1 

Powers Engineering 

August 11, 2011 

Reed Super, Esq. 

Super Law Group, LLC 

131 Varick Street, Suite 1001 

New York, New York 10013 

Subject: Powers Engineering comments on EPA 316(b) March 28, 2011 TDD 

Dear Reed: 

This comment letter summarizes my review of the EPA’s March 28, 2011 Technical 

Development Document for the Proposed Section 316(b) Phase II Existing Facilities Rule (2011 

TDD). The Powers Engineering review addresses the reasonableness of cooling tower retrofit 

capital costs identified by the EPA, projected turbine efficiency penalties and cooling tower 

parasitic fan and pump loads imposed by cooling towers, cooling tower retrofit downtime, air 

pollution impacts, cooling tower space requirements, uncertainties regarding useful remaining 

plant life, permit application requirements, and related issues. 

I. Summary of Findings 

• EPA’s reliance on the Electric Power Research Institute (EPRI) cooling tower cost 

spreadsheet results in average wet inline cooling tower retrofit capital costs that are 

approximately 45 percent higher than the capital costs estimated by the EPA’s own 

cooling tower retrofit cost model for wet inline cooling towers. 

• The EPRI spreadsheet capital cost estimate for a mix of 75 percent inline wet cooling 

towers and 25 percent inline plume-abated in-line cooling towers is more than 30 percent 

higher than a composite estimate based on EPA’s own cost model for wet inline cooling 

towers and a leading cooling tower manufacturer’s cost estimate for plume-abated backto-back cooling towers. 

• The EPRI cooling tower cost spreadsheet turbine efficiency penalty imposed by a cooling 

tower retrofit on a fossil plant of 1.50 percent is more than four times the 0.35 percent 

estimate in the EPA cooling tower cost model, and approximately ten times the 0.16 

percent average turbine efficiency penalty measured for the 346 MW Jeffries coal plant 

cited by the EPA in the 2002 TDD. 

• The EPRI cooling tower cost spreadsheet turbine efficiency penalty imposed by a cooling 

tower retrofit on a nuclear plant of 2.50 percent is more than six times the 0.40 percent 

estimate in the EPA cooling tower cost model. The EPA estimate is consistent with the 

turbine efficiency penalty projected for cooling tower retrofits at the Indian Point Nuclear 

Generating Station based on the cooling tower performance data provided by the plant 

owner.
2 

• The EPRI cooling tower cost spreadsheet overestimates the fan and pump energy 

penalties imposed by a cooling tower retrofit by about 30 percent relative to the EPA cost 

model. 

• EPA overestimates the typical downtime required for cooling tower hook-up at a fossil 

plant by a factor of two in the 2002 TDD and repeats the overestimate in the March 2011 

TDD. EPA identified one month as the upper end of the range for typical hook-ups, 

based on a review of actual cooling tower retrofits, but then stated that two months are 

assumed to be necessary. 

• EPA provides no substantial evidence for the assumption in the March 2011 TDD that 

seven months of downtime are necessary for a cooling tower retrofit at a nuclear plant. 

The agency provides only vague references to safety concerns, and these are contradicted 

in the same document. The 2002 TDD correctly assumed that nuclear plants would 

require the same cooling tower hook-up downtime as fossil plants. 

• EPA’s estimates that total annualized national pre-tax compliance costs for power plants 

under Option 2 and Option 3 would be $4,933 million and $5,079 million, respectively. 

These estimates are high by more than 60 percent. More realistic national pre-tax 

compliance costs for Option 2 and Option 3 are $3,029 million and $3,104 million 

annually. 

• EPA ignores clean air rules that will result in a substantial drop in air pollution emissions 

from coal plants, and a gradual and steady shift from coal to natural gas for electric 

power generation for economic reasons, in asserting an increase in air emissions from 

cooling tower conversions. What would occur is a slightly less dramatic drop in air 

emissions from fossil plants over time, not an increase in air emissions. 

• EPA ignores the most likely cooling tower configuration at space-constrained sites, the 

back-to-back in-line cooling tower configuration, in postulating a potential minimum 

space requirement of at least 160 acres per 1,000 MW of capacity for cooling towers to 

be feasible. The space requirement of back-to-back cooling towers is less than one-fifth 

the space requirement of the inline cooling towers assumed by EPA in the March 2011 

TDD. Inclusion of back-to-back cooling tower(s) in the scope of the analysis would result 

in this cooling tower option being presumptively feasible from a space requirement 

standpoint in essentially all cases. 

• Uncertainties regarding useful remaining plant life are easily addressed by allowing plant 

operators to commit to a permanent plant closure date of no later than 2020 to avoid a 

cooling tower retrofit. If the plant owner opts not to commit to closure, then the units 

should get no special consideration from the EPA regarding remaining useful life. 

• EPA should define the expected retrofit cooling tower cost and O&M values to be used in 

permit applications to minimize the tendency of each applicant to “reinvent the wheel” to 

the detriment of actually carrying-out a cooling tower conversion. These default values 
3 

should reflect the agency’s extensive evaluation and verification of these costs and 

parameters. Recommended default values for permit applications are (installed cost range 

represents range in cooling tower cost from 12 o

F to 8 oF design approach temperature): 

Installed cost, wet tower (in-line or back-to-back), $/gpm: 182 – 223 

Installed cost, plume-abated tower (in-line or back-to-back), $/gpm: 316 – 411 

Average turbine efficiency penalty (fossil or nuclear), %: 0.30 – 0.40 

Average fan parasitic energy penalty (fossil or nuclear), %: 0.40 – 0.60 

Average pump parasitic energy penalty (fossil or nuclear), %: 0.40 – 0.60 

Total retrofit downtime, months: fossil – 1, nuclear – 2 

• EPA employees or EPA contractors should be the sole arbiters of the technical adequacy 

of applications, not peer reviewers hired by the applicant. Peer reviewers hired by the 

applicant will generally become advocates for the applicant’s position, whether or not 

that position is technically sound. 

• Many existing once-through cooling (OTC) plants previously subject to the Phase II rule 

have already prepared cooling tower conversion studies. As a result, the start-to-finish 

application process for cooling tower conversions should be no more than 24 months. 

The cooling tower retrofit should be completed no more than 36 months after approval of 

the application. The one exception would be nuclear plants that may need up to 12 

additional months to synchronize the cooling tower retrofit outage with a refueling 

outage. 

II. Review of EPA’s analysis of the costs associated with retrofitting and operating closedcycle cooling towers at existing nuclear and fossil-fueled power plants 

EPA relies on an industry cooling tower cost spreadsheet developed by the Electric Power 

Research Institute (EPRI) to estimate cooling tower costs in the 2011 TDD. Reliance on the 

EPRI cost spreadsheet is problematic for two reasons: 1) EPRI can not be considered a neutral 

party in assessing the cost or difficulty of cooling tower retrofits, given EPRI member companies 

have consistently opposed such retrofits, and 2) the EPRI cost spreadsheet produces substantially 

higher costs than the well-documented EPA cooling tower cost model developed for the same 

purpose. 

Unlike the EPRI cost spreadsheet used by EPA in the 2011 TDD, the inputs to the cooling tower 

cost model developed by EPA and used in the 2002 TDD are thoroughly explained and 

corroborated with actual fossil and nuclear plant retrofit cost data. EPA also provides the cost of 

actual cooling tower retrofits in Chapter 4 of the 2002 TDD. However, EPA sets aside its 

reasonably accurate cooling tower cost model in favor of the EPRI cost spreadsheet, which 

estimates substantially higher cooling tower capital and operating costs, in the 2011 TDD. 

A. Wet inline cooling tower capital cost: The EPRI cost spreadsheet adopted by EPA, with no 

supporting documentation, produces wet inline cooling tower capital costs that are 45 

percent greater than the value produced by the EPA cost model 
4 

EPA relies exclusively on an EPRI cost spreadsheet model for determining cooling tower capital 

and O&M cost. EPA states:1

 In September 2007, EPA obtained an Excel spreadsheet from EPRI that contained a set of 

calculations for estimating cooling tower retrofit costs at existing steam power plants. EPA 

compared the EPRI model to the methodology used in the Phase II NODA and found that the 

two methods produced similar costs. Because these methods produced similar costs and the 

EPRI method was simpler and more flexible, the EPRI methodology was chosen to develop 

the model facility cost equations for the proposed rule. 

EPA also provides brief background information on the EPRI spreadsheet model and notes that 

other studies were also reviewed:2

The EPRI tool calculated costs based on documentation for over 50 closed-cycle retrofits and 

detailed feasibility studies. EPA also used cooling tower engineering assessments conducted 

for California as part of the Policy on the Use of Coastal and Estuarine Waters for Power 

Plant Cooling. These detailed assessments were conducted on 19 existing coastal plants. 

Maulbetsch and others have documented cooling tower assessments and presented such 

findings in symposiums and proceedings; for example see “Issues Associated with 

Retrofitting Coastal Power Plants” (DCN 10-6955) and “Water Conserving Cooling Status 

and Needs” Energy-Water Needs” (DCN 10-6953). 

Finally, EPA explains the basis for its assertion that the EPRI cooling tower cost methodology 

produces a similar result to the methodology used by EPA in the Phase II NODA:3

Exhibit 12-2 provides a comparison of the wet inline cooling tower compliance costs derived 

using the EPRI Tower Calculation Worksheet to compliance costs derived using the EPA 

Methodology used in 2004 Phase II for an option where cooling towers were retrofitted to 

facilities on estuaries and oceans. 

Exhibit 12-3 shows that the two costing methodologies produce similar results. While the 

2004 EPA non-nuclear and nuclear facility capital costs are comparable to the EPRI “easy” 

and “average” costs, the EPA’s O&M cost are higher for nuclear facilities. 

 1

 2011 TDD, p. 8-15. 

2

 Ibid, p. 12-6. 

3

 Ibid, p. 12-7. 
5 

The average EPA capital cost for a non-nuclear plant wet inline redwood tower is shown as $27 

million in EPA Exhibit 12-3. This is an average cost based on the retrofit cost adder of 20 

percent assumed by the EPA. EPA identifies the cost for the redwood tower at a nuclear plant as 

$49 million. EPRI does not distinguish between the cost of a cooling tower at a non-nuclear plant 

or a nuclear plant. The EPRI average retrofit cost for the same 200,000 gpm case, whether nonnuclear or nuclear, is $53 million. EPRI also identified the unit cost for an inline wet cooling 

tower retrofit as $263/gpm.4

 

EPA provides no specific information in the March 2011 TDD on why the agency assumes that 

cooling tower retrofit costs at a nuclear plant should be nearly double the cost of retrofits at nonnuclear plants for the same size cooling tower. 

EPA does provide an example calculation of its cooling tower model cost calculation procedure 

in the 2002 TDD for a fossil plant with a total circulating cooling water flowrate of 416,667 gpm 

(pp. 2-32 to 2-36). The total capital cost of the cooling tower retrofit, including a 20 percent 

retrofit premium and 1.08 labor rate multiplier for a high labor cost region, was estimated by the 

EPA as $53.55 million. The EPA estimated an additional cost of $1.955 million for intake and 

discharge piping modifications. This equals a total cooling tower retrofit cost, assuming inline 

redwood wet towers, of $55.5 million. 

An adjustment to the EPA model cost is necessary to account for the rise in costs between 1999 

and 2009. The rise in costs is on the order of 37 percent between 1999 and 2009.5

 The unit EPA 

inline redwood cooling tower retrofit cost, adjusted to 2009, would be $182/gpm, as shown in 

Table 1. The EPRI spreadsheet estimates an average in-line cooling tower retrofit capital cost 

that is approximately 45 percent higher than the cost estimated by the EPA model for the same 

 4

 March 2011 TDD, Exhibit 8-6, p. 8-18. 

5

 Chemical Engineering, Economic Indicators – Marshall & Swift Equipment Cost Index, Annual Index, January 

2006 and January 2011 editions, p. 68 and p. 60, respectively. Annual Index in 1999 = 1,068.3. Annual Index in 

2009 = 1,468.6. Rise in equipment cost between 1999 and 2009: (1,468.6 – 1,068.3)/1,068.3 = 0.3747 (37 percent). 
6 

cooling tower retrofit, $263/gpm versus $182/gpm, when the cost estimates are normalized to the 

same year.6

Table 1. EPA Cost Estimate for Standard Wet In-Line Cooling Tower 

Cooling 

tower type 

Flowrate 

(gpm) 

Cooling tower 

retrofit capital 

cost7

($) 

Intake/ 

discharge piping 

modifications 

($) 

Inflation 

multiplier, 

1999 - 

2009 

2009 EPA retrofit 

cooling tower 

capital cost 

($) ($/gpm) 

wet, inline, 

redwood, 

fresh water 

417,000 53.55 1.955 1.37 76 182 

The EPRI spreadsheet cost estimate is high relative to cooling tower manufacturer estimates as 

well as the EPA estimate. SPX is the largest manufacturer of power plant cooling towers in the 

U.S. SPX provided Powers Engineering with a generic capital cost estimate for wet back-to-back 

cooling towers and plume-abated back-to-back cooling towers for nuclear plant applications in 

2009. Back-to-back cooling towers are much more space efficient than the in-line, single cell 

width tower design assumed by EPA in the March 2011 TDD. A back-to-back tower design 

would be the likely cooling tower choice at space-constrained sites. SPX assumed a cooling 

tower design approach temperature of 12 o

F and a design range of 20 oF. The SPX back-to-back 

cooling tower capital cost information is summarized in Table 2 and is provided as Attachment 

A to this comment letter. 

The EPRI cost spreadsheet adopted by the EPA assumes, in addition to an average wet cooling 

tower retrofit cost of $263/gpm, an average plume-abated cooling tower retrofit cost of 

$383/gpm.8 The EPRI composite wet cooling tower retrofit cost, assuming 75 percent of cooling 

tower retrofits are inline wet towers and 25 percent are plume-abated inline wet towers, is 

$293/gpm.9

 6

 EPA in-line retrofit tower cost + piping modifications: $55,500,000/416,667 gpm = $133/gpm. Inflation 

adjustment: 1.37 × $133/gpm = $182/gpm. EPRI spreadsheet capital cost estimate, average retrofit: $263/gpm . 

EPRI spreadsheet estimate is about 45 percent higher than adjusted EPA estimate: $263/gpm ÷ $182/gpm = 1.49. 

7

 SPX states in its June 2009 cost estimate that “Infrastructure cost is estimated by some at 3 times the cost of the 

wet tower, including such things as site prep, basins, piping, electrical wiring and controls, etc.” Therefore, the total 

capital cost of the wet back-to-back tower in a fresh water application is the “wet tower only” cost of $36.4 million 

+ (3 × $36.4 million) = $145.6 million. 

8

 March 2011 TDD, Exhibit 8-7, p. 8-18. 

9

 Ibid. 
7 

Table 2. Summary of SPX June 2009 Cost Estimate for Wet and Plume-Abated Back-toBack Cooling Towers, 12 o

F Approach Temperature, 20 oF Range 

Cooling tower 

type 

Flowrate 

(gpm) 

Capital 

cost10

($) 

Unit cost 

($/gpm) 

EPA 

retrofit 

multiplier 

Capital cost including 

retrofit multiplier 

($) ($/gpm) 

standard wet, 

back-to-back, 

fresh water 

830,000 145.6 175 1.20 175 210 

plume-abated, 

back-to-back, 

fresh water 

830,000 218.3 263 1.20 262 316 

standard wet, 

back-to-back, 

salt water 

830,000 154.4 186 1.20 185 223 

plume-abated, 

back-to-back, 

salt water 

830,000 231.4 279 1.20 278 335 

B. EPA cooling tower sizing 10 o

F design approach temperature is conservative for most 

regions of the country, which lead to conservative estimates of capital cost 

The EPA cooling tower cost model assumes a relatively conservative approach temperature of 

10o F. EPA lists “Maulbetsch and others” as a source of cooling tower cost reference material in 

the 2011 TDD.11 Maulbetsch identifies a cooling tower approach range of 8 to 15 oF and states 

that, in general, warmer, more humid conditions lead to lower approach temperatures in the 

southeastern U.S. and cooler, drier climates lead to higher approach temperatures in the northern 

and western regions.12 At any particular site, a lower approach temperature translates into a 

larger and more costly the cooling tower, as EPA notes in the 2002 TDD:13

Two cooling tower industry managers with extensive experience in selling and installing 

cooling towers to power plants and other industries provided information on how they 

estimate budget capital costs associated with a wet cooling tower. The rule of thumb they use 

is $30/gpm for an approach of 10 degrees and $50/gpm for an approach of 5 degrees. 

EPA’s use of 10 o

F as the assumed approach temperature in the cooling tower cost model is a 

very conservative assumption for most parts of the country. The 2002 TDD Appendix A list of 

 10 SPX states in its June 2009 cost estimate that “Infrastructure cost is estimated by some at 3 times the cost of the 

wet tower, including such things as site prep, basins, piping, electrical wiring and controls, etc.” Therefore, the total 

capital cost of the wet back-to-back tower in a fresh water application is the “wet tower only” cost of $36.4 million 

+ (3 × $36.4 million) = $145.6 million. 

11 Ibid, p. 12-6. 

12 J. Maulbetsch, Comparison of Alternate Cooling Technologies for California Power Plants - Economic, 

Environmental and Other Tradeoffs, CEC Consultant Report, February 2002, pp. 2-8 and 2-9. “Tower approach, 

Tcold water – Tambient wet bulb: 8 to 15 oF. In general, warmer, more humid conditions lead to lower approach temperatures 

in the southeastern U.S. and cooler, drier climates lead to higher ones in the northern and western regions.” 

13 April 2002 TDD, p. 2-20. 
8 

specifications for actual cooling towers lists fifteen towers at or above a flowrate of 100,000 

gpm.

14 Six of these towers are located in the Southeast. Nine towers are located in other parts of 

the country. The average approach temperature of the six cooling towers in the Southeast is 8.7 o

F. The average approach temperature of the nine cooling towers located in other parts of the 

country is 12.6 o

F. Figure 1 shows the effect of cooling tower design approach temperature on the 

size of the cooling tower. 

Figure 1. Cooling Tower with 10 oF Approach Temperature Is 25 Percent Larger than 

Tower with 13 o

F Approach Temperature15

For the purpose of calculating the nationwide cost of plume-abated cooling towers, it is assumed 

in this comment letter that 25 percent of the plume-abated cooling tower retrofits would occur in 

the Southeast and would be designed for a 8 o

F approach temperature. Cooling towers for other 

areas of the U.S. would be designed for a 12 oF approach temperature. Cooling towers in the 

Southeast would be about 30 percent larger than cooling towers in the rest of the country for the 

same circulating water flowrate, as determined in Attachment B. All of the plume-abated units 

are assumed to utilize a compact, back-to-back design.16

From Table 1, the unit cost of back-to-back plume-abated cooling tower with a 12 oF design 

approach temperature is $316/gpm. Decreasing the design approach temperature to 8 o

F would 

increase the capital cost by about 30 percent to: $316/gpm × 1.3 = $411/gpm. 

The composite nationwide capital cost of plume-abated back-to-back cooling towers, assuming 

75 percent have a design approach temperature of 12 o

F and 25 percent have an approach 

temperature of 8 oF is: (0.75 × $316/gpm) + (0.25 × $411/gpm) = $340/gpm. 

 14 April 2002 TDD, Attachment C to Chapter 5: Design Approach Data for Recent Cooling Tower Projects. The 

100,000 gpm cooling tower circulating water flowrate threshold represents larger fossil fuel and nuclear units 

approximately 200 MW and up. 

15 SPX Cooling Technologies, Cooling Tower Fundamentals, 2nd Edition, 2006, p. 23. Red tags and lines added by 

B. Powers. 

16 This assumption is made to simplify cost calculations. The final mix of cooling towers could include wet back-toback cooling towers and inline plume-abated cooling towers. 
9 

C. Unlike the EPRI cost spreadsheet, the non-fossil fuel EPA cooling tower cost model inputs 

in the 2002 TDD are thoroughly explained and corroborated with actual fossil and nuclear 

plant retrofit cost data 

EPA provides extensive detail on the cooling tower cost model presented in the 2002 TDD. EPA 

also provides the cost of actual cooling tower retrofits in Chapter 4 of the 2002 TDD. The costs 

of these actual cooling tower retrofits are summarized in Table 3. 

Table 3. Cost of Closed-Cycle Retrofits at Selected U.S. Sites 

Site MW Flowrate 

(gpm) 

Cost of Retrofita 

($MM) ($/kW) ($/gpm) 

Palisades Nuclear 800 410,000 55.9 70 136 

Pittsburg Unit 7 751 352,000 34.4 46 98 

Yates Units 1-5 550 460,000 87.0b 158 189 

Canadys Station 490 Not availablec

Jeffries Station 346 Not availablec

a) Retrofit costs for Palisades Nuclear and Pittsburg Unit 7 are in 1999 dollars. Yates 1-5 cooling tower cost is in 2002 dollars. 

b) The Yates cooling tower is designed to achieve a 6 o

F approach temperature. Original estimate $75 million. Revised $87 

 million cost includes wetland remediation, remediation of old asbestos landfill where towers were to be constructed, and 

 reinforcement of concrete cooling water conduits. 

c) The U.S. Army Corps of Engineers (COE) paid for the cooling tower retrofit. COE diversion of riverwater was the reason 

 that the retrofit needed to be carried out. 

The EPA specifically notes in the 2002 TDD that the cooling tower retrofit cost model it 

developed was very accurate, especially for the Palisades Nuclear plant, stating (p. 2.23): 

As described in Chapter 4, the Agency obtained two empirical, total project costs for cooling 

tower conversion projects. The Agency calculated estimated project costs based on the 

methodology presented in Example 2 below and determined that for the case of the Palisades 

conversion that the Agency’s methodology was very accurate. 

In Example 2 of the 2002 TDD, EPA calculated the cost of the conversion of a plant to a cooling 

tower with a flowrate of 417,000 gpm and a 10o F approach temperature. The cost of the cooling 

tower and piping upgrades was calculated as $55.5 million (assuming 20 percent retrofit cost 

premium and 1.08 labor premium).17 This equals a cost per gpm cost of: $55,500,000/ 417,000 

gpm = $133/gpm (1999 dollars). A cost of $8,744,600 was identified for the surface condenser 

upgrade. This cost includes a charge for the premature retirement of the existing surface 

condenser. EPA calculated a retrofit cost with a full condenser upgrade of $64,245,000. The cost 

per gpm = $64,245,000/417,000 gpm = $154/gpm (1999 dollars). 

The EPA cooling tower cost model is conservative, as it assumes larger closed cycle cooling 

flows than are specified for actual closed cycle installations. This means that the model cooling 

tower fan energy and pump energy requirements are also conservative. The EPA states:18 

 17 April 2002 TDD, p. 2.32. 

18 Ibid, p. 2-18. 
10 

Published condenser flows and generating capacity data from the Nuclear Regulatory 

Commission (DCN 4-2521)) for all nuclear units in the US demonstrates that recirculating 

cooling systems have lower condenser flow to MW ratios than once through systems, 

regardless of age or other characteristics. After considering this information, EPA chose a 

conservative approach and used the design cooling water intake flow of the baseline oncethrough system intake to estimate the size of the recirculating cooling tower and associated 

conduit system for its model facilities. 

The EPA model is also very conservative in asserting a surface condenser upgrade cost of $8.7 

million dollars for a circulation rate of 417,000 gpm. Thermal Engineering International, Inc. 

(TEI) is a leader in surface condenser upgrades.19 TEI estimated a cost of $600,000 to replace the 

tube bundle and waterboxes on 235 MW Danskammer Unit 4 in 2005.20 The Danskammer plant 

is located on the Hudson River. Unit 4 is designed for a circulating cooling water flowrate of 

150,000 gpm.21 A linear scale-up of this surface condenser upgrade cost estimate, for a 417,000 

gpm circulating cooling water flowrate, would be: ($600,000 x 417,000 gpm/150,000 gpm) = 

~$1.7 million. This is approximately one-fifth the cost that EPA attributes to the surface 

condenser upgrade for a flowrate of 417,000 gpm in the 2002 TDD. 

The EPA also fails to note in the 2002 TDD that a surface condenser upgrade typically results in 

about a 0.5 percent efficiency improvement over original equipment.22 This performance 

improvement would significantly offsets the efficiency reduction associated with the cooling 

tower retrofit. 

D. EPA’s March 2011 TDD repeats the same errors in 2002 TDD regarding cost premium to 

retrofit cooling towers at nuclear plants 

The EPA cooling tower cost model, without the inclusion of cost premiums for nuclear safetyrelated issues such as blasting restrictions near operating reactors, was confirmed by the agency 

as conservative and reasonably accurate for both fossil fuel plant retrofits and nuclear plant 

retrofits (Palisades Nuclear) in the 2002 TDD. 

Despite confirming in Example 2 in the 2002 TDD that the EPA cost model is accurate for fossil 

fuel and nuclear plants without cost premiums for nuclear plant construction activities,23 in the 

 19 See TEI webpage on surface condenser upgrade projects: http://www.babcockpower.com/products/heatexchangers/thermal-engineering/products/surface-condensers#more-1. 20 Telephone communication, P. Luhring/Thermal Engineering International, and B. Powers/Powers Engineering, 

September 16, 2005. 

21 New York Department of Environmental Conservation, Danskammer Point Generating Station Biological Fact 

Sheet, 2003, p. 1. Unit 4 has three cooling water pumps rated at 50,000 gpm each. 22 Telephone communication, P. Luhring/Thermal Engineering International, and B. Powers/Powers Engineering, 

September 16, 2005. P. Luhring – Typical gain on a 500 MW unit is 2-3 MW with tube bundle replacement. This is 

a 0.5 percent efficiency improvement over original equipment. The project scope would include tubes, tubesheets, 

and support plants. TEI prefers to replace waterboxes with the tube bundle replacement to ease alignment. 23 2002 TDD, p. 2-23. “The Agency calculated estimated project costs based on the methodology presented in 

Example 2 below and determined that for the case of the Palisades conversion that the Agency’s methodology was 

very accurate.” 
11 

same document EPA identifies substantial cost multipliers for retrofit work at nuclear plants. The 

agency provides no references to support these multipliers. For example, the 2002 TDD states:24 

“Intake modification construction costs are based on the following general framework: . . . 

Also, EPA doubled costs of demolition and excavation (at nuclear plants) to account for 

concerns that use of blasting and high-impact equipment may be limited at nuclear facilities.” 

EPA assigns a 1.58× nuclear plant multiplier in the 2002 TDD with no supporting 

documentation.25 EPA states in the 2011 TDD that it considered a wide variety of technical 

aspects associated with retrofitting cooling towers, including (but not limited to) the availability 

of land, noise and plume effects, evaporative losses, and nuclear safety concerns.26 However, the 

only additional information given in the document regarding nuclear safety issues contradicts the 

presumption that retrofitting cooling towers at a nuclear plant would add cost relative to a retrofit 

at a fossil plant. Specifically, the EPA states:27

While nuclear safety remains a paramount concern, it is less clear that retrofitting a cooling 

tower would actually have any impact on the safety of the facility. Documentation submitted 

to the Atomic Energy Commission from Palisades Plant (the lone nuclear facility to undergo 

a closed-cycle retrofit) indicates that “[t]he existing cooling water system [...] has no safety 

related functions and the modified system will likewise have no safety related functions.” See 

DCN 10-6888B. 

EPA states qualitatively that nuclear retrofit cost is driven up in part due to nuclear safety 

concerns, yet points-out that the predecessor agency to the NRC, the Atomic Energy 

Commission, indicates there are no safety concerns related to cooling tower retrofits at nuclear 

plants. 

 

There is no inherent safety issue with nuclear plants operating as exclusively closed-cycle units, 

or as combination units capable of operating either in closed cycle mode or in OTC mode. The 

2011 TDD points-out that 23 U.S. nuclear plants use closed cycle cooling, 8 have combination 

closed cycle/OTC capability, and 31 are OTC plants.28 EPA also notes that a somewhat larger 

percentage of nuclear facilities use closed-cycle cooling than non-nuclear facilities.29 Cooling 

towers are common at U.S. nuclear plants. 

EPA presents no documentation in the 2002 TDD, the 2003 Phase II NODA, or the 2011 TDD to 

support its contention that the cost of cooling tower retrofits at nuclear plants is substantially 

higher than at fossil fuel plants. In contrast, the EPA does summarize the position of the NRC 

predecessor agency, the Atomic Energy Commission, that there are no safety issues associated 

with the cooling tower retrofit at the one U.S. nuclear plant that has been retrofit with cooling 

towers, Palisades Nuclear in Michigan. None of the qualitative concerns expressed by EPA, 

 24 Ibid, p. 2-2 and 2-3. 

25 Ibid, p. 2-35. 

26 2011 TDD, p. 2-23. 

27 Ibid, p. 6-9. 

28 Ibid, p. 4-9: Exhibit 4-10, Types of cooling systems at US nuclear plants. 29 Ibid, p. 5-4, Exhibit 5-5. 
12 

which are used by the agency as the basis for adding considerable extra cost to retrofitting 

cooling towers at nuclear plants, are supported in the record. 

E. The EPRI composite cooling tower retrofit cost adopted by EPA in the March 2011 TDD, 

including wet and plume-abated inline cooling towers, is over 30 higher than the 

composite cooling tower cost calculated using EPA and industry cost estimates 

The composite nationwide unit cost for cooling tower retrofits using the EPA cost estimate for 

wet inline cooling towers and the SPX cost estimate for plume-abated back-to-back cooling 

towers is: (0.75 × $182/gpm) + (0.25 × $340/gpm) = $222/gpm. The composite nationwide unit 

cost for average difficulty cooling tower retrofits developed by EPRI and adopted by EPA of 

$293/gpm is 32 percent higher than the estimate based on EPA and SPX cost estimates.30

II. Reasonableness of EPA’s estimate of turbine efficiency penalty and cooling tower 

parasitic fan and pump loads for nuclear and fossil plants 

A. The EPRI cost spreadsheet adopted by EPA with no supporting documentation 

produces a turbine efficiency penalty that is approximately 5x the EPA cost model 

annual average turbine efficiency penalty and 10x the turbine efficiency penalty 

identified by the EPA for the Jefferies coal plant cooling tower retrofit 

The 2011 TDD summarizes the EPRI cost spreadsheet factors the EPA has adopted for use in 

Exhibit 8-6:31

The EPRI cost spreadsheet summarized in Exhibit 8-6 assigns a turbine efficiency penalty of 1.5 

percent to fossil fuel plants and 2.5 percent to nuclear plants. 

In an effort to demonstrate that the EPRI turbine efficiency penalty estimates are accurate, EPA 

misstates the turbine efficiency penalty caused by a cooling tower retrofit:32 

The turbine efficiency penalty is typically expressed as a percentage of power output. In the 

Phase I Rule, EPA estimated an annual average energy penalty of 1.7 percent for nuclear and 

fossil-fuel plants and 0.4 percent for combined cycle plants. The estimated maximum 

summer penalty was 1.9 percent. The EPRI supporting documentation (DCN 10-6930) 

 30 $293/gpm ÷ $222/gpm = 1.32 (32 percent). 

31 March 2011 TDD, , p. 8-18, Exhibit 8-6: Cooling Tower Costs for Average Difficulty Retrofit. 32 March 2011 TDD, p. 8-25. 
13 

estimates the energy penalty to range between 1.5 percent and 2.0 percent, and the EPRI cost 

model uses 2.0 percent as the built-in default. 

In this statement, EPA confuses the peak turbine efficiency penalty with the annual average total 

energy penalty, which includes annual average turbine efficiency, cooling tower fan and pump 

energy demand. Both the 2001 Phase I TDD and the 2002 TDD included the average heat rate 

penalty, fan penalty, and pump penalty for nuclear, fossil fuel, and combined cycle plants. The 

average annual turbine efficiency penalty data is presented in Table 4 below. As shown in Table 

3, the peak turbine efficiency penalty produced by its model is substantially lower than the 

average turbine efficiency penalties included in the EPRI cost spreadsheet. The average turbine 

efficiency penalties calculated using the EPA model, and corroborated at both coal and nuclear 

plants that have been retrofit with cooling towers, are on the order of one-fifth the values 

calculated with the EPRI cost spreadsheet. 

Table 4. EPA Cost Model – Annual Average and Peak Turbine Efficiency Penalty33

Plant Type Average Turbine Efficiency Penalty (%) Peak Turbine Efficiency Penalty (%)

Nuclear 0.40 1.03 

Fossil Fuel 0.35 0.90 

Combined Cycle 0.06 0.19 

The turbine efficiency penalties shown in Table 3 are reasonably accurate, based on detailed 

efficiency penalty analyses for two coal-fired plants and one nuclear plant. The first is the 346 

MW Jeffries Generating Station in South Carolina. A summary of this analysis was included in 

the 2002 TDD (p. 5-34). The second is the Powers Engineering analysis of the turbine efficiency 

penalty that would be incurred by retrofitting 235 MW coal-fired Danskammer Unit 4 to a 

plume-abated wet cooling tower.34 This analysis is included as Attachment C to this comment 

letter. Danskammer Unit 4 is cooled with water from the Hudson River. 

The EPA identifies the annual average turbine efficiency penalty of the 10 o

F approach 

temperature Jefferies cooling tower retrofit as 0.16 percent and the peak efficiency penalty as 

0.90 percent, stating: 

“The Jefferies Generating Station – a 346 MW, coal-fired plant in South Carolina – owned 

by Santee Cooper, conducted a turbine efficiency loss study in the late 1980s. The study 

lasted several years (1985 to 1990). The efficiency penalties determined by Santee Cooper 

were a maximum of 0.97 percent of plant capacity (for both units, combined) and an annual 

average of 0.16 percent for the year 1988. The Agency notes that its fossil-fuel estimate for 

the national-average, peak-summer, turbine energy penalty is 0.90 percent and the meanannual, national-average energy penalty is 0.35 percent (at 100 percent of maximum load).” 

 33 2001 Phase I TDD, Table 3-14, p. 3-20, and 2002 TDD, Table 5-10, p. 5-20. 

34 Rebuttal Testimony of William Powers, P.E. on Behalf of Petitioners Riverkeeper, Inc., Scenic Hudson Inc. and 

Natural Resources Defense Council, Inc., NYDEC - In The Matter of a Renewal and Modification of a State 

Pollutant Discharge Elimination System (“SPDES”) Permit SPDES No. NY-0006262 by Dynegy Northeast 

Generation, Inc., on Behalf of Dynegy Danskammer, LLC (Danskammer Generating Station), November 7, 2005, 

Exhibit 11. 
14 

p. 4-2: “The Agency contacted Santee Cooper to learn about the cooling system conversions 

at Jefferies (Henderson, 2002). The Charleston District of the U.S. Army Corps of Engineers 

paid for the construction of the tower system (a common, mechanical-draft, concrete cooling 

tower unit for both units with a design approach of 10 o

F and a range of 19 oF) because of the 

re-diversion of the Santee Cooper River.” 

The coal-fired Danskammer Unit 4 cooling tower retrofit analysis assumed use of a plumeabated cooling tower with a 13 o

F approach temperature and 20 oF range. The annual average 

turbine efficiency penalty of the cooling tower relative to the existing once through cooling 

configuration was calculated to be approximately 0.2 percent. The peak turbine efficiency 

penalty was calculated to be approximately 1.5 percent.35 The reason for the small annual 

average turbine efficiency penalty is that the Hudson River increases to over 80 o

F in summer, 

which increases backpressure on the turbine. 

This phenomenon is shown in Figure 2 for Unit 2 at the Indian Point Nuclear Generating Station 

(Indian Point). The output of Indian Point Unit 2 drops from 1,015 MW at a river temperature of 

55 o

F to 983 MW at 82 oF. This is a 3.4 percent drop in output due to the turbine efficiency 

penalty experienced by the existing OTC cooling system as the river temperature rises to its 

maximum monthly level. 

 35 Ibid. 
15 

Figure 2. Reduction in MW Output from Indian Point Nuclear Unit 2 as Hudson River 

Temperature Increases36

The owner of Indian Point, Entergy Nuclear, determined the month-to-month turbine efficiency 

penalty of a cooling tower conversion on MW output from Indian Point Units 2 in its analysis of 

the feasibility and cost of such a conversion.37 Powers Engineering has overlaid curves showing 

the decline in MW output of the existing OTC-cooled Units 2 and 3 caused by increasing 

Hudson River water temperature on the cooling tower turbine efficiency penalty curves prepared 

by Entergy Nuclear.38 This data is presented in Attachment D. 

The average annual turbine efficiency penalty that would be imposed on Indian Point Unit 2 by a 

cooling tower conversion would be approximately 5 MW, or approximately 0.5 percent. The 

average annual turbine efficiency penalty imposed on Indian Point Unit 3 by a cooling tower 

conversion would be approximately 2 MW, or approximately 0.2 percent. See Tables D-1 and D-

 36 Enercon, Conversion of Indian Point Units 2 & 3 to a Closed-Loop Cooling Water Configuration, Attachment 1- 

Economic and Environmental Impacts Associated with Conversion of Indian Point Units 2 and 3 to a Closed-Loop 

Condenser Cooling Water Configuration, June 2003, p. 21. 37 Ibid, Figures 3-7 and 3-8, p. 24. 

38 Hudson River monthly average temperature data is taken from Attachment C. This river water temperature data 

was collected at the Danskammer Generating Station approximately 20 miles upriver from Indian Point. The 

monthly river water temperature is applied to the “river water temperature versus MW output” curves provided by 

Entergy Nuclear consultant Enercon in its June 2003 report “Conversion of Indian Point Units 2 & 3 to a ClosedLoop Cooling Water Configuration, Attachment 1- Economic and Environmental Impacts Associated with 

Conversion of Indian Point Units 2 and 3 to a Closed-Loop Condenser Cooling Water Configuration.” 
16 

2 in Attachment D. The average annual turbine efficiency penalty of both Indian Point Unit 2 

and Unit 3, approximately 0.4 percent, is consistent with the EPA determination in the 2002 

Phase II TDD that the average turbine efficiency penalty imposed by a cooling tower conversion 

at a nuclear plant would be 0.40 percent. 

EPA also determined the peak and annual average total energy penalty for the cooling tower 

conversion at the Palisades Nuclear Plant in Michigan as 2.7 percent and 1.8 percent 

respectively, stating:39

The Agency learned from discussions with, and information submitted by, Consumers 

Energy that the cooling tower system at Palisades might have a significant impact on the 

efficiency of the plant’s generating unit. . . Therefore, the Agency estimates that the total 

energy penalty of the recirculating tower system at Palisades may have a peak energy penalty 

close to 2.7 percent and an annual penalty approaching 1.8 percent as compared to the 

original once-through system (Sunda, et al., 2002). 

Based on the Agency’s energy penalty methodology, the turbine energy penalty for a nuclear 

unit (at peak summer conditions) would be approximately 1.4 percent (11.3 MW for 

Palisades). The Agency calculated this penalty using the historic cooling water temperature 

data for Palisades provided by Consumers Energy and ambient dry bulb and wet bulb air 

temperatures specific to Chicago, IL (Consumers, 2001). 

The annual average total energy penalty of 1.8 percent for Palisades is consistent with the EPA 

cost model presented in the 2002 TDD, which calculates a total cooling tower retrofit energy 

penalty for a nuclear plant of just over 1.5 percent (see Table 5). 

EPA shifts from using the annual average turbine efficiency penalty in the 2002 TDD, which is 

the appropriate measure of net electricity not delivered to the grid over time by a cooling tower 

conversion, to using peak turbine efficiency penalty in the 2003 Phase II NODA. The use of peak 

turbine efficiency is also carried into the 2011 TDD. This shift is described in the 2003 Phase II 

NODA in the following manner:40

Energy Penalties For the proposed Phase II rule, the average annual energy penalty, by

region and fuel type, was applied to each facility upgrading to a closed cycle, recirculating 

cooling system. Based on comments received, EPA has changed the energy penalty 

assumption to attempt to account for seasonal, peak effects. For the new analyses, the energy 

penalty applied is the greater of the peak-summer penalty or the average annual penalty for 

each facility projected to convert their cooling systems to a closed-cycle, recirculating 

cooling system. EPA notes that the approach used at proposal might have understated 

potential impacts of the energy penalty on generating capacity. 

Conversely, using the greater of the peak summer penalty and the average annual penalty 

might overestimate potential impacts of the energy penalty on generating capacity. EPA has 

adopted the latter approach in order to ensure that impacts are not underestimated. 

 39 2002 TDD, p. 5-36 and p. 5-37. 

40 Phase II NODA, Federal Register /Vol. 68, No. 53 /Wednesday, March 19, 2003 / Proposed Rules FR 13525. 
17 

What matters from a cost of replacement power and air emissions standpoint is the annual 

average turbine efficiency penalty, not the peak. The change by EPA from use of the annual 

average total energy penalty to the peak energy penalty was an error. It is also an error in the 

EPRI model. Peak output reductions caused by use of retrofit cooling towers are significant only 

to the extent that insufficient reserve margin is available to assure continuity of service during 

peak demand periods. 

Also, grid operators are constantly going out for bid for new capacity to assure that reserve 

margins in excess of grid reliability requirements are maintained. For example, PJM just 

accepted bids for more than 4,800 MW of demand response capacity to meet projected reserve 

margin requirements.41 For this reason, the slight peak demand reduction caused by the 

installation of retrofit cooling towers will not impact grid reliability. 

B. The EPRI cost spreadsheet adopted by EPA produces cooling tower fan and pump 

parasitic loads that are about 30 percent higher than the values produced by the EPA 

cost model 

The 2002 TDD includes the average cooling tower fan energy penalty and pump energy penalty 

for nuclear, fossil fuel, and combined cycle plants. The EPA cooling tower fan and pump energy 

penalties are presented in Table 5. The average fan power penalty assumed in the 2002 TDD is 

incorrect, as it is for a cooling tower with a 5 o

F approach temperature. The EPA cost model 

assumes a cooling tower with a 10 oF approach temperature. Use of the 10o F cooling tower fan 

power penalty from the same EPA dataset reduces the fan energy penalty. The correct fan 

penalty for a 10o F approach cooling tower is provided in Table 4. Table 4 also includes the 

combined fan and pump energy penalty calculated using the EPRI cooling tower fan and pump 

energy penalty factor for the same cooling tower case. 

As shown in Table 6, the annual average total energy penalty calculated for nuclear plants using 

the EPA cost model, at 1.51 percent, is substantially lower than the turbine efficiency penalty of 

2.5 percent the EPRI cost spreadsheet assumes for nuclear plants. The annual average total 

energy penalty for fossil fuel plants using the EPA cost model, at 1.24 percent, is lower than the 

turbine efficiency penalty of 1.5 percent the EPRI cost spreadsheet assumes for fossil fuel plants. 

 41 Public Utilities Fortnightly, Up in smoke: demand response knocks 6.9 GW of coal out of PJM, June 29, 2011. 
18 

Table 5. Comparison of EPA and EPRI Cost Model Outputs Assuming 525 MW Plants– 

Cooling Tower Pump and Fan Power Penalty 

Plant Type EPA Model EPRI Model 

Pump 

power 

energy (%) 

Fan power 

energy 

(%)42

Total pump 

and fan power 

energy (%) 

Total pump 

and fan power 

energy (MW) 

Total pump and 

fan power 

energy (MW)43

Nuclear 0.55 0.56 1.11 5.6 7.2 

Fossil Fuel 0.44 0.45 0.89 4.5 5.8 

Combined 

Cycle 

0.15 0.15 0.30 1.5 1.9 

Table 6. EPA Cost Model – Annual Average and Peak Total Energy Penalty 

Plant Type Annual Average Penalty (%) 

Turbine 

efficiency 

Fan power 

energy

44

Pump power 

energy 

Total Energy 

Penalty 

Nuclear 0.40 0.56 0.55 1.51 

Fossil Fuel 0.35 0.45 0.44 1.24 

Combined Cycle 0.06 0.15 0.15 0.36 

The EPA cooling tower cost model provides reasonably accurate estimates of annual average 

turbine efficiency penalty, fan energy demand, and pump energy demand. The EPRI cost 

spreadsheet substantially overestimates the turbine efficiency penalty and moderately 

overestimates the fan and pump energy requirements. EPA should continue to use efficiency 

 42 EPA model cooling tower costs are based on a cooling tower with a 10 o

F approach temperature. EPA identifies 

representative fan power energy penalties in Table 5-12 of the 2002 TDD for four sample plants. The fan power 

energy penalties shown are for Plant #3 using a cooling tower with an approach temperature of 10 o

F and a flowrate 

of 243,000 gpm. None of the other cooling towers in Table 5-12 have an approach temperature of 10 o

F. Table 5-15 

of the 2002 TDD, Summary of Fan and Pumping Energy Requirements as a Percent of Power Output, incorrectly 

uses the fan power energy penalty for a 5 o

F approach cooling tower and not the design 10 oF approach cooling 

tower assumed in the EPA cost model.

43 The EPRI cost spreadsheet assumes that the combined cooling tower pump and fan parasitic load = the cooling 

tower flowrate in gpm × 0.0000237. See 2011 TDD, Exhibit 8-6, p. 8-18. EPA provide the projected MW capacity 

for nuclear, fossil fuel, and combined cycle plants with a closed-cycle cooling flowrate of 243,000 pgm in Table 5-

12, Wet Tower Fan Power Energy Penalty. These MW capcities are: nuclear – 420 MW, fossil – 525 MW, 

combined cycle – 1,574 MW. If the plant capacities are normalized to 525 MW, the cooling water flowrates 

become: nuclear – (525 MW/420 MW) × 243,000 gpm = 304,000 gpm; fossil – (525 MW/525 MW) × 243,000 gpm 

= 304,000 gpm; combined cycle – (525 MW/1,574 MW) × 243,000 gpm = 81,000 gpm 

44 EPA model cooling tower costs are based on a cooling tower with a 10 o

F approach temperature. EPA identifies 

representative fan power energy penalties in Table 5-12 of the 2002 TDD for four sample plants. The fan power 

energy penalties shown are for Plant #3 using a cooling tower with an approach temperature of 10 o

F and with a 

flowrate of 243,000 gpm. None of the other cooling towers in Table 5-12 have an approach temperature of 10 o

F. 

Table 5-15 of the 2002 TDD, Summary of Fan and Pumping Energy Requirements as a Percent of Power Output, 

incorrectly uses the fan power energy penalty for a 5 o

F approach cooling tower and not the design 10 oF approach 

cooling tower assumed in the EPA cost model.
19 

penalty estimates from its retrofit cooling tower cost model and not rely on the EPRI cost 

spreadsheet. 

III.Reasonableness of EPA’s estimate of retrofit downtime 

A. EPA’s reasoning on downtime is contradicted by the record 

EPA identifies the hook-up time for the Jefferies coal-plant cooling tower retrofit at one week 

and the Canadys retrofit as four weeks in the 2002 TDD. In other cases, Pittsburg 7 and Palisades 

Nuclear the specific amount of time necessary to interconnect the retrofit cooling tower was not 

reported. The Plant Yates (Georgia) retrofit was completed in 2002. The hook-up was carried-out 

when the plant was off-line for an extended outage at a time the plant was not necessary for grid 

reliability. Where accurate information is available on hook-up times, specifically at the Canadys 

Station and Jefferies Station sites, the closed-cycle system hook-up was completed within the 

scheduled plant outage period. The site-specific retrofit issues at each of these five retrofit sites is 

summarized in Table 7. 

Table 7. Site Specific Issues Associated with Utility Boiler Closed-Cycle Retrofits45,46

Site Issues 

Pittsburg 

Unit 7 

Cooling towers replaced spray canal system. Towers constructed on narrow strip of 

land between canals, no modifications to condenser. Hookup time not reported. 

Yates 

Units 1-5 

Back-to-back 2×20 cell cooling tower. 1,050 feet long, 92 feet wide, 60 feet tall. 

Design approach is 6o

 F. Cooling tower return pipes discharge into existing intake 

tunnels. Circulating pumps replaced with units capable of overcoming head loss in 

cooling tower. Condenser water boxes reinforced to withstand higher system 

hydraulic pressure. Existing discharge tunnels blocked. New concrete pipes 

connect to discharge tunnels and transport warm water to cooling tower. 

Canadys 

Station 

Distance from condensers to towers ranges from 650 to 1,700 feet. No 

modifications to condensers. Hookup completed in 4 weeks. 

Jefferies 

Station 

Distance from condensers to wet towers is 1,700 feet. No modifications to 

condensers. Two small booster pumps added. Hookup completed in 1 week. 

Palisades 

Nuclear 

The conversion required new circulating pumps due to increased pumping head. No 

modifications to the condensers were initially carried-out. The condenser tubes 

subsequently replaced due to leaks unrelated to conversion. The condenser tubes 

were failing with the once-through system due to vibration. The plant was shut 

down because of various operational problems in August 1973. Consumers Energy 

stated that operational problems unrelated to the cooling tower conversion had been 

mostly responsible for the extended (10 month) outage (see DCN 4-2502).

The EPA established a strong case for one month as a reasonable and conservative outage period 

for a cooling tower hook-up in the 2002 TDD, stating: 

 45 2002 TDD, Chapter 4. 

46 EPA Region 1, memorandums on conversion of Yates Plant Units 1-5 to closed-cycle cooling, January and 

February 2003. 
20 

2002 TDD, p. 4-6: Based on the information provided to the Agency (including the late 

Palisades submission), the estimate of one-month could in some cases over- and others 

under-estimate the expected outage duration for a cooling system conversion. 

2002 TDD, p. 4-6, p. 4-7: The Agency also consulted a detailed historical proposal for a 

Roseton Generating Station cooling system conversion (Central Hudson Gas & Electric, 

1977). The report estimates a gross outage period of one-month for the final pipe connections 

for the recirculating system. The report estimates the net outage as 10 days for one of the two 

units and no downtime for the second. The reason given for the short estimates of downtime 

is the coincidence of the connection process with planned winter maintenance outages. 

Unlike the projection in the 1999 DEIS described above, this 1977 projection was 

accompanied by a relatively detailed description of the expected level of effort and 

engineering expectations for connecting the reciruclating system to existing equipment. 

2002 TDD, p. 4-9: “The Agency located a reference for a project where four condenser 

waterboxes and tube bundles were removed and replaced at a large nuclear plant (Arkansas 

Nuclear One). The full project lasted approximately 2 days. The facility, based on 

experience, had estimated the full condenser replacement to occur over the course of 8 days. 

Even though the scope of condenser replacements differ from potential cooling system 

conversions, the regulatory options considered for flow reduction commensurate with wet 

cooling anticipate that a subset of conversions would precipitate condenser tube 

replacements. As such, the condenser replacement schedule is important to the consideration 

of select cooling system conversions.” 

2002 TDD, p. 2-19: “The Agency estimates for the flow-reduction regulatory options 

considered that the typical process of adjoining the recirculating system to the existing 

condenser unit and the refurbishment of the existing condenser (when necessary) would last 

approximately two months. Because the Agency analyzed flexible compliance dates 

(extended over a five-year compliance period), the Agency estimated that plants under the 

flow reduction regulatory options could plan the cooling system conversion to coincide with 

periodic scheduled outages, as was the case for the example cases. For the case of nuclear 

units, these outages can coincide with periodic inspections (ISIs) and refueling. For the case 

of fossil-fuel and combined-cycle units, the conversion can be planned to coincide with 

periodic maintenance. Even though ISIs for nuclear units last typically 2 to 4 months, which 

would extend equal to or beyond the time required to connect the converted system, the 

Agency estimates for all model plants one month of interrupted service due to the cooling 

system conversion.” 

EPA modifies its treatment of construction downtime for nuclear plants in the 2011 TDD, stating 

that:47 “In the Phase II NODA, EPA assumed net construction downtimes of 4 weeks for non--

nuclear plants and 7 months for nuclear plants. . . Thus, the net value includes a deduction of the 

estimated maintenance downtime period (4 weeks for non-nuclear facilities) from the total 

estimated downtime.” EPA notes in the Phase II NODA (p. 13525) that “Just prior to proposal, 

EPA received additional technical information on the amount of operational downtime needed 

 47 March 2011 TDD, p. 8-26. 
21 

during cooling system conversions from once through to closed-cycle, recirculating with cooling 

towers at nuclear power plants (see DCN 4–2529).” 

The reasoning behind these revised EPA construction downtime estimates is provided in the 

2003 Phase II NODA:48

Net Installation Downtime and Other Site-Specific Factors for Recirculating Cooling Towers 

To support the proposed Phase II rule, EPA assumed that each projected cooling system 

conversion would require a net downtime of four weeks. 

This estimate was based on information that had been previously available to EPA on the 

downtime needed for fossil fuel and nuclear power plants. Just prior to proposal, EPA 

received additional technical information on the amount of operational downtime needed 

during cooling system conversions from once through to closed-cycle, recirculating with 

cooling towers at nuclear power plants (see DCN 4–2529). For the new analyses, EPA is 

incorporating the new information which suggests that cooling system conversions at nuclear 

power plants may take seven months. To the extent that conversions at nuclear power plants 

take less time to complete, costs for this factor would be lower. 

For non-nuclear power plants, EPA’s cost estimates at proposal assumed four weeks 

downtime for the retrofit of wet cooling towers at existing power plants. The Agency 

requests comment on whether more or less downtime may be required at some plants due to 

site specific factors and, if so, whether EPA should use a different estimate of downtime in 

analyzing the costs of this regulatory option. 

Nothing new is introduced into the record by EPA between the 2002 TDD and the 2011 TDD 

that would support extending the construction downtime estimate for nuclear plants from 2 

months to 7 months. Comments by the Atomic Energy Commission in the case of Palisades 

Nuclear and Consolidated Edison in the case of Indian Point Nuclear make clear there are no 

special safety considerations at nuclear plants for cooling tower retrofits. Therefore there is no 

basis for EPA to arbitrarily add 5 additional months of outage time for a nuclear plant cooling 

tower retrofit. 

Available information on equipment retrofits at nuclear plants strongly support the position that 

2 months is a reasonable and conservative estimate of cooling tower construction downtime at a 

nuclear plant. EPA points-out in the 2002 TDD that four surface condensers at 846 MW 

Arkansas Nuclear One were upgraded during two days of downtime. The Arkansas One surface 

condenser upgrade duration provides insight into just how quickly a large piece of equipment at 

a nuclear power plant can be modified/upgraded. 

 

The four steam generators at Diablo Canyon Units 1 and 2, 1,150 MW each, were replaced in 

2008-2009 with a total outage times of 58 days of 69 days, respectively.49 The work was done 

 48 Phase II NODA, Federal Register /Vol. 68, No. 53 /Wednesday, March 19, 2003 / Proposed Rules FR 13525. 

49 Areva, Project profile – Diablo Canyon Steam Generator Replacement Project, November 18, 2010. See: 

http://www.areva-np.com/scripts/us/publigen/content/templates/show.asp?P=1359&L=US. 
22 

concurrently with a planned refueling outage.50 This project required cutting an opening in the 

nuclear reactor containment dome. Since the containment building and original installation of the 

steam generators was not intended to provide easy replacement, a completely customized system 

and innovative assembly process were needed to remove them. 

The average duration of a steam generator replacement outage at a nuclear plant is 75 days.51 A 

typical refueling outage lasts approximately 40 days.52 All of the steam generator replacement 

work takes place within the area of a nuclear plant where safety and security issues are 

paramount. The steps involved in a steam generator replacement include:53

Step 1 All nuclear fuel is removed from the reactor and placed in a building designed for safe 

 storage. 

Step 2 A temporary 28-foot by 28-foot opening is created (in the reactor dome) to allow removal 

 of the original steam generators and installation of the new components. 

Step 3 The original steam generators are disconnected from their piping and supports. 

Step 4 A special crane lifts the original steam generators and places them on a rail system 

 running through the opening, sliding them outside the dome where they are lowered to a 

 heavy haul-vehicle and transported to a storage area. 

Step 5 The new steam generators are lifted and placed inside the dome, reversing the process 

 described in Step 4. 

Step 6 The new generators are connected to their piping and supports, the crane system 

 removed, the opening resealed, and equipment located where the opening was created 

 reinstalled. 

Step 7 Extensive inspections and testing are done to ensure the new components and reactor 

 coolant system are working correctly. 

Step 8 Personnel start up the unit and conduct functional testing. Then power production 

 resumes. 

It is not credible that the outage time for a highly invasive nuclear reactor steam generator 

replacement that occurs inside the nuclear containment dome averages 2 to 2-and-a-half months, 

and yet the hook-up of circulating water piping to an existing nuclear reactor surface condenser, 

an action the NRC predecessor agency stated would create no nuclear safety concerns, would 

require a 7-month outage. 

EPA’s defense of the 7-month outage for nuclear plants in the 2011 TDD is no more than an 

unsupported opinion that presumes that the need for a 7-month outage is a given. EPA states:54 

 50 Power Engineering, Project-of-the-year award winners, January 2009. See: 

http://pepei.pennnet.com/articles/print_toc.cfm?Section=ARTCL&p=6

51 Power Engineering, How Low Can They Go?, August 2008, Vol. 112, Issue 8, p. 44. See: 

http://www.pennenergy.com/index/power/display/337581/articles/power-engineering/volume-112/issue8/features/how-low-can-they-go.html. 52 Ibid. 

53 Southern California Edison fact sheet, Ensuring San Onofre Plant Benefits Continue Through Its Current License, 

December 2010. 

54 March 2011 TDD, p. 8-26. 
23 

Riverkeeper (DCN 6-5049A, Comment ID 316bEFR.332.001) argued that the 7-month 

period for nuclear plants was too long and that the extended duration for the Palisades plant 

included additional activities not associated with the cooling tower retrofit. EPA responded 

to Riverkeeper’s comments by suggesting that the 7-month period might be on the low side 

because it is based on historical refueling duration of 2 to 3 months, which has recently 

dropped to 30 to 40 days. These offsetting arguments support a decision to retain the 7-month 

net downtime for nuclear power plants. 

A two-month outage duration estimate for the hook-up of circulating cooling water piping to an 

existing surface condenser at a nuclear plant is conservative. EPA should assume no more than a 

two-month outage duration for a cooling tower hook-up on a nuclear reactor. 

IV. The total national pre-tax compliance costs of Option 2 and Option 3 are 

 approximately double a more realistic estimate 

EPA estimates that total annualized national pre-tax compliance costs for power plants under 

Option 2 and Option 3 would be $4,933 million and $5,079 million.55 The Option 2 and Option 3 

estimates are high by 60 to 70 percent. More realistic annualized national compliance pre-tax 

compliance costs are $3,029 million and $3,104 million, respectively, as shown in Table 8. 

Powers Engineering calculated the pre-tax compliance costs of Option 2 and Option 3 based on: 

1) EPA’s retrofit cost estimate for an wet inline redwood cooling tower adjusted to 2009, 2) the 

cooling tower capital cost assuming SPX wet tower or ClearSkyTM plume-abated tower 

technology in a back-to-back configuration, and 3) cooling tower energy penalty estimates from 

the 2002 TDD. No cost was attributed to outage time for a cooling tower hook-up at either a 

steam boiler plant or a nuclear plant. The Powers Engineering Option 3 pre-tax compliance costs 

for: 1) initial permit application, 2) O&M, 3) monitoring, recordkeeping, and reporting (MRR), 

and 4) permit renewal are the same as those in the EPA estimate. 

To determine a revised Option 3 capital cost using the alternative Powers Engineering cooling 

tower capital costs presented in this comment letter, the alternative unit composite cooling tower 

cost of $222/gpm is divided by the unit capital cost of $293/gpm adopted by the EPA in the 

March 2011 TDD and then multiplied by the annualized Option 3 nationwide capital cost 

estimate of $2.788 billion per year. This results in an alternative Option 3 annualized capital cost 

of: ($222/gpm ÷ $293/gpm) × $2.788 billion/yr) = $2.112 billion per year. 

The Powers Engineering Option 2 pre-tax compliance costs are the Powers Engineering Option 3 

pre-tax compliance costs pro-rated for the difference in cost between the EPA Option 2 and 

Option 3 categories. The capital cost in EPA Option 2 is 98 percent of the capital cost in EPA 

Option 3. This 98 percent factor is applied to the Powers Engineering Option 3 capital cost to 

calculate the Powers Engineering Option 2 capital cost. The EPA Option 2 pre-tax compliance 

costs are left unchanged for: 1) initial permit application, 2) O&M, 3) monitoring, 

recordkeeping, and reporting (MRR), and 4) permit renewal. The energy penalty cost in EPA 

Option 2 is 95 percent of the energy penalty cost in EPA Option 3. This 95 percent factor is 

 55 2011 EBA, Table 3-7, p. 3-23 and p. 3-24, 
24 

applied to the Powers Engineering Option 3 energy penalty cost to calculate the Powers 

Engineering Option 2 energy penalty cost. 

Table 8. Comparison of Annualized Pre-Tax Compliance Costs for Options 2 and 3 

($2009, millions) 

Scenario Capital 

Cost ($) 

Outage Initial 

Permit 

O&M MRR Energy 

penalty 

Permit 

renewal 

Total 

Option 2 

EPA 

2,737 280 1 316 7 1,590 1 4,933 

Option 2 

Powers 

2,070 0.0 1 316 7 634 1 3,029 

Option 3 

EPA 

2,788 296 1 319 4 1,670 1 5,079 

Option 3 

Powers 

2,112 0.0 1 319 4 667 1 3,104 

The calculations supporting the Powers Engineering annualized cost estimates for capital cost 

and energy penalty are provided in Attachment E. Both EPA and Powers Engineering use of 

design intake flow (DIF) for affected facilities to calculate the capital cost of cooling tower 

retrofits under Options 2 and 3. 

However, the calculation of Option 2 and Option 3 compliance costs using the current total U.S. 

DIF is a very conservative assumption (i.e., actual costs are likely to be lower) given the ongoing 

coal plant retirement trends unrelated to projected 316(b) compliance costs. That is because, 

given the trend, the actual number of existing plants needing to be retrofit will likely be smaller. 

V. Reasonableness of EPA’s position on air pollution issues, including increased 

emissions due to energy penalty or retrofit downtime as well as particulate 

emissions from cooling towers 

EPA does not consider the full implementation of most recent air emission requirements in 

opining on the air quality impact of cooling tower retrofits.56 Instead, the agency uses air 

emissions data that is on average ten years old at a time when the more recent air emission 

requirements are rapidly driving down air emissions from existing coal plants.57 This is a major 

deficiency in the air quality impacts analysis. 

EPA clearly states how overstated its air emissions increase projections are in the 2011 TDD:58

“For example, the 2010 Air Transport Rule and other state and EPA actions would reduce 

remaining power plant SO2 emissions by 71 percent and NOx emissions by 52 percent. The 

 56 2011 TDD, p. 10-1: “Note that the current emissions rate calculations discussed below do not reflect full 

implementation of the most recent air rule requirements.” 57 2011 TDD, p. 10-2: “The data source for the Agency’s air emissions estimates of CO2, SO2, NOx, and Hg is the 

EPA-developed database titled E-GRID 2005. This database is a compendium of reported air emissions, plant 

characteristics, and industry profiles for the entire US electricity generation industry in the years 1996 through 

2005.” 

58 Ibid, p. 10-5 and 10-6. 
25 

mercury rule would require utilities to install controls to reduce mercury emissions by 29 

percent. Since the actual emissions data used in EPA’s analysis does not reflect full 

implementation of these air rules, and since in many cases technologies to reduce emissions have 

yet to be installed, both the baseline and any potential increase in emissions are overstated.” 

Given the large reductions in NOx, SO2, and mercury that will be achieved with implementation 

of the Cross-State Air Pollution Rule (finalized in July 2011) and the Hazardous Air Pollutants 

Rule (to be finalized in November 2011), it is not credible for EPA to then state: “Despite these 

conservative estimates, EPA concludes there is the potential for an increase in total emissions.” 

As discussed above in Section II, the retrofitting of cooling towers at a limited number of U.S. 

power plants will reduce output from these plants on the order of 1 to 2 percent. Even if all of 

this output is made up by coal plants, which it will not be as discussed below, the increased 

output is a small fraction of the percentage reduction of NOx, SO2, and mercury that will occur 

within this same universe of coal plants due to EPA requirements. Air emissions from U.S. coal 

plants will not increase as a result of cooling tower retrofits at coal and nuclear plants. Air 

emissions from U.S. coal plants may decrease slightly less dramatically as a result of the 

retrofits. 

Carbon dioxide (CO2) emissions are currently decreasing in the U.S. power sector, due in part to 

the shifting of electricity production from coal plants to natural gas-fired plants for economic 

reasons. The EPA reports a 6.1 percent reduction in CO2 emissions between 2008 and 2009.59 A 

primary reason for this reduction is fuel switching between coal and natural gas. Again, 

assuming EPA’s worst case air emission scenario where coal plants burn more coal to make up 

for output reductions caused by cooling tower retrofits, so long as fuel shifting from coal to 

natural gas continues to increase, CO2 emissions from U.S. electricity generation would decrease 

slightly less dramatically – not increase. 

The reality of the U.S. electricity market is that over 200,000 MW of new, cleaner, and more 

efficient natural gas fired capacity has entered the market over the last decade, and there is now 

more natural gas-fired capacity than coal capacity in the country. See Figures 3 and 4. The 

market trend is moving from coal firing to natural gas firing for economic reasons. One ancillary 

benefit of this move is the much lower air emissions from modern natural gas-fired capacity. 

 59 EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks; 1990 – 2009, April 15, 2011, p. ES-3. “In 2009, 

total U.S. greenhouse gas emissions were 6,633.2 Tg or million metric tons CO2 Eq. While total U.S. emissions have 

increased by 7.3 percent from 1990 to 2009, emissions decreased from 2008 to 2009 by 6.1 percent 

(427.9 Tg CO2 Eq.). This decrease was primarily due to (1) a decrease in economic output resulting in a decrease in 

energy consumption across all sectors; and (2) a decrease in the carbon intensity of fuels used to generate electricity 

due to fuel switching as the price of coal increased, and the price of natural gas decreased significantly.” 
26 

Figure 3. Net Change in U.S. Generating Capacity by Energy Source, 1990 to 200760

 60 Congressional Research Service, Displacing Coal with Generation from Existing Natural Gas-Fired Power 

Plants, January 2010, p. 3. 
27 

Figure 4. Percentage of Total U.S. Generating Capacity by Energy Source, 1989 - 200761

It is reasonable for EPA to assume that natural gas-fired resources would provide replacement 

power during peak demand hours, as the primary function of these plants is daytime loadfollowing and peaking power. Air emissions from modern natural gas-fired plants are 

substantially lower than those of coal-fired plants. By way of example, assume that gas-fired 

power substitutes for the output reduction at a 2,000 MW nuclear plant caused by a cooling 

tower retrofit. Output would be reduced about 1.5 percent on an annual average, or 30 MW. If 

this 30 MW is generated by a load following natural gas fired combined-cycle plant, the annual 

NOx and PM10 emissions from this output would be about 9 tons/year (0.05 tons/day) and 5 

tons/year (0.03 tons/day), respectively.62,63,64 

The air emissions effect of shifting electricity production from natural gas-fired OTC steam 

boilers to higher efficiency natural gas-fired combined cycle units is shown in Table 9.65 All air 

 61 Ibid, p. 4. 

62 CARB, Guidance for the Permitting of Electric Generation Technologies, Stationary Source Division, July 2002, 

p. 9 (NOx emission factor = 0.07 lb/M-hr combined-cycle plants) 63 San Diego County Air Pollution Control District (APCD), Otay Mesa Power Project (air-cooled), Authority To 

Construct 973881, 18 lb/hr particulate without duct firing (510 MW output), equals ~ 0.04 lb/MW-hr. 

64 San Onofre is located in San Diego County. The NOx and PM10 emissions offset thresholds defined by San Diego 

County APCD Rule 20.1 (“New Source Review General Provisions”) are 50 tons/year for NOx and 100 tpy for 

PM10. Diablo Canyon is located in San Luis Obispo County. The NOx and PM10 emissions offset thresholds 

defined by San Luis Obispo APCD Rule 204 (“Requirements”) are 25 tons/year for NOx and 25 tpy for PM10. 65 California State Water Resources Control Board (SWRCB), Water Quality Control Policy on the Use of Coastal 

and Estuarine Waters for Power Plant Cooling - Final Substitute Environmental Document, May 2010, Figure 18, 

p. 109. This report assumes a 5 percent annual average efficiency penalty for cooling tower conversions at the 

state’s two nuclear plants, based on the February 2008 TetraTech report on cooling tower conversions at the state’s 

OTC plants prepared for the SWRCB: http://www.opc.ca.gov/2009/05/california%e2%80%99s-coastal-powerplants-alternative-cooling-system-analysis/. This report assumes average annual turbine efficiency penalties at the 

two nuclear plants of 2.9 and 3.6 percent, nearly an order of magnitude higher than the average turbine efficiency 

penalty assumed by EPA for nuclear plants in the 2001 Phase I TDD and 2002 TDD of 0.40 percent. TetraTech 

includes the EPA Phase I TDD as a reference, but does not acknowledge or address the large difference between its 

assumed average nuclear turbine efficiency penalty and the value identified by the EPA. TetraTech does not include 

sufficient reference information to allow independent corroboration of its turbine efficiency penalty calculations. If 

the EPA’s average nuclear plant total energy penalty (turbine efficiency + fan power + pump power) of 1.5 percent 

is assumed, the PM10 increase shown in Table 7 would drop by more than half. 
28 

emissions decline, with the exception of particulate emissions from cooling tower drift. This air 

emissions reduction effect would be much more pronounced in the case of production shifting 

for coal-fired OTC units to combined cycle units. 

Table 9. Air Emissions Effect of Shifting Generation from Natural Gas-Fired OTC Boilers 

to Natural Gas-Fired Combined Cycle Units66

Most nuclear plants in the country have uprated their output capacity significantly in the last 10 

to 15 years. These nuclear uprates have added capacity equivalent to five new nuclear plants.67

Additional uprates are expected to add the equivalent of three-and-a-half more reactors over the 

next four years.68 These uprates mean that U.S. reactors, in most cases, will be producing 

significantly more power than the original design rating even after these units are converted to 

cooling towers.69 Collectively, as a result of the uprates, the nuclear fleet will produce more 

power compared to original capacity ratings even if all OTC nuclear units are retrofitted to 

cooling towers. 

The amount of electricity generated from coal declined 11.6 percent in the 2008-2009 timeframe, 

primarily due to fuel switching between coal and existing combined cycle plants for economic 

reasons.70 The coal to combined cycle fuel switching is expected to continue for at least the next 

decade based on current natural gas price forecasts. The air emissions decline associated with an 

11.6 percent reduction in electricity generation from coal is an order of magnitude greater than 

the potential air emissions associated with a total energy penalty of 1.24 percent for the subset of 

coal plants that undergo a cooling tower retrofit. 

Also, many parts of the country now have renewable portfolio standards and are actively adding 

solar and other forms of renewable energy capacity. Non-polluting forms of energy will also 

 66 Ibid, Table 25, p. 110. 

67 Los Angeles Times, U.S. is increasing nuclear power through uprating, April 17, 2011. “But uprates have played 

an important role, adding the equivalent output of nearly five average-sized reactors since 1996. Regulators say they 

expect to approve boosts totaling 3 1/2 more reactors over the next four years.” 68 Ibid. 

69 Los Angeles Times, Uprates at U.S. nuclear power reactors, April 20, 2011. Virtually all uprates are 1.4 percent 

or greater. The EPA retrofit cooling tower cost model estimates a total energy penalty of about 1.5 percent for a 

cooling tower with a 10 o

F approach temperature: turbine efficiency penalty, 0.40 percent; fan power energy penalty, 

0.56 percent; pump power energy penalty, 0.55 percent. Total energy penalty: 0.40 percent + 0.56 percent + 0.55 

percent = 1.51 percent. 

70 Energy Information Administration, Electric Power Annual 2009, April 2011, pp, 1-2. 
29 

partially or fully displace the reduced output from cooling tower retrofits. This is illustrated in 

Figure 3 (new generation additions), which shows that wind power additions were second to 

natural gas-fired additions in 2005, 2006, and 2007. 

EPA erroneously infers that fine particulate emissions (PM2.5) from cooling tower drift could 

create difficulty in obtaining necessary air permits in PM2.5 non-attainment areas.71 This 

inference is based in part on the overly conservative assumption that all particulate emitted by a 

cooling tower is PM10. PM10 emissions are a fraction of total particulate emissions from cooling 

towers, and the PM2.5 component is small subset of the PM10 fraction.72 

In some non-attainment jurisdictions, cooling towers are exempt from air permit 

requirements.73,74 In those areas where they may not be exempt and where: 1) a plant is located 

in a PM2.5 non-attainment area, 2) cooling tower PM2.5 emissions are subject to an air permit 

requirement, and 3) projected cooling tower PM2.5 emission levels may be deemed to trigger 

major PM2.5 source status, then the plant owner could be required to purchase or generate 

sufficient PM2.5 emission offsets to prevent a net increase in PM2.5 emissions. In such an event, 

the requirement to purchase or generate PM2.5 emission offsets could increase the cost of 

securing an air permit for the cooling tower. The implication by EPA that cooling towers would 

be banned in some jurisdictions because they would or could emit PM10 or PM2.5 above certain 

thresholds is wrong. 

VI. EPA’s determination that many existing plants lack space for cooling towers is 

incorrect due to the agency’s failure to consider back-to-back cooling towers 

EPA is considering a determination that any plant with more than 160 acres per 1,000 MW of 

generating capacity would be presumed to have enough space for cooling towers, but that plants 

below may lack sufficient space.75 However, this proposed rule-of-thumb is based on the use of 

 71 2011 TDD, p. 6-11: “For example, EPA’s analysis suggests that increased emissions of PM2.5 may result in 

difficulty in obtaining air permits in those localities designated as non-attainment areas. For PM10, see DCN 10-

6954, which states that emissions would be approximately 60 tons per year if all drift is PM10.” 72 J. Reisman, G. Frisbie, Calculating Realistic PM10 Emissions from Cooling Towers, Electric Utility 

Environmental Conference, January 2003, p. 4. “More than 85% of the mass of the particulate in the drift from most 

cooling towers will result in solid particles greater than PM10 once the water has evaporated.” This statement is 

made based on analysis of drift from an expamle cooling tower with 7,700 ppm total dissolved solids in the cooling 

tower circulating water and a drift eliminator efficiency of 0.0006%. This paper is often cited by new fossil plant 

applicants as the basis for air permit application cooling tower PM10 and PM2.5 emission estimates. 73 SCAQMD Rule 219, Equipment Not Requiring a Written Permit, (d)(3) – water cooling towers. See: 

http://www.aqmd.gov/rules/siprules/sr219.pdf. 74 San Diego APCD Rule 11, Exemptions from Rule 10 Permit Requirements, (6)(vii) – water cooling towers. See: 

http://www.sdapcd.org/rules/Reg2pdf/R11.pdf. 75 2011 TDD, p. 5-24: “While EPA believes that the vast majority of facilities have adequate available land for 

placement of cooling towers, some facilities may have legitimate feasibility constraints. Based on site visits, EPA 

has found several facilities have been able to engineer solutions when faced with limited available land. EPA 

attempted to determine a threshold of land (one option explored a threshold of approximately 160 acres per 

gigawatt) below which a facility could not feasibly install cooling towers. Based on such an approach, EPA 

projected an upper bound of 25 percent of facilities that may have insufficient space to retrofit to cooling towers. 

While EPA estimated that some facilities would not have enough space, EPA found some facilities with a small 

parcel of land were still able to install closed-cycle cooling by engineering creative solutions.” 
30 

land-intensive in-line cooling towers, not much more space efficient back-to-back cooling 

towers.76

Figure 5 shows a comparison of site requirements for two in-line towers compared to one backto-back tower that provides the same cooling capacity. The back-to-back cooling tower requires 

about 17 percent of the space needed for two in-line towers, assuming the spacing recommended 

for parallel banks of in-line towers. The recommended in-line tower spacing is for the distance 

between the towers to equal the length of the towers, as shown in Figure 5. 

Figure 5. Comparison of Siting Requirements – Back-to-Back Versus In-Line Cooling 

Towers77

EPA should not attempt to set any “acreage-to-MW” rule-of-thumb that would presumptively 

exempt large numbers of plants from installing retrofit cooling towers. EPA did not consider the 

one cooling tower technology specifically intended for constrained sites – back-to-back cooling 

towers – in its analysis of cooling tower space requirements. Back-to-back cooling towers 

require only 17 percent the space of the in-line cooling towers evaluated by the EPA in its 

consideration of a “limited space exemption” threshold of approximately 160 acres per 1,000 

MW. This threshold would drop to approximately 27 acres per 1,000 MW if the cooling tower 

configuration assumed is back-to-back.78 

Back-to-back cooling towers, both wet and plume-abated, are in commercial use in the U.S. 

Figure 6 provides examples of operational back-to-back cooling towers and a ClearSkyTM cell in 

operation in New Mexico. 

 76 Ibid, p. 8-23: “The EPRI worksheet contains numerous assumptions and default values that can be modified using 

site-specific data. Specific relevant assumptions and default values are listed below . . . Tower configuration was inline rather than back-to-back, meaning towers are oriented in single rows rather than rows of two towers side by 

side.” 

77 P. Lindahl, K. Mortensen – SPX Cooling Technologies, Plume Abatement – The Next Generation, Cooling 

Technology Institute (CTI) Journal, Volume 31, No. 2, 2010, Figure 20, p. 22. 

78 0.17 × 160 acres per 1,000 MW = 27 acres per 1,000 MW. 
31 

Figure 6. Examples of Operational U.S. Back-to-Back Cooling Towers and ClearSky Cell 

Plant Yates, Georgia Plant Branch, Georgia 

Bergen Generating Station, New Jersey ClearSky cell, New Mexico (far left) 

ClearSkyTM is the plume-abated cooling tower option preferred by major steam boiler plant 

operators that may need to carry-out cooling tower retrofits at facilities located in populated 

areas. An example is the analysis by URS for GenOn of the cooling tower retrofit options for the 

Ormond Beach Generating Station (OBGS) steam boiler plant in California. Regarding fresh 

water cooling tower (FWCT) and salt water cooling tower (SWCT) alternatives, GenOn states:79

 GenOn engaged URS to consider the physical feasibility of installing FWCTs or SWCTs. 

As a threshold matter, due to the visual impacts that would result from a cooling tower plume 

on the Point Mugu Naval Air Station and on visual resources, especially adjacent beach 

recreation areas, plume abatement would be required for any FWCT or SWCT installation at 

the OBGS under the provision of CEQA. Therefore, throughout the rest of this 

Implementation Plan, the descriptions and analysis of FWCTs and SWCTs assume that they 

incorporate plume abatement. 

There are two potential options for plume abatement technology: the conventional “Hybrid” 

type tower and the “Clear Sky” type cooling tower. Hybrid towers are significantly larger 

 79 GenOn West, L.P., Ormond Beach Generating Station Implementation Plan for the Statewide Water Quality 

Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling, April 1, 2011, pp. 19-21.
32 

and may be appropriate for FWCTs. In saltwater applications, however, Hybrid towers would 

require installation of costly titanium heating coils, which would require frequent, extensive 

maintenance. For these reasons, only the Clear Sky technology would be practical for a 

SWCT application, although it could also be used in FWCTs. It is important to note, 

however, that there has been no full-scale commercial application of a Clear Sky cooling 

tower to date. While there is a significant technological feasibility question regarding the 

full-scale commercial application of the Clear Sky product, for the purpose of assessing 

feasibility at the OBGS, this analysis assumed it would be available and effective 

commercially. 

URS determined that, based on site layout, the configuration of the existing units, and 

available space at the OBGS site, a Clear Sky plume-abated FWCT could theoretically be 

constructed at the site. . . . URS determined that, based on site layout, the configuration of the 

existing units, and available space at the OBGS site, a Clear Sky plume-abated SWCT could 

theoretically be physically constructed. 

 

Back-to-back cooling towers can be retrofitted onto existing sites with very limited space. One 

example is shown in Figure 7. A 12-cell ClearSkyTM plume-abated back-to-back cooling tower, 

designed for a 12 oF approach temperature and 20 oF range, would be placed in the employee 

parking area to provide closed-cycle cooling for 324 MW of base load capacity at this spaceconstrained urban plant. The space requirement for the 12-cell plume-abated back-to-back 

cooling tower is about three-quarters of an acre.80 

 80 In this example, if retention of a full complement of employee parking is necessary, the retrofit can include 

adding a multi-deck parking structure to regain the desired number of parking spaces. 
33 

Figure 7. Possible Location for Back-to-Back Cooling Tower in Employee Parking Area at 

Urban, Space-Constrained Steam Boiler Plant81

There are likely to be few power plants in the country with an acreage-to-capacity ratio, based on 

use of back-to-back cooling towers, of less than 27 acres per 1,000 MW. No limited acreage 

exemption should be put forward by the EPA. As the agency notes, “EPA found some facilities 

with a small parcel of land were still able to install closed-cycle cooling by engineering creative 

solutions.”82 Creative solutions, like back-to-back cooling towers in parking areas or placed 

where non-essential structures are currently located, generally address the concern that 

insufficient land is available to locate cooling towers at acreage-limited power plants. 

VII. Uncertainties regarding remaining useful plant life should not be used as an 

excuse to avoid cooling tower retrofits 

The EPA states that “Making major structural and operational changes (such as retrofitting to 

closed-cycle cooling) may not be an appropriate response for a facility or unit that will not be 

operating in the near future.”83 This is a reasonable statement to the extent that the plant owner 

has made a legally binding commitment to permanently retire the once-through cooled units 

within, for example, a 5-year period. If a plant operator cannot make a legally binding 

commitment to permanently retire the units within such a timeframe, then the units should get no 

special consideration from the EPA regarding remaining useful life. 

 

 81 Bill Powers, P.E., Declaration on Feasibility and Cost-Effectiveness of Cooling Tower Retrofit at GenOn 

Potomac River, LLC Potomac River Generating Station (May 2007 Draft NPDES Permit DC 0022004), February 

18, 2011. 

82 2011 TDD, p. 5-24. 

83 Ibid, p. 6-11. 
34 

 VIII. Permit application requirements and compliance timelines 

EPA should define the expected retrofit cooling tower cost and O&M values to be used in permit 

applications to minimize the tendency of each applicant to “reinvent the wheel” to the detriment 

of actually carrying-out a cooling tower conversion. These default values should reflect the 

agency’s extensive evaluation and verification of these costs and parameters. Recommended 

default values for permit applications are: 

Installed retrofit cost, wet tower (in-line or back-to-back), $/gpm: 182 – 223 

Installed retrofit cost, plume-abated tower (in-line or back-to-back), $/gpm: 316 – 411 

Average turbine efficiency penalty (fossil or nuclear), %: 0.30 – 0.40 

Average fan parasitic energy penalty (fossil or nuclear), %: 0.40 – 0.60 

Average pump parasitic energy penalty (fossil or nuclear), %: 0.40 – 0.60 

Total retrofit downtime, months: fossil – 1, nuclear – 2 

EPA employees or EPA contractors should be the sole arbiters of the technical adequacy of 

applications, not peer reviewers hired by the applicant. Peer reviewers hired by the applicant, 

regardless of whether the EPA has authority to opine on the adequacy of the proposed peer 

reviewer, will generally be advocates for the applicant’s position, whether or not that position is 

technically sound. 

As the EPA notes, most existing OTC plants previously subject to the Phase II rule have already 

prepared cooling tower conversion studies.84 For example, preliminary cooling tower retrofit 

evaluations have been conducted for all California OTC plants, and the document containing 

these preliminary retrofit evaluations is cited in the 2011 TDD.85 As a result, the start-to-finish 

application process for cooling tower conversions for these facilities should be no more than 24 

months. 

Cooling tower retrofit(s) should be completed no more than 36 months after approval of the 

application. A 36-month timeline is set in the compliance order for conversion of Dominion 

Energy’s Brayton Point Station to cooling towers.86 The one exception would be nuclear plants 

that may need up to 12 additional months to synchronize the cooling tower retrofit outage with 

the reactor refueling outage. This compliance schedule is based on the expectation that the 

outage necessary for typical cooling tower hook-ups at fossil plants would be no greater than the 

 84 Federal Register /Vol. 76, No. 76 /Wednesday, April 20, 2011 / Proposed Rules, p. 22254. 85 2011 TDD, p. 2-12. “In February 2008, California Ocean Protection Council completed a study entitled, 

California’s Coastal Power Plants: Alternative Cooling System Analysis, (DCN 10-6964) which evaluates the 

feasibility of retrofitting coastal facilities to closed-cycle cooling towers to mitigate impingement and entrainment 

impacts at these sites. EPA reviewed this study to identify site-specific considerations involved in cooling tower 

retrofits.” 

86 U.S. Environmental Protection Agency Region I - New England, Docket 08-007, In the matter of Dominion 

Energy Brayton Point, LLC, Brayton Point Power Station, Somerset, Massachusetts, NPDES Permit No. 

MA0003654Proceedings under Section 309(a)(3) of the Clean Water Act, as amended, Findings and Order for 

Compliance, pp. 5-6. “Within 29 months of obtaining all permits and approvals, commence tie-in of condenser units 

to cooling towers. . . Within 36 months of obtaining all permits and approvals, complete tie-in of all condensor units 

such that all permit limits are met.” 
35 

typical four-week annual maintenance outage, and the typical outage necessary for a cooling 

tower hook-up at nuclear plants would be no greater than the typical 40-day refueling outage. 

There is no technical need or justification for EPA’s proposed extended implementation schedule 

for cooling tower retrofits.87 The only time it might be critical to avoid having substantial 

numbers of fossil and nuclear plants offline is during the June – September peak demand period 

in any year. There should be no grid reliability issues associated with bringing plants offline 

during the October – May period, when far more electrical generation reserves are available than 

necessary to serve the demand. This is already industry scheduling practice for maintenance and 

refueling outages. 

EPA states in the 2011 TDD that “nuclear facilities were permitted a longer timeline to account 

for additional requirements due to NRC licensing and approvals,”88 but in the same document 

EPA notes the NRC has identified no safety issues related to cooling tower retrofits at nuclear 

plants.89 There is no technical or safety justification for a period of greater than three years 

between the time a fossil fuel plant is directed to carry-out a cooling tower retrofit and the time 

that cooling tower is operational. In the case of a nuclear plant, up to one additional year may be 

justifiable to synchronize the cooling tower outage with the reactor refueling outage. 

My resume is included as Attachment F. Please contact me at (619) 295-2072 or 

bpowers@powersengineering.com if you have any questions about the content of this comment 

letter. 

Regards, 

Bill Powers, P.E.

 87 2011 TDD, p. 7-5: Extended implementation: “EPA evaluated an extended compliance timeline for several 

options (especially those involving closed-cycle cooling) to mitigate concerns over grid reliability and add 

flexibility. For example, the Director could schedule facility compliance timelines to avoid multiple baseload 

facilities from being offline at the same time. In some cases, additional time to comply would allow opportunity for 

transmission system upgrades to further mitigate local reliability. Further, this would allow installation outages 

(downtime) to be coordinated with each specific facility's maintenance schedule. Under this option, most existing 

facilities would have no more than 10 years to complete the retrofit to closed-cycle cooling. The Director would 

determine when and if any such schedule for compliance is necessary, and if the facility is implementing closedcycle as soon as possible. This provision would give the Director the discretion to provide nuclear facilities with up 

to 15 years to complete the retrofit, because all nuclear facilities baseload generating units and the additional 

flexibility in timelines would further mitigate energy reliability, and because the retrofits at these types of facilities 

in particular involve additional complexities and safety issues. The 15 years for nuclear facilities also provides an 

opportunity to schedule the installation outage to coincide with safety inspections, uprates, and other outages due to 

major facility modifications.” 

88 Ibid, p. 7-6. 

89 Ibid, p.6-9. 
Nuclear Plant Retrofit Comparison for Powers Engineering 9-June-2009 

Case 1A Case 2A Case 1B Case 2B 

Water Salt Salt Fresh Fresh 

Type ClearSky BTB Wet BTB ClearSky BTB Wet BTB 

Cells 3x22=66 3x18=54 3x20=60 3x18=54 

Footprint 3@529x109 3@433x109 3@481x109 3@433x109 

Rough Budget $115.6 million $38.6 $109.1 $36.4 

Basis: 830,000 gpm at 108-88-76. Plume point is assumed at 50 DB/90% RH. 

Low clog film type fill is used for all of the selections, assuming any fresh water used 

would likely be reclaimed water of some sort. Low clog fill has been used successfully 

in various sea water applications. Intake screens would be required for the make-up sea 

water to limit shells, etc. Make-up for the ClearSky tower would be approximately 80-

85% of the wet tower make-up on an annual basis. Budget is tower only, not including 

basins. Infrastructure cost is estimated by some at 3 times the cost of the wet tower, 

including such things as site prep, basins, piping, electrical wiring and controls, etc. Subsurface foundations such as piling can add significantly, and may be necessary for a 

seacoast location. The estimates above are adjusted for premium hardware and 

California seismic requirements, which are a factor in the taller back-to-back (BTB) 

designs both for wet and ClearSky. These are approximate comparisons. Both the wet 

towers and ClearSky towers could likely be optimized more than what has been estimated 

here, and may have to be tailored to actual site space in any event. ClearSky has pump 

head like a wet tower, is piped like a wet tower, and has higher fan power than a wet 

tower to accommodate the increased air flow and pressure drop. 

Coil type wet dry towers would cost significantly more, with premium tube (titanium for 

sea water, and possibly for reclaimed water) and header materials. An appropriate 

plenum mixing design has yet to be developed, but would also require non-corrosive 

materials and high pressure drop on the air side. No coil type BTB wet dry towers are 

likely to be proposed. 

Attachment A

A-1
Bill Powers

From: PAUL.LINDAHL@ct.spx.com

Sent: Tuesday, June 09, 2009 9:27 AM

To: bpowers@powersengineering.com

Subject: Nuclear Comparison

Page 1 of 1

6/14/2009

Bill, 

A comparison of wet and ClearSky back to back towers for a reference duty is included in the attached summary. 

 

 

 

Paul Lindahl, LEED AP

Director, Market Development 

SPX Thermal Equipment & Services 

7401 W 129th St 

Overland Park, KS 66213 

TEL 913.664.7588 

MOB 913.522.4254 

paul.lindahl@spx.com 

www.spxcooling.com

www.balcke-duerr.com/

 

The information contained in this electronic mail transmission is intended by SPX Corporation for the use of the named individual or entity to which it is 

directed and may contain information that is confidential or privileged. If you have received this electronic mail transmission in error, please delete it from 

your system without copying or forwarding it, and notify the sender of the error by reply email so that the sender’s address records can be corrected. 

 

 

Attachment A

A-2
Attachment B 
ISSUE: 1

SECTION: Basics COOLING TOWER PERFORMANCE

Basic Theory and Practice

SUBJECT:

INTENT 

In the foreword of Cooling Tower Fundamentals (published by SPX Cooling 

Technologies, Inc.) the scope of cooling tower knowledge was recognized 

as being too broad to permit complete coverage in a single publication. As a 

consequence, treatment of the subject matter appearing in that book may have 

raised more questions than it gave answers. And, such was its intent—“to provide 

a level of basic knowledge which will facilitate dialogue, and understanding, 

between user and manufacturer.” In short, it was designed to permit questions to 

spring from a solid foundation—and to give the user a basis for proper evaluation 

of the answers received.

This is the first of a series of papers intended to expand upon the basic 

information already published. The plan for the series is to limit individual topics to 

as few aspects of cooling tower design, application, and operation as necessary 

to make for quick and informative reading. From time to time, however, subjects 

will arise whose scope precludes adequate coverage in a short paper, and whose 

thread of continuity would be lost in separate installments. Those subjects will 

be treated in “Technical Reports” of somewhat greater length, receiving the 

same distribution as will have been established by evidence of reader interest. In 

addition, existing publications whose content remains current and fundamentally 

sound will become part of the useful cooling tower library that recipients will 

compile.

Although this first paper touches briefly upon the theory of cooling tower 

performance, the basic content of future papers will be far more practical than 

theoretical. This is because the brands of SPX Cooling Technologies, in their 

course of existence, have designed and manufactured every type of tower 

currently utilized in the industry, which allows all information and comparisons 

given to come from experience. However, since the operating characteristics 

of any cooling tower are governed by the laws of physics, psychrometrics, and 

thermodynamics, such laws may be described occasionally for purposes of 

promoting complete understanding.

TOTAL HEAT EXCHANGE

An open circuit cooling tower, 

commonly just called a cooling tower, 

is a specialized heat exchanger in which 

two fluids (air and water) are brought into 

direct contact with each other to affect the 

transfer of heat. In the “spray-filled” tower 

shown in Figure 1, this is accomplished 

by spraying a flowing mass of water into 

a rain-like pattern, through which an 

upward moving mass flow of cool air is 

induced by the action of a fan.

Ignoring any negligible amount of 

sensible heat exchange that may occur 

through the walls (casing) of the tower, 

the heat gained by the air must equal 

the heat lost by the water. Within the air 

stream, the rate of heat gain is identified 

by the expression G (h2 – h1), where:

G = Mass flow of dry air 

through the tower—lb/min.

h1 = Enthalpy (total heat 

content) of entering air— 

Btu/Ib of dry air.

h2 = Enthalpy of leaving air—

Btu/Ib of dry air.

Within the water stream, the rate of 

heat loss would appear to be L (t1 – t2), 

where:

L = Mass flow of water 

entering the tower—lb/min.

t

1= Hot water temperature 

entering the tower—°F.

t

2 = Cold water temperature 

leaving the tower—°F.

This derives from the fact that a Btu 

(British thermal unit) is the amount of heat 

gain or loss necessary to change the 

temperature of 1 pound of water by 1° F.

However, because of the evaporation 

that takes place within the tower, the 

mass flow of water leaving the tower 

is less than that entering it, and a 

proper heat balance must account for 

this slight difference. Since the rate 

of evaporation must equal the rate of 

change in the humidity ratio (absolute 

humidity) of the air stream, the rate of 

➠

FIGURE 1
Sea Level

Barometric Pressure—14.696 lb/sq in

FIGURE 2
HEAT

LOAD = L x R

FIGURE 3

Heat Load Factor

Tower Size Factor

1

1

2

2

3

3 4

4

5

5

6

6

Constants:

Range

Approach

Wet-bulb

Constants:

Heat Load

Approach

Wet-Bulb

Decreasing gpm

60 80 100 120 140 160 180 200

Range Variance —%

Tower Size Factor

.6

.7

.8

.9

1.0

1.1

1.2

1.3

heat loss represented by this change 

in humidity ratio can be expressed as 

G (H2 - H1) (t2 - 32), where:

H1 = Humidity ratio of entering 

air—lb vapor/lb dry air.

H2 = Humidity ratio of leaving 

 air—lb vapor/lb dry air.

(t2 - 32) = An expression of water 

enthalpy at the cold water 

temperature—Btu/Ib. (The 

enthalpy of water is zero at 

32°F)

Including this loss of heat through 

evaporation, the total heat balance between 

air and water, expressed as a differential 

equation, is:

Gdh = Ldt + GdH (t2 - 32) (1)

The total derivation of equation (1) 

can be found in A Comprehensive 

Approach to the Analysis of Cooling 

Tower Performance by D.R. Baker and 

H.A. Shryock, printed in the August 1961 

issue of the Journal of Heat Transfer, 

and available from Marley Cooling 

FIGURE 4

Technologies.

HEAT LOAD, RANGE & GPM

The expression “Ldt” in equation (1) 

represents the heat load imposed on the 

tower by whatever process it is serving. 

However, because pounds of water per unit 

time are not easily measured, heat load is 

usually expressed as:

Heat Load =

gpm x R x 81

⁄3 = Btu/min. (2)

Where:

gpm = Water flow rate 

through process and over 

tower—gal/min.

R = “Range” = Difference 

between hot and cold

water temperatures—°F. 

(See Fig.3)

81

⁄3 = Pounds per gallon of water.

Note from formula (2) that heat load 

establishes only a required temperature 

differential in the process water, and is 

unconcerned with the actual hot and cold 

water temperatures themselves. Therefore, 

the mere indication of a heat load is 

meaningless to the Application Engineer 

attempting to properly size a cooling tower. 

More information of a specific nature is 

FIGURE 5

required.

Optimum operation of a process 

usually occurs within a relatively narrow 

band of flow rates and cold water 

temperatures, which establishes two of 

the parameters required to size a cooling 

tower—namely, gpm and cold water 

temperature. The heat load developed 

by the process establishes a third 

parameter—hot water temperature 

coming to the tower. For example, let’s 

assume that a process developing a heat 

load of 125,000 Btu/min performs best if 

supplied with 1,000 gpm of water at 85°F. 

With a slight transformation of formula (2), 

we can determine the water temperature 

elevation through the process as:

Therefore, the hot water temperature 

coming to the tower would be 85°F + 15°F 

= 100°F.

WET-BULB TEMPERATURE

Having determined that the cooling tower 

must be able to cool 1,000 gpm of water 

from 100°F to 85°F, what parameters of 

the entering air must be known? Equation 

(1) would identify enthalpy to be of prime 

concern, but air enthalpy is not something 

that is routinely measured and recorded 

at any geographic location. However, 

wet-bulb and dry-bulb temperatures are 

values easily measured, and a glance at 

Figure 2 (psychrometric chart) shows that 

lines of constant wet-bulb are parallel 

to lines of constant enthalpy, whereas 

lines of constant dry-bulb have no fixed 

relationship to enthalpy. Therefore, wetbulb temperature is the air parameter 

needed to properly size a cooling tower, 

and its relationship to other parameters is 

as shown in the Figure 3 diagram.

R = = 15°F 125,000

1,000 x 81

⁄3
EFFECTS OF VARIABLES 

Although several parameters are defined 

in Figure 3, each of which will affect the 

size of a tower, understanding their effect 

is simplified if one thinks only in terms 

of 1) heat load; 2) range; 3) approach; 

and 4) wet-bulb temperature. If three 

of these parameters are held constant, 

changing the fourth will affect the tower 

size as follows:

1) Tower size varies directly and linearly 

with heat load. See Figure 4. 

2) Tower size varies inversely with 

range. See Figure 5. Two primary 

factors account for this. First; 

increasing the range—Figure 

3—also increases the ITD (driving 

force) between the incoming hot 

water temperature and the entering 

wet-bulb temperature. Second, 

increasing the range (at a constant 

heat load) requires that the water 

flow rate be decreased—Formula 

(2)—which reduces the static 

pressure opposing the flow of air.

3) Tower size varies inversely with 

approach. A longer approach 

requires a smaller tower. See

Figure 6. Conversely, a smaller 

approach requires an increasingly 

larger tower and, at 5°F approach, 

the effect upon tower size begins 

to become asymptotic. For that 

reason, it is not customary in the 

cooling tower industry to guarantee 

any approach of less than 5°F.

4) Tower size varies inversely with wetbulb temperature. When heat load, 

range, and approach values are 

fixed, reducing the design wet-bulb 

temperature increases the size of 

the tower. See Figure 7. This is 

because most of the heat transfer 

in a cooling tower occurs by virtue 

of evaporation (which extracts 

approximately 1000 Btu’s for every 

pound of water evaporated), and 

air’s ability to absorb moisture 

reduces with temperature.

JUNE 1986

Constants:

Heat Load

Range

Wet-Bulb

Approach — F

Tower Size Factor

5 10

.05

1.0

1.5

2.0

2.5

15 20 25 30

FIGURE 6

Constants:

Heat Load

Range

Approach

55

0.5

1.0

1.5

2.0

60 65 70 75 80

Wet-Bulb (F) (Example)

Tower Size Factor

FIGURE 7

ENTHALPY EXCHANGE VISUALIZED

 To understand the exchange of 

total heat that takes place in a cooling 

tower, let’s assume a tower designed 

to cool 120 gpm (1000 lb/min) of water 

from 85°F to 70°F at a design wet-bulb 

temperature of 65°F and (for purposes 

of illustration only) a coincident dry-bulb 

temperature of 78°F. (These air conditions 

are defined as point 1 on Figure 2) Let’s 

also assume that air is caused to move 

through the tower at the rate of 1000 lb/

min (approximately 13,500 cfm). Since 

the mass flows of air and water are 

equal, one pound of air can be said to 

contact one pound of water and the 

psychrometric path of one such pound 

of air has been traced on Figure 2 as it 

moves through the tower. 

Air enters the tower at condition 1 

(65°F wet-bulb and 78°F dry-bulb) and 

begins to gain enthalpy (total heat) and 

moisture content in an effort to achieve 

equilibrium with the water. This pursuit 

of equilibrium (solid line) continues until 

the air exits the tower at condition 2. 

The dashed lines identify the following 

changes in the psychrometric properties 

of this pound of air due to its contact with 

the water:

– Total heat content (enthalpy) 

increased from 30.1 Btu to 45.1 

Btu. This enthalpy increase of 15 

Btu was gained from the water. 

Therefore, one pound of water 

was reduced in temperature by the 

required amount of 15°F (85-70). 

See page 1.

– The air’s moisture content increased 

from 72 grains to 163 grains (7000 

grains = 1 lb). These 91 grains of 

moisture (0.013 lbs. of water) were 

evaporated from the water at a 

latent heat of vaporization of about 

1000 Btu/Ib. This means that about 

13 of the 15 Btu’s removed from 

the water (about 86% of the total) 

occurred by virtue of evaporation. 

(The latent heat of vaporization of 

water varies with temperature, from 

about 1075 Btu/Ib at 32°F to 970 

Btu/Ib at 212°F. Actual values at 

specific temperatures are tabulated 

in various thermodynamics 

manuals.)

At a given rate of air moving through 

a cooling tower, the extent of heat 

transfer which can occur depends upon 

the amount of water surface exposed to 

that air. In the tower depicted in Figure 1, 

total exposure consists of the cumulative 

surface areas of a multitude of random 

sized droplets, the size of which depends 

largely upon the pressure at which the 

water is sprayed. Higher pressure will 

produce a finer spray—and greater 

total surface area exposure. However, 

droplets contact each other readily in 

the overlapping spray patterns and, of 

course, coalesce into larger droplets, 

which reduces the net surface area 

exposure. Consequently, predicting the 

thermal performance of a spray-filled 

tower is difficult at best, and is highly 

dependent upon good nozzle design as 

well as a constant water pressure.

Subsequent issues will deal with 

water distribution system arrangements 

used in other types of towers, along 

with the various types of “fills” utilized to 

increase water surface area exposure and 

enhance thermal performance.
Effect of Increasing Approach Temperature from 12 oF to 13.5 oF: 12% Reduction in Tower Size
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Cooling Tower Capital Cost and Energy Penalty Calculations

Cooling tower

type

Flowrate Cooling tower

retrofit capital cost

Intake/ discharge

piping

Inflation

multiplier,

(gpm)

cost

(1999 $)

piping

modifications ($)

1999 ‐ 2009

($) ($

wet inline,

Redwood,fresh water

417,000 53.55 1.955 1.37 76 

Cooling tower

type

Flowrate Capital cost New unit cost EPA retrofit

multiplier

(gpm) (2009 $) ($/gpm) ($) ($

standard wet,back‐to‐back,fresh water

830,000 145.6 175 1.2 175 

plume‐abated,

back‐to‐back,fresh water

830,000 218.3 263 1.2 262 

standard wet,back‐to‐back,salt water

830,000 154.4 186 1.2 185 

plume‐abated,back‐to‐back,salt water

830,000 231.4 279 1.2 278 

Table 1. SPX June 2009 cost estimate for wet and plume‐abated back‐to‐back towers, 12 oF approach, 20 oF rang

Retrofit capital cost includ

multiplier

Table 1. EPA cost estimate for wet inline tower, 10 oF approach, 20 oF range

2009 EPA retrofit cooling to

cost

source: 2002 TDD, p. 2‐32 to p. 2‐36 and p. 5‐30. EPA explains on p. 5‐30 "The data did, however, indicate a median approach 

(average 10.4 °F) and a median range of 20 °F (average 21.1 °F). This range value is consistent with the value assumed in other 

analyses and therefore a range of 20 °F will be used.SPX 2009 back‐to‐back cooling tower quote statement: Estimates are adjusted for premium hardware and California seismicrequirements.

Powers Engineering

Exhibit 

E
Cooling Tower Capital Cost and Energy Penalty Calculations

Cooling tower

type

Flowrate Capital cost ×

1.3

New unit cost, 8

oF approach

EPA retrofit

multiplier

(gpm) (2009 $) ($/gpm) ($) ($

standard wet,back‐to‐back,fresh water

830,000 189 228 1.2 227 

plume‐abated, 830,000 284 342 1.2 341 

standard wet,back‐to‐back,salt water

830,000 201 242 1.2 241 

plume‐abated,back‐to‐back,salt water

830,000 301 362 1.2 361 

Tower type Southeast capacity

multiplier

Southeast unit cost

($/gpm)

Rest‐of‐nation

capacity

multiplier

Rest‐of‐nation

unit cost ($/gpm)

standard wet,inline, fresh

water (EPA)plume‐abated,back‐to‐back,

fresh water

0.25 410 0.75 316

Tower type Plume‐abated

multiplier

Plume‐abated unit

cost ($/gpm)

Standard wet

inline tower

multiplier

Wet inline tower

unit cost

($/gpm)

Table 4. U.S. average retrofit cooling tower cost, assuming 25% of towers are plume‐abated, back‐to‐back

U.S. average retrofit cap

($/gpm)

182340

Note: There is a difference of ~5 percent in the capital cost of cooling towers of similar design in fresh water and salt water ap

10 oF design approach temperature is composite for all regions based on

2002 TDD Table AA‐1, pdf p. 216.

Table 2. SPX cost data modified for 8 oF approach in Southeast sites, 1.3x cooling tower size multiplier

Retrofit capital cost includ

multiplier

Table 3. U.S. average retrofit wet and plume‐abated back‐to‐back tower cost, assuming 25% of plant capacity in Sout

U.S. average retrofit cap

($/gpm)

Powers Engineering

Exhibit 

E
Cooling Tower Capital Cost and Energy Penalty Calculations

75% wet inline,25% plume‐abated back‐to‐back

0.25 340 0.75 182

Plant type

gal/day x 109 gpm x 106 gal/day x 109 gpm x 106

nuclear 70 49 53 36

fossil boiler 210 146 158 109

EPA, Economic and Benefits Analysis for Proposed 316(b) Existing Facilities Rule, March 2011, p. 3‐18. Cooling tower cost reco

on 30 years, 7 percent.

222

March 2011 Phase II TDD, p. 8.33: "EPA developed the existing facility retrofit costs using existing flow data and cost equationcooling flow in gpm as the basis. . . These cooling water requirements assume that the typical existing plant design includes a 

through cooling system with a condenser temperature rise (ΔT) of 15 oF, and that the closed‐cycle cooling system that replace

though system will be optimized using a ΔT of 20 oF." Powers Engineering comment ‐ The amount of heat absorbed by the cir

cooling water is a function of flowrate in gpm x the rise in circulating water temperature across the surface condenser in oF. T

reduction in circulating water flowrate in a retrofit closed‐cycle cooling system relative to the original OTC system is inversely

proportional to the increase in the rise in water temperature increase across the surface condenser ("range"). Therefore, the acirculating water flow reduction with a closed‐cycle cooling retrofit is: OTC flowrate x (15 oF/20 oF) = 0.75 x OTC flowrate.

Table 5. Capital cost of cooling tower retrofits at nuclear and fossil boiler OTC plants, all effected U.S. units retrofit by 

Total U.S. cooling tower ca

Total capital cost (billions):

OTC flowrate, 210 x 109 gal/day fossil Optimized cooling tower flowrate,

8.1

EIA, Annual Energy Outlook 2011, April 2011, p. 48. "The Electric Power Research Institute (EPRI) has estimated that 312 gigawcapacity currently in operation (252 gigawatts of fossil fuel capacity and 60 gigawatts of nuclear capacity) would be affected b

cycle cooling] rule." Fossil OTC demand: 252,000 MW x 35,000 gallons/MWh x 24 hour = ~210 billion gallons per day. Nuclear 

demand: 60,000 MW x 48,000 gallons/MWh x 24 hour = ~70 billion gallons per day.

($ x 109)

24.232.3

Powers Engineering

Exhibit 

E
Powers Engineering 1 of 17

BILL POWERS, P.E. 

PROFESSIONAL HISTORY

 Powers Engineering, San Diego, CA 1994- 

 ENSR Consulting and Engineering, Camarillo, CA 1989-93 

 Naval Energy and Environmental Support Activity, Port Hueneme, CA 1982-87 

 U.S. Environmental Protection Agency, Research Triangle Park, NC 1980-81 

EDUCATION

 Master of Public Health – Environmental Sciences, University of North Carolina 

 Bachelor of Science – Mechanical Engineering, Duke University 

PROFESSIONAL AFFILIATIONS

 Registered Professional Mechanical Engineer, California (Certificate M24518) 

 American Society of Mechanical Engineers 

 Air & Waste Management Association 

TECHNICAL SPECIALTIES

 Twenty-five years of experience in: 

 Power plant air emission control system and cooling system assessments 

 Combustion equipment permitting, testing and monitoring 

 Air pollution control equipment retrofit design/performance testing 

 Petroleum refinery air engineering and testing 

  Oil and gas emission inventory development 

  Latin America environmental project experience 

POWER PLANT AIR EMISSION CONTROL AND COOLING SYSTEM CONVERSION ASSESSMENTS

Utility Boilers – Correlation Between Opacity and PM10 Emissions at Coal-Fired Plant. Provided expert 

testimony on whether correlation existed between mass PM10 emissions and opacity during opacity excursions 

at large coal-fired boiler in Georgia. EPA and EPRI technical studies were reviewed to assess the correlation of 

opacity and mass emissions during opacity levels below and above 20 percent. A strong correlation between 

opacity and mass emissions was apparent at a sister plant at opacities less than 20 percent. The correlation 

suggests that the opacity monitor correlation underestimates mass emissions at opacities greater than 20 

percent, but may continue to exhibit a good correlation for the component of mass emissions in the PM10 size 

range.

Utility Boilers – Correlation Between Opacity and PM10 at Coal-Fired Plant and Solutions. Lead engineer 

on evaluation of historic record at Alabama coal-fired power plant to establish a correlation between sitespecific continuous opacity data and particulate source test data. Sufficient data was available to establish that a 

good correlation existed between the visible emissions limit and the permitted PM10 emissions limit. Solutions 

to opacity exceedances, including a replacement baghouse or a polishing baghouse downstream of the existing 

ESP, were evaluated and found to be cost-effective. 

Combined-Cycle Power Plant Startup and Shutdown Emissions. Lead engineer for analysis of air permit 

startup and shutdown emissions minimization for combined-cycle power plant proposed for the San Francisco 

Bay Area. Original equipment was specified for baseload operation prior to suspension of project in early 

2000s. Operational profile described in revised air permit was load following with potential for daily start/stop. 

Recommended that either fast start turbine technology be employed to minimize start/stop emissions or that 

Attachment F
Powers Engineering 2 of 17

“demonstrated in practice” operational and control software modifications be employed to minimize 

startup/shutdown emissions. 

Biomass Plant NOx and CO Air Emissions Control Evaluation. Lead engineer for evaluation of available 

NOx and CO controls for a 45 MW biomass plant in Texas where proponent had identified selective noncatalytic reduction (SNCR) and good combustion practices as BACT. Identified the use of tail-end SCR for 

NOx control at several operational U.S. biomass plants, and oxidation catalyst in use at two of these plants for 

CO and VOC control, as BACT for the proposed biomass plant. 

IGCC as BACT for Air Emissions from Proposed 960 MW Coal Plant. Presented testimony on IGCC as 

BACT for air emissions reduction from 960 MW coal plant. Applicant received air permit for a pulverized coal 

plant to be equipped with a baghouse, wet scrubber, and wet ESP for air emissions control. Use of IGCC 

technology at the emission rates permitted for two recently proposed U.S. IGCC projects, and demonstrated in 

practice at a Japanese IGCC plant firing Chinese bituminous coal, would substantially reduce potential 

emissions of NOx, SO2, and PM. The estimated control cost-effectiveness of substituting IGCC for pulverized 

coal technology in this case was approximately $3,000/ton. 

Analysis of Proposed Air Emission Limits for 600 MW Pulverized Coal Plant. Project engineer tasked with 

evaluating sufficiency of air emissions limits and control technologies for proposed 600 MW coal plant 

Arkansas. Determined that the applicant had: 1) not properly identified SO2, sulfuric acid mist, and PM BACT 

control levels for the plant, and 2) improperly utilized an incremental cost effectiveness analysis to justify air 

emission control levels that did not represent BACT. 

Eight Pulverized Coal Fired 900 MW Boilers – IGCC Alternative with Air Cooling. Provided testimony 

on integrated gasification combined cycle (IGCC) as a fully commercial coal-burning alternative to the 

pulverized coal (PC) technology proposed by TXU for eight 900 MW boilers in East Texas, and East Texas as 

an ideal location for CO2 sequestration due to presence of mature oilfield CO2 enhanced oil recovery 

opportunities and a deep saline aquifer underlying the entire region. Also presented testimony on the major 

increase in regional consumptive water use that would be caused by the evaporative cooling towers proposed 

for use in the PC plants, and that consumptive water use could be lowered by using IGCC with evaporative 

cooling towers or by using air-cooled condensers with PC or IGCC technology. TXU ultimately dropped plans 

to build the eight PC plants as a condition of a corporate buy-out. 

Utility Boilers – Conversion of Existing Once-Through Cooled Boilers to Wet Towers, Parallel Wet-Dry 

Cooling, or Dry Cooling. Provided expert testimony and preliminary design for the conversion of four natural 

gas and/or coal-fired utility boilers (Unit 4, 235 MW; Unit 3, 135 MW; Unit 2, 65 MW; and Unit 1,65 MW) 

from once-through river water cooling to wet cooling towers, parallel wet-dry cooling, and dry cooling. Major 

design constraints were available land for location of retrofit cooling systems and need to maintain maximum 

steam turbine backpressure at or below 5.5 inches mercury to match performance capabilities of existing 

equipment. Approach temperatures of 12 o

F and 13 oF were used for the wet towers. SPX Cooling 

Technologies F-488 plume-abated wet cells with six feet of packing were used to achieve approach 

temperatures of 12 o

F and 13 oF. Annual energy penalty of wet tower retrofit designs is approximately 1 

percent. Parallel wet-dry or dry cooling was determined to be technically feasible for Unit 3 based on 

straightforward access to the Unit 3 surface condenser and available land adjacent to the boiler.

Utility Boiler – Assessment of Air Cooling and Integrated Gasification/Combined Cycle for Proposed 500 

MW Coal-Fired Plant. Provided expert testimony on the performance of air-cooling and IGCC relative to the 

conventional closed-cycle wet cooled, supercritical pulverized coal boiler proposed by the applicant. Steam 

ProTM coal-fired power plant design software was used to model the proposed plant and evaluate the impacts on 

performance of air cooling and plume-abated wet cooling. Results indicated that a conservatively designed aircooled condenser could maintain rated power output at the design ambient temperature of 90 o

F. The IGCC 

comparative analysis indicated that unit reliability comparable to a conventional pulverized coal unit could be 

Attachment F
Powers Engineering 3 of 17

achieved by including a spare gasifier in the IGCC design, and that the slightly higher capital cost of IGCC was 

offset by greater thermal efficiency and reduced water demand and air emissions. 

 Utility Boiler – Assessment of Closed-Cycle Cooling Retrofit Cost for 1,200 MW Oil-Fired Plant. 

Prepared an assessment of the cost and feasibility of a closed-cycle wet tower retrofit for the 1,200 MW 

 Roseton Generating Station. Determined that the cost to retrofit the Roseton plant with plume-abated closed-

 cycle wet cooling was well established based on cooling tower retrofit studies performed by the original owner 

 (Central Hudson Gas & Electric Corp.) and subsequent regulatory agency critique of the cost estimate. 

 Also determined that elimination of redundant and/or excessive budgetary line items in owners cost estimate 

 brings the closed-cycle retrofit in line with expected costs for comparable new or retrofit plume-abated cooling 

 tower applications. 

Nuclear Power Plant – Assessment of Closed-Cycle Cooling Retrofit Cost for 2,000 MW Plant. Prepared 

an assessment of the cost and feasibility of a closed-cycle wet tower retrofit for the 2,000 MW Indian Point 

Generating Station. Determined that the most appropriate arrangement for the hilly site would be an inline 

plume-abated wet tower instead of the round tower configuration analyzed by the owner. Use of the inline 

configuration would allow placement of the towers at numerous sites on the property with little or need for 

blasting of bedrock, greatly reducing the cost of the retrofit. Also proposed an alternative circulating cooling 

water piping configuration to avoid the extensive downtime projected by the owner for modifications to the 

existing discharge channel. 

Kentucky Coal-Fired Power Plant – Pulverized Coal vs IGCC. Expert witness in Sierra Club lawsuit 

against Peabody Coal Company’s plan to construct a 1,500 MW pulverized-coal fired power plant in Kentucky. 

Presented case that Integrated Gasification Combined Cycle (IGCC) is a superior method for producing power 

from coal, from environmental and energy efficiency perspective, than the proposed pulverized-coal plant. 

Presented evidence that IGCC is technically feasible and cost competitive with pulverized coal. 

Power Plant Dry Cooling Symposium – Chair and Organizer. Chair and organizer of the first symposium 

held in the U.S. (May 2002) that focused exclusively on dry cooling technology for power plants. Sessions 

included basic principles of wet and dry cooling systems, performance capabilities of dry cooling systems, case 

studies of specific installations, and reasons why dry cooling is the predominant form of cooling specified in 

certain regions of North America (Massachusetts, Nevada, northern Mexico). All technical papers presented at 

the symposium are available at http://awmasandiego.org/SDC-2002/.

Utility Boiler  Best Available NOx Control System for 525 MW Coal-Fired Circulating Fluidized Bed 

Boiler Plant. Expert witness in dispute over whether 50 percent NOx control using selective non-catalytic 

reduction (SNCR) constituted BACT for a proposed 525 MW circulating fluidized bed (CFB) boiler plant. 

Presented testimony that SNCR was capable of continuous NOx reduction of greater than 70 percent on a CFB 

unit and that tail-end selective catalytic reduction (SCR) was technically feasible and could achieve greater than 

90 percent NOx reduction.

Utility Boilers  Retrofit of SCR and FGD to Existing Coal-Fired Units. 

Expert witness in successful effort to compel an existing coal-fired power plant located in Massachusetts to 

meet an accelerated NOx and SO2 emission control system retrofit schedule. Plant owner argued the installation 

of advanced NOx and SO2 control systems would generate > 1 ton/year of ancillary emissions, such as sulfuric 

acid mist, and that under Massachusetts Dept. of Environmental Protection regulation ancillary emissions > 1 

ton/year would require a BACT evaluation and a two-year extension to retrofit schedule. Successfully 

demonstrated that no ancillary emissions would be generated if the retrofit NOx and SO2 control systems were 

properly sized and optimized. Plant owner committed to accelerated compliance schedule in settlement 

agreement. 

Attachment F
Powers Engineering 4 of 17

COMBUSTION EQUIPMENT PERMITTING, TESTING AND MONITORING

EPRI Gas Turbine Power Plant Permitting Documents – Co-Author. 

Co-authored two Electric Power Research Institute (EPRI) gas turbine power plant siting documents. 

Responsibilities included chapter on state-of-the-art air emission control systems for simple-cycle and 

combined-cycle gas turbines, and authorship of sections on dry cooling and zero liquid discharge systems. 

Air Permits for 50 MW Peaker Gas Turbines – Six Sites Throughout California. 

Responsible for preparing all aspects of air permit applications for five 50 MW FT-8 simple-cycle turbine 

installations at sites around California in response to emergency request by California state government for 

additional peaking power. Units were designed to meet 2.0 ppm NOx using standard temperature 

SCR and innovative dilution air system to maintain exhaust gas temperature within acceptable SCR range. 

Oxidation catalyst is also used to maintain CO below 6.0 ppm. 

Kauai 27 MW Cogeneration Plant – Air Emission Control System Analysis. Project manager to evaluate 

technical feasibility of SCR for 27 MW naphtha-fired turbine with once-through heat recovery steam generator. 

Permit action was stalled due to questions of SCR feasibility. Extensive analysis of the performance of existing 

oil-fired turbines equipped with SCR, and bench-scale tests of SCR applied to naphtha-fired turbines, indicated 

that SCR would perform adequately. Urea was selected as the SCR reagent given the wide availability of urea 

on the island. Unit is first known application of urea-injected SCR on a naphtha-fired turbine. 

Microturbines  Ronald Reagan Library, Ventura County, California. 

Project manager and lead engineer or preparation of air permit applications for microturbines and standby 

boilers. The microturbines drive the heating and cooling system for the library. The microturbines are certified 

by the manufacturer to meet the 9 ppm NOx emission limit for this equipment. Low-NOx burners are BACT for 

the standby boilers. 

 

Hospital Cogeneration Microturbines – South Coast Air Quality Management District. 

Project manager and lead engineer for preparation of air permit application for three microturbines at hospital 

cogeneration plant installation. The draft Authority To Construct (ATC) for this project was obtained two 

weeks after submittal of the ATC application. 30-day public notification was required due to the proximity of 

the facility to nearby schools. The final ATC was issued two months after the application was submitted, 

including the 30-day public notification period. 

Gas Turbine Cogeneration – South Coast Air Quality Management District. Project manager and lead 

engineer for preparation of air permit application for two 5.5 MW gas turbines in cogeneration configuration 

for county government center. The turbines will be equipped with selective catalytic reduction (SCR) and 

oxidation catalyst to comply with SCAQMD BACT requirements. Aqueous urea will be used as the SCR 

reagent to avoid trigger hazardous material storage requirements. A separate permit will be obtained for the 

NOx and CO continuous emissions monitoring systems. The ATCs is pending. 

Industrial Boilers  NOx BACT Evaluation for San Diego County Boilers. 

Project manager and lead engineer for preparation of Best Available Control Technology (BACT) evaluation 

for three industrial boilers to be located in San Diego County. The BACT included the review of low NOx

burners, FGR, SCR, and low temperature oxidation (LTO). State-of-the-art ultra low NOx burners with a 9 

ppm emissions guarantee were selected as NOx BACT for these units. 

Peaker Gas Turbines – Evaluation of NOx Control Options for Installations in San Diego County. 

Lead engineer for evaluation of NOx control options available for 1970s vintage simple-cycle gas turbines 

proposed for peaker sites in San Diego County. Dry low-NOx (DLN) combustors, catalytic combustors, hightemperature SCR, and NOx absorption/conversion (SCONOx) were evaluated for each candidate turbine 

make/model. High-temperature SCR was selected as the NOx control option to meet a 5 ppm NOx emission 

requirement. 

Attachment F
Powers Engineering 5 of 17

Hospital Cogeneration Plant Gas Turbines – San Joaquin Valley Unified Air Pollution Control District. 

Project manager and lead engineer for preparation of air permit application and Best Available Control 

Technology (BACT) evaluation for hospital cogeneration plant installation. The BACT included the review of 

DLN combustors, catalytic combustors, high-temperature SCR and SCONOx. DLN combustion followed by 

high temperature SCR was selected as the NOx control system for this installation. The high temperature SCR 

is located upstream of the heat recovery steam generator (HRSG) to allow the diversion of exhaust gas around 

the HRSG without compromising the effectiveness of the NOx control system. 

1,000 MW Coastal Combined-Cycle Power Plant – Feasibility of Dry Cooling. 

Expert witness in on-going effort to require use of dry cooling on proposed 1,000 MW combined-cycle 

“repower” project at site of an existing 1,000 MW utility boiler plant. Project proponent argued that site was 

two small for properly sized air-cooled condenser (ACC) and that use of ACC would cause 12-month 

construction delay. Demonstrated that ACC could easily be located on the site by splitting total of up to 80 

cells between two available locations at the site. Also demonstrated that an ACC optimized for low height and 

low noise would minimize or eliminate proponent claims of negative visual and noise impacts.

Industrial Cogeneration Plant Gas Turbines  Upgrade of Turbine Power Output. 

Project manager and lead engineer for preparation of Best Available Control Technology (BACT) evaluation 

for proposed gas turbine upgrade. The BACT included the review of DLN combustors, catalytic combustors, 

high-, standard-, and low-temperature SCR, and SCONOx. Successfully negotiated air permit that allowed 

facility to initially install DLN combustors and operate under a NOx plantwide “cap.” Within two major 

turbine overhauls, or approximately eight years, the NOx emissions per turbine must be at or below the 

equivalent of 5 ppm. The 5 ppm NOx target will be achieved through technological in-combustor NOx control 

such as catalytic combustion, or SCR or SCR equivalent end-of-pipe NOx control technologies if catalytic 

combustion is not available. 

Gas Turbines  Modification of RATA Procedures for Time-Share CEM. 

Project manager and lead engineer for the development of alternate CO continuous emission monitor (CEM) 

Relative Accuracy Test Audit (RATA) procedures for time-share CEM system serving three 7.9 MW turbines 

located in San Diego. Close interaction with San Diego APCD and EPA Region 9 engineers was required to 

receive approval for the alternate CO RATA standard. The time-share CEM passed the subsequent annual 

RATA without problems as a result of changes to some of the CEM hardware and the more flexible CO RATA 

standard. 

Gas Turbines  Evaluation of NOx Control Technology Performance. Lead engineer for performance 

review of dry low-NOx combustors, catalytic combustors, high-, standard-, and low-temperature selective 

catalytic reduction (SCR), and NOx absorption/conversion (SCONOx). Major turbine manufacturers and major 

manufacturers of end-of-pipe NOx control systems for gas turbines were contacted to determine current cost 

and performance of NOx control systems. A comparison of 1993 to 1999 “$/kwh” and “$/ton” cost of these 

control systems was developed in the evaluation.

Gas Turbines  Evaluation of Proposed NOx Control System to Achieve 3 ppm Limit. 

Lead engineer for evaluation for proposed combined cycle gas turbine NOx and CO control systems. Project 

was in litigation over contract terms, and there was concern that the GE Frame 7FA turbine could not meet the 

3 ppm NOx permit limit using a conventional combustor with water injection followed by SCR. Operations 

personnel at GE Frame 7FA installatins around the country were interviewed, along with principal SCR 

vendors, to corroborate that the installation could continuously meet the 3 ppm NOx limit. 

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Powers Engineering 6 of 17

Gas Turbines  Title V "Presumptively Approvable" Compliance Assurance Monitoring Protocol. 

Project manager and lead engineer for the development of a "presumptively approval" NOx parametric 

emissions monitoring system (PEMS) protocol for industrial gas turbines. "Presumptively approvable" means 

that any gas turbine operator selecting this monitoring protocol can presume it is acceptable to the U.S. EPA. 

Close interaction with the gas turbine manufacturer's design engineering staff and the U.S. EPA Emissions 

Measurement Branch (Research Triangle Park, NC) was required to determine modifications necessary to the 

current PEMS to upgrade it to "presumptively approvable" status. 

 

Environmental Due Diligence Review of Gas Turbine Sites  Mexico. Task leader to prepare regulatory 

compliance due diligence review of Mexican requirements for gas turbine power plants. Project involves 

eleven potential sites across Mexico, three of which are under construction. Scope involves identification of all 

environmental, energy sales, land use, and transportation corridor requirements for power projects in Mexico. 

Coordinator of Mexican environmental subcontractors gathering on-site information for each site, and 

translator of Spanish supporting documentation to English. 

Development of Air Emission Standards for Gas Turbines - Peru. Served as principal technical consultant 

to the Peruvian Ministry of Energy in Mines (MEM) for the development of air emission standards for Peruvian 

gas turbine power plants. All major gas turbine power plants in Peru are currently using water injection to 

increase turbine power output. Recommended that 42 ppm on natural gas and 65 ppm on diesel (corrected to 

15% O2) be established as the NOx limit for existing gas turbine power plants. These limits reflect NOx levels 

readily achievable using water injection at high load. Also recommended that new gas turbine sources be 

subject to a BACT review requirement. 

Gas Turbines  Title V Permit Templates. Lead engineer for the development of standardized permit 

templates for approximately 100 gas turbines operated by the oil and gas industry in the San Joaquin Valley. 

Emissions limits and monitoring requirements were defined for units ranging from GE Frame 7 to Solar Saturn 

turbines. Stand-alone templates were developed based on turbine size and NOx control equipment. NOx

utilized in the target turbine population ranged from water injection alone to water injection combined with 

SCR. 

Gas Turbines  Evaluation of NOx, SO2 and PM Emission Profiles. Performed a comparative evaluation of 

the NOx, SO2 and particulate (PM) emission profiles of principal utility-scale gas turbines for an independent 

power producer evaluating project opportunities in Latin America. All gas turbine models in the 40 MW to 240 

MW range manufactured by General Electric, Westinghouse, Siemens and ABB were included in the 

evaluation. 

Stationary Internal Combustion Engine (ICE) RACT/BARCT Evaluation. Lead engineer for evaluation of 

retrofit NOx control options available for the oil and gas production industry gas-fired ICE population in the 

San Joaquin Valley affected by proposed RACT and BARCT emission limits. Evaluation centered on leanburn compressor engines under 500 bhp, and rich-burn constant and cyclically loaded (rod pump) engines 

under 200 bhp. The results of the evaluation indicated that rich burn cyclically-loaded rod pump engines 

comprised 50 percent of the affected ICE population, though these ICEs accounted for only 5 percent of the 

uncontrolled gas-fired stationary ICE NOx emissions. Recommended retrofit NOx control strategies included: 

air/fuel ratio adjustment for rod pump ICEs, Non-selective catalytic reduction (NSCR) for rich-burn, constant 

load ICEs, and "low emission" combustion modifications for lean burn ICEs. 

Development of Air Emission Standards for Stationary ICEs - Peru. Served as principal technical 

consultant to the Peruvian Ministry of Energy in Mines (MEM) for the development of air emission standards 

for Peruvian stationary ICE power plants. Draft 1997 World Bank NOx and particulate emission limits for 

stationary ICE power plants served as the basis for proposed MEM emission limits. A detailed review of ICE 

emissions data provided in PAMAs submitted to the MEM was performed to determine the level of effort that 

Attachment F
Powers Engineering 7 of 17

would be required by Peruvian industry to meet the proposed NOx and particulate emission limits. The draft 

1997 WB emission limits were revised to reflect reasonably achievable NOx and particulate emission limits for 

ICEs currently in operation in Peru. 

Air Toxics Testing of Natural Gas-Fired ICEs. Project manager for test plan/test program to measure 

volatile and semi-volatile organic air toxics compounds from fourteen gas-fired ICEs used in a variety of oil 

and gas production applications. Test data was utilized by oil and gas production facility owners throughout 

California to develop accurate ICE air toxics emission inventories. 

AIR ENGINEERING/AIR TESTING PROJECT EXPERIENCE  GENERAL

Reverse Air Fabric Filter Retrofit Evaluation  Coal-Fired Boiler. Lead engineer for upgrade of reverse air 

fabric filters serving coal-fired industrial boilers. Fluorescent dye injected to pinpoint broken bags and damper 

leaks. Corrosion of pneumatic actuators serving reverse air valves and inadequate insulation identified as 

principal causes of degraded performance. 

Pulse-Jet Fabric Filter Performance Evaluation  Gold Mine. Lead engineer on upgrade of pulse-jet fabric 

filter and associated exhaust ventilation system serving an ore-crushing facility at a gold mine. Fluorescent dye 

used to identify bag collar leaks, and modifications were made to pulse air cycle time and duration. This 

marginal source was in compliance at 20 percent of emission limit following completion of repair work. 

Pulse-Jet Fabric Filter Retrofit - Gypsum Calciner. Lead engineer on upgrade of pulse-jet fabric filter 

controlling particulate emissions from a gypsum calciner. Recommendations included a modified bag clamping 

mechanism, modified hopper evacuation valve assembly, and changes to pulse air cycle time and pulse 

duration. 

Wet Scrubber Retrofit  Plating Shop. Project engineer on retrofit evaluation of plating shop packed-bed wet 

scrubbers failing to meet performance guarantees during acceptance trials, due to excessive mist carryover. 

Recommendations included relocation of the mist eliminator (ME), substitution of the original chevron blade 

ME with a mesh pad ME, and use of higher density packing material to improve exhaust gas distribution. Wet 

scrubbers passed acceptance trials following completion of recommended modifications. 

Electrostatic Precipitator (ESP) Retrofit Evaluation  MSW Boiler. Lead engineer for retrofit evaluation of 

single field ESP on a municipal solid waste (MSW) boiler. Recommendations included addition of automated 

power controller, inlet duct turning vanes, and improved collecting plate rapping system. 

ESP Electric Coil Rapper Vibration Analysis Testing - Coal-Fired Boiler. Lead engineer for evaluation of 

ESP rapper effectiveness test program on three field ESP equipped with "magnetically induced gravity return" 

(MIGR) rappers. Accelerometers were placed in a grid pattern on ESP collecting plates to determine maximum 

instantaneous plate acceleration at a variety of rapper power setpoints. Testing showed that the rappers met 

performance specification requirements. 

Aluminum Remelt Furnace Particulate Emissions Testing. Project manager and lead engineer for high 

temperature (1,600 o

F) particulate sampling of a natural gas-fired remelt furnace at a major aluminum rolling 

mill. Objectives of test program were to: 1) determine if condensable particulate was present in stack gases, and 

2) to validate the accuracy of the in-stack continuous opacity monitor (COM). Designed and constructed a 

customized high temperature (inconel) PM10/Mtd 17 sampling assembly for test program. An onsite natural 

gas-fired boiler was also tested to provide comparative data for the condensable particulate portion of the test 

program. Test results showed that no significant levels of condensable particulate in the remelt furnace exhaust 

gas, and indicated that the remelt furnace and boiler had similar particulate emission rates. Test results also 

showed that the COM was accurate. 

Aluminum Remelt Furnace CO and NOx Testing. Project manager and lead engineer for continuous weeklong testing of CO and NOx emissions from aluminum remelt furnace. Objective of test program was to 

characterize CO and NOx emissions from representative remelt furnace for use in the facility's criteria pollution 

Attachment F
Powers Engineering 8 of 17

emissions inventory. A TECO Model 48 CO analyzer and a TECO Model 10 NOx analyzer were utilized 

during the test program to provide +1 ppm measurement accuracy, and all test data was recorded by an 

automated data acquisition system. 

PETROLEUM REFINERY AIR ENGINEERING/TESTING EXPERIENCE

Big West Refinery Expansion EIS. Lead engineer on comparative cost analysis of proposed wet cooling 

 tower and fin-fan air cooler for process cooling water for the proposed clean fuels expansion project at the Big 

 West Refinery in Bakersfield, California. Selection of the fin-fin air-cooler would eliminate all consumptive 

 water use and wastewater disposal associated with the cooling tower. Air emissions of VOC and PM10 would 

 be reduced with the fin-fan air-cooler even though power demand of the air-cooler is incrementally higher than 

 that of the cooling tower. Fin-fan air-coolers with approach temperatures of 10 o

F and 20 oF were evaluated. 

 The annualized cost of the fin-fin air-cooler with a 20 o

F approach temperature is essentially the same as that 

 of the cooling tower when the cost of all ancillary cooling tower systems are considered. 

Criteria and Air Toxic Pollutant Emissions Inventory for Proposed Refinery Modifications. Project 

manager and technical lead for development of baseline and future refinery air emissions inventories for 

process modifications required to produce oxygenated gasoline and desulfurized diesel fuel at a California 

refinery. State of the art criteria and air toxic pollutant emissions inventories for refinery point, fugitive and 

mobile sources were developed. Point source emissions estimates were generated using onsite criteria pollutant 

test data, onsite air toxics test data, and the latest air toxics emission factors from the statewide refinery air 

toxics inventory database. The fugitive volatile organic compound (VOC) emissions inventories were 

developed using the refinery's most recent inspection and maintenance (I&M) monitoring program test data to 

develop site-specific component VOC emission rates. These VOC emission rates were combined with speciated 

air toxics test results for the principal refinery process streams to produce fugitive VOC air toxics emission 

rates. The environmental impact report (EIR) that utilized this emission inventory data was the first refinery 

"Clean Fuels" EIR approved in California. 

Development of Air Emission Standards for Petroleum Refinery Equipment - Peru. Served as principal 

technical consultant to the Peruvian Ministry of Energy in Mines (MEM) for the development of air emission 

standards for Peruvian petroleum refineries. The sources included in the scope of this project included: 1) SO2

and NOx refinery heaters and boilers, 2) desulfurization of crude oil, particulate and SO2 controls for fluid 

catalytic cracking units (FCCU), 3) VOC and CO emissions from flares, 4) vapor recovery systems for marine 

unloading, truck loading, and crude oil/refined products storage tanks, and 5) VOC emissions from process 

fugitive sources such as pressure relief valves, pumps, compressors and flanges. Proposed emission limits were 

developed for new and existing refineries based on a thorough evaluation of the available air emission control 

technologies for the affected refinery sources. Leading vendors of refinery control technology, such as John 

Zink and Exxon Research, provided estimates of retrofit costs for the largest Peruvian refinery, La Pampilla, 

located in Lima. Meetings were held in Lima with refinery operators and MEM staff to discuss the proposed 

emission limits and incorporate mutually agreed upon revisions to the proposed limits for existing Peruvian 

refineries. 

Air Toxic Pollutant Emissions Inventory for Existing Refinery. Project manager and technical lead for air 

toxic pollutant emissions inventory at major California refinery. Emission factors were developed for refinery 

heaters, boilers, flares, sulfur recovery units, coker deheading, IC engines, storage tanks, process fugitives, and 

catalyst regeneration units. Onsite source test results were utilized to characterize emissions from refinery 

combustion devices. Where representative source test results were not available, AP-42 VOC emission factors 

were combined with available VOC air toxics speciation profiles to estimate VOC air toxic emission rates. A 

risk assessment based on this emissions inventory indicated a relatively low health risk associated with refinery 

operations. Benzene, 1,3-butadiene and PAHs were the principal health risk related pollutants emitted. 

Air Toxics Testing of Refinery Combustion Sources. Project manager for comprehensive air toxics testing 

program at a major California refinery. Metals, Cr+6, PAHs, H2S and speciated VOC emissions were measured 

Attachment F
Powers Engineering 9 of 17

from refinery combustion sources. High temperature Cr+6 stack testing using the EPA Cr+6 test method was 

performed for the first time in California during this test program. Representatives from the California Air 

Resources Board source test team performed simultaneous testing using ARB Method 425 (Cr+6) to compare 

the results of EPA and ARB Cr+6 test methodologies. The ARB approved the test results generated using the 

high temperature EPA Cr+6 test method. 

Air Toxics Testing of Refinery Fugitive Sources. Project manager for test program to characterize air toxic 

fugitive VOC emissions from fifteen distinct process units at major California refinery. Gas, light liquid, and 

heavy liquid process streams were sampled. BTXE, 1,3-butadiene and propylene concentrations were 

quantified in gas samples, while BTXE, cresol and phenol concentrations were measured in liquid samples. 

Test results were combined with AP-42 fugitive VOC emission factors for valves, fittings, compressors, pumps 

and PRVs to calculate fugitive air toxics VOC emission rates.

OIL AND GAS PRODUCTION AIR ENGINEERING/TESTING EXPERIENCE

Air Toxics Testing of Oil and Gas Production Sources. Project manager and lead engineer for test plan/test 

program to determine VOC removal efficiency of packed tower scrubber controlling sulfur dioxide emissions 

from a crude oil-fired steam generator. Ratfisch 55 VOC analyzers were used to measure the packed tower 

scrubber VOC removal efficiency. Tedlar bag samples were collected simultaneously to correlate BTX removal 

efficiency to VOC removal efficiency. This test was one of hundreds of air toxics tests performed during this 

test program for oil and gas production facilities from 1990 to 1992. The majority of the volatile air toxics 

analyses were performed at in-house laboratory. Project staff developed thorough familiarity with the 

applications and limitations of GC/MS, GC/PID, GC/FID, GC/ECD and GC/FPD. Tedlar bags, canisters, 

sorbent tubes and impingers were used during sampling, along with isokinetic tests methods for multiple metals 

and PAHs.

Air Toxics Testing of Glycol Reboiler  Gas Processing Plant. Project manager for test program to 

determine emissions of BTXE from glycol reboiler vent at gas processing facility handling 12 MM/cfd of 

produced gas. Developed innovative test methods to accurately quantify BTXE emissions in reboiler vent gas. 

Air Toxics Emissions Inventory Plan. Lead engineer for the development of generic air toxics emission 

estimating techniques (EETs) for oil and gas production equipment. This project was performed for the 

Western States Petroleum Association in response to the requirements of the California Air Toxics "Hot Spots" 

Act. EETs were developed for all point and fugitive oil and gas production sources of air toxics, and the 

specific air toxics associated with each source were identified. A pooled source emission test methodology was 

also developed to moderate the cost of source testing required by the Act. 

Fugitive NMHC Emissions from TEOR Production Field. Project manager for the quantification of fugitive 

Nonmethane hydrocarbon (NMHC) emissions from a thermally enhanced oil recovery (TEOR) oil production 

field in Kern County, CA. This program included direct measurement of NMHC concentrations in storage tank 

vapor headspace and the modification of available NMHC emission factors for NMHC-emitting devices in 

TEOR produced gas service, such as wellheads, vapor trunklines, heat exchangers, and compressors. 

Modification of the existing NMHC emission factors was necessary due to the high concentration of CO2 and 

water vapor in TEOR produced gases. 

Fugitive Air Emissions Testing of Oil and Gas Production Fields. Project manager for test plan/test program 

to determine VOC and air toxics emissions from oil storage tanks, wastewater storage tanks and produced gas 

lines. Test results were utilized to develop comprehensive air toxics emissions inventories for oil and gas 

production companies participating in the test program. 

Oil and Gas Production Field  Air Emissions Inventory and Air Modeling. Project manager for oil and 

gas production field risk assessment. Project included review and revision of the existing air toxics emission 

inventory, air dispersion modeling, and calculation of the acute health risk, chronic non-carcinogenic risk and 

Attachment F
Powers Engineering 10 of 17

carcinogenic risk of facility operations. Results indicated that fugitive H2S emissions from facility operations 

posed a potential health risk at the facility fenceline. 

TITLE V PERMIT APPLICATION/MONITORING PLAN EXPERIENCE

Title V Permit Application  San Diego County Industrial Facility. Project engineer tasked with preparing 

streamlined Title V operating permit for U.S. Navy facilities in San Diego. Principal emission units included 

chrome plating, lead furnaces, IC engines, solvent usage, aerospace coating and marine coating operations. For 

each device category in use at the facility, federal MACT requirements were integrated with District 

requirements in user friendly tables that summarized permit conditions and compliance status. 

Title V Permit Application Device Templates - Oil and Gas Production Industry. Project manager and 

lead engineer to prepare Title V permit application “templates” for the Western States Petroleum Association 

(WSPA). The template approach was chosen by WSPA to minimize the administrative burden associated with 

listing permit conditions for a large number of similar devices located at the same oil and gas production 

facility. Templates are being developed for device types common to oil and gas production operations. Device 

types include: boilers, steam generators, process heaters, gas turbines, IC engines, fixed-roof storage tanks, 

fugitive components, flares, and cooling towers. These templates will serve as the core of Title V permit 

applications prepared for oil and gas production operations in California. 

Title V Permit Application - Aluminum Rolling Mill. Project manager and lead engineer for Title V permit 

application prepared for largest aluminum rolling mill in the western U.S. Responsible for the overall direction 

of the permit application project, development of a monitoring plan for significant emission units, and 

development of a hazardous air pollutant (HAP) emissions inventory. The project involved extensive onsite 

data gathering, frequent interaction with the plant's technical and operating staff, and coordination with legal 

counsel and subcontractors. The permit application was completed on time and in budget.

Title V Model Permit - Oil and Gas Production Industry. Project manager and lead engineer for the 

comparative analysis of regional and federal requirements affecting oil and gas production industry sources 

located in the San Joaquin Valley. Sources included gas turbines, IC engines, steam generators, storage tanks, 

and process fugitives. From this analysis, a model applicable requirements table was developed for a sample 

device type (storage tanks) that covered the entire population of storage tanks operated by the industry. The 

U.S. EPA has tentatively approved this model permit approach, and work is ongoing to develop comprehensive 

applicable requirements tables for each major category of sources operated by the oil and gas industry in the 

San Joaquin Valley. 

Title V Enhanced Monitoring Evaluation of Oil and Gas Production Sources. Lead engineer to identify 

differences in proposed EPA Title V enhanced monitoring protocols and the current monitoring requirements 

for oil and gas production sources in the San Joaquin Valley. The device types evaluated included: steam 

generators, stationary ICEs, gas turbines, fugitives, fixed roof storage tanks, and thermally enhanced oil 

recovery (TEOR) well vents. Principal areas of difference included: more stringent Title V O&M requirements 

for parameter monitors (such as temperature, fuel flow, and O2), and more extensive Title V recordkeeping 

requirements. 

RACT/BARCT/BACT EVALUATIONS

BACT Evaluation of Wool Fiberglass Insulation Production Line. Project manager and lead engineer for 

BACT evaluation of a wool fiberglass insulation production facility. The BACT evaluation was performed as a 

component of a PSD permit application. The BACT evaluation included a detailed analysis of the available 

control options for forming, curing and cooling sections of the production line. Binder formulations, wet 

electrostatic precipitators, wet scrubbers, and thermal oxidizers were evaluated as potential PM10 and VOC 

control options. Low NOx burner options and combustion control modifications were examined as potential 

NOx control techniques for the curing oven burners. Recommendations included use of a proprietary binder 

Attachment F
Powers Engineering 11 of 17

formulation to achieve PM10 and VOC BACT, and use of low-NOx burners in the curing ovens to achieve NOx

BACT. The PSD application is currently undergoing review by EPA Region 9. 

RACT/BARCT Reverse Jet Scrubber/Fiberbed Mist Eliminator Retrofit Evaluation. Project manager and 

lead engineer on project to address the inability of existing wet electrostatic precipitators (ESPs) and atomized 

mist scrubbers to adequately remove low concentration submicron particulate from high volume recovery boiler 

exhaust gas at the Alaska Pulp Corporation mill in Sitka, AK. The project involved thorough on-site 

inspections of existing control equipment, detailed review of maintenance and performance records, and a 

detailed evaluation of potential replacement technologies. These technologies included a wide variety of 

scrubbing technologies where manufacturers claimed high removal efficiencies on submicron particulate in 

high humidity exhaust gas. Packed tower scrubbers, venturi scrubbers, reverse jet scrubbers, fiberbed mist 

eliminators and wet ESPs were evaluated. Final recommendations included replacement of atomized mist 

scrubber with reverse jet scrubber and upgrading of the existing wet ESPs. The paper describing this project 

was published in the May 1992 TAPPI Journal. 

Aluminum Smelter RACT Evaluation - Prebake. Project manager and technical lead for CO and PM10

RACT evaluation for prebake facility. Retrofit control options for CO emissions from the anode bake furnace, 

potline dry scrubbers and the potroom roof vents were evaluated. PM10 emissions from the coke kiln, potline 

dry scrubbers, potroom roof vents, and miscellaneous potroom fugitive sources were addressed. Four CO 

control technologies were identified as technologically feasible for potline CO emissions: potline current 

efficiency improvement through the addition of underhung busswork and automated puncher/feeders, catalytic 

incineration, recuperative incineration and regenerative incineration. Current efficiency improvement was 

identified as probable CO RACT if onsite test program demonstrated the effectiveness of this approach. Five 

PM10 control technologies were identified as technologically feasible: increased potline hooding efficiency 

through redesign of shields, the addition of a dense-phase conveying system, increased potline air evacuation 

rate, wet scrubbing of roof vent emissions, and fabric filter control of roof vent emissions. The cost of these 

potential PM10 RACT controls exceeded regulatory guidelines for cost effectiveness, though testing of modified 

shield configurations and dense-phase conveying is being conducted under a separate regulatory compliance 

order. 

 RACT/BACT Testing/Evaluation of PM10 Mist Eliminators on Five-Stand Cold Mill. Project manager and 

lead engineer for fiberbed mist eliminator and mesh pad mist eliminator comparative pilot test program on 

mixed phase aerosol (PM10)/gaseous hydrocarbon emissions from aluminum high speed cold rolling mill. 

Utilized modified EPA Method 5 sampling train with portion of sample gas diverted (after particulate filter) to 

Ratfisch 55 VOC analyzer. This was done to permit simultaneous quantification of aerosol and gaseous 

hydrocarbon emissions in the exhaust gas. The mesh pad mist eliminator demonstrated good control of PM10

emissions, though test results indicated that the majority of captured PM10 evaporated in the mesh pad and was 

emitted as VOC. 

Aluminum Remelt Furnace/Rolling Mill RACT Evaluations. Lead engineer for comprehensive CO and 

PM10 RACT evaluation for the largest aluminum sheet and plate rolling mill in western U.S. Significant 

sources of CO emissions from the facility included the remelt furnaces and the coater line. The potential CO 

RACT options for the remelt furnaces included: enhanced maintenance practices, preheating combustion air, 

installation of fully automated combustion controls, and energy efficiency modifications. The coater line was 

equipped with an afterburner for VOC and CO destruction prior to the initiation of the RACT study. It was 

determined that the afterburner meets or exceeds RACT requirements for the coater line. Significant sources of 

PM10 emissions included the remelt furnaces and the 80-inch hot rolling mill. Chlorine fluxing in the melting 

and holding furnaces was identified as the principal source of PM10 emissions from the remelt furnaces. The 

facility is in the process of minimizing/eliminating fluxing in the melting furnaces, and exhaust gases generated 

in holding furnaces during fluxing will be ducted to a baghouse for PM10 control. These modifications are 

being performed under a separate compliance order, and were determined to exceed RACT requirements. A 

water-based emulsion coolant and inertial separators are currently in use on the 80-inch hot mill for PM10

Attachment F
Powers Engineering 12 of 17

control. Current practices were determined to meet/exceed PM10 RACT for the hot mill. Tray tower 

absorption/recovery systems were also evaluated to control PM10 emissions from the hot mill, though it was 

determined that the technical/cost feasibility of using this approach on an emulsion-based coolant had not yet 

been adequately demonstrated. 

BARCT Low NOx Burner Conversion – Industrial Boilers. Lead engineer for evaluation of low NOx burner 

options for natural gas-fired industrial boilers. Also evaluated methanol and propane as stand-by fuels to 

replace existing diesel stand-by fuel system. Evaluated replacement of steam boilers with gas turbine cogeneration system. 

BACT Packed Tower Scrubber/Mist Eliminator Performance Evaluations. Project manager and lead 

engineer for Navy-wide plating shop air pollution control technology evaluation and emissions testing program. 

Mist eliminators and packed tower scrubbers controlling metal plating processes, which included hard chrome, 

nickel, copper, cadmium and precious metals plating, were extensively tested at three Navy plating shops. 

Chemical cleaning and stripping tanks, including hydrochloric acid, sulfuric acid, chromic acid and caustic, 

were also tested. The final product of this program was a military design specification for plating and chemical 

cleaning shop air pollution control systems. The hydrochloric acid mist sampling procedure developed during 

this program received a protected patent. 

BACT Packed Tower Scrubber/UV Oxidation System Pilot Test Program. Technical advisor for pilot test 

program of packed tower scrubber/ultraviolet (UV) light VOC oxidation system controlling VOC emissions 

from microchip manufacturing facility in Los Angeles. The testing was sponsored in part by the SCAQMD's 

Innovative Technology Demonstration Program, to demonstrate this innovative control technology as BACT 

for microchip manufacturing operations. The target compounds were acetone, methylethylketone (MEK) and 

1,1,1-trichloroethane, and compound concentrations ranged from 10-100 ppmv. The single stage packed tower 

scrubber consistently achieved greater than 90% removal efficiency on the target compounds. The residence 

time required in the UV oxidation system for effective oxidation of the target compounds proved significantly 

longer than the residence time predicted by the manufacturer. 

 

 BACT Pilot Testing of Venturi Scrubber on Gas/Aerosol VOC Emission Source. Technical advisor for 

project to evaluate venturi scrubber as BACT for mixed phase aerosol/gaseous hydrocarbon emissions from 

deep fat fryer. Venturi scrubber demonstrated high removal efficiency on aerosol, low efficiency on VOC 

emissions. A number of VOC tests indicated negative removal efficiency. This anomaly was traced to a high 

hydrocarbon concentration in the scrubber water. The pilot unit had been shipped directly to the jobsite from 

another test location by the manufacturer without any cleaning or inspection of the pilot unit. 

 

Pulp Mill Recovery Boiler BACT Evaluation. Lead engineer for BACT analysis for control of SO2, NOx, 

CO, TNMHC, TRS and particulate emissions from the proposed addition of a new recovery furnace at a kraft 

pulp mill in Washington. A "top down" approach was used to evaluate potential control technologies for each 

of the pollutants considered in the evaluation. 

Air Pollution Control Equipment Design Specification Development. Lead engineer for the development of 

detailed Navy design specifications for wet scrubbers and mist eliminators. Design specifications were based on 

field performance evaluations conducted at the Long Beach Naval Shipyard, Norfolk Naval Shipyard, and 

Jacksonville Naval Air Station. This work was performed for the U.S. Navy to provide generic design 

specifications to assist naval facility engineering divisions with air pollution control equipment selection. 

 Also served as project engineer for the development of Navy design specifications for ESPs and fabric filters. 

CONTINUOUS EMISSION MONITOR (CEM) PROJECT EXPERIENCE

Process Heater CO and NOx CEM Relative Accuracy Testing. Project manager and lead engineer for 

process heater CO and NOx analyzer relative accuracy test program at petrochemical manufacturing facility. 

Objective of test program was to demonstrate that performance of onsite CO and NOx CEMs was in compliance 

with U.S. EPA "Boiler and Industrial Furnace" hazardous waste co-firing regulations. A TECO Model 48 CO 

Attachment F
Powers Engineering 13 of 17

analyzer and a TECO Model 10 NOx analyzer were utilized during the test program to provide +1 ppm 

measurement accuracy, and all test data was recorded by an automated data acquisition system. One of the two 

process heater CEM systems tested failed the initial test due to leaks in the gas conditioning system. 

Troubleshooting was performed using O2 analyzers, and the leaking component was identified and replaced. 

This CEM system met all CEM relative accuracy requirements during the subsequent retest. 

Performance Audit of NOx and SO2 CEMs at Coal-Fired Power Plant. Lead engineer on system audit and 

challenge gas performance audit of NOx and SO2 CEMs at a coal-fired power plant in southern Nevada. 

Dynamic and instrument calibration checks were performed on the CEMs. A detailed visual inspection of the 

CEM system, from the gas sampling probes at the stack to the CEM sample gas outlet tubing in the CEM 

trailer, was also conducted. The CEMs passed the dynamic and instrument calibration requirements specified 

in EPA's Performance Specification Test - 2 (NOx and SO2) alternative relative accuracy requirements. 

LATIN AMERICA ENVIRONMENTAL PROJECT EXPERIENCE

Preliminary Design of Ambient Air Quality Monitoring Network  Lima, Peru. Project leader for project 

to prepare specifications for a fourteen station ambient air quality monitoring network for the municipality of 

Lima, Peru. Network includes four complete gaseous pollutant, particulate, and meteorological parameter 

monitoring stations, as well as eight PM10 and TSP monitoring stations. 

Evaluation of Proposed Ambient Air Quality Network Modernization Project  Venezuela. Analyzed a 

plan to modernize and expand the ambient air monitoring network in Venezuela. Project was performed for the 

U.S. Trade and Development Agency. Direct interaction with policy makers at the Ministerio del Ambiente y 

de los Recursos Naturales Renovables (MARNR) in Caracas was a major component of this project. 

Evaluation of U.S.-Mexico Border Region Copper Smelter Compliance with Treaty Obligations 

Mexico. Project manager and lead engineer to evaluate compliance of U.S. and Mexican border region copper 

smelters with the SO2 monitoring, recordkeeping and reporting requirements in Annex IV [Copper Smelters] of 

the La Paz Environmental Treaty. Identified potential problems with current ambient and stack monitoring 

practices that could result in underestimating the impact of SO2 emissions from some of these copper smelters. 

Identified additional source types, including hazardous waste incinerators and power plants, that should be 

considered for inclusion in the La Paz Treaty process. 

Development of Air Emission Limits for ICE Cogeneration Plant - Panamá. Lead engineer assisting U.S. 

cogeneration plant developer to permit an ICE cogeneration plant at a hotel/casino complex in Panama. 

Recommended the use of modified draft World Bank NOx and PM limits for ICE power plants. The 

modification consisted of adding a thermal efficiency factor adjustment to the draft World Bank NOx and PM 

limits. These proposed ICE emission limits are currently being reviewed by Panamanian environmental 

authorities. 

Mercury Emissions Inventory for Stationary Sources in Northern Mexico. Project manager and lead 

engineer to estimate mercury emissions from stationary sources in Northern Mexico. Major potential sources 

of mercury emissions include solid- and liquid-fueled power plants, cement kilns co-firing hazardous waste, 

and non-ferrous metal smelters. Emission estimates were provided for approximately eighty of these sources 

located in Northern Mexico. Coordinated efforts of two Mexican subcontractors, located in Mexico City and 

Hermosillo, to obtain process throughput data for each source included in the inventory. 

Translation of U.S. EPA Scrap Tire Combustion Emissions Estimation Document  Mexico. Evaluated 

the Translated a U.S. EPA scrap tire combustion emissions estimation document from English to Spanish for 

use by Latin American environmental professionals. 

Environmental Audit of Aluminum Production Facilities  Venezuela. Evaluated the capabilities of 

existing air, wastewater and solid/hazardous waste control systems used by the aluminum industry in eastern 

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Powers Engineering 14 of 17

Venezuela. This industry will be privatized in the near future. Estimated the cost to bring these control 

systems into compliance with air, wastewater and solid/hazardous waste standards recently promulgated in 

Venezuela. Also served as technical translator for team of U.S. environmental engineers involved in the due 

diligence assessment. 

Assessment of Environmental Improvement Projects  Chile and Peru. Evaluated potential air, water, soil 

remediation and waste recycling projects in Lima, Peru and Santiago, Chile for feasibility study funding by the 

U.S. Trade and Development Agency. Project required onsite interaction with in-country decisionmakers (in 

Spanish). Projects recommended for feasibility study funding included: 1) an air quality technical support 

project for the Santiago, Chile region, and 2) soil remediation/metals recovery projects at two copper 

mine/smelter sites in Peru. 

Air Pollution Control Training Course  Mexico. Conducted two-day Spanish language air quality training 

course for environmental managers of assembly plants in Mexicali, Mexico. Spanish-language course manual 

prepared by Powers Engineering. Practical laboratory included training in use of combustion gas analyzer, 

flame ionization detector (FID), photoionization detector (PID), and occupational sampling. 

Stationary Source Emissions Inventory  Mexico. Developed a comprehensive air emissions inventory for 

stationary sources in Nogales, Sonora. This project requires frequent interaction with Mexican state and federal 

environmental authorities. The principal Powers Engineering subcontractor on this project is a Mexican firm 

located in Hermosillo, Sonora. 

VOC Measurement Program  Mexico. Performed a comprehensive volatile organic compound (VOC) 

measurements program at a health products fabrication plant in Mexicali, Mexico. An FID and PID were used 

to quantify VOCs from five processes at the facility. Occupational exposures were also measured. Worker 

exposure levels were above allowable levels at several points in the main assembly area. 

Renewable Energy Resource Assessment Proposal  Panama. Translated and managed winning bid to 

evaluate wind energy potential in Panama. Direct interaction with the director of development at the national 

utility monopoly (IRHE) was a key component of this project. 

Comprehensive Air Emissions Testing at Assembly Plant  Mexico. Project manager and field supervisor 

of emissions testing for particulates, NOx, SO2 and CO at turbocharger/air cooler assembly plant in Mexicali, 

Mexico. Source specific emission rates were developed for each point source at the facility during the test 

program. Translated test report into Spanish for review by the Mexican federal environmental agency 

(SEMARNAP). 

Air Pollution Control Equipment Retrofit Evaluation  Mexico. Project manager and lead engineer for 

comprehensive evaluation of air pollution control equipment and industrial ventilation systems in use at 

assembly plant consisting of four major facilities. Equipment evaluated included fabric filters controlling blast 

booth emissions, electrostatic precipitator controlling welding fumes, and industrial ventilation systems 

controlling welding fumes, chemical cleaning tank emissions, and hot combustion gas emissions. 

Recommendations included modifications to fabric filter cleaning cycle, preventative maintenance program for 

the electrostatic precipitator, and redesign of the industrial ventilation system exhaust hoods to improve capture 

efficiency. 

Comprehensive Air Emissions Testing at Assembly Plant  Mexico. Project manager and field supervisor 

of emissions testing for particulates, NOx, SO2 and CO at automotive components assembly plant in Acuña, 

Mexico. Source-specific emission rates were developed for each point source at the facility during the test 

program. Translated test report into Spanish. 

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Powers Engineering 15 of 17

Fluent in Spanish. Studied at the Universidad de Michoacán in Morelia, Mexico, 1993, and at the Colegio de 

España in Salamanca, Spain, 1987-88. Have lectured (in Spanish) on air monitoring and control equipment at 

the Instituto Tecnológico de Tijuana. Maintain contact with Comisión Federal de Electricidad engineers 

responsible for operation of wind and geothermal power plants in Mexico, and am comfortable operating in the 

Mexican business environment. 

EXPERT TESTIMONY

 On behalf of Attorney General of Iowa, In re Application of Interstate Power and Light Company for a 

Generating Facility Siting Certificate, Docket No. GCU-07-01, Iowa Utilities Board, November 9, 2007. 

Nature of testimony - IGCC with CO2 control as alternative to pulverized coal-fired boiler. 

 On behalf of individuals, the National Parks Conservation Association and Group Against Smog 

 and Pollution, In the Matter of Greene Energy Resource Recovery Project, Plan Approval PA-30- 

 00150A, Pennsylvania Department of Environmental Protection, June 2006. Nature of testimony – best 

 available NOx control for CFB boiler. 

 On behalf of the Consumer Advocate Division of the Public Service Commission of West Virginia, 

 Appalachian Power Company, Application for a Certificate of Public Convenience and Necessity 

 to construct a 600 MW Integrated Gasification Combined Cycle Generating Station in Mason 

 County, Public Service Commission of West Virginia, Case No. 06-0033-E-CN, November 19, 

 2007. Nature of testimony – challenges of converting IGCC designed without CO2 capture for later retrofit 

 to CO2 capture. 

 On behalf of Sierra Club, Sierra Club vs. Environment and Public Protection Cabinet and East 

 Kentucky Power Cooperative, Inc., File No. DAQ-27974-037, October 30, 2006. Nature of testimony – 

 best available NOx control for CFB boiler. 

 On behalf of Californians for Renewable Energy, In the Matter of Southern California Edison 

 Company (U 338-E) for Approval of Results of Summer 2007 Track of its New Generation 

 Request for Offers and for Cost Recovery, Application 06-11-007, Public Utilities Commission of 

 California, November 30, 2006. Nature of testimony – cost to ratepayers of peaking gas turbines. 

 On behalf of Utility Consumers’ Action Network (UCAN), In the Matter of the Application of San 

 Diego Gas & Electric Company (U 902-E) for a Certification of Public Convenience and Necessity 

 for the Sunrise Powerlink Transmission Project, Application 06-08-010, Public Utilities 

 Commission of California, May 2008. Nature of testimony – advantages of distributed generation 

 alternative to new transmission line. 

 On behalf of Environmental Health Coalition, In the Matter of: the Application for Certification for 

 the Chula Vista Energy Upgrade Project, Docket No. 07-AFC-4, California Energy Resources 

 Conservation and Development Commission, September 17, 2008. Nature of testimony – cost viability of 

 distributed photovoltaics alternative to peaking gas turbine. 

 On behalf of Sierra Club, Sierra Club v. Tennessee Valley Authority, Case No. CV-02-J-2279-NW (N.D. 

 Ala. 2008). Nature of testimony – opacity issues and particulate controls for existing coal-fired boiler. 

 In re the PSD Air Quality Permit Application of Hyperion Energy Center South Dakota Department of 

 Environment and Natural Resources, Board of Minerals and Environment, June 25, 2009. Nature of 

 testimony – air emissions from proposed petroleum refinery and best available control technology. 

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Powers Engineering 16 of 17

 On behalf of Sierra Club and the National Audubon Society, In The Matter Of Southwestern Electric 

 Power Company (SWEPCO) – Turk Power Plant, Docket No. 08-006-P, Arkansas Pollution Control and 

 Ecology Commission. March 6, 2009. Nature of testimony – best available SO2 and PM controls for 

 proposed coal-fired boiler. 

 On Behalf of Protestant Annie Mae Shelton, In the Matter of Applications of Aspen Power, 

 LLC for TCEQ Air Quality Permit No. 81706, Prevention of Significant Deterioration Air 

 Quality Permit PSD-TX-1089, and HAP 12, SOAH Docket No. 582-09-0636, TCEQ Docket No. 

 2008-1145-AIR, Before the Texas State Office of Administrative Hearings, March 3, 2009. 

 Nature of testimony – best available NOx, PM, and CO/VOC controls for biomass boiler. 

 On Behalf of Sierra Club and No Coal Coalition, in the Matter of Applications of White Stallion 

 Energy Center, LLC for State Air Quality Permit 86088; Prevention of Significant Deterioration 

 Air Quality Permit Psd-Tx-1160 and for Hazardous Air Pollutant Major Source [FCAA § 112 

 (G)] Permit Hap-28 and Plant-wide Applicability Limit Pal-48, Texas State Office of 

 Administrative Hearings, November 2, 2009. Nature of testimony – best available NOx, PM, SO2, and 

 CO/VOC controls for CFB boilers. 

 On behalf of Montana Environmental Information Center and Citizens for Clean Energy, In the Matter of: 

 Southern Montana Electric Generation & Transmission Cooperative – Highwood Generating Station Air 

 Quality Permit No. 3423-00, Montana Board of Environmental Review, Case No. BER 2007-07-AQ, 

 October 2, 2007. Nature of testimony – IGCC with CO2 control as alternative to coal-fired CFB boiler. 

 On behalf of NRDC, Natural Resources Defense Council, Inc., v. Chris Korleski, Erac No. 996266, Erac 

 No. 996267, State of Ohio Environmental Review Appeals Commission, May 11, 2010. Nature of 

 testimony – best available air emission control levels for proposed coal-to-liquids plant. 

 On Behalf of Save The Dunes Council, Inc., et al., In The Matter of Objection to the Issuance Of 

 Significant Source Modification Permit No. 089-25484-00453 to BP Products North America Inc. 

 Whiting Business Unit, Cause No. 08-A-J-4115. Nature of testimony – estimation of air emissions from 

 proposed petroleum refinery expansion. 

 On behalf of North Carolina Waste Awareness Reduction Network Inc., North Carolina Waste Awareness 

 Reduction Network Inc. v. N.C. Department of Environment and Natural Resources, Division of Air 

 Quality, 08-Ehr-0771, 0835 & 0836, 09-Ehr-3102, 3174 & 3176, North Carolina Office of Administrative 

 Hearings, March 1, 2010. Nature of testimony – best available SO2 and PM emission controls for proposed 

 pulverized coal-fired boiler. 

PUBLICATIONS

Bill Powers, “Federal Government Betting on Wrong Solar Horse,” Natural Gas & Electricity Journal, Vol. 27, 

Issue 5, December 2010, pp. 15-22. 

Bill Powers, “Today’s California Renewable Energy Strategy—Maximize Complexity and Expense,” Natural 

Gas & Electricity Journal, Vol. 27, Issue 2, September 2010, pp. 19-26. 

Bill Powers, “Environmental Problem Solving Itself Rapidly Through Lower Gas Costs,” Natural Gas & 

Electricity Journal, Vol. 26, Number 4, November 2009, pp. 9-14. 

Bill Powers, “PV Pulling Ahead, but Why Pay Transmission Costs?” Natural Gas & Electricity Journal, Vol. 

26, Number 3, October 2009, pp. 19-22. 

Bill Powers, “Unused Turbines, Ample Gas Supply, and PV to Solve RPS Issues,” Natural Gas & Electricity 

Journal, Vol. 26, Number 2, September 2009, pp. 1-7. 

Attachment F
Powers Engineering 17 of 17

Bill Powers, “CEC Cancels Gas-Fed Peaker, Suggesting Rooftop Photovoltaic Equally Cost-Effective,” Natural 

Gas & Electricity Journal, Vol. 26, Number 1, August 2009, pp. 8-13. 

Bill Powers, “San Diego Smart Energy 2020 – The 21st Century Alternative,” San Diego, October 2007. 

Bill Powers, “Energy, the Environment, and the California – Baja California Border Region,” Electricity 

Journal, Vol. 18, Issue 6, July 2005, pp. 77-84. 

W.E. Powers, "Peak and Annual Average Energy Efficiency Penalty of Optimized Air-Cooled Condenser on 

515 MW Fossil Fuel-Fired Utility Boiler," presented at California Energy Commission/Electric Power 

Research Institute Advanced Cooling Technologies Symposium, Sacramento, California, June 2005. 

W.E. Powers, R. Wydrum, P. Morris, "Design and Performance of Optimized Air-Cooled Condenser at 

Crockett Cogeneration Plant," presented at EPA Symposium on Technologies for Protecting Aquatic 

Organisms from Cooling Water Intake Structures, Washington, DC, May 2003. 

P. Pai, D. Niemi, W.E. Powers, “A North American Anthropogenic Inventory of Mercury Emissions,”

presented at Air & Waste Management Association Annual Conference in Salt Lake City, UT, June 2000. 

 

P.J. Blau and W.E. Powers, "Control of Hazardous Air Emissions from Secondary Aluminum Casting Furnace 

Operations Through a Combination of: Upstream Pollution Prevention Measures, Process Modifications and 

End-of-Pipe Controls," presented at 1997 AWMA/EPA Emerging Solutions to VOC & Air Toxics Control 

Conference, San Diego, CA, February 1997. 

W.E. Powers, et. al., "Hazardous Air Pollutant Emission Inventory for Stationary Sources in Nogales, Sonora, 

Mexico ," presented at 1995 AWMA/EPA Emissions Inventory Specialty Conference, RTP, NC, October 1995. 

W.E. Powers, "Develop of a Parametric Emissions Monitoring System to Predict NOx Emissions from 

Industrial Gas Turbines," presented at 1995 AWMA Golden West Chapter Air Pollution Control Specialty 

Conference, Ventura, California, March 1995. 

W. E. Powers, et. al., "Retrofit Control Options for Particulate Emissions from Magnesium Sulfite Recovery 

Boilers," presented at 1992 TAPPI Envr. Conference, April 1992. Published in TAPPI Journal, July 1992. 

S. S. Parmar, M. Short, W. E. Powers, "Determination of Total Gaseous Hydrocarbon Emissions from an 

Aluminum Rolling Mill Using Methods 25, 25A, and an Oxidation Technique," presented at U.S. EPA 

Measurement of Toxic and Related Air Pollutants Conference, May 1992. 

N. Meeks, W. E. Powers, "Air Toxics Emissions from Gas-Fired Internal Combustion Engines," presented at 

AIChE Summer Meeting, August 1990. 

W. E. Powers, "Air Pollution Control of Plating Shop Processes," presented at 7th AES/EPA Conference on 

Pollution Control in the Electroplating Industry, January 1986. Published in Plating and Surface Finishing

magazine, July 1986. 

H. M. Davenport, W. E. Powers, "Affect of Low Cost Modifications on the Performance of an Undersized 

Electrostatic Precipitator," presented at 79th Air Pollution Control Association Conference, June 1986. 

AWARDS

Engineer of the Year, 1991 – ENSR Consulting and Engineering, Camarillo 

Engineer of the Year, 1986 – Naval Energy and Environmental Support Activity, Port Hueneme 

Productivity Excellence Award, 1985 – U. S. Department of Defense 

PATENTS

Sedimentation Chamber for Sizing Acid Mist, Navy Case Number 70094 

Attachment F