Statement of Scott H. Segal

Bracewell & Patterson, L.L.P.

Before the Subcommittee on Superfund, Toxics, Risk and Waste Management

Committee on Environment and Public Works

United States Senate

 

Hearing on the Status of the Enforcement Program of the U.S. EPA

March 12, 2002

 

Senator Boxer and Members of the Subcommittee, thank you for this opportunity to testify regarding the current state of EPA enforcement programs.  My name is Scott Segal, and I am a partner at the law firm of Bracewell & Patterson.  In that capacity, I have represented clients here in Washington on environmental policy matters for thirteen years.  I have worked with a wide variety of federal agencies, and have become familiar with a number of industrial sectors.  I have represented private corporations, trade associations, and non-profit organizations.  In addition, I serve on the adjunct faculty of the University of Maryland (University College) in the area of Science and Technology Management.

 

I represent many groups that have taken an active interest in environmental enforcement matters.  With respect to the current need to clarify the New Source Review program, I specifically represent the Electric Reliability Coordinating Council, a group of six electric utilities.  Further, I serve as outside counsel to the Council of Industrial Boiler Owners, a trade association whose members represent some twenty industrial sectors.  While I have learned much from these clients, the views I express today are my own.

 

1.         Environmental Indicators Show Marked Improvement: the Example of Clean Air.

 

In the United States today, we have much to be proud of when we contemplate the success of environmental programs.  It has often been observed that at the outset of the current federal environmental programs in the early 1970's, our problems were substantial and obvious.  It stands to reason that at that time, and for a period following, our environmental enforcement priorities were also fairly obvious.  In many ways, as milestones of environmental achievement have been reached, our adversarial enforcement model has not caught up.

 

It is clear that substantial environmental progress has been made since the adoption of major control statutes.  Using clean air progress as an example, we can see measurable success.  An analysis of federal government data earlier this year demonstrates astounding reductions.  The analysis tracks air quality gains and energy consumption during the 30‑year period from 1970‑1999. It is derived solely from data produced by the U.S. Environmental Protection Agency (EPA) and the Energy Information Administration (EIA) of the U.S. Department of Energy.

 

The nationwide data show that since 1970:

 

_          Carbon monoxide (CO) levels have dropped 28 percent;


_          Sulfur dioxide (SO2) levels have decreased 39 percent;

_          Volatile organic compound (VOC) levels have declined 42 percent;

_          Particulate matter (PM‑10) levels have fallen 75 percent;

_          Airborne lead levels have declined 98 percent; and

_          Overall energy consumption has increased 41 percent ‑ by sectors, commercial energy consumption grew by 80 percent, residential energy by 34 percent, and industrial energy consumption by 21 percent.[1]

 

Senator Boxer, these gains are evident even in challenging air emission situations, such as your own State of California. As Peter Venturi, a California State Air Resources Board official stated at a recent EPA hearing in Sacramento, "The system is working," noting that smog-forming emissions from businesses in the state have declined by 50% in the past 20 years despite a 40% increase in population and commensurate industry growth.[2]

 

The acid rain reductions, contained in Title IV of the l990 CAAA, are of special importance because they in part serve as a model for the Administration's recent Clear Skies Initiative and for legislation pending before this Committee. Title IV has, by all accounts, been highly successful. Gregg Easterbrook, a senior editor at the New Republic, wrote last summer that the results have been "spectacular. Acid rain levels fell sharply during the 90's, even as coal combustion (its main cause) increased."[3]

 

Notwithstanding these successes, there remain some difficult problems. Ozone levels, while improving, are still in violation of the NAAQS in substantial sections of the country. I think it's important to say here that while acid rain is primarily, though not exclusively, a power plant problem, ozone is primarily a mobile source problem today. Cars, trucks and buses account for twice the NOx produced by power plants, which in turn have no role in VOCs, the other smog precursor.  That mobile sources account for the greater portion of pollutants of concern to human health is clear.  EPA itself has observed that, "in numerous cities across the country, the personal automobile is the single greatest polluter, as emissions from millions of vehicles on the road add up. Driving a private car is probably a typical citizen's most 'polluting' daily activity."[4]

Much has been written recently about the effects of small diameter particulate matter, or PM.  Thanks to a combination of the TSP and PMl0 NAAQS, the ozone standard and the acid rain program, the United States has engineered a massive reduction of PMl0, which is now largely in attainment (achieving a 15% reduction from 1990 to 1999 and a 80% reduction from 1970). EPA has pending a NAAQS to control PM2.5 which could, if implemented, call for further reductions of power plant emissions, along with other pollutants. In the meantime, existing EPA control programs are producing continuing reductions of what EPA describes as the "gaseous precursors of fine particles (e.g., SO2, NOx and VOC), which are all components of the complex mixture of air pollution that has most generally been associated with mortality and morbidity effects" (PM2.5 emissions declined 17% from 1990-1999).  In addition, it is far from clear that PM levels should be viewed as a traditional enforcement issue; the President's own proposal for a Clear Skies Initiative is another, undoubtedly more efficient mechanism to incentivize and engineer further reductions in PM.  And recent data has demonstrated that among the most dangerous forms of PM are those arising from automobile exhaust B a source controlled by the federal reformulated gasoline program, a program enforced with a minimum of traditional adversarial enforcement actions.

 

2.         Changing Environmental Enforcement to Reflect New Realities.

 

In some respects, we are a victim of our own success.  As environmental indicators are trending in a positive fashion, the decisions we make as a society become more difficult in the area of allocation of resources.  Environmental protection remains just as important, but the tools we use must become more refined.  Unfortunately, while many program officers understand the need for changing priorities, enforcement officers often view the world in a binary fashion with little room for subtlety. 


There seems to be a bipartisan consensus that such an approach makes little sense, and can even produce perverse results.  Then-Vice President Al Gore, in his September 1994 report to President Clinton on the progress of governmental reinvention activities, observed that, "EPA Administrator Carol M. Browner, for instance, is reaching out to all parties with potential roles to play. Environmental protection, she says, can no longer succeed as an adversarial process, with the polluter on one side of the table and the offended party on the other. Now, all parties must sit and work together."[5]  Two years later, Vice President Gore revealed the successes that could be achieved when pilot projects were adopted B sometimes over the objections of enforcement officers B such as Project XL and the Common Sense Initiative at EPA.  He stated, "EPA has found that when they let companies volunteer to cut pollution without the government dictating how they had to do it, thousands of companies jumped at the chance."[6]

 

What Vice President Gore and Administrator Browner recognized from their efforts at governmental reform is what is evident today: as the nature of environmental challenges has changed, so too must antiquated notions of a purely adversarial approach to enforcement.

 

Two thoughtful legal observers have articulated a rubric for judging effective environmental enforcement.  To be effective, an enforcement regime must:

_          be clear in what it mandates and prohibits;

_          be predictable in how it punishes violations of the regulations, and rely where possible on cooperative, problem-solving approaches; and,

_          seek environmental improvement, not numerical enforcement targets.[7]

By the standards of this approach, it would appear that the current approach to environmental enforcement is less than optimal.  One the first measure B clarity B the New Source Review program is an example presently of what NOT to do.  But it is hardly alone in a lack of clarity.  In fact, one widely-quoted study has it that fewer than one third of the responding attorneys felt that it was even possible to comply fully with federal environmental laws given their current lack of clarity.[8]  Unfortunately, the mechanism used to address enforcement clarity often is part of the problem: when EPA issues enforcement guidance documents that have the effect of creating entirely new obligations without notice and comment rulemaking, obligations become all the more confusing and less respectful of proper process.[9]

The second observation, the need for predictability, is also missing in many of today's enforcement activities.  Again, the NSR program is an excellent example of the problems faced by the regulated community.  As we further discuss in the White Paper attached to this Statement as Appendix One, EPA's NSR rules, which for thirty years have been consistently applied only to new greenfield sources or major modifications of existing sources, are now being reinterpreted without any rulemaking change and applied to routine repair, replacement and maintenance activities at all existing sources, causing major disruption in routine maintenance schedules, curtailing power output, and dismembering whole Titles of the Clean Air Act.

 

The rationale for the radical shift in interpretation is in the allegation that utilities are by illicit maintenance keeping afloat old plants that were "grandfathered" from any CAA controls and that are now threatening the nation's health. But the 1990 CAA Amendments mandated sweeping reductions for all power plants regardless of age through the use of highly efficient market incentives. The 1990 Act thus established a flexible market-based system that is working very efficiently to drive down pollution through 2010 and beyond, but that is now being repealed by administrative fiat and replaced by an outmoded, inefficient and counterproductive command and control regime. 

 

And the clear truth is that many of the targets of the current NSR enforcement initiative are functionally related to routine maintenance, repair and replacement.  They cannot usefully be characterized as major modifications or boiler or powerplant expansions.  Appendix Two delves into the exact nature of the activities at issue here.

 

The last component of effective enforcement B a desire to embrace outcomes over mere numbers of cases B is again often missing in today's approach to enforcement.  Of course, current enforcement efforts are not without their traditional numerical successes.  Indeed, EPA released data on its enforcement and compliance assurance results earlier this year, which included "record-setting amounts of money violators have committed to environmental cleanups and restoration, and for projects to protect the environment and human health beyond injunctive relief, and to record penalty assessments."[10] 

 

Despite this numerical success, Administrator Whitman has recognized that such numbers are not the sole relevant benchmark .  "With our state and local partners, we set a high priority on areas that posed serious threats to health and the environment," said EPA Administrator Christie Whitman. "The Administration is determined to actively pursue those who fail to comply with the law while working closely with the regulated community to find workable and flexible solutions."[11]  Clearly then, there is growing recognition that it is important to prioritize enforcement; to target areas of greater environmental reduction; and to work cooperatively towards solutions.

 

Perhaps it is Administrator Whitman's experience as a Governor that has led her to this conclusion.  We should remind ourselves that the number of federal enforcement actions are not the sole indicators of success.  In fact, two years ago, the U.S. Congress commissioned the Environmental Commission of the States to examine relevant differences and interrelationships between federal and state enforcement actions.  ECOS reported that in one year alone, States passed over 700 environmental statutes for which there were no federal counterparts.  However, federal statistics collected by EPA do not count enforcement efforts undertaken by the States in reference to these actions.[12]    Indeed, of the universe of all enforcement actions undertaken by both the States and EPA, States alone conducted about 90 percent.[13]  However, the great majority of these actions are undertaken in a spirit of cooperation and compliance assurance.  ECOS concluded:

 

"Many State environmental leaders do not believe that their primary goal is just to conduct enforcement actions.  It is more important to assure compliance, and more important still to improve environmental quality and public health.  For this reason, States have been leaders in developing 'compliance assistance' programs."[14]

 

But, in any event, it is curious and misplaced criticism to look at elements such as numbers of cases and workyears of budget allocation as reflective of actual realities.  If it is to succeed in moving the needle towards additional compliance, enforcement programs must be less adversarial and of greater real assistance.  As one State regulator put it, "the true measure of successful enforcement is in quantifiable improvement in our environment. Improved natural resources, not fines, must be the primary objective of any effective environmental policy."  She concluded: "Allowing states to establish, develop, and implement environmental improvement policies is critical to their autonomy and the health of the environment. Heavy fines simply encourage litigation and slow environmental progress."[15]

 

3.         The Price of Failure: the Case of NSR Clarification.

 

EPA's reinterpretation is not only flawed as a matter of law, but it also undermines our energy supply, environmental protection and workplace safety. Because NSR is a costly and time-consuming process, EPA's current position discourages utilities from undertaking needed maintenance projects. This makes plants more reliant on deteriorating components, resulting in less efficient, less reliable and higher emitting power generation. For example, the efficiency of currently available steam boiler equipment deceases over time as plant components deteriorate. Boiler tubes, in particular, are subject to very harsh temperature, pressure, and chemical conditions, and leaks result. Short-term fixes include patching tubes where there are leaks, but eventually whole sections begin to wear out and must be replaced if the plant is to continue to operate. Yet EPA's reinterpretation of NSR could have such a routine and necessary activity declared non-routine.

 

There are 300,000 megawatts of coal-fired generating capacity which is 55% of all electricity generated in the United States. Approximately 1,200 coal-fired generating units are in service. These generating units involve two distinct sets of operations: (1) a steam cycle (e.g., the boiler and related equipment), and (2) the turbine cycle (where the electricity is generated). In the past few years, there have been some very exciting innovations in the turbine technology area. For example, just one type of efficiency improvement project, the so-called Dense-Pack which enhances the efficiency of turbine blades, can result in a very significant improvement in the efficiency with which steam is turned into electricity.

 

A more efficient turbine results in more electricity output from the same steam input, with no greater fuel use. For example if one assumes that most generating units could improve efficiency by between 2% and 4% (a very conservative estimate, based upon the actual operating experience of several units which have installed the Dense-Pack technology), this would mean an additional output of 6,000-12,000 megawatts of power in the near term, with significant decreases in emissions per unit of fuel burned. This increase in available installed capacity is the equivalent of building 20-40 new plants of 300 megawatts each with no new emissions.  We should recall that the very definition of pollution is inefficiency; getting more electrons out of less coal is the best way to prevent pollution.

 

Last, we should be clear that many of our colleagues in organized labor support the notion that the NSR program should be clarified in order to allow for sufficient routine maintenance activities.  The greater the incentive for maintenance, the safer our work environment will be.  Attached for the Subcommittee's review as Appendix Three is a statement offered by the International Brotherhood of Boilermakers at EPA's regional conference on NSR held last summer.

APPENDIX ONE: ELECTRIC RELIABILITY COORDINATING COUNCIL

WHITE PAPER ON CLARIFICATION OF NEW SOURCE REVIEW

 

SUMMARY

EPA's NSR ("New Source Review") rules, which for thirty years have been consistently applied only to new greenfield sources or major modifications of existing sources, are now being reinterpreted without any rulemaking change and applied to routine repair, replacement and maintenance activities at all existing sources, causing major disruption in routine maintenance schedules, curtailing power output, and dismembering whole Titles of the Clean Air Act. The rationale for the radical shift in interpretation is in the allegation that utilities are by illicit maintenance keeping afloat old plants that were "grandfathered" from any CAA controls and that are now threatening the nation's health. But the 1990 CAA Amendments mandated sweeping reductions for all power plants regardless of age through the use of highly efficient market incentives. The 1990 Act thus established a flexible market-based system that is working very efficiently to drive down pollution through 2010 and beyond, but that is now being repealed by administrative fiat and replaced by an outmoded, inefficient and counterproductive command and control regime.

I. How did we get here?

·A The CAA, which has produced dramatic reductions in air pollution over the last three decades despite explosive economic growth, operates through two approaches. The first approach develops national health and environmental standards for the states to apply to the existing sources in their jurisdictions. DOE reports that the utility industry alone has spent more than $30 billion to achieve compliance with these health standards.

·A The second approach applies the best current technology to new sources and major modifications of old sources that increase pollution levels where inclusion of such technology can be integrated in an efficient manner without highly disruptive retrofitting. The purpose is to prevent new pollution by new plants, both to preserve air quality in areas that attain health standards, and to avoid complicating ongoing plans to clean up existing plant and equipment in areas that do not.

·A Because of delays and regulatory difficulties primarily associated with ozone attainment and a need to address acid rain not previously regulated, the Congress enacted the 1990 CAA Amendments ("1990 CAAA") to impose a sweeping array of new pollution reductions on power plants (and other pollution sources as well). These new programs included the acid rain program of Title IV, which mandates a 50% reduction in SO2 by 2010, and the interstate transport provisions of Title I, which are now being implemented to impose additional NOx controls in Midwestern power plants that may themselves be located in attainment areas, but that send pollution through tall smoke stacks to the neighboring states.

·A These new programs adopt a different -- and highly successful -- approach that assigns and limits the absolute number of tons a plant can emit, leaving to the plant the decision as to how to reduce its tons, rather than assign a particular technology to the plant which it must build. Because the preexisting NSR program is technology-based, rather than ton-based, EPA issued a rulemaking in 1992 to reconcile the old with the new, as described more fully below. It is this 1990 CAAA and 1992 rulemaking which EPA is now blatantly violating -- by, for example, forcing utilities to accelerate reductions much faster than those mandated by Title IV of the 1990 CAAA.

·A As indicated above, NSR was intended primarily to apply to new sources and can also apply to existing plants only when a large industrial source of air emissions, a refinery or a power plant makes a non-routine physical or operational change that results in or causes an emissions increase.

·A Over the last thirty years, EPA's regulations and practice have excluded from NSR all "routine maintenance, repair and replacement" activities undertaken by power plants and other industries. Additionally, EPA surveyed utility maintenance projects, including "life extension projects," in the early 1990s and concluded that those did not trigger NSR. EPA also has published guidance in the Federal Register defining what was routine by reference to the standard practices of the relevant source category, in this case the utility industry. Likewise, EPA's regulations specifically exclude any increases in emissions associated with operating a facility more hours, unless such an increase is prohibited by a federally enforceable permit condition.

·A EPA's practices interpreting the NSR rule were explicitly described to Congress by then-EPA Administrator Reilly and other Agency officials when Congress was considering the Clean Air Act Amendments of 1990. One of the reasons Congress adopted the Acid Rain provisions of Title IV to reduce SO2 by 50% (10 million tons) was because utility units typically operate for 65 years or longer without major modification and the NSR program would not obtain equivalent reductions. To help facilitate cost-effective compliance by the utility industry with both the ton-based 1990 CAAA and the pre-existing technology-based NSR program, EPA, after an extensive notice and comment process in 1992, promulgated a rule which explicitly laid out all of the NSR procedures applicable to the utility industry and confirmed that "pollution control" projects would not trigger NSR.

·A In 1996, EPA initiated a rulemaking to revise the 1992 NSR rule, but never finished it. Instead, in 1999, EPA commenced a major enforcement initiative against virtually every coal-fired utility plant in the country for repair and replacement activities undertaken over the past 20 years. Under EPA's reinterpretation, virtually every maintenance, repair or replacement project undertaken by any utility plant could be considered non-routine. Any project that increases availability or efficiency or corrects problems causing forced shutdown of plants potentially triggers NSR. EPA abandoned its simple test for determining when maintenance practices are routine -- common industry practices -- and now applies a multi-factor (more than 20 different factors) weighing and balance test that only it can perform with any sort of regulatory certainty. Amazingly, even installation of pollution control equipment by utilities may now be viewed as an NSR-triggering event.

·A Whatever policy merits EPA believes justify its new position on NSR applicability, EPA's efforts to achieve this through enforcement actions against utilities for projects undertaken decades ago is inconsistent with current law. If EPA believes this NSR reinterpretation is correct, it should only apply it after notice and comment rulemaking or ask Congress for new legislation to revise the 1990 CAAA.

·A In justifying its enforcement actions, EPA claims that its sole goal is to avoid emission increases by power plants operating more hours than in the past. This point is so important that a more detailed explanation is in order. Under the Clean Air Act provisions, every power plant in the country is allowed to emit a certain quantity of various regulated pollutants, of which NOx and SOx are the two key ones. Each utility plant has a legally mandated emission rate -- a maximum amount of pollution that can be emitted per hour, per day, per month, or even annually, depending upon air quality and other consideration. But, any time a plant slows down because of a maintenance problem, it will necessarily be able, once repaired, to operate more hours -- and emit more -- than it did during the problem period -- even the emissions are well within the limits spelled out in the State SIP and the federal reductions required by Title IV. These various limits are spelled out in permits held by utility plants or in state implementation plans, and they reflect EPA-prescribed public health-driven ambient standards. These limits cannot be breached by power plants under any circumstances, and there is no claim that any of the plants subject to the EPA enforcement did exceed the permitted limit of emissions. However, every unit must be prepared to operate more hours within their tonnage limits in order to meet customer demand.

·A EPA's definition of an emission increase is artificial and arbitrary. Power plants operate under extremely harsh conditions; every several years, as the plant equipment deteriorates, the plant's efficiency, availability and reliability go down. Eventually, the plant operator performs a set of routine maintenance procedures to restore and maintain the plant's efficiency, availability and reliability. To emphasize, throughout all of these changes, the plant never increases or exceeds its legally binding and public health-driven emission limits. EPA, however, compares a plant's actual emissions at the time it was operating in the recent past before a maintenance procedure with its future potential emissions following that procedure, assuming that the plant will, as a result of the project, operate every hour of every day in the year at maximum output. In other words, EPA's methods always predicts an emission increase even though none may occur, and even though the plant may not under any circumstances exceed the CAAA's mandated reductions.

II. EPA's Reinterpretation Discourages Needed Maintenance Procedures and Reduces Generating Capacity

·A EPA's reinterpretation is not only flawed as a matter of law, but it also undermines our energy supply. Because NSR is a costly and time-consuming process, EPA's current position discourages utilities from undertaking needed maintenance projects. This makes plants more reliant on deteriorating components, resulting in less efficient, less reliable and higher emitting power generation. For example, the efficiency of currently available steam boiler equipment deceases over time as plant components deteriorate. Boiler tubes, in particular, are subject to very harsh temperature, pressure, and chemical conditions, and leaks result. Short-term fixes include patching tubes where there are leaks, but eventually whole sections begin to wear out and must be replaced if the plant is to continue to operate. Yet EPA's reinterpretation of NSR could have such a routine and necessary activity declared non-routine.

·A A plant operator typically will accept some level of deterioration in efficiency for a short period of time but must eventually undertake the repair and maintenance necessary to regain lost efficiency and to maintain unit availability. The timing of these projects depends in part on the demands being placed on the power plant to operate to meet energy supply needs. Unit unavailability can seriously impair a utility's ability to meet customer demand and nearly always results in running less efficient units. Operating inefficient units increase the amount of pollution emitted. Under the EPA Office of Enforcement and Compliance Assurance's new interpretation of the NSR rules, it is these projects, designed to maintain efficiency and availability, that are no longer regarded as "routine." EPA then assumes the unit will operate more hours than before the project and further assumes that the project, rather than customer demand, weather, or other unit outages, causes this increase. Once EPA thus determines that NSR will be triggered, the unit cannot even begin to proceed with the project without either going through the lengthy NSR permitting process, which takes a year or more, or without "capping" operations at historical levels. Thus, the unit must either wait or derate. Either alternative can have significant adverse consequences for the reliability of the country's electric supply. Waiting can idle a unit during peak demand for 12-24 months, more if intervenors challenge the permitting. Derating effectively confiscates capacity, even when the unit is permitted to operate at maximum output year-round.

·A Over the next 3-5 years, thousands of megawatts of existing generating capacity will be lost if companies are not able to undertake these routine maintenance and repair projects, or if companies must accept caps on utilization to avoid lengthy NSR. In the longer term, EPA's new position would involve the loss of an even greater number of megawatts. The result of EPA's reinterpretation will be the decrease in available installed power plant capacity at a time when we already have a supply shortage -- something this nation, and the West in particular, can ill afford.

III. EPA's Reinterpretation Discourages Efficiency Improvements

·A There are 300,000 megawatts of coal-fired generating capacity which is 55% of all electricity generated in the United States. Approximately 1,200 coal-fired generating units are in service. These generating units involve two distinct sets of operations: (1) a steam cycle (e.g., the boiler and related equipment), and (2) the turbine cycle (where the electricity is generated). In the past few years, there have been some very exciting innovations in the turbine technology area. For example, just one type of efficiency improvement project, the so-called Dense-Pack which enhances the efficiency of turbine blades, can result in a very significant improvement in the efficiency with which steam is turned into electricity.

·A A more efficient turbine results in more electricity output from the same steam input, with no greater fuel use. For example if one assumes that most generating units could improve efficiency by between 2% and 4% (a very conservative estimate, based upon the actual operating experience of several units which have installed the Dense-Pack technology), this would mean an additional output of 6,000-12,000 megawatts of power in the near term, with significant decreases in emissions per unit of fuel burned. This increase in available installed capacity is the equivalent of building 20-40 new plants of 300 megawatts each with no new emissions.

·A As an example, this type of efficiency improvement, if installed by the approximately 1,000 utility units (out of some 1,200 existing coal-fired utility plants) that can be most easily retrofitted with Dense-Pack technology, would reduce criteria pollutants that NSR was meant to address (NOx and SOx) substantially.


·A However, under EPA's reinterpretation of its NSR rules, the installation of even this type of beneficial technology requires an elaborate, expensive and time-consuming permitting process, which results in the imposition of additional costly control technology requirements on existing plants, and therefore discourages the installation of new and more efficient technologies.

IV. Conclusion

Overall, the effect of EPA's recent position is to block routine maintenance, repair and efficiency improvement projects that could immediately expand generating capability without increasing fuel burning and will decrease by a significant percentage the total available installed capacity through caps on operations. Stated differently, EPA's reinterpretation of NSR is tantamount to shutting down dozens of utility units every year at a time when electricity supply is already so short as to be unreliable in many areas.

 

APPENDIX TWO: THE TRUE NATURE OF REPAIR AND REPLACEMENT

 

This document provides more detail on major repair and replacement projects that must be undertaken at utility generating stations, in order to keep those facilities operational. The utility industry generally plans for a major outage at each generating unit at a regular interval, which has changed over time. During the 1970s and earlier, annual outages were the norm, and each unit would be removed from service for several weeks at a time to undertake a comprehensive boiler inspection and repair outage. Currently such outages occur on schedules ranging from 18 months to three years, and they therefore last longer. Turbine overhauls are planned on longer intervals, approximately every five to eight years, and generally last even longer due to the nature of the work required. In the years when turbine overhauls are scheduled, more extensive boiler work can also be scheduled to occur.

During each major outage, work will be conducted on one or more of the projects discussed below. For each, this document provides examples of the types of major repair and replacement projects that are conducted in the industry, a discussion of the consequences of not undertaking the project, and information on typical project costs. There are many smaller repair and replacement projects that take place in each of these projects that are not discussed here, given our focus on major repair and replacement projects that are common in the utility industry. These smaller projects will typically be performed during forced outages as time permits, during shorter scheduled outages on weekends, or during the planned outages scheduled for the more significant projects discussed in this paper. These smaller projects add to the overall capital costs incurred for repair and replacement projects at an individual unit over time.

1. Boiler Tube Assemblies

a. Project Description

Boiler tube assemblies include superheaters, reheaters, economizers and boiler walls and floors. These tube assemblies may also be known as division walls, wing walls, waterwalls or steam generation tubes. Boiler walls consist of rows of tubes mounted along (and essentially forming) the interior walls of a boiler. Superheaters, economizers and reheaters are typically bundles of tubes which hang from the ceiling or sides of a furnace into the hot combustion gasses. The heat in the furnace is thereby transferred to the water or steam passing within each tube.

Boiler tubes function in extreme conditions. These tubes are not exotic alloys and therefore are expected to experience wear and periodic failure. Corrosion and erosion, in addition to temperature and pressure-related stresses, wear or weaken the tubes. When boiler tubes leak, those tubes, and typically surrounding tubes, must be repaired or replaced. If deterioration is limited to a few tubes, repairs can be effected by cutting out the leaking section of tubes and welding in place a new tube section. More extensive deterioration, including deterioration anticipated based on the results of nondestructive analysis of the boiler walls, requires replacing an entire tube assembly. When materials that can better withstand the destructive environment of the boiler and can reduce the susceptibility of the tubes to wear are available, it is common practice to use those materials to the extent it is cost-effective. Similarly, improvements in tube arrangement in the boiler are common as the individual air/gas flow patterns of a boiler are established. Finally, the headers that collect the water or steam and feed it into the tube assemblies and the structural components associated with the tube assemblies are also subject to deterioration due to the same failure mechanisms.

b. Consequences of Forgoing Project

Once a tube develops a leak, the unit can only operate for a few hours to a couple of days, depending on where the leak is in the boiler and whether the leak endangers the integrity of other tubes or components. After that short time, the unit must be shut down in order to repair or to replace the leaking tubes, because tube repairs must be conducted off-line after the boiler has cooled. Replacement of an entire tube assembly becomes necessary as anticipated or projected failures increase. Forgoing replacement severely jeopardizes the reliability of the unit by requiring that it be repeatedly shut down in response to tube leaks. Ultimately, tube leaks can require that the plant be shut down. Foregoing replacement also jeopardizes the integrity of other tubes and components, creating a risk of massive boiler failure that would endanger employees and prevent the boiler from being operated to supply electricity.

c. Other Information

Repair of leaking sections and wholesale replacement of tube assemblies are common projects. Replacing tube assemblies can cost up to $40/kw on a large coal-fired boiler, and even more on a smaller boiler. A census of repair and replacement practices at coal-fired utility boilers shows that entire tube assemblies have been replaced by almost every boiler in the industry, with some replacements occurring as early as 5 years after commercial operation.

2. Air Heaters

a. Project Description

Electric steam generating plants use air heaters to pre-heat the combustion air to improve the combustion process and the overall efficiency of the unit. Generally, air heaters receive hot flue gas passing through the economizer and cooler combustion air from the forced draft fan. Air heaters transfer the heat from the hot flue gas to the cooler combustion air. Regenerative air heaters perform this heat transfer through the use of air heater tubes or baskets (which are comprised of rows of metal plates with corrugations and undulations designed to facilitate flow paths and heat transfer).

Condensation and the presence of ash can corrode, erode or plug air heater baskets or tubes. While washing and sootblowing (see project family #10) may address short-term plugging issues, corrosion of the metal surfaces and the resulting losses in heat transfer require the replacement of air heater baskets or tubes at a frequency ranging from 5 to 15 years.

Air heaters also suffer from the erosive effects of ash and other materials, especially if gaps in air heater seals are worn or weakened. This may lead to the replacement not only of air heater tubes and basket layers, but also of structural elements, seals and gaskets. When air heater tubes or basket layers and associated equipment are replaced, it is standard practice to consider improvements in plate configuration, in materials or in the corrugation or undulation of the plates, or in the arrangement of tubes to account for the specific requirements of a particular boiler.

b. Consequences of Forgoing Project

If air heater tubes, baskets and other air heater equipment are not replaced when they deteriorate, the plant loses efficiency because the incoming combustion air is not warmed sufficiently. As the air heater becomes further plugged or corroded, the unit is further limited in its capability to generate electricity because less air and exhaust gases can pass through the air heater. As the efficiency of the unit decreases, the amount of emissions per unit of electricity generated increases. If most or all of the air heater is plugged, no air can flow through, and the unit cannot operate. Ultimately, if not replaced, pieces of the air heater that have been eaten away could be sucked into the boiler, causing damage and forcing the boiler to shut down.

c. Other Information

The replacement of air heater basket layers, tubes and the seals around the air heater are common projects. Replacing tubes and basket layers can cost up to $6/kw on a large coal-fired boiler. As with other components, costs in $/kw tend to be higher on smaller boilers. A census of repair and replacement practices at coal-fired utility boilers shows air heater baskets/tubes have been replaced by over 80% of the units surveyed.

3. Fans

a. Project Description

A fan consists of a bladed rotor, or impeller and a housing to collect and direct air or gas. Many boilers operate with both forced and induced draft fans - also known as "balanced draft." These boilers use the forced draft fan to push air through the combustion air supply system into the furnace. The induced draft fan is on the other end of the furnace, and sucks combustion gases through. In this way, the two fans maintain the pressure of the boiler in "balance" or at atmospheric pressure or slightly negative pressure.

Other boilers were designed to operate at positive pressure, using only a forced draft fan and no induced draft fan. However, this design forces heat and ash through the joints of the boiler and ducting system, resulting in employee health, safety and other concerns stemming from the dusty environment. These include increased equipment maintenance needs due to the high dust levels. Accordingly, many companies with positive pressure boilers have replaced the forced draft fan system with a balanced draft fan system to correct these maintenance and employee safety problems.

Another kind of fan necessary to pulverized coal-fired boiler operation is a primary air fan. Primary air fans supply coal pulverizers with the air needed to dry the coal and transport it to the boiler. Primary air fans may be located before the air heater (cold primary air system) or downstream of the air heater (hot primary air system).

In some cases, gas recirculation fans are used for controlling steam temperature, furnace heat absorption and slagging of heating surfaces. They are generally located at the economizer outlet to extract gas and re-inject it into the furnace.

Fans rotate at high speeds, and experience erosion and cyclic fatigue. They therefore need to be replaced periodically. Fans (e.g., induced draft fans) may also be subject to high temperatures, erosive ash, and corrosive gases.

b. Consequences of Forgoing Project

Poor fan operation translates immediately and directly to reduced boiler load and less production of electricity. If a large fan fails, it can shut down the unit. Failure of small fans in a multiple system will result in reduced boiler load. Fan systems that fail or that cause maintenance and employee safety problems must be replaced for the boiler to continue to operate.

c. Other Information

Common replacement projects include balancing and blade replacements, and wheel, motor and rotor replacement. Fan replacement projects can cost up to $20/kw. Replacement of a forced draft fan system with a balanced draft fan system can cost up to $70/kw. A census of repair and replacement practices at coal-fired utility boilers shows that fans have been substantially replaced at more than 70% of the units in the industry.

4. Mills/Feeders

a. Project Description

Feeders deliver raw coal from the coal bunker to the pulverizer (also called "mills"). Coal crushers and conditioners are used in some cases to prepare the coal for the mills. Coal pulverizers then grind coal to a fine powder, suitable for efficient combustion in the furnace.

Various types of feeders are used in the industry, including gravimetric feeders, volumetric feeders, and bucket-type feeders. Replacing volumetric feeders with technologically superior gravimetric feeders is common in the industry, in order to improve the consistent measurement of coal added to the mills.

Pulverizers are manufactured in several designs. Some pulverizers use metal balls that roll around a metal track and crush coal. Other pulverizers use rollers to crush the coal. Both designs contain motors and gear boxes to drive the grinding mechanism. Pressurized air created by seals and air fans keeps the fine coal dust out of the motor and gears. Nevertheless, fine coal dust is present and causes continual wear and eventual failure of mills.

The coal is sorted within the pulverizer and delivered to the burners by the primary air fan. In some designs, exhauster fans then deliver the pulverized coal through pipes to the burners for introduction into the furnace. The "classifier," located at the top of the pulverizer, contains openings through which fine coal passes on its way to the burners; coarser particles hit the classifier and fall back to the grinding mechanism.

The major causes of wear and deterioration in pulverizer systems are abrasion due to exposure to hard minerals such as quartz and pyrite found in raw coal, and erosion due to the stream of solids that strikes pulverizer surfaces. Given the constant wear experienced in a pulverizer, repair and replacement of pulverizers and related equipment is essential to continued operation of the boiler.

The components that experience direct, constant wear and that require periodic replacement include rollers, tables, and balls; classifiers; bearings in rollers and the shaft; and seals and motors. Within the feeder system, belts, flow control devices, and associated piping must periodically be repaired or replaced. Eventually, abrasion and erosion of the pulverizer may become so severe that the pulverizer or mill internals must be replaced.

b. Consequences of Forgoing Project

The obvious consequence of mill/feeder failure is the reduction of the capability of the mill to deliver coal to the boiler, and hence of the unit to generate electricity. As less fuel is available to the boiler, less steam can be produced. More subtly, improper mill performance leads to combustion problems that not only damage other equipment but that increase emissions. For example, coal which remains too coarse will not combust completely, and will cause a loss of efficiency and an increase in particulate emissions. Some equipment in a mill or feeder cannot be repaired effectively more than a few times because the mill parts then will not work together properly. Replacement of the mill is then necessary.

c. Other Information

Replacing wear parts in the interior of the mill can cost up to $2/kw, and replacement of a mill can cost up to $5/kw. A census of repair and replacement practices at coal-fired utility boilers shows that pulverizer mills have been replaced or substantially replaced (e.g., the entire grinding zone) at more than 50% of the units in the industry.

5. Turbines and Generators

a. Project Description

In the steam turbine at a modern power plant, superheated steam from the boiler is exhausted over turbine blades (these look like the fanjet blades in a jet engine). Because the steam is very hot (about 1000E°F), enters at very high pressure (2400 to 3600 pounds per square inch), and contains impurities, turbine blades experience substantial wear and tear. For example, there are impurities in the steam - like little pieces of sand - hit the turbine blades at extremely high velocities and damage the blades by pitting them. When turbines are inspected, some blades or rows of blades (e.g., the "high pressure" or HP section) may need to be replaced.

When blades are replaced, the manufacturer typically offers a new, more efficient design or better alloys as the result of R&D or new, more durable materials. Indeed, the older, less efficient design may no longer be available. Use of more efficient turbine blades also allows the turbine to use a smaller amount of steam to produce the same amount of electricity, thereby decreasing emissions per megawatt of power output. Other turbine components, including nozzles, diaphragms and rotors, are also commonly replaced when they deteriorate or fail.

Generator rotors and stators are also subject to failure. The generator rotor turns (is rotated) inside the stator. Both the stator and the rotor are typically made of steel and have "slots" that run their length. Both the rotor and the stator have windings, that is, wires that fit into the slots. A direct current is applied to the rotor winding, which turns this large piece of steel into an electromagnet. The stator winding is a conductor (typically copper). When an electromagnet is turned relative to a conductor, it produces a current in the conductor. The current produced in the stator winding is the electricity made by the generator, which is then sent to the transmission grid.

The windings are surrounded by insulation. This insulation can wear out due to heat, electrical and/or vibratory stress (e.g., rubbing on adjacent insulation.) Also, insulation can deteriorate due to exposure to contaminants such as moisture and oil, particularly from the cooling mechanism. If the wear is extensive, the entire winding itself must be replaced.

Finally, the steam turbine shell may develop defects due to stresses created by high temperatures and high pressures. If the turbine shell develops defects, it is commonly repaired or replaced at the same time the turbine blades are replaced.

b. Consequences of Forgoing Project

Replacement of damaged turbine blades is a necessity both from a reliability and from a safety standpoint. Damaged, rotating turbine blades can break off and fly through the turbine casing at extremely high velocity, creating the risk of serious injury or death and extensive damage to the power plant. To avert this catastrophe, turbine blades are inspected and replaced if wear and tear indicates they may fail.

Besides the employee safety issue, a broken blade can damage other portions of the generating unit, resulting in prolonged unit shut-down. Even prior to failure, deteriorated blades reduce the efficiency with which steam is turned into electricity, thereby reducing the electric output of a generating station and increasing the amount of emissions per unit of electricity produced.

Worn windings and insulation in the generator stator and rotor decreases the efficiency of the generator to convert mechanical energy to electrical power. This translates to increased fuel consumption and increased emissions per unit of electricity and decreases the capacity of the unit to produce electricity. Failed insulation also presents a fire hazard, and can result in faults that prevent the generator from operating at all.

c. Other Information

Common projects include the replacement of turbine blade rows or sections and turbine rotors. Moreover, a generator rotor or stator is rewound periodically in the life of a unit. Turbine blade and turbine rotor replacement projects can cost up to $20/kw, while shell replacements can cost up to $60/kw. A census of repair and replacement practices at coal-fired utility boilers shows that more than 90% of the units in the industry have replaced turbine blades or rotors.

6. Condensers

a. Project Description

Once steam has passed through the turbine, it is condensed back to water, which is cleaned, pumped again to high pressure and returned to the boiler. The condenser provides the heat transfer necessary to convert the spent steam into water.

The condenser consists of a large chamber containing bundles of long, thin tubes. The tubes contain flowing water (typically river water or some other source of cooling water). Low temperature steam exiting the turbine at pressure approaching a perfect vacuum is directed into the chamber across the outside of the bundles of tubes, which are arranged perpendicular to the steam path. As the steam flows over the outside of the tubes, the heat from the steam is transferred to the cooling water inside the tubes. As enough heat is removed from the steam, the steam condenses to water.

The combination of steam constantly passing across the outside of the condenser tubes and water (filtered, but typically untreated) passing through the inside of the tubes leads to corrosion and erosion. Also, the interior of the tubes is subject to plugging and biological fouling. Despite constant efforts to clean the tubes, tubes eventually become partially or entirely plugged and no longer provide heat transfer. Also, if a condenser tube leaks, untreated river water will enter the steam path due to the vacuum on the steam side and will contaminate the high purity steam.

Short-term repairs include intentionally plugging a leaking tube. When numerous tubes have become plugged, it is necessary to replace an entire set of condenser tubes (also known as retubing the condenser). When new materials designed to better withstand the destructive environment of the condenser are available, it is typical to use the improved materials.

b. Consequences of Forgoing Project

Because the steam side of the condenser is at a vacuum, when a leak occurs, the dirtier cooling water flows into the steam side. This necessitates shutting down the unit so as not to allow the untreated water to damage the boiler and the turbine. The leaking condenser tubes are then plugged. As tubes are plugged, the unit becomes less efficient, meaning that its ability to generate electricity declines and more emissions are associated with each unit of electricity produced. Condenser tube leaks eventually become so significant that the unit is constantly being shut down to plug tubes. Eventually, the condenser must be retubed or the unit can no longer operate.

c. Other Information

The replacement of entire tube bundles is common, and such replacement projects cost up to $10/kw at larger boilers. A census of repair and replacement practices at coal-fired utility boilers shows that more than 60% of the units in the industry have replaced condenser tubes.

7. Control Systems

a. Project Description

Careful monitoring and control of operating conditions at a coal-fired electric steam generating unit are necessary to insure safe, efficient, and reliable operation of the unit. Control and monitoring equipment at a unit consists of three major (core) systems: 1) boiler controls; 2) turbine controls; and 3) balance of plant management. Instruments and controls have advanced rapidly in the past two decades to provide greater operator knowledge and ability to optimize unit performance and to control emissions. For this reason, it is typical to replace out-dated benchboard type switches, lights, gauges, recorders, and manual/automatic stations with digital, computerized controls with touch screen monitors.

b. Consequences of Forgoing Project

Because controls help manage all aspects of combustion, unrepaired or outmoded controls will prevent the boiler from operating as efficiently and safely as is possible with modern controls. Moreover, because outmoded controls cannot manage a unit with the same efficiency as modern controls, failure to replace outmoded controls will result in higher emissions associated with start-up, shut-down and combustion staging. Often, replacement parts for outmoded controls may simply be unavailable.

c. Other Information

The replacement of pneumatic controls with solid state, computerized or automated controls has occurred at most units, and will continue to occur as technology improves. Such projects can cost up to $10/kw on larger units, and $40/kw on smaller units.

8. Coal and Ash Handling

a. Project Description

Coal handling equipment includes everything involved in unloading the coal from its transportation device (a railcar, barge or truck), storing it in a pile, and then conveying it to the plant so that it arrives at the feeders. After unloading, the coal is typically transported to a storage pile by a conveyor belt and reclaim system. While on the pile, the coal is usually managed by bulldozer, and then pushed onto a conveyer belt feeder. Sometimes a crusher in the coal storage area "pre-crushes" the coal. The coal travels by conveyor belt to the plant, where it is distributed among a series of bunkers by the tripper cars. The bunkers sit above and supply the feeders.

Much of the coal handling system is exposed to the weather. Moreover, coal is a hard substance that wears away the handling equipment. For example, conveyor belts, the motors that drive them, and structural equipment wears and corrodes over time, and this equipment is therefore commonly repaired and/or replaced. The rate at which the coal handling equipment deteriorates is influenced by the type of coal that is burned, with the result that variations in the coal that is burned in a boiler can lead to accelerated deterioration or obsolescence of existing coal handling equipment. Other factors that contribute to deterioration include local climate and proximity to salt water.

Once coal is combusted, the ash that results from the combustion process is collected in hoppers (bottom ash) or by pollution control equipment (fly ash). Once collected, the ash is recycled or treated and stored in ash storage ponds or landfills. The equipment for collecting, transporting and storing ash is subject to deterioration resulting from corrosion, abrasion and exposure to the environment.

b. Consequences of Forgoing Project

If coal handling equipment is not repaired or replaced when it deteriorates, fuel cannot be fed to the units and the plant must reduce load or eventually be shut down. Replacements are necessary when deterioration is so severe that repairs would be ineffectual, or where repairs would not resolve reliability problems. If ash handling equipment and disposal systems are not subject to constant maintenance and repair, the boiler will have to reduce load or cease operation until the ash it generates can be properly handled.

c. Other Information

Common projects involving coal handling equipment include the replacement of conveyer belts and motors, pre-crushers, barge and rail unloaders, and tripper cars. Such projects can cost up to $4/kw. Common projects involving ash handling equipment can cost up to $15/kw.

9. Feedwater Heaters

a. Project Description

Once the turbine has finished with the steam, the steam is condensed into water in the condenser and sent back to the boiler for reuse. Between the condenser and the boiler are a series of low pressure and high pressure feedwater heaters that gradually raise the temperature of the feedwater prior to returning it to the boiler, where it is then converted to steam. The feedwater system includes a condensate polishing unit (more common on larger, newer units) where impurities are removed, low pressure feedwater heaters, a deaerator heater, a boiler feed pump and high pressure feedwater heaters. From the last high pressure feedwater heater, the feedwater is delivered to the economizer inside the boiler.

A feedwater heater consists of a shell that covers a densely packed bundle of U-shaped tubes in which the condensate or feedwater flows. On top of the shell, there is an inlet for extraction steam from the turbine. As the condensate or feedwater flows through the tubes, extraction steam passes over the outside of the tubes and transfers heat to the water inside the tubes. Condensate or feedwater passes through the heaters in series, gradually increasing temperature thereby making the overall unit more efficient.

The feedwater heater system is subject to deterioration due to the effects of pressure, temperature and corrosion. It is common for tubes in this system to spring leaks, with the result that the heater must be bypassed until the unit can be taken off line to conduct repair or replacement activity. Newer corrosion resistant alloys to reduce maintenance problems are under constant development.

When leaks are detected, feedwater tubes are typically plugged. From 10 to 30% of the tubes may be plugged in some units, resulting in a significant reduction in unit efficiency. At some point, plugging tubes is no longer an option and replacement is necessary.

b. Consequences of Forgoing Project

Failure to plug leaking tubes results in a loss of overall unit efficiency and reliability. A tube leak therefore requires that the feedwater heater be bypassed until the unit can be taken off line for plugging or replacement of the leaking tubes. Plugged tubes cannot be feasibly repaired, so replacement is necessary once enough tubes have been plugged. Failure to replace the heater means that the heater must be removed from service, which can cause significant losses in efficiency and reduce the capacity of the unit to generate electricity, increase the emissions from the boiler per amount of electricity generated, and increase the reliability problems of the other feedwater heaters.

c. Other Information

Replacing an individual feedwater heater can cost up to $5/kw for a large unit. A census of repair and replacement practices at coal-fired utility boilers shows that more than 80% of the units in the industry have replaced feedwater heaters or major tube bundles in the feedwater heaters.

10. Sootblowers/Water Lances

a. Project Description

When coal is burned in the boiler, "ash" is produced which adheres to the boiler walls and tube assemblies and to the air preheater. The buildup of ash immediately reduces the heat transfer capability of these components which, in turn, means that more fuel is required to maintain the same load. In the long term, the presence of ash (slag) will cause tube overheating and boiler tube leaks, and may completely plug an air preheater.

Sootblowers are mechanical devices used for on-line cleaning of ash and slag deposits in the boiler, in order to maintain the heat transfer efficiency and to prevent damage to tube assemblies and other components. Various types of sootblower are used in a boiler depending on the location in the boiler, the cleaning coverage required and the severity of the deposit accumulation. Sootblowers basically consist of: (1) a tube element or lance which is inserted into the boiler and carries the cleaning medium (typically steam or compressed air), (2) nozzles in the tip of the lance to accelerate and direct the cleaning medium, (3) a mechanical system to insert or rotate the lance, and (4) a control system.

Acoustic blowers, which rely on sound waves, are also used. Sootblowers of all designs must function in the harsh environment of the boiler and are subject to wear due to exposure to high temperatures, corrosion, and erosion from high velocity particles. Accordingly, sootblowers are commonly replaced as they wear out. Also, because the slagging characteristics of a boiler can change over time, it is common to change the type of sootblower as the slagging characteristics change or become better understood.

b. Consequences of Forgoing Project

Failure to replace a deteriorated sootblower so that it can continue to remove soot, ash, and slag, will limit the capacity of the unit to generate electricity, and will eventually shut the unit down. Moreover, if boiler tube assemblies are not kept clean, more tube failures will occur, requiring more frequent shut downs to replace tube assemblies (see project family #1). Uncontrolled slagging can also cause catastrophic boiler damage if the accumulated slag falls from the boiler wall or roof onto the boiler floor.

c. Other Information

Sootblowers damaged from wear have been replaced at most units in the industry. Replacement of water lances, sonic blowers and related technology is also common. Such projects can cost up to $9/kw.

11. Burners

a. Project Description

Burners provide the final link between the fuel and combustion air and the boiler. Burners are specialized tubes or barrels (in the case of cyclone boilers) which direct pulverized coal (carried by primary air) and combustion air (or secondary air) into the combustion zone. Each boiler has many burners. The arrangement and performance of the burners have a direct impact on the distribution of air, the stability of the flame in the boiler and the combustion efficiency. These factors are adjusted by controlling the rate and pattern in which air and fuel enter the boiler.

For boilers other than cyclone boilers, dampers (driven by attached linkages) and vanes control the swirl and volume of air, while restrictors may be used to manage the volume of coal. Each burner consists of a coal (or other fuel) pipe and nozzle with a nozzle tip or impeller at the end of the nozzle at the interior wall of the boiler. Surrounding the fuel nozzle is the windbox, with secondary air passing through the windbox and into the boiler via a toroidal opening with the nozzle tip at the center. Accessories such as flame scanners and lighters are commonly found in the burner assembly.

Burners, particularly the nozzle tips, are required to function in extreme conditions. Corrosion, erosion and temperature-related stresses wear or weaken the tips. Further, the combustion zone can extend to the tip itself, and the high temperatures can effectively destroy the tip. The damper linkages are subject to high use and may fail from exposure to the boiler environment. Finally, because burner configuration and performance play a key role in staging and controlling combustion, entire burners may be replaced with modernized designs intended to control the formation of NOx or otherwise improve the efficiency or completeness of the combustion, thereby reducing emissions.

A cyclone boiler is designed to melt as much ash in the coal as possible during the combustion process, and then to drain it from the bottom of the furnace in order to keep molten slag off of the superheater and other tube assemblies. This design objective is accomplished by creating a combustion zone outside the main furnace. These combustion zones or "cyclones" are cylindrical barrels attached to the sides of the main furnace. Crushed coal and air are introduced into the cyclone in a tangential pattern, in order to create a swirling motion to promote mixing of the coal and air to ensure complete combustion of the coal. The introduction of crushed coal and air at high velocities erodes the cyclone, and the hot molten slag environment causes corrosion. High temperatures cause metal fatigue and deterioration of the cyclone.

b. Consequences of Forgoing Project

Failure to replace damaged burners or cyclones reduces the efficiency of combustion. Moreover, a damaged burners can clog and create a safety hazard. Unrepaired damper linkages prevent the unit operator from controlling the volume and spin of combustion air and will reduce the efficiency of the unit, thereby increasing emissions for each unit of electricity generated.

c. Other Information

Common projects involving burners include the replacement of cyclones, burner tips, burner linkages and the wholesale replacement of burners for low NOx designs. Burners or cyclones have been replaced one or more times at most units in the industry, at a cost of up to $30/kw.

12. Motors

a. Project Description

There are numerous electric motors in a power plant. For example, motors are used to drive fans, pumps, conveyor belts, pulverizers, and so on. All motors have insulation which breaks down over time, causing the motor to overheat and even short out. Usually, when motors short out they shut down automatically, but they can even catch on fire or explode. When motors short out, they can be rewound or, if rewinding is too expensive, they must be replaced.

b. Consequences of Forgoing Project

Failure to replace or to rewind a damaged motor risks a fire (or explosion if the motor is near coal dust) if the motor continues operating. Shutting down the motor means the pump, fan, mill, conveyor, etc. will no longer operate. This means that the unit must either operate at a lower capacity or potentially even that the unit must be shut down.

c. Other Information

It is common to rewind or to replace a motor. Replacement projects can cost up to $5/kw per motor. A survey of repair and replacement practices at coal-fired utility boilers shows that it is common in the industry to replace electric motors.

13. Electrical Equipment

a. Project Description

Electrical equipment is used to transmit electricity and make it usable for electrically-powered fans, motors, conveyors, lights, and numerous other applications in a power plant. There are several types of electrical equipment, including buses or wires that transmit the electricity, transformers that convert it into a usable form, switchgear or breakers that turn it on and off and protect it from electrical surges. In addition, for motors, there are often motor control centers and motor starters. Also, the plant itself uses buses, transformers and switchgear in the process of supplying electricity from the generator to the grid.

Shorts and overloads can occur in any of this equipment due to coal dust and the harsh environment of power plants. Damaged equipment is either repaired or replaced, depending on the severity of the damage.

b. Consequences of Forgoing Project

Replacement of electrical components that have deteriorated or are damaged due to the harsh power plant environment is necessary to support the electrical equipment at the power plant. If the electrical circuits are not operating, the equipment served by that circuit cannot operate and the unit will be unable to supply electricity at its previous capacity, if at all.

c. Other Information

Replacement of switchgears, and other electrical equipment components are very common. Replacement projects can cost up to $9/kw.

14. Pumps

a. Project Description

Pumps are used to convey fluids around a power plant, including water (condenser circulating pumps) or water containing ash (ash sluice pumps). Pumps have moving parts. Ash sluice pumps are exposed to erosive, highly stressful environments. Other pumps, such as boiler feed pumps, are exposed to extreme temperatures and are expected to operate at very high pressures. These failure mechanisms lead to deterioration, which often requires replacement of a pump.

b. Consequences of Forgoing Project

If a pump is not repaired, additional stress is placed on other pumps in the system, and reliability problems will result. Eventually (immediately for some pumps) failure to replace certain broken pumps means that the boiler cannot operate at its design pressure.

c. Other Information

Common projects involving pumps include replacement of boiler feed pumps and ash sluice pumps. Replacement projects can cost $10/kw. A census of repair and replacement practices at coal-fired utility boilers shows that nearly 100% of the units in the industry have overhauled or replaced boiler feedpumps.

15. Piping/Ducts/Expansion Joints

a. Project Description

Pipes are used to carry mass (fluids or fluids containing solids) through a power plant. Ducts are essentially square pipes that carry air or flue gas. In an industrial environment like a power plant, pipes and ducts spring leaks due to the high pressure, high temperature and corrosive environment. If a section of pipe or duct leaks on an ongoing basis, the economic choice is to replace that section.

Expansion joints are flexible pieces that connect two sections of ductwork or piping. They are used because temperature differences cause different sections of ductwork or pipe to expand and contract at different rates. Even though expansion joints are designed to move as the contraction and expansion occurs, they can experience cracks and separations due to fatigue. If too many leaks occur, they must be replaced.

b. Consequences of Forgoing Project

Leaking ducts, pipes or expansion joints dilute the power of the fan or pump. Failure to repair or replace the pipe, duct or joint, therefore, will prevent the unit from generating electricity at its design capacity. Moreover, leaks of steam, gasses or fuel present safety hazards which must be addressed in a timely manner once they are identified.

c. Other Information

Replacing leaking ductwork, high temperature steam pipes, ash handling pipes, fuel piping, and expansion joints are common projects. It is also common to convert from fabric to metal joints or the reverse, depending upon boiler characteristics. Replacement and repair projects can cost up to $23/kw.

16. Air Compressors

a. Project Description

Air compressors are mechanical devices similar to a pump, except that they compress air instead of a liquid. Air compressors have moving parts that are subject to wear. The principal use of compressed air in steam plants is for pneumatic drives for dampers and valves, system controls, some types of sootblowers, and power repair hand tools.

b. Consequences of Forgoing Project

Failure to repair the service air system will affect at least some and perhaps many aspects of the plants controls. If control air is no longer available, it becomes impossible to position valves properly and the unit cannot be operated.. Failure of the air compressors that service sootblowers will prevent the operation of those devices, with the resulting damage to the boiler (see project family #10).

c. Other Information

Replacement is often the most economical choice for fixing a damaged compressor. Replacement projects can cost up to $2/kw.

APPENDIX THREE: BOILERMAKERS STATEMENT

 

Statement of Paul Kern, Recording Secretary, Local Number 105

International Brotherhood of Boilermakers, Iron Ship Builders,

Blacksmiths, Forgers and Helpers, AFL-CIO

4561 U.S. 23 - South

Piketon, Ohio 45661

Public Meeting Regarding New Source Review

Members of the panel, thanks for allowing the Boilermakers Union to provide a statement at today's discussion of New Source Review.  The Boilermakers are a diverse union representing over 100,000 workers throughout the United States and Canada in construction, repair, maintenance, manufacturing, professional emergency medical services, and related industries.  I am recording secretary at one of our large locals, located in the Greater Cincinnati area.

First, let me be clear today that Boilermakers do not oppose the Clean Air Act, nor do we oppose its rigorous enforcement.  In fact, construction lodges of our union look forward to doing much of the actual work for the installation of new technologies and controls at utility plants and for industrial boilers across this region and the country.  In reference to the Nox control program alone, our international President Charlie Jones recently wrote:

"The EPA estimates that compliance measures will cost about $1.7 billion a year. A sizeable portion of that money will go to the Boilermakers who do the work necessary to make the additions and modifications required by the SCR technology."[16]

Aside from Nox control, Boilermakers have always led the way on Clean Air Act issues.  For example, Boilermakers were pioneers in installation of scrubbers and further in fuel-substitution programs at our cement kiln facilities.  In short, Boilermakers have been there to meet the challenges of the Clean Air Act, to the benefit our members and all Americans that breathe clean air.

However, Boilermakers cannot support the EPA's recent interpretation of its authority under the New Source Review program.  NSR, correctly interpreted, forces new sources or those undergoing major modifications, to install new technology, like the technology President Jones mentioned.  We support NSR in that context.

But, when NSR is applied to the routine maintenance policies and schedules of existing facilities, very different results occur.  In those cases, facilities are discouraged from undertaking routine actions for fear of huge penalties or long delays or both.  By applying NSR in that way, we are pretty sure that Boilermakers won't have the opportunity to work on maintenance projects that we know are extremely important to energy efficiency.  Just hearing about recent events in California is enough to make the case that facilities need to be as efficient as possible.

Efficiency is not the only reason to encourage routine maintenance. Experienced professionals or Boilermakers new to the trade can both tell you:  maintenance is necessary to maintain worker safety. Electric generating facilities harness tremendous forces:  superheater tubes exposed to flue gases over 2000 degrees;  boilers under deteriorating conditions; and parts located in or around boilers subjected to both extreme heat and pressure.  Any EPA interpretation which creates incentives to delay maintenance is simply unacceptable to our workers.

As you can see, Boilermakers do not ask for repeal or substantial revision of the NSR program.  We encourage the development and installation of new technology, and we stand ready to continue to train and apprentice workers to meet the needs of the Clean Air Act.  However, when the NSR programs goes where it wasn't intended - and discourages the very maintenance, repair and replacement activities that constitute the livelihood of Boilermakers - we must strongly object.

Thanks for the opportunity to make a statement.

 


[1]Foundation for Clean Air Progress, Air Pollution Plummets as Energy Use Climbs (release of study results)(January 17, 2002), available at: www.cleanairprogress.org /news/energy_01_02.asp.  The study's state‑by‑state analysis tracks air quality and energy consumption during the 15‑year period of 1985 to 1999. The data were drawn from the National Emission Trends (NET) database which is available from EPA.

[2]Venturi is quoted in the Statement of C. Boyden Gray, Hearings: Air Emissions from Power Plants, Senate Committee on Environment and Public Works, July 26, 2001.

[3]Id.

[4]U.S. Environmental Protection Agency, Automobile Emissions: An Overview, Factsheet OMS-5 (August 1994).  With respect to Nox emissions, a comparison of reductions required of mobile sources and electric utilities shows that the utilities are pulling their own weight. Mobile sources contribute 58% of annual NOx emissions, more than double the 25% generated by electric utilities, and consequently would seem to have much more scope for emissions reduction.

[5]Vice President Al Gore, Creating A Government That Works Better and Costs Less (Chapter III - Creative Approaches to Environmental Protection)(September 1994).

[6]Vice President Al Gore, "The Environment" from 1996 Annual Report: The Best Kept Secrets in Government (report to President Clinton regarding Reinvention of Government and the National Performance Review).

[7]Alexander Volokh and Roger Marzulla, Environmental Enforcement: In Search of Both Effectiveness and Fairness, RPPI Policy Study No. 210 (Aug. 1996) at http://www.rppi.org/environment/ps210.html.

[8]Jonathan H. Adler, Anti-Environmental Enforcement (Feb. 1, 1997), at http://www.cei.org/utils/printer.cfm?AID=1307(citing a 1993 survey of 200 corporate general counsels conducted by the National Law Journal).

[9]The same source continues: "Federal agencies publish more than 65,000 pages of rules and interpretive statements in the Federal Register each year, and issue countless pages of regulatory guidance. Much of this "guidance" actually attempts to change the meaning of the regulations, or to add new requirements not contained in the published rule. These thousands upon thousands of pages of regulations and interpretations often are inaccessible to most Americans, creating a welter of "private regulations" of which citizens are completely unaware. These memoranda, letters, and notes, prepared by thousands of separate government employees, are sometimes inconsistent with each otherCCas well as with the regulation. Indeed, the more ambiguous the regulation, the greater the proliferation of interpretations and guidance, leaving the citizen to pick through them to ascertainCCat his perilCCwhat those regulations require of him. The results, in many instances, include ruinous penalties and the shattering of lives of ordinary, law-abiding Americans who tried to do the right thing."

[10]U.S. EPA, FY 2001 Enforcement and Compliance Results (Jan. 31, 2002), available at: http://es.epa.gov/oeca/main/2001eoy/index.html.

 

[11]Id.

[12]The Environmental Council of the States, State Environmental Agency Contributions to Enforcement and Compliance (April 2001), at 9.

[13]Id. at 14.

[14]Id. at 10.

[15]Becky Norton Dunlop, Environmental Enforcement: Supporting State Efforts to Encourage Voluntary Compliance at http://www.adti.net/html_files/reg/dd/dddunlop.htm

[16]Boilermaker Reporter, vol. 38, No. 1 (1999)  SCR means selective catalytic reduction.  SCR essentially consists of injecting ammonia into boiler flue gas and passing it through a catalyst bed where the NOx and ammonia react to form nitrogen and water vapor.