here.

Audience speaker. Senator, would you indulge me for a second,

please?

Senator INHOFE. No, sir, we won’t. I’m sorry. I don’t want to be

rude, but we have to comply with our rules. This is the way things

get out of hand. We would run out of time, sir. I’d ask you to please

sit down.

I’d ask now Mr. Bynum to come forward. Most of the witnesses

today are either industry or government, and I think Mr. Bynum

is a hybrid. Which are you, Mr. Bynum?

Mr. BYNUM. I’m a hybrid. You’re absolutely right, Mr. Chairman.

Senator INHOFE. By the way, I would like to have all of the panels to understand that you’re entire statement will be made a part

of the record, but for time sake we have to do this. And that’s why

I always regret having to not deviate from the published rules by

not allowing people from the audience to join in. When we’re on

time constraints, that takes away from our invited witnesses.

Mr. Bynum?

Mr. BYNUM. Thank you.

STATEMENT OF JOE BYNUM, EXECUTIVE VICE PRESIDENT,

FOSSIL POWER GROUP, TENNESSEE VALLEY AUTHORITY

Mr. BYNUM. Mr. Chairman, thank you for the opportunity to testify before the subcommittee today. In my testimony I am providing

the committee with the views that are solely those of the Tennessee Valley Authority. I appreciate your interest in the Environmental Protection Agency’s proposed changes to the New Source

Review Program, which will have a lasting impact on the operation

of individual fossil plants and, in fact, the reliability of our nation’s

electric system.

TVA has been operating various kinds of generating technology

for more than 65 years and has substantial expertise in the maintenance of fossil plants. I am here today to represent TVA’s dual

responsibilities as a power producer and an environmental steward.

Although there has been some criticism of its complexity, the

TVA believes the NSR program has generally been a success. The

EPA has largely applied the program’s requirements in a way that

does not impede routine maintenance or efficiency improvements of

the nation’s electric generating resources. TVA believes such improvements, long a part of routine maintenance, are desirable to in-
17

sure a reliable supply of electricity and are in the public interest.

As the person responsible for the operation and maintenance of 59

coal units, I urge great caution as EPA contemplates changes to

the program. Unfortunately, some of the ideas being discussed can

discourage such desirable improvements and have a detrimental

impact on the electric utility industry’s ability to safely and effectively operate our plants.

The current NSR regulations have long excluded routine maintenance, repair, and replacement projects at existing sources. Historically the EPA has employed a common sense understanding of the

term that encompasses those maintenance activities that are customary in the industry but optimize reliability, safety, availability,

and efficiency. It would be a serious mistake in its rulemaking for

the EPA to change its historic interpretation of the definition of

routine maintenance. The EPA should not make changes to the

program that discourage utilities from making improvements that

increase plant efficiency and improve reliability. The utilities in the

eastern interconnect have strained to meet demand and keep the

lights on the last two summers. Now more than ever utility maintenance programs are key to meeting demand and reliably serving

the public.

TVA has recently released a technical report on routine maintenance on the TVA system and in the utility industry. This report

demonstrates how important maintenance is for reliable service. I

would like to submit a copy of this report for the record.

Senator INHOFE. Without objection.

[The referenced report follows:]

ROUTINE MAINTENANCE OF ELECTRIC GENERATING STATIONS

TENNESSEE VALLEY AUTHORITY

(Gerry L. Golden Manager, Production Technology Fossil Power Group)

EXECUTIVE SUMMARY

The Tennessee Valley Authority (TVA) has more than 65 years of experience in

maintaining electricity-generating units with a wide range of unit size and technologies.

This report examines TVA’s maintenance philosophy and highlights specific TVA

and industry routine maintenance activities. TVA and utility maintenance practices

have as their goal unit reliability and availability and safe working conditions. This

report presents maintenance case studies including:

• Cyclone replacements (at least 300 replaced industrywide [43 percent]).

• Draft system replacements (at least 79 replacements of forced-draft systems

identified in a sample of 151 boilers [52 percent]).

• Reheater replacements (231 in a sample of 190 generating units [121 percent—

some units had multiple replacements]).

• Economizer replacements (98 replacement projects identified in a sample of

202 generating units [49 percent]).

A large number of variables affect unit components’ useful lives and dictate varying maintenance responses. These responses range from simply lubricating equipment to replacing components with improved materials to lessen component degradation and downtime. TVA’s analyses indicate that component replacement does

not occur at a certain age but varies widely, both within the TVA system and elsewhere in the industry.

The case studies presented herein are only illustrative of the broad range of maintenance, repair, and replacement activities necessary to ensure safe and reliable

production of electric power from coal-fired units. They do, however, provide insights

into commonly encountered failure mechanisms and the advancements in assessment and repair techniques that have occurred over the last three decades.
18

Introduction

A steam electricity-generating unit is a complicated machine consisting of thou- sands of separate parts and components that must be operated together in an integrated fashion to produce electricity. Like any complex mechanical system, an electricity-generating unit may suffer impaired performance caused by defects in design

or manufacture, extreme operating conditions, or catastrophic failure. This impaired

performance affects the economic performance of a unit and employee safety. In addition, it negatively impacts the ability to supply adequate and reliable electric energy to the public. To complicate matters, the unit’s component parts are subject to

different operating conditions and deteriorate at different rates. To ensure reliable

integration and operation of all of these parts, an active maintenance program is

necessary. The Tennessee Valley Authority (TVA) has more than 65 years of experience in maintaining various kinds of power-generating technologies. In the early 1930’s,

TVA began operating and maintaining hydroelectric units. When the public’s demand for electricity exceeded the region’s hydroelectric generation potential, TVA

turned to coal-fired steam generating units. Output from its hydroelectric and coalfired units was later supplemented by generation from nuclear units. Whatever the

choice of fuel or generating technology, maintenance has been and continues to be

the key to reliable operation of a unit throughout its useful life. In a 1972 report, two TVA power-system managers, T. H. Gladney and H. S. Fox, described TVA’s maintenance experiences to date and its maintenance philosophy.

Maintenance practices and techniques have improved since then, with better analytical tools and more experience, but the maintenance philosophy has remained unchanged for more than 25 years. TVA and other power-system operators try to attain and maintain the highest practical availability and reliability of generating assets while taking into account safety and economic and financial considerations.

Only through careful maintenance of generating assets can the public’s need for

electric energy be reliably and safely met. This report builds on the TVA maintenance activities documented in the earlier

Gladney and Fox work. First, information about TVA’s power system is provided.

The report then discusses the life of a generating unit, the utility obligation to

serve, and overall maintenance concepts in order to provide the fuller context in

which maintenance decisions are made. This is followed by several case studies of

specific maintenance projects and information about the frequency of similar maintenance activities on the TVA system and elsewhere.

TVA’s Electric Power System

TVA is an agency and instrumentality of the United States created by the Ten- nessee Valley Authority Act of 1933. Congress has tasked TVA with the development and conservation of the resources of the Tennessee Valley region in order to

foster the region’s economic and social well-being. One component of TVA’s regional

resource development program is the generation, transmission, and sale of electric

power. TVA’s power system now serves approximately 8 million people in parts of

seven States.

Generation sources currently operated by TVA include 11 coal-fired power plants, 29 hydroelectric plants, 4 gas-turbine plants, 1 hydro pumped-storage facility, and

3 nuclear plants. TVA’s 11 coal-fired power plants consist of 59 units, which are located in Alabama, Kentucky, and Tennessee. These units represent approximately

60 percent of the installed generating capacity on the TVA system. TVA’s oldest active coal-fired unit was placed into service in late 1951; the newest

unit was placed into service in 1989. Four of the units are supercritical units. The

unit boilers are a diverse mix of burner types and configurations: 26 are tangentially fired; 24 are wall-fired; 2 are cell burners; 6 are cyclones; and 1 is atmospheric

fluidized-bed combustion. Unit sizes range from 125 MWs to 1,300 MWs (nameplate

capacities). These boiler types and sizes are typical for more than 90 percent of the

United States coal-fired boiler fleet. All of the boilers originally burned medium- to

high-sulfur eastern coals, but a number of them currently burn coal blends consisting of low-sulfur western and medium- or high-sulfur eastern coals. TVA’s nominal

fossil fuel-fired capacity is now 19,917 MWs. TVA is widely recognized as one of the leaders in the utility industry. Throughout its history, TVA has championed the evolution of electricity-generating technologies

to improve efficiency and reliability and to reduce costs. Since the 1960’s many of

the major step increases in the size and economic performance of coal-fired generating plants have been taken by TVA. These steps included the construction and operation of:

• Gallatin Unit 1—first 300 MW tangentially fired unit in 1956;

• Widow’s Creek Unit 7—first 500 MW tangentially fired unit in 1961;
19

• Colbert Unit 5—first 500 MW wall-fired unit in 1965; • Paradise Unit 1—first 700 MW unit in 1963; • Bull Run—first 900 MW unit in 1967; • Paradise Unit 3—first 1100 MW unit in 1970; • Cumberland Unit 1—first 1300 MW unit in 1973; and • Shawnee Unit 10—first utility-scale (160 MW) atmospheric fluidized-bed com- bustion unit in 1989.

As Gladney and Fox stated, these units ‘‘. . . represented the largest units the turbogenerator and steam-generator manufacturers were capable of designing and

building; consequently, maintenance problems associated with prototype units were

faced during the entire period.’’ In its 1955 Annual Report to the President and Congress, TVA observed:

Because of the size of the TVA power system and its region-wide integration, TVA has been able to take advantage of the economies of ‘‘bigness’’ and to stimulate advances in steam-plant technology. Turbogenerators of unprecedented capacity and

greater efficiency have been purchased in multiple units of 2 to 12. As a result, the

new TVA steam plants have made excellent field laboratories for the manufacturers,

providing an opportunity for inspecting and testing a whole series of machines

under operating conditions. The later machines in each series could be improved

from the experience with earlier installations.

Many of the maintenance practices developed by TVA on these prototype units therefore became the practices that were adopted and refined by others in the industry. Today, many of TVA’s generating units are among the top performers in the coun- try, ranking in the top decile in efficiency and reliability.

The Integrated Steam Electric Generating Unit

A typical steam driven electricity-generating unit is a complex assembly of off-the- shelf components and custom-engineered equipment. Steam: Its Generation and Use

(40th edition 1992) by Babcock and Wilcox, and Combustion Fossil Power (4th edition 1991) by Combustion Engineering Inc., describe in detail from the equipment

vendors’ perspective the various kinds of boilers and their component parts.

The design, installation, and operation of boiler and turbogenerator component parts must be fully integrated in order to achieve the ultimate objective of generating electricity reliably, safely, and at the least cost possible. This integration is, even

for the simplest, smallest units, a major undertaking. Thousands of components and

pieces of equipment that are designed and supplied by different firms must ultimately be properly assembled, tested, and, almost always, tuned and refined before

a generating unit can be initially connected to the grid. Furthermore, it is not unusual for replacements of equipment and systems and refinements to operational

procedures to continue for months and years before a unit achieves its efficiency and

reliability objectives.

Maintaining integrated operation of all components is difficult because of the

large number of components and the varying stresses on components. Failure of a

component, or its failure to meet performance specifications, results in the inability

of a unit to perform efficiently or to generate at design capability and may even prevent the unit from generating at all. This is true for almost all components. Failure

of a critical electrical relay, sensing device, or valve can interfere with a unit’s ability to operate properly as much as can failure of larger boiler or turbine components.

The components and equipment of a generating unit face a wide range of operating environments and service conditions. These conditions range from the heat- and

humidity-controlled environment of a control room to the extremely harsh environment inside a large furnace. Heat transfer surfaces in a boiler must retain adequate

structural integrity to contain water/steam at pressures up to 4500 psi, the approximate equivalent to an ocean depth of two miles.

Components must retain this structural integrity while being exposed to furnace

temperatures exceeding 3000F; to highly corrosive gases; to deposition of corrosive

solid materials; and to erosion caused by high-velocity, abrasive solid materials.

Solid particles and water droplets traveling at supersonic velocities bombard steam

turbine blades. Dynamic forces from the formation and collapse of steam bubbles

can gouge chunks of metal from seating surfaces and rotating elements of control

valves and pump impellers. Insulation inside electrical generators must maintain

integrity while withstanding up to 24,000 volts.

Because of this wide variation in conditions of service, the service lives of individual components differ considerably. This affects the ability to maintain reliable integrated operation. Even the various components of a system or assembly do not have

the same expected service life. For example, the rotating elements of a steam tur-
20

bine, under design conditions, will require repair or replacement before the stationary components of the turbine. The superheater section of a boiler, which operates

in a substantially more hostile service environment than the economizer section of

the same boiler, typically has a shorter life than the economizer—even though the

superheater is made of higher grade materials that can tolerate very adverse conditions.

The power system may fail to meet its performance and reliability expectations because of design and integration errors. Components often fail to achieve their initially anticipated service lives. Poor quality control, manufacturing errors, design errors, and imperfect information regarding conditions of service can result in exposure to stresses higher than anticipated by the design engineer. Unexpected trace

materials in the fuel supply can result in higher corrosion. Improper operation due

to human error or failure of control components may also shorten component lives.

For example, a single overheating event can occur early in the life of a plant and

shorten the useful life of an entire section of heat transfer surfaces within a boiler

(e.g., a superheater or reheater). All of these circumstances eventually require some

form of maintenance response to ensure safe and reliable operation.

Advances in industry standards, metallurgical developments, and improvements in inspection procedures and performance-testing techniques can also result in reduced life for components. Codes and standards exist to minimize the threat of a

major safety-related failure. Industrial experience and increased knowledge of materials behavior can result in changes to these codes and standards that require removal of components from service earlier than anticipated by the designer. For example, in 1965 and again in 1991, the American Society of Mechanical Engineers

reduced the allowable high-temperature stress levels for 11/4 Cr. 1/2 Mo steel

(chrome-molybdenum, also known as T–11), which was commonly used in the

waterwall, reheater, and superheater sections of a boiler. This significantly affected

the assessment of remaining useful life for some of the boiler sections fabricated

from this material. Similarly, the development of improved nondestructive examination techniques for boiler tubes and other components allowed sophisticated assessments of the remaining useful life of pressure parts to be conducted, which in turn

allowed for planned replacements of wearing parts to be undertaken before a forced

outage required emergency repairs.

Life of a Generating Unit

Given the variations in the design life of individual unit components and systems,

the life of a generating unit depends upon how a unit is operated, how well it is

maintained, and other external factors. As a result, there is no preordained expected

life of a generating unit. For TVA and other generating utilities, there are in fact

two different concepts of expected life.

First, there is the project planning life or accounting life. When a decision is made

to put a new generating unit on line, a minimum expected lifetime is defined for

accounting or planning purposes. In other words, for a project to be viable, it must

be expected to perform long enough to generate sufficient revenues to provide a minimum targeted return on investment. In the case of for-profit entities, this minimum

expected life or ‘‘accounting life’’ also establishes the depreciation schedule, an important parameter in the economic evaluation of a new project because of tax considerations. TVA periodically adjusts its depreciation schedules to reflect current estimates of a plant’s remaining useful life. It is not unusual, however, for a generating

plant to become fully depreciated yet remain in service.

Second, generating units have a useful life, one that is based on a dynamic assessment of unit-specific internal and external factors to determine its continuing viability. Just as automobiles are not retired once the car loan is paid, generating units

are not retired from service at the end of their accounting lives simply because they

have been fully depreciated. Rather, they are retired when they no longer remain

viable assets. This means that units are removed from service when either:

The revenue they generate is inadequate to cover fixed plus variable operating

costs and to provide sufficient return on investment in needed component restorations; or Technological advances provide the opportunity for an investment in new

facilities to generate greater return on investment and lower cost of electricity than

could be achieved through continued operation of the existing facility.

Maintenance, repair, and replacement of unit components are necessary to

achieve reliable and safe operation of a generating unit throughout this useful life.

Since 1940, TVA has permanently shut down 24 steam-driven electrical power

plants. TVA acquired 23 of these plants from other power companies or from the

government. One of the 24 plants shut down was the Watts Bar coal-fired plant,

the first steam plant designed and constructed by TVA. Many of the plants included

in the acquisition of entire utility systems had internal combustion engines and
21

were retired immediately upon their acquisition. Others were coal-fired plants of

varying size and description that were shut down from 1941 to 1997 based on system needs and the relative economics of the individual plants.

Review of this retirement history shows that retirements of coal-fired units on the

TVA system have been limited to small (<60 MW) units that operated at low steam

pressure and low temperature and had high heat rates (low efficiency) compared to

other existing TVA units. Those units identified in Table 1 represent the largest and

most efficient of the coal units shut down by TVA.

Table 1

Thermal Conditions of Retired TVA Fossil Units

Steam Pressure (PSI)Steam Temp

(T)

Estimated

Heat Rate

(Btu/kWh)

Parksville ................................................................................................................. 250 575 21,000

Hales Bar ................................................................................................................ 365 725 18,000

Watts Bar ................................................................................................................ 865 900 11,400*

*Design Value

As demand grew on the TVA electrical system, substantially larger, more efficient

generating units were added. The significantly lower production cost of these new

units resulted in the older units being used less. This decrease in utilization led to

the old unite’ net annual revenue going negative (often, even net generation would

go negative). Retirement of the old units typically followed soon thereafter.

Table 2 was compiled based on information obtained from a review of TVA’s Annual Reports to the President and Congress in 1957–1959. Table 2 compares the average cost and capacity factor of the TVA-acquired units that were in service and

the average figures for the TVA coal system overall. For example, in the late 1950’s,

the average cost of electric power generated by TVA’s old, acquired units was about

4.4 to 6.5 times the cost of electric power generated by TVA’s new coal-fired units.

The acquired units were all retired in the early to mid-1960’s. (TVA retired the

Parksville, Bowling Green, and Watauga units in 1960, the Nashville plant in 1962,

Hales Bar in 1963, Memphis in 1965, and Wilson in 1966.)

Table 2

Financial Performance of JVA Coal Units 1957–1959

1957 1958 1959

TVA Coal System—Average Cost ($/MWh) ............................................................. 2.773 2.898 2.793

Effective Capacity Factor (%) ................................................................................ 90.110 77.960 82.200

TVA-Acquired Units.—Average Cost ($/MWh) ........................................................ 17.918 12.640 17.200

Effective Capacity Factor (%) ................................................................................ 4.440 4.740 3.130

* Generating units acquired by TVA from other power companies or from other government agencies from 1933 through 1950. Plants still active in 1957–1959 included Wilson, Nashville, Hales Bar, Parksville, Watauga, and Bowling Green.

This retirement sequence demonstrates that neither the accounting age nor the

actual age of units dictates when units are retired. TVA’s 1960 Annual Report indicated that the Nashville, Memphis, and Parksville units had reached the end of

their accounting lives; that is, they were fully depreciated. Yet, the 1960 retirements

included the Bowling Green and Watauga units but not the Nashville and Memphis

units. Table 3 provides a summary of the age of some of these acquired facilities

at the time of their retirements. Even in the 1950’s and 1960’s, unit age at date

of retirement ranged from just less than 30 to over 60 years, confirming that plant

age was not the motivation behind retirement.

Table 3

Age of TVA Coal-Fired Plants at Retirement

Generating Unit Retirement

Date

Age at Retirement

Hopkinsville ...................................................................................................................................... 1954 41

Parksville ......................................................................................................................................... 1960 46

Bowling Green .................................................................................................................................. 1960 28

Watauga ........................................................................................................................................... 1960 38
22

2 NERC is a not-for-profit organization responsible for promoting the reliability of the electric

supply for North America. This mission is accomplished by working with all segments of the

electric industry as well as customers. Electric utilities formed NERC in 1968 to coordinate efforts to avoid blackouts such as the November 1965 event that left 30 million prople without

power in the northeast USA and Ontario, Canada. NERC reviews the past for lessons learned

Table 3—Continued

Age of TVA Coal-Fired Plants at Retirement

Generating Unit Retirement

Date

Age at Retirement

Nashville .......................................................................................................................................... 1962 61

Hales Bar ......................................................................................................................................... 1964 40

Wilson .............................................................................................................................................. 1966 50

TVA’s most recent plant to be shut down was the Watts Bar Steam Plant. This

four-unit, combination wet-bottom/dry-bottom boiler plant was the first coal-fired

plant actually built by TVA. The units began operation in 1942–45. In only one decade, the unite’ operation was shifted from base-load to peaking mode following completion of the Kingston units in 1954–55. The technology of coal-fired generating

stations had evolved considerably during this period because of increases in operating temperature and pressure and the addition of steam reheating to the thermodynamic steam cycle. As a result, the new Kingston units were approximately 20

percent more efficient than the Watts Bar units (design heat rates of 9,400 Btu/kWh

compared to 11,400 Btu/kWh at Watts Bar) and produced electricity at costs substantially lower than the Watts Bar units. The generation from Watts Bar continued to decline as other generating units

were added to the TVA system until, as early as 1960, the net generation of the

plant was negative—it consumed more electricity when it wasn’t operating than it

generated when it was operating. The units were effectively retired at ages ranging

from 15 to 18 years. However, Watts Bar’s value as backup capacity exceeded the

cost to maintain it as a viable generating asset, so it continued to be staffed and

remained capable of operation. This changed in 1982 when an analysis indicated

that, for the number of hours of expected operation, it would be more economical

to generate the standby power from combustion turbines than to maintain full staffing and absorb the total fixed cost of the Watts Bar facility. As a result of this analysis, the plant was shut down and put into mothballed condition. Subsequently, in

1997 Watts Bar was permanently shut down—55 years after going into service.

Technological advances have continued to improve the efficiency and reduce the

variable operating costs of new generating units. However, these more recent efficiency improvements have not approached the giant strides that were made in the

1950’s and 1960’s. Additionally, the economy-of-scale factor that allowed the fixed

cost of the replacement capacity to be relatively small prior to 1970 is no longer relevant because there has been no increase in the size of generating units since the

early 1970’s. In fact, almost all of the new generating units added in the 1990’s have

capacities considerably smaller than those built in the late 1960’s and early 1970’s.

Simply stated, the more recent limited improvements in unit operating efficiencies

are not sufficient economically to justify the replacement of existing units, especially

when the public’s demand for electricity has continued to increase.

1 Refer to the care study on reheater replacement on p. 28 of this report for additional details.

Service Mandates

The TVA Act requires TVA to provide an ample supply of electric power to aid

in discharging its congressionally mandated responsibility for the advancement of

national defense and the physical, social, and economic development of the TVA region. The TVA Act also requires TVA to provide power at the lowest feasible rates,

which in turn requires that TVA generate power at the lowest feasible cost.

Maintaining generating units to ensure they are available to generate when needed is a critical element of any program to ensure reliability of supply. Maintenance

activities are also necessary to reduce costs. If generating are not reliable, more capacity must be installed (or obtained from some other power supplier) to ensure that

total energy needs are met. Furthermore, if the lowest cost coal-fired units are not

fully available when needed, energy needs must be met from generating units with

higher production costs.

As a member of the North American Electric Reliability Council 2 (NERC), TVA

is also obligated to help preserve the reliability of the national electricity trans-
23

and monitors the present for member compliance with published policies, standards, principles,

and guides. NERC assesses the future reliability of the bulk electric systems in North America.

NERC’s owners are ten regional councils whose members come from all segments of the electric

industry—investor-owned Federal State/municipal and provincial utilities electric cooperatives,

independent power producers, power marketers and electricity customers. TVA is a member of

Southeastern Electric Reliability Council (SERC). NERC governance is by a board of trustees

comprised of 47 electric industry executives. TVA has representation on the board of trustees.

Operating guides and policies are developed and revised by committees comprised of members

from the ten councils. Guides and policies are approved at various levels and ultimately by the

board of trustees (Information from NERC’s Web site January 2000—http://www.nerc.com)

mission and distribution grid. NERC’s Operating Policy 1, Section C, defines the responses required of participating utilities in order to maintain acceptable frequencies at the transmission interfaces between entities. Upsets such as loss of a

major generating unit on another utility’s system can require TVA to activate its

standby generation facilities or start idle ones. In addition to having an obligation

to respond reliably to such events, TVA must minimize the number of events that

are initiated on its system. Reliable generation and the ability to control the times

when generating units operate or are shut down are crucial to fulfilling this obligation.

In addition, TVA must operate its generating units and transmission assets in a

manner that fully protects the health and well-being of its employees. As a result,

TVA strives to promptly correct conditions that might lead to an unsafe or

unhealthy working environment.

Other companies that own and operate electricity-generating facilities for profit

have also long been under a legal duty to maintain and to operate their facilities

in a manner that ensures a safe, efficient, and reliable supply of electricity to their

consumers. This legal duty is described in the utilities’ compacts with their public

service or public utilities commissions (PUCs). Activities aimed at improving or

maintaining the reliability and efficiency of generating facilities are also subject to

public scrutiny through reports to State PUCs, to the Federal Energy Regulatory

Commission (FERC), and to the Energy Information Administration (EIA) within

the U.S. Department of Energy.

Theory of Maintenance

To fulfill their respective obligations to serve, TVA and the rest of the electric utility industry have developed a very simple maintenance philosophy—maintain the

reliability of generating units in a way that preserves the value of the asset and

minimizes the cost of electricity. For some maintenance activities, this simple statement is equally simple to implement. However, for other activities, determining the

appropriate approach may involve more complicated engineering and economic evaluations. Furthermore, the conclusions that are reached today may not be valid at

some future date because of changes in the technology or economic circumstances.

Under this maintenance philosophy, routine maintenance of components of a generating unit generally falls into three categories. It can be proactive, reactive, or

predictive.

Proactive Utilities routinely change lubricants, clean lubricants, replace gaskets,

repack pump seals, etc., based on fixed calendar schedules or hours of service—regardless of the condition of the equipment. Typically, major overhauls of equipment

have also been performed on a predetermined schedule based on manufacturers’ recommendations or utility experience. Improvements in monitoring and diagnostic capabilities in recent years have enabled plant operators to reduce the level of this

proactive maintenance in favor of the more cost-effective ‘‘condition based’’ or predictive maintenance.

Reactive Reactive maintenance is routinely performed when components or systems fail or experience performance degradation. This may entail replacement of

components with identical parts, replacement with components with improved design or materials, replacement followed by changes in operating procedures, or replacement of an entire assembly or system that includes the failed component. The

actions taken following a failure are determined by an economic evaluation that includes consideration of the immediate needs of the generating system, impact of the

failure on unit operation, the frequency of the failure, and the availability of alternative solutions designed to prevent similar failures in the future.

When a failure results in loss of generating capability of a unit, either partial or

total, the economics normally dictate choosing a maintenance solution that minimizes lost generation. This sometimes results in an immediate response to restore

unit capability followed by a later action to avoid future failures. For example, consider the case of a tube failure in the reheat section of a steam generator.
24

If the damage is isolated to a single tube, that area of the tube is cut out and replaced, and the unit is returned to service. If there is visible collateral damage

or if it is clear from initial analysis and review of operating history that other tubes

in close proximity to the failure have been exposed to similar conditions that would

make their early failure likely, a larger number of tubes may be replaced before the

unit is returned to service. In this case, reactive maintenance is augmented by a

proactive component replacement in order to avoid future failures that would result

in loss of generation or create safety risks. If it is determined that the root cause of a failure is a condition that has exposed

all or a large number of the reheater tubes to increased risk of failure, the economic

analysis may indicate that replacement of the entire reheater is needed to maintain

unit reliability and safety and that replacement is the most cost-effective approach

to maintaining system reliability. Such a condition might result from identification

of a design or materials deficiency, operational errors such as temperature or waterquality excursions, or changes in the condition of service such as might result from

unexpected changes in fuel combustion characteristics due to variation of properties

within a coal seam. The economic analysis would indicate that the loss of generation

and wear and tear on the unit resulting from anticipated failures and shutdowns

justify the investment needed to replace the reheater. Reactive maintenance can also be initiated by discovery of conditions that will lead to component failure if not corrected. If evidence of damage is found during inspections, a similar economic analysis is performed to determine the appropriate response. When the condition is detected prior to failure, however, repair of the component may also be a viable option. For example, discovery of cavitation damage at

the suction of a pump could lead to weld repair of the pump impeller, replacement

of the impeller, replacement of the impeller with improved materials, reconfiguration of the suction piping, or changes to the system upstream of the pump. The selected course of action would depend upon the costs of the alternative solutions and

the benefits each solution would provide to system reliability.

Predictive As technology has advanced, so have the maintenance tools used by the

electric utility industry. Advances in equipment-monitoring capability and analytical

techniques now achieve many of the benefits of proactive maintenance while avoiding the costs of inspecting and overhauling equipment that is operating well and

poses no current threat to unit reliability or employee safety. Predictive capability

also allows threatening conditions to be discovered and mitigated prior to failure,

thus avoiding the cost of lost generation, wear and tear on equipment that occur

during the shutdowns and startups that accompany failures, and safety risks associated with a failure.

Examples of predictive or condition-based maintenance are plentiful. Deterioration of a piece of rotating equipment can now be discovered by spectral analysis long

before vibration reaches levels that would have been detectable with originally installed equipment. Portable vibration-monitoring equipment allows this analysis

technique to be extended to components that have never previously been equipped

with any type of vibration-monitoring equipment. Evaluation of metallurgical samples now enables the condition of tubing or other structural members to be determined and the remaining service life of the component to be predicted with increased precision. This allows the replacement of components before failure while

fully utilizing the life of the component. Modern computational fluid dynamics capabilities allow the prediction of corrosive conditions within boilers that may result

from installation of low-NOx burners. This enables localized mitigation techniques

such as protective cladding to be applied.

Timing of Maintenance Activities

The economic evaluation of maintenance activities at a generating unit is dependent upon a total generating system optimization that assigns a role and set of operating objectives to each individual unit. Unit roles and objectives change because

of independent factors that include changes in fuel costs, overall economic conditions, and the condition of other units in the operating system. As a unit’s role

changes, the maintenance practice for that unit may also change.

For example, a unit operating as a ‘‘swing’’ or load-following unit affords more opportunities to patch or replace failed components one at a time without severely impacting systemwide reliability because system load demand does not require that

the unit be operated continuously. (It should be noted that this swing mode of operation might, in fact, create more opportunities for failure because of the thermal,

mechanical, and electrical cycling of equipment and systems.) However, conditions

on the operating system (such as loss of another generating unit for an extended

period of time) can quickly change the role of the unit to base-load operation. Because a base-load unit is expected to operate continuously, opportunities for failure-
25

driven maintenance are less frequent and certainly more costly. Proactive replacement of a complete assembly of components that have failure potential, rather than

reactive replacement of individual components, may become economically justified

with the increase in production rate or hours of operation.

Many of TVA’s coal-fired units experienced a major change of roles in the mid1980’s when TVA decided to shut down all operating nuclear units for an extended

period because of safety concerns. The reliability of the coal-fired units during this

period became critical to meeting system demand and fulfilling TVA’s mission and

obligation to serve.

Decisions to repair or replace and the scope of the repair or replacement are not

based only on assessments of the least-cost approach to maintaining the requisite

reliability of TVA’s generating and transmission system. The evaluations of options

at a generating unit must also include consideration of the condition of the rest of

the electrical system and the general economy as well as the safety of TVA employees.

Technologically Superior Replacement It has been the common practice within

TVA and the utility industry for decades to replace components and systems with

state-of-the-art equipment that is often more reliable or more efficient than the

original, sometimes obsolete, component. It is also typical for maintenance activities

to include improved maintenance and operational practices that respond to conditions experienced during actual operation of the unit. The following discussion lists

specific examples of these practices on the TVA system.

Replacements with improved design or materials

• Boiler feedpump recirculation valves for supercritical units underwent a complete evolution of materials and design and were replaced numerous times on many

units.

• Cooling tower fill was replaced with fill systems that had better structural and

thermal properties and/or eliminated asbestos materials.

• Metallic expansion joints were replaced with more durable fabric joints.

• Insulation of generator stator bars was upgraded because of continuing failures

of the originally supplied design.

• Steam turbine blade shape and materials of construction have been improved

with resultant increases in thermodynamic efficiency and reliability.

• Feedwater heaters have been completely retubed with new materials that have

improved the reliability of the heaters with resultant increases in thermal efficiency

of the generating units.

• Analog control systems have been replaced with digital systems that provide

increased control flexibility and accuracy and improved reliability.

Improved maintenance tools or operational practices:

• Continuous-cleaning systems for condenser tubes have increased efficiency

through improved heat transfer capability and increased reliability by eliminating

the need for unit outages or short-term load reductions to manually clean tubes.

• Vibration-monitoring systems with expanded capability have provided increased analytical capability and have increased the number of pieces of rotating

equipment that can be monitored. This has resulted in improved reliability by making maintenance programs more effective and avoiding forced outages. Continuousemissions-monitoring equipment has been added to improve combustion controls

and overall thermal efficiency. Continuous-cleaning and filtration systems have been

added to lubricating oil systems of turbine generators and other large rotating

equipment to improve bearing life and decrease bearing-related forced outages.

• More recently, artificial intelligence control systems have been added to continuously optimize unit efficiency while minimizing pollutant emissions.

TVA Historical Practices

The overall maintenance philosophy described above has been in place at TVA for

many years. This philosophy is reflected in a report presented to the American

Power Conference in 1972, ‘‘TVA’s Power Plant Maintenance Program’’ by T.H.

Gladney and H.S. Fox. At the time of that report, TVA’s oldest coal-fired plant had

been in service just over 20 years. Many of the units were less than 10 years old.

The report clearly stated TVA’s approach to maintenance:

In an effort to maintain unit reliability, major replacement or rehabilitation in

areas where excessive tale failures occur is made after an evaluation based on loss

of generation, cost of repairs, and damage to the and from frequent startups and

shutdowns indicates it is justified.

Examples of the types of routine maintenance activities and projects that were

identified in the report after less than 20 years of operation include the following.
26

3 Babcock and Wilcox, Storm: Its Generation and Use, 40th edition, 1992, pp 14–1–14–11

• In one family of 14 similar turbines, 3 high-pressure spindles had to be replaced because of creep-rupture cracking.

• Another high-pressure spindle was replaced and two intermediate-pressure

spindles were on order following discovery of unacceptable cracks in the rotor bore.

• Steam chests were replaced on two 700 MW units after only 8 years of operation.

• Four generators required complete stator rewinding with upgraded insulation

material, and 42 percent of the total generator fleet required partial replacement

of bars.

• Although the projects had not yet been implemented, the decision had been

made to pressurize the penthouse on all pressurized furnaces.

• Most crotch tubes, reentrant throat tubes, wrapper tubes, and face tubes had

been replaced at least once on all cyclones of two 700 MW units, and it was thought

that replacement of all cyclone tubes would be required within 3 to 5 years. (See

Paradise Unit 1 Cyclone Replacement Case Study later in this report.)

• Of 41 low-pressure heaters using admiralty tubing, 14 had been retubed using

better quality copper-nickel material and all others were anticipated to require retubing in the near future.

• Stainless steel tubes were removed, heat-treated, and reinstalled in the superheater and reheater sections of 11 steam generators.

• The return bends in all reheater pendant elements of two steam generators

were redesigned and replaced.

These maintenance activities left the basic design of the steam/heat cycle and the

maximum heat input to the furnace unchanged. Within these overall design constraints, however, all of these maintenance activities were intended to improve the

reliability or efficiency of the generating units.

Case Studies

The same TVA maintenance philosophy has been consistently applied since the

Gladney-Fox report. Four case histories of maintenance projects are presented

below. Each case presents a discussion of the component, its function, and its conditions of service; the relevant operational history of the component; alternatives considered; and the rationale behind the maintenance decision. This specific case is

then extended to analyze the history of replacements of the component on both the

entire TVA coal-fired system and a larger data set that represents either the entire

electric utility industry or a large segment of the industry.

Cyclone Furnace Replacement

Cyclone Background

As related in Steam: Its Generation and Use, 3 cyclone-fired boilers were developed by Babcock and Wilcox (B&W) to burn coals with low ash-melting (fusion) temperatures that are not well suited for pulverized-coal (PC) combustion. The ash from

these coals would enter the superheater of a PC unit in a molten state and create

severe slagging and fouling problems. The ‘‘cyclone’’ design developed by B&W addressed this problem by deliberately melting as much ash as possible and draining

it from the bottom of the furnace. This kept molten slag out of the superheater and

substantially reduced the total amount of ash that was transported out of the boiler

with the flue gas (fly ash). The cyclone design also had these collateral benefits:

• Eliminated the need for high-cost and high-maintenance pulverizers.

• Resulted in overall smaller furnaces (with the associated reductions in powerhouse dimensions).

• Required smaller particulate collection equipment due to reduced fly ash loading.

• Opened the market to a range of fuels that were not usable with pulverizedcoal firing.

The design objective was accomplished by creating a zone where combustion takes

place outside the main furnace. The hot flue gas and molten slag then discharges

into the main furnace, with the gas being cooled and discharged from the top of the

furnace while the molten slag is kept at elevated temperatures and is drained

through the main furnace bottom. This allows very high temperatures to be maintained in the combustion zone while the majority of the evaporative heat transfer

occurs in the main furnace.

These combustion zones or ‘‘cyclones’’ are horizontally oriented, cylindrical barrels

that attach to the sides of the main furnace. Cyclones range from 6 feet to 10 feet

in diameter. As few as 1 or as many as 23 of these cyclones are attached to the
27

4 Babcock and Wilcox, Steam: Its Generation and Use, 40th edition, 1992, p. 141.

main furnace of different units. The term ‘‘cyclone furnace’’ is used to describe both

the individual cyclones and the total furnace assembly of a cyclone-fired unit. The

cyclones are a water-cooled, tangent tube construction, but a thick layer of refractory lining is used to protect the tubing material while allowing the sustained high

temperatures (greater than 3000F) needed to consistently melt the ash. BOW describes the operation of cyclones as follows:

Crushed coal and some air . . . enter the front of the Cyclone through specially

designed burners in thefrontwall of the Cyclone. In the main Cyclone barrel a swirling motion is created by the tangential addition of the secondary air in the upper

Cyclone barrel wall. A unique combustion pattern and circulating gas-flow structure

result. . . . The products of combustion eventually leave the Cyclone furnace through

the re-entrant throat. A molten slag layer develops and coats the inside surface of

the Cyclone barrel. The slag drains to the bottom of the Cyclone and is discharged

through the slag tap. 4

While cyclones achieved their design objectives, they also presented some difficult

problems. The introduction of crushed coal and air at high velocities resulted in erosion problems, particularly in areas of the cyclone that do not form a protective slag

layer. The hot, molten slag environment also introduced high risk for corrosion damage to the water-cooled tubes. Generally, the refractory material would protect the

tubing. However, in areas where refractory eroded, cracked, or otherwise was removed from the tubing, the tubing’s exterior surfaces would be subjected to the corrosive matter (such as iron sulfide) and rapidly lose metal thickness and strength.

As a result, cyclones were plagued by tube failures that resulted in forced outages

and decreased reliability. In the face of these cyclone failures, B&W developed rehabilitative repair and replacement strategies, such as welding flat steel stock onto

tube surfaces in areas of high erosion potential and using a high-density pin-studding pattern to better hold refractory in place.

Paradise Unit 1 Case Study

Unit 1 of the Paradise Fossil Plant (located on the Green River in Muhlenberg

County, Kentucky) is a 700 MW (nominal) cyclone-fired unit that was put into service in 1963. It has 14 ten-foot diameter cyclones—7 on each of the front and rear

walls. Its boiler produces steam at 2450 psi’’, 1003F. Within its first year of commercial operation, the unit began experiencing failures of cyclone tubes. These failures

increased in frequency such that by the time of the Gladney and Fox report in 1972,

most of the crotch tubes, reentrant throat tubes, wrapper tubes, and face tubes had

been replaced at least once. It was projected at that time that replacement of all

cyclone tubes would be mandatory within 3 to 5 years, but this anticipated wholesale replacement was delayed by a manpower-intensive program of frequent,

proactive, tube replacements. This piecemeal replacement of the tubes continued

through 1982; however, during this period the cyclones continued to exhibit failures

that resulted in decreasing reliability, wear and tear on equipment, and labor and

materials charges. The increase in unit forced outages from 1962 is shown in Figure

1. (The peak forced-outage rate experienced in 1979 was the result of a single turbine casing failure that resulted in a forced outage of approximately 1350 hours and

contributed 20.5 percent to the 42.5 percent forced-outage rate for the year. Without

this single event, the forced-outage rate for 1979 would have been about 22 percent—consistent with the trend at the time but still unacceptably high.)
28

The contributions to forced outages for calendar year 1982 are analyzed in Table

4 below. These data show that cyclone failures were the principal cause of the unit’s

degraded performance.

Table 4

Paradise 1—1982 Forced Outage Rate (FOR) Analysis

Description No. of

Events

Forced

Outage

Hours

MWH Loss Contr. To Unit FOR

Estimated Dif- ferential

Power Replacement Cost

Cyclone Tube Leaks ................................................................... 10 882 516118 15.50 4,077,000

Waterwalls ................................................................................. 2 158 98052 2.95 775,000

Condenser Shell ........................................................................ 1 158 10839 0.33 86,000

Wet Coal .................................................................................... 2 11 6881 0.21 54,000

Main Turbine Control Valve ...................................................... 2 5 2903 0.09 23,000

Main Turbine Shop Valve .......................................................... 1 2 1002 0.03 8,000

Boiler Feedpump Turbine .......................................................... 1 1 744 0.02 6,000

Total ........................................................................ 19 1026 636539 19.12 5,029,000

In addition to decreasing reliability and increasing costs, cyclone repairs were becoming increasingly manpower-intensive. Although there were only ten forced-outage events attributed to cyclones during calendar year 1982, there were 213 tube

leaks (and 168 leaks in 1981). Each of these leaks required maintenance attention.

As discussed above, when equipment experiences repeated failures that adversely

impact performance, it is TVA’s practice to undertake a structured analysis of various alternatives to correct the problem. The maintenance decision involves a choice

between:

• Repair or replacement of individual components (reactive maintenance);

• Replacement of other components that have also experienced conditions that

could affect future performance (proactive maintenance); and

• Incorporation of improved materials or design elements that might help address the causes of equipment degradation in the future.

TVA evaluated three primary options to address this unacceptable situation.

1. Do nothing—Make no proactive tube replacements. Take only those measures

necessary to return the unit to service after cyclone tube failures.

2. Status quo—Continue with the past program of proactive replacement of damaged or high-risk tubes.

3. Replacement—Replace all cyclones in a single scheduled outage, incorporating

advances in materials and design developed by BOW based on lessons learned in

service.

TVA knew that there were similar cyclone problems at other utilities and that

other utilities had replaced cyclones as part of their maintenance programs. The

TVA analysis considered the results that had been achieved or projected by other

utilities with similar large boilers. The results achieved by these utilities are shown

in Table 5 below.
29

Table 5

Results of Prior Cyclone Replacements

Unit 1 Unit 2 Unit 3

Availability Before ................................................................................................... 60% 59% 50%

1Availability After ................................................................................................... 82% 78% 75%*

FOR** Before .......................................................................................................... 24.5% 29% 35%

FOR After ................................................................................................................. 6.58% 13% 12%*

* Projected results—projects were being implemented at time of economic evaluation.

** FOR—Forced Outage Rate.

Based on TVA’s experience to that time, complete inspection and evaluation of the

condition of the cyclones, and the results of similar replacement projects performed

by others, TVA projected the future performance of the unit for all three options as

shown in Figure 2.

Using these projections for future performance, the expected cost of the three options, and projected differential costs for replacement power, the economic analyses

Droduced the results shown in Table 6.

1Table 6

Paradise 1 Cyclone Options Economic Evaluation

Low-Load

Forecast*

High-Load

Forecast*

Present Worth Savings ($ million):

Alternative 2 vs. Alternative 1 ........................................................................................................ ¥2.70 5.90

Alternative 3 vs. Alternative 1 ........................................................................................................ 15.90 45.30

Benefit/Cost Ratio:

Alternative 2 vs. Alternative 1 ........................................................................................................ 0.75 1.58

Alternative 3 vs. Alternative 1 ........................................................................................................ 2.11 5.12

* TVA typically projects a range for future energy demands on its system: low-, medium-, and high-load forecasts. This table shows the

range of cost estimates based on the low- and high-load forecasts at that time.

As Table 6 shows, Alternative 3 (full replacement during a scheduled outage) was

the best alternative, maximizing both the savings and the benefit/cost ratio for both

the low- and high-load forecasts. TVA chose Alternative 3 and implemented the

project in 1984.

Experience on the TVA System

TVA operates six cyclone-fired units, three each at the Allen and Paradise Fossil

Plants. In total, the Allen units have 21 seven-foot diameter cyclones and the Para-
30

5Throughout this report, TVA experience is also included in the analysis of industry experience.

dise units have 51 ten-foot diameter cyclones. All the cyclones have experienced the

erosion and corrosion problems discussed above and, like Paradise Unit 1, all the

originally supplied cyclones have been replaced. Figure 3 depicts the replacement

history for these cyclones since 1978. The major tubing replacements refer to replacement of reentrant throat tubes at the Allen Fossil Plant. (Note that the replacements during the proactive, partial tube replacement effort are not included in

Figure 3. That effort, which was performed at all TVA cyclones, is discussed above

in the case study for Paradise Unit 1.)

Other Industry Experience 5

The TVA experience with operating and maintaining cyclones is not unique. Virtually all cyclone owners have encountered the same problems with varying degrees

of severity. There are 96 electricity-generating stations in the United States, (totaling 26,152 MW of capacity) powered by cyclone-fired furnaces. These units contain

701 individual cyclones. At these units, 300 cyclones (representing 13,981 MW of capacity) have been replaced since 1979. Industrywide data on partial replacements

were not available for this report. Figures 4 and 5 show the number of cyclones replaced and the associated capacity as a function of cyclone age. The median age of

the replaced cyclones was 21 years, while the mean age of those cyclones was 23.1

years.

Of these 300 replacement cyclones, only 13 cyclones (representing a total capacity

of 569 MW) were replaced with identical cyclones. All other replacements included

some improvement based on the B&W rehabilitative repair and replacement strategies (discussed in the background above) or similar measures.
31

It is apparent from the TVA case study and the analysis of industrywide maintenance history and practices that full replacement of cyclones has occurred frequently

throughout the industry. It is also apparent that cyclones have been replaced on

units of varying ages, confirming that many variables affect the actual condition and

performance of boiler components. Full replacement of cyclones to correct problems

created by corrosion and erosion of materials has occurred frequently and routinely

throughout the utility industry.

Balanced-Draft Conversion

Balanced-Draft Background

In the 1950’s, boiler designers began to employ a new design concept for large

utility boilers—pressurized furnace operation. Prior to this design, the furnaces of
32

all utility pulverized-coal-fired boilers had operated under a slight vacuum (negative

pressure). The majority of these negative-pressure furnaces operated in a ‘‘balanced

draft’’ mode. That is, they were equipped with a forced-draft fan that supplied the

combustion air to the furnace and an induced-draft fan that mechanically drew the

combustion gasses out of the furnace and expelled them through the chimney. Some

smaller units were equipped with only an induced-draft fan, while some had no fans

at all, using the draft effect of the chimney to draw air into the boiler and evacuate

the combustion products.

There were several recognized incentives to move to pressurized firing. Operation

with a negative-pressure furnace introduces some inefficiency caused by the unavoidable in-leakage of air not needed for combustion. This extra air requires additional motive power from the induced-draft fans and increases thermal losses because the total mass of hot gas lost from the system through the chimneys is increased. Keeping the furnace, the convective sections of the boiler, and the duct to

the chimney under positive pressure eliminates this inefficiency. In addition, elimination of the induced-draft fan lowers the initial cost of the draft system and subsequent operation and maintenance costs.

The early installations with this forced-draft system design were initially successful and were soon followed by construction of other small, pressurized firing units.

Pressurized firing was increasingly used in the industry by the mid to late 1950’s

and was widely accepted by the mid-1960’s. (Of 284 boilers sold from 1955 to 1965

by Babcock and Wilcox and Combustion Engineering, the two largest boiler suppliers in the United States, 127 were pressurized. Of 185 sold from 1966 to 1975, 76

were pressurized.)

Although the pressurized furnaces were gaining in popularity during this period,

certain shortcomings in the concept began to be manifested. Leakage of air into the

furnace was replaced by leakage of combustion products out of the furnace. These

combustion products, laden with fly ash and high concentrations of SO2 and other

corrosive gasses, caused several unacceptable conditions that called for a maintenance response:

• Infiltration of corrosive gasses and fly ash into the penthouses above the furnaces resulted in accelerated corrosion and structural failures.

• The employee work environment deteriorated because of exposure to high concentrations of combustion byproducts.

• Corrosion of components in the powerhouse near the boilers increased.

• Rotating machinery was exposed to increased levels of damaging particulate

matter.

• Component performance was degraded because accessibility to the components

was reduced, impeding performance of maintenance.

As a result, no pressurized Babcock and Wilcox units and only two pressurized

Combustion Engineering units were sold after 1975 (none after 1977), and many

utilities began to replace their forced-draft systems with balanced-draft systems to

address equipment degradation and related health and safety problems. Some of the

replacements were undertaken for economic reasons based on loss of reliability

caused by component failure and inability to perform required maintenance. However, the primary reason for many of the replacements, including those on the TVA

system, was improvement of the operating environment for plant personnel— employee health and safety.

The trend back to balanced-draft systems was accelerated by the addition of control equipment to meet air-quality regulatory requirements. The new control equipment added resistance (pressure drop) to the flow of the flue gas. Often, this added

resistance could not be overcome by the existing draft system. Thus, when a utility

considered the addition of control equipment, one of the options considered to enhance the draft system to accommodate the added pressure drop was replacement

with a balanced-draft system. This was often the preferred option because it both

accommodated the added pressure drop and resolved other operational, maintenance, and safety concerns, as discussed above. A TVA survey of 79 balanced-draft

conversions indicates that 68 were done either out of concerns for employee health

and safety or in conjunction with the addition of pollution-control equipment.

Cumberland Unit 1 Case Study

Unit 1 of the Cumberland Fossil Plant (located on the Cumberland River in Stewart County, Tennessee) is a 1300 MW (nominal) opposed-wall, pulverized-coal-fired

unit that was put into service in 1973. It produces steam at 3650 psi’’, 10030F. The

unit was not yet in service at the time Gladney and Fox reported in 1972 that the

decision had been made to pressurize the penthouse on all pressurized units. This

decision was made in an effort to mitigate the severe maintenance and safety prob-
33

6Tennesssee Valley Authority Project Authorization, Serial No. 3384, September 29, 1978.

lems that had been encountered on the six other TVA units that had been operating

with pressurized furnaces.

Very early in the life of the Cumberland unit, it was apparent that state-of-the- art efforts to reduce gas leakage were inadequate. (These efforts included the redesign of tubing penetrations, sootblower penetration seals, expansion joints, and

other design details aimed at reducing the tearing of ductwork and other pressure

boundaries during boiler startups and shutdowns.) The environment inside the powerhouse when the unit was operating was intolerable—especially at upper elevations

near the boiler bay. It was determined that the SO2 concentrations inside the powerhouse exceeded the levels allowed for safe industrial occupancy. Cumberland also was unable to consistently attain the reliability that is normally expected of a new generating unit. While this was due to a number of reasons, TVA

determined that the hostile environment caused by the leakage from the pressurized

furnace was a major contributor to the unit’s poor initial performance, which is depicted in Figure 6.

Accordingly, TVA decided to replace the pressurized firing system with a bal- anced-draft system in conjunction with its decision to add new, high-efficiency electrostatic precipitators to the unit for particulate control. In this instance, a rigorous

economic evaluation justifying the decision was not made; providing a safer work

environment for employees was deemed a major priority. The authorization document for the conversion states:

. . . (G)as leakage from the boilers has resulted in sulfur dioxide and fly ash prob- lems in the plant. Sulfur dioxide concentrations exceed the recognized national

standard established to limit employee exposure and also prohibit adequate equipment maintenance and increase unit deratings. Also, the entrained fly ash infiltrates plant equipment, resulting in premature failures and further deratings. The

addition of induced-draft fans and conversion to balanced-draft firing will eliminate

these problems.

. . . The addition of induced-draft fans and conversion to balanced-draft firing will bring the two Cumberland units into compliance with TVA Code VIII HAZARD

CONTROL and consistent with the Occupational Safety and Health Act of 1970.

The cost of converting these units to balanced-draft is estimated to be $41 million;

this cost will be partially offset by the potential saving of reduced deratings and

unit trips and by reduced plant maintenance. 6

The project was approved in 1978 and implemented in 1981.

Experience on the TVA System

Eleven of TVA’s 59 operating units, totaling over 7,100 MW, were initially constructed and operated with pressurized furnaces. This included all units that went

into service between 1962 and 1973. Today only one of these units, the 900 MW Bull

Run unit, remains in pressurized operation.

Bull Run is unique among the TVA pressurized units in that it has historically

burned coal with a much lower sulfur concentration. (The lower sulfur content re-
34

duces the corrosiveness and SO2 concentration of gasses that may leak into the powerhouse.) Bull Run has experienced many of the adverse conditions associated with

pressurized firing. However, the twin-furnace, membrane-wall construction of the

unit combined with its continuous operation as a base-load unit burning low-sulfur

coal has allowed plant staff to maintain a safe working environment while balancing

the impact of reduced reliability and other economic penalties associated with pressurized units. The penthouse at Bull Run was pressurized in 1972.

Similar to the Cumberland project, other forced-draft system replacement projects

on the TVA system were performed in conjunction with addition of environmental

control equipment. Table 7 summarizes the history of TVA balanced-draft conversions.

Table 7

Draft System Replacements of JVA Coal-Fired Units

Unit Size, MW

Date of

Initial

Operation

Date of

Draft

System

Replacement

Concurrent Environmental

Control

Allen 1 ............................................................................................................................ 330 1959 1991 None

Allen 2 ............................................................................................................................ 330 1959 1993 None

Allen 3 ............................................................................................................................ 330 1959 1993 None

Colbert 5 ........................................................................................................................ 500 1965 1981 None

Cumberland 1 ................................................................................................................ 1300 1973 1981 ESP

Cumberland 2 ................................................................................................................ 1300 1973 1982 ESP

Paradise 1 ...................................................................................................................... 700 1963 1983 FGD

Paradise 2 ...................................................................................................................... 700 1963 1983 FGD

Paradise 3 ...................................................................................................................... 1150 1970 1983 ESP*

Widow’s Creek 8 ............................................................................................................ 500 1965 1977 FGD

* Paradise 3 replacement of forced draft system was delayed one outage cycle by delays in delivery of induced draft fans.

Other Industry Experience

There are no readily accessible data that identify industrywide pressurized furnaces and those where a forced-draft system was replaced with a balanced-draft system. However, TVA was able to obtain data from a large sample of U.S. utilities

that own a significant number of coal-fired generators. This data set includes 19

utilities that operate 166,000 MW of fossil generation. These utilities collectively

own 151 boilers that were purchased and initially operated with pressurized furnaces. Within a 15-year period beginning in 1972, utilities replaced forced-draft systems with balanced-draft systems on 73 of these units. (Six other units were converted between 1991 and 1995 for a total of 79 conversions representing 52 percent

of the sample population.) Draft system replacement did not alter these unite’ treat

input capacity or steam flow but in most instances reduced the net electrical output

because of increased auxiliary electrical loads for the induced-draft fans. The ages

of the units at the time of the conversions are shown in Figure 7.
35

7 Combustion Engineering Inc. Combustion Fossil Power, 4th edition, 1991, pp. 1–8.

8 Babcock and Wilcox, Steam: Its Generation and Use, 40th edition, 1992, pp. 1–8

These data show that replacement of forced-draft systems with balanced-draft sys- tems in order to address equipment degradation, maintenance problems, health and

safety concerns, and pollution control requirements has occurred frequently in the

utility industry. The data show that these draft system replacements occurred regardless of the age of the unit, with age at conversion ranging from 4 to 36 years.

On the TVA system, conversions to balanced-draft were justified primarily because

of the need to improve working environments for employees. Improvement in unit

reliability was an important collateral benefit. Balanced-draft conversions have occurred frequently and routinely in the utility industry.

Reheater Replacement

Reheater Background

Modern coal-fired power plants operate on cycles based on the regenerative Rankine cycle. In this cycle the boiler feedwater is converted to superheated steam

in the boiler and used to drive a turbine-generator for electrical energy production.

The steam is then condensed to liquid water to allow it to be pumped back to the

boiler. The water is then heated using heat exchangers and returned to the boiler

again as the boiler feedwater (thus being a regenerative cycle). In efforts to increase

the plant thermal efficiencies (that is, reduce the amount of coal required to be

burned for a specified output of electric power), the cycle was first improved to use

superheated steam and then further improved with the addition of the reheat circuit. This latter addition, referred to as the reheat cycle, includes removing energy

from the superheated steam in a high-pressure turbine and then returning the

steam to the reheat section of the steam generator for additional heat energy. The

steam is then again returned to the turbine-generator for further energy removal.

For large installations, reheat makes possible a thermal efficiency improvement of

approximately 5 percent and substantially reduces the heat rejected to the condenser cooling water. 7

Most of the TVA coal-fired plants built since 1951 (all since 1954) use the reheat

cycle. The portion of the steam generator that transfers the heat to the steam is

referred to as the ‘‘reheater’’ or the ‘‘reheat superheater.’’ This system is, in general

terms, a simple single-phase heat exchanger with steam flowing on the inside and

the flue gas passing on the outside, generally in a cross-flow configuration. 8 The

major components are:

• Inlet header (which distributes steam returning to the boiler from the high- pressure turbine exhaust to the individual tubes) • Heat exchange tubes or elements (horizontal, pendant, platen, terminal, or crossover depending on individual design)
36

9 Electric Popover Research Institute, Boiler Tube Failures Theory and Practice, TR-J05261.

• Outlet header (which collects heated steam from the individual tubes for passage to the intermediate-pressure turbine)

Because of the high operating temperatures, appropriate construction materials

are critical to a successful reheater design. Accordingly, steel alloys were used in

parts of the reheater construction because of their superior high-temperature properties and resistance to oxidation. But, as in all components of these steam generators, portions not operating at high temperatures were constructed of lower alloy

steels (also referred to as higher carbon steels) that were lower in cost. The design

of the reheater components, as other boiler components, was an attempt to optimize

between the initial cost of materials of construction and the need for higher-cost

steel alloys for reliable operation.

As a result, carbon and low-alloy steels were used for portions of the reheater subject to lower temperature ranges, such as the reheater inlet tubes (where the lower

temperature steam from the high-pressure turbine exhaust enters the reheater). Intermediate chrome-molybdenum (Cr-Mo) steels were used for portions subject to

higher temperatures, such as toward the reheater outlet (where the steam achieves

its maximum temperature). Unfortunately, this use of differing materials added an

unforeseen failure mechanism to these components—the difficulties of welding dissimilar metals together.

In early reheater designs, the materials selected were not always adequate to address the full range of the conditions that would be experienced, such as varying

temperatures during operational upsets, varying physical and thermal stresses,

water chemistry conditions, and changes in coal and ash physical and chemical

properties. Accordingly, the useful life of these reheaters varied significantly among

the many units in the industry because of the differences in operating environments.

In addition to construction materials, the physical design of the reheaters was

critical to the actual performance of the components in service. Again, an optimization was required to balance the desired high heat transfer from the gas to steam

and the need to avoid undesirably high metal temperatures. Another major factor

was the optimization of available tube surface while maintaining adequate tube

spacing to avoid high gas velocities and the resulting excessive erosion of the tube

material.

Combined with these design considerations were the coal-ash properties that must

be factored into the design in order to avoid fouling and, again, excessive erosion.

To manage the fouling conditions, sootblowers were added in some applications. As

with the welding of dissimilar metals, installation of sootblowers to reheaters adds

a potential failure mechanism to reheater components, namely, erosion caused by

sootblower impingement.

Design features similar to those described above are extremely important in determining the life of reheater components. Equally important however is the actual operating environment to which the reheater is subjected. This can probably be best

illustrated by examining the most common tube-failure mechanisms experienced in

reheaters and the corresponding potential root causes as identified in the Electric

Power Research Institute’s Boiler Tube Failures: Theory and Practice. 9 See Table

8 which follows.

Table 8

Failure Mechanisms in Reheaters (RH)

Failure Mechanism Possible Root Causes

Short-Term Overheating

in RH Tubing.

• Tube blockage induced (especially exfoliated oxide blockage)

• Maintenance induced (improper chemical cleaning or repairs)

• Operation induced (improper startup or shutdown, or overtiring with top heater out of service)

Long-Term Overheating/

Creep.

• Influences of initial design and/or material choice

• Buildup of internal oxide scale

• Overheating due to restricted flow caused by chemical or other deposits, scale, debris, etc.

• Operating conditions or changes in operation

• Blockage or laning of boiler gas passages

• Increases in stress due to wall thinning
37

Table 8—Continued

Failure Mechanisms in Reheaters (RH)

Failure Mechanism Possible Root Causes

RH Fireside Corrosion

(Sootblower or Ash).

• Influence of overheating of tubes (poor initial design, internal oxide growth during operation,

high temperature laning, tube misalignment, operational problems when coal is changed, and

rapid startups causing reheater to reach temperature before full steam flow)

• Change to coal with unusually corrosive ash

• Incomplete or delayed combustion

Dissimilar Metal Weld

Failures (Failures

occur where ferritic

and austenitic steels

are welded together).

• Excessive tube stresses such as caused by improper initial design or improper tube supports

• Excessive local tube temperatures

• Change in unit operation (increased unit cycling, change of fuel, redesign of adjacent heat

duties)

• Initial fabrication defects

Stress Corrosion Cracking.• Influence of environment (mainly contamination from carryover of chlorides from chemical

cleaning of waterwalls, boiler water carryover, caustic from attemperator spray, condenser cooling water leaks, or ingress of fireside contaminants or flue gas during primary leaks)

• Influence of excessive stresses (especially at supports)

• Need to change material to a stabilized grade of stainless steel

These failure mechanisms can occur concurrently or individually. Depending upon

the failure mechanisms, different maintenance responses may be required. These

range from repair or replacement of individual tubes or tube sections, to redesign

and replacement of the reheater, to the installation of equipment that will address

the root cause of the maintenance problem (such as sootblowers).

Cumberland Units 1 and 2 Reheater Replacement Case Study

In addition to the Cumberland Unit 1 features described earlier, Cumberland

Units 1 and 2 each had 233,200 square feet of reheater surface installed as part

of the original construction. During operation of the plant, high wear rates caused

by fly ash or sootblower impingement resulted in numerous erosion shields being

added and subsequently replaced. Cracks were routinely identified during inspections and were ground out and repaired. Individual tubes were cut out and replaced

because of thinning from high-temperature oxidation and coal ash corrosion, mechanical damage, sootblower erosion, or overheating damage. Misaligned tube elements were realigned and numerous support lugs replaced. Still, the reheater condition continued to degrade and require increasing maintenance attention.

In the 1986–1988 period, deterioration of the inlet pendant lower loops led to their

being cut out and replaced with SA213-T22 material, a higher chromium content

steel that is more resistant to loss of strength with long-term exposure to high temperature. However, the T22 material is susceptible to out-of-service pitting. As a result, these loops were replaced again in 1996.

In 1996, TVA conducted a comprehensive review of the failure experiences in the

Cumberland reheaters. The review showed that during the period of fiscal years

1992–1996, 11 leaks had occurred in the Unit 2 reheater pendant tubes. A root

cause analysis was performed on the 11 leaks, and several failure mechanisms were

identified (including corrosion fatigue, stress corrosion cracking, weld defects, hightemperature oxidation/coal ash corrosion, dissimilar metal welds, and sootblower

erosion) with several root causes. Inspections and nondestructive testing indicated

that further failures were developing. It was projected that the failure rate would

increase and further jeopardize the availability of the unit, potentially causing two

forced outages per year by the year 2000.

TVA concluded that, because of the damage that already existed and the overall

condition of the existing reheat pendant tubes, the most economical solution was the

complete replacement of the 147 inlet and outlet elements. The following items were

also recommended:

• Changes in the design of the structural attachments that were welded to the

tubes. These attachments were limiting thermal expansions, thereby creating high

local stresses that were leading to corrosion fatigue failures. The supports were redesigned and materials changed to reduce or eliminate this mechanism.

• Improvement in the unit’s boiler water chemistry program. Condenser tubes

were replaced to stop leakage of contaminants from the untreated condenser cooling

water into the feedwater system. Also, the feedwater chemistry treatment process

was changed to reduce or eliminate water chemistry contributions to the conditions

that led to reheater internal tube corrosion.
38

• Improvement in the welding quality assurance program. Failures had been occurring in field welds and header socket welds. A new welding quality assurance

program was implemented to avoid repeats of these failures.

The cost of the element replacement project was estimated to be $8.4 million, with

a projected benefit of $2.9 million per year. Thus the project would pay for itself

in 3 years. The recommendations were implemented and the reheater was replaced

in 1999.

Experience on the TVA System

Of TVA’s currently operating 59 units, 49 use the reheat cycle. In all these units,

partial or complete replacement of the components of the reheaters exposed to the

flue gas stream has been required in order to keep the units in reliable operation.

Some plants have had different life experiences of the inlet versus the outlet reheater pendants. For example, TVA had to replace the outlet pendant elements at

Gallatin Fossil Plant Units 1 and 2 within 8 to 15 years, while the inlet pendant

elements operated for more than 35 years without replacement. Figure 8 below provides a summary of the reheater modification/replacement projects performed on the

TVA system. At least one significant portion of the reheater pendant elements in

every TVA reheat cycle unit has had to be replaced within 20 to 40 years of initial

operation.

Other Industry Experience

To assess industry practice in the maintenance of reheaters, TVA analyzed data

from other utilities with predominately coal-fired generation. These data represent

the maintenance histories of 219 generating units totaling more than 80,000 MW

of electrical generation. Of these 219 units, 190 are equipped with reheaters. The

results of this analysis are given in Figure 9.
39

Of the 190 reheaters included in the sample, there have been 231 reheater replacement projects, with some reheaters having been replaced more than once. As

with the cyclone and the draft system replacement data, these data show no strong

correlation between reheater replacement projects and reheater age. Ages at replacement ranged from 5 to 44 years, with a mean age of 25.1 years and a median

age of 25 for this data set. This leads to the conclusion that factors other than age

determine the need for reheater replacement.

Economizer Component Replacement

Economizer Background

Another enhancement to improve the efficiency of the base Rankine thermal cycle

was the addition of a heat exchanger in the flue gas stream exiting the steam generator. This heat exchanger, called an economizer, is typically a simple single-phase,

tubular heat exchanger with boiler feedwater flowing on the inside and flue gas

passing on the outside of the tubes. Thermal energy in the flue gas is transferred

across the heat exchange surface into the feedwater, increasing its temperature before it enters the unit’s steam drum or the furnace surfaces, depending upon the

boiler design.

The economizer provides another useful function by reducing the magnitude of

thermal shock caused by feedwater temperature fluctuations at the inlet to either

the boiler drum or the waterwalls. Thermal shock, the rapid change in metal temperature due to changes in the fluid temperature, produces stress increases in thick

walled boiler components. Large numbers of these stress cycles will ultimately lead

to failure of the component.

The economizer is usually the last heating surface in the flue gas stream before

the gas stream exits the steam generator and passes through the combustion air

preheater. The overall efficiency of a boiler is improved more by using the thermal

energy in the flue gas to heat feedwaterthan by using it to preheat the combustion

air. Sizing an economizer, that is, determining the amount of heat transfer surface

to be provided, is an economic optimization among three principal parameters: the

cost of the economizer surface, the cost of the air preheater, and the thermal efficiency of the boiler.

The major components of the economizer, in general terms, are the inlet header,

the heat exchange tubes or elements, and the outlet header. Since these components

are exposed to considerably lower temperatures and a less hostile environment than

other boiler components (reheaters and superheaters, for example) they are typically

constructed from low-carbon steel to reduce cost. However, because this steel is subject to corrosion in the presence of even extremely low concentrations of oxygen, it
40

11 Combustion Engineering Inc., Combustion Fossil Power, 4th edition 1991, pp 5–10. 12 Electric Power Research Institute, Boiler-Tube Failures: Theory and Practice, TR–105261

Volume 2: Water-Tooched Tubes, 1996.

is necessary to provide boiler water that is practically 100 percent oxygen-free. 11

This tubing is also susceptible to fly ash erosion and erosion/corrosion.

Thus, as with the reheater, both the physical design and fabrication details of the

economizer and the operating conditions it encounters are important factors that determine its useful life. Their importance is again clearly illustrated by the summary

of the most common tube-failure mechanisms experienced in economizers and the

corresponding potential root causes taken from the Electric Power Research Institute’s Boiler Tube Failures: Theory and Practice. 12

Table 9

Failure Mechanisms in Economizers

Failure Mechanism Possible Root Causes

Corrosion Fatigue ............... • Influences of excessive stresses/strains (especially restraint stresses at attachments)

• Influence of environmental factors (poor boiler water chemistry, overly aggressive or improper chemical cleaning, and/or improper boiler shutdown and/or lay-up procedures)

• Influence of historical unit operation (operating procedures that have caused high

stresses)

Fly ash or Sootblower Erosion.• Excessive local velocities (geometry of design, distortion or misalignment of tubing rows,

misalignment or loss of gas flow guides and baffles, operating above the continuous design rating, and/or operating above design excess air flow)

• Increased particle loading (fuel considerations and/or soot-blower operation or maintenance)

• Improper sootblower operation (control of frequency, temperatures, pressures, and travel;

mechanical malfunctions, etc.)

Thermal fatigue of economizer inlet header tubes.• Operating conditions that produce large through-wall thermal gradients in the header

• Header design and construction

Erosion/corrosion in economizer inlet headers.• Very low O2 levels and high levels of oxygen scavenger

Low-temperature creep

cracking.

• High stresses (high residual stresses from the cold forming process, enhanced membrane

stresses caused by tube ovality, and/or high service stresses)

Fatigue in tubes ................. • Excessive strains caused by constraint of thermal expansion

• Excessive mechanical stresses (poor design or manufacturing)

• Vibration induced by flue gas

• Poor welding

Pitting in tubes .................. • Influence of improper shutdown practice (presence of stagnant oxygenated water)

• Sagging economizer tubes preventing tube draining after shutdown (presence of stagnant

oxygenated water)

Acid dew point corrosion .... • Operation of economizer below the acid dew point (SO2 oxidizes to SO3 and combines

with moisture to form sulfuric acid)

Paradise Unit 3 Economizer Replacement Case Study

Unit 3 of the Paradise Fossil Plant (located on the Green River in Muhlenberg

County, Kentucky) is a 1,100 MW (nominal) cyclone-fired unit that were put into

service in 1970. It produces steam at 3650 psi’’, 10030F.

The unit has 281,580 square feet of economizer surface, which was installed as

part of the original B&W design and installation. During the first 20 years of unit

operation, the reliability of the economizer began to decrease as a result of many

of the failure mechanisms addressed in the background discussion. A 1992 review

of the generating unit’s performance reliability found that tube failures in the economizer was one of the leading causes of forced outages.

A root-cause analysis investigation found numerous failure mechanisms and root

causes contributing to these leaks. The predominant failure mechanisms were identified as fly ash erosion, corrosion fatigue, pitting in tubes, and thermal fatigue of

economizer inlet header tubes. The root causes were determined to be the following:

• Poor original design of the economizer (including the baffles).

• Inadequate boiler water treatment and boiler water chemistry control.

• Startup procedures that were allowing slugs of cold water to enter the economizer inlet header.

• Cycling stresses due to forced outages on the unit from other causes.
41

Measures were implemented to eliminate these root causes or reduce their future

impacts. However, past operations had already significantly damaged the economizer elements and inlet header. It was projected that without replacement of most

of its components the economizer would increasingly contribute to unit unreliability.

It was determined that component failures would, in fact, increase the economizer

contribution to unit downtime by approximately 10 percent per year. This equated

to a differential cost of replacement power to TVA of $19,543,000 plus the cost of

repairs for the fiscal years 1995–1999 period. The total cost to replace the economizer was estimated to be $9,153,000. It was replaced in 1994.

Experience on the TVA System

Of TVA’s currently operating 59 units, 44 are equipped with economizers. TVA

has replaced all or a significant portion of the economizer elements/tubes on 11

units and has replaced the inlet headers on 3 units. Because of the relatively less

severe service conditions of economizers, they have generally experienced longer

useful lives than other boiler components discussed above. The TVA history of

economizer component replacement projects is provided in Figure 10 below.

Other Industry Experience

The age analysis of economizer replacement projects for the same industry sample

used in the reheater analysis above is presented in Figure 11. Of the 219 units in

the sample, 202 are equipped with economizers.

As might be expected, because of the generally less severe service conditions,

there have been fewer economizer replacement projects than reheater replacement

projects: 98 economizer projects versus 231 reheater projects. However, the average

and median ages of the affected economizer at the time of the replacement project

are less than the average and median ages of the reheater replacements by 2.3 and

3 years, respectively. The age distribution of the economizer replacements is similar

to the reheater age distribution. There is no strong correlation between economizer

age and economizer replacement. It is apparent that factors other than age create

the situations that lead to economizer replacement.
42

Conclusions

The Tennessee Valley Authority has, in its more than 65 years of operating electricity-generating plants, established a philosophy of maintenance that has as its objective the safe, reliable, low-cost supply of electricity to the residents of the Tennessee Valley. This maintenance philosophy has been in place and implemented consistently since long before 1972, as is evidenced by the 1972 Gladney-Fox report referenced previously.

At the core of TVA’s philosophy is a thorough evaluation of factors that contribute

to loss of reliability and consideration of alternatives to mitigate the loss. The selection of the appropriate alternative is most often based on economic considerations.

The selection is also heavily influenced by other factors that are important to TVA,

such as employee health and safety. It is common for the selected alternative to be

replacement of equipment or components—often with functionally identical equipment or components that reflect improvements in technology and lessons learned

from actual service. The many factors that influence equipment or component replacement include design or fabrication errors, unanticipated operating conditions,

operational errors, and technology advancements.

Analysis of selected TVA projects that involved replacement of components and

systems at TVA generating units does not reveal any strong correlation between the

need for replacement and age of the equipment or component. TVA is no different

from other electric utilities in its maintenance practices. Others in the industry routinely perform the projects performed by TVA. Furthermore, analysis of data from

a large sampling of other utility projects clearly indicates that this routine maintenance behavior—component and equipment replacement—is driven by factors other

than unit or component age.

Biographical Notes

Jerry L. Golden is the Senior Manager of Production Technology in the Tennessee

Valley Authority’s Fossil Power Group. At various times he has served as TVA’s

Head Mechanical Engineer, Fossil Steam Generation and Equipment; Manager, Advanced Production and Environmental Technology; Manager, Clean Air Program

and Generation Technology; Manager, Fossil Engineering; and (Acting) Vice President, Governmental Relations.

Mr. Golden served on the U.S. Environmental Protection Agency’s Acid Rain Advisory Committee and chaired the Base Programs Analysis and Policies Work Group

of EPA’s Clean Air Act Advisory Committee. He currently serves as utility chair of

the EPRI advisory committee dealing with post-combustion NOx control and is an

advisor on the EPRI boiler performance and SO2 committees. He also serves on the

board of directors of the UtiliTree Carbon Company, an entity formed to implement

carbon reduction and sequestration activities for utilities participating in the Climate Challenge Program of the U.S. Department of Energy.
43

Mr. BYNUM. Mr. Chairman, TVA finds itself in the position of

agreeing with what appears to be the EPA’s broader goals in these

NSR changes improving the nation’s air quality. However, we remain concerned that the agency may be tempted to shoehorn this

admirable goal into a program that’s primarily designed to address

the permitting and control of new sources. Literally, the New

Source Review Program is about who turns the wrench, when, and

where. It is not intrinsically designed to handle broad shifts in air

quality policy.

In the Summer of 1998 TVA announced a voluntary installation

of selective catalytic reduction controls to control of nitrogen oxide

emissions at ten of our larger coal plants. TVA has undertaken this

effort because we believe it is necessary if air quality improvements

are to continue in the Tennessee Valley region. We have committed

to this effort although it will cost more than $500 million on top

of the more than $2.5 billion that TVA has already spent to reduce

emissions from it coal-firing plants.

I note this voluntary effort for two reasons. First, I think it demonstrates our commitment to environmental stewardship. Second,

it represents an emission control effort based on a comprehensive

analysis of our entire system to achieve improved air quality

throughout the Tennessee Valley and adjacent areas. TVA carefully

considered the air quality challenges facing our region and we’re

placing SCR controls where they will do the most good. When considering how air quality should be improved, an approached similar

to TVA’s system-wide plan for nitrogen oxide reductions can be a

template. Although, the utility industry has just finished substantially reducing its NOx emission, the TVA thinks more can and

should be done. What is needed is a program that allows utilities

to reduce emissions on the system-wide or industry-wide basis over

time while still allowing units to be maintained as they have been

historically. Unfortunately, the attempts to achieve this goal

through the New Source Review Program likely will fall flat. The

underlying program is ill-equipped to answer these far reaching

policy considerations. TVA stands ready to work with this subcommittee and EPA to continue the improvements in air quality

and to develop the requirements for a successful program.

Mr. Chairman, the subcommittee’s interest in the proposed

changes to the New Source Review Program is well timed. We are

in an important juncture in trying to find a way to continue improvements in air quality without sacrificing the maintenance of

individual facilities or the reliability of the overall collective system. Thank you.

Senator INHOFE. Thank you, Mr. Bynum. As the only Federal

agency who must live under the NSR regulations, your testimony

is very important to us. You have both the credibility, if you want

to call it that, of a Federal agency and the real-world experience

of a private sector or a regulated industry.

Mr. BYNUM. Yes, sir.

Senator INHOFE. On the average how long does it take to apply

for and receive a permit under the NSR program?

Mr. BYNUM. I think the 12 months that have been mentioned is

probably a realistic average for permits.

Senator INHOFE. So you agree with Mr. Seitz in that?
44

Mr. BYNUM. I do. I think that’s about average. I think the difficulty with the timeframe, however, is if you look at some of the

activities that we’re concerned about being contemplated is you

don’t always have a 12-month lead time to know when you’re going

to have to do some of those activities. For instance, just 2 days ago

we removed a rotor from one of our fossil plants that was, in fact,

running just fine a week ago. Now we’re contemplating doing work

on that rotor and replacing that rotor and we can have that done

in a relatively short period of time. And we would be severely restrained if we had to go through a 12-month permitting process to

do that type of a replacement. So it’s not only the timing. I wish

I had a year to know every replacement, every major piece of maintenance that I had to do. I wished I had a year’s advance to know

what I was going to have to do.

Senator INHOFE. As a Federal agency, do you think you were

treated the same as other facilities?

Mr. BYNUM. Yes, I do.

Senator INHOFE. Could you explain what effect the NSR program

has on your reliability and also the effect on your rate payers?

Mr. BYNUM. Well, clearly, you know, we have to be able to maintain the reliability of our fossil plants. You know, we had understood and hope will continue the new source review, you know,

should not be aimed at not allowing us to do those projects that

improve efficiency, improve reliability of the system. We absolutely

have to maintain that reliability. This past year we broke our previously all-time record system usage 16 times in a 30-day period.

So the demand is continually growing, which means the reliability

of our fossil plants continually has to increase.

So in the case you were talking about with Mr. Seitz, the number

of hours those units are going to run is expected to increase. It has

to increase because of the increase in demand that we have on our

system. So it’s extremely important.

From our standpoint, we don’t have stockholders. The rate payers in our communities pay for all of the modifications, pay for all

of the—if a unit is not available, we have to go out on the

market——

Senator INHOFE. You never hear from them, of course?

Mr. BYNUM. Of course. We have quite a vocal rate paying community, I can assure you.

Senator INHOFE. Senator Voinovich?

Senator VOINOVICH. Earlier today I was talking to someone and

trying to get an understanding of what we’re talking about here.

And there is some understanding that when the Clean Air Act

went into effect that we grandfathered in the pollution that was already being generated at the time, and that nothing has been done

since that time to modify the facilities over that period.

I’d like you to comment about even though some of the old facilities have been grandfathered, are they still spewing out the same

emissions that were there when they were originally grandfathered? I would like you to comment on that.

Mr. BYNUM. Absolutely not. In fact, that is a common

misperception. As was discussed before, there are national ambient

air quality standards, and we have to meet those national ambient

air quality standards and those are met with modifications and
45

met by the existing power plants that we have that have been socalled grandfathered.

The Clean Air Act of 1990 which, through the acid rain portion,

required additional reductions. Those were done with these fossil

plants. Literally every plant in our system has had to do some type

of change as far as scrubbers—all the way from scrubbers on some

units down to fuel switches. But they all have been required to

change some mode of operation in order to meet the new—not only

the national air ambient quality standards but the acid rain legislation that was placed on top of that. So these facilities have not

been exempt from that. In fact, these are the facilities that we have

made the adjustments to that have been able to meet those requirements. We’ve reduced our SO2 by—or will have reduced it by

80 percent. By 2005 we will have reduced our NOx by 70 to 75 percent in the same timeframe on these units.

Senator VOINOVICH. I appreciate your clarifying that, because

there is that perception among some of the public that this is the

way it is. I know in our State utilities have spent an enormous

amount of money reducing the emissions going into the air. As a

matter of fact, when I looked the last time at some statistics, that

we had spent more in Ohio on dealing with that problem than

many of the utilities in the States that were complaining about the

loading of ozone going into their respective States.

One of the things that I’m concerned about, the WEPCO decision

came in and basically said if you make a major modification you’ve

got to get the permit. But they also said that miner modifications

were not subject.

Do you think that the rules that are being written today are

aimed at changing the WEPCO decision through regulation and applying a new standard?

Mr. BYNUM. I have a concern that they are. And, again, if you

look at the—you know, the exclusion is for routine maintenance.

And what’s routine maintenance and the types of things that I’m

talking about, boiler tube repairs, replacements, certain boiler sections, reheater replacements, major turbine work. I mentioned the

turbine rotor, other turbine type work. This work has been routinely done in our industry for years, before the WEPCO ruling. In

fact, I have a—I indicated the one paper that we had on routine

maintenance. I have another which was, in fact, written in 1972

that describes the typical maintenance that’s required to maintain

the reliability and availability of fossil power plants. Those things

have not changed. They are the same things that were good basic

maintenance practices to improve the reliability and efficiency of

plants in 1972 are the same things that we’re talking about today,

that we are concerned could be put in a rule that would prohibit

us from doing this or that would require repermitting and then the

putting on of controls subsequent to that. So that is our concern.

Senator VOINOVICH. One other comment, Representative

Strickland mentioned the statement of J.J. Berry, the International

President of the International Brotherhood of Electrical Workers.

And he raised some questions about safety and the welfare of utility workers. Would you like to comment on that?

Mr. BYNUM. Well, I share this concern. Anything that would tend

to threaten the reliability of pieces of equipment in a fossil plant
46

where you might have a failure of a piece of equipment could certainly be not only an issue of reliability but safety for our employees. We’re talking about conditions—4,000 pounds of pressure in

some of these boiler tubes, that’s a two-and-a-half mile depth in the

sea, 3,000 degree Fahrenheit, 24,000 volts in our generators. So

we’re in, you know, a relatively hostile environment. And anything

that degrades the reliability of equipment in that environment, you

know, certainly would be an issue with public health and the safety

of our employees.

We have done projects in the past. For instance, we did a balance

draft conversion on a number of our units, and that was largely

driven by the atmosphere that was created in the upper sections

of our power plants. And now, you know, we would be afraid that

those types of projects through some new rule would be prohibited

or at least require you to go back through the permitting process.

And we think that would be very detrimental to us being able to

conscientiously go forth with our responsibilities for employee

health and safety.

Senator VOINOVICH. Thank you.

Senator INHOFE. Thank you, Mr. Bynum.

I’d now ask that our fourth panel come to the witness table.

Panel 4 includes Mr. Bob Slaughter, Director of Public Policy for

the National Petrochemical and Refiners Association; Mr. W.

Henson Moore, an old friend of mine from the House of Representatives days and now the President and Chief Executive Officer of

the American Forest and Paper Association; Mr. David Hawkins, of

the Natural Resources Defense Council; and Mr. Bill Tyndall, who’s

been back with us several times before and used to be with one of

my closest friends in the House John Dingle, now Vice President

of Environmental Services of Cinergy Corporation.

With that said, we’ll start in the order that the panelists appear

on the agenda.

Mr. Slaughter?

STATEMENT OF BOB SLAUGHTER, DIRECTOR, PUBLIC POLICY

NATIONAL PETROCHEMICAL AND REFINERS ASSOCIATION

Mr. SLAUGHTER. Good afternoon, Mr. Chairman, and Senator

Voinovich. My name is Bob Slaughter. I am general counsel and director of public policy for the NPRA, the National Petrochemical

and Refiners Association. I am here today to present joint testimony on behalf of both NPRA and the American Petroleum Institute. Together those associations represents essentially all petrochemical and petroleum refiners for whom NSR reform is a very

critical issue.

My message today is a simple one. New Source Review reform

is needed to allow refiners to continue their record of achieving significant environmental progress. And almost as we speak the EPA

is in the process of issuing far reaching new environmental regulations which necessitate further changes in refinery facilities and

operations.

The current EPA interpretation of NSR threatens to frustrate

our efforts at compliance with these new initiatives. Even worse,

certain EPA activities indicate that some agency officials may even

be seeking to second guess past actions which were taken in good
47

faith and in reliance upon NSR interpretations, which we believe

to be both firmly established and long settled. This amounts to

changing an existing regulation without public notice and comment

or congressional review.

Clearly NSR reform is needed to remove the cloud of uncertainty

over the current and future operations of refiners and other key industries. We hope that this hearing will help lead to effective NSR

reform.

Refineries have an impressive record of emission reduction. As

shown on the first chart, EPA figures demonstrate that we have reduced our emissions by 74 percent between 1980 and 1996. Refining capacity declined only 16 percent during the same period. Since

then we have made further progress both in reducing emissions

from refineries and in cutting emissions from our products, such as

through the reformulated gasoline program.

We are being asked to do much more. The second chart is what

we call our regulatory blizzard chart. It lists recent anticipated environmental initiatives, 13 of them, with which the refining industry must comply in the immediate and near future. We will spend

billions of dollars to meet these requirements. Most, if not all, will

require changes in facilities or procedures. For example, the final

Tier II gasoline sulfur rule will require roughly $8 billion of industry investment in a short timeframe to accomplish what EPA estimates is the environmental equivalent of removing 164 million cars

from the road.

The upcoming diesel sulfur regulation will cost roughly an additional $4 billion and must be implemented over nearly the same

time period as gasoline sulfur reduction. Current NSR interpretation will impede our efforts to comply with these new environmental requirements. Although intended to limit emission increases, New Source Review now applies to actions which do not

increase or which may even reduce emissions. Traditional tests to

determine NSR application are now structured to require NSR in

most instances.

Former exceptions to NSR application have been narrowly construed or recast so that they provide little or no relief. At best current NSR policy is hopelessly confusing. At worst it can be paralyzing. When triggered, NSR is an onerous and time consuming process. Despite the fact that it is effectively impossible to determine

when an NSR permit is required, refiners must somehow decide

whether an anticipated action triggers NSR permitting and controls. If it does, they must obtain the required permit before beginning any construction, install appropriate emissions control technology, and perhaps meet other requirements as well. On average

it takes 18 months to 2 years to get an NSR permit.

State NSR decisions may also not reflect the EPA’s latest positions. The EPA has delegated the program to most States but is

now investigating State permitting decisions affecting refineries

over the last 20 years. These decisions were not questioned during

20 years of State and EPA inspections. Refineries are in a quandary because State decisions may not be supported by EPA, while

EPA’s own guidance is difficult to find and often contradictory or

confusing when located.
48

Some EPA officials, however, do seem to realize these problems.

Talks have recently taken place between EPA and representatives

of several affected industries to discuss the need for NSR reform.

API and NPRA have been participants. We are encouraged by the

discussion that has occurred and hope that more talks will be

scheduled. The EPA has also participated in one industry workshop

regarding ways to expedite permitting relative to the gasoline sulfur rule. A joint workshop will be held next month. We appreciate

EPA’s commitment to these efforts but believe that underlying

NSR reform is needed to provide us and other affected industries

with greater certainty. We need an NSR process that is simple, efficient and transparent.

Our thanks to you, Mr. Chairman, and you, Senator Voinovich,

for your interest in this important issue. I look forward to answering your questions.

Senator INHOFE. Thank you, Mr. Slaughter.

Henson?

STATEMENT OF W. HENSON MOORE, PRESIDENT AND CHIEF

EXECUTIVE OFFICER, AMERICAN FOREST AND PAPER ASSOCIATION

Mr. MOORE. Mr. Chairman and Senator Voinovich, thank you

both for having this hearing. I’m Henson Moore, the President of

the American Forest and Paper Association. We think the NSR program ought to meet a few basic principles. They ought to be consistent. They ought to follow congressional intent. It ought not be

changed retroactively, that they should benefit the environment,

and the program regulators, the program office, not the enforcers,

ought to set new changes in policies and ought to be open to public

scrutiny. Based on these principles today’s NSR program is broken.

We’re not the only ones that think that. The EPA itself thinks it’s

broken. The States do. Republicans and Democrats in Congress do.

And we have a statement we would like to include in the record,

Mr. Chairman, from unions in our industry representing a quarter

of a million of our workers who also feel this program is broken.

Basically it’s broken because when it requires a permit, something that takes—in the case of our industry we’re seeing somewhere between a year and a year-and-a-half to get one of these permits for a physical change, we think this is something that ought

to be looked at very carefully. Congress never intended NSR to impose new controls on equipment simply because of routine maintenance. The idea was if you’re doing something that’s going to increase emissions, you ought to go get a permit. We agree to that.

The problem is not congressional intent. It’s the way it’s being implemented. Furthermore, it’s confusing.

Mr. Chairman, you’ve got a few pages in the United States Code

that deal with this. These citations deal with New Source Review.

Here are 4,000 pages of conflicting guidelines, regulations, and

rules put out by EPA and various offices of EPA to interpret these

few pages. That’s the problem. The program is so complicated. It’s

so conflicting. It’s so difficult to deal with. Nobody in the EPA

knows how it works, and certainly the people trying to conform to

it don’t know how it works.
49

Let me give you an example of routine maintenance. In 1980

EPA provided an exclusion from NSR review for routine maintenance. We operated fine under that for 8 years. Then EPA came

out and said, well, we’re going to change that. We’re going to weigh

a variety of factors to arrive at a common sense finding of what

was routine maintenance. We operated with that. Then last year,

the enforcement office now, the people who actually fine you and

hold you in violation of the rules, substantially narrowed this exclusion and without any public input stated it was meant to cover,

I quote, ‘‘frequent, traditional, and comparatively inexpensive repairs to maintain existing equipment.’’ That’s a 180-degree change.

Now you are liable retroactively for fines and penalties back to

1980 when you were told it was OK and there is no amount of permitting time for this kind of routine matter that is acceptable.

Even if you got it down to 6 months, as Mr. Seitz said, or 3

months, you still can’t run a business based on this kind of a holdup, waiting to see if you can get something routinely done without

risking fines on a per diem basis. So the first problem is you’ve got

to reform NSR to make it work. This is not workable. Nobody

thinks it is. It needs to be changed.

But you’ve also got another problem. The problem is the unfair

and egregious enforcement of these retroactive rules, interpreting

and changing rules and applying them retroactively and applying

fines. For example, 10 years ago we had a mill that replaced an

old power boiler with a new one that had potential lower emissions.

The State, after getting comments from EPA, said this is OK and

gave us the approval to go ahead and proceed. Now EPA says the

boiler increases mill operating capacity and potential emissions

and, therefore, alleges the mill failed to comply with NSR requirements and is now asking for fines going back 10 years when, in

fact, it was cleared by the State. There have been no increase in

emissions. And actually, at the time it was thought it would have

potential lower emissions. There are other examples.

Now we’re not quarreling with implementation of the law, where

somebody, as Mr. Seitz says, where you’ve got a change of a stationary source that increases emissions. If that’s the case, you

ought to go throught NSR; and if you didn’t do that and get a permit you are liable, and it’s OK to go back no matter how long you

have to go back to enforce that kind of a situation. Now we’re talking about potential, phantom emission increases. We’re talking

about not actual changes at all or actual changes in the emissions

from these plants. Therefore, we feel like EPA ought to suspend

these enforcement actions—against anybody that has not actually

increased emissions until such time as they finish the reforms in

the regulations themselves. This is a program that is broken and

needs to be fixed. And unfortunately, they are continuing to break

the rules retroactively through the enforcement procedures to make

it even more egregious and make it worse.

Senator INHOFE. Thank you, Mr. Moore. Are you going to submit

that document you held up?

Mr. MOORE. This one, but not this one. If you want them, you’re

welcome to them.

Senator INHOFE. That reminds me a little bit of in the 1980’s a

State of Union message that I heard when they brought the tax
50

code out. No, I’m talking about the document on the workers that

were affected——

Mr. MOORE. Yes, that’s this one.

Senator INHOFE. Thank you very much. [The referenced document follows:]

STATEMENT OF MICHAEL DRAPER, CHAIRMAN, FOREST PRODUCTS INDUSTRY

NATIONAL LABOR MANAGEMENT COMMITTEE

On behalf of the Forest Products Industry National Labor Management Commit- tee (LMC), I would like to submit the following statement for the record. The LMC is a coalition of labor unions and forest products associations formed

10 years ago to pursue the conunon goals of the working men and women of our

industry. Collectively, the LMC represents over 2 million workers nationwide, include 250,000 forest products workers. Our members are employed in hundreds of

wood, pulp and paper manufacturing cities throughout the nation, producing the

products used by consumers in households, offices and schools across the globe. I began my career as a member of the United Brotherhood of Carpenters and Joiners of America (UBCIA) in a sawmill in California. Today, I am the Regional

Vice President for the UBCJA and represent workers across the Western United

States. The forest products industry—both the wood and paper sectors—has been

devastated over the last decade due to a decline in timber harvests and restrictions

on manufacturing facilities. I have personally seen entire towns destroyed as local

mills shut their doors because they were no longer able to compete, sending thousands of workers to the unemployment line. Throughout my proud career, I have

had the oppose to work with thousands of individuals, including community leaders,

county officials, working families, environmental groups, local and State legislators,

as well as leaders in Washington, DC—all in pursuit of a common goal to provide

the best public policy solutions for forest products workers and rural communities. The forest products industry and its workers depend upon the environment for our livelihooods, and working together, our Coalition is proud of our strong record

of environmental stewardship and we recognize our responsibilities to ensure a

cleaner environment for all Americans. We have come a long way over the last decade, and increasingly our industry continues to embrace new standards in environmental stewardship, including the American Forest and Paper Association’s Sustainable Forestry Initiative (SFI)’sm, The SFIsm is an innovative approach to securing the proper guidelines and principles to providing sound scientific practices to

protect our air, water and land.

On behalf of the working men and women in pulp and paper manufacturing facilities throughout the nation, I am submitting this statement today out of concern for

the Environmental Protection Agency’s New Source Review (NSR) program. We support the Agency’s goal of providing a cleaner and safer environment for all Americans, yet are concerned that the NSR program is not working and the complexities

of the guidelines are dwarfing its ultimate mission.

The Environmental Protection Agency is currently reviewing what the Agency admits is a ‘‘broken’’ New Source Review (NSR) program. First established under the

1917 Clean Air Act Amendments, the NSR program is considered to be the Act’s

single-most complicated regulatory program. As a result, our industry has struggled

to understand and comply with the regulations, which stem from more than 4,000

pages of interpretive guidance.

Oftentimes, decisions orally approved by the Agency are overturned several years

later based on changes in interpretive guidance that did not exist at the time the

original compliance decision was made. In a 1996 proposal to reform the Cleen Air

Act, the Agency explained that it had specifically recognized that routine maintenance, repair and replacement did not trigger the modification rule. Now, the NSR

program is being interpreted to cover virtually anything the pulp and paper industry is doing to expand, improve operations and make equipment changes to meet

environmental requirements, even when these changes reduce emissions and improve efficiency.

Today, the guidelines of the NSR program are confusing and oftentimes inconsistent and contradictory, which is ultimately hampering our ability to successfully

compete in the global market. The complexities are impeding innovation, inhibiting

the use of new technologies or forestalling attempts to enhance environmental performance and energy efficiency. Our manufacturing facilities are shelving these

plans, stifling new opportunities for growth and development.

Yet even more troublesome is the fact the the Agency is moving ahead with a new

enforcement initiative before the NSR program is fixed. Manufacturing facilities are
51

facing penalties reaching $25,000 per day starting when the actual construction or

modifications began, in some cases going back nearly 20 years! Our industry estimates that the initiative could cost as much $10 to $50 million per mill, a price tag

that would halt production and force many of our plants to shut their doors. The

end result: high-skill, living wage jobs will be sent overseas. The demand for our products is high and we must all work to keep these jobs on American soil. Natural resources are an integral part of our work; the environment is our Trade—from the products we produce, to the air we breathe and the

water we drink. It is critical that we work toward the best policy solutions to balance the environmental, social and economic needs of our society. We are all committed to a common mission, so let’s work together to sustain a healthy environment

for future generations. Today, we ask our leaders in Congress to work with the Environmental Protection Agency and all shareholders to create and quickly implement a reformed NSR program—a new program that will not stifle innovation and cost American jobs—a new

program that will be fair, consistent and allow smallholders to comply in the spirit

of law, providing a cleaner and safer environment for our children and grandchildren.

Senator INHOFE. Mr. Hawkins?

STATEMENT OF DAVID HAWKINS, NATURAL RESOURCES

DEFENSE COUNCIL

Mr. HAWKINS. Thank you, Senator. Well, looking at this stack, no one can argue that the program has been bad for the paper industry.Senator, thank you. Most of today’s witnesses have focused on the problems that the Clean Air Act presents for polluting sources.

I’d like to comment on the problems that are presented for our

members and your constituents, particularly the elderly and children, whose health is at risk from today’s pollution burden. Just last week Ohio environmental groups published a report on the continuing problem of smog in the Ohio River Valley that documented the large number of adverse health effects, including over

83,000 asthma attacks that were directly attributable to elevated

smog, over a thousand emergency room visits, over 600 hospital admissions. Now it’s important to understand how much of a smog

problem is due to old, grandfathered pollution sources, ones that

should have been cleaned up under the Clean Air Act but have not

been.

For example, fossil electric power plants are major contributors to smog and soot problems. What’s astonishing is how much those

older plants dominate the inventory for that sector. Over 80 percent of the total U.S. emissions from fossil electric generating

plants for sulfur and nitrogen emissions come from power plants

built more than 20 years ago. Now contrast that to the motor vehicle program. In the motor vehicle program 20 year old cars contribute to less than 7 percent of NOx emissions. If we had the problem

with motor vehicles that today’s power plants represent in terms

of old sources, we would all be choking to death quite literally.

Why is this? Well, because contrary to the expectation of Congress old plants have been kept running. They have been kept running rather than being replaced by cleaner sources. Many of these

actions were due to loopholes in the law. But too many instances

the strategies of keeping plants running have been carried out

without complying with NSR requirements.

The courts are going to decide based on the facts in particular

cases, so I’m not going to get into the facts in particular cases. But

let me comment on a couple of broad arguments that were repeated
52

here today. The first is, ‘‘It’s all just routine maintenance.’’ And the

second is, ‘‘EPA has changed the rules.’’

On the first point, the claim that everything is just routine maintenance is a rewriting of history. I have here two large volumes of

proceedings of electric industry conferences held in the mid 1980’s.

All of the documents in these two volumes relate to programs to

extend the life of existing coal-fired power plants by another 20 to

30 years past the design life of those facilities. And just to quote

from the proceedings themselves, at the beginning of this 1984 document it says: ‘‘Typically the fossil fuel power plant is designed for

a 30-year life. But as new fossil plants become increasingly difficult

to finance, efforts are being made to extend the life of aging fossil

plants to 50 or 60 years of reliable service.’’

In this 1984 conference 27 out of the 33 utility companies that

were surveyed said they had begun or were planning life extension

programs. And I would like to submit that survey for the record,

if I might.

Senator INHOFE. Without objection.

[The referenced survey follows:]

PROCEEDINGS: FOSSIL PLANT LIFE EXTENSION CONFERENCE AND WORKSHOP

Washington, DC, June 12–15, 1984

Workshop Director J. R. Scheibel

Prepared for Electric Power Research Institute

SYNOPSIS OF QUESTIONNAIRE RESULTS FOR EPRI PLANT LIFE EXTENSION WORKSHOP

JUNE 12–15, 1984

Plant life extension will play an increasingly important role in meeting U.S. generating requirements. This fact was made apparent in the utility responses to questionnaires concluding the June 12–15 workshop held in Washington, D.C. Approximately 94 percent of 33 responding utilities expect plant life extension to play a significant role in meeting their system demand in the future. Of the utilities expecting

plant life extension to play a significant role in meeting their system demand, 40

percent have already implemented such a program, 10 percent expect to implement

a plant life extension program within 5 years, and the remaining 50 percent plan

to implement a plant life extension program within 20 years.

Six principal considerations stand out for establishing a power plant as a candidate for life extension. They are, in order of importance:

• Plant age.

• System load demand and future expectation.

• Physical plant condition.

• Operating Efficiency.

• Availability.

• Maintenance costs.

Other considerations identified by the responding utilities as considerations for establishing a plant as a candidate for life extension include: 1) plant replacement

cost, 2) proximity to load, 3) operating costs, 4) fuel availability, 5) operating history,

6) politics, 7) new pollution control equipment, and 8) safety.

The responding utilities indicated that plant life extension studies are generally

carried out in house. This is primarily dependent on having adequate in-house engineering staff and expertise to support the study or studies. Where the magnitude

of the effort exceeds the utilities technical resources, assistance from OEMs and A/

Es is obtained.

The utilities identified four units that have already had their life extended, or are

scheduled for completion in 1984. One additional unit is scheduled for completion

in 1986. Life extension studies have been completed for another 43 units, most of

which have begun plant modifications and are in various states of completion,

though no specific completion dates are identified. An additional 134 units have
53

been identified as candidates for study or presently being evaluated for life extension.

Noted units range in size from 40 MW to 900 MW with coal being the predomi- nant fuel Present age of the subject units ranges from 10 years to 49 years with

the greatest concentration of units in the 20- to 35-year bracket. Desired total service life, including the extended life period, is from 50 to 60 years. Of the 139 units

identified thus far for plant life extension, the predominant operating mode intended is for cycling and/or baseload service. Approximately 52 percent of the units

will operate in cycling service while 43 percent of the units will be base loaded. The

remaining 5 percent will operate in peaking service or load following mode. One unit

is scheduled for mothballing. In addition to the units noted above, 15 additional units are slated for conversion

from their design condition fuel. Nine are to be converted from oil or gas firing to

coal, and six units will be converted to either atmospheric fluidized bed combustion

(AFBC) or integrated gasification combined cycle plants. Fourteen of the 15 units

are 80 MW and under in size, while one unit is 250 MW. Unit ages range from 28

to 40 years, with an average age around 32 years. The utilities identified three principal areas for uncertainty when evaluating plants for life extension. In order of importance, these uncertainties are:

• Estimating remaining life. • Evaluation of boiler and turbine. • Evaluation of headers, drums, and piping.

Other uncertainties identified include: 1) verification of life extension and

uprating, 2) material properties, 3) evaluation of electrical components, 4) generation planning and costs, including maintenance cost to support target availability,

5) evaluations requiring historical OEM data, 6) environmental considerations, and

7) probability of major failures. The utilities see a very significant role for diagnostic monitoring equipment in- cluding: vibration, stress, and condition analyzers during the extended life period. The utilities noted that they would like future workshops planned on plant life extension. Primary areas of interest, listed in order of preference, include:

• Concentration on utilities’ findings. • Update on ongoing projects. • Methodologies. • Equipment evaluation and diagnostics. • Remaining life estimation. • Program planning. • Metallurgy and electrical components. • Generic problems. • High pressure piping. • Instrumentation and controls.

In order of preference, the utilities desire EPRI to undertake development programs in the following areas to assist in their carrying out or implementing life extension activities:

Boiler life extension—Drums and headers

—Superheaters and reheaters

—Waterwalls

—Controls

—Structural members

—Burners

—Fans

—Pulverizers and feeders

—Valves and piping

—Ductwork

—Fabric expansion joints. • Balance of plant evaluation

—Piping

—Controls.

—Feedwater heaters

—Condensers

—Pumps

—Valves

—Motors

—Transformers

—Switchgear

—Cable, wiring

—Precipitators
54

—Cooling towers

—Deaerators.

• Turbine life evaluation

—Shafts

—Generators

—Blades Discs

—Controls

—Bearings.

• Generation planning studies.
55
56
57
58

Mr. HAWKINS. The conference participants were clear that these

life extension efforts involved much more than routine maintenance, and I’d like to quote from a paper delivered by Duke Power.

Duke Power said: ‘‘As in the case with most U.S. utilities, Duke

Power has experienced a major change in operating philosophy in

the past several years. This necessitated us developing a different

approach than routine plant maintenance, which would have been

responsive to the new schedule constraints. Plant maintenance program previously employed did an excellent job in minimizing cost

outlays versus keeping this plant in service until the end of its design life. This program simply can’t be applied to the present situation.’’

At another industry conference 2 years later TVA described how it had begun its fossil and hydro unit evaluation and modernization

program in 1984 with the primary goal: ‘‘to extend plant life 20 or

more years beyond its design life of 35 to 40 years.’’ Cincinnati Gas and Electric presented a detailed paper describing its life extension project at the Beckjord Unit 3, which involved

49 capital improvement projects which the paper distinguished

from normal maintenance. And I’d like to submit that for the

record.

Senator INHOFE. Without objection, it will be entered into the record.

[The referenced report follows:]

LIFE EXTENSION AND ASSESSMENT OF FOSSIL POWER PLANTS

CONFERENCE PROCEEDINGS

(Editors, Barry Dooley and Ramaswamy Viswanathan)

ABSTRACT

A great many utilities across the country have included Life Extension as an inte- gral part of their generation expansion plans. Life Extension has temporarily replaced new construction. Most of these utilities have adopted a ‘‘phased’’ approach

to Life Extension of candidate units. The Cincinnati Gas 6 Electric Company’s W.

C. Beckiord Station-Unit 3 is the first generating unit in the country to complete

a ‘‘full’’ instead of ‘‘phased’’ life extension program. During a 13-week outage which
59

ended in January, 1986, all life extensive modifications recommended as a result of

extensive studies were implemented. A total of forty-nine replacement and/or modification projects were performed to add approximately 25 years to the unit’s life at

a total cost of less than $100/kW. The planning, coordination and project management utilized to inspect and evaluate the condition of the unit, procure materials,

equipment, and contractors and complete the installation and startup are discussed

in detail.

BACKGROUND

LL C. Beckjord Station is located on the Ohio River near New Richmond, Ohio,

approximately 17 miles upstream from Cincinnati, Ohio. Unit 3 has a rated capacity

of 128 MW and was placed into service in 1954. The unit consists of B&L front fired

single reheat pulverized coal boiler and a General Electric tandem compound two

flow turbine. Steam conditions are 1800 psig/1000 deg. F/1000 deg. F.

The unit was conservatively designed, well-built, and has been well- maintained.

Its heat rates and availability have been favorable. An analysis of CO&E’s generation expansion plan identified Unit 3 as the prime candidate for life extension.

STUDIES

For 30 years, the plant operators, maintenance and other support personnel have

worked with the unit. They know it well; they know its limitations and its strong

points. They have a good idea of what equipment is or is not suitable for another

twenty-five years. This knowledge is a valuable source of information. In our studies, it was used to build the foundation for our detailed investigations. It allowed

us to focus our resources on specific areas.

Our preliminary studies had estimated a cost of $89/kW to extend the life of Unit

3.

One of the most questionable areas in the determination of remaining life is turbine-generators, especially rotors and shells. We realized that this equipment is

highly engineered and that much of the information required to properly evaluate

this equipment is proprietary by the manufacturer, General . Electric. In the case

of Unit 3, General Electric had been involved in every turbine overhaul since the

initial startup. For these reasons, GE was contracted to perform a life extension

evaluation of the turbine-generator equipment. This study was initiated in September 1983, and completed in February, 1984.

The GE study of the turbine-generator supported our original estimate. Management approval was obtained in June, 1984, to proceed with life extension. A 13 week

outage was scheduled for the fall of 1985.

A team was assembled to investigate the remaining areas of the unit. Organization of the study team is shown in Figure 1. The Boiler Plant study was conducted

by our in-house engineering personnel with assistance in the evaluation of high temperature components from Babcock & Wilcox. Electrical equipment and structures

were also evaluated by in-house personnel. Bechtel Associates was contracted to perform the life extension evaluations of balance of plant equipment. Bechtel was responsible for basically all other equipment not supplied by either the original boiler

or turbine contractor??

These studies were formally kicked off in July, 1984, and were completed in February, 1985, as scheduled. This demanding schedule was complicated by the need

to conduct the inspection during a 2-week period. This required special considerations and careful planning. The inspection work was carefully staged and scheduled so that the unit could be returned to service within 24 hours notice if required

for load.

SCOPE OF WORK

As a result of the study, 49 capital improvement projects were identified for the

life extension outage. CG&E defines capital projects in accordance with Federal Energy Regulatory Commission guidelines. A list of these refurbishment projects is

provided in Table I.

A MAJOR PROJECT WITP A MINOR SCHEDULE

At the time of our inspections, the outage to implement the recommendations of

those inspe * ions was less than 1 year away. Action had to be taken to expedite

procurement of long lead time items. Our requirements for obtaining competitive

pricing could not be compromised and, before we could proceed with any purchase,

our evaluation and cost justification for the replacement or modification had to be

approved.
60

It was obvious, that in order to maintain our commitment to the outage schedule, we must utilize some of the project controls normally reserved for major, new construction projects.

WCB–3—LIFE EXTENSION CAPITAL WORK

• Turbine Related

Bucket Replacement (5 rows)

Steam Seal Conversion

HP Inner Shell Replacement

Static Exciter

Stop Valve Bypass Valve Installation

Generator Field Rewind

Generator Stator Rewind

Starting & Loading Thermocouples

Misc. Control Improvements

Condenser Retubing

Fine Mesh Screens.

• Boiler Related

Bunker Replacement

ID Fan Drive Replacement

Demineralizer Replacement

Combustion Controls

Service Water Piping Replacement

Water Sampling Room

Annunciator Replacement

Boiler Skin Casing

Insulation Replacement

Ignitor Replacement

Feeder Motor Replacement

Secondary Air Dampers

Primary Air Fan Replacement

Sootblowers Replacement

Secondary Superheater

High Temp. Headers (3)

Primary Reheater

Secondary Reheater

Uninterruptible Power Supply

Misc. Control and Panel Equipment.

Total Project cost approximately $13,000,000, including all engineering, overheads, and allowance for funds.

Table I

We had recently acquired the PREMIS critical path method scheduling program. In the past, on major projects, our scheduling work had always been handled by outside consultants. As soon as we were able to identify a potential replacement or

modification for the outage, action was taken to input the schedule into the PREMIS

program. Our primary concerns at this point were to:

1. Order and receive all materials and equipment prior to the first day of the out- age, and 2. Complete all engineering and drafting in-time to allow for obtaining competitive bids, and

3. Award installation contracts in time to allow contractors to prepare detailed installation schedules.

On this project, our plans were to complete all engineering in-house for capital projects. Many of our engineering personnel were unfamiliar with the PREMIS program. To expedite the input of information, standard forms were prepared that listed the normal steps in the engineering-procurement-drafting process in our company. The engineer simply had to fill in the estimated time to complete each step

in the process and/or fix the date when the step had to be complete. These forms

greatly simplified the schedule formation process. Once the PREMIS schedules were input, the critical paths were identified and we

were able to concentrate our efforts on those items in trouble.

CONTRACTORS

It has been our experience that the fewer contractors on the jobsite, the easier

it is to control the project. Limiting the contractors also limits the ‘‘finger-pointing’’

and simplifies coordination. For this project, installation contractors were chosen for

the following work packages:
61

• Turbine-Generator • Boiler • Electrical • Piping • Condenser • Asbestos Removal • Insulation.

Besides the capital work involved in the life extension project, there was a large amount of maintenance work identified by the plant that had to be included in the

work packages. This required a close working relationship between engineering and

plant personnel related to the outage. The turbine-generator installation contract was awarded to General Electric. Much of this work, especially service shop work, was awarded on a firm price basis.

Late in the outage, problems were found with the stator windings in the generator.

National Electric Coil was contracted to manufacture and install the new stator

windings without impacting the outage schedule. Competitive bids were obtained for the boiler work. Babcock & Wilcox was successful. This scope of work was by far the most extensive of the project. B&W was

also successful supplier of all of the boiler material being installed in this work

package. This offered a great advantage since we were able to negotiate a single

source responsibility from B&W for both materials and installation. This project involved the removal of asbestos bearing insulation from the entire boiler, (over 15,000 sq. ft.). Both the removal and the replacement were performed

on firm price, competitive bid contracts. R. E. Kramig Co. of Cincinnati, Ohio performed the removal. Powerhouse Equipment of Akron, Ohio performed the replacement.

All electrical work was assembled into a package and awarded to a local Contrac- tor’ Watson-Flagg. Likewise, all piping work (except for boiler related) was assembled in a package and awarded by competitive bid to a local piping contractor,

Mechanicals, Inc.

The condenser retubing and installation of ID fan drives (both in secluded areas of the plant) were bid separately and awarded to a local contractor, Enerfab. Each of the installation contractors were required to provide detailed Schedules

within several weeks of award. These bar charts were required to include each step

of the installation process and men per shift per day for each of these steps. This

data became the basis for the project outage schedule. Prior to award of the installation contracts on this project, our management nego- tiated an agreement with the National Maintenance Policy Committee for craft

labor of signatory unions to work at 90 percent of full scale wages. This resulted

in a considerable savings in installation cost for this project.

THE OUTAGE TEAM

As with any major project, a field engineering staff is necessary to service con- struction and administer the contractors. When our last new unit was completed,

our normal field construction staff was reassigned. A new team with special characteristics had to be assembled for this project. These special characteristics for the

Outage Team were:

1. A clear understanding of existing plant operations and good working relation- ships with plant personnel.

2. A familiarization with the modifications and equipment to be installed. The outage length did not allow time for someone to be trained. 3. The tenacity necessary to effectively manage contractor personnel.

4. A willingness to devote long hours to the project.

Fulfilling these objectives required a mix of engineering and plant personnel. Our

General Engineering and Electric Production Departments each contributed individuals to the Outage Team. Temporary reassignments were made. The Outage Coordinator was brought in from another generating plant, thereby allowing for his undivided attention to the project. The organization is shown in Figure 2. The Outage

Coordinator was directly responsible for the outage work. His team of Field Engineers were the single source contacts for the contractors. It was the responsibility

of the Life Extension Project Leader to procure equipment and contractors. It was

the Outage Coordinator’s responsibility to see that the contracts are carried out.

The Outage Team was located in a room off the Turbine Room fittingly called

‘‘Outage Central’’. An outage board 35 foot long by 8 feet high (see Figure 3) displayed all schedules for boiler and balance of plant equipment installations. A smaller board on the opposite wall displayed turbine work. These boards were the focal

point of daily contractor meetings. Each morning at 8:30 a.m. all contractor rep-
62

resentatives grouped to discuss progress from the proceeding day and activities to

take place that day. If activities scheduled for the previous day were not completed

as scheduled, they were moved back and their impact on other operations and the

overall schedule could be assessed immediately. These meetings could be intimidating and were an effective tool. The discussion of daily activity by each contractor

was very effective in minimizing lack of coordination problems. The contractors were

also responsible for reporting their manpower levels at these meetings.

THE OUTAGE

The outage was scheduled for October 25, 1985 thru January 25, 1986. The first

15 days of the outage were used exclusively for asbestos insulation removal. The entire boiler area from ash hopper to penthouse was enclosed with plastic sheeting

and placed under a negative pressure. The insulation removal contractor worked

three 8-hour shifts per day for these 15 days and completed all work as scheduled.

Eighty large dumpsters of material was removed. During this work, we maintained

field engineers at the site around the clock to ensure the work remained on schedule

and was completed in accordance with applicable safety regulations.

During these 15 days, the Boiler Room of the unit was closed off to all other personnel.’ As a result; other contractors, such as the boiler and piping contractors,

could not begin work until November 11, 1985.

The outage went well. Jobs initially considered crucial and close to impossible,

such as the boiler skin casing, went very well. All contractors, with the exception

of the turbine contractor, were originally scheduled for one or two 8-hour shifts. The

turbine work was done on two 10-hour shifts. It was only during the last week of

the outage that limited overtime became necessary.

Three occurrences took place during the outage which had great potential for upsetting the schedule. Each occurrence was dealt with accordingly and adjustments

made to compensate. As a result, the scheduled completion date remained unaffected. These occurrences are described below.

1. As mentioned earlier, the stator rewind was found to be in need of rewinding.

Coils were manufactured, installed and tested within 8 weeks of award.

2. The main steam and hot reheat lines were found to be severely exfoliated.

Within 10 days of a decision to acid clean this piping, the cleaning system connections were fabricated and installed, the cleaning completed, and the temporary connections were removed. Total cost of this work was slightly over $100,000. The turbine and boiler contractors were slightly delayed, however, a weekend of overtime

brought them back on schedule.

3. Difficulties in electrical testing and delays in release for testing. Adjustments

were made in testing responsibilities, work hours and overtime to compensate.

The Outage was completed on schedule. On January 25, 1986, at 9:37AM the generator relay was closed. On January 27, 1986, a cold spell hit the Cincinnati area

and the unit was used to produce over 100 MW’s (75 percent of full load) to meet

the system demands.

Generator vibration at the first critical was unacceptable. After several balance

attempts, the rewound field was removed and balanced at low speed on Site. Mid

plane balance was required to reduce vibration. This field removal, balance, and replacement work took 1 week after the unit was finally removed from service.

COMPANY LABOR EFFORT

CG&E labor efforts were monitored throughout the entire project from study thru

the full implementation of life extension recommendations. All but one Of the jobs

in this project were engineered by in-house engineering personnel. All field engineering, drafting, and electrical testing was completed by our company personnel.

A summary of the hours is shown in Table II below:

Table II

Summary of Company Labor WCB–3 Life Extension

Description Manhours

Engineering (study only) 5,900

Engineering of Modifications (incl. field

eng’rg.).

13,800

Drafting ......................... 8,200

Scheduling .................... 1,100
63

Table II—Continued

Summary of Company Labor WCB–3 Life Extension

Description Manhours

Electrical Testing .......... 8,400

Plant Support ................ 1,600

Total ..................... 39,000

Figure 4 compares monthly manpower requirements to major events in the schedule.

CONCLUSION

Our work is complete on Unit 3. All modifications required for life extension have

been implemented. We can walk away from the unit with reasonable assurance of

its operating reliably thru the extended life period.

The outage was a great success. It was completed on time and within budget, and

at a cost of less than $100/kW. We’ve learned from our experience and are implementing changes now for our next outage on WCB–2 in October, 1986. This will be

another full implementation of life extension recommendations.

The PRENIS program will be used to schedule not only the engineering and procurement, but the actual outage work itself. Through careful planning for completion of each item prior to contractor bidding, we hope to greatly reduce our electrical

testing and contractor overtime.

Work scopes are being detailed far in advance of the outage to minimize extra

work. We are capitalizing on our experience to reduce our engineering and drafting

efforts. Major scope changes such as the rewind of the generator stator and acid

cleaning of the main steam and hot reheat line are being planned. Our field engineering personnel will be better supported with assistance to provide better cost

control and cost reporting.

ACKNOWLEDGEMENTS

Presentation of this paper is not complete without acknowledgement to the hundreds of individuals who made this life extension project a success. Everyone involved; the engineers, draftsmen, craft labor, technicians, clerks and typists played

an important role in the final outcome. Special recognition is given to the Outage

Team, whose unselfish dedication to the project made the pieces all come together.

REFERENCES

Pulskamp, B.E., ‘‘Life Extension of W. C. Beckord Station—Units 1, 2 & 3’’, Electric Power Research Institute Fossil Plant Life Extension Workshop, June, 1984

Mr. HAWKINS. How about the point that the EPA has changed

the rules? Well, my time is up and I don’t want to bend the rules.

So if we get into that in the question and answer I would be happy

to respond.

Senator INHOFE. You’ll have that opportunity, Mr. Hawkins,

thank you.

Mr. Tyndall?

STATEMENT OF BILL TYNDALL, VICE PRESIDENT OF

ENVIRONMENTAL SERVICES, CINERGY CORPORATION

Mr. TYNDALL. Good afternoon, Senators. Thank you for inviting

me here today to testify before you on the EPA’s proposed changes

to the Clean Air Act’s New Source Review Program. My name is

Bill Tyndall. I am Vice President of Environmental Services for

Cinergy Services, a service company for Cinergy Corporation,

which is the utility that serves the Cincinnati area and home to

this committee room, or temporary committee room.

Cinergy serves about 1.4 million electric customers and 478,000

gas customers in Indiana, Ohio and Kentucky. Let me talk very

quickly about why the issue of New Source Review is so critical to
64

Cinergy and to other companies trying to provide electrical service

to our customers.

Steadily increasing customer demand for electricity and a strong

and increasing economy have provided a test to our nation’s electric

supply in many areas of the country, particularly in the Midwest.

The EPA’s proposed changes to the New Source Review rule must

be carefully screened to make sure that they do not undercut our

ability to continue to supply power reliably and safely. And let me

emphasize there is no margin for error here, as most observers recognize that the Midwest faces narrow reserve margins this summer

and for the next few years.

As you are aware, electricity generating units are operated under

extreme conditions of temperature, pressure and wear that makes

such failures particularly likely. As an automobile or other highly

integrated pieces of equipment, these various parts wear at different rates with the results that parts, both large and small, must

be replaced on a periodic basis in order to keep the unit running

properly. If the parts are not replaced, the failure to make such repairs results in rapid and declining reliability, unit availability,

and really increases in—or decreases in the safe operation of the

plant.

And I brought with me one sort of show-and-tell item. This is

tubing from our Zimmer power plant. There are 30 to 50 miles of

tubing in a boiler. This shows a rupture from the pressure blowing

out the tubing. It is this kind of repairs that you constantly have

to be making. And when you see this or where you see this starting

to happen, you actually go in and will repair whole areas. And, you

know, to response to some of the things that Mr. Hawkins brought

up, the question of whether there was over-extensive repair and replacement in the past will be something that obviously EPA has

chosen to resolve in court cases. And, you know, it’s not at this

point probably in the committee’s ability to look at that issue or to

influence it, and we’ll be happy to defend ourselves in court.

But going forward, we need to have a system that allows this

kind of project to go forward and make the units available because

we simply can’t risk having them not on line and having to wait

a year or longer to get them on line because of having a food fight

with EPA over whether a certain repair is covered or not under the

New Source Review rules.

Also, just to comment on the grandfathering issue, as has already been talked about by other witnesses, these existing power

plants are subject to a host of Clean Air Act requirements. And

really, as I’ve testified before in front of this committee and, you

know, mimicking what’s up there from the refiners, there’s a whole

other addition of requirements coming at coal-fired power. Cinergy

at this point has spent about $650 million on putting on controls

in the 1990’s and we expect to spend $400 million more over the

next few years making NOx reductions, partly in which will address some of the issues that David described in terms of health

effects in the Ohio Valley.

But all of that is taking place in response to programs in Title

I of the Clean Air Act, programs that are designed to reduce emissions and improve ambient air quality. To try and turn the New

Source Review Rule into the place where the reductions take place
65

is to put too much of a burden on this program. To put it succinctly, it is not going to work that every time in the 30 to 50 miles

there is a blow-out of a tube, it is not going to work to have that

be the moment when plants have to be shut down for a year when

difficult decisions about whether you put upwards of $250 million

or more of controls on a plant versus repowering it versus closing

it down are made. The system at this moment in time is not going

to survive. The companies and the system at this moment in time

are not going to survive a world where that’s the basis on which

we put our control.

There’s an alternative, which is to deal with these issues directly.

I think the chairman of this committee has put forward a proposal

to get all the sites together to talk about the challenges facing coalfired power, to get all the stakeholders, the States, the environmentalists, into a room and see if there isn’t a way of developing

a path forward that gets the reductions, that also provides certainty for the industry.

My CEO, Mr. Rogers, has been working with EEI on an internal

task force, and hoping to work with the committee to try and do

the same thing. And we think that’s where the environmental issues should be resolved so that we can—in terms of New Source

Review it should just be a program that puts controls on new

sources. It shouldn’t be providing mockup for all these other air

quality issues.

Senator INHOFE. All right, thank you, Mr. Tyndall.

Mr. Hawkins, you were going to make some comments about

changing rules. I want to give you an opportunity to do that. I have

instructed Mr. Wheeler to extinguish the traffic light so we can go

ahead and give ample time to each of the four of you. So why don’t

you go ahead and share what you were going to share with us concerning the change in the rules.

Mr. HAWKINS. Thank you, Mr. Chairman. Very briefly, the New

Source Review Program as has been described involves the EPA

writing regulations which appear in the Federal Register. And then

from that point on it is largely a self-policing system where the applicants are responsible for determining whether their facilities and

changes at their facilities may require a permit. And they are entitled to and invited to consult with the local permitting authority

or with EPA.

In the early 1980’s when the industry began to discuss these life

extension programs that I’ve been talking about, industry members

discussed the fact that regulatory agencies might say these projects

would be subject to New Source Review. What did the industry do?

Instead of going to EPA and asking for clarification, they said, let’s

characterize these things as ‘‘upgrades’’ and ‘‘maintenance;’’ let’s

characterize them as ‘‘reliability related,’’ downplay the life extension, and above all deal with it at the local level. Do not elevate

it to a national level. In other words, they made a deliberate decision to try to fly under the radar screen with respect to this very

important issue.

EPA has always been ready to respond to applicability requests,

and a large part of this stack of documents are EPA’s responses to

inquiries from other industries. Other industries have asked EPA

for applicability determinations. But the utility industry by and
66

large chose not to do so. Why? Because we think they didn’t like

the answer they would get.

So then what happened? Well, in 1988 the State of Wisconsin

did, in fact, elevate it to a national level. It wrote a letter to EPA

that said, ‘‘We’ve got a project in front of us involving Wisconsin

Electric Power. We’d like to know whether you think it triggers

New Source Review.’’ The agency looked at that and said, ‘‘Yes, it

does.’’ What did the company do? It hired the law firm that represents all the investor-owned utilities, virtually all of them, and

took EPA to court and sued EPA saying, ‘‘What you said is unlawful.’’ In 1990 the Seventh Circuit upheld EPA’s interpretation of

routine maintenance. The industry had claimed that all the

WEPCO work was routine maintenance. They brought in lots of

data similar to the information that TVA has shared about practices in the industry. The court said EPA is right. The court said

if the industry’s arguments were to be accepted, an indefinite loophole would be created in the Clean Air Act contrary to Congress’

intentions.

While that case was pending, EPA began an investigation of utility practices, a broad investigation. What happened in that investigation? The same industry lawyers that brought the WEPCO case

went to OMB and they got OMB to kill the investigation 2 weeks

after the WEPCO case came out. So that stopped EPA in its tracks

for awhile. Then the industry went to Congress and tried to get an

amendment in the 1991 and 1992 sessions, which was the Energy

Policy Coordination Act before Senator Bennett Johnson’s committee.

Congress did not enact the loopholes that the industry sought, so

they went back to EPA and they tried to get the EPA to write in

broadened exemptions for routine maintenance. The industry knew

exactly what the game was here and they were trying to get a very

expanded definition of this loophole, because they knew what they

had been doing didn’t fit within the regulations as they were written.

EPA did give an expanded loophole for some things in 1992, but

it didn’t do it with respect to routine maintenance. Then a few

years passed, EPA again began another investigation in 1997.

Again, the industry went back to OMB trying to get that investigation killed, but this time OMB refused to kill it and that has resulted in where we are today. And that’s why I say the rules have

not been changed.

Senator INHOFE. Do any of the other panel members have a brief

response to what Mr. Hawkins has just stated?

Mr. TYNDALL. Just to respond to several things. There have

been—I mean, there was guidance put into the 1992 rulemaking on

the WEPCO rule, of the so-called WEPCO rule, that talked about

what routine repair and maintenance is. And there it said that it

was an activity that was undertaken by others in the industry. So

there have been some marks given by EPA, and obviously companies are making decisions and they are trying to shoot for the targets that EPA has provided.

You know, I don’t want to—I know David has a view of how this

has rolled out. But I think the best example of how the reality of

trying to get EPA clarification on this, what it really looks like, is
67

a company last spring asked for a clarification as to whether when

they changed the turbine blade, or the turbine blades, whether that

would trigger New Source Review. And they are still waiting for a

response. The only thing——

Senator INHOFE. How long ago was that?

Mr. TYNDALL. That was almost a year ago. And the only thing

they have gotten from EPA was what’s called a 114 request, which

is essentially a request of information regarding all the projects

they’ve done in the past. Essentially what they’ve done is, when

they requested a clarification as to whether one of their projects

would trigger New Source Review it only triggered a Federal investigation. So in that world, you know, the companies are not going

to be writing EPA a lot of letters seeking clarification of what they

can and cannot do.

You know, again, what has happened in the past, you know,

whether companies have gone over some line and whether the line

was apparent or not, is right now, you know, the subject of litigation. I’m not really in a position to comment on it. But I will tell

you and, you know, echo something that Mr. Bynum says. In terms

of the people out there having to make decisions about what they

can and cannot do at a plant, and especially in an emergency situation where a unit goes down in the summer because of one component or another failing, and when you have very little time to get

it back on line when it’s needed right at that time because we don’t

have excess power in this area, there is not a line out there that

anyone understands.

Senator INHOFE. OK, let me ask you, when you were talking

about the blade in the turbine, that was not a turbine change, that

was a blade in an existing turbine?

Mr. TYNDALL. You know, Senator, I’m not sure whether it was

all or part of a turbine.

Senator INHOFE. I think that would be helpful for us to know. I’d

like the examples. Maybe some of you have other examples, in

which case for the record you could submit them. Because there’s

no way that we can interpret and determine this without having

specific examples that are obvious to those of us who are not in the

business.

Let me ask each of you to respond to Mr. Seitz’s approximation

of about six to 9 months in terms of the—I know this will differ

from industry to industry. But as far as those industries that are

represented today, and of course Mr. Hawkins having been with

the EPA, you might want to respond to this, too. But I’d like to ask

you your assessment of an average timeframe in which these permits—the application and the receipt of the permit. Let’s start with

you, Mr. Slaughter.

Mr. SLAUGHTER. Yes, Mr. Chairman. Our experience has been on

the order of 18 months to 2 years. And I know you are familiar

with this, but this particular question has been of so much concern

with regard to the Tier II gasoline sulfur rings and the fact that

the permit process, the time it takes, may inhibit our ability to

comply in the given time that EPA took special notice of the problem in its recently finalized rules.

So our experience has been 18 to 24 months. We have every indication that EPA is concerned with the time.
68

Senator INHOFE. And you probably have records on this?

Mr. SLAUGHTER. Yes.

Senator INHOFE. If you could supply those, would you do that?

Mr. SLAUGHTER. Yes.

Senator INHOFE. Mr. Moore?

Mr. MOORE. The information we have from our companies is

typically—the words used are typically 18 months.

Senator INHOFE. All right, sir. Mr. Tyndall?

Mr. TYNDALL. We have one plant which was permitted in the late

1980’s, early 1990’s, and we’re double checking but the recollection

of one of the engineers who was involved in the project was that

that was a two to 3-year permitting process for a new unit.

Senator INHOFE. That’s one example and one permit you’re talking about?

Mr. TYNDALL. Right. I mean I—having both worked on the program at EPA, monitored it in Congress, and sort of attended a lot

of these New Source Review meetings, my overall impression for

the industry and for the industry in general is one to 2 years and

even longer in situations where issues involving—any kind of issue

can slow it down considerably.

Senator INHOFE. Mr. Hawkins, any response to that or do you

generally agree?

Mr. HAWKINS. Just a quick comment, Mr. Chairman, which is

that most changes of facilities never see the Federal NSR permit

process. Most changes of facilities either net out of review or are

processed through the State, minor new source review. And it’s

only a very small fraction of all the permitting actions that are carried on by State and local agencies that are actually subject to a

major Federal new source review.

Senator INHOFE. That’s interesting. Do you think it might be that

Mr. Seitz is taking those, including those in the averaging to come

up with his time that he’s——

Mr. HAWKINS. No. There are in the audience from the local agencies that may want to say something about it, but there are thousands of changes that are looked at by local and State permitting

control authorities.

Senator INHOFE. OK, then a very similar question for each of you

to respond to would be, addressing this reliability issue and its effect on foreign competition, competitiveness. Would anyone like to

respond to that?

Mr. HAWKINS. I would like to respond to the electric supply reliability issue. I would submit that this argument about the impairment of the ability to respond to emergencies or worker safety is

a classic red herring. Nobody has ever interpreted the rules to

apply to the emergency replacement of the pieces of equipment in

the electric utility sector, and I’m not aware of it happening in

other sectors. None of the cases that have been brought, if you look

at the complaints and notices of violation, involve these kinds of

things. The agency has never indicated that it regards to these

kinds of actions as not entitled to the exceptions.

As I was saying in my testimony, what we’re talking about here

are organized activities that were planned over a lengthy period by

the companies themselves, going up to corporate management level
69

for approval in the capital budgets. These are not emergencies.

These are substitutes for new capacity.

Senator INHOFE. Mr. Slaughter, you had mentioned 18 to 24

months. And I would ask you specifically if it takes your industry

18 to 24 months for permits before they can make equipment

changes for new products, what does that do to your competitiveness? Do you have any thoughts about that?

Mr. SLAUGHTER. Well, we have had a lot of problems, Mr. Chairman. Because as you know, we’ve not had a new refinery sited in

the United States since the early to mid-1970’s. This essentially

means that we have had to basically take place—take care of delivering product to consumers and taking care of any increase in demand through changes at the existing facilities, through maintenance, repair, replacement, some additional capacity. Now with the

tremendous burdens of the Tier II requirements upon us, and also

others to come, as you know we are going to be forced probably to

go in and look for permits in an unprecedented fashion over the

next few years. So we are not going to be able to make our compliance dates, particularly on Tier II, unless we have some relief on

the permit process. And EPA has been trying to address that, at

least in part.

Senator INHOFE. All right, sir.

Senator Voinovich?

Senator VOINOVICH. I was interested in Mr. Hawkins’ testimony.

I would think that from what I heard from Mr. Bynum, who is with

Tennessee Valley Authority, that he is concerned that some of the

things that you are talking about under the new rules would be included. That’s the concern there. That’s the kind of thing you’re

trying to share with the agency in terms of coming up with the

rules to make sure that those kinds of things, indeed, are not included in that situation.

Mr. Slaughter, it’s very interesting. I’d like you to tell everybody

here at this hearing, you now have Tier II sulfur requirements and

it’s going to cost the industry this $8 billion, I think it was?

Mr. SLAUGHTER. Yes, sir.

Senator VOINOVICH. Approximately how much will that add to

the cost of a gallon of gasoline in this country?

Mr. SLAUGHTER. Well, there are different estimates. The industry’s estimate is four to five cents per gallon. The EPA estimate

was about one-and-a-half to one-point-nine cents. We are much

more comfortable with our estimate. It is a total of $8 billion. And

then as you know, the agency is also about to propose a rule on

diesel sulfur which will cost about half as much on diesel. And as

you know, Washington and other areas have been getting their

share of complaints about diesel prices as of late.

Senator VOINOVICH. I think at the time the biggest complaint I’m

getting at my offices here in Ohio is that people are complaining

about the high cost of gasoline. There’s lots of reasons for that, but

the fact of the matter is it’s interesting that because of policies you

haven’t built a new refinery in this country in God knows how long.

And the reason for it is it’s not—why don’t you tell us the reason

why.

Mr. SLAUGHTER. Well, it’s not possible to site a refinery because

there are a multiplicity of regulations that would apply to it and
70

areas generally have problems with it. We are pretty much resigned to the probability that another refinery will not be sited in

the United States. We’re going to be permanently reliant upon the

sites that we have now. And I might just add, as you pointed out,

we have a stewardship responsibility which we’re reminded of from

time to time to deliver gasoline and diesel to the public. So we’ve

got to keep the plant in order and up to date.

Senator VOINOVICH. One of the things that the public ought to

pay attention to is the lack of energy or oil policy that we have in

this country. We are right now at the mercy of the OPEC nations.

If we got ourselves—our capacity to deliver gasoline is down to—

we’re more reliant today on overseas oil, I think at 65 percent. In

1973 it was about 35 or 40. And we’re requiring you now to do

some other things.

The interesting thing is I think what you’re talking about is

some of the things that you’re going to have to do to the current

facilities that you have, you’re concerned that that will then trigger

this New Source Review, which would then make it more difficult

for you to do the job that we are asking, or EPA is asking you to

do, and that is to get rid of the sulfur from your gasoline.

Mr. SLAUGHTER. That’s right.

Senator VOINOVICH. The public has got to start putting some of

this stuff together, about how it all works. And the point is you

want to—you know, we haven’t built—I’d like—why haven’t the

utilities explained why—why don’t you build brand new utility

plants? How come you haven’t—you’ve tried to extend the life of

those plants?

Mr. TYNDALL. Well, I think that’s a very good point, because—

I don’t know. I mean, I’ve looked at the legislative history of the

Clean Air Act amendment in 1970 and some of the claims that

there was a specific date. There wasn’t a specific date that was

really used as when these plants would stop operating. But obviously what occurred was there wasn’t the ability to add a whole

bunch of new plants, so there was needed capacity continuation

into the 1990’s from the existing plants. Again, there was—I don’t

think it was a secret that there were projects undertaken to restore

deteriorating capacity.

You know, it’s certainly one of—you know, a line that EPA is

now claiming it can discern that it certainly wasn’t informing people of in the past as to what exactly could be done and couldn’t be

done. They have never provided a list of projects, they’ve never said

a money amount that couldn’t be done. They’ve never said if you

capitalize something it can’t be done. So none of the—there’s never

been any discussion about exactly what can and can’t be done until

they bring enforcement actions and cite companies. First Energy

was cited for something that occurred in 1979.

So the ability to site these plants is—and to site any plants.

Cinergy is trying to build a state-of-the-art gas-fired unit in a small

town in Indiana, the kind of project that I think NRDC would want

to see us doing, and we’re having a very difficult time siting it because of issues involving land use, local air quality issues. And so

in that world where it’s so difficult to bring new things on line, you

are going to continue to see pressure where there is very little margin for error, you are going to see continued pressure to keep these
71

plants running. If any of our major units have to go down for whatever reason in the summer, it puts a serious strain on the entire

Ohio-Indiana—and really the whole Midwest region. And, you

know, we’re going to do whatever we can to avoid that.

Senator VOINOVICH. Well, your company I think did Zimmer. It

was going to be a nuclear power, and they just that down and they

spent——

Mr. TYNDALL. Right, which is the last plant we brought on.

Senator VOINOVICH. That last plant. And I think part of the

problem—I mean, another reason I would think logically that

you’re trying to extend the life is you have rate payers, people that

have got to pay the rates. As the Governor of this State in terms

of the rates that our residents pay, in terms of the competitiveness

of our industries, we have parts of the State where people complain

their rates are so high they’re not competitive. We’re concerned

about, you know, competitiveness. All this has to be tied in. It’s a

reasonable, rational way of trying to develop rules and regulations.

The other thing, Mr. Chairman, is the whole issue of fossil fuel.

There are a lot of people in this country today that believe that

there are some folks that just want to eliminate fossil fuel plants

period, get rid of them. But you get rid of fossil fuel and nobody

wants nuclear.

If you don’t mind, Mr. Chairman, we had a big hearing in Cleveland a month ago with some folks that were very concerned that

they’re going to run this nuclear waste through the City of Cleveland, out to Yucca Mountain. Well, I’ll be dead before Yucca Mountain ever becomes a storage facility for nuclear waste. And someone

was saying, well, what’s the deal? We want to kill nuclear waste.

Well, where are we going to get our power? Solar.

We need to bring some rationality to all of this. And I think the

environmental groups and the industry ought to get together at a

table, and I’m hope that maybe in this room, like you suggested,

Mr. Chairman, get everybody together and talk about this and

where are we going? What is our national policy in regard to, say,

the oil industry? Where are we going? Are we going to be completely relying on everyone else?

Henson, your industry—you know, 18 months to 2 years. I think

one of the other things is, you’re all from different regions. That’s

the other thing. Is there a variation in the regions in terms of issuing the permits?

Mr. Slaughter, I’m sure you have several regions.

Mr. SLAUGHTER. Lots of them.

Senator VOINOVICH. Would you comment on that?

Mr. SLAUGHTER. There is some variation, but the average is what

I’ve given you. A lot of our permitting activity takes place in Region

VI, which is Texas and Louisiana, but that’s the national average.

Senator VOINOVICH. Mr. Hawkins?

Mr. HAWKINS. Senator, may I? If I can comment briefly on the

question of the ability for new coal plants to get a permit and the

life extension issue.

Again, the facts won’t bear out the claim that new coal plants

couldn’t get permits under the NSR and PSD rules. East Bend, the

Trimble County Plant, the Rockport Plant, these are all plants

within a hundred miles or so of here along the Ohio River that all
72

got permitted with state-of-the-art controls under the PSD regulations.

As far as life extension, we don’t object to extending the life of

these facilities, provided that they modernize their pollution controls when they do. Our objection is that the companies were not

up front about what they wanted to do and failed to negotiate out

what the requirements would be for cleaning up their power plants

when they decided to extend the life of these old units, rather than

building new capacity.

So we’re not objecting at all to finding ways to save money for

the rate payer. I’m a rate payer, too; and my bill is as high as anybody else’s and I’d like it to be lower. But you can clean these

plants up economically and improve air quality and improve public

health. And if that’s part of your life extension program, then

you’re not going to have any arguments from us.

Senator VOINOVICH. So the issue is not the length of the old

plants, just tearing them down and rebuilding them, your point is

that if you’re going to be going forward with it that you ought to

try to have the most modern technology available to you when

you——

Mr. HAWKINS. If you want to run them longer, clean them up.

I mean, the irony is that we’re embarking on new regulation and

a competitive playing field. And the fact is that the grandfather

status of these extended life power plants is introducing a competitive distortion against new merchant gas-fired power plants that

want to come on to the market and they’re having trouble getting

financing because they have to compete head to head against

plants with a built-in pollution subsidy because of their grandfather status.

Senator VOINOVICH. But you will admit that they have done, as

one of the other witnesses said, they have reduced the pollution

from these coal-fired plants.

Mr. HAWKINS. Some industries have done better than others. As

I said in my prepared testimony, 20-year-old power plants are responsible for 88 percent of the power plant sulfur oxide pollution,

and 84 percent with the nitrogen oxide power plant pollution.

They’re hanging on there with the bulk of the pollution in those 20-

year and older power plants. That’s not impressive performance in

my view.

Mr. TYNDALL. But, I mean, Senator, there is a very legitimate

issue about talking about what is the best way of—if further reductions are to be made what is the best way. I think the question

where Mr. Hawkins and I may disagree is whether you use a program that essentially says, you know, when you blow—you know,

as he would have it, and it’s been described as a hair trigger. When

you blow a tube in the 30 to 50 miles that are in a power plant,

that’s a second that you swoop in and shut down the plant. You

put on state-of-the-art controls. That isn’t going to work. That’s not

reality.

And Cinergy has been working constructively with lots of environmental groups, with other companies, to try and find a way of

resolving these issues in a manner that makes sense for the environment, that makes sense for industry. And, you know, I mentioned before, Senator—Chairman Smith’s initiative. I know there’s
73

some discussions going on between companies and environmental

groups, in other words, trying to find a solution. I don’t think the

solution is to have a hair trigger on New Source Review so that if

you have the misfortune of having any unit, any portion of your

unit, have a problem, that that’s the moment you’re going to swoop

and have to face the 2 years, make the investment. That’s not a

rational way of resolving these issues.

You know, the life extension issue, again, it’s in the courts. I

don’t think there was—some of these quote, unquote, life extension

projects, I don’t think there was a lot of hiding the ball. You know,

I think I know of an example where there were T-shirts and mugs

and it was on annual reports. So I don’t think that the court is

going to find some conspiracy to violate the law. But, again, that’s

all in the courts.

Senator VOINOVICH. That’s in the courts. I think the thing is to

look at the whole picture, the spectrum, and figure out where Mr.

Hawkins would come out in terms of, hey, this is something that

really ought to have required. And you know, I’m sure there are

instances of that out there. And I think that if there are, then we

should say that there are, OK; and then they’re going to be brought

under the net. But there is a rational, common sense way of handling this that doesn’t put the industry in a place of not being able

to protect workers or reliability and some of these other things.

The last question I’m going to ask is, and maybe I’m taking it

away from the chairman here was, but he talked about my briefing

for this issue of the actual and the potential, that today if you’re

going to do something you’re looking at what it is actually today

and then what it’s going to be actually tomorrow, although the potential may be there for the new thing to increase emissions. I

guess that’s what it’s about. But if you look at the actual experience, common sense would say that you’re not, even though someone says you’ve got the potential of going up, that in all practicality

that’s not going to be the case. I don’t know if we’re just talking

about words here. Is this a real issue?

Mr. SLAUGHTER. Senator, if I could jump in for a minute, it’s a

very real issue. All the major industries like ours that are regulated build in a compliance margin to our operations. In other

words, we don’t go all the way out to our permitted levels of emissions. So the problem is that that means that there’s a built in

problem with NSR, because they look at your actual emissions to

your potential emissions, and your potential emissions include the

compliance margin. So that is being done almost automatically to

trigger NSR.

So one of the things I mentioned is that the net has been cast

very widely to bring everybody into the ambit of NSR review, and

the actual—the potential emissions test is one of the major reasons

why.

Mr. MOORE. Senator, we also feel that this is a major problem

and it’s recent. Here again, since 1998, EPA is going back and

changing something that had been a practice for largely 20 years

of measuring actual to actual. Now the idea is you have to look at

potentially the problem, that’ll potentially increase. We take the

position, our interpretation of the law, would be for our numbers

that if you are operating at a certain level and if you make some
74

kind of a change to your equipment under the regulations before

1998, or the guidelines, you didn’t have to go through the permitting process, because you weren’t changing any of the actuals.

If you did increase your actual emissions, even within your permit level, if under the regulations it meets the term ‘‘significant,’’

then you should go get a permit. But what we’re talking about here

is no realization of an increase at all and then you go through this

process. This is new. This is conflicting the system. This is causing

States not to know what to do. It’s causing the industry not to

know what to do. And for what purpose? If there is no increase in

emissions, why do you have to go through this? The law says clearly an increase in emissions. Nowhere does it talk about a possibility. And if a possibility is achieved, then you’ve got to go back, because the law says, you change your operations and increase your

emissions, you’ve got to go back and go through the review process.

So the law is pretty clear. But what we’re getting into here is

something different, something new, something, as Mr. Hawkins

has said in all honesty, you’re trying to get at not permitting an

increase. You’re trying to get into forced decreases. And I think Mr.

Tyndall said that was not the intent of the statute. Congress didn’t

intend that. There are other ways you get at that, other laws that

you get at that.

Senator VOINOVICH. Mr. Hawkins?

Mr. HAWKINS. First, it’s not new. This was the subject of a 1979

lawsuit by the Chemical Manufacturers Association and I believe

the forest products industry was part of that lawsuit. A settlement

was entered in 1981 where the agency said it would propose alternatives to the potential to actual test. In 1989 the agency completed public comment and issued a rule saying it was going to retain this actual to potential test.

Now, that’s all the legalisms, but let’s talk about the common

sense aspect because I think it’s a more powerful argument. The

common sense point is the statute says no emissions increase. EPA

has always taken the position that if a company is willing to live

with its forecast of what the actual emissions in the future will be,

then it can get a permit. The difficulty has been that the companies

want to come in and say there’s not going to be any emission increase and then the agency says put it in writing, and they say,

‘‘Oh, no, I don’t want to do that.’’ They don’t want to be bound by

their assertions that there isn’t going to be an emission increase.

If they are willing to take an enforceable commitment that there

will not be an emission increase, they can get their permit without

the potential test at all.

Mr. TYNDALL. But to just add to the complexity, that sounds

great until you realize that if you have a plant—you know, you had

a low demand the year before, you only have 80 percent or in our

industry you only use it about 80 percent of the time. What Mr.

Hawkins is suggesting is in order to repair your tube you go in,

and assuming EPA will respond to you and not launch a Federal

investigation and allow you the level of emissions you had in the

past, that essentially they’ll let you freeze yourself at that 80 percent capacity. Therefore, you have essentially frozen that plant’s

output from that time forward at that level regardless of what future demand may be and regardless of whether any increase in the
75

future was related or not related to you repairing this tube. And

that—I mean, this gets into the complexities of this program and

the sort of arguments that swirled around it for the last 20 years.

That’s why we really need to find something that’s much simpler,

like addressing the environmental issues in a different manner and

then saying because of—we have a NOx cap over all emissions in

Ohio, which we may have very shortly, or whatever reason, we’re

protecting the environment and we’re satisfied we’re protecting the

environment, then we don’t need to worry about whether any individual plant—we don’t have to worry as much about whether any

individual plant is going to increase emissions and we can do something by just essentially stating you’re not changing the emissions

rate, something very simple. The engineers understand it. If you’re

change doesn’t increase the emissions rate, you can go ahead and

make them. It’s a very simple approach. It’s one that can be made

to work with a number of safeguards, some of which are already

in place, and it’s the kind of thing that I think if EPA were willing

to really sit down and talk to Mr. Hawkins but also talk to industry and look at this issue, it might be something that could be resolved instead of them going forward—I think partly because their

enforcement office is making them, going forward and just making,

you know, as I said, the hair trigger approach to this program.

Senator INHOFE. Well, I appreciate your following up on that because I was going to do that.

Mr. Hawkins, in your testimony and in previous briefings you

emphasized the fact that industry changes the names of maintenance work depending on their audience. I think one of the examples you used is to switch from the term ‘‘life extension’’ to ‘‘reliability of projects.’’ You seem to equate that to an admission, I

guess, of guilt. Having been in the business world, I know that you

use different terms depending upon your audience. If a manager

wants funding for a project, he uses a term that he knows the accountants will approve.

Now I understand that the environmental organizations do this,

too. In a recent news article, and I was reading this, it’s Inside

EPA. They are talking about changing the name of the Environmental Defense Fund to Environmental Defense, because this has

a greater appeal in their fund raising efforts out there. The article

also says that your own organization was searching for a new communications director and an employee said that the NRDC was

hoping to become ‘‘the Bloomingdale’s of the environmental movement.’’ Does the NRDC hire or work with consultants to figure out

the best words to use to raise the most money?

Mr. HAWKINS. I haven’t heard that one. I think we would be better off if we were the Wal-Mart of the moment. Actually, we’ve

been fairly stodgy as these things go. We haven’t done focus groups

or taken polls on our name. And I think proof of the pudding is our

name—Natural Resources Defense Council. I have joked that we

should have a tag line: ‘‘We’re the group you’ve never heard of.’’

We’ve pretty much resisted the idea of trying to come up with,

you know, turning ourselves into Exxon or American Brands or

something that nobody knows what it stands for.

Senator INHOFE. Do you have any questions, Senator Voinovich?

Senator VOINOVICH. No, I haven’t.
76

Senator INHOFE. Do any of the members of this committee have

something they’re just dying to say that they haven’t had the opportunity to say? Mr. Moore?

Mr. MOORE. Yes, sir. I’ve got a lot of respect for Mr. Hawkins

and his organization and worked with them while I was in government and I wish we could work with them more closely now. I can’t

let this routine maintenance thing go by. We have a different view

of this. We aren’t involved in a lot of things that he’s been talking

about involving the power companies, maybe things are different

there.

All we know is in 1980 the rule was clear, you know, what was

maintenance. And, yes, we didn’t have a lot of needs for the Federal permitting process. It was fairly clear. Now we’re having a

new enforcement decision in 1999 saying what routine maintenance is, and that’s where the impact is. Anything you do, these

words mean anything. They cover frequent, conditional, comparative, inexpensive repairs to maintain existing equipment. Look at

the position that puts a middle manager in and then look at the

position that puts the State regulator in when he calls them on the

phone and says, I’m getting ready to do something that’s routine.

It’s maintaining existing equipment. It’s not going to increase anything. Do I have to get the permit? What does he say back? He says

I don’t know. He says, you know, I gave you a permit 10 years ago

and now retroactive they are coming back and saying they didn’t

do it right because it had a potential of increasing emissions.

Basically the rules have changed. The rules have gotten to where

now they are even more unenforceable or more unfollowable, if

that’s a word, than they ever were before. And so, yes, you’re not

going to see—I mean, I don’t know, by one measure you could see

a great deal more of the permits being requested because of being

forced to because now you are getting into things that up until

1999 everybody thought were not included.

Well, what’s going to happen is you’re just going to freeze the

process. Nobody is going to do anything. In the mills you are not

going to do anything, adding anything to improve the processing or

even improve the environment. Sometimes you do both at the same

time on the grounds that we don’t want to go through this. It’s a

marginal project. We’re not going to go through all this red tape

and wait 18 months or maybe longer if this thing is getting more

complex and more permits being required. And the States are saying we don’t know what to tell you. As a matter of fact, the States

are asking EPA to go back to a simpler, reformed rule and get

away from some of the stuff they’re proposing here, particularly in

the routine maintenance area.

So I don’t think we ought to let this area go by with some of us

saying that we think that routine maintenance is a way to keep

doing something or get away from something or whatever, that’s

not the case at all. Routine maintenance in our industry is meant

to be just that. We are supposed to be doing something to keep a

mill working, keep it running. If it increases emissions, we’re supposed to get a permit and they were supposed to put some kind of

equipment on to take that back down to below the emission levels.

And that’s not how this thing is working out there. This is something that’s headed in the wrong direction. In other words, in how
77

it is being enforced and by what it’s doing to those of us who are

trying to follow these rules and regulations. And we ought not let

that go by as some kind of a no real change or no real difference

in procedures. That’s just not true from the point of view of us trying to live under these things.

Senator INHOFE. Mr. Hawkins, do you want to respond?

Mr. HAWKINS. Actually, I’d like to make my final comment be

one of agreement with something that Bill Tyndall and Joe Bynum

said. Both of them pointed out the benefits of looking at a comprehensive approach to reducing emission from existing sources

and preferably focusing on multiple pollutants. I think that has a

great deal of merit. We are engaged in discussions, formal and informal, with a variety of players in the electric sector and we’re

committed to exploring that and seeing whether we can come to

agreement.

Senator INHOFE. Thank you very much. Mr. Tyndall? All right,

any final——

Mr. SLAUGHTER. I just might add one point, Mr. Chairman,

which is, you know, it’s been suggested that maybe there are people who haven’t been doing much. I know you’re aware of the Natural Petroleum Council’s study that shows that basically over this

last decade the refining industry spent more on basically environmental controls than the entire book value of the industry. So there

is a major commitment there. I probably should also add as mentioned in my oral statement that we hope these talks with EPA on

NSR go forward and the program office and Mr. Perciasepe, whom

you mentioned, has generally been helpful in this regard. Unfortunately, that hasn’t been the uniform position across the agency.

We’re hopeful that this hearing will help move things in a more

positive direction.

Senator INHOFE. I appreciate that.

Senator VOINOVICH. Mr. Chairman, I just want to point out one

thing to verify that. As Governor I really worked hard with communities to get us some ambient—to get into attainment. And there

was one industry, BP, had a big refinery up in the Toledo area, and

they put on an enormous amount of money into cleaning up that

facility. And as a result of what they did, they brought the Toledo

area into attainment. So there’s a lot of good that’s being done out

there by industry, and I guess the thing is that we want to all keep

working to continue to improve the quality of our air but we want

to do it in a way that makes sense and doesn’t require you to spend

money on things you ought not to spend money on, at the same

time realize that we want to get better.

Senator INHOFE. Thank you very much. Well, I thank all of our

panelists. We’re quitting exactly on schedule. But I appreciate

you’ve come a long ways. We’ve come a long way to have this hearing. I appreciate your attendance here very much, and we are adjourned.

[Whereupon, at 4:45 p.m., the subcommittee was adjourned, to

reconvene at the call of the Chair.]

[Additional statements submitted for the record follow:]
78

STATEMENT OF HON. TED STRICKLAND, U.S. REPRESENTATIVE FROM THE STATE OF

OHIO

Introduction

Good morning, Mr. Chairman. Thank you for your kind welcome and for allowing

me to offer testimony at today’s hearing. I especially would like to thank Senator

Voinovich and take this Opportunity to express the appreciation of southern Ohio

for his leadership in defending the use of coal—one of Ohio’s most valuable natural

resources.

My name is Ted Strickland. It is my privilege to represent the people of the 6

Congressional District of Ohio in the U.S. House of Representatives. Ohio’s 6th Congressional District spans all or part of 14 counties across the southern part of Ohio,

from Warren County in the west to Washington County in the east. This part of

the State also offers a beautiful national forest, some of the most pristine farmland

in Ohio and many unique historic sites.

I appear here today because I am very concerned that new approaches to Federal

environmental policies may result in an excessive and disproportionate hardship on

already distressed parts of the country, like southern Ohio. The New Source Review

(NSR) program directly affects southern Ohio and its neighboring States where

some of my constituents travel to work. This region is home to coal-fired power

plants, coal mines, manufacturing plants, a petroleum refinery and a large paper

mill. After visiting this part of the country, it becomes readily apparent why we

must strive for a healthy environment and why we must do so in a manner that

allows for a healthy economy.

I support strong environmental protections which improve the nation’s ability to

be a good steward of our natural resources, and I am proud of the fact that the 6th

Congressional District has attained compliance with all of the National Ambient Air

Quality Standards for all of the criteria pollutants regulated under the Clean Air

Act. However, I believe equally strongly that we have a responsibility to develop a

reasonable balance between the specific goal of air quality improvement and other

important public policy objectives. Like Vice President Al Gore, I firmly believe that

both a good environment and a good economy can coexist while we continue to use

one of our most abundant energy resources—coal. In fact, I would share that Ohio

University, right here in southern Ohio, offers promising research on the development of a practical biologically based process to reduce emissions from fossil generation units. This type of research provides some assurance that in the long run our

fuel supply will remain diversified, reliable and efficient. The technological possibilities are within reach, but only if research and regulation compliment each other.

Briefly, I will share with you some troubling statistics from my district and my

concerns about the EPA’s New Source Review (NSR) program. I think together this

information demonstrates the need for meaningful reform of the NSR program so

that we strike a better balance between the pace of desired environmental benefits

and the increased productivity anticipated through economic development initiatives.

New Source Review Creates Problems For Economic Development

As Senator Voinovich knows, the 6th Congressional District of Ohio is one of the

poorest in the State and the country. It has the lowest per capita income ($ 10,349)

and the highest poverty rate (20.1 percent) of any Congressional District in Ohio.

Unfortunately, Southern Ohioans have not experienced the economic recovery that

most of the U.S. has enjoyed in 1990’s. The 6th District includes Meigs and Vinton

Counties, which have among the highest unemployment rates of any of Ohio’s 88

counties (11.1 percent and 13.8 percent, respectively, compared to the statewide average of 4.3 percent). These statistics clearly underscore the region’s enthusiasm for

economic development opportunities and its fear of regulations which may hamper

job creation. Without a doubt, low cost energy and high quality manufacturing labor

are vital to the economic prospects of the region. A substantial number of the labor

force—more than 25 percent—is employed in the manufacturing sector. And, this region provides a significant number of jobs in the utility, mining, and refinery sectors. Southern Ohio cannot withstand the loss of these jobs, and it certainly cannot

afford to overlook any opportunity for job creation.

I have heard from the International Brotherhood of Electrical Workers (IBEW)

who raise specific issues about the EPA’s New Source Review proposed rule, and

it should come as no surprise that one such concern is job loss. Under the current

NSR program, decisions could be made to shut down utilities rather than venture

into the confusing NSR permitting program to undertake what could be considered

‘‘routine maintenance’’ activities. Obviously, this would result in layoffs. At this
79

time, I would like to ask to include for the record, the statement of John J. Barry,

International President of the IBEW.

Clean Air Act New Source Review ‘‘Reform’’ Rulemaking Concerns

As you know, New Source Review was first introduced as part of the 1977 Clean

Air Act Amendments. The program is designed to ensure that newly constructed facilities and substantial modifications of existing facilities do not result in violation

of applicable air quality standards. The New Source Review program is widely acknowledged to be very complicated and to be a potential bottleneck to many positive

community development projects including, brownfields redevelopment and to manufacturing facility improvements and modernizations.

For example, the specific requirements dictated by the New Source Review Program depend on the location of the facility. If a plant is sited in a part of the country that fails to meet the National Ambient Air Quality Standard (NAAQS) for a

pollutant, one set of requirements apply. If the plant is in a NAAQS attainment

area, another set of rules apply. As you can imagine, some facilities may rest in a

region that is considered in attainment for some criteria pollutants, but not others,

complicating the requirements even further.

Let me describe some general frustrations my constituents and others have

shared with me concerning the New Source Review program. I have learned that

merely determining whether the program ‘‘applies’’ to a project depends on complicated rules and guidelines which have been subject to 20 years’ of EPA interpretation. I have also heard that EPA could require a preconstruction permit under

NSR for the replacement of worn equipment parts even though the replacements are

only modifications and not new construction. In fact, these types of modifications are

aimed at pollution reduction and efficiency increases—two worthy goals. On top of

that, I understand that preconstruction permitting can take a year or longer. I do

not understand why industry, whose business practices benefit the economy and

comply with the Clean Air Act standards should suffer from the inconsistent and

unintended application of the NSR program. It seems quite clear to me the program

is broken and it is time to fix it.

With the Objective of creating a more efficient NSR program, EPA announced

back in 1991 that it would ‘‘simplify and reform’’ the original New Source Review

rules. To the agency’s credit, it understands that the NSR program demands a thorough review and it has engaged stakeholders to work on a comprehensive reform

package. I would hope that this effort results in a program that encourages modifications and maintenance at our facilities so that they remain reliable, competitive

and safe.

Conclusion

I know the EPA claims many successes under the NSR program and I applaud

the reduction or prevention of pollutant emissions. The environmental protections

afforded under the NSR program should not be minimized here today. However, the

EPA’s most recent proposed changes to the NSR led to considerable controversy and

the agency acknowledges the need to build in more flexibility in the program and

streamline the permitting process. I would suggest that a truly meaningful reform

of the NSR program could actually lead to even greater environmental benefits in

the future. If the NSR program remains in its current broken state, I suspect certain facility maintenance functions may be delayed, thereby stifling progress on the

air quality front.

This past fall, I raised the concern that the EPA should not shortchange the discussion on meaningful NSR reform. I am pleased to hear that a full review of approaches to NSR reform is ongoing. Without sufficient dialog among the interested

parties, I have little confidence that a workable solution can be reached. Therefore,

I would like to state very clearly that congressional oversight of this process does

not stop here in Cincinnati. Instead, I think today’s hearing demonstrates that both

Senators and Representatives will continue to monitor the progress made to reform

the New Source Review Program. With hard work and cooperation, I believe an equitable proposal can be crafted that creates an efficient NSR rule that avoids unnecessary pitfalls and establishes a proper balance between environmental benefits and

economic progress.

I commend the chairman, Senator Voinovich, and the subcommittee for their attention and oversight with respect to this important issue. Thank you again for the

opportunity to testify here today.
80

STATEMENT OF JOHN SEITZ, DIRECTOR, OFFICE OF AIR QUALITY PLANNING AND

STANDARDS, OFFICE OF AIR AND RADIATION, ENVIRONMENTAL PROTECTION AGENCY

Good afternoon Mr. Chairman and members of the subcommittee. Thank you for

the opportunity to talk with you about the New Source Review program under the

Clean Air Act. The New Source Review (or ‘‘NSR’’) program was enacted by Congress in 1977. It’s goal is to minimize air pollution from large new and modified stationary sources. Recent figures suggest that over the life of the program, NSR has

prevented more than a hundred million tons of air pollution. When companies upgrade facilities, either by building a new plant or making major modifications to an

existing plant, they are required to install the best available pollution control equipment. In areas with unhealthy air, NSR assures that these sources do not impede

progress toward cleaner air. In areas with clean air, especially pristine areas like

national parks, the program assures that emissions from new and modified sources

do not significantly degrade air quality. The program also assures citizens that any

large new or modified industrial source in their neighborhoods will be as clean as

practical.

Upgrading pollution controls and the industrial infrastructure simultaneously

makes economic and environmental sense. In general, it is more cost-effective for

sources to install pollution control equipment such as scrubbers, electrostatic

precipitators, or selective catalytic converters at the same time that they make

major capital improvements. Because the NSR program relies on this principle, it

minimizes emissions from new sources while maximizing opportunities for additional industrial and economic growth. It’s a simple concept that has been working

in the NSR program for almost a quarter-century, protecting our nation’s air resources, and making up a critical component of our total air quality program.

Background

The NSR provisions of the Clean Air Act combine air quality planning, air pollution technology requirements, and stakeholder participation. NSR is a

preconstruction permitting program. If new construction or making a major modification will increase emissions by an amount large enough to trigger NSR requirements, then the source must obtain a permit before it can begin construction. States

are key partners in the program. Under the Act, States have the primary responsibility for issuing permits, and they can customize their NSR programs within the

limits of EPA regulations. EPA’s role is to approve State programs, to review, comment on, and take any other necessary actions on draft permits, and to assure consistency with EPA’s rules, the State’s implementation plan, and the Clean Air Act.

(EPA also issues permits where there is no approved NSR program, such as on some

Tribal lands). Citizens also play a role in the permitting decision, and must be afforded an opportunity to comment on each construction permit before it is issued.

The NSR permit program for major sources has two different components—one for

areas where the air is dirty or unhealthy, and the other for areas where the air is

cleaner. Under the Clean Air Act, geographic areas (e.g., counties or metropolitan

statistical areas) are designated as ‘‘attainment’’ or ‘‘nonattainment’’ with the

health-based National Ambient Air Quality Standards (NEARS)—the air quality

standards which are set to protect human health. Permits for sources located in attainment (or unclassifiable) areas are called Prevention of Significant Deterioration

(PSD) permits and those for sources located in nonattainment areas are called nonattainment NSR permits.

A major difference in the two programs is that the control technology requirement

is more stringent in nonattainment areas and is called the Lowest Achievable Emission Rate (LAER). On the other hand, in attainment areas, a source must apply

Best Available Control Technology (BACT) and the statute allows consideration of

cost in weighing BACT options.

Also, in keeping with the goal of progress toward attaining the national air quality standards, sources in nonattainment areas must always provide or purchase ‘‘offsets’’—decreases in emissions which compensate for the increases from the new

source or modification. In attainment areas, PSD sources typically do not need to

obtain offsets. However, PSD does require an air quality modeling analysis of the

impact of the construction project, and if the analysis finds that the project contributes to ambient air pollution that exceeds allowable levels, this impact must be mitigated. Sometimes these mitigation measures can include offsets in PSD areas. In

addition to ensuring compliance with the NAAQS, States track and control emissions of air pollution by calculating the maximum increase in concentration allowed

to occur above an established background level—that change in concentration is

known as a PSD increment.
81

Another key requirement is the provision in the PSD program to protect pristine

areas like national parks or wilderness areas (referred to as Class I areas). If a

source constructs or modifies in a way that could affect a Class I area, the law affords a Federal land manager (for example, a National Park Service superintendent)

an opportunity to review the permit and the air quality analysis to assure that relevant factors associated with the protection of national parks and wilderness areas

are taken into consideration, and, if necessary, that harmful effects are mitigated.

(The Clean Air Act also requires States to regulate construction for smaller

changes, and at sources that are not big enough to be classified as ‘‘major.’’ This

program is known as minor NSR. However, minor NSR is not part of the NSR Reform rule and is not the focus of today’s remarks)

Current Status of the NSR Program

Let me give you a few statistics about the NSR program to put things in perspective. Preliminary estimates based on our most recent data indicate that approximately 250 facilities apply for a PSD or nonattainment NSR permit annually. That’s

out of the approximately 20,000 sources that would be classified as ‘‘major’’ under

the Act, and the far larger number of additional stationary sources of air pollution

in the United States that are not large enough to be called major. The nonattainment NSR and PSD programs are designed to focus on changes to facilities that

have a major impact on air quality. And the NSR program is resulting in cleaner

air. Recent data show that, each year, NSR permits at PSD sources have prevented

about half a million tons per year of new emissions compared to what would be

emitted if there were no Federal or State permitting. Clearly, in the absence of

NSR, Americans would be breathing less healthy air. Even in areas with clean air,

there would likely have been significant declines in air quality in some places, as

well as harmful impacts in national parks. As these reductions have been occurring,

the United States is in the midst of a record-breaking economic expansion. Thus,

the program is accomplishing its intended purpose.

In addition to the emissions reductions, the NSR program has sparked improvements and innovations in pollution control technology. Whenever demand for good

control technology exists, vendors compete to supply better control technology at

lower cost. This competition reduces the cost of controls as the control technology

improves. This technology-forcing aspect of the program is an important reason why

it has been so successful in allowing for continued economic growth while ensuring

environmental protection. It also ensures that the U.S. will remain a leading exporter of pollution control technology.

NSR Reform

Despite the successes of the NSR program, some of those with a stake in the program—EPA, regulated industry, State and local governments, environmental

groups, Federal land managers, and others—have engaged in a long-running dialog

about how to make the program work more efficiently and effectively. The issues

raised fall into five general categories. First, some argue that the process for determining exactly whether a permit is necessary for changes they are making to existing sources could be easier. Second, despite the statutory requirement that PSD permits be issued within 12 months of a complete permit application, some believe that

the process for obtaining a permit can take too long, delaying construction. Third,

some are concerned that the decisions made in the NSR process, such as the selection of a control technology, have been arbitrary, making it difficult to plan ahead.

Fourth, stakeholders such as citizens and Federal land managers want to be more

involved in the decisionmaking process. In addition, some believe that the program

needs to cover more sources and is not sufficiently rigorous, while others feel that

the existing program is already too rigorous and too broad in scope.

For the past several years, the EPA has been undertaking a thorough multi-stakeholder process to understand and address the concerns associated with NSR in an

effort to make the program work better. The NSR program protects the public from

air pollution from large sources—from every type of industry. EPA has been diligent

about being inclusive and comprehensive in our analysis of industry concerns. Since

1992, we have held hundreds of hours of meetings actively seeking comments and

recommendations from various stakeholders. We formed the NSR Reform Subcommittee of the Clean Air Act Advisory Committee, a group of experts from industry, environmental groups, and State and local government brought together for the

purpose of making recommendations on improving NSR. We listened to analysis and

debate from a wide variety of often conflicting points of view. We issued a proposed

rule in 1996, took written comments, and held a public hearing. Since then, we continue to meet with stakeholders, and, as recently as this month, have had multiple

meetings with outside groups representing industry.
82

Our fundamental principle during this reform effort has been to promote more certainty and flexibility in the permitting process while maintaining at least the

same level of environmental protection as the current program. A few examples of

the approaches we have proposed include: (1) promotion of flexible plantwide caps

that would enable sources to make changes at their plants without triggering NSR

applicability so long as the overall cap is not exceeded; (2) a more clearly defined

and faster process for making control technology decisions; (3) deregulation of source

modifications that have already recently installed good controls; (4) increased incentives for new or modified sources to incorporate pollution prevention or innovative

control technology; and (5) opportunities for more meaningful participation in the

permitting process for the public and Federal land managers through increased

availability of information and earlier involvement.

We are also considering other ways to better achieve the same goals as the current program. For example, we recently held a meeting of NSR stakeholders to obtain views on the concept of a sector-based approach to NSR at utilities. This approach would tailor NSR regulations specifically to the utility sector in an effort to

address issues unique to utilities, while still providing the overall environmental

protection of the NSR program. As noted, we continue to discuss several issues with

stakeholders, and have not reached final decisions on the Reform package. However,

we hope to complete an NSR Reform rulemaking later this year.

Mr. Chairman, this concludes my prepared statement. I appreciate the opportunity to be here today. I would be happy to answer any questions that you may

have.

STATEMENT OF JOE BYNUM, EXECUTIVE VICE PRESIDENT, FOSSIL POWER GROUP

TENNESSEE VALLEY AUTHORITY

Mr. Chairman, thank you for the opportunity to testify before the subcommittee

today. In my testimony today, I am providing the committee with the views that

are solely those of the Tennessee Valley Authority. I appreciate your interest in the

Environmental Protection Agency’s proposed changes to the New Source Review

(NSR) program. Depending upon how EPA changes this program, there could be a

lasting impact on the operation of individual fossil plants and, in fact, the reliability

of our nation’s electric system.

The Tennessee Valley Authority is a Federal agency and corporation charged with

fostering the economic and social well being of the residents of the Tennessee Valley. This includes managing the Tennessee River system, with responsibilities for

flood control, navigation and stewardship of land and water resources. As part of

this mandate, TVA operates the nation’s largest integrated public power system,

providing electricity to eight million residents in a seven-State region.

In total, we have over 28,000 megawatts of generating capacity. Coal-fired generation comprises about 60 percent of this capacity, with 59 units at 11 plants in three

southeastern States. This places us among the largest coal-using utilities in the

country. TVA has been operating various kinds of generating technologies for more

than 65 years and has substantial expertise in the maintenance of fossil plants. I

am here today to represent TVA’s dual responsibilities as a power producer and an

environmental steward.

Although there has been some criticism of its complexity, TVA believes the NSR

program has generally been a success. EPA has largely applied the program’s requirements in a way that does not impede routine maintenance of the nation’s electric-utility generating resources. Moreover, in the past the program has not been applied in a way to discourage improvements in unit efficiency and reliability. TVA

believes such improvements—long a part of routine maintenance—are desirable to

ensure a reliable supply of electricity and are in the public interest.

As the person responsible for the operation and maintenance of 59 coal units, I

urge great caution as EPA contemplates changes to the program that could preclude

improvements in efficiency and reliability. Unfortunately, some of the ideas being

presented to EPA by others as part of the rulemaking process could discourage such

desirable improvements and have a detrimental impact on the electric-utility industry’s ability to safely and effectively operate our plants.

EPA’s stated goal in its proposed regulation is to ‘‘reduce the costs and regulatory

burdens for applicants’’ to the program. However, I would counter that, rather than

achieving this admirable goal, these potential changes to the proposed rule will actually impede the NSR process. In fact, several aspects of the proposal are not only

unsound on policy grounds, but appear counter to the intent of the Clean Air Act.

The current NSR regulations have long excluded routine maintenance, repair, and

replacement projects at existing sources. Industries of all kinds, including the elec-
83

tric utility industry, have relied upon this exclusion to maintain production capabilities and capacity. Historically, EPA has employed a common-sense understanding

of the term that encompassed those maintenance activities that are customary in

the industry to optimize reliability, safety, availability and efficiency.

It would be a serious mistake in this rulemaking for EPA to change its historic

interpretation of the definition of routine maintenance. EPA should not make

changes to the program that discourage utilities from making improvements that increase plant efficiency and improve reliability.

Utilities in the Eastern Interconnect have been straining to meet demand and

keep the lights on the last two summers. Now more than ever, utility maintenance

programs are key to meeting demand and reliably serving the public. TVA has recently released a technical report on routine maintenance on the TVA system and

in the utility industry. This report demonstrates how important maintenance is to

reliable service. I would like to submit a copy of this report for the record.

Mr. Chairman, TVA finds itself in the position of agreeing with what appears to

be EPA’s broader goals in these NSR changes—improving the nation’s air quality.

However, we remain concerned that the agency may be tempted to shoehorn this

admirable goal into a program that is primarily designed to address the permitting

and control of new sources. Literally, the new source review program is about who

turns a wrench, when and where. It is not intrinsically designed to handle broad

shifts in air quality policy. Instead, this rule should use a straightforward approach

that does not block the maintenance practices that have allowed this nation’s industrial capacity to support the booming economy.

In the summer of 1998, TVA announced the voluntary installation of selective

catalytic reduction controls to control nitrogen oxide emissions at 10 of our larger

coal units. TVA is undertaking this effort because we believe it is necessary if air

quality improvements are to continue in the Tennessee Valley region. We are committed to this effort although it will cost more than $500 million on top of the more

than $2.5 billion that TVA has already spent to reduce emissions from its coal-fired

plants. By 2005, TVA will have reduced its system sulfur dioxide emissions by SO

percent. Moreover, by the same period, we aim to reduce our ozone season its nitrogen oxide emissions by 70–75 percent, driven in large part by our voluntary efforts.

I note this voluntary effort for two reasons. First, I think it demonstrates our commitment to environmental stewardship. Second, it represents an emissions control

effort based on a comprehensive analysis of our entire system to achieve efficient

air quality throughout the Tennessee Valley and adjacent areas. TVA carefully considered the air quality challenges facing our region, and we are placing SCR controls

where they will do the most good.

When considering how the NSR program should be improved, an approach similar

to TVA’s system-wide plan for nitrogen oxide reductions can be a template. Although the utility industry has just finished substantially reducing its NOx emissions, TVA thinks more can and should be done. What is needed is a program that

allows utilities to reduce emissions on a system-wide or industry-wide basis over

time while still allowing units to be maintained as they have been historically. TVA

stands ready to work with this subcommittee and EPA to build on the improvements already well under way.

Finally, in general, there should be greater emphasis on multi-pollutant planning,

taking a look at how to improve air quality generally rather than just one pollutant

at a time. Utilities need greater certainty as they plan for emissions control. Most

importantly, air quality improvement efforts must have adequate mechanisms to ensure the most cost-effective air quality improvements. Unfortunately, the attempts

to achieve these goals through the New Source Review program will likely fall flat.

The underlying program is ill-equipped to answer these far-reaching policy considerations.

Mr. Chairman, the subcommittee’s interest in the proposed changes to the New

Source Review program is well timed. We are at an important juncture, trying to

find a way to continue improvements in air quality without sacrificing the maintenance of individual facilities or the reliability of the overall electric system.

STATEMENT OF BOB SLAUGHTER, GENERAL COUNSEL AND DIRECTOR OF PUBLIC POLICY, AMERICAN PETROLEUM INSTITUTE, ON BEHALF OF THE NATIONAL PETROCHEMICAL AND REFINERS ASSOCIATION

I. INTRODUCTION

Good morning. My name is Bob Slaughter. I am General Counsel and Director

of Public Policy for the National Petrochemical & Refiners Association (NPRA). I am
84

very pleased to be here this morning to address the need for reform of the ‘‘New

Source Review/Prevention of Significant Deterioration’’ (‘‘NSR’’) program under the

Clean Air Act on behalf of both NPRA and the American Petroleum Institute

(‘‘API’’).

NPRA’s membership includes virtually all U.S. refiners, as well as petrochemical manufacturers using processes similar to refineries. Our members own and/or operate almost 98 percent of U.S. refining capacity. NPRA includes not only the larger

companies, but also many small and independent companies. API is a trade association that represents more than 400 member companies involved in all aspects of the

petroleum industry including refining, exploration and production, transportation,

and marketing industries. The NSR program significantly affects NPRA and API

member companies.

II. OVERVIEW

The refining industry has dramatically reduced its direct and indirect emissions since Clean Air Act regulation began in the 1970’s. Between 1980 and 1996, according to EPA’s own figures, the refining industry decreased its criteria pollutant air

emissions by 74 percent. Congress and EPA have required us to attain additional

dramatic emissions reductions in the next few years. We will meet these obligations. However, both our ability to meet them and our ability to efficiently make and deliver the products we refine to consumers is currently threatened by the likely prospect that EPA will claim that almost any operational change we make triggers ‘‘new source review’’ (‘‘NSR’’) under the Clean Air

Act.

Congress enacted the NSR program in the 1970’s to ensure that sources that significantly increase their emissions must install technology to control that increase.

You may well ask how an industry with the continuing record of dramatic emissions

reductions which I have mentioned could be so affected by a program intended to

control emissions increases.

The answer lies in the manner in which EPA now administers this program. EPA

applies NSR to many changes that will never cause emissions increases, even to

changes that will reduce emissions. Moreover, EPA’s practice of defining critical elements of the program by guidance rather than through rulemaking—or not defining

them at all—has created a situation where it is effectively impossible for even the

most diligent refiner to determine when NSR applies and when it does not.

This state of affairs has created an urgent need for NSR reform. The policy consideration is this: EPA’s reinterpretation of NSR threatens our ability to make the

plant changes necessary to comply with important environmental requirements for

stationary sources and fuel reformulation.

I would now like to address these points in more detail.

III. HOW THE NEW SOURCE REVIEW PROGRAM THREATENS FUTURE ENVIRONMENTAL

PROGRESS

The refining industry now faces extensive new Clean Air Act regulations that will

take effect in the near future. These include requirements both for control of refinery emissions, and for the reformulation of gasoline to remove sulfur and selected

‘‘air tonics’’. It seems certain in addition that EPA will require the reformulation of

diesel fuel, and likely that Congress or EPA will consider requiring the phase-down

or elimination of MTBE from gasoline.

Attached is a chart titled, ‘‘Cumulative Regulatory Impacts on Refineries: 2000–

2010’’ reflecting these requirements in more detail.

Implementing these upcoming programs is very important to EPA’s environmental agenda. The refining industry’s environmental progress to date is very impressive. Between 1980 and 1996, according to EPA’s own figures, the refining industry decreased its criteria pollutant air emissions by 74 percent, while refining

capacity decreased by only 16 percent (see attached chart titled ‘‘U.S. Refinery

Emissions Reductions’’). These figures underestimate our current emissions reductions, since they do not include the impact of many regulations issued under the

1990 amendments to the Clear Air Act. Nor do they reflect the significant emissions

reductions that have been obtained through the use of reformulated gasoline produced by our industry. EPA expects emission reductions achieved by future fuel reformulation and stationary source emission requirements to be even greater. EPA

estimates that just one of the upcoming product reformulation regulations, the Tier

IV gasoline sulfur reduction requirements, will produce emission benefits equivalent

to removing 164 million cars from the road.

EPA has recognized that refiners face tremendous logistical challenges in meeting

the ambitious goals and deadlines of these important new regulations. To implement
85

1 Clean Air Act §111(a)(4); 40 CFR 52.21(b)(2).

the regulations, refiners must make many infrastructure and process changes. For

each change, refiners must determine whether NSR permitting and controls are required, and then obtain required permits before commencing any construction. Because it is now effectively impossible to determine when an NSR permit is required,

and extremely time-consuming to obtain a permit, the current state of the NSR program directly threatens the industry’s ability to meet Congress’ deadlines for this

suite of new regulations. In order to meet Congress’ ambitious goals and deadlines for upcoming Clean Air Act regulations, it is essential that refiners have a flexible and efficient permitting

process. The current NSR program prohibits this and must be substantially reformed. Moreover, as discussed below, EPA’s new interpretation of NSR applicability threatens continued environmental progress, as it penalizes refiners for making

changes that decrease emissions.

IV. THE PROBLEM WITH EPA’S CURRENT APPROACH TO NSR APPLICABILITY

NSR is one of the most complicated regulatory programs ever created. EPA has recognized this and initiated the reform process to simplify and rectify the program.

In this hearing, however, I want to focus on certain aspects of the program. EPA’s

current approach to NSR applicability makes it extremely difficult for refiners to determine when NSR permitting and controls are required and leaves refineries in enforcement jeopardy unless they consider NSR for any and all operational changes.

As a result, the program is an untenable burden on State permitting authorities and

refineries and threatens their ability to implement Congress’ future environmental

goals in a timely manner.

A. Background

Under the Clean Air Act and EPA’s regulations, NSR is triggered by any ‘‘physical change or change in the method of operation’’ of a source that increases its emissions by a significant amount. 1 If a physical/operational change does not itself significantly increase source emissions, or if the source ‘‘nets out’’ the change by offsetting emissions reductions in other places, then, under the law, NSR does not apply.

If a change does cause a significant emissions increase, NSR requires the source

to get a permit before beginning construction of the change, install emissions control

technology on the change, and perhaps meet other requirements as well. It takes

18 months to 2 years on average to get an NSR permit.

EPA officials have recently made public statements that many changes at refineries over the past 20 years required NSR permits but that none were obtained. Since

NSR is only triggered by an emissions increase, and given that the refining industry

since 1980 has experienced dramatic emissions reductions, any such EPA claim of

widespread NSR noncompliance would appear inconsistent with the basic intent of

the Clean Air Act.

EPA has not disclosed information to support its claims of widespread refinery

NSR noncompliance, and so we cannot comment on them specifically. However, EPA

has reinterpreted its NSR rules in recent years so as to enable the Agency to allege

that virtually any change a source might make requires NSR permitting and controls, even if emissions have not increased. In creating NSR, Congress intended that

facilities that significantly increase emissions, by adding new equipment or making

major changes, must install the latest pollution control equipment. NSR was never

intended to impose new controls on older facilities simply because of their age and

need for routine maintenance.

B. The Elements of EPA’s Current Approach to NSR Applicability

1. The ‘‘Actual-to-Potential’’ Test

EPA uses the ‘‘actual-to-potential’’ test to determine whether a source has significantly increased its emissions. As explained below, the ‘‘actual-to-potential’’ test is

bad public policy because it provides an incentive for sources to maximize their

emissions, and punishes them for minimizing their emissions. The ‘‘actual-to-potential’’ test is also inconsistent with Congress’ intent for the NSR program, because

it requires a source to add controls when its emissions do not increase significantly

or even when they decrease. Congress intended NSR to apply only when a source

significantly increases its emissions. The ‘‘actual-to-potential’’ test is a result of EPA

interpretation and should be altered or abandoned through the reform process.

In determining whether a ‘‘physical/operational change’’ at a source caused a significant emissions increase, EPA does not compare actual emissions before the

change with actual emissions after the change. Instead, EPA compares actual emis-
86

2 EPA policy forbids sources that engage in ‘‘emissions trading’’ from counting their compliance

margin as an ‘‘emissions credit’’ when it would be advantageous to the source to do so. See Draft

Economic Incentive Program Guidance (September 1999) at 81, 106–107. But EPA NSR policy

counts that same compliance margin toward non-compliance with NSR and uses it to trigger

permit requirements.

sions before the change with potential emissions—that is, the maximum amount the

source could emit—after the change. According to EPA, NSR is triggered whenever

the difference between ‘‘past actual’’ emissions and ‘‘future potential’’ emissions is

‘‘significant’’. This ‘‘actual-to-potential’’ approach always overstates the emissions increase caused by a physical/operational change. There will always be a difference between

‘‘past actual’’ emissions and ‘‘future potential’’ emissions at any source that complies

with its emissions limits. Sources must maintain a buffer between actual emissions

and potential (permitted) emissions to avoid inadvertently exceeding the permitted

limit. A source that cares about its environmental performance will go further and

try to minimize its emissions at all times, and EPA should encourage this. However,

EPA’s ‘‘actual-to-potential’’ test punishes sources for doing so. The ‘‘actual-to-potential’’ test penalizes efforts to maintain a compliance margin or minimize emissions and uses them to trigger NSR for changes that do not really

increase emissions, or even decrease emissions. As a source lowers its actual emissions, the difference between those actual emissions and potential emissions gets

greater. EPA counts that difference as an emissions increase that triggers NSR

whenever that source makes a physical/operational change. Thus a source is rewarded for maximizing emissions and deterred from minimizing emissions. Additionally, under this approach, a process unit at a source can trigger NSR repeatedly

even when its emissions do not increase at all or even decrease. 2

Although the ‘‘actual-to-potential’’ test is inconsistent with the intent of the statute, EPA requires that sources use this method and only this method to determine

whether an emissions ‘‘increase’’ has occurred. EPA has found it to be a convenient

way to require controls on more sources, whether or not their emissions have increased significantly.

What is a ‘‘Physical Change or Change in the Method of Operation’’?

As we have shown, the ‘‘actual-to-potential’’ test creates phantom emission increases. As a result, almost any change labeled a ‘‘physical change or change in the

method of operation’’ of a source will trigger NSR even if in reality it will not increase emissions at all, or even decreases emissions.

The question then become, what is a ‘‘physical change or change in the method

of operation’’. EPA’s application of the term is a moving target. Small repairs and

improvements are needed constantly at complex sources like refineries. Under

EPA’s current approach, it is impossible to determine when such a repair or improvement will be counted as an NSR-triggering ‘‘physical/operational change’’, and

when it will not. We know that EPA is increasingly aggressive in its claims that

such repairs and improvements trigger NSR. However, that change in position has

never been subject to public notice and comment, as the Administrative Procedure

Act requires. Some of its elements have not even been issued as guidance. In some

cases, we do not even know what they are.

Let me offer two illustrations of these points, picked from many possible candidates.

• A’s rules provide that ‘‘routine maintenance repair and replacement’’ does not

trigger NSR. EPA has never defined these terms, either in rulemaking or guidance.

However, recently, EPA has begun to claim in enforcement actions and informal

conversations that this exclusion never applies to changes that increase the efficiency of a unit, improve its reliability, or reduce its costs. Under that approach,

repairing or maintaining a 1990 unit with year 2000 components that improve its

performance could trigger NSR. Such an approach is both economically and environmentally counterproductive. It destroys the ‘‘total quality improvement’’ programs

that businesses must adopt in today’s competitive markets—and that the Administration has endorsed because of their environmental benefits.

• EPA has always recognized that NSR is triggered when a single ‘‘physical

change or change in the method of operation’’ causes an emissions increase. EPA

has also always cautioned that if a source artificially splits a single project into two

projects in order to avoid NSR, it will still treat that project as one. We agree. But

EPA now claims that all changes at a plant should be aggregated together whenever

they serve the ‘‘basic purpose’’ of the facility. Since changes that did not serve that

‘‘basic purpose’’ would not be made, this is a formula for aggregating all changes

that a plant makes into one change. Once those changes have been aggregated, the
87

‘‘actual-to-potential’’ test makes it virtually certain NSR requirements will be triggered.

V. THE CONSEQUENCES OF EPA’S CURRENT APPROACH TO NSR

EPA’s current approach to NSR applicability results in significant compliance uncertainty, overburdens State and refinery resources, and hinders future environmental progress.

1. Compliance Uncertainty

Under EPA’s current approach, it has become nearly impossible for any refinery

to determine which of its activities might trigger NSR and which will not; EPA’s

requirements are extremely unclear and a constantly moving target.

Refiners cannot rely on the current written guidance to determine when NSR is

required because the existing guidance is unclear and often contradictory. It consists

of over 4,000 pages of guidance documents, many of which are in draft form and

contradict each other, and various EPA memoranda. Many of EPA’s new positions

on NSR applicability contradict the older guidance, and are not even in writing. Refiners often do not know EPA’s latest position until it is incorporated into an enforcement action or initiative.

Refiners should be able to rely on State permitting authority decisions to determine when NSR is applicable, but it now appears they cannot. In most States, EPA

has delegated the implementation of the NSR program to State permitting authorities. The State permitting authorities make permitting decisions for refineries, and

regularly inspect refineries to ensure that State decisions are properly implemented.

EPA also reviews and approves the States’ programs, and periodically inspects the

refineries themselves. However, compliance with State decisions does not necessarily accord with EPA’s latest positions. In fact, EPA is currently conducting a

widespread investigation of refineries regarding NSR permitting compliance as far

back as 1980. In effect, EPA has called into question State NSR permitting decisions

over the last 20 years. These decisions were not questioned during 20 years of State

and EPA inspections.

2. Overburdening State Resources

Moreover, under EPA’s current approach, hundreds of projects a year at a refinery

might trigger NSR. No State has the resources to answer thousands of NSR permitting questions annually from all its major stationary sources, or to review its NSR

permitting decisions over the past 20 years. Certainly, States have much better and

more environmentally productive ways to invest their resources (e.g., expediting permitting for gasoline sulfur reduction requirements as EPA has agreed to do). State

permitting may also be slowed down because States will proceed more cautiously

for fear that they may be second-guessed by EPA. This may create permitting bottlenecks at the very time States need to proceed expeditiously to implement important upcoming regulations.

3. Overburdening Refineries

The end point of EPA’s current position is universal NSR. However, no industrial

economy could function if every change to a factory required a permit before construction could begin. This will be particularly burdensome for refineries given the

operational changes necessary to comply with the blizzard of new fuel reformulation

and stationary source regulations. EPA recognized that Congress did not intend universal NSR in its 1996 proposal for NSR reform, however EPA’s new approach is

achieving just that:

‘‘. . . section 111(a)(4) of the Act could—read literally—encompass the most mundane activities at an industrial facility (even the repair or replacement of a single

leaky pipe, or an insignificant change in the way that pipe is utilized). However,

the EPA has recognized that Congress did not intend to make every activity at a

source subject to major new source requirements under parts C and D. As a result,

the EPA has adopted several exclusions from the ’physical or operational change’

component of the definition. For instance, the EPA has specifically recognized that

routine maintenance, repair and replacement. . . [is not by itself] considered a physical or operational change in the method of operation within the definition of major

modification.’’ 61 Fed. Reg. 38250, 38253 (July 23, 1996).

4. Hindering Future Environmental Progress

As discussed in section III, EPA’s current approach to NSR threatens the Agency’s

future environmental agenda by posing significant logistical challenges for implementing important upcoming regulations.
88

Additionally, the unnecessary costs of EPA’s current approach to NSR will compete with resources needed to implement these regulations. Our resources are limited and the costs of these upcoming regulatory initiatives are high. Just one of

these regulations, the Tier II/gasoline sulfur reduction requirements, is expected to

nearly double the refining industry’s environmental expenditures to approximately

$8 billion annually. Expected requirements to reformulate diesel fuel could increase

these costs by half again.

We simply do not see the logic for applying EPA regulatory reinterpretation to

activities that do not increase emissions, or actually reduce emissions.

VI. REFINING INDUSTRY GOALS FOR NSR REFORM

The refining industry is encouraged by our current round of discussions with EPA

on NSR reform and hope that this joint effort will continue and produce real reform.

The discussions so far have been candid and useful, but we still do not know clearly

what to expect from them.

We believe that any real reform must address both substantive and procedural

issues. Real reform should ensure that NSR applies only if emissions actually increase significantly. The current system of perpetual exposure to NSR cannot be defended.

Real reform must alter or abandon the ‘‘actual-to-potential’’ test so that changes

that do not increase emissions do not automatically trigger NSR. Real reform must

also change EPA’s current approaches to ‘‘routine maintenance, repair and replacement’’ and ‘‘aggregation’’, which work together with the ‘‘actual-to-potential’’ test to

create exposure to NSR for virtually any change a plant makes. Perpetual NSR is

unworkable, contrary to Congressional intent, and bad environmental policy.

Finally, real reform will address the need to expedite rather than hinder efforts

to comply with federally mandated environmental programs.

These changes should be subject to full public review and comment.

VII. EPA’S ENFORCEMENT INITIATIVE WILL UNDERMINE NSR REFORM

I would like to conclude with a word about enforcement.

Over the past 2 years, EPA has been conducting a massive investigation of the

refining industry, and several other industries, for purported ‘‘widespread’’ noncompliance of the NSR program. Violations of NSR do occur, and the government

should pursue them whenever they do. However, the refining industry believes

EPA’s allegations of widespread noncompliance are based on new and controversial

reinterpretations of the NSR requirements that amount to rulemaking without notice and comment. By making fundamental changes to the NSR program through

enforcement actions, EPA threatens to undermine the NSR reform process and an

clarification of the program that reform can provide.

The reinterpretations that EPA wants to retroactively enforce would allow EPA

to claim that virtually any source is subject to NSR. As previously discussed, this

approach would be impossible to comply with, overburden State and industry resources, and undermine the implementation of future environmental regulations.

By questioning State permitting decisions and policy over the past 20 years, EPA

will only further slow down the permitting process and divert State resources toward reviewing past decisions. This is inappropriate at a time when it is critical

that State permitting authorities and refiners work together to expedite the permitting processes for important upcoming environmental regulations, such as the Tier

II/ gasoline sulfur reductions requirements.

The decision criteria for many NSR issues are so opaque, and have changed so

many times that, in our view, it is neither fair, nor just, nor sound public policy

to make them the excuse for an aggressive enforcement program. The opportunity

for public comment and congressional review of EPA’s proposed reinterpretation of

NSR is necessary to respect the due process rights of those who have to comply. If

EPA wants to revise the NSR program, it should do so through the reform process.
89
90

STATEMENT OF W. HENSON MOORE, AMERICAN FOREST & PAPER ASSOCIATION

Good afternoon. I am Henson Moore, President and CEO of the American Forest

& Paper Association Thank you for inviting me to present the views of America’s

leading forest and paper companies on EPA’s New Source Review Program, or NSR.

This hearing exemplifies your concern to see that our environmental laws work.

AF&PA believes that the NSR program should meet a few basic principles. First,

the rules should be consistent, in sync with congressional intent, and not change

in midstream. Second, policies should benefit the environment. And finally, program

regulators, not enforcers—should set regulatory policies in a process that is open to

public scrutiny.

Based on these principles, our industry judges today’s NSR program as fundamentally ‘‘broken.’’ It needs immediate reform.

Everyone agrees it’s broken EPA, the States, industry, Republicans and Democrats in Congress and notably labor unions. In fact, the Forest Products Industry

National Labor Management Committee, a coalition of labor unions and industry organizations which represent over 1 million workers, issued a statement today raising similar concerns with EPA’s reform and enforcement efforts. I would like to submit it into the hearing record.

Making matters worse, EPA is playing ‘‘good cop, bad cop’’ with targeted industries, sending out conflicting signals on how it intends to pursue NSR. While the

air program continues an on-going process started in 1991 to clarify, simplify, and

fix NSR, the office of enforcement is aggressively issuing notices of violation on pulp

and paper facilities. Other major industries are, or may soon be, facing similar assaults. By doing this, the enforcement office is reinterpreting established NSR policies that industry has long used to comply with the law and doing so without notice,

comment, or any public procedure and applying these new interpretations retroactively asking for fines in the process. In addition, EPA’s judgments frequently second-guess State permitting agencies earlier decisions leading to EPA’s erroneous

conclusion that 80 percent of industry is in non-compliance. This is as unfounded

as the underlying guidance is confusing.

In some cases, plants are deferring routine maintenance, delaying conversion to

cleaner fuels or making other environmental improvements, and shelving plans to

move forward with production innovations all to avoid the uncertainties and burdens imposed by the current NSR review process. If this continues, two things will

happen: our industry will lose its competitive edge in a global marketplace and the

environment will suffer.
91

Our Industry and Its Commitment

Let me tell you a little about the forest and paper industry. With more than 1.5

million workers and an annual payroll of $41 billion, we’re a major contributor to

the nation’s overall economic health.

Importantly, every AF&PA company subscribes as a condition of membership to

a set of eight environmental, health, and safety principles designed to make environmental performance an essential part of every aspect of their operations. As we

have increased employment and production as an industry, we’ve also made important environmental strides:

• We cut our sulfur dioxide emissions by 63 percent between 1980 and 1995.

• We reduced the amount of chlorine used in bleaching by 89 percent from 1988

to 1994.

• We decreased surface water discharges by 47 percent between 1988 and 1996.

• We’ve reduced the total energy we consume to make a ton of paper by 21 percent.

• Our industry are recycling leaders, recovering nearly half of all the paper and

paperboard Americans use each year.

We have a similarly rigorous commitment to the management of forestlands,

called the Sustainable Forestry Initiative SM (SFIsm) program. Participants in this

innovative program abide by a set of strict principles and objectives. A panel of 18

nationally recognized experts including leading environmentalists, academics, and

foresters, as well as representatives of the U.S. Forest Service and EPA oversees

our performance and critiques it as part of our annual SFIsm progress report. We

are especially proud that in 1999, Renew America and the President’s Council on

Sustainable Development recognized SFIsm with the National Award for Sustainability.

In addition to our commitment to innovation, we’re also committed to cooperation.

In meeting our environmental responsibilities, we work closely with regulators, environmentalists, and leaders in the communities that host our facilities, and others.

A good example is the way we worked in concert with EPA to develop the socalled pulp and paper ‘‘Cluster Rule,’’ the first-of-its-kind multi-media regulation

governing air and water quality in our industry. In fact, we were the only industry

to voluntarily accept EPA’s invitation to develop the ‘‘cluster’’ concept. Although it

requires us to invest an estimated $2.8 billion in environmental upgrades, we’re satisfied that the final rule fairly balances environmental improvements and benefits

with our industry’s capital planning expectations.

And, of course, we’ve been heavily involved in EPA’s effort to reform the New

Source Review program from the very beginning, putting constructive ideas on the

table, working with other industries and stakeholders, and being responsive to

EPA’s requests. Incidentally, our experiences with Assistant Administrator Bob

Perciasepe and his staff have always been positive and productive. We are ready

to work diligently toward a reasonable NSR program.

Why NSR Is Broken

In broad terms, NSR requires a company to get a permit before it begins construction of any new ‘‘major source’’ with the ‘‘potential to emit’’ more than 100 to 250

tons a year of any regulated pollutant under the Clean Air Act. It also requires before construction begins a permit for a physical change to an existing ‘‘major

source,’’ or any change in its ‘‘method of operation,’’ that will cause an increase in

actual source emissions of any regulated pollutant exceeding specified levels. Typically, it takes over a year and a half to get a permit, even for very small plant

changes, requiring extensive air quality analysis and a commitment to install expensive state-of-the-art control technology.

In creating NSR, Congress told plant operators who would increase emissions by

adding new equipment or making major changes to existing facilities to install the

latest pollution control equipment. But Congress never intended NSR to impose new

controls on older already permitted equipment simply because of their age and need

for routine maintenance. So the problem with NSR is not congressional intent.

NSR was designed to hold the line against emissions increases, not to aggressively

pursue broad emission reductions. Other sections of the Clean Air Act already have

that mandated purpose. The statutory term ‘‘prevention of significant deterioration’’

(PSD) makes that purpose clear.

The problem with NSR has always been with the way EPA has implemented it

not congressional intent. The rules are too complex. The informal guidance, memoranda and letters EPA has issued over the last 23 years more than 4,000 pages of

interpretations and reinterpretations is inconsistent. It is no surprise that so much

confusion abounds when most of these interpretive changes occurred at EPA behind
92

closed doors without the benefit of public notice and comment. In particular, in recent years, EPA has sought to change interpretations that industry, the States, and

EPA itself have followed for years. The definition of ‘‘routine maintenance’’ is a good example of EPA’s flip-flopping policies.

In 1980, EPA provided an exclusion from NSR review for ‘‘routine maintenance’’

without defining the term. In 1988, an EPA memorandum indicated the agency would weigh a variety of fac- tors ‘‘to arrive at a common-sense finding’’ as to what was routine maintenance.

This admittedly ambiguous interpretation left much latitude in State and EPA’s

case-by-case reviews. Then, in 1999 the enforcement office substantially narrowed the exclusion, with- out public input, stating it ‘‘was meant to cover frequent, traditional, and comparatively inexpensive repairs to maintain existing equipment.’’ EPA is changing the rules 180 degrees contrary to congressional intent, and is ap- plying those changes retroactively, using a process that lacks public involvement.

For example, if a plant manager replaces worn-out bricks on the inside of a furnace,

doesn’t that sound like routine maintenance even if the replacements are costly and

occur on an irregular basis. Real NSR reform needs to go back to a ‘‘common sense’’

definition of routine maintenance. So the first problem is to reform NSR to make

it workable.

EPA has long known of the problem. As far back as 1991, it announced it would ‘‘simplify and reform’’ the ‘‘old’’ 1980 NSR program to reduce confusion over its applicability and to streamline NSR review. Several years later, the Clinton Administration cited NSR as a candidate for reform in its National Performance Review of

Regulations. At a September 1996 hearing, an EPA spokesman acknowledged: ‘‘A

lot of uncertainty exists in the old regulations as they have evolved since about

1980.’’

Major efforts by the EPA air office in 1996 and 1998 to rewrite the NSR rules did not yield successful reform, but clearly indicated EPA’s desire to fix the broken

program. However, the job is not completed and confusion still exists. Recently, two

senior EPA staff members heavily involved in the NSR reform discussions publicly

debated the ‘‘correct’’ interpretation of its ‘‘actual to potential’’ NSR policy. If EPA

officials can’t figure it out and agree on a single meaning, how are States and industry supposed to? Some people familiar with NSR, again including some within EPA, have gone so far as to suggest the program is working at cross-purposes with the Clean Air Act.

During a 1993 NSR Simplification Workshop, for example, Ed Lillis, the Chief of

EPA’s Permits Program Branch, admitted: ‘‘the rules seem to work against the purpose of why they were established.’’ The agency’s current method for estimating emissions from a planned plant

change is another good example of how NSR policy defies logic. EPA has recently

changed its interpretations to require the facility to compare its pre-change actual

emissions to its post-change potential emissions. This ‘‘apples to oranges’’ accounting

scheme forces every facility to count imaginary emissions from unused capacity as

an increase in emissions resulting from the modification, thus triggering NSR even

when the change will cause no real increase in actual emissions, and, in many

cases, will reduce actual emissions. For example, an effort to reduce emissions and

comply with the ‘‘Cluster Rule’’ could land a facility in the 18-month NSR permit

review process and end up requiring even more controls. Where’s the common sense

in this? To quote a letter from Pennsylvania’s Department of Environmental Protection to Robert Perciasepe, ‘‘How can we expect industry to do everything they can

to minimize emissions when we will be penalizing them for these actual reductions

when they come in for New Source Review?’’

Or consider the outcome of this real-world scenario.

In 1 year, a typical pulp and paper site may make 40,000 changes in equipment,

procedures, and operations. Based on the latest round of EPA guidance and interpretations, the environmental manager at this typical site screens them all and

comes up with 400 (or roughly 1 percent) that may be considered ‘‘changes’’ under

the new guidance. Of these, the manager decides about 25 projects that would make

the plant run better and cleaner might require permitting. In the past, the State

regulatory agency would have considered most of those projects inconsequential, but

now they are reluctant to take a position for fear they may be second-guessed by

EPA’s enforcement office. Because of this uncertainty, and the fact that the State

lacks the resources to process that number of projects in the first place, all 25 efficiency and reliability improvements are stopped cold.

Does any of this sound like something that’s good for the environment or good for

business?
93

Misdirected Enforcement

What’s even more egregious than having to deal with a confusing myriad of guidance and interpretations is being held accountable for a constantly changing standard. We cannot sit here today and talk reasonably about NSR reform without talking about the aggressive NSR enforcement initiative launched last year. Just as we

couldn’t have a reasonable discussion about reforming the IRS while an army of IRS

auditors were launching an all-out attack on taxpayers based on the old rules.

Unfortunately, that’s what’s happening under the NSR program. The enforcement

actions rely on new interpretations of past EPA policy and seek large retroactive

fines which can exceed $20 million per facility. The enforcement office is taking the

program in the exact opposite direction of where the NSR reform effort needs to go.

Hundreds or thousands of minor changes at facilities would be pulled into the review system, swamping the State review process and further delaying permitting

decisions all with little or no environmental benefit. This is very counterproductive.

I think all Americans can agree, it is unfair to change the rules in the middle of

the game and penalize people for their retroactive application.

This abrogation of the basic principles previously outlined is leading to enforcement actions like these where EPA is overturning past determinations that NSR review was unnecessary because there was no significant expected increase in emissions.

Ten years ago, a mill replaced an old power boiler with a new one that had lower

potential emissions. The State, after soliciting comments from EPA, approved the

mill’s permit application for the new boiler without requiring an NSR review. Now,

EPA says the new boiler increases mill operating capacity and potential emissions

and alleges the mill failed to comply with the NSR requirements. But the law states

that only actual increases in emissions require NSR review.

A pulp and paper facility installed a boiler with a Prevention of Significant Deterioration (PSD) permit many years ago. Some years later, part of the boiler was replaced with a slightly different design that did not increase the capacity but improved the efficiency, reduced overall downtime, and decreased emissions. Now,

years later, EPA’s enforcement office, using new interpretations of what triggers

NSR review, determined that this project was a modification that required a NSR

permit and issued a notice of violation. Again, only actual emission increases require NSR review.

A facility obtains a permit from a State agency, using best emissions estimates

available at the time those from EPA’s emissions factors data base. Data developed

years later shows the original estimate was low. EPA holds that the source should

have obtained a permit based on the new data. The agency also orders it to undergo

a Best Available Control Technology (BACT) analysis using today’s measure of best

available technology. As a result, the earlier State decision is reversed. The source

must install expensive controls that were not originally available and EPA imposes

a large fine. This type of ratcheting of control requirements is unfair and not required by the law.

What is EPA trying to accomplish by going after actions that are within the law

and in some cases even reduce emissions?

As we cite these real-world examples to illustrate how EPA would overstep its authority, we need to make one thing clear. We are not here today to talk about the

details of individual enforcement actions. We do not want to impede any legitimate

enforcement discussions between EPA and our member companies. The record of the

American Forest & Paper Association in recent years makes it quite clear that we

have little patience for those who fail to meet their environmental responsibilities.

Real violations of clear environmental regulations should be enforced. Period.

Rather, we are here today to raise legitimate concerns over EPA’s overall enforcement policy. We question the logic behind the timing of what appears to be a wellorchestrated enforcement campaign at the same time that the rules underlying the

enforcement actions are in flux. EPA incorrectly claims that 80–90 percent of our

industry is not in compliance, 80 to 90 percent! This claim comes from bizarre interpretations of NSR. For example, one EPA enforcement official recently stated, ‘‘If

capital investments at major facilities have been made for the purpose of meeting

market demand, diversifying product lines, increasing production efficiency, or reducing operating costs there is a high probability of PSD violations.’’ [Betsy Wise,

EPA Region 10 Enforcement Official at January 2000 meeting of the Joint Legislative Environmental Common Sense Committee in Idaho.] In other words, if a company has pursued its routine business goals, then it seems likely to have violated

the PSD standards. Yes, under this convoluted logic, 100 percent of the industry is

guilty guilty of providing products to meet the changing demands of the American

public while doing its best to meet the intent and spirit of the Clean Air Act!
94

We are here today to raise concerns over a broken environmental regulation that allows one EPA office to retroactively reinterpret regulations established two decades ago. A clear NSR regulation must be developed to eliminate arbitrary enforcement that is being imposed on companies going about their normal business in full

compliance with the adopted NSR rules.

To draw a sports analogy, it’s like the National Basketball Association eliminating the 3-point shot and then going back to overturn any victories that were won based

on 3-point shooting. Or, if we’re talking about the IRS and taxes again, it’s like the

IRS eliminating the mortgage-interest deduction for millions of American taxpayers

today and then demanding their past taxes with huge penalties for having used the

deduction in prior years. So the second problem is this out-of-control enforcement binge. EPA should sus- pend those enforcement actions that rely on new interpretations of older policies and

do not involve emissions above permitted limits until the NSR reforms are successfully completed. Enforcement actions where emission increases exceeded permitted

limits and clearly violated the law should proceed.

Summary and Conclusions

You know the axiom all too well. It’s not the role of the judicial branch to legis- late. Likewise, it should not be the role of the EPA’s enforcement office to regulate.

Compounding this issue is the matter of timing. Not only should the enforcement

office not be regulating and changing the rules of the game and applying them

retroactively, they shouldn’t be doing so as part of an aggressive campaign while

the air office is rewriting the rules. We fully appreciate the challenge before the air office. Making sense out of these complex rules is no easy task. And we applaud the ‘‘open door policy’’ that the air

office has shown us in working on the reform effort. We ask, however, that EPA’s

reform effort follow the basic principles I have identified: establish consistent rules

and only apply them prospectively, give the job to the air office, not the enforcement

office, and base them on the law.

We’re prepared to hold up our end of the bargain by working tirelessly with EPA to make NSR reform a reality. All we ask is that EPA all of EPA hold up its end

of the bargain as well. Thank you.

STATEMENT OF DAVID G. HAWKINS, DIRECTOR, AIR AND ENERGY PROGRAMS, NATURAL RESOURCES DEFENSE COUNCIL

Mr. Chairman, members of the subcommittee, thank you for your invitation to testify on behalf of NRDC, the Natural Resources Defense Council, regarding the

New Source Review (NSR) regulatory program of the Clean Air Act. NRDC is a nonprofit citizen organization dedicated to environmental protection, with more than

400,000 members nationwide. Since 1970, NRDC has followed closely the implementation of the Clean Air Act and has sought to promote actions under the law that

carry out Congress’ policy decisions to protect public health and the environment

from harm caused by air pollution. In this testimony I would like to touch on three topics: the role of new source re- quirements in the nation’s air quality management program; features of the current

regulatory program that need improvement; and some of the general claims surrounding efforts to enforce the Act’s NSR programs against various electric utility

companies.

I. The Clean Air Act’s Dual-Track Air Quality Strategy

In 1970 Congress adopted a dual-track program to protect and enhance our nation’s air quality. The first program calls on States to adopt comprehensive pollution

control programs under State law to achieve air quality objectives set forth in National Ambient Air Quality Standards (NAAQS) adopted by EPA. This ambient program is an example of the ‘‘assimilative capacity’’ approach to environmental management based on the belief that the environment can assimilate a certain amount

of dirt or toxins released from human activities without causing identifiable harm.

This approach starts by identifying exposure levels of pollution that current research indicates may be tolerable for humans and ecosystems and then seeks to reduce emissions from pollution sources enough to meet the maximum tolerable exposure targets.

The 1970 Act’s ambient management program strengthened previous efforts enacted by Congress in the 1960’s and relied on States to set control rules for pollution

sources at levels just tough enough to bring total pollution down to the level of the

national ambient standards. Implicit in this approach is that an area’s air quality
95

determines the amount of clean-up required of sources. Even if there are readily

available means of reducing a source’s pollution, a State is not required to adopt

such measures if not needed to meet the NAAQS.

But Congress did not rely exclusively on the assimilative approach to air quality

protection in the 1970 Act. Congress adopted another strategy designed to minimize

air pollution by requiring sources to meet emission performance standards based on

modern ‘‘best practices’’ in pollution abatement. The performance standard approach

does not set required levels of control based on the air quality conditions of particular areas. Rather, the required emission reductions are determined by assessing how

much polluting processes can be cleaned up, taking account of technical and economic constraints.

Congress expected that future ambient goals would likely be more ambitious than

1970’s defined goals and wanted an independent program that would be effective

in reducing total emissions over time. Congress’ intent in the performance standard

program was to use the force of new purchases and investments to incorporate advances in pollution prevention and control as a complementary strategy to the ambient management program.

Congress applied the performance standard approach to both stationary and mobile sources but with some important distinctions. In the mobile source area (cars,

trucks, buses), only entirely new vehicles were subject to federally established modern performance standards. Congress was presented with analyses demonstrating

that with traditional rates of ‘‘fleet turnover,’’ most of the benefits of tighter new

car standards would be experienced in less than 10 years.

In requiring performance standards for stationary sources, Congress adopted more

sweeping provisions. The Act requires that both new and modified stationary

sources must meet modern performance standards. As I will discuss later, Congress

in 1970 also adopted a very expansive definition of ‘‘modification.’’

The 1970 Act’s principal tool for improved pollution control for new and modified

sources was the New Source Performance Standard (NSPS), a national, categorical

requirement based on very good, but not the best, pollution minimizing practices.

In 1977, when the Act was amended, Congress adopted the new source review

(NSR) and prevention of significant deterioration (PSD) programs to strengthen efforts to minimize emissions and air quality impacts from new and modified sources.

In the 1977 Amendments Congress expanded both the scope of the rigor of the requirements for improved performance from new and modified sources. Coverage

would no longer be limited to the categories for which EPA had adopted NSPS requirements; rather all new and modified sources above certain pollution tonnage

thresholds would be required to minimize their emissions. Second, the level of the

performance requirement would not be tied to often out-of-date NSPS; rather caseby-case determinations of current best performance would be required. Third, covered sources locating in clean areas as well as dirty areas would have to pass ambient impact tests to prevent a worsening of air quality. In 1990, Congress again increased its emphasis on pollution prevention from new and modified sources, reducing the size thresholds for coverage in badly polluted areas.

In sum, Congress has repeatedly endorsed the concept of modern performance

standards for new and modified pollution sources, adopting, in successive amendments, strengthened requirements intended to make the NSR programs more effective in reducing pollution.

However, these programs have for 20 years been the subject of criticism from industry representatives and from many academic economists. The economists’ argument runs, ‘‘why should new sources be regulated more strictly than existing

sources? After all, air quality is determined by how much pollution is released and

where it is released. The air certainly cannot tell the difference between a pound

of pollution from a plant built in 1965 and that from a plant built in 1995.’’

Critics of the Act’s new source requirements argue that instead of regulating new

and old sources differently, we should simply establish our desired air quality objectives and allow them to be met by the most efficient means. Under this approach,

agencies first would do research to identify the adverse effects of air pollution on

health and welfare; next, agencies would convert this research into environmental

standards; then, the agencies would design pollution control programs to achieve the

environmental standards; finally, agencies and pollution sources would implement

the pollution control programs and the air would become cleaner.

This critique and prescription has a certain superficial appeal. As I have mentioned, the ambient management program has been a central program of the Clean

Air Act since 1970 and it should continue. The question is whether it is prudent

to rely on the ambient standards approach as the only strategy for improving and

protecting air quality. In my view that would be a mistake.
96

The 1970 and later Clean Air Acts reflect a judgment by Congress that the ambient standards approach should be the major pollution control strategy but that it

should be complemented by other independently functioning programs such as the

NSR and Mobile Source Emission Standards programs. I think that this judgment

was a wise one. The history of air pollution control efforts both before and after the

1970 Act reveals that the ambient standards approach, while conceptually sound,

has its weak spots, which when exploited by well-organized opposition, can prevent

the program from solving air quality problems in a timely fashion.

First, the Government’s capacity to acquire unambiguous information about natural processes is very limited. The research is complex, expensive, and time consuming. Due to perennial shortages of money, talent, and time, most of the studies undertaken in the past and those being conducted now are less than perfect. As a result, their conclusions are easy to pick apart and dismiss as not dispositive. Moreover, the health effects we are concerned about are increasingly related to chronic

exposures to low levels of combinations of pollutants. We have never conducted an

adequate study to characterize the effects from these kinds of exposures and none

is even planned.

The uncertainties in what we know about air pollution effects in turn lead to controversy and delay in establishing environmental standards. All of us, including this

committee, have experienced this controversy in the continuing disputes about

EPA’s revised ozone and particulate standards.

The next step in the process—control program design—can also be affected. Different interests argue at length about how emissions in a particular location relate

to air quality in that location or elsewhere. This can and has led to uncertainty, controversy and delay in designing pollution reduction programs to meet environmental

standards. The continuing fights over efforts to address transported air pollution are

an example of this problem.

Another weak spot in the ambient standards abatement program is that it often

requires large changes in established patterns of behavior. When an air pollution

control agency adopts a regulation that applies to an existing source it is trying to

get firms to spend their money, time, and thought in ways they have not planned.

Not surprisingly, these firms often resist, which leads to uncertainty, controversy

and delay in the final step of the ambient standards approach, the actual implementation of pollution reduction measures in the real world.

This resistance to change often feeds back to the first step in the ambient standards process, setting the standards themselves. Pressure is mounted to weaken existing standards and to oppose the setting of new ones. Again, the unified fight of

industrial polluters against the revision of the ozone and particulate standards highlights this problem.

These weaknesses do not call for abandoning the ambient standards approach.

But they do suggest the wisdom of complementing that approach with programs

that are strong where the ambient approach is weak. The Act’s NSR programs meet

that need. Implemented properly, these programs can assure that as new well-controlled sources replace old ones, we will make progress in reducing emissions as our

economy grows. By controlling the major pollutants, the new source programs also

serve as a hedge against unidentified risks associated with those pollutants. By

dealing with engineering facts rather than biological facts, the new source programs

usually involve more manageable factual controversies. We are relatively good at

measuring the dollar costs of meeting performance standards and calculating the

emission reductions such standards can provide. Finally, by focusing on new and

modified sources, the new source programs can lessen the social and political costs

of reducing pollution. Because they operate at the time firms are making new investments, these programs allow firms to plan pollution prevention and control into

their plant operations.

All of this does not argue that the new source programs should replace the ambient program, only that they should complement that program. For the new source

programs have weaknesses in areas where the ambient program performs better.

The new source programs focus on the highly technical details of engineering and

thus are too insulated from effective public participation. Controlling pollution only

from new sources often is not the cheapest way to achieve a unit of emissions reduction. In my view, the premium we pay to accomplish reductions where the ambient

program has failed to deliver them is a prudent investment, but controls on new

and modified sources should not be our only program. Finally, new source programs,

because they are technology based, do not guarantee a desirable level of environmental quality. We will degrade our air quality unless we improve pollution reducing methods and processes at least as fast as we grow. The new source programs

do not create adequate incentives for such improvements and thus must be com-
97

plemented by the ambient standards and PSD programs which do recognize that

clean air is a scarce resource.

In sum, the Clean Air Act’s dual track approach to air quality management em- ploys the principle of diversification to reduce risks. In an uncertain world, a prudent investor will forego putting all his money into the one stock with the apparent

highest yield. Instead he will spread his risk by selecting a range of investments

some which offer high risk and high yield and others which offer less risk and less

yield. Similarly, the Act resembles a stable ecosystem which has a diversity of species. Such systems are much less likely to fail in the face of adversity than systems

that have no diversity.

II. How Should EPA’s NSR Programs be ‘‘Reformed’?

NRDC has participated over the last decade in stakeholder discussions convened

by EPA to consider ways to improve the Act’s NSR programs. A major reason these

talks have made little progress is the lack of agreement on the purposes of these

programs. There are two major purposes: to assure that new investments do not degrade air quality and to assure that when new investments are made, emissions are

minimized by requiring sources to meet performance standards that reflect modern

emission prevention capabilities.

While a great deal of attention has been paid to the complexity of the NSR per- mitting process, the larger environmental failure of the NSR program is that the

program has not brought down emissions as Congress intended. Citizens, pollution

control agencies, and Members of Congress are increasingly aware of the fact that

grandfathered air pollution sources are more and more the central impediment to

clean air progress. Contrary to the intent of Congress, investments in new production have not resulted in existing grandfathered sources being replaced by facilities

that must meet modern performance standards. As a result, grandfathered sources

dominate the pollution inventory throughout the United States.

The degree to which old stationary sources determine our nation’s burden of air

pollution is striking, especially when compared to the impact of old cars on pollution

loads. For example, fossil electric powerplants built more than 20 years ago are responsible for 84 percent of total US nitrogen oxides (NOx) pollution from that sector

and 88 percent of sulfur dioxide (SOx). In contrast, 20-year-old cars contribute less

than 7 percent of U.S. car NOx pollution and 3 percent of that sector’s VOC (volatile

organic compounds) pollution.

It is obvious that the Title II new mobile source program has done quite a good

job of preventing old cars from dominating today’s pollution problems but the Title

I new stationary source program has performed miserably on this score.

There are some obvious reasons for the NSR program’s poor pollution reduction

performance. First, the rules themselves contain too many loopholes that allow

sources to avoid NSR even though they continue to make significant investments

year after year. Second, as recent enforcement actions have alleged, there are many

instances of firms escaping the requirements of the rules by misclassifying projects

in an unlawful manner.

Reform of the NSR program should address its failure to produce pollution reduction from old grandfathered sources as a priority issue as well as explore ways to

simplify the NSR process. A genuine reform of the program should aim to make two

basic changes: the program should apply to more industrial projects than it now

does and the review process should be streamlined to enable decisions to be made

quickly while protecting the public’s right to participate. Instead, the ‘‘reform’’ proposals EPA has published over the last decade have concentrated almost entirely

on changes that would expand the loopholes of the current rules so that even fewer

grandfathered sources would be required to clean up as they upgraded their capital

equipment.

The combination of categorical exemptions and exclusions, weak rules for calculating emission increases, and broad provisions for ‘‘netting out’’ of review allow far

too many sources to avoid the NSR program indefinitely. When illegal evasions of

the rules are added to the many exemption opportunities in the rules, we get the

results we see most sources never encounter the Federal NSR program and their

pollution remains with us.

NRDC has filed lengthy comments with EPA on these issues over the years and

I will not burden the subcommittee with a recitation of the details here. I would

like to mention one area that of ‘‘netting.’’ Netting is the jargon for a transaction

that allows new projects at existing sources to escape NSR. In essence it allows the

source operator to count ‘‘reductions’’ from grandfathered pieces of polluting equipment at the site in calculating whether a new project will result in an emission increase that would require new source review. By allowing sources to avoid the modern performance requirements of NSR, netting preserves the status quo, perpetuat-
98

ing excessively high levels of pollution originally emitted by poorly controlled grandfathered pollution sources.

Netting rewards sources that have managed to manipulate the current system to preserve high levels of emissions. Current netting policy allows those high emission

levels to function as an asset that can be deployed to avoid NSR/PSD review. Thus,

netting operates at cross purposes with sound air quality objectives. It creates incentives to keep emissions at unnecessarily high levels and perpetuates an inefficient

allocation of emission ‘‘shares’’ by providing the greatest rewards to the most polluting sources. Netting frustrates one of the primary objectives of the NSR/PSD program, which is to link requirements for modern emission performance standards to

investments, so that emissions are reduced as the economy expands. Instead, netting allows existing emission levels to be perpetuated indefinitely. While the netting rules are complex, the fundamental problem with the approach is easy to understand. Netting allows a grandfathered pollution source to ‘‘bequeath’’

its excessive pollution privileges to its descendant, the new piece of equipment.

Under netting, the new piece of equipment is not required to meet modern performance standards; it can emit at much higher levels by relying on the pollution entitlements transferred from old, grandfathered pieces of equipment. In this way, excessive amounts of pollution can live on long after the original sources have disappeared. Netting resembles the former hereditary peerage system in England,

where membership in the House of Lords and other privileges were handed down

from generation to generation. England recently acknowledged this system has no

proper place in a modern democracy. We too need to eliminate the pollution peerage

that is embedded in EPA’s netting rules.

For nonattainment NSR, the Supreme Court in Chevron made it clear that EPA

has the authority to eliminate the availability of netting altogether. One perverse

effect of netting in nonattainment NSR is that new equipment is installed without

meeting ‘‘lowest achievable emission rate’’ (LAER) performance standards. This in

turn means that a greater level of emission reduction is required to offset the new

equipment’s emissions than if the new equipment had met LAER standards. These

additional emission reductions must come from a finite pool of existing emission

sources whose total pollution load must be further reduced for the area to attain

the ambient standards. Thus, the effect of NSR netting is to allow existing source

owners to unilaterally dedicate the cheapest and easiest emission reductions in a

nonattainment area to compensate for poorly controlled new units, leaving State

and local control agencies with the more difficult task of developing an attainment

plan from the more expensive, politically controversial remaining emission reduction

opportunities.

EPA’s original defense of its 1981 change to allow netting under the nonattainment NSR program was that areas choosing such an approach would be required

to develop timely attainment plans in any event so that there would be no environmental harm. It is now the year 2000 and EPA can no longer deny that the theory

it presented to the Supreme Court in the early 1980’s has no basis in reality. In

fact, areas have not succeeded in developing timely and adequate attainment plans.

State and local agencies have protested repeatedly to EPA that they cannot identify

sufficient, politically feasible emission reductions to demonstrate timely attainment.

EPA has responded with policies that have permitted lengthy delays in the submission of adequate plans. Given that the premise for EPA’s initial adoption of NSR

netting in 1981 has not been achieved, it is time for nonattainment netting to be

abolished.

To restrict netting in the PSD NSR program, EPA should reform its definition of

contemporaneous so that only activities which are part of the project for which the

netting claim is made can qualify. Second, EPA should reduce the netting credits

available for shutting down or limiting operations at existing units to reflect the obvious fact that the new emission-increasing projects will have greater longevity than

the older existing units that are generating the netting credits. For example, consider a source that proposes to build a 100-ton-per-year new unit with a 35-year

useful life and to net out the increase with the shutdown of a 100-ton source that

has only 5 years of life remaining. The stream of emission reductions from the shutdown source ends after 5 years but the emission increases from the new source continue for an additional 30 years. There clearly is an enormous increase in the cumulative emissions from the facility over the life of the new project that is not captured

if netting credits are given for the shutdown unit based only on a comparison 1

year’s emissions.

III. Enforcement of NSR Requirements

The ‘‘new source review’’ enforcement actions filed against major electric utilities

are an effort to end a flagrant abuse of the Clean Air Act ‘‘grandfather clause’’ provi-
99

sions relating to existing pollution sources. As mentioned above, Congress in the

1970 Clean Air Act did include a grandfather clause that exempted existing stationary pollution sources from the duty to meet modern emission performance standards. However, Congress did not intend to extend a permanent, blanket exemption

to existing sources. Thus, Congress provided that when an existing source was

‘‘modified’’ it would become subject to new source requirements. Moreover, Congress

defined ‘‘modification’’ extremely broadly, including in the term ‘‘any physical

change or change in method of operation’’ that increases emissions. Congress adopted an expansive definition of the term to prevent sources from evading new performance standards with piecemeal changes. EPA regulations narrow the Act’s modification definition somewhat by including an exemption for ‘‘routine maintenance, repair, and replacement.’’ It is this exemption the defendant companies claim shield their plants from NSR. However, the

challenged projects cannot be called routine, as a matter of law, logic, good policy,

or history. Public information documents an industry capital investment strategy,

starting in the 1980’s, to upgrade existing plants to run longer and harder rather

than letting them retire and be replaced by new capacity. For instance, one of the

challenged projects involved removing existing 700 horsepower fans (the ‘‘lungs’’ of

a powerplant) and replacing them with new 900 horsepower fans. If this is routine

replacement, then so is taking the original 350 horsepower engine out of your car

and ‘‘replacing’’ it with a 450 horsepower engine. In essence, the industry decided to sell more electricity by building new capacity into their existing machines rather than building entirely new units. This practice

has both kept pollution at unreasonably high levels and has functioned as a barrier

to entry into the market keeping many new clean, efficient units from being built. While the industry is now labeling these projects as ‘‘routine maintenance,’’ utility equipment vendors as well as utility witnesses in public utility commission rate

cases have described these projects as going beyond maintenance and providing capacity that otherwise would have to be created by building new units. Indeed, in

a recent filing with the Department of Energy, American Electric Power Co. explicitly referred to some of the challenged projects as not including ‘‘routine maintenance’’ activities.

Industry’s claim today is that any rebuild project, regardless of scope is ‘‘routine’’ as long as the rebuilt plant’s maximum production capacity is no greater than the

plant’s original maximum design capacity. This may remind you of the fabled ‘‘onehundred-year-old’’ axe: it’s only had two new heads and four new handles over its

life.

The industry’s interpretation would read the ‘‘modification’’ provision out of the Act, creating a permanent grandfather exemption for all the capacity that existed

prior to 1970. And when the industry litigated their interpretation over a decade

ago, they lost. The utility industry in the 1980’s challenged a Reagan-era EPA ruling that rebuilding a deteriorated plant to ‘‘restore’’ original capacity could not fit

within the routine maintenance exemption. In 1990, the 7th Circuit rejected industry claims that original design capacity should define the boundary for the ‘‘routine’’

exemption. Wisconsin Electric Power Co. v. Reilly, 893 F.2d 901. In WEPCO, the

court flatly rejected industry’s interpretation as one that would confer indefinite immunity from new source standards, contrary to Congress’ intent.

When the WEPCO court upheld EPA, the industry prevailed on the Office of Management and Budget (OMB) to kill a broader examination of industry practices initiated by EPA. Industry also lobbied Congress following the court ruling to amend

the law to create broad new exemptions for utility modification projects. When they

did not get new statutory exemptions, industry lobbied the Bush Administration for

regulatory exemptions. In 1992, the Bush Administration amended the NSR rules

to give the utility industry a more generous formula for calculating whether an

emission increase had occurred. But the rule did not change the definition of routine

maintenance. After the 1992 rule had been in place for a few years, EPA again

launched an investigation to determine why so few NSR applications had been filed.

The industry again sought intervention by OMB, using the Paperwork Reduction

Act as a pretext. While this effort delayed EPA’s investigation for a time, this time

OMB ultimately rejected the industry’s Paperwork Act claims.

The industry complains that EPA has not published a detailed reference book listing exactly which projects are ‘‘routine maintenance’’ and which are not. But EPA

has explained in numerous communications with utilities and other industries, that

determining the correct classification of many projects is a highly fact-specific undertaking. For that reason, These letters are similar to the opinion letters that the

IRS uses to answer fact-dependent tax questions.

The utility industry implies that EPA has not given them fair notice of their NSR

obligations. The opposite is true. It has been EPA’s practice for 30 years to issue
100

‘‘applicability determination’’ letters to resolve questions about whether a specific

project would trigger NSR. Industry officials have known from the beginning of their

rebuild programs that these types of projects could trigger NSR but they did not

seek determinations from EPA for any of the challenged projects.

Minutes of a 1984 industry discussion shed some light on the industry’s thinking.

The minutes report a consensus that companies should——

• identify their projects as ‘‘upgraded maintenance programs;’’

• ‘‘downplay the life extension aspects of these projects (and extended retirement

dates) by referring to them as plant restoration (reliability/availability improvement) projects;’’

• deal with the air regulatory issues ‘‘at the State and local level and not elevate

[them] to the status of a national environmental issue.’’ (ie, don’t ask EPA because

you won’t like the answer) EPRI, Proceedings: Fossil Plant Life Extension Conference and Workshop (1984) at 27–4.

As a final argument to inspire fear in the public, the industry has claimed that

they now cannot make needed repairs for fear of triggering additional enforcement

actions. There is no merit to this claim. EPA’s NSR rules for utilities provide generous ‘‘baseline’’ emission formulas (the maximum polluting hour in the past 5 years

and the average of the two maximum polluting years of the previous 5 years). A

company that commits to not exceed these generous limits can carry out any maintenance or other project it wishes, routine or otherwise, without triggering NSR.

Companies who refuse to commit to limit their pollution increases can seek applicability determinations from EPA.

In short we believe EPA and the other plaintiffs are doing the right thing by enforcing the NSR law as Congress intended. The results of that enforcement should

be to achieve a major reduction in pollution from these plants and to improve all

industries’ attention to their NSR obligations when they modify their facilities.

Thank you for this opportunity to testify. I am happy to answer any questions

you may have.

STATEMENT OF WILLIAM F. TYNDALL, VICE PRESIDENT, ENVIRONMENTAL SERVICES,

AND VICE PRESIDENT FOR FEDERAL AFFAIRS, CINERGY SERVICES, INC.

Introduction

Good afternoon. Thank you for inviting me here today to testify before you on

EPA’s proposed changes to the Clean Air Act’s new source review (‘‘NSR’’) requirements.

My name is Bill Tyndall. Since August 1998, I have been Vice President of Environmental Services for Cinergy Services, Inc., and I recently was named Vice President of Federal Affairs as well. Cinergy Services is the service company for Cinergy

Corp., one of the nation’s leading diversified energy companies. Its operating companies, The Cincinnati Gas & Electric Company and PSI Energy, Inc., serve more than

1.4 million electric customers and 478,000 gas customers in Indiana, Ohio, and Kentucky. Cinergy is active in U.S. power and natural gas markets and maintains a

24-hour-a-day, 7-day-a-week trading operation. The company’s international business unit, Cinergy Global Resources, has assets in power generation, transmission,

and distribution projects in the Czech Republic, Spain, the United Kingdom,

Zambia, Estonia, and the United States. Cinergy’s 1999 revenues were $5.9 billion,

and its total assets are $9.6 billion. Cinergy’s core energy system comprises approximately 11,000 megawatts at 14 baseload stations and seven peaking stations. Its

natural gas distribution system is connected to six interstate pipelines.

Before joining Cinergy, I served as minority counsel to the House Commerce Committee and advised committee Democrats on air quality issues. Before that, I spent

5 years at EPA, serving first in EPA’s Office of General Counsel, where I worked

on new source review and other stationary source issues, and later as a senior policy

advisor in EPA’s Office of Air and Radiation, the office responsible for administering

the NSR program.

Today I am here on behalf of Cinergy, a company with nearly three decades of

experience under EPA’s regulatory treatment of NSR. Thus, I am speaking as someone who has spent nearly 10 years working with EPA’s new source review program

from a variety of perspectives. My testimony also is on behalf of the Edison Electric

Institute, an association of investor-owner electric utilities such as Cinergy. I will

be addressing what I believe to be the serious ramifications of EPA’s attempt to reform the Clean Air Act’s new source review program.

A series of summer heat waves and steadily rising consumer demand have forced

many utilities to the limits of their generating capacity. With the industry’s equip-
101

ment pushed to the breaking point for extended periods, the Nation as a whole faces

a risk of electricity shortfalls that is higher than ever before. As these trends continue, the need to keep electric utilities running, and running reliably, is at its apex.

The availability of power in America depends on the ability of utilities to continue

maintaining their facilities in the manner needed to ensure safe, efficient, and reliable generation on demand. To exacerbate the situation, electric utilities, rural cooperatives, municipal electric systems, and independent power producers are all facing significant obstacles in siting and building needed additional peaking capacity. In the midst of these potential electricity shortfalls, EPA now proposes changes to the Act’s NSR program that could require existing facilities to undergo an expensive and time-consuming permitting process before they undertake any activities intended to maintain safety, availability, and reliability. A close examination of EPA’s

proposal shows not only that it is contrary to Congress’ focus on new sources of pollution, but that it is inconsistent with how the rule has been written and applied

for nearly three decades. Moreover, EPA’s plan to promulgate an unworkable rule

that discourages or delays needed maintenance projects is at odds with maintaining

the reliability of the nation’s power supply.

Background

Electric utilities occupy a unique position in the industrial world. We arguably are the ultimate example of ‘‘just-in-time delivery’’ of a product to our customers. Because it is not feasible to store significant amounts of power, we must generate electricity at the very instant that our customers consume it. This requires constant and

careful maintenance of our generating units, which are comprised of thousands of

individual components working together as an integrated system. In this interdependent environment, the failure of a single component is sufficient in many cases

to cause an entire generating unit to be shut down and require repair.

Furthermore, utilities are operated under extreme conditions of temperature,

pressure, and wear that make such failures particularly likely. As in an automobile,

or any other highly integrated piece of equipment, these various parts wear at different rates, with the result that parts both large and small must be replaced on

a periodic basis in order to keep the unit running properly. In contrast, the failure

to make such repairs results in rapid and predictably declining reliability and unit

availability. At present, Cinergy operates over 60 individual generating units in our

three-State system, and the maintenance required to keep these facilities operating

smoothly has been, and remains, a daunting task.

Note that a failure to maintain generating units properly results not only in decreased performance, but also can cause unsafe conditions for our employees, as well

as our customers. The early history of steam generation was plagued by equipment

failures, with many injuries to plant employees. Since that time, the American Society of Mechanical Engineers (ASME) and other industry authorities have developed

detailed codes that guide utility maintenance and repair activities to ensure that

generating units may be operated safely and reliably for decades. In addition, various State agencies and insurance underwriters regulate boiler operation, maintenance, and repair practices to ensure utilities maintain their equipment properly.

These generating facilities are subject to a host of Clean Air Act provisions that

constrain emissions to levels that protect the public health and welfare. For electric

utilities, this includes, but is not limited to, (1) compliance with SIP-based limitations designed to achieve or maintain the national ambient air quality standards

(‘‘NAAQS’’); (2) restrictions on NOx and SO2 emissions under the Act’s Title IV acid

rain program, including a more stringent phase two of that program which commenced on January 1, 2000; (3) restrictions on ozone, SO2, and particulate matter

under Title I of the Act; and (4) EPA’s Title V operating permit program. In this

manner, Congress has ensured that all industrial facilities both old and new are

subject to extensive and costly pollution control requirements. In addition, State environmental programs impose additional emission limitations that apply to our

plants.

In 1970, and again in 1977, Congress enacted significant amendments to the

Clean Air Act targeted at new sources of pollution. Specifically, Congress amended

the Act to provide that companies that construct new facilities, or make ‘‘major

modifications’’ to existing facilities that result in significantly increased emissions,

must apply an extra layer of pollution control to these units. As EPA has recognized, Congress targeted new construction and the extensive alteration of existing

units because it understood that it is more feasible technically, and less disruptive

economically, for companies to install new control technology at the time these

events occur than it is to retrofit existing units.

Under the terms of the NSR program, new and ‘‘modified’’ units must satisfy ‘‘new

source performance standards,’’ and install controls that represent ‘‘best available
102

control technology’’ or ‘‘lowest achievable emission rate’’ requirements. Such units

also must undergo review for their impact on ambient air quality either under the

‘‘prevention of significant deterioration’’ program (for areas where air quality is

cleaner than the NAAQS require) or under the nonattainment program (for areas

where one or more NAAQS is not being achieved). Thus, a ‘‘major modification’’ to

an old plant can create a ‘‘new’’ source for regulatory purposes and trigger the congressional mandate for the plant to undergo a permitting process that takes 18

months or longer to complete and results in millions of dollars in control equipment

costs. While Congress may have considered this a reasonable process for a ‘‘major

modification,’’ it is clear that such a process and cost cannot be imposed on routine

maintenance and repair activities if the U.S. is to maintain a safe, reliable, and reasonable supply of electric generation to homes and businesses.

EPA’s Historical Treatment of the Modification Rule

Given this history, the question of whether a source has undergone a ‘‘major modification’’ for purposes of NSR is a crucial one for older generating units. Historically,

EPA has interpreted the modification rule in a manner consistent with Congress’

focus on new sources of pollution and its concern about the costs of retrofits. For

example, EPA guidance recognizes that Congress ‘‘did not intend to make every activity at a source subject to new source requirements’’ via the modification rule, and

that EPA ‘‘in no way intends to discourage physical or operational changes that increase efficiency or reliability or lower operational costs, or improve other operational characteristics of the unit.’’ 57 Fed. Reg. 32,327. Similarly, EPA has expressed concern with requirements that would ‘‘unduly hamper the ability of any

company to take advantage of favorable market conditions.’’ 45 Fed. Reg. at 52,704.

For these reasons, EPA has always excluded ‘‘routine maintenance, repair and replacement,’’ as well as increases in production rate or hours of operation within a

facility’s capacity, from the definition of a modification.

EPA’s actual application of the modification rule to utilities also has been consistent with both congressional intent and the agency’s regulatory pronouncements.

Specifically, EPA has allowed utilities to make those repairs that are customarily

undertaken in the industry to maintain the availability and reliability of electric

generating facilities, and to thereby maximize the useful lives of these units, without any suggestion that such repairs were non-routine modifications subject to NSR.

Importantly, EPA adopted this approach while armed with an extensive agency

awareness of utility maintenance practices from onsite inspections, reports filed

with State and Federal regulatory agencies, and countless industry articles.

There is one case where EPA has found that repair and replacement activity

crossed the line between those routine projects that keep a facility operating, and

a non-routine expansion of the facility subject to NSR. In a 1989 administrative decision, EPA ruled that a plant-wide reconstruction project at Wisconsin Electric’s

(‘‘WEPCo’’) Port Washington facility was a non-routine change because it involved

a ‘‘massive’’ and ‘‘unprecedented’’ replacement of major components, some of which

had never been replaced before by WEPCo or other utilities. By pursuing the

WEPCo project as a non-routine modification, after years of allowing less ambitious

repair and replacement projects that extended unit life, EPA confirmed that the majority of utility maintenance projects to extend life qualified as routine maintenance

and did not trigger the modification rule. EPA later confirmed this to Congress,

leading GAO to report later in 1990 that:

According to EPA policy officials, WEPCo’s life extension project is not typical of

the majority of utilities’ life extension projects, and concerns that the agency will

apply the ruling it applied to WEPCo’s project are unfounded. (emphasis supplied)

In keeping with its statements to Congress, EPA has continued to allow utilities

to undertake repair and replacement projects as needed to maximize unit life in the

10 years following the WEPCo decision, without any finding that such projects triggered NSR.

EPA’s Proposal to Revoke the WEPCo Rule

However, in Federal Register notices issued in July 1996 and 1998, EPA has proposed a major revision to the NSR modification rule. I refer you to 61 Fed. Reg.

38,250 and 63 Fed. Reg. 39,857. In these notices, EPA essentially proposes to revoke

parts of a 1992 rule EPA issued to formalize its WEPCo decision (the so-called

‘‘WEPCo Rule’’). EPA would replace this WEPCo Rule with a new interpretation of

the modification standard under which nearly all activities intended to maintain or

restore the reliability or efficiency of a generating unit would trigger NSR.

EPA’s original modification rule is fairly straightforward, and defines a ‘‘modification’’ as a: (1) physical or operational change (2) that results in (3) a significant net

emissions increase. The rules then provide examples of activities that do not con-
103

1 63 Fed Reg. 39,860.

stitute a physical or operational change, including routine repair, replacement and

maintenance, pollution control projects, fuel switches, and so on. See 40 C.F.R.

§ 52.21(b)(2), § 60.14. As I mentioned earlier, this rule historically has resulted in

a regulatory program where utilities are allowed indeed encouraged—to maintain

and operate their plants as they were designed to operate. EPA now seeks to change how each of these criteria is applied to determine whether a modification has occurred. First and most important is EPA’s new approach to what constitutes a ‘‘physical or operational change.’’ As described above,

EPA has always excluded traditional utility maintenance activities, whether performed singly or grouped together, from the definition of a physical or operational

change under the exclusion for ‘‘routine maintenance, repair and replacement.’’ EPA now proposes an interpretation of the ‘‘routine maintenance, repair and replacement’’ exclusion under which all activities that restore deteriorated capacity

and availability must be treated as ‘‘non-routine’’ repairs. This would mean that all

utility maintenance projects would be ‘‘non-routine,’’ since even the simplest utility

maintenance project is intended to restore lost availability and reliability. This

again is in direct conflict with the history discussed earlier. It also is logically inconsistent with the language of EPA’s exclusion for ‘‘routine maintenance, repair and

replacement.’’ If all repairs are non-routine, there can be no such exclusion. EPA

would, in effect, read this exclusion out of the NSR regulations.

Another major change is EPA’s elimination of the causation requirement of the

modification rule, and its removal of the so-called ‘‘demand growth’’ exclusion, which

excludes increases in production rate and hours of operation. EPA created this latter

provision based on its understanding that Congress did not in any way intend for

the modification rule to punish utilities for responding to changes in demand growth

within the design capabilities of their facilities. Thus, under the rule as written, a

physical or operational change cannot be considered a ‘‘modification’’ unless the

change ‘‘results in’’ a significant increase in emissions. In other words, the mere fact

that there is an increase in net annual emissions after a particular change does not

necessarily trigger NSR. If the increase was caused not by the change but by something else for example, by an increase in production rate or hours of operation, occurring in response to an increase in product demand or some similar market

force—a ‘‘modification’’ has not occurred. In this regard, EPA stated in the preamble

to the 1992 WEPCo Rule that it ‘‘declines to create a presumption that every emissions increase that follows a change in efficiency is inextricably linked to the efficiency change.’’ 57 Fed. Reg. at 32,327.

EPA now proposes a regulatory regime under which any non-routine (or otherwise

non-excluded) change that is followed by a significant increase in annual utilization

of the facility would be presumed to be a modification, even if that change does not

affect a facility’s overall capacity to burn fuel (and hence its emission rate). According to EPA, the Agency’s ‘‘experience’’:

. . . . leads to the conclusion that sources generally make non-routine physical or

operational changes which are substantial enough that they might trigger NSR in

order to increase reliability, lower operating costs, or improve operational characteristics of the unit and do so in order that they may improve their market position.

A proximate cause for making such changes may be to respond to increased demand, or to more efficiently compete for share of a market that has flat, or even

decreasing, demand. 1

‘‘For these reasons,’’ the Agency continues, ‘‘EPA now seriously questions whether

market demand should ever be viewed as a significant factor in answering the relevant regulatory question of whether an emissions increase results from a physical

or operational change at an existing source.’’ Indeed, according to EPA, ‘‘in a market

economy, all changes in utilization and, hence, emissions might be characterized as

a response to market demand.’’ Id. In this manner, EPA’s proposal appears to require that any change that is followed by a significant increase in annual utilization

is a ‘‘modification’’ and, therefore, subject to NSR.

EPA’s final change is to redefine how an emissions increase is calculated. EPA

claims that ‘‘[u]nder current regulations,’’ non-routine activity at a unit must be

‘‘deemed to be of such significance that ’normal operations’ are deemed not to have

begun’’ at the facility. In other words, EPA would treat a company that undertakes

a non-routine change at a unit as if the unit had never been operated before and

had no emissions history. This change is significant because the NSR rules provide

that, for a unit that has not begun ‘‘normal operations,’’ post-change emissions must

be calculated based on the assumption that the unit will be operated at full tilt, 24

hours a day, 365 days a year after the change. Under this test, any change will
104

show an increase in emissions, even if the change would not truly result in any new

pollution.

But the Seventh Circuit specifically rejected this view of the emissions increase

test in its review of EPA’s WEPCo determination. See Wisconsin Elec. Power Co.

v. Reilly, 893 F.2d at 917–18. Moreover, EPA rejected this interpretation in its 1992

WEPCo Rule, explaining that the Agency is required to compare actual emissions

before and after a change, unless the unit is brand new or has been entirely rebuilt

by spending 50 percent of the cost of a new facility. See 57 Fed. Reg. at 32,317,

32,323.

When one considers these changes together all repairs are non-routine, all nonroutine repairs are deemed to result in an emissions increase, regardless of whether

they actually did so it becomes clear that EPA plans to subject the entire electric

utility industry to a new level of controls not contemplated by the original NSR program.

Summary

If EPA’s goal is to obtain new source levels of emission reduction from existing

sources even though those sources have already reduced emissions to address the

public health and welfare requirements of the Clean Air Act then let’s address this

directly as a policy issue. The new source review program was never meant to require such sweeping reductions from existing utilities, and is uniquely ill-suited as

a vehicle for obtaining them. In particular, EPA’s interpretation of NSR would require all utilities to delay repair, and possibly shut down their facilities, for 18

months or more every time there is a minor equipment failure in order to go

through the NSR process. There simply isn’t enough capacity in the Nation to allow

for so many units to remain inactive for such extended periods, nor would consumers appreciate the jump in rates that would accompany such a change.

EPA’s proposed revision to NSR is problematic for other reasons as well. EPA’s

proposed NSR approach would force utilities to guess on when to install new pollution controls according to the unpredictable failure of minor pieces of equipment,

rather than choosing a time that minimizes outages and technical difficulties the

very problem Congress sought to avoid in creating NSR. Utilities faced with the

prospect of undergoing NSR every time they replace broken turbine blades or boiler

tubing would be discouraged from making such changes for as long as possible, with

serious ramifications for the reliability of the nation’s power supply and for the safe

operation of the units. Degradation in reliability is counter to the expectations of

State public utility commissions, which can and have financially penalized companies for substandard performance. Finally, for many utilities, EPA’s NSR proposal

also would mean foregoing the adoption of new technologies that could increase the

efficiency of generating units by reducing the amount of coal needed to produce

power. By discouraging such opportunities, EPA would be losing a chance to obtain

significant reductions in pollutants not currently regulated under the Act, in particular, greenhouse gases.

In sum, the utility industry already faces many challenges to its ability to provide

safe, reliable, and affordable power to the American public. EPA’s proposed changes

to the NSR modification rule should not be among them. The ongoing rulemaking

process needs to be conducted in a manner that will truly reform the NSR program,

rather than the piecemeal approach currently being taken by the Agency. It is now

time for EPA to abandon such impractical approaches to NSR in favor of straightforward negotiations with industry, and for Congress to address the important policy issues raised in the current debate. Regardless, EPA’s proposed NSR rule should

not proceed on its current track.

I thank you for the opportunity to present these comments, and would be happy

to respond to any questions.

Æ