A national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

National Renewable Energy Laboratory 

Innovation for Our Energy Future 

Modeling the Benefits of Storage 

Technologies to Wind Power 

Patrick Sullivan, Walter Short, and Nate Blair 

Presented at the American Wind Energy Association (AWEA) 

WindPower 2008 Conference 

Houston, Texas 

June 1–4, 2008 

Conference Paper 

NREL/CP-670-43510 

June 2008 

NREL is operated by Midwest Research Institute ● Battelle Contract No. DE-AC36-99-GO10337 
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Modeling the Benefits of Storage Technologies to Wind Power

 Patrick Sullivan, Walter Short, Nate Blair 

National Renewable Energy Laboratory 1 

1617 Cole Boulevard 

Golden, CO 80401 

patrick_sullivan@nrel.gov 

June, 2008 

1 Introduction 

Rapid expansion of wind power in the electricity sector is raising questions about how 

wind resource variability might affect the capacity value of wind farms at high levels of 

penetration. Electricity storage, with the capability to shift wind energy from periods of low 

demand to peak times and to smooth fluctuations in output, may have a role in bolstering the 

value of wind power at levels of penetration envisioned by a new Department of Energy report, 

“20% Wind by 2030, Increasing Wind Energy’s Contribution to U.S. Electricity Supply”2

released in May, 2008. 

Utilities are still experimenting to determine the capacity value—the amount of 

conventional capacity a given amount of wind capacity can replace—of the wind farms they are 

building today. No matter how accurate forecasting of wind patterns becomes, the nature of the 

resource does not allow operators to dispatch wind power to meet load as they can with a 

conventional plant. Storage technologies provide synergies with wind power either by shifting 

electricity from periods of low demand to those of higher demand, or by damping out 

fluctuations in output. This process helps reduce stresses on other plants that would otherwise 

have to ramp up and down to compensate for the variations from the wind farms. The more 

wind installed in a system, the more valuable storage becomes—at higher penetrations, wind 

variations are larger and there is less balance-of-system to compensate. 

This paper quantifies the value storage can add to wind. The analysis was done 

employing the Regional Energy Deployment System (ReEDS) model, formerly known as the 

Wind Deployment System (WinDS) model (http://www.nrel.gov/analysis/winds/). ReEDS, 

developed at the National Renewable Energy Laboratory (NREL), was used to estimate the cost 

and development path associated with 20% penetration of wind in the “20% Wind by 2030” 

report. ReEDS differs from the WinDS model primarily in that the model has been modified to 

include the capability to build and use three storage technologies: pumped-hydroelectric storage 

(PHS), compressed-air energy storage (CAES), and batteries 

To assess the value of these storage technologies, two pairs of scenarios were run: 

• business-as-usual, with and without storage 

• 20% wind energy by 2030, with and without storage 

This paper presents the results from those model runs. 

 

1

NREL is a national laboratory of the U.S. Department of Energy, Office of Energy Efficiency and Renewable 

Energy, operated by Midwest Research Institute and Battelle 

2

DOE EERE “20 % Wind by 2030, Increasing Wind Energy’s Contribution to U.S. Electricity Supply”, DOE/GO102008-2567, May 2008.

1 
2 ReEDS Overview 

The ReEDS model began in 20033

 to examine the expansion of generation and 

transmission capacity in the U.S. electric sector. ReEDS is a linear programming model that 

minimizes system-wide costs of meeting loads, reserve requirements, and emission constraints 

by building and operating power generators and transmission capacity in each of 23 two-year 

periods spanning 2006-2050. Although ReEDS considers all major generator types, it was 

designed primarily to address the principal market issues related to the penetration of wind 

energy into the electric sector over the next several decades — specifically, wind resource 

variability and transmission requirements. 

ReEDS is better able to model transmission and wind resource variability, primarily by 

using a much higher level of geographic disaggregation than other models—358 distinct regions 

in the continental United States, illustrated in Figure 1. Many of the data inputs to ReEDS are 

tied to these regions and derived from a detailed geographic information system (GIS) 

model/database of the wind resource, transmission grid, and existing plant data. The geographic 

disaggregation of wind resource allows ReEDS to calculate transmission distances (and charge 

appropriately) as well as account for regional differences in wind resource. 

Figure 1. ReEDS regions 

ReEDS considers the availability of capacity on existing transmission lines, the cost of 

accessing and using those lines, and the cost of building new transmission lines dedicated to 

wind generation when existing lines are not available. These costs are made to reflect current 

electricity transmission pricing as realistically as possible. 

 

3

Short, Walter; et al., May 2003, “Modeling the Long-Term Penetration of Wind in the United States,” WindPower 

2003 Proceedings, Austin, Texas 

2 
ReEDS disaggregates the wind resource into five classes ranging from Class 3 (5.4 

meters/second at 10 meters above ground) to Class 7 (>7.0 m/s) for the lower 48 states (see 

Figure 2). Each class and each region has a unique diurnal generation profile so in those parts of 

the country where the wind generally blows more strongly at night than during the day, for 

instance, the model reflects that and takes it into account when stochastically determining the 

capacity value. The stochastic calculations also include wind already supplying the grid and 

apply statistical measures to account for the fact that wind farms that are closer together are more 

likely to have their output profiles correlated than wind farms that are widely separated. The 

more correlated the outputs, the lower the capacity value. 

Figure 2. Wind resources in ReEDS 

Each class of wind has different cost and performance characteristics. Often, higher 

wind-class sites are more desirable, though additional expenses for transmission, terrain, and 

population considerations can make, for example, an otherwise high-quality, but remote, Class-7 

resource much more expensive than a more conveniently located Class-5 site. The result is that a 

mix of classes is built in a given year—a mix that changes over time—depending on which class 

is the cheapest in that particular region at that time. 

ReEDS is also disaggregated over time, not only with the two-year periods, but also 

within each year. ReEDS has 16 time-slices: four seasons, each with four daily slices (except 

spring, which has three); and one super-peak slice to account for the few highest-demand hours 

in the summer. These 16 time-slices allow ReEDS to capture the intricacies of meeting peak 

electric loads with both conventional sources and intermittent wind generators. 

3 
ReEDS models the major conventional electricity generators, including: 

• pulverized coal: traditional and next generation 

• integrated gasification combined-cycle coal (IGCC) 

• natural gas combined cycle 

• natural gas combustion turbines 

• nuclear 

• hydroelectricity: existing only, and energy limited by water-use requirements 

Fuel costs are specified exogenously by time and by North American Electric Reliability 

Corporation (NERC) region, as are the electric loads. In addition, ReEDS has the capability to 

consider a renewable portfolio standard (RPS) —a requirement that a certain percentage or 

quantity of capacity or generation be derived from renewables—at state and national levels; meet 

emission caps for SO2, NOx, mercury, and CO2; impose a carbon tax; and adjust options for 

financing of capital expenditures and tax credits for investment or production. 

3 Storage in ReEDS 

Storage can provide benefit to the system in three ways, each loosely associated with a 

timescale. On super-hourly timescales, storage can provide load-shifting and arbitrage usually 

by charging overnight and discharging during peak afternoon or evening hours. Load-shifting is 

by no means of exclusive utility to wind power: a fully conventional system can benefit from the 

practice by running cheaper plants at a slightly higher level overnight to bank energy and then 

call on that storage during the day instead of dispatching an expensive peaking plant. On the 

other hand, because wind tends to blow harder at night in many parts of the country, the benefit 

can be even greater for wind-heavy systems. 

 On shorter timescales, storage can be used to smooth variations in wind farm output, 

reducing the need for conventional spinning reserve to be ready to either take up slack or back 

off to adjust to changes in wind. A wind-heavy system without storage would need substantial 

amounts of responsive capacity to be able to rapidly ramp up or down; this means that such 

capacity must be both built and operated, at substantial cost to the system. A quick-ramping 

storage technology with enough stored energy for a few hours of output might be a better option 

than a gas turbine in certain circumstances. 

Quick-acting storage can also add value by providing voltage and frequency regulation 

and other similar ancillary services. 

As implemented in ReEDS, storage can provide some of these benefits explicitly and 

others implicitly. Storage can charge or discharge in any of 16 time slices, directly allowing for 

load shifting between periods of low demand and high demand. Additionally, any capacity 

unused for either charging or discharging in a given period is available as operating reserve, 

allowing storage to address wind smoothing and ancillary services. Of course, storage also 

counts toward available capacity as well, for meeting peak load and reserve margin 

requirements. 

4 
In ReEDS, three types of storage are permitted: pumped hydro storage (PHS), 

compressed air energy storage (CAES), and batteries. The battery chemistry assumed in the 

model—chosen on the basis of the current robustness of the technology and well-established and 

competitive costs—is sodium-sulfur. Cost/performance parameters for the storage technologies 

are listed in Table 1. Costs for each technology are for systems with eight hours of storage. 

Table 1. Storage Technology Cost and Performance Data ($ 2004) 

 Capital Cost Fixed O&M 

Variable 

O&M 

Round Trip 

Efficiency Heat Rate 

 1000$/MW $/MW-year $/Mwh Mbtu/MWh 

PHS 2010 1500 12720 5.0 0.80 

 2020 1500 12720 5.0 0.80 

 2030 1500 12720 5.0 0.80 

Battery4 2010 1964 51000 5.0 0.77 

 2020 1810 47002 5.0 0.78 

 2030 1668 43317 5.0 0.80 

CAES5 2010 840 10310 3.1 1.38 4.40 

 2020 820 10105 3.1 1.40 4.30 

 2030 820 10105 3.1 1.40 4.30 

CAES is not a pure storage technology; for the storage portion, cheap electricity is used 

to charge the reservoir, in this case by pumping high-pressure air into an underground cavern 

(e.g., a salt dome). Upon discharging, however, the compressed air is mixed with natural gas and 

combusted before expanding it through a turbine to generate power. In effect, CAES is a hybrid 

technology that uses electrical-to-physical storage to enable a highly efficient combustion 

turbine; the heat rate of a CAES plant is roughly half that of a traditional natural gas plant. 

Because there are two inputs (electricity and natural gas), it is difficult to create a single 

performance metric, so the table above includes both round-trip efficiency and heat rate. For 

every 0.72 MWh of electricity and 4.4 Mbtu of gas, the plant will provide 1 MWh of electricity. 

ReEDS can choose to build storage either co-located with wind farms or sited at the load. 

In either case, the storage can be charged in ReEDS by either wind generated electricity or 

generation from the general grid (see Figure 3). The primary advantage of co-locating with wind 

is the potential to save money by downsizing a long transmission line. (With a 100 MW wind 

farm, a 20 MW battery allows the developer to build a transmission line of only 80 MW without 

risking losing energy generated by the top 20 MW.) There is a trade-off in that the maximum 

capacity the combined wind-storage system can generate is then limited by the transmission line. 

Storage at the load does not allow downsized transmission, but the storage will always be able to 

discharge at full power. Storage at load also assists the movement of wind power to load centers 

by charging overnight when transmission lines are relatively free, rather than trying to move the 

power during peak hours when the lines are congested. Storage at the load also allows slightly 

more wind energy to be stored for the same storage capacity since transmission losses are 

incurred before the load-sited storage. Similarly, storage at the load site charged from the 

general grid does not incur transmission losses to and from a remote wind-sited storage facility. 

 

4

 Electric Power Research Institute (EPRI)/Department of Energy (DOE). “EPRI-DOE Handbook of Energy Storage 

for Transmission and Distribution Applications.” 2003. 

5

 Holst, Kent. “Iowa Stored Energy Plant: Status Report,” California Energy Commission. February 2005. 

5 
Figure 3. Storage-wind-grid interconnections 

There are 21 GW of utility-scale electric storage currently in use in the United States, the 

vast bulk of which is PHS. A single 110 MW CAES plant operates in McIntosh, Alabama. For 

further expansion, the model restricts PHS to load-located only, assuming that the odds of 

finding appropriate hydrological features at many attractive wind sites are slim. Because much 

of the country has geological features appropriate to CAES caverns (e.g., aquifers, domal salt, or 

bedded salt), wind-located CAES is permitted. However, CAES of either type is restricted in 

regions without appropriate geology (Figure 4 shows where suitable geology exists). Batteries 

can be installed anywhere. 

Figure 4. Potential CAES locations6

 

6

 Succar, S. and R. Williams. “Compressed Air Energy Storage: Theory, Operation, and Applications.” March 2008. 

6 
4 Business-As-Usual Scenarios 

The business-as-usual scenario for this comparison trial uses values from the Reference 

Case of the Annual Energy Outlook (AEO) 20067 for input data for fuel prices and load 

forecasts. Wind data inputs and costs for conventional technologies are from Black & Veatch8

and match those used in the “20% Wind by 2030” report. Tables 2 and 3 contain the technology 

cost and performance data used in this analysis. Other inputs are set according to current 

conditions: no national renewable portfolio standard (RPS), but state standards are enforced if 

currently enacted; the SO2 cap follows current regulations; no carbon cap or tax is applied. 

Table 2. Onshore Wind Cost and Performance Data (2004 $) 

Class Year Capital Cost Fixed O&M Variable O&M Capacity Factor 

k$/MW $/MW-year $/MWh 

3 2010 1570 10946 5.19 0.35 

2020 1490 10946 4.41 0.38 

2030 1413 10946 4.16 0.38 

4 2010 1570 10946 5.19 0.39 

2020 1490 10946 4.41 0.42 

2030 1413 10946 4.16 0.43 

5 2010 1570 10946 5.19 0.43 

2020 1490 10946 4.41 0.45 

2030 1413 10946 4.16 0.46 

6 2010 1570 10946 5.19 0.46 

2020 1490 10946 4.41 0.48 

2030 1413 10946 4.16 0.49 

7 2010 1570 10946 5.19 0.50 

2020 1490 10946 4.41 0.52 

2030 1413 10946 4.16 0.53 

Table 3. Selected Conventional Cost and Performance Data (2004 $) 

Technology Year Capital Cost Fixed O&M Variable O&M Heat Rate 

k$/MW $/MW-year $/MWh 

Natural Gas 2010 714 6281 2.67 8.90 

Combustion Turbine 2020 714 6281 2.67 8.90 

2030 714 6281 2.67 8.90 

Natural Gas 2010 742 13706 2.86 6.87 

Combined Cycle 2020 742 13706 2.86 6.87 

2030 742 13706 2.86 6.87 

New 2010 2075 33600 1.62 9.47 

Pulverized Coal 2020 2132 33600 1.62 9.47 

2030 2132 33600 1.62 9.47 

Coal IGCC 2010 2703 36264 3.71 8.58 

2020 2703 36264 3.71 8.58 

2030 2703 36264 3.71 8.58 

Nuclear 2010 3016 85663 0.48 10.4 

2020 2874 85663 0.48 10.4 

2030 2801 85663 0.48 10.4 

 

7

 U.S. Department of Energy, Energy Information Administration. Annual Energy Outlook 2006 with Projections to 

2030. DOE/EIA-0383, February 2006. 8

 Personal communication with Ric O’Connell, Black & Veatch. January, 2007. 

7 
Figure 5. Cumulative installed capacity, business-as-usual with-storage case 

0

200

400

600

800

1000

1200

1400

1600

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2000

2006

2008 2010 2012 2014 2016 2018 2020

2022

2024 2026 2028 2030 2032

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2040

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2048 2050

Cumulative Installed Capacity (GW)

Storage

Wind

Geothermal

Hydro

Nuclear

Gas-CC

Gas-CT

Oil-gas-steam

Coal-IGCC

Coal-new

Coal-w/scrub

Coal-no scrub

Figure 5 shows the cumulative installed capacity for the business-as-usual case with 

storage. The two business-as-usual cases are identical except that the model has the option of 

building and using storage only in the second. (The first does not even have access to the 

existing 21 GW, a decision that was made because the goal of the study was to examine the 

value of storage in general rather than the value of additional storage.) Therefore, comparisons 

between the two can rely on having similar economics driving the decisions. The most 

substantial difference in the results is that an additional 50 GW of wind power are installed in the 

storage case (Figure 6). Figure 7 shows the delta between the two cases for both storage 

additions and wind. Until about 2042, storage and wind both grow; while after 2042 storage 

grows in support of nuclear, not wind. 

0

100

200

300

400

2006

2010

2014

2018

2022

2026

2030

2034

2038

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2046

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Capacity (GW)

Storage Case

Base Case

Figure 6. Cumulative wind capacity comparison, business-as-usual cases 

8 
-20

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2006

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Capacity (GW)

Storage Capacity

Additional Wind Capacity

Figure 7. Effect of storage on wind capacity, business-as-usual cases 

The storage and additional wind in the storage case contribute to energy and capacity 

requirements and reduce the need for conventional plants. Figure 8 shows comparisons of 

capacity and generation between the two scenarios. Coal, gas, and nuclear capacity are all lower 

in 2050 in the storage case (“coal-old” is coal capacity that already exists in 2006, so its capacity 

is essentially the same in both cases), having been replaced by wind and storage. Energy-wise, 

coal, gas, and nuclear generation are again all down, though “coal-old” has a net increase. It 

makes sense for an existing cheap base-load technology to increase generation when storage is 

available because excess overnight generation can now be stored and dispatched during the day 

to replace electricity from expensive gas plants. 

9 
Figure 8. 2050 capacity and generation comparison, business-as-usual cases 

It should be noted that all storage built in all four scenarios (except for the existing PHS) 

is CAES and is located with the load. Regarding the former, CAES plants have substantially 

lower capital and operating costs than either PHS or batteries, and the fuel costs are relatively 

low. CAES is widely considered to be the cheapest of the utility-scale storage options today, and 

these results support that. It is certainly possible that battery technology could improve enough 

before 2050 to become competitive with CAES; however, with the projections used in this study, 

that did not occur. A less-expensive battery option probably would not substantially change the 

results, and what changes there were would serve to reinforce the benefits of storage. As for the 

lack of wind-located storage; the capacity, transmission loss, and congestion penalties evidently 

outweighed the cost savings of downsizing transmission lines. 

 5 20% Wind by 2030 Scenarios 

In the 20% wind by 2030 scenarios, the model is required to ramp up to generating 20% 

of annual energy from wind by 2030 and to maintain that level thereafter. Both cases (with and 

without storage), therefore, build similar amounts of wind (for this analysis, non-wind 

renewables, such as solar, biopower, and geothermal, were not included). Figure 9 shows 

cumulative capacity for the with-storage case. 

One metric that can be used to compare the scenarios is the price of electricity, which is 

lower in the storage case by more than $2/MWh by 2050, the delta having increased steadily 

since the mid-2020s (see Figure 10). The price difference can be partially attributed to a 

0

50

100

150

200

250

300

350

400

Hydro

Gas-CT

Gas-CC

Coal-Old

Coal-New

Nuclear

Wind

Storage

Capacity (GW)

0

500

1000

1500

2000

2500

3000

Hydro

Gas-CT

Gas-CC

Coal-Old

Coal-New

Nuclear

Wind

Storage

Generation (TWhr)

Storage Case

No-Storage Case

10 
reduction in the amount of conventional capacity built (more combustion turbines are necessary 

in the no-storage case to back up the wind), and in the amount of generation from those plants. 

The other factor is that, with the ability to store off-peak wind, some wind farms that may have 

been cheap yet undeveloped without storage—perhaps due to an unfavorable diurnal profile or 

high wind variance—may become highly desirable when storage is available. Those sites can 

then be built out economically, replacing other more expensive sites. 

0

200

400

600

800

1000

1200

1400

1600

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2000

2006 2008 2010 2012 2014

2016

2018

2020 2022 2024

2026

2028 2030 2032 2034

2036

2038 2040 2042 2044

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2048 2050

Cumulative Installed Capacity (GW)

Storage

Wind

Geothermal

Hydro

Nuclear

Gas-CC

Gas-CT

Oil-gas-steam

Coal-IGCC

Coal-new

Coal-w/scrub

Coal-no scrub

Figure 9. Cumulative installed capacity, 20% wind by 2030 with storage case 

82

84

86

88

90

92

94

96

2006

2010

2014

2018

2022

2026

2030

2034

2038

2042

2046

2050

$/MWh

RPS With Storage

RPS No-Storage

Figure 10. Electricity price comparison, 20% wind by 2030 case 

11 
Figure 11 contains a pair of graphs showing the build-out of storage capacity and changes 

in generation from storage in the 20% wind case. The charts begin in 2006 with the 21 GW of 

existing capacity and 26 TWh of storage—a number that closely matches actual output from 

storage in 2006. Generation decreases after 2006 as the generating mix includes more natural 

gas. Gas is a more flexible technology than coal and neither requires backup nor benefits much 

from load shifting, so storage becomes less desirable in those years. As wind is built and natural 

gas becomes more expensive, however, generation from storage recovers and then surpasses the 

2006 value. By 2024, storage has become sufficiently valuable that building additional storage 

capacity becomes viable. From then on, storage grows rapidly—in both capacity and generation. 

Installed Storage Capacity

0

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40

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140

2006

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GW

Storage Generation -- at Outlet

0

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TWh

Figure 11. Storage build-out, 20% wind by 2030 with-storage case 

More storage capacity is built in the 20% case than in the business-as-usual case: 120 

GW by 2050, compared to 97 GW. Furthermore, just as more wind capacity is built earlier in 

the 20% case, there are 70 GW of storage installed by 2038 in the 20% case, while only 28 GW 

are installed by that time in the business-as-usual case (see Figure 12). That more wind leads to 

more storage is further indication that storage is providing tangible benefit to wind specifically, 

not just to the grid as a whole. Nevertheless, it is also the case that even in this aggressive 

scenario, the model did not build new storage until 2024, when there were already 200 GW of 

wind capacity on the grid supplying 15% of the nation’s energy. 

12 
0

50

100

150

200

250

300

350

400

450

2006 2010 2014 2018 2022 2026 2030 2034 2038 2042 2046 2050

Installed Capacity (GW)

20% Case -- Wind

Base Case -- Wind

20% Case -- Storage

Base Case -- Storage

Figure 12. Storage and wind growth comparison 

6 Diurnal Behavior of Storage in ReEDS 

The charging and discharging cycles of storage units are of tangential interest to this 

study. While they may not directly demonstrate benefits of storage to wind, they do show how 

storage interacts with the system and add legitimacy to the study’s conclusions, showing 

predictable and explainable behavior. 

Figure 13 is a chart of power output—national total in 2030, in the 20% wind case—of 

each major generator type by time-slice. As expected, base-load technologies such as nuclear 

and coal change little from hour-to-hour or day-to-day. Natural gas plants are used to meet 

higher daytime loads, with single-cycle plants coming online only after the combined-cycle 

plants are already dispatched. Storage charges during overnight hours, when coal is on the 

margin, and discharges during the peak period each day, replacing gas generation. 

13 
Figure 13. Generation by time slice (2030) 

Figure 14 is similar, but contains only storage; and the width of each time-slice is 

proportional to the number of annual hours in that time-slice (e.g. winter occupies four months to 

fall’s two). In this chart, it is apparent that stored energy may not be transferred from one season 

to another: for each season, energy-in matches the energy-out once round-trip efficiency is 

considered. Also, the diurnal trend of charging overnight and discharging during the day is 

evident. 

-30

-20

-10

0

10

20

30

40

summer fall winter spring

GW

storage out

storage in

Figure 14. Hourly storage profile (2030) 

14 
15 

7 Summary and Conclusions 

Several types of storage, including CAES, PHS, and batteries, have been added to the 

ReEDS model. Under several scenarios, results from this new capability have proved to be 

realistic and explainable. The new capability was used for this analysis but will now become a 

standard component of the larger ReEDS model. The results presented here demonstrate that at 

high levels of penetration storage can lead to more wind power installations. Within the 

constraints of the ReEDS model and with the assumptions outlined above, this analysis showed 

that CAES plants can be economically competitive with conventional technologies in the future 

and that the ability to store electricity adds value to the system as a whole and to wind power in 

particular. 

In the business-as-usual cases, the capability to build and use storage allowed an increase 

in 2050 wind capacity from 302 GW in the no-storage case to 351 GW in the storage case. The 

scenarios were otherwise identical, so the additional capacity, which was not economically 

competitive with conventional sources in the no-storage case, must have become competitive in 

the storage case. Comparisons also show that the additional wind and storage have replaced both 

capacity and generation from conventional sources. 

In the 20% wind by 2030 cases, the results show that with a fixed amount of wind 

generation, storage can lower electricity prices, a good proxy for the cost of the overall system. 

For both the business-as-usual cases and the 20% wind cases, results indicate that the value of 

storage to wind increases along with amount of wind in the system. However, storage does not 

become sufficiently valuable to warrant the investment until there is significant wind capacity 

already on the grid. 

Analysis of the charge-discharge behavior of storage with the seasonal and diurnal 

behavior of the system as a whole indicates that storage is behaving in ways that are consistent 

and explainable, lending credence to the other results. 
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Modeling the Benefits of Storage Technologies to Wind Power 

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7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

National Renewable Energy Laboratory 

1617 Cole Blvd. 

Golden, CO 80401-3393 

8. PERFORMING ORGANIZATION

REPORT NUMBER

NREL/CP-670-43510 

9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES) 10. SPONSOR/MONITOR'S ACRONYM(S)

NREL 

11. SPONSORING/MONITORING

AGENCY REPORT NUMBER

12. DISTRIBUTION AVAILABILITY STATEMENT

National Technical Information Service 

U.S. Department of Commerce 

5285 Port Royal Road 

Springfield, VA 22161 

13. SUPPLEMENTARY NOTES

14. ABSTRACT (Maximum 200 Words)

Rapid expansion of wind power in the electricity sector is raising questions about how wind resource variability might 

affect the capacity value of wind farms at high levels of penetration. Electricity storage, with the capability to shift 

wind energy from periods of low demand to peak times and to smooth fluctuations in output, may have a role in 

bolstering the value of wind power at levels of penetration envisioned by a new Department of Energy report (“20% 

Wind by 2030, Increasing Wind Energy’s Contribution to U.S. Electricity Supply”). This paper quantifies the value 

storage can add to wind. The analysis was done employing the Regional Energy Deployment System (ReEDS) 

model, formerly known as the Wind Deployment System (WinDS) model. ReEDS was used to estimate the cost and 

development path associated with 20% penetration of wind in the report. ReEDS differs from the WinDS model 

primarily in that the model has been modified to include the capability to build and use three storage technologies: 

pumped-hydroelectric storage (PHS), compressed-air energy storage (CAES), and batteries. To assess the value of 

these storage technologies, two pairs of scenarios were run: business-as-usual, with and without storage; 20% wind 

energy by 2030, with and without storage. This paper presents the results from those model runs. 

15. SUBJECT TERMS

NREL; wind energy; 20% by 2030; storage; Wind Deployment System model; WinDS; Regional Energy Deployment 

System model; ReEDS; pumped-hydroelectric storage; compressed-air energy storage; Nate Blair; Walter Short; 

Patrick Sullivan 

16. SECURITY CLASSIFICATION OF: 17. LIMITATION 

OF ABSTRACT

UL 

18. NUMBER 

OF PAGES 

19a. NAME OF RESPONSIBLE PERSON 

a. REPORT 

Unclassified 

b. ABSTRACT 

Unclassified

c. THIS PAGE 

Unclassified 19b. TELEPHONE NUMBER (Include area code)

Standard Form 298 (Rev. 8/98) 

Prescribed by ANSI Std. Z39.18