Chapter 13: UK Renewable Energy Policy since Privatization

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13

UK Renewable Energy Policysince PrivatizationMichael G. Pollitt

This chapter reviews the progress with increas-ing renewable energy supply in the United

Kingdom since 1990, with a particular focus onrecent developments. This country is regarded asone where the considerable potential for renew-able energy,1 relative to other major Europeancountries, has failed to be realized. It is also fre-quently suggested that the United Kingdomneeds to change its policies to renewables to lookmore like those in Germany or Spain (e.g.,Mitchell 2007).

The aim of this chapter is to look at theUnited Kingdom’s renewable energy policy in thecontext of its overall decarbonization (i.e. carbonemissions reduction) and energy policies. Thechapter explores the precise nature of the failureof UK renewables policy and suggests policychanges that might be appropriate in light of thecountry’s institutional and resource endowments.The focus is on the electricity sector in terms ofboth renewable generation and, to a lesser extent,the facilitating role of electricity distribution andtransmission networks. The interactions amongthe UK’s electricity, heat, and transport sectorswithin the overall decarbonization policy contextare also examined.

The discussion suggests that the precise natureof the failure of UK policy is rather more to dowith societal preferences and the available mecha-

nisms for resolving social conflict than with eco-nomic incentive arrangements. Radical changesto current policy are required, but policymakersmust be careful that they are institutionally appro-priate to the United Kingdom. Calls to “just doit” with respect to delivery of larger quantities ofrenewables are economically irresponsible andhighly likely to backfire in terms of achievementof ultimate policy goals such as decarbonizationand energy security.

UK renewable energy policy exists in a widerenergy policy context. The country’s statedenergy policy can be summed up as aiming toachieve “secure, affordable and low-carbonenergy” (see DECC n.d.b). It therefore has threeidentifiable priorities: addressing climate change,providing energy security, and keeping energybills down.These policy objectives are naturally intension.The first two are expensive, whereas tack-ling the third entails keeping prices down, if notfor everyone, then for a significant minority ofpoor consumers. Between 1990 and 2003, resi-dential electricity prices fell significantly in realterms in the United Kingdom, by around 30% perunit, but have risen by around 40% from 2003 to2008 (QEP 2009). The number of householdsdefined as being in energy (or fuel) poverty,spending 10% or more of total expenditure onheating and power, has risen from a low of 2 mil-

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lion in 2003 to 3.5 million in 2006 (BIS 2008),out of a total of around 25 million households(ONS 2007).This has put a strain on the ability ofricher consumers to simultaneously finance poorconsumers, via bill payments to company supportschemes (see Ofgem 2009b),2 and expensive poli-cies arising from climate change and energy secu-rity objectives. European Union (EU) directiveshave also provided significant shape to UK energypolicy, providing the basis for targets to 2020 forCO2 reduction and renewable electricity genera-tion share.

The chapter begins by reviewing the UnitedKingdom’s overall decarbonization policy andpotential for renewables, then its policy towardrenewables since 1990, with a particular focus onrecent developments. This is followed by anexamination of the evidence on the performanceof UK policy compared with that of other coun-tries. Next, a new institutional economics per-spective is used to discuss what sorts of policiesmight be right for the United Kingdom in thelight of the evidence. Finally, the chapter exam-ines the issue of overall policy toward decarbon-ization and the place of renewables within this.

Decarbonization Policy and thePotential for Renewable Energyin the United KingdomAn important context for the United Kingdom’srenewable energy policy is its overall decarboniza-tion policy. The country has one of the mostambitious decarbonization policies in the world,as embodied in the 2008 Climate Change Act(OPSI 2008a).3 This policy consists of a commit-ment to reducing net greenhouse gas (GHG)emissions by 80% by 2050 (from 1990 levels),with an intermediate target reduction of 26% by2020. This target is supported by five-year carbonbudgets, the first period being 2008–2012 inclu-sive.These budgets are formulated in the Office ofClimate Change and supported by a report fromthe independent Committee on Climate Change(CCC). Government ministers have a statutory

duty to introduce policies that support achieve-ment of the targets. The committee’s first report(CCC 2008) was published in December 2008.This gave indicative budgets for the periods 2008–2012, 2013–2017 and 2018–2022.The budget forany period beyond this must be set at least 12years ahead.

The report was then followed up by a signifi-cant discussion in the HM Treasury budget for2009 of policy measures aimed at supporting theachievement of the decarbonization targets in thelight of the report (see HM Treasury 2009).4 Theannounced measures included support for greenmanufacturing, improvements to the renewablesupport for offshore wind, increased funding forcombined heat and power, and a support mecha-nism for up to four carbon capture and storage(CCS) plants. The intention of the legislation isthat if the government were to fail to enact appro-priate policies to keep the United Kingdom ontrack to achieve its targets, this could result in legalaction against ministers by third parties, though itremains to be seen on what grounds any actionwould be likely to be successful, given the lessthan direct link between specific governmentpolicy and impact on a national GHG target.

For reference, in 2008, UK GHG emissionswere 623.8 metric tons of CO2e (CO2 equivalentunits), which is 20% below the 1990 baseline of779.9 tons (Defra 2008). This means the UnitedKingdom is the only major European country tohave already met and exceeded its 2012 Kyototarget for emissions reduction target, which was12.5% (see EEA 2006, Table 1). It is, however,worth pointing out that the UK target is the resultof negotiations within the EU to share out theKyoto-negotiated EU-wide target, and that thebaseline date of 1990 is very favorable to theUnited Kingdom. This is because it coincideswith the privatization of the UK power industry,leading to a “dash for gas,” which resulted in anunintended environmental windfall as dirtiercoal-fired plants were displaced from the system(see Newbery and Pollitt 1997). This favorablestarting place in which the United Kingdom findsitself is certainly a major factor in its relativeenthusiasm for decarbonization.5 The 2009 EURenewables Directive further commits the

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United Kingdom to a 15% target for renewablescontribution to total final energy consumption in2020 as part of the EU’s overall 20% renewablesby 2020 target. This further target is acknowl-edged and accepted in the CCC report. TheUnited Kingdom also has a specific annual targetfor the percentage of electricity from renewablesout to 2015 as part of its Renewables ObligationCertificate scheme, discussed later in this chapter.

The report suggests that by 2020, the share ofrenewables could be as much as 30% in total elec-tricity generation (CCC 2008, 208). It also dis-cusses the potential for the direct reduction ofemissions from buildings rather than via large-scale grid-connected electricity. This involves acombination of renewable heat and micro-generation. For residential buildings, it identifies apotential contribution of 14% reduction in heatemissions via a combination of biomass, solar hotwater, heat pumps, and biogas by 2020. In addi-tion, small contributions may be made by PV andother sources for microgeneration of electricity.

Recently, the newly created responsible gov-ernment ministry, the Department for Energy andClimate Change published its UK RenewableEnergy Strategy (DECC 2009f). In line with theCCC report, this suggested that more than 30% ofelectricity should be generated from renewablesby 2020, as well as 12% of heat and 10% of trans-port energy, in order to meet EU targets.

The United Kingdom’s commitment todecarbonization is likely to lead to a relativelytight domestic policy with strong pressure forpurchasing of renewable electricity and CO2 per-mits from abroad. In 2007, the country was a netpurchaser of CO2 permits to the tune of 26 tons,or 3% of its 1990 GHG level (Defra 2009). It alsopurchased energy via the interconnector withFrance (3% of total electricity delivered), whichmay have displaced higher-carbon energy in theUnited Kingdom, and was one of the largest netimporters of internationally traded bioenergy,mainly for cofiring in coal-fired power plants andfor blending in gasoline (DECC 2009b; Jungingeret al. 2008; Perry and Rosillo-Calle 2008). All ofthese have some scope for expansion in terms ofachieving the net decarbonization of the UKeconomy.

Given the ambitious targets for decarboniza-tion and renewable energy in the United King-dom, it seems highly likely that nationally thesetargets will be missed, certainly on renewables. Inthese circumstances, serious consideration will begiven to meeting the targets via net purchases ofCO2 or green energy certificates from abroad(e.g., funding CCS in China). Indeed, ifadditionality could be clearly established, thiswould seem to be a very sensible option given thatat the margin, such purchases would be muchcheaper than domestic alternatives.

A defining feature of the United Kingdom isthe considerable potential it has for renewableenergy relative to its demand. The country hassome of the best wind, tidal, and wave resourcesin Europe, as well as affording opportunities forbiomass and solar. The technical potential of eachof these resources is very great, but the estimatedeconomic potentials are given in Table 13.1. UKelectricity supplied in 2008 was 380 terawatt-hours (TWh) (DECC 2009b, Table 5.5).

In addition, it is worth mentioning that theUnited Kingdom has up to 1,000 years’ worth ofstorage capacity of CO2 in the North Sea andcurrently generates around 13% of its electricity

Table 13.1. Estimates of the likely economicpotentials for different renewable technologies in theUnited Kingdom

Technologycategory

Technologydetail

Annualpotential

Wind power Onshore 50 TWh

Offshore 100 TWh

Bioenergy Biomass 41 TWh

Geothermal Ground sourceheat pumps

8 TWh

Hydro Large scale 5 TWh

Small scale 10 TWh

PV Retrofitted andbuilding inte-grated

> 1 TWh

Marine Wave energy 33 TWh

Tidal barrage 50 TWh

Tidal stream 18 TWh

Total ~316 TWh

Source: Jamasb et al. 2008b, 81–82

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from nuclear power (DECC 2009b). The UnitedKingdom has endowments of coal, oil, and gas(though all three are depleting).Thus carbon cap-ture and storage and nuclear power are likely tocompete with renewables to play a part in decar-bonization of the electricity sector.The country isalready committed to an auction for one demon-stration CCS plant and is reviewing designs for anew generation of nuclear power plants, with anannouncement in November 2009 on its pre-ferred sites for new building (see DECC 2009c).Electricity demand growth is increasing slowly, ataround 1% a year, and energy efficiencymeasures—such as the elimination of filamentlightbulbs starting in 2011 (DECC 2009e) and theintroduction of smart metering for all electricitycustomers by 2020—seem likely to moderatedemand growth.

MacKay (2008, 109) predicts the likely con-tribution of renewables to UK decarbonization inthe context of delivering the current level ofenergy consumption of 125 kilowatt-hours perday per person. He suggests that renewables con-tribution is likely to be only 18.3 kWh/day/person, made up of the following: hydro, 0.3;tidal, 3; offshore wind, 4; biomass, 4; solar PV, 2(+ 2 from solar hot water); and onshore wind, 3.Thus renewable energy would contribute around15% toward total decarbonization. MacKay’sanalysis is helpful in that it illustrates that a bigcontribution toward current electricity provisioncomes in the context of electricity being thesource of only about one-third of current emis-sions of GHGs.

The exact mix of different renewable tech-nologies, CCS fitted to coal- or gas-fired plants,nuclear, and demand reduction in the UK energymix will depend on the relative costs of the differ-ent technologies. Kannan (2009) shows theimpacts of different assumptions on the signifi-cance of CCS in UK decarbonization and hencethe implications for other sources of decarboniza-tion. Demand reduction technologies are thecheapest GHG abatement technology at themoment (see CCC 2008, 221), though demandreduction measures suffer from well-known insti-tutional barriers to adoption (Grubb and Wilde2008). Nuclear is probably the next cheapest.

Among the renewable technologies in the UnitedKingdom, onshore wind, biomass, and offshorewind are lowest-cost at scale to 2020. Table 13.2shows some cost sensitivities for 2005.

The table illustrates large uncertainty in thecosts of building new plants, even with establishedtechnologies. For wind, this reflects the impor-tance of exact location, which determines bothbuilding costs and the available wind.The range ofcosts illustrates substantial overlap under favorableversus unfavorable circumstances for any pair oftechnologies. However, it is important to pointout that this uncertainty over actual costs for cur-rent new building does call into question projec-tions of costs to 2020. For instance, Dale et al.(2004) assume onshore and offshore new buildingcosts of £650 and £1,000 ($975 and $1,500) perkW, respectively, in scenarios with 25% energyfrom wind. The most recent (albeit prerecession)wind parks are currently costing nearer to £1,000and £2,500 ($1,500 and $3,750) per kW (seeBlanco 2009; and Snyder and Kaiser 2009).This issomewhat concerning, given a return tomacroeconomic growth, for the likely projectedcosts of renewable scenarios to 2020, especiallygiven that the costs of electricity (which willinclude cumulative subsidy commitments torenewables) in 2020 will still likely reflect, tosome extent, the cumulative cost of all windcapacity installed since 2005.

Table 13.2. Examples of estimated costs oftechnologies for the United Kingdom in 2005

Technology Technologydetail

p/kWh

Nuclear Generation III 3.04–4.37

Gas CCGTa with CCS 3.65–6.78

Coal IGCCb with CCS 3.5–5.67

Wind Onshore 4.68–8.89

Offshore 5.62–13.3

Source: Jamasb 2008b, 75.Notes: The spread of estimates reflects ranges in the discountrate, capital cost, fuel and carbon prices, and other sensitivities;p/kWh = pence per kilowatt-hour, given in 2005 values; 1 pence= 1.5 cents (U.S.) as of this writing.aCCGT = combined cycle gas turbinebIGCC = integrated gasification combined cycle



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As Jamasb et al. (2008b) note, a key determinantof the relative attractiveness of different technolo-gies will be the degree of learning in costs, andthis depends on their current stage of develop-ment. Foxon et al. (2005) note that the variousrenewable technologies available to the UnitedKingdom are at different stages of development.Wind costs can be expected to fall as capacityincreases significantly around the world; however,the prospects for learning in hydro and tidal bar-rages are low, limiting their ultimate scope forexpansion. The additional costs of fitting CCS aredifficult to estimate because of a lack of informa-tion, while the scope for learning may be con-strained by the maturity of the different elementsof the CCS process (see Odenberger et al. 2008).This is in addition to the difficulty of reconcilingall the interested parties (Drake 2009). PV, tidalstream, and other marine technologies offer thegreatest potential for decreases from the currentcosts, given low current levels of output and theimplied scope for cost reduction.6

SKM (2008) provides estimates of the possiblecost of decarbonization of the electricity sector to

2020. Under their estimates, renewables provide34%, 41%, and 50% of electricity supply underthe lower, middle, and higher renewables sce-narios. Table 13.3 shows that renewables couldimpose significant total costs on the electricitysystem. The capital costs of connecting offshorewind in particular could involve up to £15 billion($22.5 billion) of expenditure, more than the totalcost of generation under a conventional scenario.The cost of balancing and intermittency couldrise by up to £7 ($10.50) per megawatt-hour(MWh), or 10% of total system costs. The UnitedKingdom may have the wind resources, but theywill have significant cost implications for the sys-tem, raising average electricity costs by up to 40%against baseline.

Policies toward Renewables inthe United KingdomThis section provides an overview of UKrenewables policy since the privatization of the

Table 13.3. Costs of electricity sector decarbonization to 2020 (2008 prices)

Renewables scenarios

Conventional Lower Middle Higher

New generation capacity (£ billion)

Renewable capacity 2.3 50.1 60.2 77.4

Nonrenewable capacity 14.9 12.6 12.3 12.0

Total 17.2 62.7 72.5 89.4

Network (£ billion)

Offshore wind connection 0.0 8.4 10.6 14.1

Onshore wind connection 0.1 1.0 1.2 1.4

Other reinforcement 0.8 0.8 0.8 0.8

Total 0.9 10.2 12.6 16.3

Total grid investment costs(generation + network, £ billion)

18.1 72.9 85.1 105.7

Marginal generation cost (£/MWh) 35.9 25.0 22.6 18.9

Cost per MWh produced (£/MWh)

Generation costs (fixed and variable) 46.8 51.9 52.6 54.5

Balancing and intermittency 1.7 6.3 7.2 8.7

Grid expansion for renewables 0.1 3.5 4.1 5.2

Total cost including network (£/MWh) 48.6 61.7 63.9 68.4

Source: SKM 2008, 8Note: £1 = $1.50 as of this writing



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country’s electricity supply industry beginning in1990. Summarizing UK policy is not a straight-forward task because of the large range of govern-ment initiatives toward renewable energy and thegreat number of policy changes that have beenannounced in recent years, some of which haveyet to be implemented fully.7 Discovering theexact cost of renewable energy support is not easy,as evidenced by the fact that the best sources ofinformation are answers to parliamentary ques-tions rather than published annual statistics.This isparticularly true of the expenditure on individualtechnologies. The heroic efforts of Mitchell andConnor (2004), who reviewed UK renewablespolicy from 1990 to 2003, provided the inspira-tion for some of the presentation here.

In broad outline, there have been two mainsupport mechanisms for renewable electricity andheat generation since privatization in the UnitedKingdom: the Non-Fossil Fuel Obligation(NFFO), which ran from 1990 to 2002, and theRenewables Obligation (RO) scheme, whichbegan in 2002. During their period of operation,these have been the most significant forms ofrenewable energy support in the United Kingdomand were designed to work in parallel with liber-alized electricity and gas markets.

The assessment of renewable support policiesis complicated because there are two obviousmetrics of success: the amount of renewables real-ized relative to potential (quantity); and the totalcost of renewable energy support policy relative tothe amount of generation actually supported(suitably discounted). These two trade off, mean-ing that success in one is likely to be associatedwith less success in the other.

The Non-Fossil Fuel Obligation

The Non-Fossil Fuel Obligation (NFFO) wasoriginally designed as a way of financing the extracosts of nuclear power that became clear in therun-up to privatization. A non-fossil-fuel levy wasintroduced on final electricity prices to pay fornuclear decommissioning liabilities, and electri-city suppliers were forced to buy nuclear power athigher-than-market prices in auctions for non-fossil-fuel power run by the Non-Fossil Purchas-

ing Agency (NFPA).8 In order to avoid this beingseen as a discriminatory subsidy to the nuclearindustry, it was recast as a way of supporting non-fossil-fuel generation more generally, and a por-tion was allocated to support renewable energy(Mitchell and Connor 2004). The portion wassmall, but it provided a relatively significantamount of money to the industry at a time whengovernment expenditure on new technologieswas falling to a very low level, and the thenDepartment of Energy was closing. The moneywas allocated to new renewable projects via aseries of bidding rounds whereby renewableenergy projects bid for an (inflation-indexed) per-kilowatt-hour price for initially 8 and later 15years. Winning bids were selected by cost withineach technology category.

The result was a significant number of bids ineach of the auction rounds and falling bid costs ineach successive round.9 Connor (2003, 76)reports that in the five rounds of NFFO in Eng-land and Wales, onshore wind costs fell from 10pence (15.0 cents) per kWh in 1990 to 2.88 pence(4.3 cents) per kWh in 1998, with substantial fallsfor the other technology bands. Although NFFOwas successful in soliciting a large number ofcompetitive bids and in ensuring that any fundedprojects were cost-effective for electricity custom-ers, it failed rather spectacularly in one keyrespect: delivery of actual investment by the win-ning bidders.

Across the United Kingdom, between 1990and 1999, out of 302 awarded wind projects cov-ering 2,659 MW, only 75 projects were built,rated at 391 MW (Wong 2005). Spectacularly, notone of the 33 large wind projects awarded in thefifth round of NFFO in England and Wales wasever contracted. By contrast, out of 308 landfillgas projects awarded, 208 were operational in2008, with 458 MW of capacity out of 660 MWcontracted. For all the rounds of NFFO, out of933 awarded contracts, 477 were built, represent-ing 1,202 out of 3,639 MW (DECC 2009b, Table7.1.2). The primary cause for the failure was thatbidders were overoptimistic in their estimates ofthe actual delivery costs of the projects, oftenbecause the nature of the least-cost auction—withno assessment of likelihood of delivery—



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incentivized minimization of expenditure on pre-paring realistic bids (Mitchell and Connor 2004).

In reviewing the failure of the NFFO policy,it is important to remember the context in whichit operated. Renewables were then a very lowpriority for UK government policy, and it was aperiod of a rapid switch from coal- to gas-firedpower. Prices and pollution, in terms of quantitiesof CO2, SOx, and NOx, fell substantially. Thefocus on market-driven investments was good forenergy and carbon-efficient combined heat andpower (CHP) investment in the industrial andcommercial sectors (Bonilla 2006; Harvey 1994;Marshall 1993), which had struggled prior to pri-vatization (Jarvis 1986). UK privatization was asignificant policy success in economic terms,especially when the benefits to the environmentare considered (Newbery and Pollitt 1997).

The privatization and market liberalizationpolicies ensured that the United Kingdom wouldeasily meet its Kyoto targets for 2012 without anyfurther action, which was not the case for otherleading European countries. The mood at thetime was nicely summarized by a governmentminister for energy in 1988, Michael Spicer, whowrote that “privatisation of the electricity supplyindustry should boost the commercial prospectsfor these [green] technologies as a free market isestablished” (Elliott 1992, 266). Indeed, Friendsof the Earth was optimistic that the opening up ofthe residential energy market to competition in1998–1999 would give rise to demand for greentariffs and stimulate the production of greenenergy (Stanford 1998). It was only as the EUmoved toward substantial targets for renewablesthat it became clear that the United Kingdomneeded a policy that delivered large quantities ofrenewables.10 Nevertheless, significant lessons canbe learned from the NFFO experience.

Somewhat surprisingly, little quantitativeanalysis has been done on the bids that were suc-cessful under NFFO and the factors in their suc-cess and failure. Elliott (1992, 267) criticized theNFFO scheme as a “somewhat half-heartedhybrid market/interventionist system” that“would still leave short-term price and marketfactors to shape important long term strategicchoice concerning patterns of technological

development.” Institutional barriers emergedearly on as a critical factor in successful projectimplementation (McGowan 1991).

In particular, it became clear that projects hada problem with gaining the necessary consentsrequired to start building, known as “planningpermission” in the United Kingdom, and that alack of attention was given to proper environmen-tal impact assessments (Coles and Taylor 1993).Hull (1995) noted that in the early years, less thanhalf of all councils, the local government bodiesresponsible for consents, had planning guidancefor renewable energy projects, and more impor-tant, there was a lack of learning among councils.Calls came for clearer guidelines for the planningprocess to facilitate wind power (Roberts andWeightman 1994). Early industry views of thescheme were positive, recognizing that it did con-stitute a significant increase in expenditure overprevious levels (Porter and Steen 1996). However,the successive rounds of auctions were thoughtnot to provide assurance of continuity of supportfor renewables generally (Elliott 1994; Mitchell1995), and some worried that although they sup-ported near-market technologies, declines inR&D expenditure were bad for less advancedtechnologies such as marine (Elliott 1994).

The final years of NFFO, 1999–2001, coin-cided with a sharp decline in wholesale electricityprices as significant amounts of new gas-firedcapacity came into the market and competitionincreased within the initially duopolistic genera-tion sector (Evans and Green 2003). NFFO gen-erators had made overoptimistic bids, and theirsituation was exacerbated by the end of the com-pulsory wholesale power pool, which had guaran-teed the pool price to all generators, in March2001. It was replaced with a contract market and abalancing market. Imbalance between supply anddemand for an individual generator was nowmore likely to result in a financial penalty. Inter-mittent renewable generators were more likely toneed to participate in the balancing market to bal-ance their physical and contractual positions;because of the exogenous effects of weather, windgenerators have less capacity to match supply anddemand than fossil-fuel generators, who canadjust their spinning reserve. This is not necessar-



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ily inefficient, however, as generators should beincentivized to solve the imbalance problem. Theimpact of this effect seems to have subsided afterone year of operation of the new arrangements,partly as a result of the arrival of a more generoussubsidy regime when Ofgem (the independentUK agency responsible for electricity and gasregulation) found little evidence of negativeimpact from the change to the trading system onrenewable generators (see Ofgem 2002).

The Renewables Obligation Scheme

The Renewables Obligation (RO) scheme, whichreplaced NFFO in 2002, uses a form of tradablegreen certificates (TGCs), known in the UK asRenewables Obligation Certificates (ROCs).Under this plan, the government set a minimumshare of electricity to be acquired by electricitysuppliers from renewable sources (larger hydro-electric schemes in operation before 2002 are

excluded). This share is steadily increasing from2002 to 2015 (see Table 13.4). Under the ROscheme, electricity suppliers must acquire thesecertificates in the prescribed target share ofrenewable generation for each annual period.They can do this by buying or earning ROCs,which are created when renewable generatorsgenerate electricity.This essentially splits the mar-ket into two parts, renewable and nonrenewable,with renewable generators getting a price for theROCs they create plus the wholesale price ofpower.11

The UK scheme has two important featuresintroduced at its inception, however. One is abuyout price (i.e., a penalty price) for ROCs ifnot enough are created by renewable generation.This price is specified for each trading period andeffectively caps the price that creators of ROCscan receive. The other is recycling of the revenuecollected from the buyout sales of ROCs. This

Table 13.4. RO targets and delivery against targets

Target renewableshare in GBa

% delivery in UK Nominalbuyout price(£/MWh)

Total costb

(£ million)

2002–2003 3.0 59% 30 282

2003–2004 4.3 56% 30.51 415.8

2004–2005 4.9 69% 31.59 497.9

2005–2006 5.5 76% 32.33 583

2006–2007 6.7 68% 33.24 719

2007–2008 7.9 64% 34.3 876.4

2008–2009 9.1 65% 35.36 1,024.6

2009–2010 9.7 37.19

2010–2011 10.4 + inflation thereafter

2011–2012 11.4

2012–2013 12.4

2013–2014 13.4

2014–2015 14.4

2015–2016 15.4 Estimated: ~1,733(2008–2009 prices) assumingno demand growth

Sources: OPSI, 2009; and Renewables Obligation annual reports from Ofgem various dates.Notes: From 2016, the share was fixed at 15.4% until 2027, now extended to 2037 for new projects; RO scheme cost is total cost includingrevenue recycling; £1 = $1.50 as of this writingaTarget share lower in Northern Ireland, but NI ROCs are tradable throughout UK. There is also a nominal distinction between Scottish ROCs(SROCs) and English and Welsh ROCs (ROCs), but these are tradable, and both are included in the GB target share.bWe report costs based on multiplying the buyout price by the actual ROC requirement. There appear to be small discrepancies in the actualreported payments and this figure in Renewables Obligation annual reports from Ofgem.



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takes the form of allocating the revenue back tothe creators of ROCs in proportion to thenumber they created.

The renewable energy industry was very posi-tive about the new incentive mechanism (Hill andHay 2004). So they should have been, because thescheme is very generous. Thus for example in2007–2008, the buyout (penalty) price was£34.30 ($51.45) per MWh, and only 64% of therequired ROCs were created by generators,meaning the buyout price was binding in the cer-tificate market. The total payment by supplierswas the target quantity of renewables multipliedby £34.30 ($51.45) per MWh. This meant that36% of the total ROC payment made by supplierswas available to be recycled and was divided pro-portionally among the generators who createdactual ROCs. Accordingly, for each ROC actuallypresented, the renewable generators received£34.30 plus £18.65 ($27.98) (i.e., an additional36/64 times £34.30 less costs of the scheme)Thissum is in addition to the wholesale cost of power.As the total cost to suppliers of the ROC schemewas £876 million ($1,314 million), this impliesthat consumers overpaid, relative to what wasnecessary to secure the renewable generationactually supplied, by at least the value of thebuyout revenue of around £315 million (36% of£876 million [$1,314 million], or 1% of the totalelectricity expenditure of £30.7 billion [$46 bil-lion] in 2008) (DUKES 2009).12 Interestingly, thegovernment collects the associated ROC pay-ments on the generation contracted under NFFOvia the NFFO fund, which creates a surplus abovethe payments to generators under that program;this surplus is estimated to be around £200 mil-lion ($300 million) per year (Tickell 2008).

The RO scheme is curious for two reasons.First, it relies on underdelivery to trigger themaximum subsidy amount. If the target numberof ROCs (or more) were presented, then theprice would drop to zero. Second, in the case ofunderdelivery, the maximum amount of subsidy ispaid to those actually creating ROCs. Thus thescheme assumes failure to meet the target andensures that a fixed total subsidy is paid, given this,regardless of how few ROCs are created.

The scheme is further complicated by theintroduction of “banding” starting on April 1,2009 (see Table 13.5). This changes the exchangerate to ROCs of some renewable generation:established technologies will get less than 1 ROCper MWh, newer more. This change breaks thelink between the total number of ROCs and theshare of renewable energy generation and willpresumably result in a reduced amount of elec-tricity being produced from renewables if thescheme is fully successful (if the share of high-exchange-rate technologies were to take off, as itmight with offshore wind). The Carbon Trust

Table 13.5. Banding of ROCs from April 1, 2009

Generation type ROCs per MWh

Landfill gas 0.25

Sewage gas0.5

Cofiring of biomass

Onshore wind

1.0

Hydro

Cofiring of energy crops

Energy from waste with CHP

Cofiring of biomass withCHP

Geopressure

Standard gasification

Standard pyrolysis

Offshore wind

1.5Biomass

Cofiring of energy cropswith CHP

Wave

2.0

Tidal stream

Advanced gasification

Advanced pyrolysis

Anaerobic digestion

Energy crops

Biomass with CHP

Energy crops with CHP

Solar photovoltaic

Geothermal

Tidal impoundment—tidalbarrage

Tidal impoundment—tidallagoon

Source: DECC 2009d



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(2006) recommended the move to banding torecognize the different stages of development thatthe technologies had reached, and hence thehigher learning benefits associated with increasedfunding to earlier-stage technologies. Oxera(2005) points out the cost implications of allowingNFFO plants to earn ROCs once their NFFOcontracts expired (around £620 million [$930million]), giving those projects unexpected addi-tional subsidy. Oxera calculated that as much ashalf the payment via ROCs was in excess of thatrequired to ensure that the funded projects wentahead, and that existing landfill gas projects didnot require any ROCs to be economically viable.

The scheme, as shown in the table, impliesthat the subsidy to offshore wind could beincreased by £26.47 ($39.71) per MWh (50% ofthe 2007–2008 ROC revenue) and to tidal by£52.95 ($79.43) per MWh (100% of the 2007–2008 ROC revenue). In the 2009 budget, off-shore wind was subject to an emergencyrebanding provision, which saw the offshore windROC band go to 2 for 2009–2010 and 1.75 for2010–2011, now increased back to 2 from 2010–2014.

Policy Costs and Deliveryunder NFFO and RO

Table 13.6 summarizes the financial commitmentsmade under the NFFO and RO schemes, as wellas a reference amount for the amount of publicR&D expenditure reported to the InternationalEnergy Agency (IEA). The increased significanceof the RO scheme is evident.

While the RO scheme is the most significantelement of the United Kingdom’s expenditure onrenewables, it is not the only element. Table 13.7is a summary offered in a ministerial answer to aparliamentary select committee question. It isnoteworthy that significant additional amounts arestill being spent by the taxpayer on supportingearlier-stage technologies outside the CO2 priceand RO support mechanisms. However, the orderof magnitude of energy customer support forrenewables is of the order of £1.8 billion ($2.7billion) in 2008, in addition to £400 million($600 million) by the taxpayer. This level of sup-

port is up 47% in real terms from the figure esti-mated by Wordsworth and Grubb (2003) of £1.3billion ($1.95 million) in 2002–2003.13

As the above discussion of the progress withthe RO scheme has made clear, the developmentof electricity from renewables has been disap-pointing in terms of overall cost relative to deliv-ery, given the United Kingdom’s resource poten-tial and ambitious targets.Table 13.8 gives the fig-ures in terms of total electricity generation. Anumber of features stand out. First of all, electri-city from biomass in 2008 is larger than that fromwind. Hydro remains significant within the UKrenewable portfolio. Connor (2003) reported esti-mates from 2002 that suggested the United King-dom would meet only two-thirds of its target levelby 2010. This still seems likely. However, thestriking thing about the 2002 estimates is that forbiomass, offshore wind, and hydro, they seemlikely to be met or exceeded, though not byonshore wind. The United Kingdom is failing tomeet its projections for renewables as predicted,

Table 13.6. Financial support (£ million) forrenewables in the United Kingdom (nominal)

R&D RO NFFO

1990–1991 14.7 6.1

1991–1992 17.1 11.7

1992–1993 16.1 28.9

1993–1994 15.2 68.1

1994–1995 9.1 96.4

1995–1996 9.1 94.5

1996–1997 6.2 112.8

1997–1998 4.3 126.5

1998–1999 3.3 127

1999–2000 4.6 56.4

2000–2001 4.4 64.9

2001–2002 6.1 54.7

2002–2003 10.5 282.0 -

2003–2004 11.6 415.8 -

2004–2005 19.7 497.9 -

2005–2007 36.6 583.0 -

2006–2007 49.5 719.0 -

2007–2008 41.6 876.4 -

Sources: UK government renewable R&D budget data from IEA2009; Mitchell and Connor 2004, 1943



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but this is largely due to the failure to deliver thelong-expected increase in generation fromonshore wind.

Both NFFO and RO have stimulated electri-city from landfill gas and cofiring of biomass andmunicipal waste (with fossil fuels). These tech-nologies were near market in the early 1990s andhad good prospects at that time. Brown andMaunder (1994) discuss the United Kingdom’spotential for exploiting landfill gas, and Jamasb etal. (2008a) explore the prospects for waste toenergy, noting it has significant further potential,especially if CHP is involved. The use of biomassfor cofiring in coal-fired plants continues to beone of the most sensible uses of biomass, as it iswell proven that mixes of up to 10% biomassrequire little adjustment to existing plants(Thornley 2006). Small hydro projects have also

had some success, with a steady increase in hydrogeneration from these schemes.These projects useestablished technology and have benefited frommarket-based support mechanisms. Paish (2002)highlights around 400 MW of further potentialfor small-scale hydro in the United Kingdom.

There also have been promising developmentswith offshore wind in the United Kingdom,assuming the actual delivered costs can be keptdown. As of August 2009, offshore wind capacityis currently 598 MW, but an additional 1,246MW are under construction, and a further 3,613MW have been consented. This contrasts with3,730 MW of onshore wind capacity, with only930 MW under construction and 3,275MW con-sented (BWEA n.d.).

It seems likely, given the continuance of highlevels of support via banded ROCs, that offshore

Table 13.7. Support for renewable energy in 2007–2009

Scheme Description Cost Paid by

Renewables ObligationCertificates

Electricity suppliers must buy a proportion oftheir sales from renewable generators or pay abuyout charge

£874 million in 2007–2008

Electricityconsumers

EU Emissions TradingScheme

Renewable generators indirectly benefit from theincrease in electricity prices as other companiespass the cost of emissions permits into the priceof power

Perhaps £300 million in2008, given current per-mit prices

Electricityconsumers

Carbon EmissionsReduction Target

Energy companies must install low-carbon itemsin homes, which could include microgenerationfrom 2008

Total cost will be £1.5billion over 3 years,mostly spent on energyefficiency

Gas and electricityconsumers

Renewable TransportFuel Obligation

Fuel suppliers must supply a proportion ofbiofuels or pay a buyout charge

No more than £200 mil-lion in 2008–2009

Consumers

Climate Change Levy Electricity suppliers need not pay this tax (passedon to non-residential consumers) on electricityfrom renewable generators

£68 million to UK genera-tors, £30 million to gen-erators abroad in 2007–2008

Taxpayers, viareduced revenues

Lower fuel duty forbiofuels

The rate of fuel duty is 20 pence (30 cents) perliter below that for petrol and diesel

£100 million in 2007 Taxpayers, viareduced revenues

Environmental Transfor-mation Fund

Grants for technology development and deploy-ment, including subsidies for installing renewablegeneration, planting energy crops, and develop-ing biomass infrastructure.

£400 million over 3 yearsstarting in 2008–2009

Taxpayers

Research councils Grants for basic science research £30 million in 2007–2008 Taxpayers

Energy TechnologiesInstitute

Grants to accelerate development (after the basicscience is known) of renewables and otherenergy technologies

Allocation and eventualsize of budget not yetannounced

Taxpayers and spon-soring companies

Source: House of Lords 2008, Table 6 Note: £1 = $1.50 as of this writing



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wind will overtake onshore wind generation,albeit on the back of very disappointing deliveryof onshore wind projects.

Looking at the success of the NFFO and ROschemes, NFFO did well on cost of the policy butnot as well on quantity of renewables delivered,whereas RO did better on quantity delivered butmuch less well on cost of the policy.

Other Renewables Policies

While the main support mechanisms have favoredwind and biomass, direct government funding hasalso helped the marine industry. A resurgence inresearch and demonstration funding in the last 10years has resulted in some positive developments

(see Mueller and Wallace 2008).The first 1.2 MWtidal stream plant was installed in 2008 (Riddell2008), and the industry is well placed internation-ally to exploit this and related marine technolo-gies (Elliot 2009). The UK government is cur-rently conducting another feasibility study of the8.5 GW Severn Barrage, which could generate5% of the country’s current electricity demand.This is the biggest of the United Kingdom’spotential tidal projects (Conway 1986), but costand environmental issues remain to be addressed(see DECC 2009f). However, a trial with asmaller scheme first, such as a barrage across theMersey, would seem sensible for learning thatmight benefit the much larger Severn project.

Table 13.8. Renewable electricity generation (GWh) in the United Kingdom, 1990–2008

1990 2000 2001 2002 2003 2004 2005 2006 2007 2008

Wind

Onshore wind 9 945 960 1,251 1,276 1,736 2,501 3,574 4,491 5,792

Offshore wind 0 1 5 5 10 199 403 651 783 1,305

Solar photovoltaics 0 1 2 3 3 4 8 11 14 17

Hydro:

Small scale 91 214 210 204 150 283 444 478 534 568

Large scale 5,080 4,871 3,845 4,584 2,987 4,561 4,478 4,115 4,554 4,600

Biofuels:

Landfill gas 139 2,188 2,507 2,679 3,276 4,004 4,290 4,424 4,677 4,757

Sewage sludgedigestion

316 367 363 368 394 440 470 456 496 564

Municipal solidwaste combus-tion

221 840 880 907 965 971 964 1,083 1,177 1,226

Cofiring withfossil fuels

286 602 1,022 2,533 2,528 1,956 1,613

Biomass 0 410 743 807 947 927 850 797 964 1,155

Total Biofuels and wastes 676 3,796 4,493 5,047 6,174 7,364 9,107 9,288 9,270 9,315

Total Renewables 5,857 9,828 9,516 11,093 10,600 14,147 16,940 18,136 19,646 21,597

Total Generation 319,701 377,069 384,778 387,506 398,209 393,867 398,313 398,823 397,044 389,649

% Total Renewables 1.83% 2.61% 2.47% 2.86% 2.66% 3.59% 4.25% 4.55% 4.95% 5.54%

Wind 0.00% 0.25% 0.25% 0.32% 0.32% 0.49% 0.73% 1.06% 1.33% 1.82%

Hydro 1.62% 1.35% 1.05% 1.24% 0.79% 1.23% 1.24% 1.15% 1.28% 1.33%

Biofuels 0.21% 1.01% 1.17% 1.30% 1.55% 1.87% 2.29% 2.33% 2.33% 2.39%

Source: Digest of UK Energy Statistics, various issues



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PV has relied on direct government supportfor installation programs that have involved only asmall number of installations, mainly funded viathe government’s Industry Department (DTI,then BERR) under the Low Carbon BuildingsFund. This funding has installed only a few hun-dred PV systems. The degree of satisfaction withthe technology among the recipients of fundinghas been positive (Faiers and Neame 2006), but alack of significant sums of money and properassessment of the learning from the policy hasbeen noted (Keirstead 2007). This is in spite of awell-regarded R&D plan for solar being put inplace in the 1990s (Stainforth et al. 1996) andwork showing that significant community instal-lations of solar would not pose any local gridproblems (Thomson and Infield 2007). The gov-ernment has made two very recent changes to itsrenewables policy, which are relevant to anyassessment of the need for reform of the currentarrangements (allowed for in primary legislation(OPSI 2008b)).

First, a feed-in tariff (FIT) for small-scale low-carbon generation commences in April 2010 (seewww.fitariffs.co.uk/). This will be for renewableelectricity generation up to 5 MW and fossil-fuelCHP up to 50 kW. Meant to encourage PV,small-scale wind (including microwind),microhydro, and micro-CHP, this policy respondsto industry concerns about the lack of ambition inmicrogeneration policy (Lupton 2008).

The second policy is a Renewable HeatIncentive (RHI) (see www.rhincentive.co.uk).This has the potential to be a significant policycovering all scales of production: household,community, and industrial. It is intended to drivethe share of renewable heat to 14% (though this isnot a firm target) up from 0.6%. It could cover airsource heat pumps, anaerobic digestion to pro-duce biogas for heat production, biomass heatgeneration and CHP, ground source heat pumps,liquid biofuels (but only when replacing oil-firedheating systems) and solar thermal heat and hotwater.

The scheme is not finalized at the time ofwriting and is due to commence in April 2011.

An Assessment of RenewablesPoliciesA 20-year view of UK renewables policy suggestsa failure to translate the country’s early resource-based promise into actual delivery of renewableenergy. It would be wrong to suggest widespreadpolicy failure, however. The United Kingdom ismaking progress on decarbonization and hasstrong and increasingly comprehensive policies inplace, covering electricity, heat, and transport (viapolicies toward electric vehicles and biofuels).

Two points are worth making at this stage.First, renewable energy policy remains an expen-sive gamble for all countries. Second, it is unclearwhat part particular renewable technologiesshould play in decarbonization to 2050.

As Helm (2002) has pointed out, a sensiblyhigh and stable price of carbon is the startingpoint for all economically feasible decarboniza-tion policies. In the absence of this, it is virtuallyimpossible to establish proper signals for maturetechnologies and near-market technologies,whose response to the proper price signal deter-mines how fast the country needs to accelerateless developed technologies. This is particularlytrue for nuclear, CCS, and demand reductioninvestments, many of which are being delayed bylow, volatile, and uncertain prices for carbon.TheUnited Kingdom, with its diversified energy sys-tem, exposure to world energy markets, andopenness to both nuclear and CCS, has keenly feltthe lack of a proper carbon price signal.

As Nelson (2008) discusses, the failure to set asufficiently tight cap on CO2 at the EU levelmakes UK renewables policy meaningless as apolicy for decarbonization. More renewable elec-tricity generation within the EU Emissions Trad-ing System (ETS) simply causes fuel switching inthe fossil plants from gas to coal, not to mentiondelaying nonrenewable low-carbon investmentsin CCS and nuclear. In this context, UKrenewables policy has been somewhat conserva-tive with respect to funding levels under NFFOand to renewable energy targets under the ROand, until recently, unwilling to pick winners. AsEikeland and Sæverud (2007) point out, however,



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the ending of the United Kingdom’s status as anenergy exporter in 2003 and the associated rapiddecline in oil and gas reserves have led to areawakening of energy security concern as amajor driver of UK energy policy.This is likely toexplain substantially increased interest in deliver-ing more domestic renewable capacity.

Failure to deliver large quantities ofrenewables so far is not a particular issue, in thatdelay will probably mean lower costs of exploita-tion (resulting from learning by doing elsewhereand learning by research) when they are finallyexploited. The unfortunate aspect of the RO sys-tem is its failure to deliver cost-effectively therenewables that it has delivered. This has been aserious design flaw, and the inability of the UKgovernment to learn and correct the flaw does notbode well for any other long-term mechanism putin place to support renewables. Nevertheless,given the targets for delivery that exist within thescheme, it is clearly important to consider whythe scheme has not delivered the quantity ofrenewables intended.The failure of the scheme todeliver overall lies squarely with one particulartechnology: the failure to deliver sufficient quan-tities of onshore wind.

Onshore Wind and the Planning Problem

The standard reason given for the delivery failureis difficulties in getting new wind farms throughlocal planning processes. Whereas conventionalpower plants can easily be built on existing sitesand require national-level planning consents,wind farms are often small in terms of MWcapacity and require local planning permission ifless than 50 MW, which covers most onshoreinstallations.14 Evidence has consistently shownthat gaining planning permission is a seriousobstacle to the development of wind farms or,more precisely, that the costs of obtaining permis-sion are often prohibitive in terms of imposeddelays, negotiation costs, and planning restrictionson the precise nature of the final investment.

In the United Kingdom, local planning deci-sions typically involve an applicant, such as a windproject developer, making a planning application.This includes the submission of detailed plans and

an impact assessment to the relevant local govern-ment authority.The application is initially assessedby a local planning officer, who makes recom-mendations on the plans to the relevant group ofelected local councilors for the area, who in turnvote on the proposal. Plans would be available forpublic consultation, and objections could beraised during the review period. Planning applica-tions can be granted subject to conditions andobligations. This process might result in a numberof iterations in the plans. Should permission berefused, the applicant can appeal the decision, inwhich case a costly public inquiry would ensue.The relevant central government department alsohas the right to disallow a locally approved plan-ning application so objectors can appeal to therelevant government minister. At the nationallevel, plans need to be submitted to the relevantgovernment department for referral to the secre-tary of state for final decision. Objections can beraised to these plans according to the planningguidelines. This national-level process is beingstreamlined, as below.15

The average time for local and national plan-ning decisions on onshore wind in 2007 was 24months, with approval rates of 62% (Chamberlain2008, 21). For large projects, the Ministry ofDefence, National Air Traffic Control, and civilairports were major objectors. Attempts have beenmade since 2007 to obligate local councils to settarget levels of energy from renewables for newdevelopments. The 2008 Planning Act (see OPSI2008c) allows for setting up an InfrastructurePlanning Commission to decide on large onshorewind farms (greater than 50 MW) as well as largeoffshore projects (greater than 100 MW) (seeNAO 2008, 40–41, for a discussion).

The literature has dug more deeply into theplanning problem. Hedger (1995) highlights thatwind power development involves a clash of plan-ning cultures: land use versus energy supply. Thefirst is fundamentally local, participatory, and con-cerned with preserving rural landscapes; the sec-ond is fundamentally national, top-down, andconcerned with delivering technological solutionsto national energy supply requirements. Thesecultures were bound to clash in onshore windpower development.



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Mitchell and Connor (2004) stress that theemphasis on cost minimization, combined withthe tying of subsidies to particular locations andplans, meant that many successful NFFO bidsfailed to get through the planning process. Thiswas because the bidders were not able to invest inlocal engagement or respond to the outcome ofthe engagement process by modifying their pro-posals. Indeed, the competitive nature of NFFOmeant that often the bidders had to keep prospec-tive locations secret and did not engage in localconsultations prior to bidding. Toke (2005b)found that for the projects he examined from thethird through fifth NFFO rounds in England andWales, 47 were granted planning permission, 47refused planning permission, and 96 did not makeor complete an application.16

The main reasons given for planning objec-tions were visual amenity impairment and worriesabout noise (Eltham et al. 2008). These gave riseto concerns about economic effects on houseprices and tourism. The United Kingdom is adensely populated island, with many areas oflower population and high ground located innational parks or other places that attract tourists.Increasing numbers of residents or second-homebuyers have been moving to such areas for theirvisual amenities rather than employment reasons(see Strachan and Lal 2004 for a discussion of thedebate around tourism). The decline of employ-ment in farming and rural industries has reducedthe scope for arguments based on the smallnumber of permanent jobs that might be createdin the energy sector, because increasing percent-ages of people living in the countryside work innearby conurbations and are not looking foremployment in local industries.

Rural environmental protection and localcommunity action groups thus had strong incen-tives to organize opposition to individual windfarm projects, although in some cases tourismactually increased after wind turbines wereinstalled, and the noise from a modern turbinethat is 500 meters away is no more than in a quietbedroom (Strachan and Lal 2004). A number ofstudies (e.g., Eltham et al. 2008; Warren et al.2005) have shown that attitudes to wind farmsconsistently improve after construction, with

many people’s fears not being realized. It is alsotrue that in general, majority support exists fornew wind farms, but there are a significantnumber of both local and nonlocal objectors togiven schemes (Warren et al. 2005). This suggestsa social gap or democratic deficit at the local levelthat needs to be overcome (Bell et al. 2005) inorder to connect national policy delivery withlegitimate local concerns.

Rather surprisingly, little systematic study hasbeen done of success rates in individual localauthority areas or by individual developers orownership type. OnlyToke (2005b) has attempteda regression analysis, looking at planning permis-sion acceptance and refusal for wind projectsbased on a sample of 51 proposals. Among hisfindings is that if the local planning officers (whoprocess applications and make recommendationsto the local councilors who vote on the applica-tion) object, then projects are almost alwaysrefused, whereas if they accept a project, it is likelyto go through on appeal.Toke also finds that if theCampaign to Protect Rural England, which cam-paigns “for the beauty, tranquillity and diversity ofthe countryside” (CPRE n.d.), objects to aproject, it is likely to be opposed by the localparish council. One developer, Wind Prospect(2008), which has a joint venture with EDF, amajor energy company, to develop onshore windfarms in the United Kingdom, has invested heav-ily in local consultation and seems to have beenmore successful in gaining planning permission(see Toke 2005b). Active community involvementhas led to successful development in some cases,particularly when the community owns shares inthe wind farm, but these are small in capacityterms.17 However, under both NFFO and RO,there has been an unwillingness to actively involvecommunities in co-ownership of onshore winddevelopments, possibly because of the dominanceof large power companies within the UK windpower sector and the high transaction costs ofsuch engagement.

Overall, it is difficult to tell whether the fullcost of developing wind power onshore is actuallymuch higher than it would appear, given thesocial value of the UK countryside, or whether afeasible redistribution of the current benefits



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toward potential local objectors would be enoughto solve the planning problem. Bergmann et al.(2008) use willingness-to-pay modeling of a sam-ple of rural and urban dwellers in Scotland. Whileboth groups value reduced environmental impactfrom power generation highly, the authors findthat urban dwellers are willing to pay more for anoffshore wind farm than for an equivalent largeonshore wind farm and value the rural employ-ment opportunities less than do rural people. Theactual construction costs of wind farms in theUnited Kingdom are difficult to come by, but theinformation that is available suggests thatsimulations of the likely penetration of newprojects are still based on optimistic assumptionsthat wind costs will be much cheaper than theycurrently are.18 High actual costs may therefore bea factor delaying investment. The achieved loadfactors for the whole UK wind portfolio in 2008were 27% for onshore and 30.4% for offshore(DECC, 2009b, 206) in contrast to higherassumptions in some calculations (e.g., Dale et al.2004, who assume 35% for both onshore and off-shore wind).

No doubt smaller, more local developmentswould facilitate reduced planning objections, butthey would come with their own higher costs.The move to FITs for such smaller developmentsshould help increase the number of such projects.However, in examining scenario rankings fromdifferent wind actors in northwest England,Mander (2008) finds that expansion of offshorewind was the only part of a wind strategy thatboth pro-wind and pro-countryside lobbies couldagree on, even if onshore wind became morecommunity-driven. Attempts to streamline theplanning process have been made, with significantreforms to the appeals process in 2003 (Toke2003), giving more power at the national level;nevertheless, there is clearly still an issue of gettingpermission. Attempts in 2005 to streamline theplanning process in Wales (under a devolvedadministration) have had mixed success (Cowell2007). The Welsh Assembly designated “strategicsearch areas,” which were assessed to be moresuitable for large wind farm developments andhence more likely to be approved on appeal.These proved controversial, with both pro- and

anti-wind lobbies. The wind developers wereunhappy that many proposed schemes lay outsidethe designated areas, and anti-wind groups wereunhappy with where some of the boundaries ofthe acceptable areas were drawn.

BiomassBiomass is likely to be the second-largest renew-able energy source out to 2020 in the UnitedKingdom. Biomass is frequently cited as a signifi-cant, albeit finite contribution to UK decarbon-ization (of the order of up to 5%) (seeTaylor 2008for a review). Biomass policy toward waste hasbeen largely successful because of the near-marketnature of the technology and its responsiveness toboth NFFO and RO subsidies. The direct burn-ing of biocrops has also been successful, given theemerging global market in tradable biomass fromcountries such as Brazil, Canada, and the UnitedStates (Junginger et al. 2008).

Government support for local biocrop plantshas proved problematic, however, given the tech-nological, planning, and economic constraints. Ahigh-profile project involving local biomass andnew technology failed as a result of financing con-cerns (Piterou et al. 2008), and it is difficult tojustify the use of local biocrops for anything otherthan direct burning in existing coal-fired powerstations in direct competition with internationallytraded biomass, which is usually produced moreefficiently abroad. Nevertheless, some focusgroup studies have suggested that there is publicsupport for the use of local biomass in small CHPplants and skepticism about the overall GHGimpact of the use of internationally tradedbiomass (see Upham et al. 2007).

It is not environmentally sensible to use localbiocrops to produce biofuel in the United King-dom. Local biocrops produce more GHG impactwhen directly burned to produce power and heat(Hammond et al. 2008). Indeed, in the longerrun, the current use of biofuels to blend withpetrol and diesel may be phased out as the vehiclefleet is electrified (for current use, see Bomb et al.2007). The difficulty of making a sensible indus-trial policy argument for a local crop-dedicated



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biomass power plant within a viable long-rundecarbonization strategy is helpfully discussed byvan der Horst (2005). Indeed, Slade et al. (2009)criticize UK bioenergy policy as being character-ized by lots of initiatives but with a lack of clarityas to precise objectives to be delivered. If thecountry were to rely on internationally tradedbiomass as its key input, this would require bettercertification as to the source of the biomass (vanDam et al. 2008).

Bioenergy, with its complicated supply chain,displacement impacts, and total production cyclesustainability impacts, requires proper pricing ofall its environmental effects, including GHGs andlocal pollutants, in order to calculate whether it isworthwhile (Elghali et al. 2007). The life cycleGHG impact of biocrops (i.e., the impact on theamount of carbon stored in the stock of growingcrops) is further complicated by the carbon stor-age impacts of increasing the area set aside forgrowing them (Cannell 2003).

UK Performance versus That ofOther CountriesThe discussion so far indicates that comparativeassessment of UK policy on renewable energywould not be straightforward. It is clear that theUnited Kingdom has pursued a successful decar-bonization strategy to date and that relative suc-cess has been achieved in several areas, both inresponding to price signals and in developing newtechnologies for deployment in the country. Theone area of failure is in deployment of onshorewind at least cost. The net environmental impactof this failure is currently zero, given that theUnited Kingdom is on course to meet its GHGreduction targets. Still, this environmental per-formance could have been delivered at lower cost.The excess costs of the current set of policies arehard to estimate, given the diversity of supportinstruments. However, a lower-end estimatewould be the amount of revenue recycling withinthe RO mechanism, as this overpayment seemslargely unnecessary to deliver the observed quan-tity of renewables connected to the electricity sys-

tem.19 This excess cost is significant and rising.Nevertheless, it remains small compared with thehigh cost of the renewable deployment strategiesof some other countries, such as Germany andSpain, which have not allowed them to meet theirGHG reduction targets.

It is fashionable to suggest that the root causeof the problem of underdelivery of onshore windis the use of a tradable green certificate (TGC)scheme rather than a FIT, as used in Germany andSpain (see, e.g., Butler and Neuhoff 2008;Jacobsson et al. 2009; Lipp 2007; Meyer 2003;Toke 2005a; Toke and Lauber 2007). A more bal-anced assessment by the International EnergyAgency (IEA 2006) of the UK renewable energypolicy points out that TGCs have worked well (atleast to the date of the IEA’s assessment) in anumber of jurisdictions, such as Texas, Sweden,Australia, and New Zealand. It is only in theUnited Kingdom where they seem to have mani-festly failed to deliver the intended capacity.

Two common theoretical arguments havebeen made for the superiority of FITs overTGCs.One is that by offering a fixed price per kWh todevelopers, this allows new renewables to befinanced more easily.The other is that FITs attractlarge quantities of renewables because these arenot limited to the most attractive sites.

The first argument is well put by Mitchell etal. (2006), who maintain that the UK RO schemeexposes renewables to price, volume, and balan-cing risks, rather than just volume risks as under aFIT. Although this clearly does impose costs, it isnot clear that it is suboptimal or that it explainsnondelivery against the United Kingdom’srenewables targets. Higher risk is relevant to non-delivery where development is small-scale and thedevelopers have little or no credit history; herethere may well be a significant market failure inthe market for external finance. However, it israther a weak argument when the ultimate devel-opers are mostly large multinational companiesmaking portfolio investments, and when mostROC credits are bought by the six multinationalsupply companies who dominate the UK market,each with generation interests and the option toinvest directly in renewable capacity.



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The second argument makes less theoreticalsense, because it is not clear why developing themost attractive sites first is not desirable in anycase. The quantity of renewables forthcoming isclearly accelerated by offering initially highreturns, but offering a margin for renewables toattract investors is a function not of whether thesubsidy regime is a FIT or TGC, but of how largea quantity of renewables is required under eitherscheme. TGCs can set ambitious targets, as in theUnited Kingdom, and can deliver attractiveprices. Low prices for renewables are not a prob-lem with the ambitious RO targets.

In the end, the question becomes whether theUnited Kingdom would have delivered moreonshore wind capacity had there been a FIT forwind energy. For community schemes, the answeris quite possibly yes, because the uncertainty ofindividual project cash flows may well have beenan issue for funders. However, for larger schemeschiefly owned by multinational energy compa-nies, it is hard to say.The problem has clearly beenrelated to planning permission, and it is not obvi-ous how changing the funding regime improvesthe prospects for gaining planning permissionunless it is more generous and offers scope forproviding attractive payments to the local com-munity.

The literature seems to suggest that two morefundamental dimensions are of interest to explainthe differences in delivery of onshore wind amongthe United Kingdom, Germany, Spain, and Den-mark: land use constraints and local involvementin ownership, such as via local cooperatives orfarmers (see Table 13.9).

Local ownership, which is very high in Den-mark and also notable in Germany, is a determi-nant of successful strategic deployment in thesecountries (Szarka and Bluhdorn 2006; Toke2007). This is important because these two coun-tries face similar land use constraints to the UnitedKingdom. The development in Spain, however,has occurred with similar ownership of windassets by multinational companies, but in the con-text of very little land use constraint (Toke andStrachan 2006). Thus it seems clear that thesecountries have different institutional and physicalstarting points than the United Kingdom.

Econometric modeling by Soderholm andKlaassen (2007) of diffusion rates of wind poweracross Europe confirms that the United Kingdomhas lower diffusion (penetration) relative to othercountries, and that FITs do tend to be more suc-cessful in encouraging diffusion, but that a givenFIT would likely have less of an impact here thanin Germany.

What is clear is that the financial cost of windpower delivered onshore is unnecessarily high inthe United Kingdom. Butler and Neuhoff (2008,1856) show that while the NFFO schemes didresult in much lower support prices for wind inthe United Kingdom than in Germany, they werenot that much lower once adjusted for the qualityof the underlying wind resources. Under the RO,renewable support costs are estimated to havebeen twice as high in 2006 as they would havebeen under a German support tariff applied toUK wind resources (which would have beenlower than the actual tariff in Germany). Toke(2005a) shows that the RO scheme with revenue

Table 13.9. Differences among leading wind countries in Europe

1,000 mi2 landper millionpopulation,2009–2010

% onshore wind ownedby utilities/

corporations

% owned byfarmers

% owned bycooperatives

Wind cap-acity (MW),end 2008

UnitedKingdom

1.5 98 1 0.5 3,288

Germany 1.7 55 35 10 23,903

Spain 4.3 > 99 < 0.5 0 16,740

Denmark 2.9 12 63 25 3,160

Sources: Wikipedia, List of Countries and Dependencies by Population Density (accessed 26 March 2010); Wind Power 2009; Toke 2005a



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recycling was more expensive per kWh than theGerman FIT following reductions in the size ofthe FIT in Germany.

Looking at Spain, where large utilities havedominated in ownership of wind generation simi-larly to the situation in the United Kingdom,Stenzel and Frenzel (2008) note the positive reac-tion of incumbent Spanish companies to windpower development in Spain in contrast with thatin Germany. They highlight the importance ofcorporate self-interest in promoting wind powerdevelopment. Wind power in Germany devel-oped in spite of opposition from German utilities,which were forced to accommodate renewablesand bear the costs of connection to the grid. InSpain, this has led the corporate generators tosupport investment in better prediction of windspeeds at individual wind farm sites in order tobetter manage the grid. In Germany, however,significant costs have been imposed on the trans-mission system that are not reflected in the con-nection incentives of wind developers. This hasled to grid management issues in Germany, whichwill become more costly to deal with as windcapacity increases (Klessmann et al. 2008). It iseven possible to suggest that the continuation ofthe grip of incumbents on the German powermarket is in significant part because of the unwill-ingness of the German government to liberalizethe market fully, for fear of undermining the abil-ity of the incumbents to finance the significantreinforcement costs associated with renewablesexpansion.

In 2008, the United Kingdom had around13.2 GW in 195 projects that were in Great Brit-ain’s “GB Queue” (see Ofgem 2007a).These wereprojects that wished to connect to the power grid,but for which no firm connection right could beoffered, unlike under the German FIT, whererenewable capacity must be connected and paidfor generated power (see Swider et al. 2008). TheUK government has suggested that this is one ofthe barriers to the rollout of renewables (DECC2009e). This may explain some of the slow deliv-ery of renewable wind connection in the UnitedKingdom, but it certainly does not explain themost significant part of it. It is impossible to tellhow economically viable many of the projects in

the GB Queue are, and Ofgem has identified onlyaround 450 MW of wind capacity that needs tobe prioritized via accelerating transmission invest-ment (see Ofgem 2009a). It is also the case thatnew renewable connections should face the truecosts of connection to the grid and capacity, andthey should come onstream when it is at leastsystem cost, rather than only least generation cost.Nodal pricing would seem to be a more appropri-ate way of signaling this, rather than the “connectand manage” approach under FITs in Germany(see Pollitt and Bialek 2008).

The correct pricing for transmission capacityalso points to the need for the United Kingdomto look closely at the efficiency of utilization oftransmission assets and their operational criteria.The GB transmission system in general operatesunder an N-2 safety standard, wherein the systemmust be operated in such a way that if a major linkfails, it must be capable of handling anothersimilar-size failure.This gives rise to lower rates ofutilization of transmission grid assets than incountries with an N-1 safety standard and givesrise to less use of automatic voltage control equip-ment. This suggests that there is scope for operat-ing the assets much more smartly in the presenceof large-scale renewables. For instance, the nomi-nal rating of Scotland–England interconnectors isaround 7 GW, whereas the declared capacity is 2.2GW; this suggests that transmission constraintscould be made less in practice than they might beon paper. Ofgem’s recent LENS scenariomodeling (Ault et al. 2008) of the electricitytransmission and distribution networks suggeststhat a range of network sizes and capabilities arepossible by 2050, depending on how and wherenew generation capacity, including renewables,was connected.

Looking to other countries with TGCschemes, it is quite clear that Sweden, Australia,and New Zealand have avoided the problems ofoverpayment that characterize the UK ROscheme, and these jurisdictions have significantlyfewer land use constraints. Kelly (2007) discussesthe UK scheme in contrast to those of Australiaand New Zealand. The Australian scheme, com-plemented by an Office of the Renewable EnergyRegulator (see ORER n.d.), has much less ambi-



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tious targets than the UK scheme but does nothave any revenue recycling. The New Zealandscheme has higher targets than Australia’s but isvoluntary.The Swedish scheme also does not haverevenue recycling and is combined with carbontaxes throughout the economy (see SwedishEnergy Agency n.d.). The United Kingdomwould do well to examine the overall carbonreduction incentives in Sweden.

Szarka (2006) raises an important issue aboutpolicy comparison across countries in the case ofrenewables, suggesting that policy should beaimed at paradigm change, not just installedcapacity. Clearly what matters is where the coun-try ends up in terms of decarbonization, and whatis required is radical change to the UK energysystem. He maintains that the real success of Ger-man policy has been to engage large numbers ofindividuals in taking action on climate change, asinvestors in local wind farms.This is an importantperspective, because it suggests that the real failureof UK policy is not gaining practical support forthe sorts of changes to the energy system that arerequired. Failure to focus on this aspect of theproblem has led to an ineffective policy onrenewables deployment, which will be moreexpensive than it need have been, due to a com-bination of underdelivery and overpayment.

Another issue is the stability of policy throughtime. A concern of UK policymakers in setting upthe RO scheme was to introduce stability in thesubsidy regime over a long period, in contrast tothe stop-start nature of NFFO. However,although stability is a desirable goal in itself, thishas been an excuse for not facing up to the seriousdeficiencies of the RO scheme. Little evidence isavailable to indicate that the United Kingdom hashad a less stable policy toward renewables thancountries with high penetration rates ofrenewables, such as Denmark, Germany, andSpain, where responses to incentives were rapidand significant changes have occurred to supportpolicy over time.

What Might Be Right for theUnited KingdomIf a problem exists with the delivery of onshorerenewable capacity in the United Kingdom, whatshould be done about it? Answering this questionrequires attention to the institutional context ofthe United Kingdom (following Rodrik 2008).The country’s policy context is a liberalized mar-ket for a relatively small island with concernsabout fuel poverty, global warming, and energysecurity. It is clear that what is needed is a policyconsistent with a liberalized energy market andwith environmental targets. By contrast, Germanyis much less committed to liberalized energy mar-kets. It also has much more of a focus on a greenindustrial policy aimed at promoting the manu-facture of wind turbines for export. Although theUnited Kingdom has paid lip service to this sortof objective, the reality is that only 4,000 jobs inthe country depend on the wind productionindustry; even in Germany, the figure is only38,000 (EWEA 2009). It is quite clear that for anindustry requiring around £1 billion ($1.5 bil-lion) of subsidy per year, this is not a cost-effectivejob creation scheme.

The focus should rather be on least-costachievement of environmental targets, which willbe much more important for the competitivenessof the UK economy and for incomes and employ-ment. The current RO scheme is clearly far toogenerous to existing onshore wind, and it doesnot guarantee cost-effectiveness for offshore windand marine energy. It is also important that theaim of long-run cost reduction for technologiesthat are currently not cost-effective be main-tained, and that these technologies compete withnuclear and CCS projects in a reasonable timeframe. An important starting point for this is thecreation of a single high and stable carbon pricethroughout the economy. This would immedi-ately give clear signals to nuclear and CCS andprovide the backstop technologies against whichcontinuing subsidies can be measured. It wouldalso provide the right incentives to biomass interms of cofiring, landfill gas, and waste.



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The principle of various levels of support fortechnologies at different stages of development isalso well established, and recent moves in UKpolicy to recognize this are sensible and impor-tant. What is needed is the right mix of R&Dsupport, competitions, and general supportmechanisms such as a FIT or TGC. It seems clearthat for small schemes, a FIT for small-scale windand small hydro does offer an attractive mecha-nism at the current low levels of development inthe United Kingdom, and hence moves in thisdirection are sensible, given high transaction costsin setting up such schemes and arranging finance.

For offshore wind, it would seem that aNFFO-style set of annual auctions would offerthe best way of keeping prices down. NFFOarrangements could be amended to ensure actualdelivery, with penalties for nondelivery. Indeed,given the scale of offshore wind’s potential and theproblem of finding a suitable level of support ini-tially, relative to other sources of renewables, thiswould seem to be a good way forward. Bids couldtake the form of contracts for differences (as sug-gested by Ofgem 2007c for the reform of the ROscheme), whereby bids would be for a fixed pricefor the electricity generated, which would be paidat that price minus a reference wholesale price,with the payments being levied across licensedsuppliers in proportion to their supply.This wouldincentivize efficient location decisions, as connec-tion and use of system charges would still beborne by the generators, and they would beincentivized to maximize the actual wholesaleprice they received in the market. It would also tiein with successful experience of the use of com-petitions for infrastructure delivery under the pri-vate finance initiative (Pollitt 2002). As with anyprocurement process that is repeated with (poten-tially) a smallish number of bidders over time, theauctions would have to be monitored for collu-sion among the bidders, but given the standardnature of the investments and transparency of thebidding strategies employed by the players, actualor tacit collusion would be easy to spot. Annualbid rounds would offer the chance to adjust quan-tities required and other details of the auction eas-ily over time to reflect learning.

For large-scale onshore wind, the RO mecha-nism could be made to work by removing therevenue recycling and adjusting the targetsaccording to the expected amount of capacityfrom offshore wind.This would essentially rewardonshore renewable generation with a fixed rev-enue supplement equal to the buyout price,assuming the target was not met or exceeded.However, it remains the case that all renewablecapacity should be expected to face the fullamount of transmission and distribution costsimposed on the system. This would encourageoptimal siting, local generation more generally,and proper competition between renewable sup-ply and demand reduction measures. Barthelmieet al. (2008) show that there would be benefits tolearning from Spain in terms of improving theshort-term forecasting of wind power availability.Improved forecasting might have increased theprice of wind power received by generators by theorder of 14% in 2003.20

In sum, the current revenue recycling withinthe RO mechanism is unnecessary and should bestopped. This is line with an early National AuditOffice report on the RO mechanism, whichwarned the government that it needed “to keep afirm grip of the Obligation’s cost relative to otherinstruments for reducing carbon dioxide” (NAO2005, 4). The system needs to be altered withrespect to offshore renewables in order to ensureleast-cost delivery of an initially very expensiverenewable energy source. Large onetime projectslike the Severn or Thames Barrage (associatedwith a new London airport), if deemed necessaryafter appropriate cost–benefit analysis, must beauctioned rather than financed within the ROmechanism.21 The RO scheme could further beamended to remove its all-or-nothing property byensuring that in the unlikely event that targetswere met or exceeded, the total amount of sub-sidy would be divided proportionately among allthose presenting ROCs. This would remove thecliff-edge effect on the renewable subsidy ofmeeting the target.22

What the history of UK renewables since1990 really tells us is that there are importantinstitutional barriers to expansion of renewablesonshore. These have to do with the lack of local



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benefit from renewable projects that employ asmall number of people and have a significant per-ceived amenity impact. The key learning fromDenmark and Germany is that local populationsmust perceive such projects as being of positivebenefit to them rather than simply satisfying somedistant national policy objective, which they mayotherwise support. The United Kingdom mustdevelop local energy companies that are owned bylocal investors or local customers or councils if thepotential exploitation of local energy resources—wind, biomass, hydro, and other technologies—isto be realized. This is because virtually all renew-able electricity and heat technologies involve sig-nificant local impacts in terms of siting of indus-trial facilities close to residential areas.

For offshore renewables, getting costs downwill be the challenge. Costs need to decrease sig-nificantly in order for energy customers to bewilling to support large quantities of offshorerenewables. The current combination of capitalgrants and arbitrary ROC banding is not a satis-factory or sustainable way forward. Auctions fornew capacity would be institutionally compatiblewith the United Kingdom’s liberalized electricitymarket and offer the prospects of falling pricesover time. They would also tie in with the auc-tions to build, own, and operate offshore trans-mission lines to the new wind farms that Ofgem iscurrently implementing (see Ofgem 2007b).Under Ofgem’s offshore transmission auctionscheme, once an offshore wind farm has a firmcontract for connection to the onshore transmis-sion grid, an auction is triggered to build theinterconnection between the shore and the windfarm.

In the end, success in UK policy towardrenewable deployment, relative to other coun-tries, must be measured in terms of the net presentvalue of the amount of renewable electricity gen-erated scaled by the amount of subsidy. Althoughthis success metric will be difficult to measure atany point along the pathway, in the interim, suc-cess should be measured in terms of the extent towhich the maximum amount of renewable gen-eration (adjusted for technological maturity) isbeing supported for the current level of subsidy.UK policy clearly is not being successful, given

the large amount of relatively cheap unexploitedwind resources in the United Kingdom, in theface of overpayment to existing renewable gen-erators.

ConclusionsThe United Kingdom is struggling to develop acoherent set of policies for decarbonization fol-lowing its successful experience in liberalizingenergy markets. Various authors have suggestedthat the decarbonization policy is so ambitiousthat it demands radical institutional changes(Mitchell 2007; Pollitt 2008). However, little con-sensus has been reached on what form those insti-tutional changes should take.

What is clear is that solutions must targetleast-cost, or else the whole policy is likely to failas a result of the actual cost becoming prohibitive.On the path to this sort of ultimate policy failure,large amounts of resources are likely to be wasted,to little overall effect and for no benefit to the UKeconomy or the global climate.The United King-dom has had a long history of failed governmentintervention in the energy market and in indus-trial policy in general (Pollitt 2008). It must notcontinue this sort of tradition. It has, however,had good experience with the role of markets,undertaking basic R&D, and the use of marketmechanisms to deliver public goods. The countryhas also particular concerns about fuel poverty,which argues for a focus on keeping the costs ofrenewables policy down.

The United Kingdom agreed to an ambitiousrenewable generation target that was unnecessar-ily tough—in terms of the required speed ofincrease in the share—in the face of its EU CO2

targets, which could have been met in a muchmore straightforward way by a combination ofdemand reduction and a switch from coal- to gas-fired generation (see Grubb et al. 2008). Why thecountry got itself into this position is not appar-ent, but it clearly hoped that the EU ETS wouldbe much more effective than it has been in sup-porting decarbonization. Because of this, the EURenewables Directive has become more signifi-cant for the country than it needed to be.



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The United Kingdom also must resist calls tosee national renewables policy as anything otherthan a policy for delivering learning benefits onthe path to cost parity with established technolo-gies. An industrial policy based around theemployment or export potential of renewables isnot a sensible use of national economic resources.No doubt some benefit will accrue to the UnitedKingdom from exploiting its domestic renewablespotential, but this will arise naturally and shouldnot be an objective of policy. The British WindEnergy Association (BWEA) reports that theUnited Kingdom is a net exporter of small-scalewind turbines, the part of the market least affectedby government subsidy (see BWEA 2009). Thecountry needs to move to a more competitiveenergy market wherein smaller firms competewith large incumbents to supply power anddeliver national targets and the capacity to rapidlyadopt new lower-cost innovations exists. This isessential if incumbent costs are to be kept downand oligopoly pricing and excessive subsidyregimes are to be avoided.The 40 years from 2010to 2050 are very likely to see huge technologicaland lifestyle changes that will substantially changethe potential picture of the power, heat, and trans-port sectors (see Ault et al. 2008). The UnitedKingdom must have institutional arrangements toincentivize potentially drastic innovation withinthe renewables sector.

The country must incorporate the learningfrom both its NFFO and its RO experiences intofuture subsidy regimes.The evidence suggests thata reformed NFFO-type auction could be a sensi-ble way to deliver large offshore wind parksmostly built by big multinational utility compa-nies. Onshore, it is clear that there are legitimateland use issues with renewables, which can beaddressed only by smaller-scale projects for localpublic benefit. This policy is in line with some ofthe more decentralized scenarios of the futuredevelopment of electricity networks, and it wouldhave the added co-benefits of substantially re-inforcing the need for paradigm change at theindividual level and aiding behavioral changes thatwould support the optimal use of technologiesthat promote energy efficiency.

The United Kingdom also needs to signifi-cantly improve the quality of the information onwhich policy decisions are being made. There is asevere lack of analysis of the drivers of past policyoutcomes, partly as a result of the lack of informa-tion on the financial characteristics of individualprojects that have received subsidies. No study hasbeen done on the actual performance of renew-able projects in the United Kingdom. Foxon andPearson (2007) highlight the need for improve-ments to the process of energy policymaking,whereby analysis is properly used to evaluatepolicy, and policy is revised in the light of analysis.One particular area for improvement is in theconsistency of energy policy among heat, power,and transport fuel in terms of value of subsidies forcarbon reduction, entry barrier reduction, andpromoting learning.

The information available to potential, oftensmall-scale, developers could also be improvedwith significantly more use of geographical infor-mation system (GIS) mapping of potential renew-able energy sites and guidance on acceptabledesigns and siting rules. This would focus devel-oper efforts on sites much more likely to securelocal public support and obtain planning permis-sion. This sort of proactive approach to preparingthe ground for projects would seem to addresssome of the calls for more united governmentapproaches (e.g., Keirstead 2007) toward energypolicy in the United Kingdom. It also likelywould aid in resolving resource conflicts amonglocal community, leisure, defense, air traffic, andenergy interests.

Finally, a focus on renewables must not detractfrom the overriding policy aim of decarbonizationof the economy. This requires sensible carbonprices and the workings of the price mechanismwith regards to transmission and distributioncosts. In the end, it is only when locational costsand environmental externalities are properlypriced that any given renewables project, with itsparticular characteristics, can be evaluated amongthe myriad alternatives. Although the UK policiestoward renewables may currently be failing todeliver new capacity in sufficient quantity to hitlong-term renewables targets, it is by no means



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clear that those countries that are doing better inthis regard are any nearer to achieving long-termdecarbonization.

AcknowledgmentsThe author acknowledges the ongoing intellec-tual support of the ESRC Electricity PolicyResearch Group. Bin Feng provided excellentresearch assistance. The comments of BoazMoselle, David Newbery, Jorge Padilla, DickSchmalensee, Steve Smith, and Jon Stern areacknowledged.

Notes

1. The definition of renewables used in this chapter isthat in the EU Renewables Directive(2009/28/EC): “ ‘energy from renewable sources’means energy from renewable non-fossil sources,namely wind, solar, aerothermal, geothermal,hydrothermal and ocean energy, hydropower,biomass, landfill gas, sewage treatment plant gasand biogases” (European Commission 2009, Arti-cle 2(a)).

2. This indicates that in August 2009, 8% of a typicalelectricity bill and 3% of a typical gas bill wasbeing charged to support environmental schemes,of which the most expensive were targeted towardlower-income consumers.

3. UK carbon targets are net of trading, and hencecan include carbon credits purchased from abroad.

4. HM Treasury (Her Majesty’s Treasury) is the UKMinistry of Finance.

5. It is worth noting that Germany also likes the1990 baseline date, as this coincides with the col-lapse of the Berlin Wall and the rapid decarboniza-tion of the former East Germany as a result ofindustrial decline and improved environmentalstandards.

6. See, e.g., DECC (2009a, 92), which shows pro-jected cost decreases for PV of 70% to 2050,against only 22% for coal-fired CCS.

7. NAO (2008, 17) reports 20 government policies,strategies, and reviews on energy between 1997and 2009, with 16 of those from 2003 onward.

8. Initially the levy was 10.6% in England and Wales,but it fell to 0.9% in 1998 when payments for

nuclear power ended. It was phased out in April2002, having been 0.3%. The levy rate in Scot-land, which was not used to fund nuclear liabili-ties, began at 0.5% in 1996 and reached a maxi-mum of 1.2% (Wikipedia, s.v. “Fossil Fuel Levy”).

9. England and Wales had five rounds of NFFO:NFFO-1, start date 1990, followed by NFFO-2,-3, -4, and -5 in 1992, 1995, 1997, and 1998.Scotland had three rounds: SRO-1, -2 and -3 in1995, 1997, and 1999. Northern Ireland had tworounds: NI-NFFO-1 and -2 in 1994 and 1995.See Wong (2005, 131). The last NFFO contract isdue to expire in 2018.

10. Under the 2001 EU Renewables Directive, theUnited Kingdom signed up to a 10% target forrenewable electricity generation, which is embod-ied in the successor scheme to NFFO (EuropeanCommission 2001).

11. Continuing NFFO contracts are funded via therevenue from the auction of ROCs (by the NFPA)associated with the contracts (see Ofgem 2004).

12. Assuming here that no one has invested in arenewable generation project that would beunprofitable without the “recycled” revenues. Theactual reported figure for recycled revenue is£307m (Ofgem, Renewables Obligation AnnualReport 2007–2008, 1).

13. UK inflation between September 2002 and Sep-tember 2008 was 15% (ONS 2009). The NationalAudit Office reported a figure of only £700 mil-lion ($1.05 billion) per annum for annual costs2003–2006 (NAO 2005, 35).

14. In May 2009, only eight operational schemesexisted with a capacity of 50 MW or moreonshore (DECC 2009b, 145–51).

15. For more details on the planning process in Eng-land, see DECC (2009 n.d.b).

16. In this vein, Upreti and van der Horst (2004) havean enlightening discussion of one NFFO biomassproject that, because it could not be modified assuggested by the local consultation process, even-tually had to be abandoned.

17. One of the few examples of significant capital rais-ing from the local community was the Baywindproject in Cumbria, which first raised £1.2 mil-lion ($1.8 million) to form a cooperative todevelop wind power (see www.baywind.co.uk).

18. Compare actual costs in Snyder and Kaiser (2009)and Blanco (2009) with cost simulation assump-tions in Dale et al. (2004) and Strbac et al. (2007).

19. This is because the recycled revenue component ishighly uncertain and unlikely to be a key part ofthe business case for a new renewables project.



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20. It might be considered odd that UK wind genera-tors have not done this already, given the financialincentive to do so, but this may be due to thecurrently low level of wind capacity, relative tosome of the fixed costs in setting up such a system.

21. See SDC (2007) on potential tidal projects in theUnited Kingdom.

22. The government has considered this issue but hasdecided not to do anything about it at themoment, given the gap between delivery andactual (or future) targets (DECC 2008).

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Chapter 13: UK Renewable Energy Policy since Privatization

Technology

energy policy context

uk renewable energy

policy measures

policy objectives

uk energy

uk renewables policy

policy towardsupport

current policy