The First 100 GW of SCR in the U.S. - What Have We 

Learned?

Paper # 129

J. Ed Cichanowicz

Consultant

236 N. Santa Cruz Avenue

Suite #202

Los Gatos, CA 95030

ec@jecinc.info

Lawrence J. Muzio

Fossil Energy Research Corporation

23342-C South Pointe Drive

Laguna Hills, CA 92653

lmuzio@ferco.com

Michael C. Hein

Michael Hein Consulting

221 Henson Drive

Travelers Rest, SC 29690

mighein@aol.com

ABSTRACT

Since 1998, SCR NOx control has been installed on more than 100 GW of coal-fired capacity in 

the U.S. The design basis for these applications was experience from Japan, accumulated since 

1978 mostly on coals with less than 1% sulfur content, and from Europe, accumulated since 

1987 mostly on coals with less than 1.5% sulfur content. 

The U.S. experience reveals several lessons not evident from prior observations. Among those 

most broadly witnessed are: (a) the significant role of large particle ash (LPA), (b) widespread 

use of static mixers to achieve high NOx removal, (c) almost universal migration by suppliers to 

low SO2 oxidation catalysts, (d) implementation of reagent-based SO3 mitigation systems, and 

(e) frequent accumulation of ash within the reactor and required intermittent cleaning, 

particularly on PRB coal. Other trends less broadly adopted are the use of aqueous ammonia and 

urea for reagent and temporary reactor operation at low temperature to eliminate economizer 

bypass.

Each lesson imposes cost and operating consequences that can be either detrimental or 

beneficial. Specifically, LPA impacts can be significant, but a $300-500K investment in 

modeling and retrofitting LPA screens can be recovered in two years through lower catalyst cost. 
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Also, the relatively modest cost for static mixers – usually about $500K for acquisition and 1 in 

w.g. pressure drop – can add several percentage points to NOx removal, proving significant nearterm payback. Perhaps most significantly, the annual cost for reagent to mitigate SO3 -

depending on the specific process - can approach the annualized cost for catalyst supply. 

These and other lessons from the continually-evolving U.S. experience are reviewed, and the 

cost and performance implications for a 500 MW plant quantified.

INTRODUCTION

Significant SCR capacity on coal-fired power plants has been installed in the U.S. since 1997, 

most in response to the 1995 NOx SIP-Call. The timing of installation is shown in Figure 1, 

which presents the year of unit startup. Figure 1 suggests that by the end of 2005, the 100th GW 

of SCR-equipped capacity became operational. 

Figure 1. Coal-Fired Capacity of SCR Retrofits, By Startup Year10715

1192

728

1475

114

346

811

1304

10702

4915

3297

2754

7289

21130

16393

41917

0

5000

10000

15000

20000

25000

30000

35000

40000

45000

50000

199519981999200020012002200320042005200620072008200920102012

TBD

Installation Year

Total MW SCR

100 GW by EOY 2006

The inventory of SCR-equipped units will continue to grow – Figure 1 shows that between 2006 

and 2012, approximately 20 GW of additional capacity are planned, predominantly to meet 

Phase I CAIR mandates. EPA and industry sources estimate an additional 10-20 GW of capacity 

will be installed by 2015, to meet Phase II CAIR mandates. The state-of-art of SCR that has 

evolved and is anticipated to be deployed differs from early U.S. applications. Key evolutions 

are summarized in this paper. 
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TECHNOLOGY EVOLUTION AND CATALYST PRICE

Catalyst technology has evolved significantly. The first-generation SCR applications in Japan 

targeted 50-70% NOx removal, with residual NH3 of 5 ppm, and generally did not specify a limit 

on SO2 conversion. Development focused on catalyst longevity and performance, with early 

grid, plate, and pipe-type geometries offered. Development also focused on mechanical 

integrity, and simply avoiding erosion. As catalyst technology was relatively new, prices were 

initially high. 

Figure 2 depicts the trend in catalyst prices cited in public literature. Figure 2 shows that catalyst 

prices – on the dollar basis of the year reported and thus not adjusted for escalation - have 

decreased from approximately $16,000/m3 to less than $4000/m3. Significantly, present-day 

demands on catalyst technology far exceed those from the early applications – NOx removal of 

90% is the usual design target, with control of residual NH3 to 2 ppm, and SO2 oxidation to 

usually less than 1%, and in many cases to less than 0.5%. Further, the catalyst substrate is 

desired to be able to withstand numerous one cleaning or regeneration procedure, and in some 

cases a guarantee for Hg oxidation.

Figure 2. Catalyst Unit Costs with Time

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

1980 1985 1990 1995 2000 2005 2010

Year

Catalyst Unit Price, $/c.m. (In Year)

The simultaneous decrease in catalyst price and expansion in demand has provided a challenging 

environment for catalyst suppliers. At present prices of catalyst and ammonia feedstock (e.g. 

natural gas), the supply of catalyst is no longer the major contributor to SCR operating cost, and 

can be significantly less than reagent costs, or costs to mitigate SO3. 

REFERENCE CASE

A 2006 state-of-art SCR application for retrofit to an existing unit will exhibit a variety of 

performance-enhancing features, that incur either capital or operating cost (or both), but provide 

benefit. As background, it is instructive to consider the SCR cost components for a 500 MW 
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coal-fired unit, which provides a basis for comparing the cost impacts of factors unique to the 

U.S. experience, as well as remedial methods.

Table 1 summarizes the key SCR cost components for a 500 MW medium sulfur (2.6%%) 

bituminous coal-fired unit, operating at 85% capacity factor, with SCR operation initiating on an 

annual basis in January of 2007. The SCR process is designed for 88% NOx removal from 

0.40 lbs/MBtu, SO2 oxidation of 1.5%, and employs a 3+1 reactor layout. Incurred costs for 

SCR are reported as net present value (NPV) basis, for a seven year period (through 2013).

Table 1. SCR Cost Components: 500 MW Reference Case, 7 Years Annual Operation

Cost Element ’07-13 

NPV, $M

Comment

Catalyst Addition/Replacement 4.4 Based on $6200/m3, four events from ’07-13

Reagent Supply 8.6 Delivered reagent cost: $250/ton

Labor for Catalyst Replacement 0.064

Flue Gas Fan Auxiliary Power 0.54 Aux power charge of $20/MWh

Note: Capacity factor 85%, catalyst cost $6,200/cubic meter, initial guarantee life of 16,000 hours, delivered 

reagent cost of $250/ton, power cost @$20/MWh

Table 1 shows reagent supply comprises the largest component, followed by catalyst supply, flue 

gas fan auxiliary power, and labor for catalyst replacement. Key lessons from the 100 GW of 

experience in the U.S. will be cast in terms of impact on capital and operating cost, and 

compared to Table 1 results.

WHAT HAVE WE LEARNED?

The U.S. experience since 1995 has taught us:

• SCR capital cost has exceeded anticipated and projected values,

• NOx removal performance, based on 5 month operation, is near design targets and 

generally supports compliance needs,

• LPA has emerged as a key issue; but remedial action is low cost and evolving,

• SO2 oxidation is perhaps the most significant “unintended consequence”, and imposes 

new constraints on design and additional significant operating cost,

• Uniformity of reagent mixing has evolved from 5-10% RMS basis, to consistently less 

than 5%, and in some cases 3-4%; to achieve these targets static mixers, if not essential, 

are the clear “technology of choice”,

• Sonic horns provide a lower cost alternative to sootblowers; however cleaning problems 

may justify both,

• Urea is proven as feasible alternative to ammonia reagent, to simplify permitting 

obstacles and reduce (possibly misplaced) safety concerns, and 

• Hg oxidation is evolving and could soon equate in importance to control of NOx.

Each of these is considered in the following, including where possible a quantitative evaluation 

of costs.
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CAPITAL COSTS HIGHER THAN PROJECTED

The capital cost of SCR has evolved with time, and significantly exceeds early estimates 

developed in the mid-1990s by EPA(1). This escalation has been witnessed in spite of the 

considerable decrease in catalyst unit cost depicted in Figure 1. Three surveys have documented 

the increase in SCR capital cost(2, 3, 4). The findings from these surveys are not directly 

comparable to each other, as all utilize a different unit population, and a reference year basis. 

Further, important factors such as the scope of equipment supply and construction labor rates 

have not been normalized. Regardless, Table 2 shows that initial cost projections by EPA of 

$55-90/kW, based on early and perhaps atypical applications and market conditions, were not 

realized. The reasons may never be known without a detailed autopsy of actual incurred project 

costs. It is likely the initial estimates were low due as (a) strong competitive forces, with 4-5 

major suppliers competing for a limited number of projects, (b) relaxed performance target 

between 60 and 80% NOx removal, demanding less equipment and engineering compared to 

present-day applications, and (c) degree of retrofit difficulty of the first sites, that although not 

simple did not reflect the design challenges of recent for SIP-Call units. 

Table 2. SCR Capital Cost Survey Results

Reference Average Capital, 

MW 

($/kW)

Low-High Cost 

Observed 

($/kW)

Observation

Hoskins, 2003 120 (400 MW) 80-160 Cost Basis: 2002. 15 of 20 reported 

unit costs exceeded $100/kW. 

Weak relationship of unit cost and 

scale. 

Cichanowicz, 

2004

81 (600-899 MW) to 

123 (100-399 MW)

56-185 Cost Basis: 2003. For four 

categories of generating capacity, 

the least cost units were among the 

first installed.

Marano, 2006 118 (>900) to 167 

(<300 MW)

Most costs 

reported to be 

within 100-200

Cost Basis: 2005. “Units with a 

capacity of 600 to 900 MW appear 

to be more difficult to retrofit than 

those in other size ranges.”

The most significant observations from Table 2 are the paucity of units with reported costs 

< $100/kW, and lack of a correlation with generating capacity. With regard to the latter, 

Cichanowicz(3) shows capital cost actually can increase (per unit basis, or $/kW) at higher 

generating capacities. Similarly, Marano(4) concludes that units of 600-900 MW are more 

difficult to retrofit with SCR than other sizes. The challenge of large capacity retrofit is likely 

due to the increased complexity of the site. The case of Duke Energy’s Belew’s Creek Station, 

where the construction “laydown” area was one mile from the unit has been well documented(5). 

Marano(4) notes the early SCR adopters incurred lower capital cost, with the year of 2003 

recognized as a milestone after which costs increased significantly.

Lesson Learned. As SCR is deployed on an increasing fraction of generating capacity, the 

remaining host sites are becoming less amenable to retrofit. Compounding the increasing 
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complexity of site are greater demands on the process. The early SCR installations, in hindsight, 

may not have reflected to bulk of the U.S. boiler population. 

NOX REMOVAL PERFORMANCE

If the cost of SCR has exceeded projections, then so has NOx control performance. NOx

emission rate data available from the EPA Clean Air Markets website 

(www.epa.gov/airmarkets/emissions/raw/index.html) for 2005 shows that SCR equipment is for many 

units providing 90% NOx control, achieving low levels of outlet NOx, and generally meeting 

industry’s needs.

Figure 3 presents a plot of outlet NOx emission rate as reported to the EPA website, comparing 

data reported for the third quarter of 2004 and 2005. Notably, in 2004 approximately 28% of the 

units achieved a 5 month average of 0.06 lbs/MBtu, or less; the fraction of units achieving this 

outlet rate increased to 42% in 2005. 

Figure 3. NOx Outlet Emissions in 3Q: 2004 vs. 2005

How were these reductions in 2005 achieved? Examining the hourly NOx data is revealing. 

Figure 4 shows the cumulative distribution of NOx data as measured in 2004 and 2005 for a 

medium high sulfur coal-fired unit. Figure 4 is prepared by ordering the entire population of 

data from lowest to highest NOx emission rate, and plotting this rate as a fraction of the total 

population. Compared to data in 2004, the data in 2005 is distinguished by a relatively small 

population above 0.20 lbs/MBtu. The essence of Figure 4 can be captured by noting the NOx

emission rates that typify the 5% and 95% population – that is, NOx emissions at which 5% and 

95% of the data are below. Figure 4 shows that in 2004, 5% of the operating time NOx exceeded 

0.20 lbs/MBtu – suggesting either partial or compromised performance of instrumentation and 

0

0.02

0.04

0.06

0.08

0.1

0.12

0.14

0.16

0.18

0.2

0 10 20 30 40 50 60 70 80 90 100

Percent Units Below A Given Quarterly NOx Rate

3rd Qtr Mean NOx Rate (lbs/MBtu)

Q3 2004

Q3 2005

2004: 28% of Units 

Achieved Quarterly 

<0.06 lbs/MBtu

2005: 42% of Units 

Achieved Quarterly 

<0.06 lbs/MBtu
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control systems, reagent feed system, partial blockage of catalyst, inadequate distribution of 

NH3, or any other reason. These issues were corrected in 2005.

Figure 4. Cumulative Distribution of NOx Emission Rates: 2004 vs. 2005

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0 10 20 30 40 50 60 70 80 90 100

Fraction of NOx Emission Rate Below Given Value

NOx Emission Rate (lbs/mBTU)

2004 2005

5% 

Operating 

Value

95% 

Operating 

Value

Comparing the 5% and 95% NOx emission rates for several units shows that eliminating the data 

population with high NOx is usually responsible for achieving low NOx for an ozone season. 

Figure 5 compares 2004 versus 2005 NOx data for 6 units, showing the mean values and those 

characterizing 5% and 95% of the data. Four of these units reduced ozone season NOx in 2005 

by eliminating many of the incidents of high (e.g. 95%) NOx emissions. One unit incurred 

higher 2005 seasonal NOx as the data population with high NOx increased. Figure 5 suggests 

that process upsets and equipment malfunctions are being eliminated as experience increases, 

resulting in lower seasonal NOx values.

Of the 101 units reporting to the EPA website with single stack data, most exhibited a decrease 

in NOx in 2005, when comparing third quarter data with 2004. Specifically, 52 units reported 

lower NOx, while 28 were unchanged and 21were higher. 

Lesson Learned. A significant number of SCR equipped units – over 40% - can achieve on a 

seasonal basis a NOx emission rate of 0.06 lbs/MBtu, or less. SCR NOx outlet levels have been 

reduced in 2005 by improving equipment reliability so that the fraction of data incurring high 

NOx “peaks” is reduced. 
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Figure 5. Mean, 5%, and 95% Percentile Emission Rates: 2004 vs. 2005

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

Trimble County 1 2004Trimble County 1 2005

Pleasants 2 2004Pleasants 2 2005

Montour 1 2004Montour 1 2005

Chesterfield 5 2004Chesterfield 5 2005

Mill Creek 4 2004Mil Creek 4 2005

Bowen 2 2004Bowen 2 2005

NOx Emission Rate (lbs/MBtu)

5% Percentile

Mean Nox ER

95% Percentile

THE GENERATION AND ROLE OF LARGE PARTICLE ASH (LPA)

Perhaps the most significant and unprecedented phenomena experienced in the U.S. is the 

generation and accumulation on catalyst surfaces of large particle ash (LPA) – historically 

referred to as “popcorn ash”. In general, LPA is defined as particles that are 4-7 mm in 

characteristic dimension, of adequate dimension to lodge within the openings of grid- or platetype catalysts. LPA asserts an impact on catalyst performance that is separate and 

distinguishable from conventional fly ash.

The genesis of LPA is not clear – most perplexing was the infrequent observation of LPA in 

early SCR applications in Germany, where the rare occurrence was viewed atypical. It is also 

unclear why U.S. SCR applications have been so prone to LPA-induced reliability problems. 

Several reasons have been speculated: the composition of coal that is fired, degree of 

combustion staging and low NOx firing conditions, and the physical geometry of the furnace and 

convective section. Ryan(6) speculated that LPA was generated from the convective section, and 

further that 100% capture of particles 5 mm and greater would be necessary to protect the 

integrity of a conventional 7 mm pitch catalyst. It is interesting to note that most SCR 

applications in Germany have been on tower design boilers, in which the convective section is 

located directly above the radiant zone. If LPA is generated as a consequence of sootblowing 

furnace walls and the subsequent fragmentation of deposits, the geometry of the tower design 

boiler may provide a barrier to penetration of LPA particles to the SCR reactor. In U.S. 

applications, where the Carolina-type boiler geometry is predominant, there is a smaller physical 

barrier between the convective section and the reactor. Further, some observers have noted 
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minor accumulation of LPA within air heater prior to SCR retrofit, only to experience 

significance LPA plugging after SCR retrofit. It is possible the change in ductwork preceding 

the SCR reactor – and possibly the loss of the economizer hopper and increase in flue gas 

velocities at the economizer exit – are responsible for a higher degree of LPA reporting to the 

SCR reactor.

Several mitigation methods exist and have been summarized by Ryan(7) and Gretta(8). First, 

frequently evacuating the economizer ash hoppers and implementing minor modifications to 

encourage LPA capture and minimize re-entrainment are the least cost options. Next, installing 

screens and baffles to deflect LPA to the economizer hoppers encourages LPA removal. 

Expanding ductwork to slow flue gas velocity, and increasing hopper slope angles to retain more 

LPA is effective but can require significant ductwork modifications. The screens and baffles can 

be rigid and fixed as described by Ryan(7), or flexible as described by Gretta(8). Designs can be 

modularized allowing replacement of screens, which may erode in high velocity areas. One 

screen design employs a robust, erosion-tolerant, self-cleaning design that, depending on space 

available and capital cost, may be appropriate(9). Screen material can be uncoated if ductwork 

velocities are consistently less than 40 aft/s, but may require flame-spray coating if velocities 

exceed 60 aft/s. McLaughlin(10) recommends that economizer hoppers be enlarged as part of any 

SCR retrofit, particularly if baffles or screens are employed. These mitigation methods are 

offered by individual suppliers or boiler manufacturers, for both new and existing applications. 

Finally, the design of ductwork routing flue gas to the SCR reactor should be maintained at 

modest levels, generally not exceeding 40-45 aft/s, to encourage particle drop-out. 

LPA remedies provide cost-effective means to prevent premature deterioration of SCR 

performance. Table 4 summarizes the cost impact of LPA mitigation methods and benefits for 

the reference 500 MW unit. The capital cost for a simple rigid screen can require from $200K 

up to $500 K installed, for an erosion-tolerant design to accommodate high flue velocities, and 

include exotic material of construction. Operating costs can be 1 in w.g. pressure drop, and an 

additional $150 K every 2 years to replace eroded screen panels. 

For the reference plant in Table 1, the 7 year NPV for these costs elements is approximately $1.1 

M, which can be recovered over any of three scenarios. First, this $1.1 M cost can be recovered 

by avoiding a single outage, or accelerating an outage, to clean catalyst. Alternatively, as shown 

in Table 3, simply providing for an increase in open area by 10 percentage points – e.g., reducing 

plugging so that a reactor 80% open (20 % plugged) can be 90% open (10% plugged) - provides 

at least 2% additional NOx removal at the same residual NH3 limit. The NPV of the additional 

NOx removed over the 7 year period significantly exceeds the cost of adding screens. 

Alternatively, the LPA remedy prevents catalyst replacement rate from being accelerated to meet 

the same performance targets – maintaining the open reactor area by an additional 10 % will 

avoid the purchase of one more layer of catalyst over the seven year period. The NPV of these 

actions is reported in Table 3. 

LPA Lesson Learned. For a variety of reasons stemming from coal properties, low NOx firing 

conditions, or boiler design, U.S. SCR-equipped units have been prone to LPA. Experience to 

date suggests perhaps 1 in 4 or 1 in 5 units are susceptible to some impact. LPA mitigation 

methods that are state-of-art require modest cost, and provide significant benefit.
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Table 3. LPA Mitigation Cost, Benefits: 7 Year NPV Basis

Item Capital 

Cost 

(EOY 

2006)

Other Fixed 

Charges

Annual 

Cost 

($000)

LPA 

NPV 

($M)

Benefit/NPV

LPA 

Mitigation

500 $150K screen 

replacement 

at 24 months

60 1.1 Consistently achieve 

additional 2% NOx removal 

over 7 years.

NPV: $13.5

Prevents need for 5 catalyst 

events over 7 year period, 

saving $1.5 M

SO2 Oxidation

The ability of SCR catalyst to oxidize a portion of SO2 to SO3 has been recognized as a potential 

issue since early designs, derived from experience on lower sulfur coals in Japan and Germany, 

were adapted to higher sulfur environment in the U.S.(11). In the early 1990s, in Germany there 

were several occasions of SCR-induced sulfuric acid particle generation and drop-out(12). 

Catalyst suppliers recognized the need to mitigate SO2 conversion, and began development of 

lower SO2 conversion designs; however not all procurement specifications in the evolving U.S 

market called for SO2 oxidation below 1.5%. Many industry participants envisioned that 

specifying low SO2 oxidation catalyst would place a product at a competitive disadvantage, as 

historically low SO2 conversion catalyst has required for some suppliers 20-30% greater volume 

to achieve the same level of NOx and residual NH3 control.

Controlling SO2 became of paramount importance after the first broadly witnessed SO3

plume(13). Subsequent to this milestone event in 2001, controlling SO2 oxidation has evolved to 

be of equal significance in SCR design as NOx control. This is due to additional SO3 control 

requirements that have been imposed, as SO3 plumes have come under scrutiny of local 

regulators. In response, some local jurisdictions have implemented SO3 limits of 5 ppm or less, 

significantly lower than the pre-SCR value. As of this writing, at least six states are known to be 

contemplating SO3 limits on power stations, triggered by the implementation of SCR. 

Consequently, all catalyst suppliers have further explored low SO2 designs. With capabilities of 

different catalyst for NOx and residual NH3 becoming similar, SO2 oxidation can be a key 

deciding point for replacement or initial inventory catalyst. At least one eastern bituminous coalfired unit of greater than 1000 MW capacity has replaced one layer of the initial inventory of 

catalyst with a low SO2 oxidation variety; and further the authors have advised several catalyst 

decisions where the deciding factor has been SO2 oxidation, not control of NOx. The only 

downside is that depending on the catalyst supplier, low SO2 oxidation designs can require 

greater catalyst volume to meet the same NOx removal and residual NH3 performance. This 

trend does not reflect all suppliers, and evolving technology may provide alternatives(14), but 

recent procurement actions suggest this trend is valid at present.
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A key impetus to minimize the SO2 oxidation is to reduce the relatively high operating cost for 

reagent-based SO3 mitigation methods. Dombrowski(15) has shown that reagent costs alone to 

lower SO3 from 40 to 3 ppm can range from $1.2-1.5 M annually, for any of the sodium, 

magnesium, or calcium-based sorbents. This cost rivals that for annual SCR reagent supply and 

can exceed catalyst replacement charges.

Table 4 summarizes the cost impact of specifying low SO2 conversion catalyst. For the reference 

unit in Table 1, it is assumed a low SO2 conversion catalyst of 0.3% is available but requires 

20% more catalyst to achieve the same degree of NOx control as the “baseline” 1.5% SO2

oxidation catalyst. As a consequence the SO3 exiting the SCR reactor is reduced from 

approximately 45 to 23 ppm (at 3% O2). If the unit is required to meet a strict SO3 limit of 

< 5 ppm and uses any of the reagent-based methods, the lower SO3 generated translates into a 

reduction in reagent consumption.

Table 4. Cost Summary: Low SO2 Catalyst and SO3 Remediation

Case Initial Catalyst 

Volume 

(m3)

Catalyst Layers 

Purchased In 7 

Years

7 Year NPV 

Cost 

($M, NPV)

SO3 Reduction 

Cost 

($M, NPV)

Baseline 3 layers at 220 

each

4 4.4 N/A

Low SO2 (0.35% 

oxidation) Case

3 layers at 264 

each

4 5.3 1.3

Low SO2 (0.35% 

oxidation) Case

3 layers at 220 

each

6 6.7 2.3

Depending on reactor and catalyst layer design, higher cost can be incurred in two modes, which 

are shown in Table 4. If the catalyst layer height can be expanded from the initial design, higher 

costs will be incurred for a 20% greater initial inventory, and commensurately larger addition or 

replacement layers. Alternatively, if the catalyst layer height cannot be increased, the catalyst 

replacement rate will be increased to compensate for the lower activity (with respect to NOx) 

catalyst. 

Table 4 shows that compared to the baseline case, catalyst costs (7 year NPV) can be $1.3M 

greater if an enlarged quantity of initial and replacement catalyst is used to achieve the same NOx

reduction/residual NH3 target. Alternatively, if reactor design limits the catalyst volume in each 

layer, more frequent catalyst changeout is required and a 7 year NPV of $6.7M may be incurred, 

representing an increase by $2.3M.

Any additional costs for lower SO2 oxidation catalyst are either fully or partially compensated 

for by lower operating costs for reagent-based SO3 mitigation. As shown in Table 5, reagent cost 

to provide 80-90% SO3 removal can be reduced for the reference case between $155,000 to 

$440,000 annually. These costs equate to a 7 year NPV of almost $1M to $2.7M, and may not 

completely offset the higher catalyst management costs. However, lower SO3 provides benefits 

beyond the scope of this paper.
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Table 5. Reduction in SO3 Mitigation Cost Due To Lower SO2 Oxidation Catalyst

Reagent Delivered 

Cost ($/ton)

Stoichiometric 

Ratio (X/SO3)

Reduction in

Annual Cost

(~80-90% Removal)

7 Year Cost 

($M, NPV)

Hydrated Lime 100 3/1 285,000 1.7

Trona 125 2/1 155,000 0.95

NaHSO3 250 1.2 440,000 2.7

Lesson Learned. Specification of SO2 oxidation – to 0.75% and possibly to as low as 0.30 % -

for replacement or for new catalyst inventory is evolving to be of equal importance to control of 

NOx and residual NH3. The use of extremely low SO2 oxidation catalyst can – depending on the 

supplier –increase catalyst volume and alter management strategy. Higher catalyst management 

costs can be partially or completely offset by reduced reagent for SO3 mitigation. 

REAGENT MIXING

The ability of to mix NH3 with NO is perhaps the most important factor in determining – and 

maintaining – high NOx removal and low outlet NOx emissions. Criteria for NH3/NO uniformity 

for present-day SCR design of 90% NOx removal and 2 ppm residual NH3 is specified to be less 

than 5%, where the degree of uniformity is based on a RMS or coefficient of variation basis.

Reagent mixing technology has evolved significantly from the first SCR applications, which 

were based on the design criteria in Europe to control of NOx to a nominal 100 ppm per unit, and 

required on average 80-85% NOx reduction. This level of control was usually achieved with a 

grid-type array of injectors, with occasional use of static mixers. The early grid-type injectors at 

the time could feature over 1000 individual injection nozzles on one unit – offering flexibility in 

NH3 control, but potential maintenance issues. One of the early SCR installations in the U.S. –

the Orlando Utilities Commission Stanton Unit 3 – featured static mixers. In general, an SCR 

specification for NH3/NO ratio in the mid 1990s might require 5-7% NH3/NO, but recent needs 

are evolving to be less than 5% and in some cases 3-4%.

At present, most SCR installations will employ some type of static mixer to achieve this level of 

NH3/NO mixing. There are several options by which to acquire static mixer technology - some 

proprietary to a process or boiler supplier, with others available for unrestricted use. Three 

boiler suppliers offer an exclusive technology: Babcock-Power offering the delta-wing, Siemens 

both the Parmix and Turbomix designs, and Babcock & Wilcox developing a proprietary design, 

in addition to their “bat-wing” particle knock out device. Individual suppliers such as Koch and

Sulzer offer static mixers for any boiler or SCR process application. Significantly, static mixers 

provide a more uniform flux of NOx, temperature, and induce mixing of NH3 and NO with a 

simple system. Although static mixer use is prevalent, it is not a requirement for success –

several installations such as the AES Somerset and First Energy’s Mansfield station have 

achieved at or near 90% NOx removal with conventional grid-type systems.

Figure 5 depicts the degree of NH3/NO uniformity achieved after tuning the ammonia injection 

grid (AIG) on numerous SCR reactors, and considering six different reagent injection schemes, 
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Figure 5. NH3/NO Uniformity (RMS Basis): Various Reagent Injection Schemes

0

2

4

6

8

Cross Grid Multi Zone Static Mixer-1 Static Mixer-2 Static Mixer-3 Delta Wings

Reagent Injection Scheme

NH3/NOx Uniformity, RMS Basis

including four different static mixer designs. Figure 5 suggests static mixers of any design will 

improve NH3/NO uniformity compared to multiple injectors alone.

The cost of installed static mixers will vary – units with reactor inlet ductwork well above grade 

can incur major structural costs to support the additional mass. As an example, a 500 MW unit 

may incur an installed capital cost of $750K, and induce an additional 1 in w.g. of flue gas 

pressure drop. The 7 year NPV cost incurred for this mixing system can be $1.05M. 

Equally important to achieving good NH3/NO uniformity is retaining it. Figure 6 compares the 

NH3/NO ratio for eight SCR reactors, comparing the (a) as-found state, after at least one year of 

operation after startup, and (b) immediately after tuning. Figure 6 suggests that an investment in 

annual tuning – $30K-$50K depending on the unit size – can consistently reduce NH3/NO 

unmixedness by 2-5%, RMS basis. 

The benefit of employing static mixers and frequent tuning to reduce unmixedness in NH3/NO 

can be quantified. For the hypothetical plant reported in Table 1, reducing the NH3/NO ratio 

from 7 to 3% RMS basis can either increase NOx removal at the same residual NH3, or extend 

catalyst life at the same NOx removal. Table 6 summarizes the benefits of the latter, showing 

that maintaining the lower NH3/NO ratio can eliminate one layer of catalyst purchased over a 

seven year period, saving $1.1 M. Even after accounting for the $0.17 M NPV cost for 

outsourced tuning ($50 K at 18 month internals), significant savings are derived. 

Lesson Learned. The requirement to achieve 90% NOx removal and 2 ppm residual NH3 requires 

NH3/NO uniformity significantly less than 5%, and perhaps to 3%, as measured on a RMS basis. 

There is no guarantee that this degree of unmixedness can be achieved, or attained consistently 

after startup. Static mixers, although perhaps not essential to meet these strict requirements, 

enables achieving these levels. Annual tuning of the AIG can also help maintain NH3/NOx

uniformity and reduce operating costs.
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Figure 6. NH3/NO Uniformity: As-Found, Newly Tuned

0

2

4

6

8

10

12

A B C D E F G H

SCR Reactor

NH3/NOx RMS, %

Y1 Tuned

Y2 As Found 

Y2 Tuned

Table 6. Catalyst Savings Due to Improved NH3/NO Uniformity (90% Design Target) 

Case Initial Catalyst 

Volume

NH3/NO 

Uniformity

(% RMS)

Catalyst Layers 

Purchased In 7 

Years

7 Year Cost 

($M, NPV)

Baseline 3 layers at 220 

m

3

 each

3 4 4.4

As-Found Same 7 5 5.5

Catalyst Cleaning: Sonic Horns

The use of sonic horns in maintaining a clean catalyst has progressed in 10 years from 

experimental to a standard design practice. In 1998, a fact-finding trip by EPRI to SCRequipped units in Europe identified only several units experimenting with sonic horns, some 

exploring side-by-side trials with sootblowers. In the U.S., as recently as 1999, few units 

featured sonic horns – the first reportedly tried in the U.S. at Orlando Utilities Commission 

Stanton Unit 3. The use of sonic horns in the U.S. has risen steadily to where approximately half 

of the new retrofit or new units are designed to include sonic horns; one supplier claims 

installation on 100 reactors

Sonic horns are reported to not remove ash deposits but prevent accumulation on catalyst 

surfaces. Early European and U.S. experience suggested sonic horns maintained catalyst as 

clean as sootblowers, but for less capital and operating cost. Also of importance, sonic horns are 

reported to require less preventative maintenance, and cannot damage catalyst through either 

high pressure operation, or through steam leaks. 
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Sonic horn capital cost can be 25% of that required for steam sootblowers, thus a single layer of 

catalyst can be equipped with sonic horns for $40,000-100,000 depending on the size of the unit. 

In comparison, traveling-rake steam sootblowers can require an installed cost of $120,000-

160,000. Operating cost savings can be significant – one supplier reports that the auxiliary 

power to operate two sonic horns at the conventional frequency (10 seconds every 10 minutes) 

equates to about $1 per day. The cost for operating steam sootblowers depends on the quantity 

of steam required, and how that steam is valued – as either a heat rate penalty, or a capacity 

penalty, or both. At the 250 MW Birchwood Generating Facility in Virginia, where both 

cleaning modes were compared side-by-side, operators report maintaining the 1.5 layers of 

catalyst clean with sonic horns requires a daily operating cost of less than $4/day, compared to 

approximately $41/day for conventional sootblowers. For the 500 MW reference unit equipped 

with a 3+1 SCR reactor design, the total investment for sonic horns including installation could 

approximate $275K, with $5K required annually for power. Travel-raking sootblowers could 

require $550K, with $20K required annually in the value of steam consumed. Based on these 

assumptions, sonic horns provide a saving on a 7 year NPV basis of $375K ($305K for sonic 

horns vs. $680K for sootblowers). In the present-day competitive utility market, these savings 

cannot be ignored – as long as equivalent cleaning is provided.

In terms of operation, traveling rake sootblowers can require significant maintenance, and 

damage the catalyst if steam leaks and condenses on the catalyst surface, or excessive cleaning 

pressure if used above recommended values. For sonic horns, the intrusion of moisture and fly 

ash, particularly PRB ash, into the horn casing can plug the horn and compromise operation. 

Condensation of moisture that penetrates the housing and enters the horn is promoted by the 

expanding compressed air that drives the horn and lowers temperatures. Several PRB-fired units 

have encountered this problem. Insulating the portion of the horn outside of the reactor has 

helped mitigate this issue.

This favorable summary of experience and cost for sonic horns should not be construed as an 

endorsement - maintaining the catalyst clean and open to flue gas flow is critically important, 

and even a slight advantage to sootblowers will justify their use. The demands for high SCR 

NOx removal performance requires extremely clean catalyst. The higher cost for sootblowers 

can be justified in many applications. At least two PRB-fired units have retrofit sootblowers to 

augment or replace sonic horns in maintaining clean catalyst with PRB coal. As shown by the 

example for LPA in maintaining a clean surface, increasing the catalyst open surface area derives 

significant cost benefit that outweighs the additional cost for sootblowers. 

Lesson Learned. Sonic horns have evolved to provide a lower capital and operating cost 

alternative to steam sootblowers. However, the value in providing extremely clean surfaces is so 

great that the best cleaning system should be used regardless of cost. Experience is the best 

guide.

REAGENT SUPPLY BY UREA 

With the potential hazards associated with anhydrous ammonia, local communities have 

frequently demanded that utilities find alternate reagents; specifically aqueous ammonia and 

urea-based systems. By using urea, utilities 1) simplify the permitting process, 2) avoids a risk 
Cichanowicz & Muzio

Draft, 2006 Mega-Symposium

16

management program, 3) mitigate potential hazards shipping ammonia to the site, and 4) 

mitigate hazard during storage and handling at the site. These advantages require higher process 

capital, additional energy to convert urea to ammonia, and a more complex reagent handling 

system to operate; however they can be offset by indirect costs in terms of staff in developing 

risk management and safety training. 

Four systems are sold commercially in the U.S. to convert urea to ammonia for use with SCR 

systems. Two of these systems hydrolyze an aqueous urea solution, one melts solid urea and 

reacts the melted urea over a catalyst, and the fourth decomposes an aqueous urea solution by 

spraying it into a hot air stream. Each is described briefly below:

U2A was developed under an EPA Small Business Innovative Research (SBIR) award to 

EC&C Technologies, and is based on the hydrolysis of an aqueous solution of urea and/or biuret 

by heating under pressure to form a mixture of ammonia, carbon dioxide, and water. The patent 

awarded was licensed to Wahlco and Hamon Research-Cottrell.

AOD also hydrolyzes a urea solution to form gas phase ammonia and carbon dioxide. The 

process was exclusively licensed to Environmental Elements Corp. (EEC) from Hera, LLC and 

Siirtec Nigi. In December 2000, EEC announced that it executed an agreement with American 

Electric Power Company to provide additional support for the commercialization of AOD

technology in the power generation market. The agreement also grants AEP an exclusive sublicense to market and sell urea-to ammonia systems.

NOxOUT ULTRA has been developed by Fuel Tech NV and involves the atomization of a urea 

solution within a decomposition chamber containing an air or flue gas stream between 800 –

1200°F The urea dissociates at these temperatures to ammonia and isocyanic acid (NHCO), 

whereupon the vapor stream is introduced into the flue gas ahead of a SCR through an injection 

grid.

The SafeDeNOx

 process involves melting urea and mixing the liquor with steam, where it 

reacts across a catalyst to form ammonia, carbon dioxide, and water vapor. Chemithon is the 

sole implementer of this process.

Although several startup problems and operating issues were encountered on the first units, in 

time a reliable system evolved that does not limit the reliability of the SCR process or the power 

station. Of note is that safety concerns by local communities are evolving, and even for existing 

SCR equipped units, pressure to adopt urea may exist. Significantly, the Brandon Shores station 

– one of the first SCR-equipped units in the U.S. – has employed all three forms of reagent 

supply, due to evolving demands of the local community.

Each of the reagent options - anhydrous ammonia, aqueous ammonia, and urea - will feature a 

different capital and operating cost. The capital cost of these systems can vary with design, and 

a comparison is beyond the scope of the present paper. In addition to the capital cost of the 

reagent supply system, and reagent procurement cost, the energy required to vaporize, or 

decompose, the reagent is also an important factor.
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Table 7 summarizes the key cost components that can influence reagent operating cost. Also 

shown is an approximate delivered reagent cost; the latter is highly site specific and will vary 

with delivery distance and volume of material purchased. Table 7 shows that anhydrous reagent 

is usually the least cost; however local communities may assert their preference for alternative 

reagents regardless of cost. Further, when considering the demands on management and staffing 

for safety, planning, and training, anhydrous reagent may not be the least cost.

Table 7. Comparison of Key Reagent Operating Cost Variables

Reagent Energy For 

Vaporization 

(Btu/lb)

Cost for 

Vaporization

($/year)

Delivered Reagent 

Price ($/TonNH3/Urea)

NPV For 

Reference 

Unit ($M)

Anhydrous 588 $16,000 $225 3.75

Aqueous 

Ammonia, 29%

2683 $72,600 $250 4.45

Aqueous 

Ammonia, 19.5%

4312 $116,700 $400 6.82

Urea 3500 $167,200 $300 8.94

Lesson Learned. Local communities have been successful in asserting an influence in reagent 

selection. Both anhydrous and urea-based reagent supply systems offer state of art and reliable 

alternatives to anhydrous forms of ammonia. Despite the excellent safety record with anhydrous 

ammonia to date, pressure to utilize alternatives will persist.

MERCURY OXIDATION

Interest in mercury (Hg) oxidation in the last few years has escalated, with recognition that the 

combination of SCR and wet FGD can provide some degree of Hg removal. Critical to the 

amount of so-called Hg “co-benefits” is (a) the degree of Hg oxidation by the SCR, and the 

ability to retain this oxidation with time, (b) sensitivity to fuel composition, including subtle 

changes in coal chloride content, and (b) eliminating the Hg re-emission by wet flue gas 

desulfurization (FGD). Given the importance and cost impact of Hg control, it is possible the socalled “co-benefits” will supercede in importance SO2 conversion for some fuels. 

Following early tests in Germany, the first orchestrated attempts to determine the oxidation of 

Hg by SCR were conducted as part of the EPA ICR progr am. These early results prompted 

measurements to date on about 20 individual units, sponsored collectively by EPRI, the 

Department of Energy, and the EPA. Chu(16) has summarized the degree of Hg oxidation by 

SCR for 15 different units, and the results in Figure 7 suggest a weak correlation with coal 

chloride content. Data in Figure 7 are not directly comparable – almost all data points represent 

a different SCR design, catalyst composition, and operating history. The ability to predict Hg 

oxidation is the subject of study by almost all catalyst suppliers as well as independent providers 

of process models(17, 18).
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Figure 7. Hg Oxidized by SCR Process Equipment: Field Tests (after Chu, 2006)

Each of major SCR catalyst suppliers is addressing the prospect of offering Hg oxidation 

guarantees. Discussions with these suppliers suggest it is not clear if there is a link between the 

oxidation of SO2 and Hg. At least one supplier reports any link between Hg and SO2 oxidation is 

weak, and high Hg oxidation catalysts may not necessarily promote SO2 oxidation; however not 

all suppliers agree with this position. Further complicating the analysis is accuracy of Hg 

measurements, which are highly variable, and may not provide the basis for guarantee 

provisions.

Additional experience and field tests in the next years will provide key information. Two 

catalyst suppliers at present will provide guarantees for Hg oxidation, depending on coal 

composition and system design. However, owners must consider the value of the guarantee and 

the difficulty of Hg measurement – so much so that a dispute may not be satisfactorily resolved. 

First, some agreement on Hg measurement should be pursued – should it be in commercial 

systems where uncertainty may be high, or in a laboratory environment with simulated flue gas 

with well controlled conditions? Also, owners should examine the significance of the guarantee 

– as is the case with an evolving technology, the protection offered to the owner may not be 

significant in terms of liquidated damages or the value of a replacement catalyst layer. 

The importance of Hg controls and their cost will elevate Hg oxidation to a major decision factor 

in purchasing replacement or new catalyst inventory. For the 500 MW reference unit, if the 

reference coal fired contained 400 ppm chlorides, then Figure 7 suggests Hg oxidation could 

vary between 60 and 90 %. The cost significance of providing a guarantee for the higher value 
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Draft, 2006 Mega-Symposium

19

(90%) compared to simply deriving the average of 75% is significant. For the reference unit, 

assuming an Hg coal content of 7 lbs/TBtu, providing for the higher guaranteed level of 90% 

oxidation increases the production of oxidized Hg (and decreases the production of elemental 

Hg) by 40 lbs per year. Assuming 95% of this oxidized Hg is collected and not re-emitted by the 

FGD, and Hg removal allowances are valued at the minimum of DOE’s research goal of 

$25,000/lb, the 90% Hg guarantee translates into an annual benefit of $0.90 M. The NPV 7 year 

value of acquiring these Hg reductions is $5.5M, rivaling the significance of any other SCR 

operating cost reported in Table 1. Accordingly, Hg control issues may dominate SCR catalyst 

design and selection. 

Lesson Learned. Depending on coal composition and SCR design, some degree of Hg oxidation 

is provided by SCR. The extent and longevity of the effect of SCR is not clear – it is possible the 

degree of oxidation will decrease with time at a rate equal to or greater than for NOx. Hg control 

may drive future catalyst design and selection decisions.

FURTHER OBSERVATIONS

Several additional observations, although not necessarily comprising a “lesson learned”, are 

noteworthy. These items are either unresolved, have not projected a consistent trend, or 

represent concepts for which our understanding is incomplete.

Catalyst Plugging with PRB

PRB-fired SCR units have been prone to excessive plugging by fly ash – without LPA. Several 

units have experienced nearly complete blocking of turning vanes and catalyst layers, in some 

cases to 40% and more across several layers of catalyst. Conversely, other PRB-fired units have 

experienced extremely clean reactors. To date, no trend can be detected that is responsible for 

the catalyst plugging – boiler type, inlet NOx and reactor design, reagent type, etc. have all been 

evaluated. Figure 8a depicts the plugging on the catalyst surface witnessed below a reactor 

structural support, and Figure 8b shows deposits on flue gas distribution vanes.

Excessive deposits have been reported have been reported with coals other than PRB, but not to 

the same extent, unless prompted by LPA. Additional work is necessary to resolve the sources 

for this blocking, on both PRB and other coals.

Regenerated Catalyst

The use of regenerated catalyst has increased from negligible in the late 1990s, to where 

regenerated catalyst can for some applications be considered equivalent to new catalyst. The 

role of regenerated catalyst has been partially responsible for the decrease in catalyst prices 

witnessed since the mid-1990s.

At present there are at least two major players in catalyst regeneration – SCR Tech and Enerfab. 

Further, at least one catalyst supplier has teamed with providers of regeneration services to offer 

this approach.
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Figure 8a. Deposits of Ash On Catalyst Surface Below Support Beam

Figure 8b. Deposits of Ash on TurningVanes
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Draft, 2006 Mega-Symposium

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Early experience was limited, but additional installations have not identified any fatal flaws or 

compromises to design. Further, one supplier claims to be able to not restore but actually 

increase catalyst activity, for a price of approximately 60% of new catalyst costs(19). As with any 

evolving technology, additional experience is desired to evaluate how claimed catalyst 

performance characteristics change with operating time.

Although the fraction of regenerated catalyst as of mid-2006 is small compared to the initial 

inventory of new catalyst, the technology is a major factor and will provide a cost ceiling to 

catalyst prices. 

Residual NH3 Monitors

The technology of continuous residual NH3 monitors has progressed to where equipment is 

reliable, and can be used if not for process control, then at least as a operating guideline. At 

present approximately 10 stations employ residual NH3 monitors on a daily basis, to provide 

insight as to process operation. The value of the residual NH3 may not be accurate, but relative 

trends are. Residual NH3 data provides operating staff with insight as to both process upsets, the 

stability of reagent injection during load changes, and the degree of catalyst deactivation or 

plugging.

CONCLUSION

Since the first SCR applications in the U.S. in the mid-1990s, significant experience has been 

derived and taught numerous lessons. Accordingly, U.S. SCR applications are unique compared 

to previous generations. Several problems unique to the U.S., notably plugging by LPA and 

excess SO3 production, were not predicted by the suppliers and have been partially but not fully 

resolved. Although SCR capital costs have been higher than the early estimates, the resultant 

NOx control performance as shown by EPA emission rate data has in general supported industry 

needs. Innovations in achieving uniform NH3/NO mixing – key to successful performance -

have been produced primarily through the use of static mixers, and more detailed and protracted 

cold flow models or CFD studies of mixing systems. Other innovations such as cleaning catalyst 

with sonic horns instead of steam-driven sootblowers have become popular, as have urea–

derived reagents to satisfy the concerns of local communities. Eventually, the impact of SCR on 

an Hg control strategy – by oxidizing a fraction of elemental Hg - may supercede all other 

factors except NOx control. Future challenges will focus on maintaining catalyst open and 

catalyst clean, retaining catalyst high activity, and precisely controlling NH3 injection and 

mixing. 

REFERENCES

1. EPA, Investigation of Performance and Cost of NOx Controls as Applied to Group 2 Boilers, 

Draft Report, prepared by The Cadmus Group and Bechtel Power Corporation, EPA Contract 

68-D2-0168, Work Assignment 3C-08, August, 1995.

2. Hoskins, B., et al., Uniqueness of SCR Retrofits Translates Into Broad Cost Variations, 

Power Engineering, May, 2003.
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3. Cichanowicz, J.E., Why are SCR Costs Still Rising, Power Magazine, April, 2004.

4. Marano, M., et al., Estimating SCR Installation Costs, Power, January/February 2006.

5. SCR: Supremely Complex Retrofit, Power Engineering, November, 2002.

6. Ryan A., et al., SCR System Design Considerations for “Popcorn” Ash, 2002 EPRI 

Workshop, Atlanta, GA

7. Ryan A., et al., SCR System Design Considerations for “Popcorn” Ash, Proceedings of the 

2003 Mega-Symposium, May, 2003, Washington, DC.

8. Gretta, B., et al., A Proven Successful Approach to the Design of SCR LPA Screens, 

presentation to the 2005 Institute of Clean Air Companies Technical Conference, Baltimore, 

MD, March, 2005

9. Sobolewski, H., et al., Large Particle Ash (LPA) Screen Retrofits at Coal-Fired Units in 

Indiana and Ohio, 2006 US DOE Environmental Controls Conference, May 2006.

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Proceedings of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control 

Symposium, The Mega-Symposium”, August, 2004, Washington, DC.

11. Itoh, H., et al., Countermeasures For Problems In NOx Removal Process For Coal-fired 

Boilers, Proceedings of the Joint Symposium on Stationary Combustion NOx Control”, 

Volume 2, May, 1981, EPRI WS-79-220.

12. Jaersky, R. ,SO3 Generation – Jeopardizing Catalyst Operation?, Proceedings of the 1991 

Joint EPA/EPRI/DOE Symposium of Stationary Combustion NOx control, May, 1991, 

Washington, DC.

13. Blue Haze Worries Town, Akron Beacon Journal, August 2, 2001.

14. Pritchard, S., Improve Catalyst Can Clean the Air, Power Magazine, May, 2006.

15. Dombrowski, K., et al., SO3 Mitigation Guide and Cost Estimating Workbook , Proceedings 

of the U.S. EPA-DOE-EPRI Combined Power Plant Air Pollutant Control Symposium, The 

Mega-Symposium”, August, 2004, Washington, DC.

16. Chu, P., Effect of SCRs on Mercury, Proceedings of the 2006 Electric Utility Environment 

Conference, Tucson, AZ, January, 2006.

17. Niksa, S., et. al., Predicting Hg Oxidation on SCR Catalyst, presentation to the 2006 Electric 

Utilities Environment Conference, Tucson, AZ, January, 2006.
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18. Senior, C., et al., Integrated Mercury Process Model for Evaluation of Co-Benefits Strategies 

for Utility Mercury Control, presentation to the 2006 Electric Utilities Environment

Conference, Tucson, AZ, January, 2006.

19. McMahon, Bill, Catalyst Regeneration: The Business Case, Power Magazine, 

January/February, 2006.