Renewable Energy 29 (2003) 471–489

www.elsevier.com/locate/renene

The role of hydrogen in high wind energypenetration electricity systems: The Irish case

A. Gonzalez, E. McKeogh �, B.O. GallachoirDepartment of Civil & Environmental Engineering, UCC, College Road, Cork, Ireland

Received 18 June 2003; accepted 29 July 2003

Abstract

The deployment of wind energy is constrained by wind uncontrollability, which posesoperational problems on the electricity supply system at high penetration levels, lessening thevalue of wind-generated electricity to a significant extent. This paper studies the viability ofhydrogen production via electrolysis using wind power that cannot be easily accommodatedon the system. The potential benefits of hydrogen and its role in enabling a large penetrationof wind energy are assessed, within the context of the enormous wind energy resource in Ire-land. The exploitation of this wind resource may in the future give rise to significantamounts of surplus wind electricity, which could be used to produce hydrogen, the zero-emissions fuel that many experts believe will eventually replace fossil fuels in the transportsector. In this paper the operation of a wind powered hydrogen production system is simu-lated and optimised. The results reveal that, even allowing for significant cost-reductions inelectrolyser and associated balance-of-plant equipment, low average surplus wind electricitycost and a high hydrogen market price are also necessary to achieve the economic viabilityof the technology. These conditions would facilitate the installation of electrolysis units ofsufficient capacity to allow an appreciable increase in installed wind power in Ireland. Thesimulation model was also used to determine the CO2 abatement potential associated withthe wind energy/hydrogen production.# 2003 Elsevier Ltd. All rights reserved.

Keywords:Wind energy; High penetration; Hydrogen

� Corresponding author. Tel.: +353-21-490-2524; fax: +353-21-427-6648.

E-mail address: e.mckeogh@ucc.ie (E. McKeogh).

0960-1481/$ - see front matter # 2003 Elsevier Ltd. All rights reserved.

doi:10.1016/j.renene.2003.07.006

1. Introduction

Ireland is richly endowed with renewable energy resources whose exploitation

has become a necessity if the challenging targets imposed by the Kyoto Protocolare to be met. The predictions anticipate a 37% rise in GHG emissions in the per-

iod 1990–2010 [1], whereas Ireland is committed to a maximum increase of 13%.

Security of supply is another issue that calls for an urgent renewable energy

deployment, since Ireland is the second most energy import-dependent country in

Europe (87% of the energy needs in 2001).Onshore wind energy is the most competitive form of renewable energy in Ire-

land, but its stochastic nature is a barrier to unlimited development. A growingshare of wind energy in the electricity sector requires changes in system manage-

ment to ensure power reliability and quality and to maintain the necessary reserve

capacity, and usually demands costly grid reinforcements. The operational changes

result in a less efficient overall system performance, eventually forcing wind energy

curtailment. These factors reduce the value of wind energy at high penetration

levels and curtail the exploitation of vast wind resources in countries like Ireland.The introduction of new technologies and strategies, such as forecasting, geo-

graphical dispersion, interconnections, and sophisticated power electronics, will

mitigate these problems to some extent, but, as these do not remove the fluctuant

nature of wind, the large penetration of wind will ultimately require the uptake of

energy storage. Among the storage options, hydrogen has attractive features for

renewables integration, primarily on account of its multi-functionality. Hydrogen

acts as a storable ‘energy carrier’ that can be either converted back into electricity-

thus providing a balancing service to electricity generators and suppliers- or usedas a ‘zero emissions’ fuel for other applications, such as transport.It is in mobile applications where hydrogen will find its first and largest market.

The high dependency of transport on fossil fuels all over the world, with the

attendant high contribution to many environmental problems, urges the adoption

of a clean, sustainable fuel. Governments, car manufacturers and energy enter-

prises are joining forces, albeit with diverse degrees of commitment, to realise the

so-called hydrogen economy, which will see the gradual replacement of fossil fuelsfor hydrogen. Although the way the transition to a hydrogen-based transport sys-

tem will be achieved remains unclear, the benefits of hydrogen will only be fully

realised when generated from renewable energies. Another option like natural gas

reforming coupled with carbon sequestration may be interesting in a transient per-

iod, but is still weak in terms of addressing concerns relating to security of supply

and fossil fuels depletion.The shift from a transport system based on fossil fuels to hydrogen requires

huge investments and involves major infrastructural changes both in the fuel distri-

bution and supply and in the vehicles. In this regard, it will be very important the

experience gained in Iceland, which has already undertaken an ambitious project to

become the first hydrogen economy in the world [2], producing hydrogen by elec-

trolysis using excess renewable energy.

A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489472

Wind-powered water electrolysis is envisaged as an important source of zero-emissions hydrogen in the future. Although it may appear very costly at a firstglance, the use of surplus wind power in future scenarios, where wind represents alarge share of the electricity market, points to a different outlook. Hydrogen sys-tems can help to overcome the problems arising in the electric system at high windenergy penetration and offset the gradual reduction in value of this energy.The general layout of a wind-hydrogen system is represented in Fig. 1. When the

power generated by wind farms exceeds the regional or scheduled demand, the sur-plus is used to electrolyse water. The hydrogen produced and stored can be eitherused for transport or supplied to stationary fuel cells in order to generate poweragain when required. The different strategies will depend on a number of factors,including the evolution of the electricity market and the success of hydrogen as afuel for vehicles, which in turn depends largely on political decisions.Initially mobile applications are believed to represent a higher market value for

hydrogen than stationary electricity regeneration. The production of hydrogen fortransport applications alone does not provide all the benefits that electricity regen-eration does for the network. It does, however, contribute to considerably smooth-ing out the wind power output, thus enhancing the electric system managementand avoiding overproduction. In this paper, only the production of hydrogen fortransport will be assessed.Significant experience has been gained during recent years in the operation of

renewable-hydrogen systems. A number of projects, mostly small-scale plants, havecontributed to improving the integration of the various components, testing newdevelopments and identifying weak points [3–10]. Yet it is necessary to undertakedemonstration schemes coupling wind turbines and electrolysers in a larger scale.In this regard, there are several ongoing ambitious schemes in Norway, Germany,UK and USA.

2. Wind deployment in Ireland

Given the abundance of the wind resource available in the country and thematurity of the technology, wind energy is set to dominate the Irish renewables sec-tor overwhelmingly. Thanks to the high wind speeds, the economically viablepenetration levels are higher than, for example, in Denmark or Germany [11]. At

Fig. 1. General layout of a wind-hydrogen system.

473A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489

present, wind power development in Ireland remains modest, with an installed

power representing only 2.4% of a total generation capacity approaching 5000

MW, contributing to about 1.5% of the electricity demand. However, an acceler-

ated growth is expected to occur in the short term as evidenced by the ambitious

targets and the current level of activity.If, as anticipated, the present renewable energy targets are largely achieved

through wind power, an additional 500 MW must be installed by 2005 [12]. The

EU Directive on the Promotion of Electricity from Renewable Energy [13] detailed

an indicative target for Ireland that would require approximately 400 MW more

for the period 2005–2010, raising wind contribution to 10.4% of Ireland’s electricity

needs in 2010. Further still, only with the projects that have already been approved

or are currently seeking planning permission, the installed capacity could rise to

4000 MW [14]. This figure includes offshore plant, for which Ireland is particularly

suited and which is likely to play an important part in the future Irish scene if tech-

nological difficulties are overcome and costs are lowered.The feasible wind energy resource in Ireland is estimated at 344 TWh/y (125

GW capacity) [15], or ten times more than the future electricity demand of 33.5

TWh predicted for 2010. Spatial planning and the exclusion of environmentally

sensitive areas largely diminish the practicable resource, which nevertheless is very

significant. However, there are further constraints which must be borne in mind.

The hugely complex question of how much the network can accommodate depends

on a variety of factors and constitutes a controversial issue. Whereas the Irish

Wind Energy Association maintains that a 20% share of wind energy is not prob-

lematic [11], for the Irish utility Electricity Supply Board (ESB) the mentioned tar-

get (10.4%) poses a major challenge [16]. Fig. 2 displays the maximum annual wind

energy the network could take in the future if restricted to 20% or 25% of the total

generation, limits which would be well surpassed by the quoted 4000 MW.The next sections will clarify the constraining factors and their effect on the wind

energy value, as well as the prominent role that hydrogen can play in wind energy

Fig. 2. Future wind penetration in Ireland.

A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489474

deployment, allowing for a higher penetration and extending its scope to the trans-port sector.

3. The loss of value of wind energy at high penetration

Although there are no insuperable technical problems in accommodating grow-ing amounts of wind energy, its lack of controllability and low capacity factor putit at a disadvantage resulting in a tangible loss of economic value. A viabilityassessment of wind-hydrogen systems requires an estimate of the true economicbenefits they bring to the network.The boundary between low and high penetration may be set at the wind energy

capacity that can be assimilated without major problems. As the wind capacityrises, changes in the operation of the of the electric system are necessary:

. Measures must be taken to ensure the demand on the system is always met; andtherefore fast response and reserve services must be available.

. Some ancillary services must be provided by the system to ensure power quality(voltage and frequency tolerances). However, new technology developments aremitigating largely the traditional inability of wind turbines to meet these require-ments. One of the key challenges will be to develop and implement fault ridethrough technology to maintain transient stability.

. The system can be eventually incapable of absorbing all the wind energy gener-ated in some periods of time, forcing curtailments.

. Areas with high wind concentration may demand costly grid upgrading,especially if the redundancy level is to be kept.

The value of renewable electricity is the net cost savings that can be realised inthe electricity system as a result of the renewable generation. These savings,grouped in three categories [17,18], are affected by a high wind share as follows:

. Energy value. This is based on the variable avoided costs of generating electricityfrom other sources. At high wind penetration, however, the operation of reserveplant at inefficient (and pollutant) part load and stand-by lessens these savings.The increased load cycling has a negative effect as well. Under some circum-stances, the part-loading limits may be reached on thermal plants and it may benecessary to shut down some wind plant (wind energy curtailment). The fre-quency of these events and their economic damage will grow with increasingwind capacity. Indeed the most serious operational challenge that a power sys-tem with high local and global penetration of wind power—like the Danish—must face is what to do when there is too much energy from wind, which cannotbe assimilated on to the system [19]. The limitations to the wind power contri-bution will also depend on the ability of wind farms to meet the network opera-tors’ technical requirements. ESB has suggested in an early study that windpower levels should be limited to 30% of the instantaneous load during the day-time, possibly higher at nights [20].

475A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489

. Generation capacity value. Those are the fixed generation costs that windcapacity can avoid by allowing the shutdown and decommissioning of conven-tional plant. Although wind energy may have a certain capacity credit, itsunreliability requires the system to keep reserve capacity, especially at high pen-etration levels as the partial loss of generation from the wind becomes anincreasingly significant source of risk of demand exceeding available generation.Calculations by the transmission system operator in Ireland attributed to windpower a capacity credit of about 20% for an installed wind capacity of 800 MW,thus equalling to 160 MW of conventional plant [21]. The credit will decrease aswind penetration increases.

. Transmission and local network value. Whereas at low penetration levels windfarms may avoid transmission lines upgrading by meeting regional demands, athigh penetration the need to export electricity has the opposite effect. The factthat good wind sites are often located remotely from electric loads in weak partsof the grid heightens the required investments, whose impact on the wind energycost is worsened by the low capacity factor.

The estimates of the loss of value show a high sensitivity to certain assumptionsand prove very site-specific, depending on the precise mix of generating plant, thegrid characteristics and the wind farm location. A strong presence of inflexiblebase-load power plant, for instance, has a negative effect. Ireland is expected to seein the coming years the construction of gas-fired combined cycle power stations,which can barely run at loads below 50–65%. The deployment of wind energy may,however, force the installation of more flexible power plant such as open-cycle gas-fired plant as reserve.According to most authors, the value of wind energy does not vary significantly

at penetration levels up to 10% (on an energy basis), but a marked decrease occursbeyond 20% [17]. A Danish study calculates an increasingly steep decline from 3.5c4/kWh at 10% penetration to 2.2 c4/kWh at 30%, and to only 0.2 c4/kWh at50% [17]. A significant share in this devaluation found in Denmark results from therequired grid reinforcements, whose cost per kWh of wind electricity wouldincrease gradually from zero to 1.3 c4/kWh at 50% penetration. A different sourcesets the total penalties in the order of 10–20% of the wind energy cost at 20% pen-etration [11]. A recent evaluation of the impacts of increasing levels of wind pen-etration in Ireland states that the losses caused by curtailments are negligible atwind capacities below 1000 MW, but will become considerable for wind capacity inexcess of approximately 1500 MW. Using a conservative approach, that study findsthat 40% of the potential wind output would be lost at a penetration near 50% [14].Grid upgrading is also an important concern in Ireland, where the network is

weaker along the western seaboard and the wind resource is strongest (Fig. 3). Thenetwork infrastructure is already constraining the development of some projects[12], and upgrades are essential if the current targets of additional green electricitycapacity are to be delivered. A different approach suggests that large wind cap-acity can be connected to the Irish transmission system without significantreinforcements on the assumption that wind farms are not regarded firm cap-

A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489476

acity and would be disconnected in the event of outages or other transmissioncontingencies [14].Interconnections to neighbouring systems offer a greater ability to cope with the

difficulties associated with fluctuant supply and constitute a key strategy in Den-mark. In Ireland, however, the existing interconnection with Scotland (throughNorthern Ireland) is limited to 400 MW. Further expansion and additional inter-connections are under investigation, but, aside from the major investment they rep-resent, their benefit is constrained as Scotland is seeking a significant expansion ofits own wind power capacity [14]. Ireland is possibly unique in facing high windpenetration on an electricity system that has only a low-capacity link with othersystems. The Crete Island system, where significant wind curtailment is necessaryat times, would be the most similar.Short-term wind forecasting is envisaged as a key tool for improving the man-

agement of the reserve capacity and lessening this loss of value. Geographical dis-persion is also acknowledged as an important means to achieve smooth and lessunpredictable combined output of wind farms located on distant sites [22].Although both will contribute to overall system efficiency and facilitate increasedwind capacity, their impact is limited, especially as the wind penetration levelincreases.The generation of hydrogen from excess wind-generated electricity offsets the

drop of wind energy value at high penetration levels in the following ways:

. Smoothing the power output and hence facilitating a more efficient operation ofthe electric system. The smaller scale of the fluctuations reduces the need forancillary services to maintain power quality.

. Avoiding wind plant shedding. The substantial lost production in Ireland fore-seen by the study cited above [14] stresses the potential of hydrogen generation.

Fig. 3. Areas of highest wind potential in Ireland and distribution system.

477A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489

. Reducing the scale of the necessary grid reinforcements if hydrogen generationplants are installed in areas with a high wind power concentration.

4. Wind-hydrogen in the liberalised market

With the exception of the curtailment avoidance, which directly benefits the windgenerator, the costs mentioned in the previous section are normally hidden orborne by different economic actors. Market incentives reflecting these costs, and sorewarding the possible benefits, are necessary if hydrogen systems are to be profit-able, compensating for the investments required and the losses involved. The roleof hydrogen in connection with the expansion of wind power will therefore beheavily influenced by energy policies.The electricity market liberalisation process, which is being implemented across

Europe in accordance with various directives, must seek to achieve the triple objec-tive of reducing energy costs, ensuring security of supply, and fostering sustainablesources. Recognition of the benefits of renewable energy and acceptance of themarket distortions, arising mostly from the fact that external costs associated withconventional generation are not internalised into the electricity price, have promp-ted the introduction of a range of support measures to stimulate wind energy. Itappears, however, that policies which have succeeded in delivering wind deploy-ment targets, e.g. Germany, Spain, are barely compatible with the liberalisationprocess. A secure market for wind-generated electricity, with a guaranteed sellingprice irrespective of when and where it is generated, results in a cost misallocation.If balancing services are provided by the system operator—a central dispatchattains probably the lowest costs—the costs incurred must be passed to the gen-erators. In short, liberalised markets must provide transparent mechanisms tovalue the full benefits of renewable energy to the society, which includes environ-mental and health externalities, and at the same time reflect the cost that theiraccommodation causes to other market actors.It is important to note that, apart from the positive effects on the electricity sys-

tem, there are further benefits that hydrogen can bring to a country. Its use inzero-emissions fuel cell cars will avoid urban pollution, responsible for significantexternal costs. Finally, the greater exploitation of renewable energies that hydrogenpermits, and the extension of their scope to the transport sector, diminish the over-reliance on fossil fuel imports, create employment and develop an indigenous tech-nology and industry.

4.1. Market trends

In order to reallocate the costs that system operators incur in providing energybalancing and ancillary services, Ireland, along with other countries, is introducingelectricity trading arrangements. The trading period is half-hourly, with a marketto clear imbalances. The differential between the ‘top up’ price (to clear shortfalls)and the ‘spill’ price (excesses) introduces a penalty for imbalances between supply

A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489478

and demand. This prompts the need for generators to be able to predict and con-trol their outputs. The actual penalties imposed to those parties who are out ofbalance should be cost-reflective and based on a careful assessment.In Ireland, in the current framework, wind energy generators that have secured

power purchase agreements can sell the electricity at a fixed price [12]. Electricitytrading has been open to green energy suppliers, a market trend that may increasein the future at the expense of current bidding schemes. Green suppliers can sellelectricity to all customers, but are required to balance any purchases of non-renewable electricity with green energy purchases, which are spilled. Suppliers willbe willing to pay less for intermittent electricity in view of the penalties they face inthe trade of this energy.Although the majority of wind farm developers may not agree, correct pricing

signals are necessary to achieve high levels of wind penetration at the lowest costand deliver a secure and stable electricity supply [11]. These mechanisms should beregarded as an opportunity to explore the most cost-effective solutions. The costestimates hint that the market incentives that should be introduced in future sce-narios—whether in the form of imbalance penalties, large on-peak/off-peak differ-ential, or other instruments—together with curtailments and transmissionconstraints, will make wind-hydrogen cost-effective in the future. The viability willbe assessed in the next section.

5. Economic assessment

Two factors undermine the economic viability of wind-hydrogen systems:

. Energy market failures

. High cost of the components.

The first barrier has already been discussed. As for the second, the present highcost of electrolysers is partly due to the lack of competitiveness in a market occu-pied by only a handful of manufacturers throughout the world. High electricitycosts have traditionally constrained the adoption of electrolysis for industrial hydro-gen generation. However, the demand for ‘green’ hydrogen indicates a rapid deploy-ment of renewable electrolysis in the future. Even non-renewable electrolysis islikely to play an important role in the short-term as a source of moderate amountsof hydrogen for small fuelling stations and domestic applications. Technologydevelopments, standardisation, mass-production, and greater competitiveness, willbring prices down within the next years. One of the most important advances is thecurrent trend to increase the operating pressure inside the stacks, thus reducing theneed for further mechanical compression and lowering the overall costs.The uncertainties relating to some issues like externalities and the future struc-

ture of the electricity market, along with the presence of many site-specificfactors, make it difficult to carry out a thorough assessment. A regional specificcase study will be analysed here, consisting of a hydrogen production facility

479A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489

connected to four wind farms in the south-west of Ireland using from surplus,low-priced wind power. Power regeneration will not be considered. The feasibilityof the production of hydrogen for transport applications will be subordinated tothe success in building a hydrogen supply infrastructure and commercialisinghydrogen-fuelled vehicles. This scheme does not avoid some of the causes of lossof value, since the same amount of reserve capacity must be kept and operationalpenalties arise when the demand exceeds generation. It is unlikely, however, thatin the medium-term the penalties associated with the purchase of ‘top up’ elec-tricity are high enough to make regeneration cost-effective. Despite the highefficiency of fuel cells, the losses are important and the capital costs of the com-plete system including fuel cells, storage, power conditioning, etc., are very high.Hydrogen as a means of electrical energy storage will have to compete with otherstorage technologies.

5.1. Case study

A key issue is whether hydrogen production systems should be sited near thewind farms or closer to the consumption points. In the latter case, the facilitieswould probably be operated by electricity suppliers balancing their positions, usingelectricity coming from a portfolio of different wind farms. But such an approachwould not avoid transmission problems. In a scenario heavily constrained by thetransmission network, hydrogen facilities are more likely to be connected to singlewind farms, or to groups of them situated in an area of high wind power density,thus limiting electricity exports. This is the approach considered herein, althoughthe future trends will be influenced by hydrogen transport and distribution costsand the final electricity market structure. The regional-scale aggregation of windfarms will smooth the imbalance to some extent and will also be beneficial for thehydrogen system’s cost-effectiveness, on account of the resulting somewhat higherutilization factor of the electrolysers.In this hypothetical case study, four wind farms, located in County Cork (Ireland)

(Fig. 4), supply their aggregated power to a portfolio of regional customers. Anelectrolysis facility connected to the grid on a site near the wind farms absorbsmost of the surplus electricity exceeding the regional customers’ demand (Fig. 5).Different factors may contribute to the low average price of the surplus elec-

tricity in a high wind penetration scenario:

. Curtailments enforced by the system operator due to operational limits or trans-mission constraints. The value of the excess electricity is zero in these intervals.This will be the key factor in all probability.

. Penalties for imbalance in the liberalised market.

. High differential between off-peak and on-peak price. Most surplus electricity isproduced at off-peak hours, when the demand is low.

. The costs of wind energy are, in general, notably lower in Ireland than in mostother countries due to the higher wind speeds available, hence making it possiblefor the surplus energy to reach yet lower prices.

A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489480

In order to assess the potential benefit of hydrogen storage and determine the

scale of future deployment, a simplified approach is adopted in this paper. This

involves the use of an average energy price for the surplus electricity produced. The

real scenario will be more complex, with prices varying throughout the day. The

management of a wind-hydrogen plant can be enhanced by the knowledge of these

variations together with wind forecasting.The wind power profile has been worked out from one year’s wind velocity data

from the four selected sites on an hourly basis, applying them to the power curve

of 850 kW, 60 m hub height, wind turbines. The overall installed capacity of the

four wind farms is 100 MW, yielding 379.5 GWh/a. In the case-study analysed, the

total regional demand of the customers amounts to 322.6 GWh/a (85% of

the wind farms’ yield). This demand reaches an annual peak of 57.9 MW and a

minimum of 20.2 MW. The power output surpasses the demand of 4473 hours a

year, the total surplus energy amounting to 135.9 GWh (35.8% of the total). Fig. 6

shows the power output and the demand for a particular seven-day period.

Fig. 4. Locations of four wind farms in Co. Cork (Ireland) in the hypothetical scenario presented for

analysis.

Fig. 5. System layout.

481A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489

The efficiency of the electrolysis unit, which varies with the load, fluctuates in the

system modelled here between 79% and 87% (Higher Heating Value, HHV). The

specific cost of the electrolyser together with the balance-of-plant has been set con-

stant at 1100 4/kW, a rather optimistic estimate at present (especially in the low

power range) but realistic for large-scale systems (several megawatts) in the

medium term. Costs are expected to drop further in the long term to 600 4/kW or

even less [23]. The lifetime of the electrolysis facility is 20 years, but the cell stacks

would need to be replaced after 10 years at an estimated cost of 700 4/kW. Annual

maintenance costs are estimated at 3% of the initial capital cost. A 5% interest rate

has been used to amortise the capital cost of the system.Fig. 7 shows the cost of hydrogen per gigajoule, calculated through Eq. (1), as a

function of two parameters; one is the average price paid to the generator for the

surplus electricity, and the other is the size of the electrolysis plant (which deter-

mines the annual hydrogen yield). This is the minimum price that breaks even;

higher hydrogen market prices would produce extra revenues which enhance the

economics of the wind farms. The remaining surplus electricity that cannot be

absorbed either by the load or the electrolyser is also displayed in Fig. 7 as a pro-

portion of the total energy yield.

CH ¼P

ðCCi � CRFiÞ þO&M þ CSEEL

Hð1Þ

where CH is the cost of hydrogen per GJ (HHV); CCi is the capital costs of the

electrolysis plant over the lifetime; CRFi is the capital recovery factors; O&M are

the operation and maintenance costs; CS is the cost of surplus electricity per energy

Fig. 6. Power output and load for seven days.

A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489482

unit; EEL is the annual surplus electricity supplied to the electrolyser; and, H is theannual hydrogen production in GJ.The shaded area indicates the cost resulting from a zero electricity value, that is

to say, the cost associated exclusively with the capital and maintenance expendi-tures. As the electrolyser power increases, the marginal wind electricity surplus itabsorbs decreases and so does the electrolyser’s capacity factor, hence resulting ingrowing hydrogen costs. The optimum electrolysis plant size (Fig. 8) depends onthe actual hydrogen market price, which, along with the surplus electricity value,will determine the profit of hydrogen production. This optimum is calculated bymaximising the revenues:

revenues ¼ CH �H �X

ðCCi � CRFiÞ �O&M � CSEEL ð2Þ

If the integration of hydrogen systems is to avoid curtailment risks and trans-mission problems, and attain the desired smoothing effect that will allow for alarge wind penetration, the installed electrolysis power must be significant. Butonly high hydrogen market prices and low surplus electricity values render the

Fig. 8. Optimum electrolysis size.

Fig. 7. Hydrogen cost.

483A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489

installation of large electrolysers cost-effective, compensating for the drop in

capacity factor and hence the ratio of produced hydrogen to capital costs. For

instance, a hydrogen price of 26 4/GJ (HHV) and a surplus electricity value of 3.5

c4/kWh result in an optimum electrolysis plant of 10 MW (10% of the wind farms

rated power), which only reduces the percentage of surplus electricity from 35.8 to

23.7%—with a peak export of 62.4 MW—while the optimum corresponding to 30

4/GJ H2 and 2 c4/kWh rises to 30 MW, bringing the remaining surplus down to

7.5% and the peak export below 41 MW. In this latter case, the benefit obtained

from hydrogen sales would be 114% greater than that from the spillage of the sur-

plus electricity to the grid.The high cost of electricity has been traditionally highlighted as the main barrier

for electrolysis as a major hydrogen source, outweighing capital costs. Yet the lat-

ter becomes crucial when capacity factors are low and electricity relatively inexpen-

sive. A further reduction of the specific initial capital costs to 600 4/kW, plus 400

4/kW for the stack replacement (long-term scenario), leads to far lower hydrogen

generation costs. For a surplus electricity average value of 2 c4/kWh, a 30 MW

electrolysis plant breaks even at a hydrogen market price of 15.3 4/GJ, compared

to 22 4/GJ in the previous medium-term scenario. Likewise, 30 MW would be the

optimum size if the hydrogen price were 20 4/GJ, while 30 4/GJ where necessary

in previous case. Table 1 shows the optimisation results corresponding to this

scenario.Irrespective of reductions in the plant expenditures, energy costs set a lower limit

for hydrogen cost. Assuming an energy requirement for electrolysis of 4.5 kWh/

Nm3 H2 (78% overall efficiency) and ignoring capital costs, hydrogen cost would be

3.53 � Ce 4/GJ, where Ce is the surplus electricity value in c4/kWh.

5.2. Competitiveness

Despite the specific nature of the case study and the existing uncertainties, the

results provide a reasonable indication of the hydrogen cost and the necessary

evolution of the energy market to make its production from surplus wind energy

viable.

Table 1

Optimum electrolysis plant size in the long-term scenario (values in MW)

H2 market price

(4/GJ)

Surplus electricity average value (c4/kWh)

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5

14 32 28 24 18 6

18 36 34 32 29 25 20 13

22 40 39 38 36 34 31 27 22 14

26 43 42 41 40 38 36 31 28 23 14

30 45 44 43 42 41 40 39 38 36 33 29

34 47 46 45 44 43 42 41 40 39 38 36

A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489484

The competitiveness of wind-generated hydrogen with transport fossil fuels,whose high taxation is well justified on account of the external costs associatedwith their production and combustion [24], appears to be ensured in the mediumterm, especially bearing in mind the high efficiency of hydrogen powered fuel cells.In the same way as support policies tend to award an extra price to renewable elec-tricity, as long as external costs are not internalised, renewable-generated hydrogenmust be rewarded vis a vis oil with an extra price. This must reflect the cost of thepollution caused by the transport sector, which depends on the substituted tech-nology and the severity of urban pollution consequences in each country. It isimportant to point out that a CO2 tax or a green credit market based exclusivelyon CO2 emissions would ignore other major environmental benefits associated withthe elimination of other emissions such as NOx, CO, suspended particles, etc.,whose localised negative impact on health must be incorporated in order to fullytake into account the benefits of hydrogen in the transport sector.But rather than petrol, the competitiveness reference should be hydrogen gener-

ated from other sources, since the shift seems unavoidable in the light of fossil fuelsdepletion and environmental concerns. During the transition to a carbon-freehydrogen economy, renewable electrolysis will have to compete chiefly with steammethane reforming (SMR) and coal gasification. SMR is the most widespread andinexpensive process nowadays, even though its cost depends largely on the naturalgas price. For a large plant (100,000 Nm3/h) and gas prices between 3.8 and 7.6 4/GJ (HHV) hydrogen costs would range from 8.3 to 13 4/GJ, excluding com-pression and distribution costs [6]. For small plants (<1000 Nm3/h) the cost wouldbe substantially higher.A study carried out by Carnegie Mellon University estimates the environmental

externalities associated with SMR at 4 $/GJ H2 (HHV) [25], a result which, despitethe divergence of methods, agrees to a great extent with a calculation made by theauthors based on the ExternE study on energy external costs [26,27] if a 1% dis-count rate is considered (impact time span of 100 years). Aside from being site-spe-cific, the calculation of externalities is subject to a lot of uncertainties and can varyto a large extent depending on some assumptions, especially with regard to globalwarming. The discount rate for the impacts caused by the greenhouse effect has anenormous influence on the calculation due to the long time span of these effects.Whereas a discount rate of 1% results in a total estimate of about 3.9 4/GJ H2, itwould rise to 10.3 4/GJ if no discount rate is considered at all. Despite the out-standing issues in this field, it does not seem very likely that the internalisation ofexternal costs alone will be enough to make wind-generated hydrogen competitivewith SMR in the medium term. Such competitiveness will depend rather on the gasmarket’s future trends. Within the EU, natural gas prices for medium industrialend-users ranged in 2001 from 3.9 to 6.8 4/GJ NG (HHV, taxes excluded), in Ire-land being around 4.5 4/GJ. These prices are predicted to rise in the coming dec-ades. It must be also born in mind that natural gas is projected to account formore than 80% of the Irish electricity generation fuel mix by 2010 [28]. Thisphenomenon, widespread in liberalised markets with access to gas, raises important

485A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489

security of supply concerns and advises against resting the transport sector on thesame source.Previous studies have assessed the economics of wind farms used entirely to gen-

erate hydrogen [6,25,29], concluding that substantial cost reductions and goodwind conditions are required to bring wind-produced hydrogen near competitive-ness. Yet wind-hydrogen systems are envisaged here not as wind turbines fullydedicated to hydrogen production, but combined with power generation, makinguse of only the surplus electricity that cannot be easily accommodated on thepower system. Mann et al. [23] acknowledge the improvement in the economicsthat operation in connection with the network can bring about, reducing the cost(2010 scenario) from 28.2 (pure hydrogen production) to 21.1 $/GJ H2. Regardlessof financial considerations, the full dedication of wind farms to hydrogen pro-duction may prove an erroneous strategy (at least in the medium term), since theCO2 abatement potential would be smaller than if part of the electricity displacedconventional thermal plant electricity generation.

6. CO2 abatement potential in Ireland

The problems foreseen in accommodating growing amounts of wind capacity inIreland point towards a huge potential for the production of hydrogen from sur-plus wind energy. Its exploitation, which will be heavily influenced by politicaldecisions, can play a key part in the abatement of harmful emissions.The current rise of CO2 emissions in Ireland becomes dramatic with relation to

the transport sector, where emissions in 2001 were 120% higher than those in 1990,due to a 7.4% average annual growth rate [29], accounting for 26% of energyrelated CO2 emissions.Table 2 shows the number of vehicles that could be fuelled with hydrogen pro-

duced from the growing surplus electricity that results from gradually adding newwind capacity and limiting the instantaneous wind power to 30% of total gener-ation. The results are based on the future electricity demand and an annual carconsumption of 8.1 MWh/y (HHV) for the new generation of vehicles [30]. Thethird column presents the achieved CO2 abatement assuming the average emissionsfor the future fossil fuel-powered vehicles to be 145 g CO2/km [30], whereas theforth column shows the CO2 emissions corresponding to the production of thesame amount of hydrogen via SMR.Considering a typical emission of around 400 mg Eq-SO2/km for current vehi-

cles [31], the scenario with 5000 MW installed wind capacity would also avoidapproximately 4500 t Eq-SO2 per year coming from the transport sector, as well assignificant amounts of pollutants relating to carcinogenesis and smog effect. SMRsaves 30% of greenhouse emissions, but would also cause the release of 656 t COand 1402 t NOX per year. Not only the environmental impacts arising during thecombustion should be taken into account, since the emissions during the rest of thelife-cycle (extraction, transformation and transport) are significant and should notbe overlooked.

A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489486

The CO2 abatement brought about by the substitution of conventional electricity

generation depends on the technology replaced. The specific emissions are currently

very high in Ireland (780 g CO2/kWh in 2001), but this figure is decreasing owing

to the installation of gas-fired combined cycles, with associated emissions as low as

430 g/kWh. A realistic estimate of the future CO2 savings would be around 600 g/

kWh. Based on this figure, Fig. 9 illustrates the CO2 abatement achieved by wind

energy development as a consequence of both conventional plant substitution and

conversion of the transport sector to hydrogen. A 5000 MW wind capacity would

cut almost one fourth of the total energy-related CO2 emissions in Ireland (over 42

Mt in 2001). In the analysed scenario, relevant amounts of hydrogen are only pro-

duced at installed capacities beyond 2000 MW, but transmission constraints in

some areas might result in much higher amounts of surplus electricity at lower

Fig. 9. Wind energy CO2 abatement. Contribution of the substitution of both conventional electricity

and transport fossil fuels.

Table 2

Cars fuelled and CO2 avoided emissions at different wind capacities

Installed wind capacity

(MW)

Car fleet fuelled Avoided CO2 car emissions

(kt)

CO2 emissions from SMR

(t)

0 0 0 0

700 0 0 0

750 15 0.05 0.03

800 56 0.18 0.12

900 334 1.04 0.73

1000 1103 3.45 2.42

1200 5055 15.8 11.1

1500 19,749 61.7 43.3

2000 68,801 215 151

2500 135,160 423 296

3000 209,580 655 459

3500 288,681 903 633

4000 370,953 1160 813

4500 455,338 1424 998

5000 541,422 1693 1186

487A. Gonzalez et al. / Renewable Energy 29 (2003) 471–489

overall capacity. The future of offshore wind energy is quite important for the pro-duction of hydrogen from wind power, since it will expand the penetration sub-stantially and raise further transmission problems.

7. Conclusions

The integration of hydrogen systems in connection with wind power generationfacilitates a large penetration of wind energy, overcoming some of the barrierswhich constrain its deployment and lessen its value. In Ireland, where the vastwind resource is further constrained by a weak grid and interconnections, the fore-seen development of wind energy will give rise in the future to growing amounts ofelectricity that the electric system will not be able to readily assimilate.The fair allocation of the costs that the electric system will incur as a conse-

quence of the large development of wind energy should be reflected in market sig-nals, which, together with the growing risks of wind curtailment and the high costsof grid reinforcements, will encourage the installation of wind-hydrogen systems.Their economic viability will depend on a number of factors in future scenarios.Cost-reductions, low surplus wind electricity average value, and high hydrogenmarket prices are necessary to render the technology cost-effective, allowing for theinstallation of electrolysis units of sufficient capacity to attain the desired levellingeffect and thus facilitating a larger wind penetration.The use of wind-generated hydrogen in the transport sector will have a substan-

tial contribution to the abatement of CO2 and other emissions. Its competitivenesswith other hydrogen sources like steam reforming during the transition to a car-bon-free hydrogen economy will also be influenced by the evolution of the fossilfuels market and the reflection of environmental costs.

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