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**Ozone Transport Assessment Group**

**Control Technologies and**

**Options Workgroup**

**FINAL**

**States\' Report on Electric Utility**

**Nitrogen Oxides Reduction Technology Options**

**for Application by The**

**Ozone Transport Assessment Group**

**Prepared for the**

**OTAG Control Technologies & Options Workgroup**

**by Ken Colburn**

**April 11, 1996**

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STATES\' REPORT

on

ELECTRIC UTILITY

NITROGEN OXIDES REDUCTION TECHNOLOGY OPTIONS

FOR APPLICATION BY THE

OZONE TRANSPORT ASSESSMENT GROUP

**TABLE OF CONTENTS**

Executive Summary ii

Section 1.Introduction 1

Section 2.NOx Formation in Utility Boilers and Combustion Turbines 5

Section 3.Electric Utility NOx Emission Control Regulatory Framework 8

Section 4.Utility Boilers and Combustion Turbines: Description of
Equipment 12

Section 5.NOx Control Technologies for Utilities 17

Section 6.Increasing Emission Reduction Requirements and Deregulation of
the Electric Utility Industry 41

Section 7.Strategy Development and Implementation Issues for Electric

Utility Sources 44

Section 8.Summary Matrix of NOx Control Technology Cost and Performance
46

Appendix A.Cost Evaluation Behind Industry-Estimated Control Cost Range
in Summary Matrix 47

Selected References 49

STATES\' REPORT

on

ELECTRIC UTILITY

NITROGEN OXIDES REDUCTION TECHNOLOGY OPTIONS

FOR APPLICATION BY THE

OZONE TRANSPORT ASSESSMENT GROUP

**EXECUTIVE SUMMARY**

This report provides a brief overview of NOx control technologies
available for fossil fuel‑fired electric utility power generation
equipment (boilers, combustors, steam generators, etc.). While this
report evaluates controls that are commer­cially available today, NOx
control technologies are undergoing rapid improve­ment by both
manufacturers and utility users, and the learning curve of their
application and use is swiftly maturing. In addition, other
high‑performance control technologies, and hybridizations of existing
technologies, are in various stages of development by major electric
utility equipment manufacturers. The extent of development of new NOx
controls, as well as the improvement of existing NOx controls, is
largely influenced by the incentives provided when establishing any
regulations.

The Ozone Transport Assessment Group (OTAG) is considering the
possibility of establishing a NOx \"cap and trade\" program to provide
market-based incentives to significantly reduce NOx emissions from
electric utilities in 37 States. The OTAG region contains approximately
1,500 fossil fuel-fired boilers capable of generating over 260,000
Megawatts (MW). These boilers emitted approximately 5,600,000 tons of
NOx in 1990 and are of varying size, design, and fuel capacities. Of the
1,500 boilers, approximately 900 burn coal and accounted for over 85% of
NOx emitted in 1990. As a result, NOx controls for coal-fired boilers
are of particular importance.

There are currently two major categories of NOx controls available for
utility boilers: combustion controls (e.g., low NOx burners, overfire
air), and post-combustion controls (e.g., selective catalytic reduction
or SCR, selective non­catalytic reduction or SNCR, and reburning).
Combustion controls prevent the formation of NOx by delaying the mixing
of fuel and air in the main combustion zone. Post-combustion controls
destroy NOx that has been formed in the main combustion zone by
injecting ammonia (SCR), urea (SNCR), or additional fuel (reburning).

Currently available combustion controls can, on average, reduce NOx by
approximately 50 percent from uncontrolled levels. Post-combustion
controls can either be applied in conjunction with combustion controls
or by themselves, and depending upon how such controls are designed and
engineered, they can reduce NOx as little as 30% or as much as 95%.[^1]
The following bullets provide summary information on the average NOx
emission levels achieved by these controls and their associated
incremental costs.

o**Coal-fired boilers**

With combustion controls, coal-fired boilers typically emit at a rate of
0.35 to 0.55 pounds per million British thermal units (lb/mmBtu) of NOx.
The addition of post-combustion controls can further reduce boiler NOx
emissions to levels below 0.2 lb/mmBtu. The cost-effectiveness of these
reductions typically ranges from \$200 to \$600 per ton of NOx removed
when applying combustion controls, and from \$500 to \$2,000 per ton of
NOx removed when applying post-combustion controls.

o**Oil-fired boilers**

With combustion controls, oil-fired boilers typically emit 0.3 lb/mmBtu
of NOx, and the cost-effectiveness of these reductions typically ranges
from \$600 to \$1,500 per ton of NOx removed. The addition of
post-combustion controls can further reduce boiler NOx emissions to
levels below 0.1 lb/mmBtu, with typical costs ranging from \$1,200 to
\$2,200 per ton of NOx removed.

o**Gas‑fired boilers**

With combustion controls, gas‑fired boilers typically emit 0.25 lb/mmBtu
of NOx, and the cost‑effectiveness of these reductions typically ranges
from \$600 to \$1,500 per ton of NOx removed. The addition of
post-combustion controls can reduce boiler NOx emissions to levels below
0.1 lb/mmBtu, with typical costs ranging from \$900 to \$2,000 per ton
of NOx removed.

It should be noted that the above figures represent typical performance
and costs. As described in detail throughout the report, some boilers
can achieve better performance at lower costs and vice‑versa.
Additionally, some controls are not applicable to certain types of
boilers.

An important factor in the evaluation of any technology is also gaining
an understanding of the underlying financial incentives for improving
performance and lowering cost. In the case of pollution controls, any
incentive to go below a certain standard prompts innovation by both the
regulated entities and the pollution control manufacturers. Trading of
emission reductions and allowances alone can be expected to reduce
overall NOx control costs by over half (56%) of the per‑ton costs noted
above.

The SOx allowance system authorized by Title IV of the Clean Air Act is
a good illustration. Through the use of market‑based programs and
incentives, the cost of SOx reduction is far lower today than even the
lowest estimate in 1990. Because of the underlying incentives built into
this program, industry responded to the regulation in ways that were
not, at the time, anticipated or expected, such as: (1) negotiating with
railroad companies to reduce their coal transportation rates; (2)
encouraging greater improvement of mining techniques; (3) blending and
burning low sulfur coals at lower cost; and (4) reducing SOx scrubber
costs by 40%.

Similarly, in the area of NOx control, such advances are already being
driven by upcoming regulatory actions in the Northeastern Ozone
Transport Region (OTR), where one commercial boiler has been retrofitted
with newer generation combustion controls and achieves a long‑term NOx
emission rate of 0.23 lb/mmBtu. Another coal fired boiler in the OTR has
been retrofitted with SCR at a cost of approximately \$400 per ton\--an
achievement previously discounted as unrealistically optimistic. The
OTAG process and newly proposed Title IV (Acid Rain) rules for NOx have
also spurred control technology markets, so much so that many of the
cost estimates for NOx control solutions referenced in this report have
already been rendered obsolete by still more cost‑effective control
options.

Additionally, the Department of Energy\'s (DOE) Low Emission Boiler
System program (LEBS) works with major U.S. manufacturers of utility
equipment to develop, among other things, higher performing NOx
controls. One goal by both DOE and the manufacturers is to develop, by
the year 2000, commercially applicable combustion controls capable of
reducing NOx to a rate of 0.20 lb/mmBtu and, in combination with
post‑combustion controls, capable of reducing NOx to a rate of 0.10
lb/mmBtu. Further, as illustrated by a recent white paper by the
Institute of Clean Air Companies (ICAC), most coal‑fired boilers in
Western Europe (e.g., Austria, Denmark, Germany, Finland, Italy, and the
Netherlands) and Japan are permitted to emit NOx at a rate of no more
than 200 mg/Nm^3^ (about 0.16 lb/mmBtu). Many boilers, however, emit at
or below 0.12 lb/mmBtu.

Thus, with appropriate incentives (e.g., trading, compliance
flexibility, and the lack of technology mandates), the industries
affected by NOx reductions can be expected to respond in innovative ways
to increase NOx control performance and decrease overall costs of
compliance far below those currently predicted.

STATES\' REPORT

on

ELECTRIC UTILITY

NITROGEN OXIDES REDUCTION TECHNOLOGY OPTIONS

FOR APPLICATION BY THE

OZONE TRANSPORT ASSESSMENT GROUP

**SECTION 1**

**INTRODUCTION**

1.1. BACKGROUND

This document provides a brief overview of NOx control technologies for
fossil fuel‑fired electric utility power generation equipment. The
information contained in this report draws upon material assembled by
the Ozone Transport Assessment Group (OTAG) Control Technology Workgroup
between August 1995 and February 1996.

1.2. OBJECTIVE OF THIS REPORT

The objective of this report is to provide a succinct, simple summary of
technology options to control NOx emissions in the OTAG region. It
builds upon several recent reports which provide comprehensive, in‑depth
overviews of NOx control technology options.[^2] One of these, prepared
for NESCAUM, MARAMA, and the EPA Office of Air Quality Planning and
Standards (*Phase II NOx Controls for NESCAUM and MARAMA Regions*,
November 1995) is a primary source for this document. Where data is
available, this report also considers actual retrofit experience to date
and vendor quotation information concerning the cost and technical
effectiveness of NOx control technology options.

1.3 FOREWORD

The NOx control technologies considered in this report are viable and
commercially available for the indicated boiler types and fuels. These
control technologies have been proven by application at both domestic
and international sites.

As with any technical solution, several key issues influence cost,
effectiveness, and choice of technology regarding NOx controls. For
example, NOx controls for a large electric boiler must be tailored to
reflect fuel type and composition, operating or duty cycle of the boiler
(e.g., baseloaded or subject to frequent load changes), and physical
characteristics of the boiler and its site (e.g., space constraints,
equipment limitations, flue gas residence times, availability of
secondary or alternative fuels, etc.).

Coupled with increasing regulatory flexibility in pursuit of innovation,
and growing competition among manufacturers of various NOx control
technologies, control options are rapidly multiplying and no single NOx
control technology can be expected to always perform best at every site.

1.4. SUMMARY AND CONCLUSIONS

The OTAG region contains almost 900 coal‑fired boilers and nearly 600
oil and natural gas‑fired boilers of varying age, size, and design.
However, 25% of all utility NOx emissions (about 1,400,000 of 5,600,000
tons per year in 1990) are emitted by just 7% of boilers: approximately
110 coal‑fueled cyclone and cell-fired boilers included in Group 2 of
the Clean Air Act (CAA) Title IV Acid Rain program. Almost half (45%) of
total utility NOx is emitted by just 200 sources. About 60% of utility
NOx emissions (about 3,300,000 tons per year) is emitted by 47% of the
boilers: the roughly 700 coal‑fueled, wall‑fired and tangential‑fired
boilers included in Group 1. The remaining 600 boilers\--40% of all
boilers\--emit just 15% of all utility NOx emissions.

The intent of this report is not to address each and every conceivable
retrofit scenario. Instead the NOx control technology costs presented in
the Summary Matrix (Section 8) are intended to provide a range of
cost‑effective solutions generally applicable to the multitude of boiler
types, ages, fuels, and control technologies that currently exist across
the wide geographic region of the 37 OTAG states. Notwithstanding
occasional exceptions due to extreme boiler-­specific limitations, the
vast majority of NOx control technology retrofits in the OTAG region
should be achievable within the cost and performance ranges illustrated
in the Summary Matrix.

Post‑1991 commercial and field experience in the United States with both
coal-­fired and gas‑fired boilers confirms that robust NOx control
technology options are more technically feasible and cost effective than
previously believed. Recent technological advancements and innovations,
increasing pressure for open transmission access and deregulation of
electrical generation, and greater understanding of the profound health
and environmental impacts of utility emissions have combined to shepherd
a number of low capital, highly effective control technology options
into proven commercial availability.

For example, the 1995 SCR retrofit of a 330 MW cyclone boiler in New
Hampshire-‑which involved substantial difficulty and was accomplished in
an extremely short timeframe which included winter
conditions\--demonstrates that at over 85% of NOx can be removed at a
per ton cost of about \$400 with capital cost under \$60/kW. Similarly,
the SNCR and LNB retrofit of three boilers in Massachusetts in 1993
reduced NOx by over 65% for less than \$700 per ton, with capital costs
under \$14 kW. Busbar costs for the New Hampshire cyclone retrofit were
about 3 mills (\$0.003) per kilowatt‑hour of electricity produced. This
figure is consistent with busbar costs for baseloaded units across all
NOx control technologies estimated by STAPPA/ALAPCO (1994) to be
typically at or below 3 mills.

Further, these costs are rapidly declining as control technology
advances and its application becomes better understood. The anticipated
capital costs to control NOx emissions from 44 oil‑ and natural
gas‑fired Southern California Edison units totaling 13,000 MW, for
instance, dropped from \$952 million to \$290 million\--a 70%
reduction\--in just one year (between 1991 and 1992). This was
accomplished through: (a) prudent, flexible selection among commercially
available control technology options including combustion modification,
urea­based selective non‑catalytic reduction (SNCR), selective catalytic
reduction (SCR), and repowering; (b) market driven innovations such as
in‑duct SCR, which eliminates the need for a full‑size reactor; and (c)
intense competition among suppliers of NOx control technologies. The end
result\--a 90% NOx reduction from the base case\--met the regulatory
requirement of a system‑wide average of 0.015 lb/mmBtu.

An often‑overlooked sector of the electric utility industry which also
merits some attention is that of peak shaving units. Interim OTAG
inventory data indicates that peak shavers comprise approximately
\_\_\_% \<\<\<*what %*\>\>\> of total NOx emissions from the utilities.
Further, these units often operate at times when ozone and/or precursor
levels are already elevated, thus magnifying their emissions impact.
Application of control technology equipment to peaking units has
traditionally been difficult to classify as \"reasonable\" because their
relatively limited use results in excessive amortization costs.
Technological progress in fuels, however, may now provide these sources
with cost‑effective NOx reduction options (i.e., \$500‑\$2,500 per ton
of NOx removed). The availability of such options should lead to renewed
regulatory consideration of NOx reductions from these high impact
sources.

For overall comparative purposes, the utility average emission rate for
all fuels over the northeast Ozone Transport Region (OTR) during 1990
was 0.649 lb/mmBtu: 43 times higher than rates already achieved in the
United States using natural gas, and about 10 times higher than those
reasonably achievable firing coal. This extremely high NOx emission rate
predictably yields extremely high daily, seasonal, and annual emissions
in the eastern U.S. As a result, OTAG has the opportunity to
substantially reduce NOx emissions in a very cost effective manner.

Nevertheless, the application of NOx control technology in the OTAG
region should not be accomplished by mandating the universal use of one
specific control technology. It is far more cost effective to establish
performance‑based standards and allow implementation flexibility and
effective trading programs to achieve them. For a small number of the
1,500 boilers in the OTAG region, for example, incremental control costs
may be much higher than actual experience to date has shown.

The application of a flexible, market‑based approach that allows
multiple units under a single operator to be averaged together (or
\"bubbled\"), and allows trading of emissions between different
operators, provides an economical and cost‑effective mechanism to meet
overall regional emission reduction targets (including emission
reductions for boilers that are expensive and difficult to control).
Trading alone can be expected to cut overall emission reduction costs by
over 50%[^3] and performance‑based standards encourage control
technology suppliers to continually upgrade price/performance
characteristics.

Further, these approaches are hardly unprecedented. Averaging approaches
have already been applied effectively in the Northeast to meet the RACT
requirements of Title I of the Clean Air Act. Southern California also
allows system‑wide averaging for all units operated by a utility. The
Title IV Acid Rain program promotes emission trading between different
utilities, and a similar \"Cap and Trade\" approach recently developed
by the NESCAUM/MARAMA states to implement the 1994 Ozone Transport
Commission (OTC) NOx Memorandum of Understanding (MOU) will offer an
economically attractive mechanism to meet future OTAG control
requirements and responsibilities.[^4]

Finally, although by definition OTAG focuses on the transport of ozone
and its precursors, other pollutants also subject to long range air
transport (including fine particulate matter, mercury, and regional
haze) appear to have profound human health and economic impacts‑‑even
greater than those of ozone in some cases. It would thus be shortsighted
for OTAG participants to endeavor to parse sensible, overall solutions
common to multiple contaminants into distinct components in order to
avoid solving overall transport issues once and for all. OTAG\'s very
existence, so soon after the great Acid Rain debate, illustrates that
broad concerns about transported air pollutants are best addressed in an
integrated and comprehensive fashion.

In short, it remains critically important to human health and
environmental quality that state and federal regulatory agencies
(economic as well as environmental), industry, and the varied publics
represented by the OTAG region work together to achieve adequate
emission reductions, in a cost effective manner, where they are most
needed, for as long as they are needed.

**SECTION 2**

**NOx FORMATION IN UTILITY BOILERS**

**AND COMBUSTION TURBINES**

2.1. INTRODUCTION

This section reviews the formation of nitrogen oxides (NOx) in utility
steam boilers and combustion turbines. The key mechanisms of NOx
production are first summarized, followed by a discussion of control
strategies.

2.2. NOx FORMATION

NOx is formed through a chemical reaction between oxygen in combustion
air and nitrogen, which is present in both the combustion air and fuel.
Two major mechanisms contribute to the formation of NOx during fossil
fuel combustion:

[Thermal NOx Formation]{.underline}. Thermal NOx pertains to formation
of NOx from the conversion of nitrogen found in the air. The rate of
thermal NOx formation during combustion is highly dependent on
temperature and oxygen concentration. In order to minimize thermal NOx
formation, it is necessary to reduce combustion temperatures and to
minimize oxygen concentration in the combustion gas. For fuels which
contain no inherent nitrogen (e.g., natural gas), essentially 100% of
NOx is thermal NOx. Thermal NOx formation from heavy fuel oil combustion
represents approximately 20-40% of the total NOx produced. For coal,
thermal NOx can comprise approximately 20‑50% of the total NOx generated
from conventional pulverized coal boilers.[^5] This contribution can
vary significantly depending on boiler design and fuel properties.

[Fuel NOx Formation]{.underline}. Fuel NOx pertains to NOx emissions
from the conversion of nitrogen organically bound in the fuel itself.
This mechanism represents 50­-80% of the NOx produced from heavy fuel oil
combustion, and approximately 60‑80% of the NOx produced from pulverized
coal combustion. Formation of fuel NOx is also affected by fuel type,
excess air, burner design, and type of boiler.

2.3. DESIGN AND OPERATING FACTORS

Design and operating factors which affect NOx production are briefly
discussed for both steam boiler and combustion turbine equipment. These
factors include burner design, combustion system heat release rate,
operating load, and fuel composition.

2.3.1. Burner Design

Burner designs that rapidly mix fuel and air promote both thermal and
fuel sources of NOx. For utility steam boilers, prior to the advent of
NOx concerns over 25 years ago, burners were designed to allow compact
(and inexpensive) furnaces. These conventional burners intentionally
produce short, compact flames that rapidly mix fuel and air, and utilize
fuel with high efficiency. In contrast, present day design criteria for
low‑NOx burners (\"LNB\") allow more gradual mixing of fuel and air,
creating conditions that minimize NOx production. The resultant flame
shape can influence boiler performance, reliability, and operating
characteristics.

For combustion turbines, design criteria prior to the advent of NOx
concerns similarly demanded a high heat release, intense combustion
process that produced a stable flame. In contrast, low NOx combustion
concepts specify operation at extreme excess air conditions to act as a
thermal diluent, thus controlling peak temperatures.

2.3.2. Combustion System Heat Release Rate

One frequently and widely used index of boiler design is the heat
release rate per unit volume, specified in terms of Btu/ft^3^‑hours.
This index reflects the \"intensity\" of the combustion process as
determined by the rapidity of fuel and air mixing and the volume of
furnace available to extract heat from the flame zone. A high heat
release rate per unit volume implies rapid fuel and air mixing, and
limited furnace surface area to remove heat. The higher this combustion
\"intensity,\" the higher the formation of NOx. This concept of heat
release intensity is equally applicable to combustion turbines.

2.3.3. Operating Load

Another variable that may influence NOx is operating load, typically
expressed in terms of percent of maximum capacity. Operating a boiler at
maximum load typically maximizes NOx production; both the rapidity of
fuel and air mixing and the heat release rate per unit volume are
maximized, thus creating conditions suitable to higher NOx formation.
There are exceptions to this relationship, particularly for
tangential‑fired boilers. Higher NOx at partial load may result
primarily due to the need for higher excess air levels at low load to
maintain flame stability and steam temperatures. For most steam boilers
with conventional burners, NOx production increases with load. However,
recent continuous emission monitoring (\"CEM\") data analyzed by EPA
suggests that when LNBs are installed, NOx emission rates do not
significantly vary with load.[^6]

2.3.4. Fuel Composition

As noted earlier, fuel‑bound nitrogen (\"FBN\") is a key determinant of
NOx production. Despite significant research, the relationship between
the properties of a fuel and the propensity to produce NOx is not yet
fully understood. FBN varies substantially by fuel type:

o[Natural Gas and Light Fuel Oil]{.underline}: These fuels do not
contain nitrogen in any significant quantity, thus thermal NOx is the
principle source. Accordingly, all other factors being equal, these
fuels generally produce the lowest NOx emissions.

o[Heavy Oil and Pulverized Coal]{.underline}: These fuels contain
significant organically bound nitrogen which often represents the major
NOx source. (Heavy oil ranges from 0.4‑0.7% nitrogen by weight. Coal
ranges between \_\_‑\_\_% nitrogen by weight. \<\<\<*what %s?*\>\>\>
Coal properties which affect fuel NOx formation are volatility, fuel
nitrogen and moisture content, and the distribution of fuel nitrogen
between the volatile and char fractions.

**SECTION 3**

**ELECTRIC UTILITY NOx EMISSION CONTROLS:**

**REGULATORY FRAMEWORK**

3.1. INTRODUCTION

This section considers the key regulatory provisions which define
current NOx emission control requirements for utility industry boilers.
It also addresses anticipated regulatory developments and other trends
in the electric utility industry.

3.2. CURRENT AND NEAR‑TERM NOx EMISSION REQUIREMENTS

The Clean Air Act Amendments of 1990 (CAAA) mandated several NOx control
requirements and regulatory reviews associated with NOx controls on
electric utility boilers and combustion turbines. The requirements and
reviews include NOx reductions: (a) in certain areas designated under
Title I for attainment of the ambient ozone standard; (b) nationwide
under Title IV (e.g., the \"Acid Rain\" requirements), and (c) for new
sources as dictated by revised New Source Performance Standards (NSPS).
Each of these is briefly reviewed in this section.

3.2.1. Title I\--Provisions for Attainment and Maintenance of National
Ambient Air Quality Standards (NAAQS)

NOx limits promulgated under this Title for ozone include the
application of \"reasonably available control technology\" (RACT) for
major NOx sources, including utility boilers and turbines, in designated
ozone nonattainment areas. RACT determinations, which are made by the
States, typically specify control technologies by source type, but
different determinations can be made on a case by case basis via a
\"RACT Order\" process. The U.S. Environmental Protection Agency (EPA)
has issued guidance suggesting that NOx RACT for utility boilers is
typically combustion modifications (such as low NOx burners), but States
have issued their own NOx RACT guidelines and rules defining flue gas
recirculation, burners out of service, SNCR, SCR, or other control
options as RACT in specific situations. For affected ozone nonattainment
areas and the entire Northeast Ozone Transport Region (OTR), NOx RACT
controls were required by May 31, 1995.

In the OTR, twelve of the thirteen jurisdictions (twelve northeastern
states and the District of Columbia) have signed a Memorandum of
Understanding (MOU) agreeing to promulgate regulations that impose NOx
controls beyond the level required by RACT for utility and other boilers
with a minimum gross heat input of 250 million Btu per hour. The MOU
requires boilers within the OTR to meet the least stringent of the NOx
reductions listed below. A regionwide trading mechanism is being
developed for NOx emissions in order to facilitate the achievement of
these reductions in the most cost‑effective manner.

o[The \"Inner Zone\"]{.underline}: Reduce NOx emissions by 65% from base
year levels (generally 1990 emissions) by May 1, 1999; [or]{.underline}
to meet a NOx limit of 0.20 pounds per million Btu of heat input
(lb/mmBtu, no averaging time specified). Further reductions of NOx
emissions, down 75% from base year levels [or]{.underline} meeting a
0.15 lb/mmBtu limit, are required by May 1, 2003 (unless new modeling
and analyses prove before 1999 that the OTC should modify the MOU).

o[The \"Outer Zone\"]{.underline}: Reduce NOx emissions by 55% from base
year levels by May 1, 1999; [or]{.underline} meet a 0.20 lb/mmBtu limit.
Further reductions of NOx emissions, down 75% from base year levels
[or]{.underline} meeting a 0.15 lb/mmBtu limit, are required by May 1,
2003 (unless new modeling and analyses prove before 1999 that the OTC
should modify the MOU).

o[The \"Northern Zone\"]{.underline}: Reduce NOx emissions by 55% from
base year levels by May 1, 2003; [or]{.underline} meet a 0.20 lb/mmBtu
emission limit. Sources in this region are required to meet State NOx
RACT requirements until May 1, 2003, however.

3.2.2. Title IV\--Acid Deposition Control

This Title calls for nationwide reductions in NOx emissions by the year
2000. Coal‑fired utility boilers will be required to meet new emission
standards that will be implemented in two steps.

o[Phase I Control Requirements for Tangential and Dry Bottom Wall‑Fired
Boilers]{.underline}: Phase I limits are 0.45 lb/mmBtu for
tangentially‑fired boilers and 0.50 lb/mmBtu for dry bottom wall‑fired
boilers. The Title IV NOx limits under both phases are annual averages.
The Phase I/Group 1 limits must be met individually, or under permitted
averaging plans, by January 1, 1996 for approximately 220 boilers.[^7]
Alternative emission limits (AELs) are allowed if a specific boiler
proves that it cannot meet its regulatory limit after properly
installing and operating the appropriate control equipment.

o[Phase II Boilers and Group 2 Boilers]{.underline}: NOx emission limits
for all Phase II boilers and Group 2 boilers (which include wet bottom
wall‑fired, cyclone, cell‑burners, and all other coal‑fired boilers)
were proposed on January 19, 1996 and are expected to be final by
January 1, 1997. The rules allow for \"grandfathering\" Phase II, Group
1 boilers if they meet the limits that apply to Phase I boilers by
January 1, 1997.

3.2.3. New Source Performance Standards (NSPS)

EPA is currently reviewing NOx control requirements for new utility
boilers and combustion turbines, and revisions to NSPS standards are
expected within the next two years. The revised NSPS standards, coupled
with \"best available control technology\" (BACT) requirements under New
Source Review, are expected to be significantly more stringent than
current requirements. In addition, EPA is in the process of revising the
NAAQS for ozone and particulate matter. EPA is also in the process of
developing standards for regional haze and has recently proposed much
lower standards for mercury emissions. Given increasing evidence of
serious human health impacts, these revisions can be expected to target
further reductions of NOx and other emissions from new electric utility
sources.

3.3. FUTURE NOx EMISSIONS TRENDS

Future electric industry emission trends are difficult to forecast
because several simultaneous dynamics exist, each of which could
increase or decrease NOx emissions. NOx emissions growth is clearly
anticipated from existing sources that increase generation or capacity
factor over historical levels in the wake of newly competitive
electricity markets following utility deregulation or \"open access.\"
Emission increases could also occur when new generation capacity is
constructed, but given today\'s over‑abundance of electricity and the
substantial capacity currently unused, new construction appears unlikely
in the near future. NOx emissions should decrease as a result of
existing regulatory requirements for NOx emission reductions and any
additional ones adopted in the future. In addition, any new generation
which is built may have significantly lower NOx emission rates.

Estimates of the magnitude of NOx emissions reductions necessary to
achieve attainment in the OTR range between 50‑85%. The 2005 CAAA
inventory estimate used in the Regional Oxidant Model (ROM) over the
OTAG \"Superdomain\" predicts that the following measures will achieve
only a 22% reduction in NOx emissions from utility sources between 1990
and 2005: \<\<\<*Cichanowicz Source?*\>\>\>

oCompliance with Title IV Acid Rain Phase I limits with no further NOx
emissions decrease during Phase II

oRACT controls on all boiler types

oNo Acid Rain or RACT controls on most Group 2 coal‑fired boiler types,
including cell burners

o65-year life for existing units

oDepartment of Energy (DOE) projections and default parameters for the
emissions production rate of new units

oSiting generic new units at existing plants

The above measures are neither particularly stringent nor adequately
protective of public health, and additional measures need to be
considered in light of: (a) the evident need for greater emission
reductions at upwind generating stations to abate the impact of long
range pollutant transport upon downwind jurisdictions; (b) increasing
scientific concern regarding the human health impacts of all utility
emissions (SO~2~, NOx, fine particulate matter, mercury, etc.) and
efforts currently underway to adopt more stringent NAAQS for ozone and
fine particles; and (c) the elevated upwind emissions likely to result
from the changing competitive environment for electric energy.

The nation is now undergoing concurrent and extraordinarily rapid change
in: (a) the improvement of the cost and performance of emission control
technologies; (b) the revision of state and federal regulatory
requirements, standards (e.g., ozone, fine particulate matter, regional
haze, and mercury), and even approaches; and (c) the replacement by
market forces of traditional regulatory oversight of utilities. Keeping
abreast of this moving target requires that new information or better
informed assumptions be brought into the OTAG process as they become
available.

**SECTION 4**

**UTILITY BOILER AND COMBUSTION TURBINES:**

**DESCRIPTION OF EQUIPMENT**

4.1. INTRODUCTION

This section briefly describes the important attributes of utility
combustion equipment used in both steam boilers and combustion turbines
which influences production of NOx. This discussion serves as a
background to the consideration of emission control options in the next
section.

4.2. STEAM BOILERS

Steam boilers are discussed below according to their classification in
the CAAA. Wall‑ and tangential‑fired dry bottom boilers are considered
Group 1 boilers; and cyclone, cell‑fired, wet‑bottom, and miscellaneous
boilers are collectively referred to as Group 2 boilers.

4.2.1. Wall‑fired Boilers (Dry Bottom, Group 1)

There are presently approximately 350 coal‑fueled, wall‑fired boilers
operating in the OTAG region, capable of 94,327 MW of generating
capacity. In 1990 (the latest year for which information is available),
this category of boilers produced approximately 1,724,000 tons of NOx
annually or about 31% of utility NOx emissions.

Wall‑fired boilers were manufactured by all four major boiler vendors
and represent the largest single design category (55% of installed steam
generation). Wall‑fired boilers employ individual burners, resulting in
the combustion of fuel in the immediate vicinity of the wall. Burners
are located in either one side (front fired) or both sides of the boiler
(opposed fired). Typically, boilers less than 300 MW are front fired
while most of the larger units are opposed fired. Uncon­trolled NOx
emissions from these types of boilers typically range from 0.7 lb/mmBtu
to 1.3 lb/mmBtu, depending on individual boiler design and coal type;
typical units run about 1.0 lb/mmBtu. Each of the four major boiler
manufacturers, as well as ancillary equipment suppliers, have recently
developed and retrofit many low NOx burners to older, existing furnaces
in response to the RACT requirements of Title I of the CAAA.

4.2.2. Tangential‑fired Boilers (Dry Bottom, Group 1)

There are presently approximately 350 coal‑fueled, tangential‑fired
boilers operating in the OTAG region, capable of 112,000 MW of
generating capacity. In 1990, this category of boilers produced
approximately 1,572,000 tons of NOx annually or about 28% of utility NOx
emissions.

Tangential‑fired boilers represent approximately 40% of the utility
boiler population. This type of boiler is characterized by fuel and air
introduction from the corners of the furnace, directed toward the
tangent of an imaginary circle in the center of the boiler. This type of
fuel firing system is generally believed to allow the overall furnace to
act as a single burner, with the fuel and air compartments serving as
injection ports. The slower mixing of fuel and air common in these
boilers results in lower NOx emissions than wall‑fired equipment.
Typical NOx emission levels for boilers constructed prior to 1970
(pre‑NSPS) are 0.6 to 0.8 lb/mmBtu. NOx emissions for the relatively few
units constructed after 1970 (post‑NSPS) range from 0.4 to 0.6 lb/mmBtu,
as many were equipped with overfire air (OFA) as described later in this
document. The typical emission rate for tangential‑fired boilers\--at
about 0.7 lb/mmBtu\--is lower than the typical emission rate for
wall‑fired boilers.

4.2.3. Cyclone Boilers (Group 2)

There are presently 77 coal‑fueled, cyclone‑fired boilers operating in
the OTAG region, capable of 22,329 MW of generating capacity. Based on
1990 emission rates, this category produced approximately 624,000 tons
of NOx annually.

Cyclone‑fired boilers, which comprise the largest category of Group 2
boilers, were manufactured exclusively by Babcock & Wilcox (B&W) from
the late 1940s to the early 1970s. Cyclone boilers are characterized by
the combustion of fuel in a separate, remote chamber connected to the
main furnace. Crushed bituminous and/or subbituminous coal is fed into
the cyclone furnace where it is fired under highly turbulent conditions,
creating the high temperatures required to melt the ash subsequently
removed at the furnace bottom through slag taps. Prior to 1971, this
design was an attractive alternative to pulverized coal‑fired boilers
since it: (a) allowed the burning of low grade (high ash) coals; (b)
significantly reduced the amount of fly ash in the flue gas thereby
reducing the size of the furnace and particulate collection equipment;
(c) reduced the degree of fuel preparation (i.e., elimination of
pulverizers); and (d) maintained a very high heat release rate.

Cyclone‑fired boilers have some of the highest NOx emission rates of all
utility boiler types. Typical uncontrolled cyclone NOx emission rates
range from 0.8 lb/mmBtu to 1.8 lb/mmBtu; averaging roughly 1.4 lb/mmBtu.

4.2.4. Cell‑fired Boilers (Group 2)

There are presently 33 coal‑fueled, cell‑fired boilers operating in the
OTAG region, capable of 24,143 MW of generating capacity. Based on 1990
NOx emissions rates, these units produce approximately 724,000 tons of
NOx annually.

The second largest category of Group 2 units in the OTAG region,
cell‑fired boilers employ multiple burners arranged in compact and
discrete \"cells.\" These units, designed and constructed by Babcock &
Wilcox, employ furnaces that feature either a 2‑burner or 3‑burner array
within one cell. The 2‑burner array dominates the cell‑fired boiler
inventory, and thus is the focus here.

The close proximity of burners within cell‑fired arrays and their
compact geometry creates an intense mixing process and high heat release
rate per unit volume of furnace, which promotes NOx formation. Unlike
cyclone boilers, cell-­fired units employ pulverized fuel (bituminous
coal), and thus approximately 80% of coal ash is entrained in flue gas
as fly ash.

In the past, conventional low NOx burners (LNBs) have been difficult to
apply to these units, as the delayed fuel and air mixing patterns
characteristic of LNBs create relatively long flames. During the last
four years, however, LNB concepts developed by Babcock & Wilcox and
Riley Stoker have been applied to cell‑fired boilers. In addition, the
original boiler manufacturer (Babcock & Wilcox) has developed a Low NOx
Cell Burner (LNCB) specifically for these units.

4.2.5. Slag Tap (Wet Bottom) Wall‑fired Boilers

There are presently 23 wet bottom, wall‑fired coal‑fueled boilers
operating in the OTAG region, capable of 4,712 MW of generating
capacity. Based on 1990 NOx emission rates, these units produced
approximately 291,000 tons of NOx annually.

Slag tap (wet bottom) wall‑fired boilers are similar to cyclone boilers
in that the high heat release rate furnace generates slag from coal ash,
which collects at the furnace bottom, and is ultimately removed through
a slag tap.[^8] These units were designed and constructed generally from
1950‑1960, almost exclusively by Babcock & Wilcox and the Foster Wheeler
Corporation.[^9] Like cyclone boilers, approximately 80% of the coal ash
is directed to slag, and the remaining 20% entrained in flue gas as fly
ash.

Though no LNB concepts have yet been applied to slag tap (wet bottom)
wall-­fired boilers, American Electric Power (AEP) successfully applied
air staging (overfire air) to one slag tap (wet bottom) boiler,
achieving greater than 40% NOx reduction at very low cost. In addition,
Public Service Electric & Gas (New Jersey) is experimenting with several
burner modification concepts that, if successful, could produce 15‑25%
reduction in NOx emissions.

4.2.6. Miscellaneous Boilers (Roof‑fired, Stoker‑fired Fluid‑Bed Group
2)

Several smaller categories of boilers cannot be classified in any of the
previously discussed boiler types. The two largest are considered in
this subsection.

[Roof‑fired]{.underline}. There are approximately 30 roof‑fired
coal‑fueled boilers operating in the OTAG region, capable of 3,111 MW of
generating capacity, which (based on 1990 NOx emission rates) produce
66,000 tons of NOx annually. A national total of 43 roof‑fired boilers
comprise 4191 MW of generating capacity, representing the fourth largest
category of Group 2 boilers.

Roof‑fired boilers (predominantly supplied by Babcock & Wilcox) employ
vertical coal nozzles located in the boiler \"roof,\" injecting
pulverized coal with combustion air. There are a wide variety of
roof‑fired boiler concepts, and depending on the specifics of fuel and
air admission, the flame can be J‑shaped, U‑shaped, or entirely
vertical. Design information on these units suggests that short furnace
residence times present difficulties in accommodating significant
staging or delay of fuel and air. Nevertheless, combustion modifications
have met with significant success in altering the mixing patterns to
reduce NOx emissions.[^10]

[Stoker‑fired]{.underline}. There are presently approximately 20 stoker
boilers comprising a total of 1160 MW of capacity in the OTAG region. No
estimate of NOx production from this category of boilers is available;
however it is undoubtedly negligible due to small generating capacity
and low capacity factor (typically \_% or less). \<\<\<*What %?*\>\>\>

Stoker boilers are generally moving chain grate units that fire crushed
coal or other solid fuels that require significant residence time for
acceptable combustion. Many utilities employ stokers to fire alternate
fuels as a supplement to coal (e.g., peat, shredded tires, etc.), so
these units often operate at a low capacity factor. Combustion NOx
control measures for stoker‑fired boilers are overfire air and flue gas
recirculation.

4.3. COMBUSTION TURBINES

Combustion turbines (CT) are essentially internal combustion engines
that employ a rotary rather than reciprocating motion to extract power.
Unlike boilers that provide steam for expansion in a separate steam
turbine, the CT is a single unit that creates and expands hot combustion
products to drive a shaft for power production.

There are three primary components to a CT: the compressor, combustor,
and the turbine. The compressor withdraws ambient air and pressurizes it
to approximately 30 times atmospheric levels since combustion at
elevated pressure improves efficiency and output. The configuration of
the combustor component dictates NOx formation.

NOx control strategies for CTs parallel those used for steam boilers:
reduce peak flame temperatures to minimize NOx formation from thermal
sources, and/or alternatively employ oxygen‑deficient combustion
conditions to minimize NOx production from fuel‑bound nitrogen. Details
of these strategies are summarized in Section 5.

4.4. RECIPROCATING INTERNAL COMBUSTION ENGINES

Compression ignition reciprocating internal combustion engines, commonly
referred to as \"IC engines\" are typically diesel engines whose niche
in electric utilities is to serve as peaking units; providing additional
generating capacity during conditions of exceptionally high electricity
demand.

These units are often more basic and less sophisticated than mobile
source diesel engines, although they are often supplied turbocharged.
The fuel most commonly used in these units is #2 diesel fuel.

NOx control strategies for diesel IC engines are three: targeting
combustion reductions by retarding ignition timing; reducing already
formed NOx through selective catalytic reduction (SCR); or employing
ultra low NOx alternative diesel fuels.

**SECTION 5**

**NOx CONTROL TECHNOLOGIES FOR UTILITIES**

5.1. INTRODUCTION

This section overviews commercially available control technologies used
to curtail NOx emissions from electric utility generating units
(boilers, combustion turbines, and internal combustion engines).

NOx formed during the combustion of fossil fuels can be controlled by
two principal strategies: (1) modifying the combustion process within
the \"flame envelope\" or within the furnace to reduce NOx formation;
and (2) inducing chemical mechanisms to bond with NOx after it has
formed, negating or \"destroying\" its character as an ozone precursor.
Generally speaking, modifications to the combustion process within the
\"flame envelope\" involve staging the introduction of air and fuel at
selected points of the combustion process in order to minimize the
generation of \"fuel NOx.\" Modifications to or within the furnace
itself endeavor to reduce furnace temperatures in order to avoid
producing \"thermal NOx.\"

The second strategy uses chemical reagents to convert already formed NOx
into molecular nitrogen, water, and small amounts of byproducts through
a chemical reaction known as \"reduction.\" This chemical reduction is
called \"selective\" because the reagent injected reacts only with NOx,
not with other flue gas constituents. Commonly used reagents are ammonia
(NH~3~) and urea. One process, effective in the temperature window of
1600 to 2100F, is called \"selective non‑catalytic reduction (SNCR).\"
A second process, known as \"selective catalytic reduction (SCR),\"
employs a catalyst to allow the reduction process to operate at
temperatures of 450 to 1100F. Catalysts are usually proprietary and
have a limited effective life (typically 6‑10 years).

5.2. NOx REDUCTION TECHNOLOGIES FOR UTILITY BOILERS

This section describes each of the major candidate NOx control
technology options: low NOx burners (LNB), overfire air (OFA),
reburning, selective non-catalytic reduction (SNCR), and selective
catalytic reduction (SCR). Fuel switching and hybrid NOx control
technologies are also briefly discussed.

5.2.1. Low NOx Burners (LNB)

[5.2.1.1. Process Description]{.underline}. Low NOx burners (LNB) delay
the mixing of fuel and air within the immediate \"flame envelope\" to:
(a) create lower combustion temperatures to control \"thermal NOx;\" and
(b) create chemical reduction zones within the flame to reduce NOx and
precursor species. For fuels with little or no nitrogen content (natural
gas and light oil), the key contribution of delayed mixing is to reduce
oxygen availability and extend flame length, thereby reducing both peak
and average combustion temperatures. For fuels with significant
fuel‑bound nitrogen (coal and heavy oil), delayed mixing serves to
create chemically reducing conditions retarding combustion of fuel‑bound
nitrogen to NOx within the flame envelope.

Generally, most LNBs are \"plug‑in\" mechanical devices that do not
require significant changes to boiler components. The physical condition
of the ancillary equipment that influences process conditions within the
flame can affect the performance of LNBs in terms of NOx control,
emission of carbon monoxide (CO) and the quantity and nature of
particulate matter (e.g., level of unburned carbon) and must be properly
maintained and operated. This ancillary equipment includes fuel
preparation (e.g., pulverization) hardware and combustion control
systems that determine burner‑to‑burner variations in air/fuel ratio.

Cell‑fired units represent a special case of wall‑fired boilers for
which special LNB systems have been developed. Specifically, in addition
to the Babcock & Wilcox Low NOx Cell Burner (LCNB) technology,
conventional LNB can be retrofit to these furnaces.

For tangential‑fired boilers, LNBs differ in implementation compared to
wall-­fired boilers. In contrast to wall‑fired boilers, where individual
burners establish a separate flame within an \"envelope,\"
tangential‑fired boilers employ a circular mixing pattern within the
entire furnace to mix and burn fuel and air. Thus, LNB for
tangential‑fired boilers influence the fuel and air mixing process
through biasing the fuel and air to different regions of the furnace.

[5.2.1.2. Retrofit Experience and Control Capability]{.underline}. LNBs
have been implemented on approximately 75,000‑100,000 MW of capacity to
comply with 1990 CAAA Title IV Phase I NOx limits, as well as RACT in
selected regions. LNB is the NOx control technology option with the
largest experience base in the United States. Several generations of LNB
have evolved in the last decade; the most recent designs even provide
for \"internal staging\" to create the physical and chemical conditions
to effectively control NOx within a compact \"envelope\" surrounding the
flame zone.

The experience from these installations suggests that typically, 40‑60%
NOx reduction is reasonably achievable depending on boiler design, coal
composition, and operating duty.[^11]

For cell‑fired boilers, at least six demonstration tests and early
commercial applications have employed either B&W\'s Low NOx Cell Burner
(LNCB) technology or conventional LNBs. Results from these activities
suggest that a 50% NOx reduction is reasonably achievable.[^12]

[5.2.1.3. Technical Feasibility]{.underline}. Most boilers can be
retrofit with some design of LNB. The specific design of the LNB in an
existing boiler depends on boiler design characteristics and fuel
properties, and whether other NOx control technologies are used. Three
key variables that LNB manufacturers consider when installing LNB are:

*Furnace Size / Heat Release Rate.* Most wall‑fired LNBs produce a
longer flame. A relatively small furnace per unit of fuel burned may not
be able to accommodate this extended flame length before flames impinge
upon an opposite wall. For these boilers, LNBs have to be selected and
operated with care to prevent impingement upon the rear wall.

This consideration presented problems for early LNBs, since flame
impingement can severely damage waterwalls and increase the frequency
and severity of boiler tube failures. Also, for coal‑fired boilers, the
change in heat release zone and the relocation of zones of
oxidation/reduction can alter patterns of slag accumulation on furnace
walls and the upper regions of the convective section. Fortunately, LNB
technology has evolved to mitigate these concerns, and LNBs are now
available for most applications.

*Boiler Operating Duty.* The load over which a boiler must perform,
defined by the frequency and extent of turndown ratio (e.g., low load
operation) can influence LNB operation. Maintaining precise balance
between fuel and air mixing systems depends on precisely controlling the
momentum of fuel and air introduced into the furnace.

Though current research indicates that LNB effectiveness varies with
load fluctuation much less than originally expected,[^13] NOx emissions
controls targeted toward units with higher capacity factors (and higher
emission rates) will still provide the greatest yield in terms of NOx
reductions. Further, over-­control on such units can greatly reduce
system average NOx emissions, potentially avoiding the need for controls
on units with lower load profiles. In addition, over‑control on high
load, high emission units will generate tradable NOx emission reductions
credits.

*Boiler Mechanical Features.* Besides the process‑related issues
described above, good LNB design can also mitigate mechanical
complications (e.g., waterwall locations, furnace division walls,
downcomers, windbox configuration, etc.) which could otherwise diminish
the cost‑effectiveness of retrofit LNBs.

5.2.2. Overfire Air (OFA)

[5.2.2.1. Process Description]{.underline}. OFA is another method to
further \"stage\" the main combustion zone to minimize the formation of
NOx. OFA also lowers combustion temperatures, thereby reducing the
formation of thermal NOx. Installing OFA generally involves additional
ductwork and the opening of new ports in the furnace wall above the main
burner zone. An exception to this rule on tangentially‑fired boilers is
\"close‑coupled\" OFA, which is accomplished by rearranging air buckets
and coal nozzles within existing burner openings. OFA is usually
installed in conjunction with LNBs, so the following discussion reflects
this combined application, denoted as LNB/OFA.

[5.2.2.2. Retrofit Experience and NOx Control Capability]{.underline}.
OFA experience is less than for LNB, but is still considerable
(approximately 20,000 MW) and includes many boiler types and fuels.
While OFA design was initially developed over thirty years ago, it has
improved in the last decade from first‑generation penetrations in the
upper furnace to advanced versions that provide significant control over
the quantity and velocity of injected combustion air. This retrofit
experience indicates OFA provides an additional 10‑20% NOx reduction
beyond that achievable with LNB alone.

[5.2.2.3. Technical Feasibility]{.underline}. The feasibility of
retrofitting OFA to existing boilers again depends on boiler design
characteristics and fuel properties. The principal design criterion is
available residence time above the burners to (1) adequately mix the OFA
with the combustion gases; (2) minimize unburned carbon; and (3)
minimize NOx formation. OFA may not be practical for boilers with
inadequate flue gas residence time between the top burner row and the
furnace exit. Adequate space and access to install OFA ductwork and
injection ports is also necessary.

Fuel properties also exert a significant role on the amount of OFA that
can be employed and hence the NOx reduction which can be achieved. Coal
selection must be carefully tailored with regard to propensity for
waterwall slagging, overall slag volume, and volatile carbon content.

5.2.3. Coal Switching: Bituminous to Subbituminous

[5.2.3.1. Process Description]{.underline}. Converting existing boilers
from firing bituminous to a subbituminous coal, such as Powder River
Basin (PRB) may require an extensive review of potential equipment
modifications and, if necessary, additions even at less than 100%
conversion. Equipment modifications or additions needed to handle larger
volumes of highly volatile, low Btu subbituminous coals can affect
several areas including: (a) boiler modifications; (b) pulverizers; (c)
electrostatic precipitator (ESP) and related particulate control
equipment; (d) coal storage and handling dust control; (e) inserting
systems for bunker fire protection, and (e) additional fuel delivery
train sets.

[5.2.3.2. Retrofit Experience and NOx Control Capability]{.underline}.
Since the Title IV (i.e., acid rain) provisions of the CAAA for SO~2~, a
significant number of utilities have switched coals from higher sulfur
to lower sulfur coals as an SO~2~ compliance strategy. Though most coal
switches were from high‑sulfur bituminous to low-­sulfur bituminous, some
utilities retrofitted to low‑sulfur subbituminous coals. It is estimated
that 50,000‑60,000 MW of coal‑fired capacity have switched or blended
fuels to meet the Phase 1 SO~2~ control limits. \<\<\<*Source of
estimate?*\>\>\>

Though there appears to be no difference is NOx emissions when switching
from high‑sulfur to low‑sulfur bituminous coals, NOx emissions can be
influenced (higher or lower) when switching to subbituminous coals. The
amount of NOx production (higher or lower) resulting from conversion to
subbituminous coal depends on the properties of the subbituminous fuel
compared to the original fuel, the fraction of fuel consumption
converted, and the impact of fuel characteristics on the boiler. Based
on experience with current coal conversions, NOx reduction on the order
of 20‑40% can be expected when switching to Powder River Basin
subbituminous coal. Several units in the Southern Company
system\--originally designed to meet NSPS-‑are firing Powder River Basin
coal and have demonstrated NOx reduction of approximately 40%. These
units are: (a) Plant Miller Unit 4 (660 MW, wall‑fired); (b) Plant
Daniel Units 1 and 2 (each 500 MW, tangential‑fired); and Plant Scherer
Units 3 and 4 (818 MW, tangential­-fired).

[5.2.3.4. Technical Feasibility]{.underline}. Converting most existing
coal‑fired boilers from bituminous to subbituminous coal is generally
feasible, but difficult to project in terms of cost. The cost to modify
the boiler and plant fuel handling systems is highly variable, ranging
from approximately \$15/kW to \$60/kW. Newer boilers, such as those
designed to meet NSPS, may not require significant cost ho convert to
subbituminous coals, and may not incur performance penalties. Because of
highly variable cost and boiler/plant impacts, conversion to
subbituminous coal is not included in the Summary Matrix.

In addition to switching to subbituminous fuels, several organizations
(e.g., Shell Oil) are developing processes to produce ultra low nitrogen
content fuels to provide NOx reductions in commercial systems.

5.2.4. Fuel Switching: Coal to Natural Gas

[5.2.4.1. Process Description]{.underline}. Converting coal‑fired
boilers to 100% natural gas firing requires: (a) natural gas access at
the site; and (b) modifying existing burners for dual fuel capability,
if that capability is not pre‑existing. For conventional or low NOx
circular burners on one or opposed walls in the furnace, the retrofit of
100% gas firing can be accomplished with the addition of gas spuds,
canes, or gas rings. Tangential burners in the corners of the furnace
can also be modified to accommodate gas firing without affecting
coal‑firing or oil‑firing capability. For units with existing gas
capability, switching to natural gas is a relatively low capital cost
control option; for those without natural gas availability at the site,
fuel switching is unlikely to be an economic alternative.

[5.2.4.2. Retrofit Experience and NOx Control Capability]{.underline}.
The NESCAUM-­MARAMA Phase 2 NOx Control Technology report (Castildini,
1995) lists approximately 4000 MW of coal‑fired boilers that have
converted to 100% natural gas firing for at least part of annual
operation. Data from these units show conversion to natural gas can
reduce NOx from 25‑75%, depending on the combustion firing system and
operating load.[^14] The relatively wide range of NOx reduction is due
to the strong interrelationship between NOx production mechanisms and
furnace design, and the method of natural gas introduction into the
furnace and flame zone, as previously described.

Applying combustion modifications appropriate for natural gas‑firing
will provide additional NOx reduction beyond that derived simply by
switching to natural gas. These combustion modifications include
techniques such as flue gas recirculation (FGR) and burners‑out‑of
service (BOOS).

[5.2.4.3. Technical Feasibility]{.underline}. Converting coal‑fired
boilers to natural gas is technically feasible. Both compromises and
improvements to selected performance features can accompany a switch to
natural gas. These compromises or improvements include:

o*Capacity Derate or Increase.* Natural gas delivers less heat to the
furnace per unit volume of combustion products. Por boilers in which
flue gas handling capacity limits heat delivered to the furnace, steam
and power production will be compromised. However, this capacity derate
penalty\--which can be 5‑15% of maximum capacity\--is not encountered in
many applications. Conversely, it is also possible that conversion to
natural gas could increase net generating capacity, particularly for
cases where: (a) the significant auxiliary power burden necessary for
coal‑firing is removed due to the use of gas; (b) furnace slagging
limits boiler steam production; and (c) draft fan capacity does not
limit maximum operating load.

o*Steam Production Characteristics.* Firing natural gas reduces furnace
gas exit temperature (FGET), distorting the heat delivered to
superheat/reheat sections, altering the characteristics of steam
produced, and impacting performance and turbine efficiency, as well as
generating capacity. As noted above, however, these characteristics of
conversion may represent compromises or improvements, especially in net
generating capacity.

o*Thermal Efficiency.* Boiler thermal efficiency can be reduced by
firing natural gas due to the higher hydrogen/carbon ratio of the fuel,
and the higher latent heat losses. The magnitude of this reduction can
typically be 1‑2% of boiler thermal efficiency. Depending on the
specific unit, however, some, all, or more than this penalty may be
compensated by the reduction in auxiliary power necessary to operate
equipment to support coal‑firing (pulverizers, ESP, sootblowers, etc.).

There are additional benefits to switching to natural gas, related to
both environmental and performance issues. Specifically, the use of
natural gas reduces emissions of SO~2~, opacity/particulate, and CO~2~.
Operating benefits are the potential for reduced maintenance
expenditure, coal inventory, and the influence of ash deposition. In
addition, improvements to peak capacity, tolerance to coal type, unit
availability, ash quality and resale value, minimum load achievable, and
startup are also possible.[^15]

5.2.5. Fuel Reburning

[5.2.5.1. Process Description]{.underline}. Reburning redistributes a
portion of both fuel and air into the upper regions of the furnace to
create a second flame zone, genera­ting chemically reducing conditions to
destroy NOx. In most fossil fuel‑fired boilers, reburning is applied
between the upper burner row and the furnace exit, and any fuel can be
utilized as the \"reburn\" fuel. Most reburn applications divert between
10‑20% of the total heat throughput to the upper furnace. Reburn
installations are engineered to maintain acceptable furnace and boiler
performance while diverting heat release and absorption from the lower
regions of the furnace (dominated by radiant heat transfer) to the exit
(dominated by convective heat transfer), minimizing unburned carbon.

At least five coal‑fired demonstrations of reburn are either operating
or completed, and several additional demonstrations are expected to be
operational within the next 6-12 months. Reburn technology does not
impose new operating requirements upon the boiler maintenance staff, and
the only modification is the relocation of fuel and air into ports in
the upper furnace region. On the contrary, reburning, particularly with
natural gas, provides significant operational flexibility due its
ability to be \"tuned\" for specific boiler conditions. In addition,
gas‑based reburning provides collateral benefits through reduced
emissions of air toxics, mercury, and SO~2~ and diminished solid waste
(ash) concerns.

Further, the \"winter peaking\" character of the natural gas demand
stands in direct contrast to the summertime peaking of ozone production.
This phenom­enon, in conjunction with an emission reduction credits
trading program, allows gas reburn to provide sources with substantial
compliance flexibility. In the summer, low NOx emissions can be produced
since natural gas is typically plentiful. In the winter, natural gas
availability may be curtailed by high demand, but ozone production is
also curtailed. Thus, a compliance strategy combining gas reburn and
credit purchases could enable utilities to achieve the requisite total
NOx at a much lower cost than anticipated. Cost savings over year round
gas delivered under relatively expensive \"firm\" (vs. lower cost
\"interruptible\") contracts would be substantial, reducing compliance
costs materially from those currently predicted.

NOx control for coal reburning is determined by several site‑specific
factors including: flue gas residence time between the upper burner row
and furnace exit, ability to locate reburn fuel injectors to allow
adequate mixing with combustion products at the furnace exit, induced
draft fan capacity, margin of acceptable operation of ESP and fly ash
handling/disposal, availability of flue gas recirculation equipment, and
space for reburn fuel supply equipment (e.g., pulverizers). Site
specific factors for gas reburning are similar for boilers themselves,
though few if any\--including residence time\--appear to limit the
applicability of reburn technology to most coal‑fired boilers. Gas
reburning is also much less onerous regarding fuel‑related issues and
equipment (e.g., pulverization, ESP, ash, slagging, etc.).

[5.2.5.2. Retrofit Experience and NOx Control Capability]{.underline}.
Five demonstrations addressing natural gas and coal reburn have been
either completed or are now operational that show the broad potential of
the technology.

For natural gas reburn, these units are:

oIllinois Power\--Hennepin Station: approximately 75 MW; pulverized
coal; complete.

oPublic Service Company of Colorado\--Cherokee Station: 158 MW;
pulverized coal; operational.

oOhio Edison\--Niles Station: 100 MW; cyclone; complete.

oCity Water Light & Power (CWL&P): 33 MW; cyclone; complete.

Reburning with coal has been demonstrated at:

oWisconsin Power & Light (WP&L)\--Nelson Dewey Station: approximately
100 MW; cyclone; operational.

Several additional natural gas reburn demonstrations are underway and
will soon be producing data. Eastman Kodak Company\'s Unit No. 43
(equivalent to 60 MW) started up on February 5, 1996 and is now
undergoing acceptance testing. New York State Electric & Gas is
installing gas reburn (with commercial guarantees) on Greenidge Unit 6,
a 105 MW tangential‑fired boiler with a current low NOx firing system;
this unit is scheduled to be operational by the 1996 ozone season. Also,
the Gas Research Institute is scheduled to test low‑cost gas reburn
approaches at Duquesne Light\'s Elrama Unit 1 or 2 (112 MW, roof‑fired)
in May 1996, and at Commonwealth Edison\'s Joliet Unit 6 (a 337 MW
cyclone) in September 1996.

In addition, natural gas reburn is being installed on a 600 MW unit in
Scotland, and a 300 MW unit is operating in the Ukraine. Italy has
extensive experience with oil reburning and has a gas reburn
installation planned. Detailed discussion of most of these
demonstrations can be found in the reburn technology sessions of the
1991, 1993, and 1995 EPRI/EPA Joint Symposia On Stationary Source
Combustion NOx Control.[^16]

Reburn NOx control efficiency is the subject of some debate between
reburn technology developers and potential utility end‑users. Results
from the referenced demonstrations suggest NOx reductions as high as
65‑70% can be achieved with natural gas reburning, and as high as 60%
with coal reburning. The NESCAUM‑MARAMA Phase II report cites NOx
reduction by gas reburn as 40‑65% from uncontrolled levels and 25‑50% in
post‑RACT applications. Utility end‑users consider 50‑60% NOx reductions
to be more accurate. One utility analysis, however, is quite consistent
with both current vendor guarantee ranges of 55‑62% from uncontrolled
levels and the NESCAUM‑MARAMA figures. It suggests that gas reburn NOx
control for pulverized coal‑firing is 54‑62% for uncontrolled pre‑RACT
deployment, and 40‑45% for post‑RACT deployment.[^17]

\"Utility vs. developer\" disputes thus have little merit at this point.
With technology developers willing to guarantee NOx reductions in the
range of 55-62%, reburn technology is now in a position to let the
commercial marketplace determine first‑hand what reductions are
possible, at what costs, and with what guarantees. Detailed engineering
design studies have been prepared for several large boilers in the U.S.
which confirm the applicability of natural gas reburning to these units.
Further, at least two vendors, Energy and Environmental Research
Corporation (EERC) and Babcock & Wilcox (B&W), are actively marketing
this technology to utilities for most boiler configurations, complete
with performance guarantees.

[5.2.5.3. Technical Feasibility]{.underline}. Generally, both gas and
coal reburn can be applied to pulverized coal and most Group 2 boilers.
Technical feasibility is considered separately in the following
discussion:

[Gas Reburn]{.underline}. Key factors influencing the technical
feasibility of gas reburn are: the boiler design; the ability of the
furnace materials to resist corrosive actions created by fuel‑rich
conditions in the reburn zone; and the supply and availability of
natural gas at the site.

o*Boiler Design.* Traditionally, reburn has been considered feasible
only for boilers in which sufficient residence time is available in the
main furnace to allow for the injection, mixing, and subsequent reaction
of secondary (reburning) fuel and combustion air. As noted previously,
adequate residence time from the top burner to where reburn fuel is
injected has been believed necessary for reburning to be feasible. For
gas reburning, a residence time of about 1.2 seconds has been considered
appropriate, based on general experience to date (DOE, 1994). This
duration is also consistent with a recent statement by Babcock &
Wilcox[^18] that 1.0 second is necessary from the reburn burners to the
furnace exit.

This traditional residence time caveat is in some doubt today, however.
Gas reburn achieved a 64% NOx reduction on CWL&P\'s 33 MW cyclone with
only about 0.25 seconds available. Further, a reburn installation on a
[roof]{.underline}‑fired unit is currently underway at Duqesne Light\'s
Elrama Station. One gas reburn vendor believes that there is no minimum
residence time requirement for gas reburn, though NOx removal and
quantity of natural gas required could be affected for units with
shorter residence times.[^19] Experience to date suggests that most
boilers will possess adequate residence time to accommo­date effective
natural gas reburning.

o*Furnace Corrosion Resistance.* Reburning requires that a fuel rich
zone within the furnace (corresponding to a reburn zone stoichiometry of
0.9) be maintained for an adequate residence time. This can expose the
furnace walls to oxygen deficient conditions, which can promote
corrosion. However, this surface chemistry is fairly well understood and
detailed modeling, measurement, and testing have been directed toward
this issue. As a result, today\'s reburn process designs generally
ensure adequate excess oxygen near the furnace walls to minimize this
problem. Experience to date with long-­term reburn demonstrations has not
identified serious corrosion problems.

o*Gas Availability.* Natural gas must be accessible at the site in
sufficient quantity and under commercially acceptable conditions (e.g.,
cost and availability guarantees), since the price of natural gas in
relation to coal for long‑term use is the key reburn cost factor. The
availability and cost of providing a reliable long‑term supply of
natural gas must be considered in the context of local and national
energy markets which, in the case of natural gas, are increasingly
deregulated. As a result, gas supply pricing, transportation, and
services options open to potential utility end‑users should continue to
increase.

Fortunately, concerns about commodity natural gas supplies and pipeline
availability are largely mooted by the fact that a large proportion of
boilers suitable to gas reburn application are located in the Midwest
where pipeline capacity is abundant. For example, of the 89 Group 2
cyclone boilers affected by EPA\'s proposed Phase II NOx Control NOPR
(Acid Rain), 77 of them are so situated. In fact, 55% of these units
either have gas service on site or are within five miles of major gas
transportation pipelines.

Another interesting feature of gas reburn is the potential ability to
recoup capacity losses incurred with a switch to subbituminous coal, due
to a change in fuel preparation or ashing characteristics that influence
fuel pulverization or boiler slagging characteristics.

[Coal Reburn]{.underline}. Employing coal as the reburn fuel entails
feasibility issues similar to gas reburning.

o*Boiler Design.* As with gas reburning, most important is upper furnace
residence time, which due to coal combustion characteristics, must be
greater than for gas reburning (approximately 1.5 sec).[^20]
Accordingly, boilers for which gas reburning is technically feasible may
not be able to accommodate coal‑reburning. Other issues, such as the
ability to retain superheat/reheat temperature, aggravated
slagging/fouling characteristics, and possible corrosive actions within
the fuel‑rich reburn zone are also of interest.

o*Furnace Corrosion Resistance.* Corrosion can be a concern for coal
reburn, as the fuel‑rich reburn zone contains a number of potentially
corrosive species derived from sulfur and trace elements in certain
types of coal. However, results after two years operation of the WP&L
Nelson Dewey demonstration do not indicate any significant furnace
corrosion problems.

o*Particulate Collection.* For cyclone boilers, coal reburn typically
increases ash loading to the particulate collector. Higher particulate
emissions may result if the ESP is sized marginally for the inlet
loading.

5.2.6. Selective Non‑Catalytic Reduction (SNCR)

[5.2.6.1. Process Description]{.underline}. Selective non‑catalytic
reduction (SNCR) typically employs chemical injection of urea into the
flue gas near the furnace exit or in the convection pass to chemically
reduce NOx to nitrogen. Ideally, reagent injection is within the
1800‑2100F flue gas temperature window, although for nearly all
commercial retrofits the injection equipment has been installed between
1700-2400F. The physical location of this temperature zone in the
boiler changes with load. The relatively high temperatures of flue gas
in these boiler sections promote high reaction rates so a catalyst is
not required for significant NOx removal.

Reagent injection into the appropriate temperature zones sets up a
series of competing chemical reactions whose aggregate \"sum\" at the
furnace exit is: (a) a reduction in NOx; (b) molecular nitrogen and
water vapor; and (c) trace amounts of ammonia (NH~3~) referred to as
\"ammonia slip\" or \"residual NH~3~.\" Ammonia slip can be more
pronounced as: (l) the reaction temperature decreases; or (2) excessive
levels of reagent injection are applied in an effort to achieve NOx
reductions beyond the capability of the specific unit.

Additionally, employing urea reagent (NH~2~COH~2~) may produce N~2~O (a
\"greenhouse gas\") as a byproduct. Flue gas SO~3~ content is also a
factor influencing SNCR feasibility when firing higher sulfur fuel oils
and coals due to the potential for fouling some types of air heaters.
However, this effect could also encourage less firing of high sulfur
coal, with attendant benefits concerning sulfur and particulate
emissions.

[5.2.6.2. Retrofit Experience and NOx Control Capability]{.underline}.
SNCR has significant experience on a wide variety of industrial and
utility fuel burning equipment, and in recent years has been deployed
extensively on utility boilers firing a wide range of fuels. SNCR
installation in Europe has been particularly widespread. Recent utility
demonstrations or commercial applications in the United States include:

oPulverized Coal‑fired Boilers:

\--New England Power: Three units at Salem Harbor Station (85‑155 MW)

\--Eastern Utilities: One unit at Somerset Station (112 MW)

\--Pennsylvania Electric Company: One unit at Seward Station (160 MW)

oCoal‑fired Cyclone Boilers:

-‑Atlantic Electric: Two units at B.L. England Station (Unit 1, 138 MW
firing 2.8% sulfur coal, is now in commercial service. Unit 2,160 MW,
will have SNCR applied in Demonstration and Test in the near future.)

\--Public Service of New Hampshire: Merrimack Unit 1 (120 MW)

oWet‑bottom Pulverized Coal‑fired Boilers

-‑Public Service Electric & Gas Corporation: Mercer Station, Units 1 and
2 (each 320 MW units; comprised of parallel 160 MW furnaces) \<\<\<*SNCR
or SCR or Both?*\>\>\>

oResidual (Heavy) Oil‑fired Boilers:

‑‑Connecticut Light & Power: Two units at Norwalk Harbor Station
(170 MW each)

-‑Atlantic Electric: B.L. England Unit 3 (160 MW)

-‑Delmarva Power & Light Edgemore Unit 3

Acceptable ammonia slip levels and the NOx reduction points at which
slip appears both vary on a case‑by‑case basis. As a result, SNCR design
parameters and operating procedures for any given unit are specified to
maximize NOx reduction while staying below unacceptable ammonia
emissions levels.

In the above cyclone demonstration units, NOx reduction of 25-40% was
achieved. NOx reduction at one permanent commercial installation was 20%
at 5 ppm slip. During initial commercial operation of SNCR at New
England Power\'s Salem Harbor Unit 1, NOx reduction of 60% was achieved
on a continuous basis with NH~3~ slip of 10-20 ppm. The reductions
achieved on Salem Harbor Unit 3 were somewhat lower, averaging about
55‑60%. The overall emission rates were reduced from 1.0 lb/mmBtu to
0.33 lb/mmBtu.

It is important to note that in many retrofit applications, a
combination of technologies will be applied to optimize both the NOx
reductions achieved and the costs incurred. For example, prior to
installing LNB at Salem Harbor Unit 2, tests indicated that SNCR could
achieve a maximum of 60‑70% reduction with SNCR alone, but this would
have resulted in significant ammonia slip and corresponding
deterioration of ash quality. SNCR alone would have reduced NOx
emissions by only about 50% before encountering ammonia slip (\<10 ppm)
and ash quality problems. Since this unit was required to meet an
emission limit of 0.33 lb/mmBtu on a long‑term basis (i.e., about 67%
reduction from its baseline of about 1.00 lb/mmBtu), the utility elected
to install LNB to essentially cut the unit\'s baseline NOx in half and
then to use SNCR to \"trim\" the resulting emissions to meet the
regulatory limit of 0.33 lb/mmBtu. This combination of LNB and SNCR
eliminated the NH~3~ slip problem as well as its impact on ash quality.
Other hybrid technology applications now being demonstrated also offer
great promise.

[5.2.6.3. Technical Feasibility]{.underline}. SNCR feasibility for
existing plants is dictated by the ability to: (1) distribute reagent
into the boiler to maintain optimum NOx removal without residual NH~3~
over a range of load and operating conditions; and (2) minimize the
influence of any process byproducts (e.g., residual NH~3~) on plant
equipment.

o*Reagent Distribution.* To achieve acceptable NOx reduction, reagent
must be properly distributed within an appropriate temperature range;
current commercial applications range from 1700‑2400F.

Boilers that operate in a cycling manner over a wide load range require
more complex injection and control systems, which account for higher
capital cost in the range presented in the Summary Matrix. As noted
previously, however, it is unlikely that SNCR would find initial
application in cycling units. NOx reduction credit (or \"allowance\")
trading should reduce or eliminate the need for such high capital costs
to be incurred. Note also that at present, the largest successful SNCR
application in the U.S. (PSE&G\'s Mercer Station) is comprised of two
parallel 160 MW furnaces.

o*Byproduct Formation.* As noted previously, the level of NOx reduction
attainable may be limited by site‑specific tolerance limits for NH~3~
slip. Excessive slip can promote deposits of ammonium sulfates and
bisulfates on heat exchanger surfaces, and/or be adsorbed by and
contaminate particulate in flue gas. This is a concern when firing
higher sulfur coal.

Formation of NH~3~ and N~2~O byproducts is discussed below for three
categories of fuel to which SNCR can be applied:

[Residual NH~3~ from Firing Natural Gas]{.underline}. Without sulfur
compounds or fly ash present in flue gas, residual NH~3~ becomes a local
regulatory issue rather than an equipment operating limit. Conceivably,
up to 10‑20 ppm slip could be tolerated, while achieving maximum NOx
reduction. No byproducts are produced that deposit on downstream
equipment.

[Residual NH~3~ from Firing Fuel Oil]{.underline}. The presence of
modest amounts of sulfur in fuel oil poses potential deposition and air
heater fouling from ammonium sulfate/bisulfate compounds. Possibly the
most relevant experience\--though now over three years old\--is from
Long Island Lighting Company\'s (LILCo) Port Jefferson (New York)
Station SNCR demonstration. Residual NH~3~ of 10 ppm was ultimately
selected for this site as a maximum level, and most current SNCR
applications in the U.S. are limited to this level.

[Residual NH~3~ from Firing Coal]{.underline}. Experience in the U.S.
defining acceptable levels of NH~3~ slip with SNCR is growing. At
present, nine pulverized low-­sulfur coal‑fired stations use SNCR
commercially; their experience suggests 5‑10 ppm slip is the best range
to maximize NOx reduction and minimize operational impact.

[N~2~O]{.underline}. SNCR may produce N~2~O (a contributor to global
climate change) when urea is used as the reagent. N~2~O production is
not a fundamental flaw in urea-based SNCR, however, because methods to
mitigate its production may be available.

5.2.7. Selective Catalytic Reduction (SCR)

[5.2.7.1. Process Description]{.underline}. Selective catalytic
reduction (SCR) employs ammonia injected into the flue gas near the
economizer exit to reduce NOx to molecular nitrogen. A catalyst is
employed to achieve significant NOx removal and ammonia utilization at
flue gas temperatures that are appropriate for process reactors. SCR can
be applied to flue gas in the temperature range of 450‑1100F, but is
frequently applied at 525‑750F. Two byproducts are generated from SCR:
(a) residual ammonia or \"slip,\" due to imperfect mixing or reaction of
the reagent; and (b) SO~3~, which is oxidized from SO~2~ by the
catalyst.

These byproducts are easily managed at the design stage:

o*Ammonia slip is a design variable.* SCR systems are designed and
operated based on the maximum ammonia slip acceptable at a given source.
Maximum ammonia slip for coal‑fired designs is typically 5 ppm. At sites
where this concentration is problematic, however, additional catalyst
can be employed to lower the concentration further. Further, substantial
recent progress in controlling ammonia slip is evident in the design and
operation of new coal‑fired boilers. For example, U.S. Generating\'s
Carneys Point (NJ), Logan (NJ), and Indiantown (FL) units, operating
24,18, and 5 months respectively, have ammonia slip levels under 0.2
ppm.

o*SO~2~ to SO~3~ oxidation is also a design variable.* Since oxidation
is controlled by catalyst selection, SO~2~ oxidation to less than 1% can
be provided.

Generally, SCR can be applied to almost all generating units; one simply
designs the installation for appropriate control of residual NH~3~ and
oxidation of SO~2~ to SO~3~. These process design decisions are not
completely unconstrained, though, since adding catalyst to lower ammonia
slip also increases SO~2~ oxidation. In practice, however, a balance
between these competing variables can be and has been achieved.

In Europe, coal‑fired SCR installations were initially designed for a 5
ppm slip limit (Rentz, 1992). Based on experience with absorption of
NH~3~ by fly, ash, several units have found it necessary to increase the
amount of catalyst and lower the maximum NH~3~ limit to 2‑3 ppm (Rentz,
1992; Necker, 1989). A residual NH~3~ limit of 5 ppm on an average basis
(i.e., with occasional higher \"spikes\" allowed) may be broadly
acceptable for low‑sulfur coals depending on the flue gas fly ash
content and composition. Key to controlling the ammonium
sulfate/bisulfate deposition byproducts is minimizing production of
SO~3~ from SO~2~.

A key factor in SCR operations is the frequency with which catalyst must
be replaced to meet NOx reduction and residual NH~3~ performance
targets. Until recently, catalyst replacement frequency was a source of
debate between SCR control equipment suppliers and utility users.
However, recent catalyst technology has made substantial advances, and
catalyst suppliers are now willing to subject their product life cycles
to rigorous, lengthy commercial guarantees.[^21] European experience
indicates that coal‑fired boilers employing a proper catalyst management
strategy will enjoy an average catalyst lifetime of 6-10 years. Vendors
for PSNH\'s MK2 commercial SCR installation guaranteed a catalyst life
of 6 years; PSNH itself anticipates an 8‑year life. New coal‑fired
boilers (e.g., U.S. Generating\--Carneys Point and Stations in New
Jersey) are securing vendor guarantees of a 10 year catalyst life. For
oil‑ and gas‑fired boilers, catalyst suppliers are confident that an
8‑12 year lifetime is possible. Utility users typically use a 6‑year
life in planning exercises. As discussed in a subsequent section, these
assumptions are important in determining SCR cost.

Ammonia handling has also made significant strides. In the past, this
was a source of great concern; however aqueous‑based ammonia handling
systems for SCR are often less troublesome than systems handling
non‑aqueous ammonia, typically for SNCR applications.

[5.2.7.2. Relevant Experience and NOx Control Capability]{.underline}.
The design flexibility and superior performance of SCR in achieving NOx
reductions has led to its adoption over a wide variety of fuel and
boiler characteristics. As noted above, SCRs are designed taking into
account acceptable levels of residual NH~3~ and additional SO~3~. These
two design factors can vary between different applications and fuel
types in a manner described as follows:

*Coal‑fired Applications.* Most early coal‑fired applications are
located in western Europe (notably Germany) and Japan. Total inventory
of coal‑fired SCR approximates 50,000 MW. \<\<\<*Any data on \# units by
country and new vs. retrofit?*\>\>\> A NOx reduction of 80% is the usual
target for coal‑fired applica­tions, though some units in Germany provide
NOx reductions as high as 90%. These higher reductions have been
properly targeted toward baseloaded, high-­inlet NOx units. European
coals are typically of Australian, German, and Polish origin with sulfur
content of 1.5%. However, high‑sulfur coal applications exist. In some
cases, American coal is used.

The success of SCR applications overseas, coupled with major recent
advances in catalyst chemistry (e.g., resistance to premature catalyst
\"poisoning\" by the arsenic commonly found in U.S. coals) has fostered
a rapidly increasing experience base in the U.S., with SCR installations
both on new units and retrofit applications. Two new coal‑fired
units\--U.S. Generating Company\'s Chambers and Keystone Works\--are now
operating with SCR. Three additional coal‑fired SCR units\--U.S.
Generating Company\'s Indiantown Station, Orlando Utilities\' Stanton
Station, and Southern Electric International\'s Birchwood Station\--are
under construction and will be operational within the next two years.
These five facilities total approximately 1,200 MW.

The first major U.S. retrofit installation of SCR on a coal‑fired unit
became operational in June 1995 on Merrimack Station Unit #2 (MK2)
operated by Public Service of New Hampshire. A cyclone boiler firing
1.5% sulfur coal, this unit generates 320 MW. Typically baseloaded, MK2
had average hourly uncontrolled NOx emissions of 2.4 lb/mmBtu, with a
maximum uncontrolled NOx emission rate of 2.66 lb/mmBtu.

Initially, MK2\'s NOx emissions rate was reduced from these levels to
0.92 lb/mmBtu, i.e., from 110 tons per day (TPD) to 37 TPD, for a
reduction of about 65% with 5 ppm NH~3~ slip. However, the unit\'s SCR
reactor and ductwork was designed and built to meet OTC NOx MOU Phase
III requirements (about 0.30-0.40 lb/mmBtu, 15 TPD, or 86% NOx
reduction) simply by adding an additional layer of catalyst in the
reactor. This \$18.5 million retrofit includes \$14 million capital cost
in 1995 and \$4.5 million for future catalyst addition. Annual ammonia
and operating expenses are expected to be \$1.5 million. The capital
cost for this retrofit was \$57.7/kW; the cost of NOx removed is about
\$400/ton.

The physical layout of MK2 made its retrofit particularly challenging.
The distances between the boiler and its electrostatic precipitator
(ESP), and between the ESP and the stack, are exceptionally limited, so
the retrofit required splitting and extensively re‑routing the
pre‑existing flue gas ductwork. Also, flue gas handling ductwork was
strengthened in the event the unit is ultimately converted to balanced
draft gas handling. This retrofit did not require upgraded fan capacity
or air heater changes, but it was made more complex by an unusually
aggressive compliance schedule. A project of this magnitude typically
takes over a year to complete; this installation was completed in about
six months despite winter construction conditions. Nevertheless, MK2\'s
SCR has been operating above expectations since July 1995.

The cost effectiveness of the MK2 SCR retrofit has been criticized on
the basis that its unusually high uncontrolled NOx emissions result in
an artificially low per ton NOx removal cost. However, even if MK2\'s
pre‑control NOx emission rate were 2.0 lb/mmBtu or 1.4 lb/mmBtu instead
of 2.6 lb/mmBtu, the \$400 per ton removal cost would only increase to
\$521 and \$745 respectively, even before reduced ammonia and catalyst
costs are subtracted. Thus, even if MK2 had had an uncontrolled NOx
emission rate closer to an average cyclone boiler, its cost
effectiveness per ton of NOx removed would remain well within EPA\'s
1994 estimated RACT cost range (\$160‑\$2,000 per ton). Indeed,
precisely because of its low per‑ton retrofit costs, New Hampshire air
regulators determined that RACT for this unit was SCR.

Finally, note that under the NOx emission reduction trading systems
currently being developed, targeting individual coal‑fired units with
unusually high uncontrolled NOx emission rates for prompt SCR retrofit
would maximize NOx reduction benefits for the costs incurred. Such
prudent economic and environmental behavior can be anticipated when
regulatory flexibility (vs. broadly applicable technology mandates) and
rational market dynamics are combined.

*Dual‑Fuel (Fuel Oil and Natural Gas) Applications.* Dual‑fueled
applications exist in Europe, Japan, and some North American sites.
Residual NH~3~ can react with SO~3~ in fuel oil since the modest
quantities of sulfur in fuel oil (0.2‑1%) are sufficient to generate
SO~3~ levels similar to coal‑firing. \<\<\<*Source?*\>\>\> A residual
NH~3~ limit of 5‑10 ppm is anticipated for fuel oil‑fired SCR
applications. NOx reduction of 80‑90% is possible under these
conditions.

*Natural Gas Applications.* Most recent SCR installations in southern
California are designed for virtually exclusive firing on natural gas.
(Though natural gas is the principal fuel, SCR has been designed for 500
hours per year firing heavy (#6) fuel oil.) Natural gas firing has
enabled small pitch, high activity catalysts to be applied. Several
innovative design concepts have been employed that reduce reactor size
and initial cost. These innovative \"in‑duct\" designs are in part
responsible for the decrease in capital cost witnessed for natural gas
SCR applications in recent years. For example, the overall capital cost
for Southern California Edison declined by nearly three‑quarters, from
\$1 billion to \$290 million.

At present, 4,000 MW of gas‑fired SCR capacity is operational in the
U.S., and it is likely that significantly more capacity will be
operating by 1999. Residual NH~3~ of 10-20 ppm is allowed (if also
allowed by the local regulatory agency). Accordingly, NOx reduction of
90% has been achieved for many of these applications. Southern
California Edison\'s systemwide emission limit of 0.015 lb/mmBtu has
been achieved for over two years.

[5.2.7.3. Technical Feasibility]{.underline}. SCR design and cost for
existing plants is dictated by: (1) the ability to locate a reactor
within the proper temperature window between the economizer and air
heater (applicable to high‑cost SCR retrofits only); and (2) the desire
to minimize any byproduct deposition on plant equipment. Generally,
there are few technical issues with regard to the engineering and
performance of the catalytic reactor in flue gas, since most performance
parameters are design variables. The principal engineering task is to
integrate the SCR process and reactor into the plant in a fashion that
minimizes impact on existing operations.

A major, two‑year technical demonstration of SCR on high‑sulfur coal
(2.8%) was recently completed by the Southern Company at Georgia
Power\'s Plant Crist. Sponsored by the Electric Power Research Institute
(EPRI) and the U.S. Department of Energy, with contributing efforts by
eight major catalyst suppliers, this study demonstrated catalyst
performance under high‑sulfur coal process conditions to be acceptable,
with catalyst deactivation rates as projected by the suppliers. Some
operating issues, however, (e.g., maintaining acceptable air heater
performance and integrating reactor performance with the boiler
economizer) have not yet been fully resolved for high‑sulfur coal
process conditions.

Thus, while several engineering issues must be faced in retrofitting SCR
to utility boilers, few, if any, of these issues prevent the effective
deployment of SCR. These factors can, however, elevate the cost beyond
the range expected for incorporating SCR into new coal‑fired units. Such
factors include: (a) the ability to configure an economizer bypass to
provide the correct flue gas temperature range; (b) fan capabilities;
(c) strengthening of ductwork to accommodate lower static gas pressure;
(d) the ability of the air heater to tolerate deposition associated with
residual NH~3~ and byproduct SO~3~; and (e) the ability of down­stream
processes (e.g., ash utilization or disposal) to tolerate specified
levels of residual NH~3~.

Clearly, these engineering issues have been successfully overcome in
Germany and Japan, where together approximately 50,000 MW of coal‑fired
SCR capacity has been operational for over 15 years (since 1980). These
factors have also been overcome in Public Service of New Hampshire\'s
Merrimack Station Unit #2 SCR retrofit. The international experience has
already been useful and will likely be instrumental in addressing
similar issues for the boiler designs and higher sulfur fuels utilized
in the U.S., in order to determine which units can yield the greatest
NOx reductions at the least cost.

At present, some debate remains between environmental control equipment
suppliers and utility industry users regarding the significance of these
engineering issues, the extent they have been resolved by international
experience, and the ultimate impact they may have on SCR cost for U.S.
applications. A recent position paper issued on behalf of the
environmental control technology suppliers cites the considerable
experience internationally, arguing that this experience adequately
addresses U.S. utility industry sites (ICAC, 1994). A second paper
summarizes SCR experience to date in Germany (Rummenhohl, 1994). A
position paper issued on behalf of the utility industry users elaborates
upon factors that influence SCR cost for coal‑fired units, dual-­fuel
(fuel oil and natural gas) applications, and natural gas‑fired units,
and the uncertainties for SCR application in the U.S. that remain
despite the impressive international experience (Cichanowicz, 1995).
\<\<*Is this paper available to OTAG?*\>\>\>

Ultimately this cost debate will be resolved by the marketplace rather
than by policymakers, as environmental control equipment suppliers bid
on\--and guarantee the performance of\--their new and retrofit control
equipment installations. Nevertheless, policymakers must be careful not
to close the door of incentive on high‑performance environmental
solutions, given: (1) the ability of emissions trading to simultaneously
maximize environmental benefit and minimize societal cost; and (2) the
historically poor correlation between early environmental cost impact
predictions by industry and the actual control costs which eventuate.

5.2.8. Hybrid Controls

[5.2.8.1. Process Description]{.underline}. As the need for substantial,
yet cost‑effective reductions in NOx emissions has become increasingly
dear, much field development has focused on compatibly combining
existing NOx control technologies to yield superior reductions than
individual stand‑alone technologies can achieve. These can include
combustion/combustion combinations (e.g., LNB/OFA);
combustion/post‑combustion combinations (e.g., LNB plus downstream SCR);
or most recently, post‑combustion/post-­combustion combinations. The two
former configurations are well established and have achieved significant
penetration. The latter combination, however, typically in the form of
hybrid SNCR/SCR, has only been field demonstrated in the last year.

The strengths and weaknesses of SNCR and SCR technologies dovetail in a
fashion that makes hybrid combinations of SNCR followed by downstream
SCR a particularly flexible method for achieving deep reductions of NOx
at reasonable cost. Such hybridized SNCR/SCR are designed to manage the
ammonia slip from the SNCR process and to utilize it as the sole NOx
reductant feed entering the downstream SCR, thus eliminating the need
for a separate ammonia handling and injection system to serve the SCR.
Cost savings from this hybridization principally result from the smaller
size SCR reactor that is required to handle the lower NOx levels exiting
the SNCR, and from the elimination of operating costs associated with
stand‑alone SCR ammonia injection.

Since ammonia slip from the SNCR and SCR catalyst performance are design
characteristics, hybrid SNCR/SCR allows lifecycle NOx reduction costs to
be minimized by determining an optimal balance between annualized
capital costs (mostly attributable to SCR) and annual operating costs
(mostly attributable to SNCR) for the life of the system.

[5.2.8.2. Retrofit Experience and NOx Control Capability]{.underline}.
As a relatively new technological option, hybrid SNCR/SCR has not yet
achieved significant field penetration. However, field demonstration
work conducted during the last two years at Public Service Electric and
Gas (NJ) (PSE&G) on a pulverized coal, wet-­bottom boiler have provided
proof‑of‑concept: Hybrid SNCR/SCR NOx reduction performance was twice
that of stand‑alone SNCR at the same reagent feed rate. Overall NOx
reduction ranged from 86‑90%. Further, it appears that NOx reduction as
high as 75% may be achieved with \"in‑duct\" catalyst on a site-­specific
basis. Utilization of existing ductwork can substantially reduce
retrofit costs.

The capital costs of the stand‑alone SNCR and SCR systems utilized in
the PSE&G field demonstration were \$14/kW (for 38% NOx reduction at 5
ppm NH~3~ slip) and \$90/kW (for 90% NOx reduction capability)
respectively. This field demonstration verified that SNCR‑related cost
performance on a coal‑fired unit can be improved substantially (in this
case doubled), and accordingly, downstream SCR systems can be re‑sized
much smaller.

[5.2.8.3. Technical Feasibility]{.underline}. The technical feasibility
of urea‑based SNCR intentionally providing ammonia slip as the sole
reactant feed to a downstream SCR has been field proven, and hybridized
SNCR/SCR systems should be capable of cost‑effectively achieving 90% and
greater NOx reductions.

The next step for field development of hybrid SNCR/SCR is to design and
test an in‑duct catalytic reactor downstream of a commercial SNCR
installation on a pulverized coal‑fired boiler. This will allow
assessment of the broad, cost-­effective applicability of hybrid SNCR/SCR
to various types of coal‑fired units to be addressed.

NALCO Fuel Tech, which conducted the PSE&G demonstration, has
commercially proposed a hybrid SNCR/SCR system for such a unit within
the OTR. This proposal promises to reduce lifecycle operating costs by
increasing reagent utilization at modest catalyst capital costs.

Though as yet untested in commercial use, hybrid SNCR/SCR appears to
offer great promise for large NOx reductions on coal‑fired units at
reasonable cost. Hybrid SNCR/SCR is dearly among the technologies that
promise to reduce actual compliance costs well below those currently
anticipated by utilities in order to make the substantial NOx reductions
which will be required in the future.

5.2.9. Ultra Low NOx Fuels

[5.2.9.1. Process Description]{.underline}. Most of the above NOx
reduction control technologies focus on thermal NOx (via optimizing
boiler and/or burner design), or on the removal of NOx already formed
(whether of thermal or fuel‑bound origin). Little attention to date has
been directed toward reduction of fuel‑bound nitrogen, other than
switching from higher to lower FBN fuels (e.g., coal to natural gas).
Sensing new market opportunities for NOx reduction solutions, some oil
companies have begun to develop and market ultra low emission
alternative fuels by targeting FBN content.

Such alternative fuels are particularly attractive control options for
oil‑fired peaking units because their comparatively low capacity factor
renders equipment‑based solutions difficult to amortize
cost‑effectively. Alternative fuels are available as \"drop in\"
replacements for #2 diesel fuel, reducing NOx as well as emissions of
total hydrocarbons, SO~2~, particulate matter, and smoke.

These alternative fuels typically require no additional capital
equipment. They are simply a switch to a fuel with very low nitrogen
content, which in turn can virtually eliminate NOx formation from FBN.
The absence of capital equipment costs means that emission reduction
cost‑effectiveness for units burning ultra low NOx fuels is independent
of the amount of time they are used during the year.

[5.2.9.2. Retrofit Experience and NOx Control Capability]{.underline}.
As a relatively new NOx reduction option, ultra low NOx fuel replacement
is just starting to penetrate appropriate markets, principally oil‑fired
peak shaving units. Shell Oil, for example, has had significant success
at Fort Bliss in El Paso, Texas, which has six 2,125 HP General Motors
Electromotive diesel engines (approximately 35 years old) under contract
to supply 9 MW of peak shaving power to El Paso Power. A solution was
required which would allow Fort Bliss to operate these engines at full
output while not exceeding allowable emissions levels for NOx, CO, and
opacity imposed by new operating permit requirements. Engine tuning was
unable to reach compliance, and capital equipment options (e.g.,
catalytic converters, natural gas conversion, or new engines) were
uneconomical. Testing determined that use of Shell\'s LOW NOX fuel would
allow Fort Bliss to reach compliance.

[5.2.9.3. Technical Feasibility]{.underline}. Though largely untested in
commercial use, there is no reason to believe that ultra low NOx fuels
possess any significant technical limitations that will curtail their
use. The principal limitation is one of cost, not technical concern,
which is why these fuels are especially suited to peak shaving units.
Since significant utility NOx emissions are attributable to peaking
units, ultra low NOx fuels represent a promising solution to a high
impact source of NOx emissions.

5.3. NOx REDUCTION TECHNOLOGIES FOR COMBUSTION TURBINES

NOx controls for combustion turbines (CTs) can employ a combination of
three strategies: (1) wet controls; (2) dry low NOx combustion controls;
and (3) selective catalytic reduction (SCR).

5.3.1. Wet Controls

[5.3.1.1. Process Description]{.underline}. Injecting water into the
flame of a CT provides a heat sink that limits thermal NOx. If
available, steam may be used as an alternative cooling media, depending
on the particular application.

Water injection equipment consists of a water treatment system, pumps,
water metering devices, injection nozzles, and the necessary plumbing. A
system to provide high water purity is essential to this process, so as
to protect high temperature surfaces from deposition and/or erosion.

[5.3.1.2. Retrofit Experience and NOx Control Capability]{.underline}.
No accessible reference detailing commercial experience with wet
controls could be found. However, each of the major CT manufacturers
offers wet controls and routinely provide process guarantees to meet a
25‑90 ppm NOx limit depending on fuel fired. Accordingly, experience
should be extensive and adequate to support broad application.

Injection of water or steam into the combustor to meet the 25‑90 ppm
limit suggests a NOx reduction of 70-90% from uncontrolled levels.
Actual NOx reduction depends on the specifics of the combustor design,
and the fuel employed (e.g., natural gas or distillate fuel oil).
Generally, CT wet controls can achieve approximate emission levels of
25-42 ppm (at 15% O~2~) with natural gas firing, and 42‑75 ppm firing
distillate oil.

The most significant factor in wet control performance is the
water‑to‑fuel ratio (WFR), reflecting the quantity of cooling media
injected. For natural gas fired CTs, WFR for either water or steam of
0.33‑2.48 is necessary to control NOx emissions to 25-42 ppm. For fuel
oil fired CT, WFR for either water or steam of 0.46-2.28 is necessary to
control NOx to 42‑90 ppm.

Other significant factors affecting wet control system performance are
the combustor geometry and the location and design of the water/steam
injection nozzles. For maximum NOx reduction efficiency, cooling media
must be uniformly injected and dispersed within the combustor to create
a homogenous cooling pattern.

Wet controls reduce only thermal NOx, but this source comprises all NOx
from natural gas firing and almost all NOx from distillate fuel oil.

[5.3.1.3. Technical Feasibility]{.underline}. Wet controls can be
retrofit to most CTs. The most significant barrier exists for units with
dual fuel capability, since the space constraints imposed by the
presence of two sets of fuel injection nozzles may limit access for
water or steam injection. In addition, there have been limited episodes
in which water‑induced dynamic pressure oscillations have increased
maintenance requirements.

Some existing CTs may employ water injection to augment power production
by 6‑8% in summer months. It is possible this concept could be applied
as a seasonal NOx control strategy that provides a small capacity
increase, thus partially offsetting other costs. All wet controls impact
CT thermal efficiency by 2‑4%.

5.3.2. Combustion Controls

Combustion controls consist of either the Lean Combustion or Lean
Premixed System which have been deployed on new CT units in recent
years. In addition, an advanced combustion control concept referred to
as Rich/Lean Quench is evolving for new CT application. The lean
combustion and lean/premixed systems are most commonly deployed as
alternatives to wet systems. The rich/lean quench concept is evolving at
present, so it is not addressed in detail.

[5.3.2.1. Process Description]{.underline}. Both lean combustion and
lean premixed systems rely upon the principle of employing significant
excess air in the combustion process to provide thermal diluent, thus
reducing peak flame temperature and thermal NOx production. As a result,
the primary factors affecting NOx control performance are the air/fuel
ratio and the type of fuel fired. Employing lean design concepts do not
require significant modification, except for provisions to maintain a
stable flame at low operating load. Employing the premixed lean concept
requires a different fuel preparation system and the fuel and air mixing
strategy differs.

[5.3.2.2. Experience and NOx Control Capability]{.underline}. Most major
CT manufacturers offer lean and lean premixed controls, and they
routinely guarantee a 9‑65 ppm NOx limit depending on fuel fired. Thus
again, experience should be extensive and adequate to support broad
application.

Lean and Premixed Lean system NOx reduction strongly depends on fuel
type. For natural gas‑fired CT, control of NOx to 9-42 ppm has been
achieved, reflecting NOx reductions similar to wet systems (70‑95%). For
fuel oil‑fired CT, NOx can be controlled to 42‑65 ppm, depending on the
combustor concept. Control of NOx to these levels represents a reduction
of 60‑90% from uncontrolled values.

[5.3.2.3. Technical Feasibility]{.underline}. Essentially all Lean and
Premixed Lean control options are technically and commercially feasible,
although primarily as part of a new unit design. It is conceivable that
these strategies can be retrofitted to an existing combustor; however
the broad retrofit/ability is not clear.

5.3.3. Selective Catalytic Reduction (SCR)

[5.3.3.1. Process Description]{.underline}. Selective catalytic
reduction (SCR) can be applied to CT in a manner similar to that for
steam boilers. CT applications with either a heat recovery steam
generator (HRSG) or in a combined cycle application deploy SCR at flue
gas temperatures similar to applications on steam boilers (550‑750F).
However, the largest number of potential applications is the \"simple
cycle\" employing flue gas temperatures of 800‑1100F. Recently,
catalysts for this relatively high temperature application have been
successfully demonstrated, and SCR is now viable on \"simple cycle\" CT
applications.

[5.3.3.2. Experience and NOx Reduction]{.underline}. There are
approximately 5,000 MW of CT equipped with SCR in either combined cycle
or HRSG applications for a variety of applications (e.g., industrial
steam production and cogeneration). Simple cycle or \"high temperature\"
SCR applications are increasing, now approaching 500 MW on approximately
10-15 units. For both HRSG/combined cycle and simple cycle applications,
natural gas is the predominant fuel. Fuel oil applications are limited.

SCR can provide 80‑90% NOx reduction, depending on the amount of
residual NH~3~ that can be introduced into the flue gas, and the SO~3~
that can be tolerated. For exclusively natural gas‑fired CT, 90% NOx
reduction is achievable as no significant residual NH~3~ exists. For
distillate fuel oil applications, NOx reduction may be limited to 80% as
the role of SO~3~ (generated from trace quantities of SO~2~) may present
ammonium sulfate/bisulfate deposition problems. \<\<\<*Source?*\>\>\>

[5.3.3.3. Technical Feasibility]{.underline}. SCR is technically
feasible for most applications employing HRSG or combined cycle
application. Recent demonstrations and commercial applications of
catalysts from zeolites and other materials assure SCR feasibility for
simple cycle conventional and high temperature applications.

5.4. NOx REDUCTION TECHNOLOGIES FOR RECIPROCATING INTERNAL COMBUSTION
ENGINES

Use of compression ignition (reciprocating) internal combustion (IC)
engines in the electric utility industry primarily involves peak shaving
units. NOx controls for IC engines can employ three strategies
individually or in combination: (1) retarding ignition timing; (2)
selective catalytic reduction (SCR); and (3) ultra low NOx diesel
alternative fuels.

5.4.1. Ignition Timing Retard

[5.4.1.1. Process Description]{.underline}. Ignition timing retard
lowers NOx emissions by moving the ignition point to later in the
stroke. With the piston already moving downward, the combustion chamber
volume is increased and the peak flame temperature is lowered, thus
reducing thermal NOx formation. It is effected by retarding the point at
which the diesel fuel is injected into the cylinder. The amount of
reduction in NOx will vary depending on specific engine design and
operating conditions, but there is a limit to which any engine can be
retarded.

[5.4.1.2. Experience and NOx Reduction]{.underline}. Retarding IC engine
ignition is a well-­established emissions control procedure. NOx emission
reductions achievable with this control option can be 20-30%.

[5.4.1.3. Technical Feasibility]{.underline}. The technical feasibility
of ignition timing retard is clear; it is already in widespread
practice. It is limited, however, in that any amount of retard is
typically accompanied by some decrease in fuel efficiency (and thus a
corresponding increase in fuel consumption and cost). Excessive
retarding can lead to engine misfires and rapidly increasing levels of
smoke and particulate emissions.

5.4.2. Selective Catalytic Reduction (SCR)

[5.4.2.1. Process Description]{.underline}. The nature of SCR has been
extensively covered in earlier sections of this report. Attributes of
SCR which relate specifically to IC engines are considered below.

[5.4.2.2. Experience and NOx Reduction]{.underline}. NOx emission
reductions achievable with this control option are in the range 80‑90%.

[5.4.2.3. Technical Feasibility]{.underline}. Variable load IC engines
require more sophisticated SCR systems, which adds to their already high
capital and operating costs when applied to peak shaving units. Fuel
composition can also be a concern since fuel properties which extend
engine life can reduce catalyst life and vice versa. High sulfur fuels
or the presence of phosphorus can contaminate catalyst, for example,
while some engine manufacturers have expressed concerns that low
phosphorus oils could reduce engine life.

5.4.3. Ultra Low NOx Alternative Fuels

[5.4.3.1. Process Description]{.underline}. Alternative diesel fuels are
now available which can significantly reduce NOx and other emissions in
comparison to #2 diesel fuel. These fuels simply replace #2 diesel and
require no additional capital equipment, though some resetting of
existing equipment may be necessary to optimize operation.

[5.4.3.2. Experience and NOx Reduction]{.underline}. Ultra low NOx
alternative fuels are currently finding initial market acceptance among
peak shaving units with particular emissions constraints. NOx emission
reductions achievable with the use of such fuels can be in the 80‑90%
range.

[5.4.3.3. Technical Feasibility]{.underline}. The technical feasibility
of ultra low NOx alternative fuels is relatively secure. The higher
costs which position such fuels appropriately for peak shaving units,
however, will limit their use for more extended applications.

**SECTION 6**

**INCREASING EMISSION REDUCTION REQUIREMENTS**

**AND DEREGULATION OF THE ELECTRIC UTILITY INDUSTRY**

6.1. INTRODUCTION

This section briefly discusses the impact of future emission control
requirements and increasing competition in the electric utility
industry.

6.2. LEVEL, IMPLEMENTATION, AND TIMING OF FUTURE NOx AND

OTHER POTENTIAL EMISSION CONTROL REQUIREMENTS

The current EPA regulatory climate possesses several currently mandated
and reasonably anticipated future emissions control requirements that
can be expected to impact electric utility sources. The level and
implementation of these emission reduction requirements\--as well as
their timing\--are key issues affecting the ultimate cost of the
reductions to be achieved.

Major factors that must be considered in determining and implementing
environmental regulations requiring electric utility emission reductions
include: (1) flexible approaches to compliance, such as allowance
trading and averaging, that can achieve or exceed necessary emission
reductions while minimizing their total cost to society; and (2) staging
the timing of regulatory requirements for reducing emissions of the many
critical public health pollutants that are emitted by electrical
generating stations, particularly coal‑fired units.

Flexible Compliance Approaches. Appropriate trading, averaging, and
limited banking of emission reduction allowances enables scarce
resources, notably human effort and financial investment, to be directed
toward the most effective emission reduction opportunities available.
Conversely, such programs allow the perpetuation of utility emissions
that truly represent diminishing returns, allowing scarce resources to
be expended where greater public health and environmental quality gains
can be secured.

The national Acid Rain program, with its SO~2~ allowance‑based trading,
is a good example of a program that incorporates flexible regulatory
approaches to reduce costs. Due largely to this trading system, market
prices for SO~2~ allowances are now a full order of magnitude less than
originally estimated. Trading of NOx allowances is expected to similarly
reduce currently high estimates for NOx emission reductions by about
one‑half.

[Staged Timing]{.underline}. There are two somewhat conflicting dynamics
which must be balanced to achieve optimal staging of environmental
regulatory requirements. First, it is essential that regulations be
implemented in a fashion that allows reasonably sound science to be
employed and which enables regulated entities to survive financially.
Typically this results in a basically sequential approach, with one
regulation adopted after another, so the science and compliance burdens
are not excessive at any given point in time. Adherence to this dynamic
reflects recognition of the risk of \"doing too much at once.\"

The second dynamic, however, applies economies of scale to the control
of several pollutants at once, thus leveraging a source\'s downtime and
engineering investment into greater environmental and public health
benefit than a purely sequential approach can provide. Ignoring this
dynamic can lead a source to do \"too little at once,\" by not \"doing
it right the first time.\"

This second dynamic is evident in the Clean Air Science Advisory
Committee\'s (CASAC) recent decision to form a subcommittee to
investigate collectively revising the NAAQS for ground level ozone, fine
particulate matter, and regional haze. The objective of this effort is
to determine new standards appropriately protective of public health,
and to provide EPA with recommendations for an integrated,
cost‑effective, national implementation of the three new standards. Such
an approach must necessarily and comprehensively address long range
transport of airborne pollutants in its implementation. OTAG\'s
conclusions should assist the subcommittee in achieving its goal of
rational integration. OTAG\'s results should similarly assist in EPA\'s
current comprehensive examination of toxic emissions from utility
sources.

6.3. COMPETITION AND ELECTRIC UTILITY EMISSIONS

The electric utility industry may be undergoing profound changes
concerning how it is regulated, especially relative to the transmission
of electric energy in interstate commerce. Discerning the need for
change, the Federal Energy Regulatory Commission (FERC) issued a notice
of proposed rulemaking (NOPR) on March 29,1995 regarding \"Promoting
Wholesale Competition Through Open Access Non‑discriminatory
Transmission Services by Public Utilities.\" In mid-­November 1995, FERC
issued a Draft Environmental Impact Statement (DEIS) on its open access
NOPR, and FERC\'s interpretation of the minimal impact its NOPR would
have on air emissions engendered a furious response from many quarters,
particularly downwind states.

Given the development constraints imposed upon nonattainment areas by
the CAAA, and its emphasis on the effects of air pollution rather than
upon causes of air pollution, the reaction to FERC\'s NOPR rapidly and
understandably turned political. Several northeast governors have
indicated approval of FERC\'s aims, but strong disapproval of the
downwind air quality impacts of its approach. The New England Governors
Council, the Council of Northeast Governors, several U.S. Senators, and
the OTC have all passed resolutions requesting that FERC, EPA, and the
Administration work together to find a way to embark upon electric
competition without negatively impacting downwind air quality and
attainment.

This turn of events has added to the political burden which OTAG is
already called upon to modulate (OTAG‑related legislative efforts have
been underway for some time by mining and utility interests, for
example). OTAG has become a critical venue in which the nation\'s
tolerance for long range transport of air pollution will be juxtaposed
with its tolerance of a monopoly electric utility industry.

As a result, OTAG is forced to consider a variety of issues not directly
related to emission controls, but which could nevertheless have a
significant impact upon transported air pollution. These include, but
are not limited to:

oWholesale competition in the electric utility industry, and its
resultant emissions impact, may occur even without new FERC rules
mandating open access to transmission lines.

oSubstantial unused, low cost electric generation capacity exists at
relatively uncontrolled, coal‑fired stations in upwind states. Earlier
authorizations of the CAA largely ignored these facilities because they
were represented to be too near to retirement to control
cost‑effectively. If, as it now appears, such uncontrolled,
nearly‑depreciated units will not be retired in the near future, then
they must now be controlled.

oSubstantial power cost differences between regions is likely to result
in significant shifts in generation. However, analyses of such shifts
must differentiate between currently available transmission capacity and
that which can be expected in both the foreseeable and long term
futures. At present, there is little doubt that transmission capacity is
adequate to meet anticipated market demand. As a result, short term
transmission constraints will probably deter huge increases in upwind
generation and its associated emissions. Nevertheless, transmission
capacity can be significantly enhanced in the foreseeable future through
such measures as reconductoring power lines and reducing line losses
(which effectively adds capacity) through series capacitance. In the
long term, of course, if adequate markets exist and transmission
constraints persist, new transmission lines will be built.

oGrowth in upwind utility NOx emissions\--and its relationship to
attainment of ozone and other air quality standards downwind\--is an
issue that must be included in the OTAG process. These discussions
should include reductions in NOx emissions expected from EPA\'s newly
proposed Title IV (Acid Rain) regulations. OTAG is also a proper venue
to contrast the magnitude of the additional revenue potentially
available to low cost, upwind utilities with the magnitude of additional
control costs that would result in no net increase or even a reduction
in transported pollutants. Busbar impacts of adequate control costs do
not appear to be determinative.

oOTAG is also an appropriate venue in which to consider the societal
cost of emission reductions in the region. In particular, a ton of NOx
can be much more cost‑effectively reduced at a relatively uncontrolled
upwind generating station than through the pursuit of diminishing
returns at stations already subject to more stringent requirements
(e.g., the OTC MOU).

oEffective mechanisms must be developed and implemented to ensure that
downwind regions experience no net emissions increase as a result of
electric industry deregulation. Ideally, such mechanisms should employ
flexible, market‑based concepts utilizing utility‑wide and/or regional
emissions averages in order to minimize the need for regulatory
involvement in the achievement of this objective.

**SECTION 7**

**STRATEGY DEVELOPMENT AND IMPLEMENTATION ISSUES**

**FOR ELECTRIC UTILITY SOURCES**

7.1. INTRODUCTION

This section offers recommendations regarding OTAG modeling of utility
emissions and suggestions regarding implementation schedules for control
technology retrofits.

7.2. MODELING SCENARIOS INVOLVING NOx REDUCTIONS FROM

ELECTRIC UTILITY SOURCES

OTAG modeling scenarios which characterize or include NOx reductions
from electric utility sources should consider several issues:

oScenarios should postulate neither generalized nor site‑specific
technology mandates. Rather, modeling scenarios should be premised upon
stringent performance standards for NOx emissions from utility
generating stations, or for overall utility NOx emission averages. Such
approaches allow utilities to optimize the cost effectiveness of their
emission reduction decisions.

oWherever possible, modeling scenarios should consider phased approaches
that enhance integration with other mandated or anticipated emissions
reduction requirements (e.g., new Title IV rules and revised ozone, fine
particulate, regional haze, and mercury standards).

oWherever possible, modeling scenarios should separate utility and
mobile source reductions (particularly heavy duty diesel engine
emissions) in order to allow clear evaluation of the ozone reduction
capability and cost effectiveness of each.

7.3. RETROFIT IMPLEMENTATION SCHEDULES

An often overlooked but important consideration in requiring control
technology retrofits is the time required to engineer, install, and test
retrofit technologies on a schedule consistent with regulatory
compliance dates. Factors affecting implementation schedules include:

oThe number of units and generating capacity to be retrofit.

oThe availability of architectural engineering capacity and
manufacturing and service support capabilities of retrofit technology
suppliers.

oEngineering, procurement, and construction schedule requirements.

oThe outage requirements necessary to install retrofit technologies.

oThe potential impact of multiple unit installations on grid reliability
(though existing low capacity factors, particularly for Midwest coal
units, probably moot any genuine concern here).

oThe ability of serious non‑attainment areas to achieve acceptable air
quality in light of observed ozone and precursor levels at upwind
boundaries.

**SECTION 8**

**SUMMARY MATRIX OF**

**NOx CONTROL TECHNOLOGY COST AND PERFORMANCE**

8.1. INTRODUCTION

This section describes the Summary Matrix of control technologies and
applications which follows.

The Summary Matrix highlights the NOx reduction efficiency (\"ΔNOx %\");
control cost in terms of cost per ton of NOx removed on an annual rather
than seasonal basis (\"\$/ton\"); and capital cost in terms of cost per
kW \"\$/kW\") for available NOx control technologies by various utility
boiler types.

Each of these items is in turn presented as a triplet of: (1) actual
costs incurred, where installation experience exists; (2) expected costs
where pre‑contract market data exists such as vendor quotations for
specific control technology installations on specific generating units
based on detailed engineering studies. (Since such studies typically
last 3-6 months, this information is superior than generalized,
hypothetical cost conclusions; the latter have traditionally overstated
costs by a dramatic margin.); and (3) an industry estimate of the cost
range applicable to the given control technology. With the exception of
LNB and LNB/OFA control options, cost figures are intended to reflect
the incremental cost to deploy any one technology. Some specifics of the
cost estimation procedures used to develop the industry estimated cost
ranges are described in Appendix A.

Care should be taken in using the industry estimated cost range figure
in the Summary Matrix, since: (1) there remains considerable
disagreement between environmental control equipment suppliers and
potential utility users as to the costs likely to be incurred when
installing retrofit control technologies; (2) extremely high or low
range endpoints may not be representative of costs applicable to the
majority of applications; and (3) technological developments and
retrofit application learning curves are advancing rapidly, reducing
estimated control costs in some cases by as much as 1‑2 orders of
magnitude per year; and (4) flexible compliance options, particularly
trading, will drive overall costs toward the lower end of any achievable
cost range.

It is particularly inadvisable to extrapolate technology‑specific costs
to estimate broad, industry‑wide totals because broad technology
mandates are not contemplated by OTAG. Flexible compliance strategies
coupled with trading and banking of emission reductions will materially
reduce cost per ton of NOx removed over the entire OTAG region.

**APPENDIX A**

**COST EVALUATION BEHIND**

**INDUSTRY‑ESTIMATED CONTROL COST RANGE**

**IN SUMMARY MATRIX**

\<\<\<*Caution: Appendix A (and its resulting \"UARG Data\" figures in
the Summary Matrix) do not reflect consensus methodologies or up‑to‑date
technical information such as catalyst life, gas‑coal price
differential, etc. Some of these differences are reflected in the table
below. Other cost factors not yet included are represented in
**bold‑italic** characters.*\>\>\>

A.1. INTRODUCTION

Cost figures cited in the Summary Matrix were abstracted from several
sources, including information submitted to the OTAG Control Technology
Committee, results in the NESCAUM/MARAMA Phase II Report, and technical
literature describing NOx control (specifically, proceedings from the
EPRI/EPA Symposia on Stationary Combustion NOx Control, most recently in
1995,1993, 1991).

The cost of NOx control on the basis of levelized dollars per ton was
either adapted from the NESCAUM/MARAMA Phase II Report, or specifically
calculated over a selected range of variables. Levelized cost was
estimated using a simplified version of the EPRI Technical Assessment
Guide (TAG). This appendix briefly summarizes the calculation
methodology for the industry-­derived cost range estimates in the Summary
Matrix.

A.2. KEY ECONOMIC VARIABLES

Several key economic variables in this calculation are described as
follows:

[Capital Recovery Factor]{.underline} The annual capital recovery factor
in current dollars of 0.17 was employed, reflecting a 20 year recovery
period, and based on 1993 EPRI TAG values calculated for a discount rate
of 9.2%. (Note: the capital recovery factor in constant dollars
according to the EPRI TAG for the same economic conditions is 0.12).

[Operating Cost Levelization Factor]{.underline} The operating cost
levelization factor in constant dollars by definition presumes a zero
inflation rate, and a zero real escalation rate over a 20 year period,
and thus is 1.0.

\<\<\<*[Capacity Factor]{.underline} How was capacity factor(s) used in
the calculation? EPA‑Bechtel & STAPPA/ALAPCO reports use 65% default.
UARG seems to use less\...*\>\>\>

A.3. CALCULATION METHODOLOGY

The methodology to calculate the cost per ton of NOx removed involved
three primary variables for most technologies: (1) capital cost; (2) NOx
reduction; and (3) capacity factor. These were evaluated over the range
indicated in the Summary Matrix.

In addition, a range of secondary variables were treated specific for
each technology. These were:

oGas reburning: Natural gas/coal price differential, from \$0.40 to
\$1.20/mmBtu

oSNCR: Normalized Stoichiometric Ratio (NSR) from 0.9 to 1.5

oAverage catalyst life (retrofit application): 6‑8 years

A \"full‑factorial\" matrix of variables was not explored; rather
combinations that reflected realistic scenarios were evaluated.
\<\<\<*\"realistic\" needs clarification.*\>\>\>

The coal sulfur content was assumed to be 2 lb/mmBtu, for the purpose of
estimating cost savings from SO~2~ allowances. \<\<\<*What is
corresponding %S ?*\>\>\> The SO~2~ allowance value was assumed to be
\$75/ton, and the cost savings accrued after a corporate tax rate of
35%.

The following numerical values were assigned for selected inputs to the
cost evaluation:

SUMMARY TABLE: VALUES OF KEY COST VARIABLES

  ----------------------- ----------------------- -----------------------
  **Cost Variable**       **UARG Values**         **States\' Values**

  Coal Unit Cost          \$1.50/mmBtu            \$1.00/mmBtu

  Natural Gas Unit Cost   \$2.20/mmBtu            \$1.50-\$2.00/mmBtu

  Anhydrous Ammonia       \$250/ton               \$250/ton

  Urea Reagent            \$315/ton               \$315/ton

  Plant Heat Rate         9,600 Btu/kWh           9,600 Btu/kWh

  Plant Capacity Factor:  \_\_\_                  \_\_\_

  Baseloaded Units        55-65%                  65%

  Peaking Units           50%                     50%

  SCR Catalyst Life       4-6 years               6 years +
  (Ave.)                                          

  SCR Replacement         \$400/ft^3^             \$400/ft^3^
  Catalyst                                        

  SO~2~ Allowance Value   \$130/ton               \$75/ton
  ----------------------- ----------------------- -----------------------

**SELECTED REFERENCES**

Cichanowicz,J.E. Cichanowicz, \"Factors Affecting SCR Capital Costs for
Coal‑Fired

1995Utility Boilers,\" Discussion Paper Prepared for the National Mining
Association and the Utility Air Regulatory Group, 1995

DOE, 1994\"Demonstration Of Coal Reburning for Cyclone Boiler NOx
Control: Final Report.\" U.S. Department of Energy/PETC, Report No. DE
FC 2290 PC 89659.

EPA, 1993Alternative Control Techniques Document-‑NOx Emissions from
Stationary Gas Turbines, final report prepared for the EPA Office of Air
Quality Planning and Standards, report no. EPA‑453/R‑93‑007,
January 1993.

EPA, 1995a\"Phase II NOx Controls for The MARAMA and NESCAUM Regions.\"
Prepared for U.S. EPA/OAQPS by Acurex Environmental, September 30, 1995.

EPA, 1995b\"Cost‑Effectiveness of Low‑NOx Burner Technology Applied to
Phase I, Group 1 Boilers.\" Prepared for EPA (EPA contract
No. 68 D3‑0005), May, 1995.

EPRI, 1995Proceedings of the EPRI/EPA 1995 Joint Symposium on Stationary
Combustion NOx Control; May 1995, Sessions 8A and 8B, Book 4.

ICAC, 1994a\"Selective Non‑Catalytic Reduction (SNCR) for Controlling
NOx Emissions.\" White Paper prepared by the Institute of Clean Air
Companies (ICAC) SNCR Committee, July 1994.

ICAC, 1994b\"Selective Catalytic Reduction (SCR) Controls To Abate NOx
Emissions.\" White Paper prepared by the Institute of Clean Air
Companies (ICAC) SCR Committee, October 1994.

Jaerschky, 1993Jaerschky, et al., \"SO~3~ Generation\--Jeopardizing
Catalyst Operation?\" Paper presented at the 1991 EPRI/EPA NOx Control
Symposium, March 1991.

Rentz, 1992Economic Commission for Europe, ECE NOx Task Force,
December 1992.

Rummenhohl,V. Rummenhohl, et al., \"Relating the German DeNOx

1994Experience to U.S. Plants: Lessons From More Than 30,000 MW of DeNOx
Retrofits.\" Paper presented at the ASME Joint International Power
Generation Conference, Phoenix, AZ, October, 1994.

Smith, 1995\"Reburn NOx Reductions on Hennepin Unit 1 Based Upon Draft
NESCAUM II Report.\" Memo from L. Smith (Energy Technology Consultants,
Inc.) to Craig Harrison (Hunton & Williams), July 26, 1995.

Veerkamp, 1993Veerkamp et al., \"Evaluation of SCR as a NOx Control
Option for Pacific Gas & Electric.\" Paper presented at the 1993
EPRI/EPA NOx Control Symposium, May 1993.

\<\<\<*Add other sources cited in footnotes\...*\>\>\>

[^1]:     ^?^ Letter from Alexander L. Huhmann of PSE&G to Brock
    Nicholson, Chair of OTAG Control Strategy Formulation mini‑group,
    dated April 8, 1996.

[^2]:     ^?^ Seven of the most recent reports are:

    o\"Phase II NOx Controls for NESCAUM and MARAMA Regions.\" November
    1995, prepared for NESCAUM, MARAMA, and OAQPS.

    o\"Discussion of Factors Relevant to Section 407 NOx Emissions
    Standards for Group 2 Boilers.\" May 1995, prepared for UARG.

    o\"Controlling Nitrogen Oxides Under the Clean Air Act: A Menu of
    Options.\" July 1994, prepared for STAPPA/ALAPCO.

    o\"Alternative Control Techniques Document\--NOx Emissions from
    Utility Boilers.\" March 1994, prepared for U.S. EPA.

    o\"Cost Estimates for Selected Applications of NOx Control
    Technologies on Stationary Combustion Boilers.\" March 1996,
    prepared by Cadmus Group and Bechtel Power Corporation for U.S. EPA.

    o\"Assessment of Performance Capabilities of LNBs Based on Reported
    Hourly CEM Data.\" December 4, 1995, prepared by Cadmus Group.

    o\"Capital and Annualized Costs of Low NOx Burner Technology Applied
    to Phase I, Group 1 Boilers.\" December 8, 1995, prepared by Acurex.

[^3]:     ^?^ Source: \"Estimated Effects of Alternative NOx Cap and
    Trading Schemes in the Northeast Ozone Transport Region.\" Prepared
    by ICF Kaiser for EPA, September 1995.

[^4]:     ^?^ According to ICF Kaiser\'s report for EPA (see Footnote
    2), the availability of trading in the Northeast provides for
    significant NOx reductions at as low as one‑third the cost of
    traditional command‑and-control strategies.

[^5]:     ^?^ Source: \"Steam.\" Babcock & Wilcox, 40th Edition, 1992.

[^6]:     ^?^ Source: \"Assessment of Performance Capabilities of LNBs
    Based on Reported Hourly CEM Data.\" Prepared by The Cadmus Group
    and Bechtel Power Corporation for EPA, December 4, 1995.

[^7]:     ^?^ For conventional pulverized coal‑fired boilers (e.g.,
    Group 1), the compliance date for NOx is determined by the SO~2~
    status. Specifically, a unit that must comply with SO~2~ reductions
    by 1995 must meet NOx limits by 1996. Similarly, Group 1 units for
    which SO~2~ reduction by 2000 is mandated must comply with NOx
    reductions on that date.

[^8]:     ^?^ Wet‑bottom means the boiler has a furnace bottom
    temperature above the ash melting point and the bottom ash is
    removed as a liquid.

[^9]:     ^?^ Several tangential‑fired units of this design were
    designed and constructed by Combustion Engineering (presently ABB)
    in the mid‑50\'s; however all but one have since been converted to
    natural gas firing. As a result, none of these units is included in
    the boiler inventory.

[^10]:     ^?^ American Electric Power and Duquesne Power and Light have
    achieved greater than 40% reduction through coal and air staging on
    roof‑fired boilers.

[^11]:     ^?^ Source: \"Assessment of Performance Capabilities of LNBs
    Based on Reported Hourly CEM Data.\" Prepared by The Cadmus Group
    and Bechtel Power Corporation for EPA, December 4, 1995.

[^12]:     ^?^ Source: \"Assessment of Performance Capabilities of LNBs
    Based on Reported Hourly CEM Data.\" Prepared by The Cadmus Group
    and Bechtel Power Corporation for EPA, December 4, 1995.

[^13]:     ^?^ Source: \"Assessment of Performance Capabilities of LNBs
    Based on Reported Hourly CEM Data.\" Prepared by The Cadmus Group
    and Bechtel Power Corporation for EPA, December 4, 1995.

[^14]:     ^?^ Tables 3‑8 and 3‑19, \"Phase II Controls For The MARAMA
    and NESCAUM Regions.\" September, 1995.

[^15]:     ^?^ See Table 4, \"Reducing Static Emissions by Gas Firing in
    Coal‑Designed Boilers\--Field Evaluation Results.\" Folsom et al.,
    Proceedings of the 1993 EPRI/EPA Joint Symposium on Stationary
    Combustion NOx Control, May 1993, Miami, FL.

[^16]:     ^?^ Most recent is Book 4 (Sessions 8A and 8B) of the
    Proceedings of the 1995 EPRI/EPA Joint Symposium on Stationary
    Source Combustion NOx Control, May 1995.

[^17]:     ^?^ L. Smith of Energy Technology Consultants, Inc., to Craig
    Harrison of Hunton & Williams (Smith, 1995) reporting short‑term vs.
    long‑term analysis of data presented in two gas reburn technical
    papers. \<\<\<*Made available to OTAG CTO Workgroup?*\>\>\>

[^18]:     ^?^ In an October 27 letter from J.M. Piepho (Marketing
    Manager, Babcock & Wilcox) to L. Kertcher (EPA Acid Rain Division),
    a furnace residence time of 1 second from the reburn burners to the
    furnace exit was estimated necessary with coal reburn to assure
    acceptable carbon burnout while achieving 50+% NOx reduction at full
    load.

[^19]:     ^?^ Letter dated July 17, 1995, from Blair Folsom (Vice
    President, EER) to John Pratapas (Senior Project Manager, GRI), page
    2.

[^20]:     ^?^ The necessary residence time has been stated to be as
    long as 1.8 seconds for a certain type of coal (see final report for
    the WP&L Nelson Dewey demonstration, DOE Report DE FC 2290 PC
    89659), and as short as 1 second by several process suppliers.
    Boilers featuring less than the minimum residence time can still
    deploy reburn, but NOx reduction capabilities would be less.

[^21]:     ^?^ Although misleading, it is convenient to express the
    catalyst replacement frequency in terms of a single number
    reflecting useful catalyst life in years. In practice, a catalyst
    management strategy is employed to minimize the cumulative cost over
    the plant lifetime of providing for replacement and disposal of
    catalyst. Generally, an SCR reactor when initially commissioned into
    service contains only a portion of the ultimate catalyst inventory,
    which after a number of years is gradually augmented with new
    catalyst to compensate for gradual deactivation. Ultimately, the
    original catalyst elements are considered \"spent\" and replaced
    with fresh catalyst, which in turn augments the older catalyst in
    the reactor. Specific strategies vary with site‑specific design
    considerations.