Water Policy With Dry Cooling System Latest

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Novel methodology for evaluating economic feasibility oflow-water cooling technology retrofits at power plants

Ashlynn S. Stillwella and Michael E. Webberb

aCorresponding author. Department of Civil, Architectural and Environmental Engineering, The University of Texas at Austin,

301 E. Dean Keeton St. Stop C1786, Austin TX 78712, USA. E-mail: [email protected] of Mechanical Engineering, The University of Texas at Austin, 204 E. Dean Keeton St. Stop C2200,

Austin, TX 78712, USA

Abstract

Increasing demand on water supplies already strained by population and economic growth and instream flow

requirements means many areas are considering conservation and reallocation to meet their needs. One method

of increasing water availability is through low-water cooling technologies at thermoelectric power plants. Cooling

towers, hybrid wetdry and dry cooling systems reduce water requirements and the environmental impact at

power plants but require additional capital and operating expenditure. These expenses can be offset with revenue

from leasing water rights made available by new cooling technologies and the added benefit of drought resiliency.

Thus, cooling technology retrofits are hypothesized as cost-effective opportunities for increasing drought resiliency

and supporting instream flows. To test this hypothesis, we developed a novel methodology for evaluating drought

resiliency as a function of economic and technical performance parameters. Using a river basin-based water resources

model of 39 Texas power plants, we illustrate this methodology to determine the feasibility of retrofitting alternative

cooling technologies. At current capital costs and water prices, switching to alternative cooling technologies is econ-

omically justifiable today at three facilities. Higher water prices, coupled with higher volatility in water availability,

will be likely to make low-water cooling technologies economically viable at more power plants in the future.

Keywords: Cooling tower; Dry cooling; Power plants; Texas; Water economics; Water policy; Water rights

Introduction

Competing water uses, changing climatic conditions and increasing demands for water and energy(because of population and economic growth) have strained water resources worldwide. Allocatingadditional water for ecosystems and instream flows as the state of Texas has done with legislationstarting in 2001 exacerbates the challenges of meeting the anthropogenic demand for water resources.In the context of drought, managing water withdrawals requires balance between different users. Finite

Water Policy 15 (2013) 292308

doi: 10.2166/wp.2012.018

IWA Publishing 2013
mailto:[email protected]:[email protected]


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water supplies or water markets where no unallocated water exists means that water must be reallocated,sold, or leased from current water rights holders to meet the needs of new users. An efficient watermarket for such reallocation operates based on economic value associated with water use.

Allocating water use on commodity-based economic value often neglects the non-use value of waterin the natural environment (Young, 2005). Instream flows as a public good make it difficult to assigneconomic value in a traditional sense (Griffin & Hsu, 1993). However, maintaining or improvinginstream water quality has an associated benefit, generally greater than the cost of water, thereby creat-ing a consumer surplus (Nallathiga & Paravasthu, 2010). To protect instream flows and ensurefreshwater inflows to bays and estuaries, the state of Texas passed legislation creating the TexasInstream Flow Program (TIFP) in 2001, with priority studies completed by the end of 2010, to mandateappropriate stream flow to protect the aquatic environment. The TIFP is one of the first formal instreamflow programs in the United States and its implementation could serve as a model for other states ( Mal-lardet al., 2005). Such policy measures are unique in that they assign a water rightgenerally the most

senior priority in the basin

to the stream itself, giving instream flows legally permitted water volumes.Without such permission, the stream itself can run dry if all the water is allocated in the basin and rightsholders exercise their rights fully; these conditions would cause a deleterious impact on the ecosystem.By assigning senior priority to the river basin itself, a legal framework exists for avoiding such scen-arios. However, for river basins with no unappropriated water available, water conservation andwater rights reallocation from other users are required.

Reallocation of water between different users is not a new concept. In many instances, agriculturalwater rights are leased or sold to other water users, generally urban municipalities, when monetary con-ditions or irrigation technologies motivate the exchange. Previous research shows that water transferbetween sectors can benefit both parties, depending on costs. For example, when agricultural usersincrease irrigation efficiency or use treated municipal wastewater, they make available excess irrigation

water for municipal users to purchase (Heinzet al., 2011). The City of Roma, TX, paid US$2.8 millionto upgrade equipment at local farms to increase irrigation efficiency in exchange for gaining access tothe saved agricultural water rights for municipal purposes, causing a net increase in water availability(Gerston et al., 2002). This water reallocation is possible within a functioning water rights market,which would enable the transfer of water and water rights from low-value uses to high-value uses. How-ever, structuring efficient water markets is difficult because water is mobile, variable in supply, low-valued, causes site-specific problems and is rife with competing political contexts (Young, 2005).

Power generation is one such high-value operation and power plants are large water users, as high-lighted by recent attention to the energywater nexus pertaining to thermoelectric power generation(Fthenakis & Kim, 2010;Macknicket al., 2011;Pfisteret al., 2011;Stillwell et al., 2011a). However,

there are alternative cooling technologies cooling towers, hybrid wet

dry cooling and dry cooling which require smaller water withdrawals at power plants. That is, power plants present an opportunityfor reducing water withdrawals through use of low-water cooling technologies and managing droughtconditions by transferring excess water rights to other users or instream flows. Previous work by Still-well et al. (2011b) reveals the potential water savings associated with implementation of alternativecooling technologies at Texas power plants. However, economic feasibility and suitable policy con-ditions that facilitate technology adoption are necessary for these savings in water withdrawals to berealized. Here we investigate the economic feasibility of using low-water cooling technologies at exist-ing Texas power plants, comparing capital and operating costs for cooling technology retrofits withrevenues generated from leasing excess water rights and avoidance of drought-related power plant

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curtailments. Texas is a suitable test bed for our work owing to its self-contained electric grid, variablewater availability, hybrid riparian and prior appropriation system of water rights and numerous distinctriver basins (in contrast to other states draining entirely to the Mississippi River, for example). Suscep-

tibility to drought, particularly the 2011 record-setting drought, makes Texas an appropriate and timelyenvironment for our consideration of alternative cooling technologies. Feasible implementation ofalternative cooling technologies can mitigate the management challenges associated with drought,increase the resiliency of the power generation sector and support aquatic environments throughincreased instream flows.

Methodology

To understand the economics of alternative cooling technologies for thermoelectric power plants, weadapted a river basin-based model developed by the authors, the details of which are presented else-where (Stillwell et al., 2011b). This river basin-based model uses existing water availability models(WAMs) from the Texas Commission on Environmental Quality (TCEQ, 2009) to simulate water with-drawals in the basin of interest over historical climate conditions with geographical fidelity, combinedwith a model of alternative power plant cooling technologies. This economic analysis is based on full

execution WAMs, which simulate each perpetual water rights holder withdrawing the entire permittedvolume with zero return flow, in 11 Texas river basins: the Brazos and San Jacinto-Brazos, Coloradoand Colorado-Brazos, Cypress, Neches, Nueces, Red, Sabine, San Jacinto and Trinity river basins.These river basins were selected based on the presence of thermoelectric power plants, as shown inFigure 1and detailed descriptions in the full execution WAMs (see Stillwell et al. (2011b)for a com-plete discussion). These full execution WAMs represent a worst case scenario since most water uses

Fig. 1. A total of 39 power plants (of varying capacities) in 11 river basins were considered in this economic analysis.

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have an associated return flow, yet these WAMs are used by TCEQ to evaluate applications for newwater rights.

The economic feasibility model described in this paper compares water requirements for current cool-

ing technologies (for instance, open-loop cooling) with reduced water requirements for alternativecooling technologies, as shown in Figure 2, in a sample of 39 power plants in Texas. We considerthree alternative power plant cooling technologies: cooling towers, hybrid wetdry cooling and dry cool-ing. Cooling towers, one of the most common methods of closed-loop cooling of thermoelectric powerplants, decrease water withdrawals compared to open-loop cooling, but increase water consumption.Evaluation of water availability and water rights in Texas are based on water withdrawals with zeroreturn flow (the full execution WAMs), thus consumption is effectively the same as withdrawalsfrom the perspective of water allocation. Overall economic feasibility was determined by comparingthe cost of alternative cooling technologies with the price of water.

Cost of alternative cooling technologies

Capital cost investments for retrofitting thermoelectric cooling technologies vary for different coolingconfigurations and power plant fuels, as shown inTable 1. The capital cost (P) of a particular coolingtechnology is dependent on fuel type, power cycle, air pollution control equipment, location, climate,water quality and many other factors such that wide ranges of costs (in US$/megawatt-electric(MWe)) are reported in literature. Our analysis uses the data found in Table 1 to inform a first-order

Fig. 2. The motivation for installation of alternative cooling technologies is the lease of excess water rights. When thermo-

electric power plants reduce water requirements for open-loop cooling (shown in panel (a)) through use of alternative

cooling (shown in panel (b)), the remaining water can be leased for various purposes. While return flows are usually associated

with power plant cooling systems, availability for surface water rights in Texas is based on an assumption of zero return flow

from all users (also known as the full execution water availability model).



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assessment of the economic feasibility of alternative cooling technologies. Actual cooling technologyretrofit costs for a specific plant would require re-evaluation with highly site-specific cost data.

To compare costs and revenues directly, we annualized the capital costs for alternative cooling tech-nologies over an assumed project life adapted from present value equations reported by Loucks & vanBeek (2005). Additional operations and maintenance costs for auxiliary equipment and cooling towerchemicals are also incurred with implementation of wet alternative cooling technologies, but these oper-ational costs are notably lower for dry cooling. Since dry cooling is inherently less efficient than wet

cooling, lost electricity revenues are associated with the parasitic efficiency loss with dry cooling. How-ever, the economic value of drought resiliency can offset cooling system costs by serving as insuranceagainst power plants decreasing or shutting down electricity generation in response to water constraints.For example, a hypothetical wet-cooled power plant might have a 6% chance of losing 15% of its poweroutput on any given year, as shown in Figure 3(and explained later); switching to dry cooling wouldreduce this risk to 0%, while introducing an average and sustained 2% efficiency loss. We capture thisrisk protection in a drought resiliency term as a function of drought probability and power losses causedby water-related power plant curtailments.

Annual cooling cost (Ac, US$/yr) comprises the four cost components shown in Equation (1): annual-ized capital cost, annual operations and maintenance costs, lost electricity sales due to parasitic

Table 1. Capital cost (P) data for cooling technologies that decrease water withdrawals, compared to open-loop cooling, vary

with different power plant fuels (natural gas, coal and nuclear).

Adjusted costa

(2010 US$/MWe)

Cooling technology Low High Reference

Natural

gas

Cooling tower US$19,100 US$25,700 California Energy Commission (2002)

Dry cooling US$145,000 US$216,000 California Energy Commission (2002);Electric

Power Research Institute (2004)

Hybrid wetdry coolingb US$165,000 US$242,000 See footnoteb

Coal Cooling tower US$85,600 US$95,100 Zhai and Rubin (2010)

Dry cooling US$177,000 US$236,000 Zhai and Rubin (2010)

Hybrid wetdry coolingb US$263,000 US$331,000 See footnoteb

Nuclear Cooling towerc US$205,000 US$1,240,000 WorleyParsons (2008);Asbury Park Press (2010)

Dry coolingd US$313,000 US$446,000 WorleyParsons (2008)

Hybrid wetdry coolingb

US$652,000 US$1,570,000 See footnoteb

aWhere possible, reported data are for cooling technology retrofits; new installation costs were substituted as a first-order

approximation when retrofit data were unavailable. Costs are highly variable depending on location and plant size. Reported

costs have been adjusted to 2010 US dollars using the Consumer Price Index ( Bureau of Labor Statistics, 2011).bCosts for hybrid wetdry cooling are assumed to be equal to the sum of wet (cooling tower) and dry cooling per MW e, such

that a facility could operate 100% wet or 100% dry. Actual costs could potentially be higher for additional equipment to

allow flexibility between wet and dry cooling, or possibly lower owing to common shared parts. Thus, additional uncertainty

is present in these cost data.cFew cost data exist regarding installation of cooling towers at nuclear power plants. The low end of the cost range presented

here is assumed to be similar to that of a solar thermal power plant. The high end is an estimate given by Exelon for a single

plant and reported byAsbury Park Press (2010). Others suggest costs at 1012% of that reported by Exelon (Bates, 2006).dDry cooling is not currently used at any nuclear power plants in the United States. The cost data reported here are those of a

solar thermal power plant as a first-order approximation; however, dry cooling might not ever be a viable option for nuclearpower plants for safety reasons.



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efficiency loss, and benefits of drought resiliency (shown as negative cost because benefits are mani-fested as additional sales during droughts):

(1)

where i is the annual interest rate, t is the cooling system life (yr), G is the annual generation of thepower plant of interest (MWh/yr) (based on King et al., 2008), rw is the average wholesale electricitysales rate (US$/MWh), AO&Mis the annual operations and maintenance cost (US$/MWh) and is thepower generation efficiency loss associated with the cooling system, where the index jdesignates thetype of alternative cooling technology (cooling tower CT, hybrid wetdryH, or dry coolingD). Selected

values for the variables in Equation (1) are presented inTable 2. These costs can be offset, in part orwhole, by revenue from water leasing, which is discussed later.Drought resiliency defined in this context as a facilitys ability to avoid negative outcomes during

drought conditions is dependent on the drought risk aversion factor (here 1 as risk neutral forthis aggregate analysis, since the actual value would be determined by individual power plants) and theexpected value of electricity generation curtailmentpf,nCnbased on probability pfand curtailment per-centageCfor a drought eventn, a sample of which is given in Figure 3(and explained later). Droughtresiliency is further explained in the next section.

The summer wholesale electricity sales price of US$44/MWh (Electric Reliability Council of Texas,2010) given inTable 2represents the 2010 zonal grid daily average market clearing price. Our analysis

Fig. 3. Sample probability distribution for electricity generation curtailment percentage shows a high probability of zero curtail-ment and a low probability of total shutdown for drought duration of 1 yr. If the probability of a given drought event increases

in the future as climate change increases the severity of droughts and heatwaves (IPCC, 2007), then these probabilities of cur-

tailment would increase.



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uses this single value ofrwto demonstrate our methodology. However, market clearing prices for elec-tricity vary in 15-minute intervals throughout the day, and electricity futures prices (representingestimated long-term prices) vary by future month. While it was not done here, a more temporallyresolved analysis could be performed using the same framework. In particular, the maximum daily aver-age wholesale electricity price in 2010 was US$194/MWh, while the 15-minute interval maximum and

minimum were US$2,250/MWh and US$32/MWh, respectively (negative prices are the result of nega-tive bids from off-peak wind power generation) (Electric Reliability Council of Texas, 2010). Thisdramatic range in electricity prices means our use of a single average value introduces uncertainty inthe analysis, yet long-term cooling technology decisions are more likely to be based on long-term elec-tricity price averages than 15-minute price spikes, so this approach is not inconsistent with the typicalassumptions of planners.

Value of drought resiliency

Dry cooling technologies have a relatively constant parasitic efficiency loss owing to the lower heatcapacity of air compared to water. Efficiency loss is generally near 2%, but can grow to 10% with highambient air temperatures (Smart & Aspinall, 2009; US Department of Energy, 2009; Zhai & Rubin,2010). Despite the parasitic efficiency loss, dry cooling can be attractive since it incorporates a built-in resiliency against drought and heat waves.

Drought is quantified using the Palmer Drought Severity Index (PDSI), a unit-less number based onprecipitation, air temperature and local soil moisture. Positive PDSI values correspond to wet conditionsand negative PDSI values correspond to dry conditions. Monthly PDSI values for Texas are shown inFigure 4. Two main parameters characterize drought: duration and severity. Duration (D) is defined asthe elapsed time from the beginning of a dry period to the beginning of a wet period, based on a drought

Table 2. Values assigned to the parameters given in the table for variables in Equation (1) based on assumptions and values

reported in literature.

Parameter Variable Value Reference

Annual interest rate i 5% Assumed

Cooling system life t 50 yr Assumed

Annual operations and maintenance,

cooling tower

AO&M,CT US$2.36 MWh WorleyParsons (2008)

Annual operations and maintenance,

hybrid wetdry

AO&M,H US$1.42 MWh WorleyParsons (2008)

Annual operations and maintenance, dry

cooling

AO&M,D US$0.24 MWh WorleyParsons (2008)

Efficiency loss, cooling tower CT 0% Assumed

Efficiency loss, hybrid wetdry H 0% Assumed

Efficiency loss, dry cooling D 2% Smart & Aspinall (2009);US Department

of Energy (2009);Zhai & Rubin (2010)

Average wholesale electricity sales rate

(summer)

rw US$44 MWh Electric Reliability Council of Texas

(2010)



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threshold (defining drier-than-normal conditions) of0.5. Severity (S) is defined as the area between thedrought threshold and the PDSI curve during drought events. Intensity (I) is the ratio of severity to dur-ation, as discussed inKimet al. (2003)and shown inFigure 4, where D corresponds to the abscissa,

PDSI corresponds to the ordinate and S is the integral of PDSI for a range D.Drought conditions are often auto-correlated Fernndez & Salas, (1999a, b) so different drought

occurrences are not necessarily independent events. Consequently, determining the return period the average number of years until an event equaling or exceeding a given magnitude occurs is difficultfor complex hydrological events like droughts. Adapted fromFernndez & Salas (1999a,b), the return

period (T) for meteorological drought is defined as:

T 1 pDf1 pf pDf

(2)

Using Equation (2), lower drought probabilities pfare associated with higher return periods Tfor agiven duration D. That is, a drought with a high return period is less likely to occur (and therefore isworse in terms of severity) than a drought of the same duration with a low return period. Similar toreturn periods for flood events, high return periods are associated with rare, extreme events.

Water stress associated with drought affects power plants differently based on plant-specific coolingsystems. For example, a drought with a high return period can cause a high percentage of power gener-ation loss owing to cooling water constraints, depending on cooling technology, as hypotheticallydepicted inFigure 5. Power plants using open-loop cooling or cooling towers might curtail power gen-eration in response to drought similar to the trend in Figure 5(a) where worse droughts cause an

Fig. 4. Palmer Drought Severity Index (PDSI) for the state of Texas indicates wet (positive values of PDSI) and dry (negative

values of PDSI) conditions over time. Drought is defined as PDSI 0.5, with drought duration, severity and intensitydefined as shown (figure created with data fromNCDC (2011); based on Fig. 2 fromKimet al. (2003)).



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exponential increase in power generation loss as thermal cooling water effluent limitations areapproached. Cooling reservoirs, on the other hand, might curtail operations like that shown inFigure 5(b)where thermal limitations might cause power generation loss initially, but total plant shutdown is requiredonce the reservoir level falls below the cooling water intake. Unlike wet cooling which approaches 100%power generation loss with worsening drought, dry cooled power plants might experience power gener-ation efficiency losses like those shown inFigure 5(c)where efficiency losses are never zero, but slowlyincrease from 2 to 10% ending at a much lower plateau than the other two options.

Based on these trends, dry cooling becomes increasingly attractive for reliable power generation in thelight of worsening drought conditions and limited water supplies. Illustrating this point, the proposedTenaska Trailblazer Energy Center (a 600-MWe (net) coal-fired power plant near Sweetwater, TX)has chosen to install dry cooling systems because of water constraints, revealing the economic feasibilityof low-water cooling in the context of water scarcity for new construction (Tenaska, 2010). In additionto feasibility in terms of direct costs and benefits, dry cooling also provides protection from infrequentyet major losses of power output caused by heat waves and droughts. This drought resiliency is a trade-off for constant yet minor power generation efficiency losses associated with dry cooling. Dry coolingcan also increase grid reliability by serving as protection against freezes, which caused rolling blackoutsin Texas in February 2011 (Federal Energy Regulatory Commission, 2011). Fully evaluating the effi-ciency loss versus drought risk trade-off requires highly site-specific data to assess the economicviability of costly cooling system retrofits. Our methodology for assigning value to drought resiliencyfrom low-water power plant cooling technologies provides a general framework for performing suchsite-specific analyses.

Price of water

Whether dry cooling systems make economic sense depends partly on the price of water, which is highlyvariable and relates to available quantity, quality and intended use, among many other factors. Two particu-lar water prices are pertinent to our economic analysis: the sale and lease of Texas water rights. A small

Fig. 5. Open-loop cooling and cooling towers (shown in (a)), cooling reservoirs (shown in (b)) and dry cooling (shown in (c))

systems respond differently to drought conditions. In these hypothetical curves, the drought return period,T(generally in units

of years) is used to represent the likelihood of drought: a higher return period corresponds to lower probabilities for a givendrought duration.



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number of reported transactions make pricing the two options difficult. The water market in Texas is noteconomically efficient, as will be discussed later, and transaction data are limited. Consequently, spatial andtemporal variance in water prices and the dynamics of supply and demand (increased water availability

affecting price) could not be incorporated into our analysis. Reported outright sales of Texas waterrights reveals the price of water ranging from US$0.57/m3/yr to US$0.97/m3/yr when adjusted to 2010US dollars (Griffin & Characklis, 2002;Price, 2010). As shown inTable 3, the cost of leasing Texaswater rights ranges from US$0.02/m3 to US$0.08/m3, making leasing of water rights more economicalfrom the perspective of the power plant operator within a typical planning horizon than outright sale. Asa result, we consider only leasing of excess water rights in this economic feasibility analysis.

Table 3also lists prices for Texas municipal water and bottled water in order to provide a context forwater pricing. Leasing of water rights is markedly less expensive than municipal water prices, whichvary over a large range owing to various resource and socio-political factors in Texas. Additionally,the costs of avoiding water use by both improved irrigation and municipal water efficiency are given

in Table 3 for comparison. Within uncertainty and the range of reported values, leasing of waterrights is nearly equal to irrigation and municipal water efficiency costs. Consequently, leasing ofexcess water can reasonably be considered along with other water efficiency investments. Notably,none of the prices shown in Table 3 directly reflect externalities or non-use value.

Annual water revenues (Aw, US$/yr) were determined using Equation (3) for subsequent comparisonto annual cooling costs.

AW cQj (3)

wherec is the price (fromTable 3, US$/m3) that power plant operators might be able to collect from

leasing excess water rights to other users and Q is the volume of water saved (m3

/yr) for each alternativecooling technology, j. The volume of water saved, Q, was determined for each modeled power plantusing the river basin-based model described by Stillwell et al. (2011b).

Results

We assessed the economic feasibility of alternative cooling technologies at Texas power plants bycomparing the amortized annual cooling cost (Ac) from Equation (1) and annual water revenue (Aw)

Table 3. Current lease prices for Texas water rights are comparable to avoided water use with both irrigation and municipal

water efficiency, but substantially lower than Texas municipal or bottled water.

Adjusted cost (2010 US$/m3)

Water source Low High Reference

Texas water rights lease US$0.02 US$0.08 Water Strategist (2009);Texas Water Development Board

(2011)

Texas municipal water US$0.21 US$2.14 Hardberger & Kelly (2008)

Bottled water US$361.00 US$5,300.00 Data collected by authors

Irrigation water efficiency US$0.04 US$0.15 Texas Water Development Board (2007)

Municipal water efficiency US$0.09 US$0.42 Texas Water Development Board (2007)



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from Equation (3) for each modeled power plant, within appropriate ranges of cost data. The numberand total capacity of power plants considered in our economic feasibility model are shown in italicsinTable 4. We analyzed a total of 39 thermoelectric power plants, as discussed previously; of these,

21 currently utilize open-loop cooling and 18 operate cooling towers or cooling reservoirs. Our econ-omic analysis considers three scenarios: (1) switching the 21 open-loop power plants to coolingtowers; (2) switching all 39 power plants to hybrid wetdry cooling by installing air-cooled condensersand cooling towers, if applicable; and (3) switching all 39 power plants to dry cooling.

When the ranges ofAcand Awcoincided for a particular alternative cooling technology such that rev-enues exceeded costs, we determined that cooling system to be economically feasible at the analyzedpower plant. For current cooling technology costs and water lease rates, moving from current coolingtechnologies to alternative cooling technologies is economically attractive for three power plants.Switching from open-loop cooling to cooling towers is economically feasible for two facilities: theLake Creek and R W Miller power plants. The Lake Creek and R W Miller facilities operate natural

gas steam turbines with capacities of 322 and 604 MW, respectively (power plant data reported inKing et al. (2008)). Switching to hybrid wetdry or dry cooling is economically feasible at FlintHills Resources Corpus Refinery power generation facility, a 55-MW natural gas turbine (data fromKing et al. (2008)) currently operating a cooling tower. These results are shown in Table 4with thetotal analysis sample data. While the Lake Creek power plant closed in 2009, we can still infer thatinstallation of alternative cooling technologies might be economically feasible at some Texas powerplants of a similar size, construction date and power generation technology. Site-specific coolingsystem and water leasing cost data and drought risk aversion and probabilities are required to determinefeasibility definitively, but our first-order results suggest that low-water cooling should be investigatedfurther, especially at power plants using natural gas.

Beyond simple economic feasibility, dry cooling can serve as insurance against drought-related power

generation losses. Since water constraints can trigger curtailment of power plants, utilizing cooling

Table 4. Switching to less water-intensive cooling technologies is currently economically feasible for three thermoelectric

power plants two switching to cooling towers and one switching to hybrid wetdry or dry cooling in the selected

analysis sample. Cooling towers, hybrid wetdry and dry cooling become economically feasible at additional power plants

when interest rates are low, dry cooling capital costs are subsidized, or water lease rates approach the price of municipal

water.

Cooling tower Hybrid wet dry Dry cooling

Economic feasibility scenario

Number of

power plants

Capacity

(MWe)

Number of

power plants

Capacity

(MWe)

Number of

power plants

Capacity

(MWe)

Total analysis sample 21 18,890 39 35,553 39 35,553

Current cost and revenue circumstances 2 926 1 55 1 55

Sensitivity analysis

Low interest rate:i 0% 5 3,725 2 604 6 1,774

Low interest rate and no capital cost for

dry cooling: i 0% and PD US$05 3,725 22 13,035 39 35,553

No parasitic efficiency loss with dry

cooling:D 0%2 926 1 55 1 55

Water lease rates equal to municipal water

prices

17 14,453 28 20,713 34 30,341



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technologies that reduce water requirements can protect facilities from such curtailments. As one par-ticular example of our methodology, we assessed the value of drought resiliency as shown inFigure 3. The two drought probabilities and associated curtailment points are approximated from histori-

cal Texas state-wide PDSI data (NCDC, 2011) and corresponding power plant curtailment percentagesestimated using reported (Dyer, 2000) and anecdotal curtailment data. We model the relationshipbetween drought and power generation curtailment to be exponential (in the absence of additional his-torical data), where there is a high probability of small curtailment and a low probability of highcurtailment. This relationship is represented by pf ae

bC, where a and b are best-fit coefficients of0.1615 and 6.712, respectively, for the data in Figure 3. Using the sample drought probabilities(Figure 4) and power generation curtailment percentages with the best-fit curve plotted in Figure 3,the expected value of power generation curtailment (i.e. the area under the curve or, in the case of com-plete discrete probabilities where

P

alln

pf 1, the area calculated asP

alln

pf,nCn) in any given year is

approximately 2.4%. Notably, this expected power generation curtailment percentage is greater than

the parasitic efficiency loss associated with dry cooling of 2%. Site-specific drought probabilities andconsideration of multi-year dry periods will be likely to give different expected values of power gener-ation curtailment. However, this baseline analysis shows that dry cooling can serve as drought protectionfor power plants without compromising total power generation when accounting for the expected valueof curtailments caused by droughts and heat waves. If droughts become more frequent or increase inseverity owing to climate change, these benefits from dry cooling will increase; quantifying the changesinduced by global warming is beyond the scope of this analysis.

Sensitivity analysis

To understand the economic viability of alternative cooling technologies fully, we performed a sen-sitivity analysis of the costs influencing feasibility. Our goal was to determine the effects of financingand to assess the cost factors that are barriers to implementation of dry cooling, namely capital cost andparasitic efficiency loss. While we used the average summer wholesale electricity rate of US$44/MWh(Electric Reliability Council of Texas, 2010) in our analysis, similar results are observed when using US$51.25/MWh, the long-term electricity futures price (CCS, 2012). This methodology can be readilyapplied to other projections of future prices. As shown inTable 4, very low interest rates (approximatelyzero) make switching to cooling towers feasible at three additional power plants (Tradinghouse, Trini-dad and Valley power plants). Low interest rates also enable implementation of hybrid wetdry coolingat the R W Miller and Corpus Refinery power plants. Dry cooling becomes feasible at six power plants

with generation capacities totaling 1,774 MWewith approximately zero interest. As a result, guaranteedlow interest loans for alternative cooling technologies constitute a policy option that might effectivelyencourage some power plants to implement low-water cooling systems.

Including fully subsidized dry cooling capital costs (PD US$0) with very low interest rates, we findthat more power plants could feasibly switch to hybrid wetdry or dry cooling, as shown inTable 4.These facilities include those where alternative cooling technologies are currently feasible (LakeCreek, R W Miller and Corpus Refinery), feasible with very low interest rates (Tradinghouse, Trinidadand Valley) and 16 additional power plants in the case of hybrid wetdry cooling. Interestingly, whenaccounting for the drought protection of dry cooling and setting i 0% and PD US$0, dry coolingbecomes economically feasible at all power plants considered in our analysis. This finding suggests



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that both cooling system capital costs and revenue from excess water rights leasing are important indetermining economic feasibility.

To determine the effects of lost revenues caused by decreased electricity production, we setD 0%

as an exercise. AchievingD 0% in practice is not physically possible without oversizing the dry cool-ing system since the heat capacity of air is much lower than that of water. In our analysis, we set drycooling capital costs equal to those reported in Table 1for an appropriately sized system and setD 0% as a hypothetical option to determine the economic limit. Even with no revenue lost to decreasedelectricity production, dry cooling is only economical at the Corpus Refinery, revealing that parasiticefficiency loss is not the sole barrier to implementation of dry cooling.

To determine the sensitivity of the economic feasibility of low-water cooling technologies to watercosts, we adjusted the value of water as a revenue source. Water is historically undervalued in Texas,with many sources costing virtually nothing beyond the energy and equipment used to collect thewater. Treating water to municipal drinking water standards requires treatment and distribution, both

with embedded energy; therefore, municipal water is more expensive than leasing water rights, asshown inTable 3. Sustainable water resources management is, however, contingent on the right pricingof water (Global Water Partnership, 2004). For example, undervalued water is easily wasted. We setwater rights lease rates equal to Texas municipal water rates in our model, since outright purchase ofwater rights (as opposed to leasing) revealed identical conclusions. As shown in Table 4, switchingfrom open-loop cooling to cooling towers is economically feasible at over 80% of the power plants ana-lyzed (representing nearly 77% of the analyzed generation capacity) when the water prices power plantsmust pay (or the price at which they can lease excess water) are equal to municipal water prices.Additionally, hybrid wetdry and dry cooling are economically feasible at 72 and 87% of the powerplants analyzed, respectively. Based on this dramatic increase in the number of power plants wherealternative cooling technologies are economically feasible, we conclude that the cost of water is the

single largest factor influencing the economics of low-water cooling systems. Low-water cooling tech-nologies become sensible when power plants can lease out excess water at high prices or, conversely,when power plants must pay high prices for cooling water (in the case of new construction). Alternativecooling technologies are likely to become increasingly feasible as water prices increase in response todecreasing water supplies and increasing demands.

Policy implications

Our economic analysis is built on an assumption of existing, functional water markets. While econ-

omic theory states that efficient markets will govern themselves to find an equilibrium price based onsupply and demand, existing Texas water markets are far from efficient. Two types of water marketcurrently exist in Texas: the Rio Grande valley and the rest of the state. The water market in the RioGrande valley is unique, with flows mandated by international treaties and no seniority associatedwith water rights. As a result, factors influencing water market efficiency in the Rio Grande valleycannot be extended elsewhere (Chang & Griffin, 1992; Leidner et al., 2011). Outside the RioGrande valley, water marketing is not common in Texas since (1) water supplies have historicallybeen adequate in populous areas, (2) few natural conduits or non-dedicated engineered infrastructureexist for transfers, (3) water rights enforcement is lax and (4) river authorities have monopolisticpower to reallocate water internally (Griffin & Characklis, 2002). As a result, few water rights sales



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or leases take place in the rest-of-Texas water market. In fact, only seven water rights outside the RioGrande are currently available in the Texas Water Bank, all of which are for lease with posting datesranging from 2000 to 2009 (Texas Water Development Board, 2011). Therefore, low-water cooling

technology retrofits are unlikely to be motivated by the current Texas water market alone.Changes in power plant cooling technologies can be motivated by policies independent of a water

market. For example, the US Environmental Protection Agency has recently considered requiring cool-ing towers at all power plants under Section 316(b) of the Clean Water Act to protect aquatic life fromimpingement, and cooling towers might be required at the discretion of the state or other water permitissuer (Environmental Protection Agency, 2011). The State of New Jersey Department of EnvironmentalQuality proposed a ruling requiring cooling towers be installed at the Exelon-owned Oyster Creeknuclear power plant to decrease the adverse impact on Barnegat Bay. Cooling tower cost estimateswere completed, with different sources quoting costs ranging from US$79 million to US$801 millionfor the 645-MWe facility (Bates, 2006). As part of a strategic business plan, Exelon has decided to

retire the Oyster Creek facility in 2019

10 years earlier than originally planned

instead of installingcooling towers (Asbury Park Press, 2010). Many factors probably influenced Exelons decision, such asthe complexity of the proposed cooling tower site, the expected life of the power plant and uncertaintyregarding licensing extensions from the US Nuclear Regulatory Commission. Notably, URS Corpor-ation evaluated the Oyster Creek cooling system and determined hybrid wetdry cooling to be mostappropriate since it both reduced water use and did not produce a visible plume, which is importantfor reducing security risks (Bates, 2006). The Oyster Creek example shows that state policies similarto that of New Jersey could require implementation of alternative cooling technologies or operationalchanges at power plants in the future.

Policies that facilitate implementation of alternative cooling technologies at thermoelectric powerplants can also help increase overall water availability. This increased water availability can fulfill grow-

ing municipal water needs, maintain freshwater inflows to bays and estuaries and provide flexibility andresiliency during times of drought. Determining the value derived from non-monetary benefits ofincreased water availability, such as additional instream flows, is beyond the scope of this analysis,yet our results suggest that such a study might reveal favorable economics for installation of low-water cooling systems at power plants. Our analysis shows that reducing water requirements forpower generation by using alternative cooling technologies is already economically feasible at somepower plants in Texas; these results motivate similar and extended economic valuations of water andpower plant cooling elsewhere.

Conclusions

We created and integrated an economic model with a river basin-based model to develop a novelmethodology for assessing the economic value of drought resiliency of different power plant coolingsystems. Using this methodology, we quantified the economic feasibility of low-water cooling technol-ogies at Texas power plants. While cooling towers, hybrid wetdry and dry cooling systems have highcapital costs, our analysis shows that installing and operating these alternative cooling technologies iscurrently feasible at three power plants. When water lease rates are set equal to municipal waterprices, switching from open-loop cooling to cooling towers becomes economically feasible for 17 ofthe 21 power plants analyzed, representing nearly 77% of the analyzed generation capacity. Similarly,



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setting water lease rates equal to municipal water prices causes hybrid wetdry and dry cooling to beeconomically feasible at 28 and 34 of 39 analyzed power plants, respectively. Water rights leaseprices are the single largest factor influencing the economic feasibility of alternative cooling technol-

ogies in our analysis. If water prices go higher, the value of dry cooling also goes up. Dry coolingalso serves as insurance for power plants against drought and associated power generation curtailmentsand therefore reaps additional value by helping to provide grid stability. While a constant parasitic effi-ciency loss is associated with dry cooling, such systems protect against infrequent yet major losses inpower generation caused by droughts and heat waves.

While our analysis reveals an underlying economic motivation to reduce water requirements at ther-moelectric power plants, our conclusions are limited by the availability of data. Costs for coolingtechnologies and water rights are highly site-specific and can vary by an order of magnitude, dependingon local circumstances. Decisions regarding actual cooling technology retrofits with associated leasingof excess water rights should be based on cost data specific to a particular site. Nonetheless, our results

indicate that low-water cooling technologies at power plants that lease excess water rights could beeconomically feasible, while increasing water availability. Such unconventional approaches to waterresources management are likely to be beneficial in areas where power plants are located and watersupplies endure increasing strain.

Acknowledgements

This research was supported in part by the National Science Foundations Emerging Frontiers inResearch and Innovation Resilient Infrastructures (EFRI-RESIN) program. The authors would like toacknowledge Graduate Research Assistant Mary Clayton, The University of Texas at Austin and co-

principal investigators David Allen and Rob Williams, The University of Texas at Austin, and MortWebster and Ron Prinn, Massachusetts Institute of Technology, for their thoughtful contributions tothis paper. This project had additional support from the US Department of Energy.

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