National Renewable Energy Laboratory 

Innovation for Our Energy Future 

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

Office of Energy Efficiency & Renewable Energy

NREL is operated by Midwest Research Institute ● Battelle Contract No. DE-AC36-99-GO10337 

Wind Energy and Production of 

Hydrogen and Electricity — 

Opportunities for Renewable 

Hydrogen 

Preprint 

J. Levene, B. Kroposki, and G. Sverdrup 

To be presented at the 2006 POWER-GEN Renewable Energy 

and Fuels Technical Conference 

Las Vegas, Nevada 

April 10-12, 2006 

Conference Paper 

NREL/CP-560-39534 

March 2006 
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1

Executive Summary 

Hydrogen can be produced from a variety of domestic, renewable sources of energy. An 

assessment of options for wind/hydrogen/electricity systems at both central and distributed scales 

provides insight into opportunities for renewable hydrogen as well as research priorities for this 

hydrogen production pathway. 

The analysis of the central production of hydrogen from wind was conducted. This technology 

involves hydrogen production at the wind site with hydrogen delivered to the point of use. The 

results of this study are that hydrogen can be produced at the wind site for prices ranging from 

$5.55/kg in the near term to $2.27/kg in the long term. A research opportunity in this scenario is 

the elimination of redundant controls and power electronics in a combined turbine/electrolysis 

system. 

A second analysis was completed in which wind power was used in a distributed fashion for 

hydrogen production. The wind farm provides a signal to a remotely located electrolyzer, which 

allows the electrolyzer to run only when the wind is blowing. An advantage of this scenario is 

that signals from many different wind farms could be used, which would increase the capacity 

factor and thus decrease the cost of the hydrogen production system. The results of this second 

study are that hydrogen can be produced at the point of use for prices ranging from $4.03/kg in 

the near term to $2.33/kg in the long term. This novel approach results in low production costs 

and could minimize delivery costs if the electrolyzer was located at the filling station. 

Both analyses reveal that in order to optimize the production of hydrogen from wind, the 

electricity and hydrogen production needs to be examined as an integrated system. Researchers 

at the U.S. Department of Energy’s National Renewable Energy Laboratory (NREL) are working 

to build renewable hydrogen from wind into a viable production method for transportation fuel in 

the future. 

Background and Purpose of the Study 

In early 2005, Xcel Energy approached NREL to conduct a study to determine if hydrogen could 

be economically produced via wind power for transportation fuel use. NREL had done such 

studies in the past, but the ability to partner with a utility and to use Xcel Energy’s expertise of 

the electricity sector provided a unique opportunity for analysis. Two cases were studied; one 

where hydrogen was produced at the wind site, and delivered to the point of use, and a second 

novel approach where hydrogen was produced at the point of use using wind energy transported 

through the electric grid from several wind farms. In both studies low temperature electrolysis 

units were used to convert the wind energy to hydrogen. 

Electrolysis is the production of hydrogen from water. An electric current is passed through an 

anode and a cathode in contact with water. The net reaction which occurs is: 

2H2O liquid + electricity → 2H2 + O2 
2

This reaction requires 39 kWh of electricity to produce 1 kilogram of hydrogen at 25 degrees C, 

and 1 atmosphere. When efficiencies of electrolysis systems are stated in this study they are 

calculated by dividing the energy used by the system into 39 kWh/kg. 

All hydrogen cost results in this report are shown in terms of dollars per kilogram ($/kg) of 

hydrogen. A kilogram of hydrogen is used as the base unit because a kilogram of hydrogen has 

roughly the same energy content as a gallon of gasoline. On a lower heating value basis, 

hydrogen contains approximately 116 MMBTU/kg, while gasoline contains 108 to 124 

MMBTU/gallon. Therefore, if used in engines with the same efficiency, a kilogram of hydrogen 

would allow a vehicle to travel the same distance as a gallon of gasoline. 

HOMER® Model 

For this study the HOMER® model (hereinafter “Model”) was used for the system optimization 

and hydrogen price calculation. The Model was developed at NREL to allow users to optimize 

electric systems and ease the evaluation of the many possible configurations that exist with such 

systems.1

 For example, when designing an electric system to meet a 30 kW load for an hour 

every day, the Model can answer questions such as: should the system have enough turbines so 

that hour always has 30 kW, or should battery storage be added, or a diesel engine, and which 

option costs less? The ability to model hydrogen was added to the Model in 2004, and further 

enhanced in 2005 for use in this study. 

One of the advantages of using the HOMER® model is its ability to conduct analysis on an 

hourly basis. For this study, system components, available energy resources, and loads are 

modeled hour by hour for a single year. Energy flows and costs are constant over a given hour. 

This type of model is ideal for showing intermittent renewable electricity producing hydrogen 

for fluctuating hydrogen demands. 

The Model requires inputs such as technology options, component costs, and resource 

availability. The Model uses these inputs to simulate different system configurations, and 

generates a list of feasible configurations sorted by net present cost (NPC). NPC can also be 

referred to as lifecycle cost and is the present cost of installing and operating the system over the 

lifetime of the project. Model results include a COE (cost of energy) or COH (cost of hydrogen) 

for each feasible configuration. 2

 The configuration with the lowest COE or COH is determined 

to be the most economic solution. 

The Model calculates the levelized COH with the following equation 

• Cann,tot is the total annualized cost [$/yr], 

• Mhydrogen is the annual hydrogen production [kg/yr] 

 

1

 HOMER® model, www.nrel.gov/homer/, National Renewable Energy Laboratory. 2

 Lambert, Tom. Levelized Cost of Energy, HOMER® help file. www.nrel.gov/homer/, National Renewable Energy 

Laboratory. October 27, 2004. 
• velec is the value of electricity [$/kWh] 

• The E values in parentheses are the total annual useful electrical production [kWh/yr] 

The Model calculates the annual electricity value by multiplying the value of the electricity 

produced by the annual electrical production. The final COH is calculated by dividing the 

difference of the total annualized cost and the annual electricity value by the annual hydrogen 

production, resulting in the $/kg of hydrogen produced during the year. If no electricity is 

produced by the system, the E terms in the parentheses will be zero, and the cost of hydrogen is 

simply the annualized cost divided by the annual hydrogen production. 

Cases 

For this study, two cases were considered. The first has been previously studied by NREL3 and 

considers the production of hydrogen at the wind farm. However, new assumptions were made 

and more specific data were used in this study as a result of the Xcel Energy/NREL partnership. 

This scenario is of interest to NREL and Xcel Energy because of the research and potential cost 

savings opportunities. For example, cost savings could be realized by combining power 

electronics of wind and electrolysis systems or by including storage of hydrogen in the wind 

turbine towers.4 Both activities are being investigated at NREL. 

In Case 1, two sites were considered. One site was near the University of Minnesota West 

Central Research and Outreach Center (WCROC) Site in Morris, MN. The WCROC site was 

chosen as the university is in the process of beginning wind hydrogen research and is partnering 

with NREL and Xcel Energy. This site has an average wind speed of 7.41 m/s. The second site 

was located in Gobbler’s Knob, near Lamar, Colorado. The Gobbler’s Knob site was chosen 

because there is currently a wind farm located there from which Xcel Energy buys wind energy. 

This site has an average wind speed of 8.50 m/s. A diagram of Case 1 is shown in Figure 1. 

Figure 1: Case 1 – Hydrogen Produced at a Wind Farm 

The second case studied was the production of hydrogen at the point of use using wind generated 

electricity from three large Colorado wind farms from which Xcel Energy buys wind energy: 

 

3 Production Case Studies. www.hydrogen.energy.gov/h2a_prod_studies.html and 

Levene, J. An Economic Analysis of Hydrogen Production from Wind. WINDPOWER 2005, American Wind 

Energy Association, 2005. 

4

 Kottenstette, R and Cotrell, J. Hydrogen Storage in Wind Turbine Towers: Cost Analysis and Conceptual Design. 

NREL/CP-500-34851. September 2003. Golden, CO: National Renewable Energy Laboratory; 10 pp. 

3
Lamar, Peetz Table, and Ponnequin. A diagram of Case 2 is shown in Figure 2. In Case 2 it was 

assumed that a signal could be sent from all three wind farms to remote electrolysis sites. This 

signal would indicate to the electrolyzer when wind energy was being produced by any of the 

three wind farms. If wind energy was being produced, the electrolyzer would be allowed to 

produce hydrogen, with certain constraints. If wind energy wasn’t being produced at any of the 

three wind sites, hydrogen wouldn’t be produced. If only a small amount of wind energy were 

produced, then only a small amount of hydrogen would be produced. This novel approach to 

analyzing a wind hydrogen system was only possible due to the partnership with Xcel Energy as 

detailed data were needed with regards to the wind energy production and electricity demand on 

their system. 

Figure 2: Case 2 – Aggregate Wind Producing Hydrogen at Point of Use 

For both Cases the costs of the system were analyzed in the near term, mid term, and long term. 

The costs and efficiencies of the equipment change over the timeframes, and are detailed in the 

assumptions sections. The timeframes used are defined as follows: 

• Near term = today until 2010 

• Mid term = 2010 – 2020 

• Long term = 2020 – 2030 or best scenario in the future 

Assumptions 

For this study, Xcel Energy and NREL worked closely to ensure that the values used in the study 

were consistent with Xcel Energy’s method of doing business. As a result, some key common 

assumptions were used for both cases. Detailed assumptions for both cases can be seen in 

Appendix A. 

4
Key Common Assumptions 

Parameter Assumption 

Peak 

electricity 

• Peak electricity usage is from 4-7 p.m. on weekdays, so no hydrogen 

can be produced during those three hours 

• There are no peak hours during the weekend, so electrolyzer can run 24 

hours a day. 

System 

pressure 

• Hydrogen is compressed after production to 6500 psi 

• Storage is provided at 6500 psi 

Wind 

turbine 

capital and 

operating 

costs 

• Turbine costs are not specifically used in analyses, rather the cost of 

wind generated electricity is used 

– Assumes this cost includes capital, replacement and operating 

costs of the wind turbines 

• Xcel Energy purchases wind generated electricity at a rate of 

$0.038/kWh 

Electrolyzer • Costs are assumed to be $740/kW, $400/kW, and $300/kW in near, 

mid, and long term 

• Uses AC power 

Compressor 

costs 

• $600,000, $300,000 and $100,000 for a 1500 kg compressor in near, 

mid, and long term 

Annual 

Real 

Interest 

Rate 

• Discount rate used to convert between one-time costs and annualized 

costs5

• Study uses 10% 

Hydrogen 

dispensing 

• No hydrogen dispensing costs included 

In addition to the common assumptions, each case has some unique aspects. The key 

assumptions for Case 1 are: 

Case 1 Key Assumptions 

• The model used a hydrogen load of 1000 kg/day, but allowed for 100% of that load to 

not be met. The result of this assumption in the model is that the amount of hydrogen 

produced is fluctuated until the minimum COH for the system is found. A minimum 

electrolyzer size of 100kW was included to ensure that the system would not 

eliminate the hydrogen production unit all together. 

• No hydrogen delivery costs are included, because the hydrogen is produced at the 

wind site, and the Model does not have the ability to include hydrogen delivery at this 

time. 

For Case 1, the system components included in the Model can be seen in Figure 3, and 

includes a Vestas V82 turbine, the WCROC or Gobbler’s Knob wind resource, an 

electrolyzer, hydrogen storage, a variable hydrogen load, and the grid. The Vestas V82 

turbine was selected as it is the turbine currently located at the WCROC site. The grid is 

 

5

 Lambert, Tom. Interest Rate, HOMER® help file. www.nrel.gov/homer/, National Renewable Energy Laboratory. 

May 6, 2004. 

5
included so electricity produced during the peak hours of 4-7 p.m. can be sold at a rate of 

$0.066/kWh, which is consistent with Xcel Energy’s peak rates for selling electricity. 

Figure 3: System Components for Case 1 in the Model 

While Case 1 optimizes a single wind resource and allows hydrogen production to fluctuate 

to minimize hydrogen cost, Case 2 has some different constraints due to the aggregate wind 

source and the point of use hydrogen production unit. 

Case 2 Key Assumptions

• This Case assumes all energy from Lamar, Peetz, and Ponnequin wind farms in 

Colorado is available for hydrogen production. 

• The hydrogen production system is located at the demand site, rather than at the 

wind site, so hydrogen prices calculated include delivery, but not dispensing. 

• The hydrogen demand is that of a 1500 kg/day filling station, and no unmet 

hydrogen load is allowed. The profile of this hydrogen demand can be seen in 

Figure 4. 

6
Figure 4: Case 2 hydrogen demand profile 

The load profile shows that hydrogen demand at a filling station is assumed to be highest 

during normal commute hours, from 8 and 9 a.m. and from 5 to 6 p.m. Hydrogen demand is 

assumed to be negligible late at night and in the early hours of the morning. Note that the 

“maximum unmet hydrogen load (%)” value for this case is 0%, meaning that fueling 

stations must meet the demand every hour out of the year, either through hydrogen 

production or hydrogen storage. 

For Case 2, the system components include an aggregate wind resource, an electrolyzer, 

hydrogen storage, a fixed 1500 kg/day hydrogen load, and the grid so electricity can be 

obtained from the wind farms. See Figure 5 for the system component diagram from the 

Model. 

Figure 5: System Components for Case 2 in the Model 

7
Results 

The purpose of this study was to determine if hydrogen can be produced economically from 

wind generated electricity. The Department of Energy Hydrogen, Fuel Cells and Infrastructure 

Technologies (DOE HFC&IT) program goal for delivered hydrogen in 2015 at the filling station 

is $2-3/kg,6 and the program goal for delivery and dispensing is $1/kg for delivery.7 This means 

that for Case 1, hydrogen needs to be produced for $1-$2/kg as the delivery cost is not included 

in this study. For Case 2, the hydrogen can be produced for roughly $2-3/kg, as the hydrogen 

can be produced at the point of use, eliminating the need for delivery. 

The results from Case 1 demonstrate that hydrogen can be produced at the wind site for prices 

ranging from $5.55/kg in the near term to $2.27/kg in the long term. Figure 6 shows the 

hydrogen prices for the WCROC and Gobbler’s Knob sites in the near, mid, and long term. 

Case 1: Hydrogen Produced at Wind Site

$5.55

$3.40

$2.70

$4.89

$2.90

$2.27

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

near term mid term long term

$/kg .

Minnesota WCROC Site Gobbler's Knob Site

Figure 6: Case 1 Results

These results illustrate that using wind to produce hydrogen from Gobbler’s Knob results in a 12 

– 16% hydrogen price reduction over hydrogen produced at the WCROC site. This is partially 

because the average annual wind speed at the WCROC site is 7.41 m/s, while the average annual 

wind speed at the Gobbler’s Knob site is 8.50 m/s. The study shows that higher average annual 

wind speeds can lead to lower hydrogen prices. 

The results also illustrate that as the long term prices for wind-produced hydrogen are $2.70 - 

$2.27/kg, so the resulting lowest delivered hydrogen prices from these systems are $3.70 - 

$3.27/kg including the $1/kg delivery goal. These costs are slightly higher then the overall DOE 

cost targets. As a result, this Case appears to only be economic for a small scale niche market 

with good wind or subsidies that help to drive the cost below $3/kg. However, because Case 1 

does not take into account any potential cost savings of an optimized wind/hydrogen/electricity 

 

6 DOE Announces New Hydrogen Cost Goal, July 14, 2005, 

www.eere.energy.gov/hydrogenandfuelcells/news_cost_goal.html. 

7 Hydrogen, Fuel Cells & Infrastructure Technologies Program Multi-Year Research, Development and 

Demonstration Plan, February 2005, www.eere.energy.gov/hydrogenandfuelcells/mypp, p. 3-45. 

8
system, NREL and Xcel Energy see this as a potential research area. If costs of the system can 

be reduced $0.27 - $0.70/kg wind hydrogen may be produced and delivered for less than the 

DOE cost target. 

The results from Case 2 in Figure 7 show hydrogen can be produced using aggregate wind at the 

point of use for prices ranging from $4.03/kg in the near term to $2.33/kg in the long term, 

assuming wind energy is available at the point of use for $0.038/kWh. These prices include 

delivery, as the hydrogen is produced at the demand center, but do not include dispensing. 

Assuming dispensing is a small portion of the DOE delivery target, it is likely that hydrogen can 

be produced for the DOE HFC&IT cost target of $2 - $3/kg delivered. 

Case 2: Hydrogen Produced at Point of Use via 

Aggregate Wind

$4.03

$2.80

$2.33

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

near term mid term long term

$/kg hydrogen .

Figure 7: Case 2 Results 

Comparing Case 2 to Case 1 results for Gobbler’s Knob, Figure 8, shows that in the near and mid 

term, hydrogen can be produced at the point of use for less then the cost of producing hydrogen 

at the wind farm. One reason for this is that the capacity factors of the electrolyzers are higher in 

Case 2 then in Case 1 because the aggregate wind signal helps even out the peaks and valleys of 

the intermittent wind energy. For example, in the near term, the capacity factor for the 

electrolyzer is 81% in Case 1 and 90% in Case 2. This increased capacity factor has a higher 

effect on hydrogen price in the near and mid term, as the capital costs are higher. In the long 

term, the production cost of hydrogen from Case 2 is slightly higher than at the Gobbler’s Knob 

site. However, as stated earlier, the hydrogen prices from Case 2 include the delivery of 

hydrogen, and the hydrogen prices from Case 1 do not, so the Case 2 results actually result in a 

lower delivered price of hydrogen. 

These results appear to show that producing hydrogen from aggregate wind at the point of use 

appears to be the most economic option. However, if research of the system in Case 1 can lead 

to cost reductions that offset the delivery costs, this study shows that hydrogen production at the 

wind site can makes fiscal sense. 

9
$4.03

$4.89

$2.80 $2.90

$2.33 $2.27

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00

$/kg of hydrogen

near term mid term long term

Case 1 versus Case 2 for Wind Hydrogen Production

Aggregate Wind Gobbler's Knob Site

Figure 8: Comparison of Case 1 and 2 

Research at NREL 

NREL is investigating opportunities for reducing hydrogen costs through component 

optimization for integrated hydrogen-electricity production applications. Most electrolyzers 

commercially available today are designed for grid-connected operation and, therefore, 

incorporate power electronics to convert alternating current (AC) from the grid to direct current 

(DC) power required by the cell stack. These power converters can represent 25%-30% of the 

total cost of the electrolyzer. Power converters are also required for renewable energy sources. 

For example, when using wind energy, variable speed wind turbines rely on power electronics to 

convert the variable frequency, variable voltage AC power produced at the generator to DC. 

This is then converted back to AC at grid frequency and voltage to connect to the grid. 

Photovoltaic (PV) systems also have DC-DC converters and DC-AC inverters. These wind and 

solar power converters can be a significant percentage of the renewable energy system cost. 

Designing integrated power electronics packages and optimizing the sizing and integration of 

components are opportunities for improving the efficiency, cost, and robustness of these systems. 

As part of this work, NREL is developing standardized test protocols that can be used to evaluate 

electrolyzer performance when connected to renewable energy systems. The protocols will be 

based on actual testing with renewable energy systems. Specific performance measures may 

include short and long-term effects of intermittent operation on the efficiency and purity of 

hydrogen, and how the electrolyzers perform at low input power levels. NREL is working with 

electrolyzer manufacturers to test the performance of their systems under these protocols. The 

long-term goal of this activity is to develop a consensus-based testing protocol with industry on 

electrolyzer performance. 

NREL currently has the ability to test electrolyzers connected to either PV systems or wind 

turbines up to 75kW. This year, NREL is expanding its testing capability and infrastructure is 

being added that will allow testing of electrolyzers up to 1MW in size. With both renewable 

energy systems and electrolyzers, there is an economy of scale in terms of cost; larger systems as 

less expensive on a $/kW basis. As these types of systems are deployed, the larger MW class 

10
systems will be most cost effective. Being able to test these size systems is extremely important 

to the hydrogen economy. 

NREL is also working through a cost-shared cooperative research and development agreement 

with Xcel Energy. In the Wind2H2 Project, NREL and Xcel Energy are examining the system 

integration issues with wind-hydrogen production, compression, storage, and use. The project 

will integrate wind turbines directly to electrolyzers testing both AC and DC connections. The 

hydrogen will then be compressed and stored for use in a hydrogen internal combustion engine. 

Conclusion 

Hydrogen produced from wind electricity appears to have potential to meet the DOE HFC&IT 

program goals. If aggregate wind electricity is available at the filling station for $0.038/kWh, it 

is possible for production, compression, and storage to cost below the target of $2-3/kg delivered 

hydrogen. Hydrogen production at the wind site makes fiscal sense if cost reductions offset 

delivery cost, and cost reductions need to be between $0.27 and $0.70/kilogram to meet the DOE 

HFC&IT cost targets. Researchers at NREL are working to determine if optimized 

hydrogen/electricity production applications can help improve the efficiency and costs of 

renewable hydrogen productions systems. 

Acknowledgements 

The authors would like to thank Frank Novachek and Vicki McCarl of Xcel Energy for their 

invaluable assistance and support during this analysis effort. 

11
Appendix A – Detailed Assumptions 

Common Assumptions

Common Assumptions Parameter

Near Term Assumption 

Mid Term Assumption 

Long Term Assumption Notes

Wind Turbine Capital Cost $0 $0 $0 

Not included in analysis. Assincluded in purchased electricturbine at $38/MWh 

Replacement Cost $0 $0 $0 

Not included in analysis. Assincluded in electricity rate. 

O&M $0 $0 $0 

Not included in analysis. Assincluded in electricity rate. 

Lifetime 

Rotor will need to be replaced after 20 years at 15-20% of initial investment 

Rotor will need to be replaced after 20 years at 15-20% of initial investment 

Rotor will need to be replaced after 20 years at 15-20% of initial investment 

Not included in analysis. Assincluded in electricity rate. 

Electrolyzer Size 1000 kg/day 1000 kg/day 1000 kg/day 

Capital Cost, electrolyzer $2,302,000 $1,220,000 $790,000

includes electrolyzer at $740/$400/kW, and $300/kW 8

Replacement Cost $1,110,600 $576,000 $307,000

Every 10 years replace the ceelectrolyzer at 30% of cost fro

100% of the compressor. 

O&M $115,100 $61,000 $39,500

5% of capital investment, doeelectricity 

Sizes to consider 

100 kW - 6900 kW 

100 kW - 6900 kW 

100 kW - 6900 kW 

A wide range of sizes is consModel simulation can optimizelectrolyzer size 

Lifetime 10 years 10 years 10 years 

8 Production Case Studies. www.hydrogen.energy.gov/h2a_prod_studies.html9 Ibid. 

12
 Electrolyzer 

(cont.) Efficiency 70% 78% 83%

53.4, 47.9, and 44.7 kWh/kg electrolyzer. Includes 2.09 kWcompression.10 Efficiencies b

HHV of hydrogen of 39 kWh

Compressor Cost $600,000 $300,000 $100,000 

Cost for a 1500 kg/day comprDOE delivery contacts 

Compressor Energy Requirement 2.09 kWh/kg 2.09 kWh/kg 2.09 kWh/kg From H2A forecourt scenario

Hydrogen Tank Size 85 kg 85 kg 85 kg 

Capital Cost $93,000 $40,000 $26,000 

From EPC quote and H2A foassumptions12

Replacement Cost $93,000 $40,000 $26,000 Assume entire tank needs repO&M $4,650 $2,000 $1,300 

5% of capital investment, doeelectricity 

Lifetime 20 years 20 years 20 years 

Based on "Compressed Gas HTubes" from H2A Delivery.13

Other Costs 

Electricity Cost (purchase) $38/MWh $38/MWh $38/MWh

Electricity is only purchased being produced. Purchasing pwind farm. 

Electricity Cost (sell) $66/MWh $66/MWh $66/MWh Annual Real Interest Rate 10% 10% 10%

Discount rate used to convert one-time costs and annualized 

10 Production Case Studies. www.hydrogen.energy.gov/h2a_prod_studies.html11 Ibid. 12 Ibid. 13 Production Case Studies. www.hydrogen.energy.gov/h2a_delivery.html 

13
Case 1 Assumptions 

Case 1 Parameter 

Near Term Assumption 

Mid Term Assumption 

Long Term Assumption Notes

Wind Turbine Power Curve 

Using University of MinnesotV82 1.65MW Turbine. Purchelectricity used from turbine a

Hub Height 70 70 70 From University of Minnesot

Wind Resource Resource 

University of Minnesota 

University of Minnesota 

University of Minnesota 

University of Minnesota monwind speeds. Sensitivity was Gobbler's Knob data. 

Altitude 1090 1090 1090 1090 feet from NREL GIS grSurface Roughness 0.01 0.01 0.01 

Hydrogen Load Hourly load profile 42 kg/hour 42 kg/hour 42 kg/hour 

Use max hydrogen load from kg/day system. No hydrogen 7 p.m. on weekdays 

Unmet Hydrogen Load 100% 100% 100% Allow up to 100% of load to n

Other Costs 

Fixed Capital Investment 

35% of electrolyzer, compressor and storage capital investment 

35% of electrolyzer, compressor and storage capital investment 

35% of electrolyzer, compressor and storage capital investment 

14
Case 2 Assumptions

Case 2 Parameter 

Near Term Assumption 

Mid Term Assumption 

Long Term Assumption Notes

Wind Turbine Power Curve 

Aggregate Xcel Energy Wind 

Aggregate Xcel Energy Wind 

Aggregate Xcel Energy Wind 

Data from 3 Xcel Energy winaggregated, and it is assumed available at a remotely locateelectrolyzer will only run whepower is available 

Wind Resource Resource 

Aggregate Xcel Energy Wind 

Aggregate Xcel Energy Wind 

Aggregate Xcel Energy Wind 

Hydrogen Load Hourly load profile variable variable variable Must match filling station dem

Unmet Hydrogen Load 0% 0% 0% 

Hydrogen load must be met ethe day 

Other Costs 

Fixed Capital Investment 

20% of electrolyzer, compressor, and storage capital investment 

20% of electrolyzer, compressor, and storage capital investment 

20% of electrolyzer, compressor, and storage capital investment 

15
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5b. GRANT NUMBER

4. TITLE AND SUBTITLE

Wind Energy and Production of Hydrogen and Electricity --

Opportunities for Renewable Hydrogen: Preprint 

5c. PROGRAM ELEMENT NUMBER

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NREL/CP-560-39534 

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HY65.2100 

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5f. WORK UNIT NUMBER

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-560-39534 

10. SPONSOR/MONITOR'S ACRONYM(S)

NREL 

9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES)

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)

An assessment of options for wind/hydrogen/electricity systems at both central and distributed scales provides insight 

into opportunities for renewable hydrogen. 

15. SUBJECT TERMS

renewable hydrogen; hydrogen production; wind hydrogen electricity; central production; distributed production 

16. SECURITY CLASSIFICATION OF: 19a. NAME OF RESPONSIBLE PERSON 

a. REPORT 

Unclassified 

b. ABSTRACT 

Unclassified

c. THIS PAGE 

Unclassified

17. LIMITATION 

OF ABSTRACT

UL 

18. NUMBER 

OF PAGES 

19b. TELEPHONE NUMBER (Include area code)

Standard Form 298 (Rev. 8/98) 

Prescribed by ANSI Std. Z39.18