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Contract No. DE-AC36-08GO28308

Modeling Climate-Water Impacts 

on Electricity Sector Capacity 

Expansion

Preprint

Stuart M. Cohen and Jordan Macknick

National Renewable Energy Laboratory

Kristen Averyt and James Meldrum

University of Colorado – Boulder

To be presented at the ASME 2014 Power Conference

Baltimore, Maryland

July 28–31, 2014

Conference Paper

NREL/CP-6A20-61435

May 2014
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MODELING CLIMATE-WATER IMPACTS ON ELECTRICITY SECTOR CAPACITY EXPANSION

Stuart M. Cohen, Ph.D.

National Renewable Energy Laboratory

Golden, CO, USA

Kristen Averyt, Ph.D.

University of Colorado Boulder

Boulder, CO, USA

Jordan Macknick

National Renewable Energy Laboratory

Golden, CO, USA

James Meldrum, Ph.D.

University of Colorado Boulder

Boulder, CO, USA

ABSTRACT

Climate change has the potential to exacerbate water 

availability concerns for thermal power plant cooling, which is 

responsible for 41% of U.S. water withdrawals. This analysis 

describes an initial link between climate, water, and electricity 

systems using the National Renewable Energy Laboratory 

(NREL) Regional Energy Deployment System (ReEDS) 

electricity system capacity expansion model. Average surface 

water projections from Coupled Model Intercomparison Project 

3 (CMIP3) data are applied to surface water rights available to 

new generating capacity in ReEDS, and electric sector growth

is compared with and without climate-influenced water rights. 

The mean climate projection has only a small impact on 

national or regional capacity growth and water use because 

most regions have sufficient unappropriated or previously 

retired water rights to offset climate impacts. Climate impacts 

are notable in southwestern states, which experience reduced 

water rights purchases and a greater share of rights acquired 

from wastewater and other higher-cost water resources. The 

electric sector climate impacts demonstrated herein establish a 

methodology to be later exercised with more extreme climate 

scenarios and a more rigorous representation of legal and 

physical water availability.

KEYWORDS: Energy-water nexus, Climate change, 

Electricity, Thermal cooling

CLIMATE VULNERABILITIES OF POWER PLANT 

THERMAL COOLING

Thermal power plants require water for operations. Water 

use includes both “withdrawal” and “consumption,” where 

withdrawal is the amount of water removed from the water 

source for use (but then returned to the source, often at a higher 

temperature), whereas consumption is the amount of water that 

is evaporated, transpired, incorporated into products, or 

otherwise removed from the immediate water environment [1]. 

Water withdrawals for thermal power plant cooling account for 

41% of total U.S. water withdrawals, making electric sector 

withdrawals the largest of any sector [1]. The electric sector 

consumes a smaller portion (~3%), but this consumption can 

have important regional implications in areas of water stress 

[2]. Thermal power plants account for 80% of U.S. electricity, 

meaning any short- or long-term disturbance in water resources 

can impact the reliability of electricity supply [3]. Already, this 

vulnerability has caused power plant shutdowns or output 

reductions on several occasions, primarily during heat waves 

and drought [4–6]. 

Climate change has the potential to exacerbate power plant 

water availability problems by altering spatial and temporal 

distributions of freshwater resources and their thermodynamic 

properties, most importantly temperature [7]. Temperature is 

especially important because higher cooling water inlet 

temperature leads to less efficient cooling and potentially 

higher outlet temperatures, which are limited by Environmental 

Protection Agency (EPA) regulation. Climate-related water 

availability changes will vary throughout the United States, 

with water supply expected to increase in some regions and 

decrease in others [8]. Less water available for thermal cooling 

could produce operational difficulties or instigate legal disputes 

over water rights. The expectation of lower water availability 

could impact decisions on what types of power plants to install, 

where to install new capacity, and regulatory decisions on 

water rights availability to proposed power plants. Thermal 

power plant lifetimes vary greatly, but they are generally 
2 

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expected to be 30–60 years; new power plant construction 

decisions can therefore have lasting impacts on and can be 

affected by water resource changes [9]. Water planning 

decisions often are made on different temporal and spatial 

horizons. This work could lead to insights that would assist in 

coordinating energy and water management decisions. 

MODELING THE CLIMATE-ENERGY-WATER NEXUS 

IN ELECTRICITY SYSTEMS

Integrated models with a wide range of spatial and 

temporal resolution are required to analyze the nexus of 

climate, water, and electricity systems. Hydrological cycle 

impacts are often connected to climate modeling and analysis, 

but few climate studies integrate hydrologic phenomena with

electric sector models. Several analyses have examined the 

energy-water nexus in the electric sector, but most use 

decoupled electricity and water models, where water impacts 

are examined as post-processing calculations of electric sector 

model results [10–13]. These studies do not include climate 

and water impacts within electricity sector models that can 

actively respond to changes in water resources.

The National Renewable Energy Laboratory (NREL) 

Regional Energy Deployment System (ReEDS) model has 

recently been updated to endogenously represent thermal 

power plant cooling water demands and constraints on water 

rights available to new generating capacity [14]. Note that the 

term "water rights" in this paper refers to a modeling construct 

that represents combined legal and physical water availability. 

Although this construct is intended to resemble the prior 

appropriation water rights regime used for surface and 

groundwater throughout much of the western United States, we 

use the term more generally in order to characterize water 

resources from all regions and many sources within a “rights” 

framework to represent the cost of gaining access to that water 

resource. That is, the ReEDS model represents the relationship 

between the long-term expected water demand and water 

availability through a water rights framework, regardless of the 

relevant legal regime in a region. This first-of-its-kind 

capability allows water availability to directly impact both the 

siting and type of generating capacity that is built. 

This paper describes a further evolution of the model that 

integrates an initial representation of climate impacts on water 

availability and examines scenarios for some possible impacts 

on electricity system capacity expansion. 

This paper describes initial insights into how climate 

driven changes in average surface water availability can be 

integrated into the model. The procedure and assumptions 

outlined below are a first step in a larger project that will elicit 

sensitivities of the power sector to risks associated with water 

availability scenarios. The results will demonstrate how future 

vulnerabilities can be reduced by considering projected 

changes in water resources when planning electricity system 

capacity expansion. 

SCOPE

This work describes and exercises an initial linking of 

Coupled Model Intercomparison Project 3 (CMIP3) climate 

projections and the ReEDS model. The ultimate goal of this 

endeavor is to determine how consideration of long-term 

changes in water availability may affect current decisions about 

power plant siting. Key characteristics of the ReEDS model, 

focusing on the cooling water supply and demand 

representation, are discussed, followed by a description of how 

CMIP3 data are utilized to represent climate-water impacts on 

electricity system planning. ReEDS simulations are performed 

with and without climate impacts and for a more restrictive 

case with climate impacts and without certain water resource 

types available. National and regional electricity and water 

results are then examined. Scenarios are intended to 

demonstrate the new capability and motivate continued analysis 

under additional climate, water, and energy conditions. We 

make no assertions about the likelihood of any scenario beyond 

the assumptions embedded in input climate, water, and 

electricity data.

METHODOLOGY

The Regional Energy Deployment System (ReEDS) 

Model with Cooling Water Availability Constraints

Model Formulation: ReEDS is an electric sector 

capacity expansion model for the contiguous United States that 

estimates cost-minimized construction and operation of

generation and transmission assets from 2010–2050 [15]. The 

model is a linear program that optimizes capacity expansion in 

two-year time steps with limited foresight using exogenous 

electricity demand projections. Within each time step, ReEDS 

performs a simplified electricity dispatch that meets electricity 

demand and reserve requirements in 17 time slices, four for 

each season and one “superpeak” representing the 40 highest 

demand hours in a year. Spatially, the contiguous United States 

is resolved into 134 supply-demand balancing areas connected 

by an aggregated transmission system of ~300 lines, and wind 

and solar resources are characterized in 356 resource regions.

All major generating technologies are represented in the 

model, including nuclear, coal, natural gas combined cycle 

(GasCC), natural gas combustion turbine (GasCT), hydro, 

wind, solar, geothermal, biopower, and storage. Technology 

types are differentiated by costs and operating characteristics, 

and renewable resources have region-specific quantities and 

costs that comprise regional supply curves. Variable renewable 

resources such as wind and solar are further described by 

statistically calculated capacity value at peak for supplying

planning reserves, induced operating reserve requirements, and 

curtailments. Existing fossil and nuclear capacity is retired 

based on proposed and lifetime-based retirements from Ventyx, 

and renewable technologies with lifetimes within the study 

period are assumed to be automatically rebuilt when their 

expected project lifespans are reached [16]. 
3 

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Thermal power generating technologies (nuclear, coal, 

GasCC, CSP-concentrating solar power) are distinguished by 

the following cooling technology types: once-through, cooling 

pond, recirculating tower, and dry (air cooling). Geothermal 

technologies are currently assumed to use dry cooling, but later 

model versions will allow alternative cooling technologies. 

Each power-cooling technology combination has a specific 

capital and operating cost, water withdrawal and consumption 

rate, and heat rate. 

Water withdrawal rates determine the quantity of water 

rights that must be purchased when new capacity is installed. 

Water rights must be purchased in the balancing area where 

capacity is built, and each balancing area has a water rights 

supply curve with quantity and cost of the following water 

rights types: unappropriated fresh surface water, appropriated 

fresh surface water, shallow groundwater, wastewater, and 

brackish groundwater. 

The water rights supply curve was developed at Sandia 

National Laboratories (SNL) by Tidwell et al. [17]. Though the 

legal definition of water rights applies only in certain western 

states, “water rights” is used throughout this analysis as a 

functional definition, where a quantity of available rights 

represents the amount of water available for use by new 

generating capacity, and a rights cost represents the capital 

investment required to access the water. This interpretation 

translates water availability data based on physical metrics into 

a “right” that new generating capacity must pay to access. 

Water rights data indicate the maximum withdrawal rate 

allowed during the annual average low flow condition, so 

ReEDS requires new capacity to purchase sufficient rights to 

operate at maximum output during this condition. In addition, 

when thermal power capacity retires, its water rights are made 

available at a cost assumed slightly below that of appropriated 

water rights in that region. Retired rights in eastern states have 

negligible cost.

There is a key distinction between the water rights 

availability constraint used for this analysis and a physical 

water availability constraint. The data developed by Tidwell et 

al. are based on gaining access to water resources and the 

capital investment required for that access, so the constraint 

implemented within ReEDS only influences generating 

capacity investment decisions, not operational decisions. Once 

capacity is built, there is no further constraint on the physical 

availability of water. Existing data have not yet been 

transformed to physical water availability data necessary to 

inform such a constraint, and doing so is the subject of ongoing 

work.

Key Model Input Data: Technology cost and 

performance projections are primarily derived from the Energy 

Information Administration Annual Energy Outlook 2013 

Reference Scenario [3]. Table 1 lists 2010 capital costs for 

several technologies. Only slight cost changes are projected for 

all of these technologies except solar, which has declining costs 

to $1,580/kW in 2020, where it remains thereafter based on 

achieving 62.5% of SunShot Vision goals [18]1

. Capital costs 

dominate investment decisions for low operation and 

maintenance (OM) cost technologies such as nuclear and 

renewables, with fuel costs playing an important role for fossilbased technologies. 

Table 1: Capital cost projections for select technologies in 

$/kW for the initial ReEDS solve year, 20102

. 

Technology 2010 capital cost ($/kW)

Coal 2,940

GasCC 970

GasCT 830

Nuclear 4,800

Solar photovoltaic 4,210

Onshore wind 1,770

Fossil fuel costs depend on heat rate and fuel price 

projections. Based on Energy Information Administration 

(EIA) Annual Energy Outlook 2013 (AEO2013) projections, 

coal- and gas-based heat rates decline from 2010 to 2025 and 

are constant thereafter at 8.74, 6.57, and 10.65 million British 

thermal units per megawatt hour (MMBTU/MWh) for coal, 

GasCC, and GasCT, respectively [3]. Coal and uranium prices 

are exogenously defined from AEO2013, with coal prices 

varying by North American Reliability Corporation (NERC) 

region (Table 2) [3]. Natural gas prices are defined 

endogenously within ReEDS using regional price multipliers 

and a linear national natural gas supply curve with a constant 

slope regressed from natural gas price-quantity pairs in EIA 

AEO2012 scenarios and y-intercepts regressed from the 

AEO2013 reference scenario [19,3]. For reference, uranium 

prices, coal prices, and energy-weighted average natural gas 

prices for the baseline scenario (described below) appear in 

Table 2. 

Table 2: Fuel prices in $/MMBTU to power producers.

Fuel 2010 2030 2050

Uranium 0.79 1.05 1.2

Coal 1.43–3.49 2.33–3.97 2.71–4.08

Natural gas3 5.40 5.63 9.58

Cost and performance variation across cooling 

technologies for a given thermal power plant type are defined 

by multipliers on capital cost, OM cost, and heat rate that are 

normalized by recirculating cooling (i.e. all multipliers are 1 for 

recirculating cooling). Several of these are shown in Table 3

[20]. Pond cooling systems are highly variable so are assigned 

characteristics of open-loop cooling. Water withdrawal and 

 1 Sensitivity analysis on technology cost and performance is outside the 

scope of this paper, but analysis leading up to the results herein suggests that 

the climate-water impacts discussed below are relatively insensitive to solar 

technology cost projections. 2 All monetary quantities are 2012 U.S. dollars.

3 Natural gas prices are calculated endogenously within the model. These 

values are derived from the baseline scenario.
4 

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consumption rates for select technologies are shown in Table 4

[20]. Once-through systems withdraw 1 to 2 orders of 

magnitude more water than recirculating cooling, though 

recirculating cooling consumes substantially more water 

through evaporation. Water withdrawal and consumption rates 

for dry cooling are negligible. Generally, systems that 

withdraw less water are more costly and less efficient.

Table 3: Cooling technology cost and performance 

multipliers for select technologies.

Power 

technology

Multiplier on capital cost/OM cost/heat rate

Once-through Dry cooled

Nuclear 0.981/0.989/0.973 1.045/1.051/1.050

Coal 0.981/0.989/0.985 1.045/1.051/1.050

GasCC 0.978/0.996/0.980 1.102/1.021/1.050

Table 4: Water withdrawal and consumption rates in 

gallons (gal) per MWh. 

Power 

technology

Water withdrawal/consumption rate

Once-through Recirculating

Nuclear 44,350/269 1,101/672

Coal 27,088/113 587/479

GasCC 11,380/100 255/208

Water rights availability and cost data were developed in a 

long-term effort by SNL researchers [17]. Availability of each

rights class is based on region-specific water law, physical 

availability metrics, and assumed technical and economic 

barriers. Though appropriation doctrine applies only to 

western states, unappropriated surface water and groundwater 

availability are estimated for eastern states using streamflow 

data, environmental flow considerations, recharge rates, and 

groundwater pumping data. Costs of unappropriated water 

rights are negligible because they consist solely of transaction 

costs to request the rights. Appropriated rights costs are based 

on known transactions in the region. Fresh and brackish 

groundwater rights costs include drilling, pumping, and 

transportation costs. Wastewater rights costs include water 

leasing, conveyance, and treatment costs. Figure 1 provides a 

sense of national water rights availability and cost. Available 

rights are primarily unappropriated surface water in regions 

outside the southwest, groundwater in the eastern half of the 

country, and groundwater between the Pacific Northwest and 

Rocky Mountains. Wastewater and brackish groundwater 

resources are substantially more expensive but are welldistributed across the country. Appropriated water is defined 

only for the western half of the country and has intermediate 

costs and relatively low availability in western states except 

California, where there is no available appropriated water. One 

model limitation is the omission of saltwater resources for 

coastal regions; the SNL work does not include salt water 

resources, and no other salt water resource assessment exists, 

so water rights estimates for coastal regions are likely lower 

than actual.

Figure 1: Most available water rights are unappropriated 

fresh surface water and fresh groundwater.

Adapting CMIP3 Climate Data for Water Availability 

Projections in ReEDS

We estimate future water supplies based on the central 

predictions of a large number of general circulation models 

represented in the CMIP3 project, as published by Milly et al.

[8]. These projections come from an ensemble of 12 general 

circulation models that were selected for performance in 

modeling observed changes in twentieth century water flows 

between the period of 1900–1970 and that of 1971–1998. We 

focus on the spatially explicit central estimates for changes in 

average annual runoff between a baseline climate for 1900–

1970 and the climate projected for 2041–2060 using the A1B 

SRES scenario developed by the Intergovernmental Panel on 

Climate Change [8]. In previous research [21], we spatially 

interpolated these data from a grid (approximately two degrees 

longitude by two degrees latitude scale) onto the 8-digit 

Hydrologic Unit Code (HUC) scale by matching the nearest 

grid centers to each watershed, then we propagated these 

changes through a flow routing network that connects the 

inflow and outflow among watersheds, subject to a full water 

balance. This central prediction will provide a reference from 

which future analysis will consider a broader range of climate 

scenarios.

For preliminary analysis of the effect of including 

projected climate impacts in ReEDS, the projected percentage

change in surface water supply is assumed to approximate the 

percent change in unappropriated and appropriated water rights

available to the power sector. This assumption does not reflect 

possible changes to groundwater availability, so overall water 

impacts could be greater than what is modeled. This 

preliminary method may overestimate future unappropriated 

water availability, because in regions following the prior 

appropriation water rights regime (i.e., certain western states), 

current state policies would allocate the entire change in 

available water volume to unappropriated rights; legally 

appropriated rights are fulfilled in entirety in order of 

decreasing priority in these regions. Figure 2 shows 2050 

percent change in surface water available for each ReEDS 

balancing area, clearly demonstrating that the western half of 

the United States is expected to experience substantially more 
5 

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water stress than the eastern half of the country, where some 

areas are projected to have increased surface water. The 

southwest, in particular, has the greatest reduction in water 

availability.

> 5

1 - 5

0 - 1

-1 - 0

-5 - -1

-15 - -5

2050 % 

Change in 

Surf. Water

-15

Figure 2: Reductions in 2050 surface water availability are 

greatest for water resources in the southwestern states.

The water availability constraints in ReEDS require water 

rights purchases for new builds but have no impact on 

subsequent operation. Thus, to reflect a change in investment 

planning due to expected climate change, climate change 

scenarios modify available surface water rights by the 2050 

percent changes in 2016and beyond, the all years the model 

considers after the present day. In addition, water rights retired 

with power capacity retirements are presumed to be surface 

water, so the quantity of rights returned is the original quantity 

multiplied by the expected 2050 percent change.

Climate and Water Availability Scenarios

The primary purpose of this article is to provide an initial 

comparison of electric sector growth and operation with and 

without climate impacts on water rights availability to 

demonstrate and test key assumptions in including future 

hydrology with climate change impacts in the ReEDS model. 

This paper provides a proof of concept and an initial test of 

assumptions. We recognize that average changes in future 

water supplies may not be greater than the observed or future 

variability in the climate system. Subsequent research will 

evaluate the sensitivities of siting to the tails of the probability 

distribution function for streamflows, a more practical 

mechanism for identifying risks and vulnerabilities. 

A baseline (Base) scenario uses original water rights data, 

while the climate change (CC) scenario uses CMIP3-adjusted 

surface water rights availability for the IPCC A1B SRES 

Scenario. In addition, to examine a more restricted case, the 

climate change with limited water (CC-LW) scenario applies 

CMIP3 modifications to surface water and removes 

appropriated surface water and fresh groundwater from the 

stock of available rights. These exclusions are plausible 

because appropriated surface and groundwater resources are 

primarily rights currently owned by agriculture, which could be 

politically or legally unavailable to the power sector. 

Unappropriated surface water, wastewater, and brackish 

groundwater resources are available in all scenarios.

Other cooling technology restrictions are common to all 

scenarios. Cooling ponds are not included as an option for new 

builds because systems are highly site-specific, so cost and 

performance parameters are too uncertain to be a defensible 

technology option in the model. In addition, due to industry 

trends and pending EPA regulations, once-through cooling 

systems are unavailable to new capacity.

Table 5: ReEDS scenarios toggle climate change impacts 

and available water classes.

Scenario Climate 

Impacts Available Water Classes

Base None All

CC CMIP3 All

CC-LW CMIP3 No appropriated water or 

groundwater

RESULTS & DISCUSSION

ReEDS produces results for capacity expansion, electricity 

dispatch, and reserve provision in each of the two-year time 

steps from 2010 to 2050 along with myriad outputs to describe 

electricity system behavior. To remain focused on climatewater impacts on the electricity sector, this discussion 

emphasizes capacity expansion results and water-related output 

associated with capacity growth.

Water Rights Purchases

Before discussing capacity growth directly, examining 

water rights purchases over time highlights differences between 

scenarios and helps explain the accompanying results. Figure 3

plots cumulative water rights purchases over time in the 

contiguous United States for the baseline scenario without 

climate effects. Most new rights in early years are

unappropriated fresh surface water, with retired rights playing a 

substantial role after 2035 and only a small fraction of the total 

coming from other water rights classes. The large jump in 

rights purchases to 2014 occurs due to actual construction of 

once-through cooled facilities, which is only allowed in the 

model for known facilities. In addition, comparing the scale to 

that on Figure 1, there are orders of magnitude more water 

rights available than are required for electric sector growth, 

notably among unappropriated resources. Thus, the percent 

changes in water rights imposed by climate change effects, 

ranging from -20.2% to 9.8% in each balancing region (see 

Figure 2), are not expected to substantially impact the 

electricity system where unappropriated rights are prevalent. 

Only in regions lacking unappropriated water, where climate 

effects are imposed on appropriated and retired surface water 

rights, would the modifications to water rights be expected to 

alter electric sector development. 
6 

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0

200

400

600

800

1000

1200

2010 2020 2030 2040 2050

Cumulative New Water 

Rights (Bgal/yr)

Wastewater

Appropriated

Potable Ground

Unappropriated

Retired

Figure 3: Nationally, most new water rights are acquired 

from unappropriated resources and retired rights.

States where the modeled impacts on water rights are 

important include California, Nevada, Arizona, and New 

Mexico, which have no unappropriated water, and Texas, 

where unappropriated water is limited or unavailable in the 

southern and western portions of the state. Figure 4 plots 

cumulative rights purchased over time in these states, 

subsequently referred to as the southwest, for the baseline 

scenario along with the 2050 total for all scenarios. 

Unappropriated rights make up a notable fraction of the total, 

but these are all in Texas. Groundwater resources are an 

important source of electric sector water in the southwest, 

representing nearly a quarter of all new water rights, split 

primarily between Texas, New Mexico, and Nevada. Retired 

rights are most often used for new capacity, but 97% of retired 

rights are purchased in Texas and California. Outside of Texas

and California, groundwater dominates, with lesser 

contributions from retired rights and wastewater. 

Southwest water rights purchases in 2050 are 

approximately 0.5% lower in the climate change scenario, and 

more than 6% lower in the limited water climate change 

scenario. Most of the change manifests in fewer 

unappropriated water rights. When groundwater and 

appropriated water rights are eliminated (CC-LW), wastewater

and retired rights are primarily used instead, and rights 

purchases are substantially lower. Though utilizing wastewater 

is more expensive than obtaining new freshwater sources, 

substituting wastewater for freshwater is favored to using less 

water-intensive (and more expensive) technologies.

0

25

50

75

100

125

150

2010 2030 2050

Cumulative New Water 

Rights in the SW (Bgal/yr)

Baseline Scenario

Base CC CC-LW

Waste

App.

Ground

Unapp.

Retired

Cumulative 2050 

Figure 4: In the southwest (CA, NV, AZ, NM, TX), retired 

and high-cost rights are more prevalent, with less rights 

purchased when planning for climate change.

National and Regional Capacity Expansion

Water rights purchases suggest that planning for average 

climate projections might have little effect on national capacity 

expansion, so this section begins with a national-scale 

discussion before transitioning to regional capacity growth.

Figure 5 plots capacity over time by technology type, with 

cooling technology denoted as O (once-through), P (cooling 

pond), R (recirculating), and D (dry). The “other” category 

includes oil- and gas-based steam turbines (OGS), biopower, 

geothermal power, and landfill gas-based generation. 

Reductions in nuclear, coal, and OGS capacity reflect assumed 

retirements in the ReEDS model [16]. Capacity growth is 

dominated by GasCT, GasCC, Solar, and Wind. This transition 

reflects projected costs as well as the need for capacity in early 

years and energy in later years, as GasCT is used only sparingly 

for electricity, primarily during peak demand hours. GasCC 

with recirculating cooling is the primary thermal technology 

experiencing capacity growth when nuclear and coal-based 

capacity, much of which uses once-through cooling, retires.
7 

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0

200

400

600

800

1,000

1,200

1,400

1,600

2010 2020 2030 2040 2050

Capacity (GW)

Storage

Solar

Wind

Hydro

GasCT

GasCC-D

GasCC-R

GasCC-O/P

Coal-R

Coal-O/P

Other

Nuclear-R

Nuclear-O/P

Figure 5: Most capacity growth is combined-cycle natural 

gas with recirculating cooling and natural gas combustion 

turbines4

. 

To compare capacity expansion across scenarios, Figure 6

shows the capacity mix in 2010 and in 2030 and 2050 for all 

scenarios. For a given year, differences across scenarios are 

negligible. At a national level, water rights are abundant 

enough for the central prediction of surface water availability 

to have a minimal impact on overall electric sector 

development in the contiguous United States.

0

200

400

600

800

1,000

1,200

1,400

1,600

All Base CC CC-LW Base CC CC-LW

2050 Capacity (GW)

Storage

Solar

Wind

Hydro

GasCT

GasCC-D

GasCC-R

GasCC-O/P

Coal-R

Coal-O/P

Other

Nuclear-R

Nuclear-O/P

2010 2030 2050

Figure 6: Nationally, capacity expansion is very similar 

across scenarios.

GasCC is the only thermal power technology built at a 

large scale, so regional impacts on electric sector development 

are made evident by mapping GasCC capacity across ReEDS 

balancing areas. Figure 7 maps the net 2010–2050 growth in

GasCC capacity for each balancing area in the baseline 

scenario. Thermal capacity growth is concentrated in the 

eastern half of the country. Given limited baseline thermal 

power growth in water-stressed regions, the regional 

distribution of net GasCC growth is nearly identical for climate 

 4 In applicable figure legends, cooling technologies are denoted by: O = 

once-through, P = cooling pond, R = recirculating, and D = dry. 

change scenarios. For a given balancing region, GasCC 

capacity in 2050 differs across scenarios by less than 1 GW, 

which is generally small compared to total generating capacity 

in a region. Though expected water availability falls in climate 

change scenarios, there remains sufficient water rights at low 

enough cost such that even water-stressed regions experience 

little change in capacity expansion. New GasCC capacity 

might resort to wastewater under modeled climate change 

scenarios, but the costs of these alternative water resources are

still very small compared to total capital costs; hence, they are 

not large enough to drive major changes in capacity expansion 

decisions.

> 20

10 - 20

5 - 10

1 - 5

0.1 - 1

0 - 0.1

GasCC 

Growth

(GW)

0

< 0

Figure 7: Growth in thermal capacity (GasCC) is 

concentrated in high-demand, high-water regions in the 

eastern United States, and the regional distribution is 

almost identical across scenarios.

Water Withdrawal and Consumption Patterns

Physical water withdrawal and consumption is calculated 

from electrical output of thermal power plant types. Figure 8

plots water withdrawals over time throughout the contiguous 

United States for the baseline scenario. Once-through cooled 

coal-based and nuclear capacity account for most withdrawals. 

As these plant types are retired and replaced primarily by 

GasCC with recirculating cooling, withdrawals fall 

considerably because the replacement technology (primarily 

driven by cooling system choice) has withdrawal rates two 

orders of magnitude smaller. The general electricity market 

trend toward less withdrawal-intensive technology reduces the 

overall influence of climate change modifications to expected 

water rights availability, so national withdrawals over time are 

almost identical for the CC and CC-LW scenarios.

Baseline scenario
8 

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0

10

20

30

40

50

2010 2020 2030 2040 2050

Water Withdrawals 

(Tgal/yr)

GasCC-R

GasCC-O/P

Coal-R

Coal-O/P

Other

Nuclear-R

Nuclear-O/P

Figure 8: Water withdrawals fall over time as retired oncethrough cooled systems are replaced by GasCC with 

recirculating cooling.

National water consumption over time for the baseline 

scenario is shown in Figure 9. Consumption rates are higher 

with recirculating cooling than with once-through or pond 

cooling, so water is consumed primarily by coal-based, nuclear, 

and GasCC capacity with recirculating cooling. Overall 

consumption is relatively stable over time because GasCC-R 

has a slightly lower water consumption rate than the oncethrough cooled nuclear and coal-fired capacity it replaces. 

Again, there are negligible differences in national consumption 

between the baseline and climate change scenarios.

0

200

400

600

800

1,000

1,200

1,400

1,600

2010 2020 2030 2040 2050

Water Consumption 

(Bgal/yr)

GasCC-R

GasCC-O/P

Coal-R

Coal-O/P

Other

Nuclear-R

Nuclear-O/P

Figure 9: Water consumption remains relatively steady as 

GasCC with recirculating cooling replaces consumption 

needs of retired capacity.

Regional differences in water withdrawals are evident in 

Figure 10, which maps 2050 water withdrawals for each 

ReEDS balancing area in the baseline scenario. Most water 

withdrawals are attributed to existing but unretired nuclear and 

coal-fired capacity in the eastern half of the country, where 

water resources are more prevalent. Low water withdrawals 

correlate with regions of water scarcity, but many of these 

regions also have relatively low electricity demand. Reflecting 

the minimal changes in regional capacity growth, regional 

water withdrawals do not vary significantly between the 

baseline and climate change scenarios.

Regional water consumption is also similar across 

scenarios. Though increased consumption owing to the shift 

from once-through cooling systems to GasCC with 

recirculating cooling could create physical water supply 

problems in high-risk regions, physical water constraints are 

not available in the model. Scenarios are differentiated by the 

availability of water rights at the time of capacity investment, 

and demands for water rights are based on withdrawal rates.

> 200

100 - 200

50 - 100

20 - 50

10 - 20

5 - 10

Withdrawals 

in 2050

(billion gal)

5

Figure 10: 2050 water withdrawals are greater in regions 

with more abundant water resources and high demand, and 

the regional distribution is almost identical across 

scenarios.

CONCLUSIONS

We have integrated projected changes in water resource 

availability resulting from climate change into the ReEDS 

capacity expansion model. This was accomplished through 

adjusting available water rights based on average regional 

climate impacts on surface water. This new capability allows 

the ReEDS model to assess changes in electric sector planning 

from expected climate impacts on cooling water supplies.

The central prediction of surface water resources from 

CMIP3 climate modeling data applied to available surface 

water rights has a negligible impact on aggregate national 

electric sector growth and operation. This result is not 

surprising as systems are generally stressed during extreme 

climatic events, not the average. In addition, assumptions 

made to simplify this preliminary analysis tend to 

underestimate changes in water availability, particularly in the 

western states. Capacity growth and water withdrawals and 

consumption change negligibly with average climate change 

projections, even if appropriated surface water and shallow 

groundwater resources are unavailable. Abundant 

unappropriated surface water rights overshadow the 

comparably small changes in surface water resources. In 

regions where unappropriated water is scarce or unavailable, 

water rights retired from coal- and nuclear-based capacity 

utilizing once-through cooling technologies are often sufficient 

Baseline scenario
9 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

to meet the demand for new water rights from combined cycle 

natural gas with recirculating cooling.

Expected climate change and water availability restrictions 

also have little effect on regional electric sector growth and 

water use patterns. Average climate impacts are notable only 

for select southwestern states (CA, NV, AZ, NM, and TX) with 

limited to no unappropriated water. Without unappropriated 

water, retired rights are an attractive source of cooling water 

rights for new capacity, and wastewater and brackish 

groundwater are utilized if necessary. Results indicate that the 

model generally chooses more expensive water rights over 

building less water-intensive power or cooling technologies 

(e.g. dry cooling) or building elsewhere and incurring 

transmission costs. Though wastewater and brackish 

groundwater are far more expensive than traditional cooling 

water sources, these costs are minimal relative to the total cost 

of new generating capacity.

Reliance on retired rights in water-stressed regions 

emphasizes the importance of assuming such rights would be 

immediately available to new power plants. If not, the 

southwest United States could be substantially more dependent 

on wastewater or brackish groundwater resources in the future. 

The scenarios examined in this analysis demonstrate 

relatively minor impacts to electric sector growth and water use 

when considering only a mean water availability projection that 

does not reflect annual variability. The analysis herein 

represents an important stepping stone to more rigorous 

integration of climate impacts on thermal cooling water 

availability in the ReEDS model. This would enable 

consideration of more extreme water restrictions, for example 

drought conditions with climate change, in future analysis.

FUTURE WORK

Future analysis could take several directions. Under the 

existing water rights framework model, additional scenario 

analysis could examine more extreme climate scenarios with 

larger changes to regional water availability. An evolution 

from the water rights formulation would add physical water 

availability constraints where power output within a region is 

constrained by the quantity of water available in that region in 

the time period being considered. Physical constraints would 

allow inclusion of seasonal water availability variations. At the 

same time, future work would benefit from representing spatial 

variation in the legal water right regimes across the country, as 

this has important implications for how changes in physical 

water availability affect current and potential water users. To 

enable such analysis, methodology must be developed to 

translate CMIP data into physical quantities of water available 

to the power sector. A combination of rights-based and 

physical water availability constraints could then be examined 

for a wide range of potential future climate and electricity 

market scenarios.

ACKNOWLEDGMENTS

This work was supported by the U.S. Department of 

Energy under Contract No. DE-AC36-08GO28308 with the 

National Renewable Energy Laboratory. The authors 

acknowledge the support of the Joint Institute for Strategic 

Energy Analysis, which is operated by the Alliance for 

Sustainable Energy, LLC, on behalf of the U.S. Department of 

Energy's National Renewable Energy Laboratory, the 

University of Colorado-Boulder, the Colorado School of 

Mines, the Colorado State University, the Massachusetts 

Institute of Technology, and Stanford University.

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