June 5, 2012

Mr. Gerardo Rios

Chief, Permits Office

USEPA Region 9

75 Hawthorne Street

San Francisco, CA 94105

Subject: Pio Pico Energy Center (PPEC) PSD Permit Application

BACT for Cooling System 

Dear Mr. Rios:

As requested by EPA in an email from Roger Kohn to Steve Hill on May 23, 2012, we 

are submitting clarifying information on behalf of Pio Pico Energy Center, LLC. In 

short, and as demonstrated below, were PPEC to use a totally dry cooling system it would 

require 16 MW of additional combustion generation capacity to deliver 300 nominal 

megawatts of power, the project’s basic design and purpose. Such induced inefficiency

would make the project uneconomic and result in an increase in emissions for the same 

power output. Using a dry cooling system only, plant capacity would begin to decrease 

at ambient temperatures greater than 70o F, and plant output would be no greater than 

283.6 MW at the plant design maximum ambient temperature of 93o F. For this reason, a 

100% dry cooling system is not technically feasible for PPEC. In addition, even if such a 

design were feasible, the additional cost of a totally dry cooling system would not be 

cost-effective, given that the PM/PM10/PM2.5 emissions from the currently proposed 

system are only 1.4 tons/year. Further support for these conclusions is presented below. 

EPA Comment:

In your letter, you state that you have eliminated dry cooling in the BACT analysis 

because “there are times when the ambient temperature in San Diego is too high for a 

100% air-cooled system to provide sufficient cooling for the intercooler system to sustain 

turbine performance.” Similarly, in the PSD application (p. PSD-App-1.92), you state 

that “The main technical issue associated with dry cooling towers for this application is 

the limited availability to provide adequate cooling under high-temperature conditions. 

The plant will use a PDCS in a closed-loop configuration that utilizes dry cooling but 

also requires additional cooling capacity. For the purposes of this analysis, dry cooling 

was eliminated as a potential BACT option for the second stage of the cooling system 

because enhanced cooling is required for the plant beyond what is already being 

provided by the dry cooling system.” 

sierra

research

1801 J Street

Sacramento, CA 95811

Tel: (916) 444-6666

Fax: (916) 444-8373

Ann Arbor, MI

Tel: (734) 761-6666

Fax: (734) 761-6755
Gerardo Rios -2- June 5, 2012

We believe we might understand your point, however, the information you have provided 

is not specific enough to justify eliminating dry cooling in Step 2 of the analysis on the 

basis of technical infeasibility. Based on your submittal, it appears that you are actually 

trying to explain that dry cooling alone is not technically feasible all the time and may 

need to be supplemented by a type of wet cooling when the ambient temperature exceeds 

a level that is not stated in the documentation you submitted. Please clarify if this is the 

case, the temperature at which the dry cooling system would not function, how often that 

is expected to occur, and how the supplemental cooling system could be used for those 

short periods of time when the dry cooling system alone would not work. Thus, you 

would provide the necessary information to eliminate dry cooling alone, but would show 

how dry cooling with intermittent use another cooling system would be technically 

feasible. As you outline your decision-making for the selected (and non-selected) control 

option, please discuss any associated trade-offs considered, such as environmental and 

economic trade-offs, as part of your design and operating criteria. 

Response:

The PPEC closed loop cooling system provides water cooling for the High Temperature 

Intercooler (HTIC) at each GE LMS100 Combustion Turbine Generator (CTG). HTIC 

water flow requirements for all three CTGs are combined into a common system that uses 

the hybrid Partial Dry Cooling System (PDCS) to provide the cooling necessary for 

maximum performance and efficiency of the CTGs. Cooling water is used for several 

purposes including, for example, cooling of lubricating oil, but the principal use is for the 

intercooler. The intercooler is used to cool the air between various compressor stages in 

each gas turbine, increasing the mass flow of air, allowing more fuel to be burned and 

greatly increasing the output and efficiency of the turbine. The heat extracted from the 

air in the intercooler is dissipated by the cooling system. Cooling water leaves the 

intercooler at a temperature of about 175o F to 190o F, after having absorbed heat from 

the compressed intake air. Cooling water must enter the intercooler at a temperature of 

80o F to achieve each turbine’s rated output of about 100 MW.

Fundamentally, a 100% dry-cooling system cannot cool the water below the ambient drybulb temperature. Because the water temperature entering the intercooler needs to be 

80o F, a dry-cooling system cannot meet the system requirements if the ambient 

temperature is greater than 80o F. 

In practice, an air cooled heat exchanger must have a temperature differential between its

hot side and cold side. A temperature difference of less than about 10o F from ambient is 

not achievable for the dry-cooling components. Therefore, at ambient temperatures 

above 70o F, the water entering the intercooler cannot be chilled to 80 o F, and each 

turbine’s output would then decrease below 100 MW. The shortfall in output would get 

larger as the ambient temperature increases above 70o F. The average daily high 

temperature in San Diego exceeds 70o F on 147 days per year (40%)1; these are the days 

when PPEC is most likely to operate.

 

1

http://www.weather.com/weather/wxclimatology/monthly/graph/USCA0982 (accessed 5/31/2012)
Gerardo Rios -3- June 5, 2012

Consequently, in order to deliver 300 MW at ambient temperatures up to the design 

maximum temperature of 93o F using three LMS100s, a dry-cooling system, by itself, is 

not technically feasible.

After determining that a 100% dry cooling system was not feasible, the PDCS design was 

incorporated. This system was optimized considering the capital cost of the dry cooling 

components; the cost of water used; and the cost of the electricity needed to drive the fans 

used for the dry cooling components. This optimized solution cannot achieve a water 

inlet temperature of 80o F based on dry cooling only with three CTGs at full load, even at 

an ambient temperature of 59o F.2 As noted above, such a system requires a wet cooling 

component for ambient temperatures above 70o F to achieve full ouput. See Table 1 for 

details about how theoretical 100% dry cooling would affect power consumption and 

production at the facility.

Operationally, there may be times when the wet cooling system would not need to be in 

service, based on plant MW load demand, the number of CTGs in service, and the 

ambient temperature. However, under most ambient conditions under which this facility 

would run (above ~44° F), both the wet and dry cooling systems will be operating. The 

amount of water applied in the wet cooling system will vary depending on ambient 

temperature: the dry cooling system will reject as much heat as possible given the 

ambient temperature, while the wet cooling system will evaporate only as much water as 

is needed to get the intercooler water inlet temperature down to 80o F.

Table 1

Incremental Power Consumption and Production from 100% Dry Cooling

Ambient Conditions

Dry Bulb, oF 59 70 80 93

Relative Humidity, % 60 57.2 37.5 21.9

All Dry Cooling

Output Loss, kW, per CTGa0 0 -1,374 -5,315

Output Loss, kW, 3 CTGsa0 0 -4,122 -15,945

Air Cooled Heat Exchanger 

Power Consumption Loss, kW,b -496 -496 -496 -496

a. CTG output loss is a comparison of output using the specified PDCS to the output if 100% dry cooling 

were specified.

b. Power difference between the PDCS and an all-dry cooling system. Load does not change with 

temperature because all dry cooling fans remain on. 

The additional power consumption for the dry cooling fans, shown in Table 1, will, of 

necessity, result in increased emissions, as that electricity will have to be produced 

somewhere and, on the days when PPEC is expected to operate, the marginal source of 

electricity will certainly be gas-fired, with per-megawatt emissions comparable to, or 

higher than, those of PPEC. More direct, however, are the economic impacts. While not 

quantifiable, a 16 MW reduction in peak power output places the project’s viability in 

jeopardy, as it would represent a material change from the project as presented to 

 

2 At 59o F, 75% of the heat rejection is taken up by the dry cooling components, and 25% of the heat 

rejection is taken up by the wet cooling components. 
Gerardo Rios -4- June 5, 2012

SDG&E. More relevant to EPA, perhaps, is the cost effectiveness of the possible 

reduction of 1.4 tpy of PM/PM10/PM2.5 associated with a totally dry cooling system 

(ignoring the increased emissions associated with the electricity required to run the 

additional dry cooling components). 

In a recent rulemaking,3EPA rejected as too expensive additional controls on an oil-fired 

boiler in Hawaii:

“For PM, the Trinity report considered the following technologies: Dry electrostatic 

precipitator (ESP), wet ESP, fabric filter, wet scrubber, cyclone and fuel switching. 

Dry ESPs, cyclones and fabric filters are not appropriate for the type of particulate 

emitted by this plant. A wet scrubber would work, but these types of devices are 

better suited to larger particulate than is emitted from an oil-fired boiler and their 

control efficiency would be small. A wet ESP would have good control efficiency and 

is technically feasible. Similarly, switching to distillate fuel would be an effective and 

technically feasible control for PM. Trinity estimated the cost effectiveness of a wet 

ESP as $13,000 per ton of PM controlled. They estimated the cost effectiveness of 

switching to distillate fuel as $170,000 per ton. Neither of these controls would be 

cost effective for PM.”

4

Although the above conclusion was reached in the context of a regional haze plan, rather 

than a BACT analysis, it is illustrative of recent thinking by EPA regarding costeffectiveness of PM controls. Using the lower $13,000 per ton cost-effectiveness value

cited in the rulemaking notice, and the maximum potential emission reduction of 1.4 

tons/year for a totally dry cooling system for PPEC, additional PM controls would not be 

cost-effective if costs exceeded $18,200 per year on an annualized basis.5 Using the 

lowest cost of electricity in the San Diego area for industrial facilities of $0.07711/kwh,6

the power consumption for operating the additional dry cooling components necessary to 

enable totally dry cooling up to a 70° F ambient condition would be $152,986 – well 

above the cost/effectiveness threshold.7 This economic analysis does not reflect the 

capital costs of the additional dry cooling components necessary to achieve 100% dry 

cooling to an ambient temperature of 70° F, nor does it include the cost of replacement 

generating capacity of 16 MW necessary to make up for the loss in generation associated 

with the use of totally dry cooling at this location for this generating technology. There is 

no question but that totally dry cooling is so expensive in this application as to be 

infeasible as a practical matter.

 

3

77 FR 31692

4

77 FR 31706

5

1.4 x $13,000 = $18,200

6

http://sdge.com/electric-tariff-book-commercialindustrial-rates, Schedule A. This rate is for small 

commercial/industrial customers. Larger customers, such as PPEC, would use a schedule such as ALTOU, which includes a substantial monthly demand charge, combined with a lower energy cost. At the 

summer peak demand charge of $7.65/kw (which most closely corresponds to PPEC’s operations), and the 

additional demand of 496 kw, the monthly demand charge would be $3,794. If PPEC’s operations were 

compressed into five calendar months, the annual demand charge would be $18,970 per year (about 

$0.01/kwh) – already above the cost-effectiveness threshold, and without accounting for the energy and 

non-energy costs. Non-energy costs would be variable, but generally on the order of $0.01/kwh, adding 

another $19,840/year in costs. Energy (commodity) costs are currently $0.070 to $0.086/kwh, bringing the 

total cost per kwh to $0.090 to $0.106/kwh.

7

496 x $0.07711 x 4000 = $152,986 per year.
Gerardo Rios -5- June 5, 2012 

Comment: 

Also, in your 5/16/12 letter, you present a bullet list of control technologies for the BACT 

analysis, in descending order of control effectiveness. However, you did not include the 

Partial Dry Cooling System (PDCS) that PPEC proposes to use in the initial ranked list. 

This means that if once-through cooling and dry cooling are eliminated from the 

analysis, we do not know if the P DCS is the highest ranked remaining option. If it is, we 

do not need to eliminate the other remaining control options from the analysis. If it is 

not, we may require additional information to justifY eliminating any other options that 

are more effective, or as effective, as PDCS. Please provide a complete list of all control 

options you considered in the analysis, ranked by control efficiency. 

Response: 

The technologies identified are listed below, ranked in descending order of control 

effectiveness. 

• Dry Cooling (closed loop cooling water cooled in heat exchanger using ambient 

air flowing over heat exchanger tubes) 

• Once-through Cooling (Cooling water drawn from a water source. Heated water 

is then discharged, usually back to the original water source) 

• PDCS. Because this is a hybrid system, with a dry cooling component and a 

spray-enhanced dry cooling system component, it is between 100% dry 

cooling and spray-enhanced dry cooling on this ranked list. 

• Spray-enhanced Dry Cooling (dry cooling with heat transfer enhanced by 

spraying water on the outside of the heat exchanger tubes) 

• Plume-abated Wet Cooling (evaporative cooling tower with a dry section that 

reduces the visible plume by heating the wet air from the wet section) 

• Non-Plume-abated Wet Cooling Tower (conventional evaporative wet cooling 

tower) 

If you have any questions regarding this application, please contact the applicant's 

representative David Jenkins at (317) 431-1004, or Steve Hill or me at (916) 444-6666. 

relY(j! 

1IoJ+a,d(!N''''Iuoenstein ~ Ir 

cc: John McKinsey, Stoel Rives LLP 

David Jenkins, Apex Power Group 

Steve Moore, SDAPCD