Switching offUK consumers areangry about bills,so why do they notchange providers?Page 2

Inside »

Germany’s biggreen experimentUnder the bonnetof the ambitiousEnergiewendePage 3

After FukushimaThree years on,Japan is poisedfor a return tonuclear powerPage 2

Peak interestHow cheap dealspersuade people tocut usage at timesof high demandPage 4

FT SPECIAL REPORT

Modern EnergyTuesday June 24 2014 www.ft.com/reports | @ftreports

The world of energy used to befairly straightforward. Bigstate-owned utilities gener-ated power and fed itthrough wires and pipes into

customers’ houses. It was a well func-tioning system that seemed to be setin stone.

But this centralised, “command andcontrol” model is under pressure asnever before. Energy is changing fast,as technological innovation disruptsthe old paradigms. Smart grids, smartmeters and smart home appliancesembedded with sensors that connectthem to the “internet of things” prom-ise to revolutionise our approach toenergy use.

Nothing better highlighted thesechanges than Google’s $3.2bn acquisi-tion in January of Nest Labs, a four-year-old start-up that makes smart

thermostats and smoke alarms for thehome. Users can turn up or switch offtheir heating from anywhere using asmartphone app.

Others are following suit. Apple isworking on a software platform thatwill turn the iPhone into a remotecontrol for lights, security systemsand other appliances. Samsungrecently unveiled its Smart Homerange of washing machines, refrigera-tors and TVs that can be controlledfrom its mobile phones and watches.

Suddenly, big technology providersare focusing on energy as a poten-tially lucrative sector. High streetretailers and telecoms companies arealso waking up to the opportunities ofretail energy provision.

This presents a huge challenge tothe traditional utilities – the bigpower companies such as RWE and

Eon in Germany, Centrica in the UKand Enel in Italy. For decades, thesevertically integrated monoliths, whichboth generate power and supply it tomillions of homes and businesses,dominated their markets. But thechanging economics of the energyindustry have depressed their returnsand constrained their balance sheets.

Some, especially the “big six” sup-pliers in the UK, are facing mountingpublic anger over rising fuel bills andcomplaints about poor service. Theyare being subjected to much greaterscrutiny from regulators, while agrowing number of politicians arecalling for them to be broken up.

“The big six are finding retail verypainful,” says Omar Abbosh, seniormanaging director of Accenture, theconsultancy. “It’s not in sync withtheir core competence, which is bigcapital formation and asset steward-ship.” That contrasts with companiesin the retail, telecom and technologyspace, who “have brands that consum-ers relate to” and “are better at man-aging customer relationships”.

For Google, buying Nest does notnecessarily mean it will become a bigenergy player. “But,” says Mr Abbosh,“it realises it can use Nest’s technol-ogy to learn more about its end con-sumers, what those consumers need,and how it can profit from them.”

Already, there are some examples ofnew entrants into the supply business.Hungary’s Magyar Telekom sells gasand electricity to residential and busi-ness customers. UK retailer Marks andSpencer has teamed up with SSE, oneof the big six, to offer energy pack-ages, with the promise of M&S vouch-ers to those who make the switch.

Some big utilities are meeting thechallenge head on, offering more serv-ices to their huge fixed installed baseof customers. There is a big incentivefor them to do so.

The backbone of their business –thermal power generation – hasbecome a lot less profitable in recentyears, undercut by weak energydemand in Europe, the rise of renewa-bles such as wind and solar, and lowpower prices. Burdened by debt, theyare largely unable to invest in newplants and have instead been cutting

Continued on Page 2

Technologydrives shiftto smarterthinkingUtilities are reinventing their businessmodelsas high street retailers and telecoms companiesmove into their territory, reportsGuyChazan

Remote control: the Nest app allows customers to adjust heating by smartphone

The history of the advancedbiofuels industry resemblesnothing so much as thealchemists’ pursuit of thePhilosopher’s Stone: a pro-cession of false promisesand broken dreams. But, ina modest way, some ofthose expectations are atlast being realised.

Over the next 12 months,three plants producing cel-lulosic ethanol, one of themost heralded of the nextgeneration of biofuels, areset to start production inthe US. Yet while thearrival of cellulosic ethanolon the US market is a bigstep forward, the industryhas a long way to go tomake a material differenceto fuel supplies. Technical,commercial and regulatorychallenges still present sig-nificant barriers to thewidespread adoption ofadvanced biofuels.

In principle, the new gen-eration of biofuels could bevital for sustaining roadand air transport in the faceof declining oil productionand emissions concerns.

The new fuels avoid theproblems of first-generationproducts such as US corn-based ethanol, includingcompetition with food pro-duction, because they areproduced from agriculturalor municipal waste, or fromspecial energy crops.

Realising that potential isdifficult. The energy lockedup in plant cellulose – or inalgae, another focus forresearch – is hard tounleash on a useful scale.

At last, though, at leastthree projects are about toget under way in the US.Two are in Iowa: one fromPoet, the US ethanol groupand Royal DSM, a Dutchbiotech company; and onefrom DuPont, the US chemi-cals group. Abengoa, theSpanish renewable energygroup, plans to open a plantin Kansas soon.

Beta Renewables, backedby the private equity firm

TPG, started operations at aplant in Italy last year.

These facilities generallytake corn stover – leavesand stalks left after maizeharvesting – or other agri-cultural waste and break itdown to make ethanol.Manuel Sánchez Ortega,Abengoa’s chief executive,is also bidding for contractswith three US cities to turntheir municipal solid wasteinto ethanol. That technol-ogy is less well developed,he adds, “but it’s somethingthat is happening”.

Other advanced biofueltechnologies are furtherbehind. Attempts to usealgae, sometimes pro-claimed as the long-termfuture of fuel, have sufferedmultiple setbacks.

Royal Dutch Shell, theEuropean oil group, stoppedits efforts with algae. Exx-onMobil of the US is contin-uing research with Syn-thetic Genomics, but shiftedto “a basic science effort”focused on genetically modi-fied algae after, in the com-pany’s words “it becameclear that economically pro-ducing suitable quantitiesof oil from naturally occur-ring or conventionally mod-ified algae would be techni-cally difficult”.

San Francisco-based Sola-zyme is one of the moresuccessful companies pro-ducing oil from algae, but isnot having much impactbecause its costs are stilltoo high.

Jonathan Wolfson, itschief executive, told arecent Goldman Sachs con-ference: “The reason westarted the company was todisrupt fuels.” Instead, hesaid, the company’s oils aregoing for higher-value usesin cosmetics, soap andfoods, and are used for fuelsonly as an additive to con-ventional crude. “We’reonly selling blends, becausewe can’t compete yet with abarrel of oil,” he said.

Shell’s remaining effortswith advanced biofuelsare concentrated on two

processes: using a thermalprocess to make petrol fromwaste wood, and a cellulosicethanol process similar tothat used by the companiesstarting production thisyear. It has a test plant inHouston for the petrol fromwood technology, and plansto expand it and add cellu-losic ethanol production.

Although Shell seems tobe making progress, it over-promised and under-deliv-ered on cellulosic ethanoland algae in the 2000s, and

is now cautious about mak-ing promises on howquickly its work will bearfruit.

Matthew Tipper, Shell’svice-president of alternativeenergies, says there is afundamental problem withmany advanced biofuels.

The logistics of deliveringthe feedstock to the plantmean each individual facil-ity has to be relativelysmall: perhaps producing6,000 barrels of ethanol aday, compared with a largerefinery that could produce500,000 b/d.

At small scales it is hardto make the processefficient enough to competewith conventional oil-basedfuels, which is Shell’sambition. The regulatoryf r a m e w o r kof the US

Renewable Fuel Standard(RFS) and similar pro-grammes in other countriestoday support biofuels,especially advanced ones,but Shell does not expectthat support to last forever,and wants any fuels it pro-duces to be able to compete.

The RFS was establishedin 2005, and in 2007 was seton a path for a steadily ris-ing volume of biofuels to beblended into US road fuel.

As that number has risen,ethanol has faced the grow-ing problem of the “blendwall”. Because 10 per centis the maximum amount ofethanol that can be blendedinto fuel used by cars in theUS, that share sets a limitfor how far volumes of etha-nol sold can grow.

Faced with that problem,the US Environmental Pro-tection Agency (EPA) hasproposed cutting back themandated biofuels volumes,to the fury of the ethanoland biodiesel industries.

DSM accuses the EPA ofcapitulating to pressurefrom the oil industry, andsays the proposal had “amassive chilling effect” oninvestor interest.

Abengoa’s Mr SánchezOrtega agrees, saying theadministration should havecompelled retailers to makea higher proportion of etha-nol available for customersthat can use it. Still headds, this is nothing newfor the renewables industry,where companies alwaysfeel they are the underdog.

“In the renewables sector,it’s always a fight againstthe big boys,” he says. “Somedays you feel like sayingyou give up, but on mostdays you feel like fighting

on. And that’s what Aben-goa will do.”

Industry’s new milestone on theroad to making fuel from wasteBiofuels

Science, logistics andregulations stilltemper expectations,writes Ed Crooks

A new generation ofbiofuels could bevital for sustainingtransport in theface of decliningoil production

Eco warrior: wasteleft after harvestcan now be usedto make ethanol

2 ★ FINANCIAL TIMES TUESDAY JUNE 24 2014

How can consumers be per-suaded to shop around fordomestic electricity and gassupplies?

In much of the world thisis not an issue. Local ornational utilities typicallyact as monopoly suppliers,with regulators left to setprices and ensure custom-ers get a fair deal.

But in the UK, domesticcustomers have been free tochoose their supplier since1999, under a liberalisationdesigned to let the threat ofswitching squeeze the prof-its of energy retailers.

Since the formal scrap-ping of price caps in 2002,retail competition has beenleft as the main marketlever to protect consumerinterests.

Growing anger amongconsumer groups and politi-cians about rising fuel billshas led the UK’s oppositionLabour party to threaten toreimpose the policy of pricecaps that it abandonedwhen in government, amidclaims of profiteeringamong the country’s lead-ing energy retailers.

The willingness of suppli-ers to let retail markets riphas been stoutly defendedthroughout the protractedpolitical debate by AngelaKnight, chief executive ofEnergy UK, the industrybody.

Ms Knight accepts theprocess of switching suppli-ers can be improved, butargues there is little to stopconsumers voting withtheir feet, aided by onlineprice comparison sites.

“Switching is simple: justpop in your postcode; howmuch gas and electricityyou use – which is on everybill; and Bob’s your uncle.It’s as simple as that, asmore than a quarter of amillion customers findevery month,” she says.

Ms Knight nonethelessrecognises that many con-sumers do not shop aroundfor energy suppliers in theway they do for other prod-ucts. “While many of uslike to hunt for a good bar-gain, we rarely apply this tosearching for a betterenergy deal,” she concedes.

The two-tier nature of theUK energy retail market isshown by recent customernumbers from Centrica,which owns market leaderBritish Gas, and SSE, theUK’s next biggest operator.

The two companies,alongside Npower, EDFEnergy, Scottish Power andEon, comprise the so-calledbig six, which last yearheld 98 per cent of thehousehold market.

But a wave of unpopularprice increases last autumn,blamed on increased whole-sale costs and the growingburden of environmentallevies, caused a surge inswitching to new marketentrants as well as betweenthe big six, according to themarket leaders.

Last month, SSE – thefirst of the big six toannounce tariff increases –blamed the rises and com-petition from alternativesuppliers for the loss of370,000 customers, as itended its year to Marchwith 9.1m accounts.

Centrica, which leads thepack with 15m customers,also conceded in a profitwarning last month that it

has lost 180,000 residentialaccounts in the year todate. Sam Laidlaw, Centricachief executive, said the falldemonstrated that “compe-tition remains fierce, partic-ularly from smaller suppli-ers that are benefiting froman exemption from someenvironmental obligations”.

Encouragement of newentrants has drawn morethan two dozen alternativesuppliers into the market-place, keen to portray them-selves as more keenlypriced or more ethicallyconcerned Davids rangedagainst the big six Goliaths.

These include GoodEnergy, which offers cus-tomers the chance to sourceelectricity solely fromrenewables such as wind,solar and hydro power, andOvo Energy, which alsooffers a range of fixed, cut-price and “green” tariffs.

Yet in spite of a surge inentrants and rule changesimposed by regulatorOfgem aimed at makingswitching easier, enthusi-asm for shopping aroundremains patchy and the bigsix still dominate.

A survey commissionedby Ofgem from Ipsos Mori,the market researcher,shows a continued patternof a small minority of cus-tomers happy frequently toseek out the best deals.Many others, whileunhappy with their suppli-ers, do not move.

Just 12 per cent of thosesurveyed last year hadswitched electricity suppli-ers in the previous 12months, while 11 per centchanged gas company – afourth year of decline inswitching.

Nearly two-fifths of thosesurveyed said they had

never switched suppliers.These consumers tend to bepoorer, less inclined or ableto pay by direct debit tosecure better deals, renttheir homes, and are morelikely to be in Scotlandthan England and Wales.

Consumer groups arguethat established suppliershave been happy to com-pete for low-margin busi-ness among the minority ofcustomers who chase thebest deal, but know thattheir margins are secureamong their core customerbases who rarely, if ever,switch suppliers.

Yet it is often the lattercustomers who are most atrisk of “fuel poverty”.

With a root-and-branchinvestigation of the UKenergy retailing marketunder way, led by the Com-petition and MarketsAuthority, Dermot Nolan,Ofgem’s chief executiverecently conceded thatnearly half of Britons didnot prioritise shoppingaround for the best deal.

“We shop and compareprices for many things inlife, yet we often don’tthink to do the same whenit comes to our energy bills,even when we could be sav-ing in the region of £200 ayear,” he said.

“Previously, people foundit difficult to compare tar-iffs and the process was tootime consuming,” he con-ceded, “but the recentreforms have changedthings for the better.”

UK consumersresist calls toshop aroundCompetition

Nearly 40 per centhave never changedsupplier, saysMichael Kavanagh

‘We compareprices for manythings, yet we don’tdo the same withour energy bills’

If you live in Europe and donot already have a smartmeter, the chances are oneis coming your way soon.

Smart meters allow forreal-time measurement andanalysis of consumption,remote connection and dis-connection of supplies, andmore accurate billing.

In Italy and Sweden theyare the norm, while inSpain, Endesa, Iberdrolaand Gas Natural Fenosa areordering the devices for aninstallation programmethat should see 70 per centof households equipped by2016 and universal adoptionby 2018.

The UK and France arenext among the 20 Euro-pean countries that havefinalised – or are about tofinalise – plans for smartmeter adoption.

The digital technologywill become part of the fab-ric of domestic energy use

by the end of the decade.Analysts are predicting

that penetration ratesacross Europe will catch upwith the 80 per centexpected in North Americaby the end of the decade,with further strong growthin Japan and China likelyto fuel demand for metermanufacturers.

However, who pays andwho gains from the adop-tion of smart metersremains controversial.

In the UK, the installationof 53m electricity and smartmeters in 30m homes andbusinesses by the end of2020 is expected to cost£10.9bn. Much of the benefitwill accrue to energy sup-pliers, which will nolonger need toabsorb the costs ofinspection of oldanalogue meters.

H o u s e h o l d s ,meanwhile, at atime of growingpolitical tensionand protest overrising energy costs,will see their annualbills rise later this dec-ade to pay for the rollout.

Last July, RWE Npowercalculated that the costwould add £24 to average

household bills by 2020.Nevertheless, the UK’s

National Audit Office(NAO) is broadly satisfiedby the benefits that will begenerated by the invest-ment. “The economic casefor the programme remainspositive,” concluded areport published in May byAmyas Morse, head of thepublic spending watchdog.

The NAO gave broad sup-port for estimates providedby the Department ofEnergy and Climate Change(DECC) that savings couldtotal £17.1bn, resulting in anet economic benefit of£6.2bn by 2030.

The DECC estimates thatenergy suppliers will be the

biggest winners, saving£8.3bn – half of the grosssaving – through reducingsite visits and cutting thecost of customers switchingcontracts.

But the DECC also arguesthat £5.7bn will be saved bycustomers. This is expectedto come largely from reduc-tions in demand, as betterinformation on their energyuse prompts consumers andbusinesses to change theirbehaviour.

Policy makers’ confidencethat smart meters can pro-voke a genuine shift in con-sumer behaviour – ratherthan simply bring cheaperrevenue collection for utili-ties – is yet to be tested.

Though Germany hasnot implementedplans for the compul-sory installation ofthe devices, Eon hasbeen piloting theirintroduction inBavaria ahead ofwidespread adoptionover the next decade.

The company saysthat experience sug-

gests smart meters can helpconsumers quickly identify“energy guzzlers” and thatgreater awareness of pat-terns of usage can reduce

bills by 5 to 10 per cent. Eonpoints to the potential ofsmart meters to allow moreflexible tariffs, for example,offering cheap rates forrecharging electric carsovernight.

Sacha Deshmukh, chiefexecutive of the SmartMeter Central DeliveryBody, which advocatesadoption of the technologyin Britain, says the assump-tions underpinning the UKrollout are modest.

The DECC’s cost-benefitanalysis of its $10.9bn pro-gramme is based on anassumed 2.8 per cent fall inelectricity consumption and2 per cent in gas.

But Mr Deshmukh pointsto a recent assessment ofpilot schemes across Europeled by Philip Lewis ofVaasaETT, an energy indus-try consultancy. Thisresearch suggested smartmeters combined with dis-plays offering real-timemonitoring of a building’susage may reduce consump-tion by 7-9 per cent.

For now, UK policy mak-ers are maintaining theirmodest assumptions. A best-case scenario could delivermore than £22bn in totalbenefits, nearly doubling

the net gain. But a pessimis-tic assessment of £12bnwould deliver almost noreturn on the high-profileproject.

Mr Deshmukh predictsfurther gains for consumersas a global rollout will trig-ger a wave of smart house-hold devices. It will be pos-sible to monitor and controlthese remotely, allowing formore efficient operation ofhot water, heating, refriger-ators and other energy-draining appliances.

Some campaigners areconcerned that the prolifer-ation of digital informationconcerning the use ofhousehold appliances raisesprivacy issues.

But Mr Deshmukh saysthe meshing of smartmeters, smart devices andsmart grids will benefit con-sumers with the emergenceof “real time of use tariffs”,allowing households to trimbills by reducing overallconsumption and also shift-ing energy use away fromtimes of peak demand.

It will be the emergenceof radical tariff deals andsmart household devicesthat will “make smartmeters really worth hav-ing”, he says.

Smart meters deliver benefits – and costs

The 21,000 townspeople ofNamie, 231km northeast ofTokyo, are allowed to gohome once a month, butnever to stay overnight.

Their houses lie in the 20-mile evacua-tion zone around the Fukushima Dai-ichi nuclear plant, torn apart byexplosions after an earthquake andtsunami hit Japan in March 2011.

Their continued exile is a reminderof the deep impact of the disaster.Japan almost immediately turned itsback on nuclear power, which hadproduced nearly a third of the coun-try’s electricity before the accident.

Namie is just one of several ghosttowns and tens of thousands of peopleare still unable to return to theirhomes. While there is no certaintythat its residents will ever be allowedhome permanently, Japan is againstarting to embrace atomic power.

This spring, the government ofShinzo Abe declared its long-termcommitment to nuclear energy,reversing the previous administra-tion’s decision to shut all reactors.

The U-turn is a fillip for the nuclearindustry, which was hard hit by aglobal change of attitude towardsatomic power. After the disaster Ger-many, Switzerland, Italy and Belgiummoved to close down or phase outtheir nuclear programmes.

Meanwhile in the US, reactors havestruggled to compete with gas-firedpower plants riding the shale gasboom. Four nuclear plants closed inthe US in the past 18 months.

A restart of atomic power in Japancould also have implications for worldenergy markets. Japanese imports ofliquefied natural gas (LNG) shot upafter it closed its nuclear plants, push-ing up the price of LNG in Asian andEuropean markets.

The country’s volte face – despitemany Japanese opposing the restart –should not have come as a surprise.The loss of nuclear power and theincreasing reliance on imports of LNGhave come at a considerable cost.

In January, the country revealed itsworst annual trade deficit on record.In 2013, the gap between imports andexports was Y11.5tn ($111bn), widen-ing from the Y6.9tn and Y2.6tn defi-cits recorded in 2012 and 2011 respec-tively. Several utilities have turned togovernment-owned banks for bailouts

to cover losses. Households too havepaid a price, with electricity pricesjumping by a fifth in the 18 monthsafter the earthquake.

So far, Mr Abe’s efforts havefocused on the short term. The primeminister is supporting efforts by elec-tricity utilities to restart about adozen of the 50 still-usable reactors,all of which are shut pending safetyreviews. That effort, however, stillfaces considerable hurdles and anyrestarts must be approved by safetyregulators and local governments.

Laszlo Varro, head of the gas, coaland power division at the Interna-tional Energy Agency (IEA), predictsthe process will be gradual. Nor doeshe expect all plants to be restarted.The agency predicts nuclear power torecover to about half its pre-Fuku-shima level by the end of this decade.

Bringing nuclear back into theenergy mix would be good news forJapan’s trade balance. Restarting fivereactors over the next 12 monthswould mean lower imported energycosts and “would reduce the trade def-icit by Y400bn a year”, according toJohn Vail, chief global strategist atNikko Asset Management.

Mr Vail also identifies some indirect

benefits of a restart. “It’s hard to over-estimate how frustrated companiesare at high electricity costs in Japanand how it affects plans to expandcapital investments there,” he says.

Whether a restart will have a bigimpact on the use of gas remains tobe seen. Mr Varro thinks that nuclearrestoration will first reduce oil-pow-ered generation in Japan, which iseven more expensive than liquefiednatural gas. The impact of the restartwill therefore “not be a game changerfor global gas markets”, he adds.

Strong demand from China for LNGover the next two years, driven bytighter environmental regulation, willhave a bigger impact on the globalgas market, he suggests.

Japanese demand for LNG increasedby 20m cubic metres in two yearsafter the disaster, in a global marketof between 340m and 350m cubicmetres.

“Even if Japanese nuclear comesback, other parts of Asia can compen-sate for less gas demand from Japan,”says Mr Varro. “New supply of LNGfrom Australia and North Americawill be a bigger game-changer thanJapanese nuclear coming back.”

For supporters of nuclear energy,

Japan’s decision underlines thatdespite its potential risks, atomicpower has a role to play, as it pro-vides a low-carbon, domestic source ofsupply without reliance on costlyimports of gas.

Turkey, for example, another coun-try with a large energy import bill, isplanning to build nuclear reactors aswell as coal plants in an attempt tocut its reliance on foreign supplies.

Some observers note that countriesin favour of atomic power before thecrisis have remained committed.

Keith Parker, chief executive of theNuclear Industry Association in theUK, says: “Clearly, Fukushima had animpact but we are now building morereactors than we have done for thelast 20 years.”

Britain is one of a number of Euro-pean countries pursuing a fleet of newreactors. Fukushima sparked a globalsafety review of reactors and in termsof new-build designs, any lessons fromthe crisis will be incorporated, saysMr Parker.

In Japan, the government’s recentannouncement, he adds, is “just thestart of the process”. The key chal-lenge will be “extensive public consul-tation to rebuild national trust”.

Japan revisits pre-Fukushima pastNuclearThree yearson, there aremovesto restart the reactors,writes Sylvia Pfeifer

Impact: visitorsto a shrine inNamie rememberthose lost in thetsunami Getty

costs and divesting assets.“There’s a strategic neces-

sity for them to find newmodels of business develop-ment that are less capital-intensive,” says Roger Rey-nolds, managing director forutilities at Exane BNP Pari-bas. Hence the attraction of“capital-lite” services, suchas advising customers onmanaging consumption, orinstalling energy-efficientboilers or batteries in theirhomes, he says. “They don’twant to just roll over andlet Google and Apple takeover that business.”

Instead of trying to beat

Continued from Page 1 the technology companiesat their own game, someare forming partnershipswith them. Eon, Germany’sbiggest utility, is workingwith rooftop solar developerSungevity to sell co-brandedpanels to customers in theNetherlands. Npower, theUK subsidiary of RWE, hasteamed up with Nest, offer-ing customers its thermo-stat for £99 – down from£279 – if they agree to fixgas and electricity prices atcurrent rates until 2017.

Similarly, British Gas, asubsidiary of Centrica,recently launched HiveActive Heating, a servicethat lets people control

their heating and hot waterremotely from a smart-phone, tablet, SMS, or via awebsite. The company saysit can save households upto £150 a year.

Such innovations may berelatively minor, but theyshow that some companiesare using technology inways that could redefinetheir relationships withcustomers.

“This industry is leavinga world where customerswere just meter numbers,”says Peter Terium, RWE’schief executive. Companiessuch as RWE can no longerjust “sell kilowatt hours”,he says. They have to

present a much broaderoffer, reflecting the rapidlychanging world of energy.

RWE is being forced tochange by the “Energie-wende”, Germany’s radicalshift from fossil fuels torenewables. The transitionhas given rise to a new phe-nomenon – “prosumers”with solar panels on theirroofs and wind farms intheir fields who both pro-duce and consume energy.

Germany now has 6.5menergy producers, many ofthem households.

“What renewables havebeen able to bring isthe miniaturisation ofthe equipment needed to

produce electricity,” GérardMestrallet, chief executiveof GDF Suez, said in arecent interview. “A windturbine is a thousand timessmaller than a powerplant.” This allows for dis-tributed generation – pro-duction in small quantitiesnear the point of use, ratherthan in vast amounts in afew locations.

With the rise of the pro-sumer, houses are graduallyturning into small powerplants that produce andstore electricity. Mr Teriumsays the utility of the futurewill form partnerships withprosumers, helping themsell excess energy to the

grid when their batteriesare full and buy it in if greyor windless days leave themshort of power.

They will also advisethem on reducing their con-sumption, which is one rea-

son why so many areinvolved in smart metersthat show customers howmuch energy they use andhow much they pay for it.

“We want to offer bun-dled products, where all

those functions can be com-bined under one contract,”Mr Terium says.

The smart meter revolu-tion comes at a time whenpressure on householdbudgets from rising energybills and concerns aboutglobal warming have under-lined the importance ofenergy efficiency, some-times referred to as the“invisible fuel”.

The growing realisationthat the energy we do notuse can have almost asmuch impact as the energywe do has had a hugeimpact on everything frombuilding designs to streetlighting.

Mr Reynolds says themove by companies such asRWE into such energy serv-ices is inevitable. But he issceptical. “I think it’s goingto be difficult for them tobuild up a meaningful busi-ness,” he says.

Meanwhile, some say thatby telling customers how tocut their energy use, utili-ties are shooting them-selves in the foot, reducingdemand for their chiefproduct.

Mr Terium’s responds: “IfI don’t shoot myself in thefoot, someone else will. I’drather be in the front row ofthat than wait and let oth-ers take it away.”

Technology drives shift to fresh thinking about business models

Technology

Savings for suppliersand consumers comeat a price, writesMichael Kavanagh

6.5mGerman energy producers,many of them households

Modern Energy

After thedisaster,Germany,Switzerland,Italy andBelgium allmoved tophase outnuclearpower

Changing behaviour: smartmeter displays can helpcustomers cut their bills

FINANCIAL TIMES TUESDAY JUNE 24 2014 ★ 3

Modern Energy

As Sigmar Gabriel, Ger-many’s economy andenergy minister, made aspeech about significantreforms to the country’srenewable power subsidyscheme, a red light began toblink on the lectern. With-out missing a beat, the min-ister glanced at the warningsignal and quipped: “That’llbe the biomass people.”

It was not only the bio-mass industry that hadcause to worry.

Germany continues to setitself ambitious targets forits shift to renewables, theEnergiewende. By 2035,Europe’s biggest economywill generate up to 60 percent of its electricity supplyfrom clean sources, accord-ing to government plans.Last year, about 23 per centof Germany’s electricitycame from renewables.

But the government isanxious to contain the costof the transition. The coali-tion of Angela Merkel’s con-servatives and the SocialDemocrats is determined tocurb a subsidy scheme thatcosts businesses and con-sumers €24bn a year.

Mr Gabriel’s speech inJanuary outlined a bill thatwas approved by the Ger-man cabinet in April. Itaims to curb rising costs byscaling back renewableenergy subsidies and plac-ing upper limits on newinstallations. Feed-in tariffspaid to renewable powergenerators will be cut to anaverage across all technolo-gies of €0.12/kWh by 2015,down from a current aver-age of €0.17/kWh.

The revamped Energie-wende will focus on solarpower and onshore windfarms, the most cost-effec-tive sources. Upper limits of2,500MW of new capacityannually each will beplaced on onshore windpower expansion and photo-voltaic generation.

The expansion of offshorewind plants, one of the new-est and most expensivetypes of clean energy, willbe limited to a total of6,500MW through to 2020.

An annual limit of 100MWhas been put on biomass,which produces energyfrom municipal waste andplant matter and can beexpensive because of theneed to harvest and trans-port the raw material.

The new rules, due tocome into force by August1, come alongside reformsto the system of exemptionsthat spare heavy industryfrom the full cost of cleanenergy subsidies.

Germany has shielded itsenergy-intensive industryfrom the cost of the switchto renewables to protectjobs. Under a deal agreedbetween Berlin and theEuropean Commission inApril, the number ofexempted companies willfall from 2,100 to 1,600,although the overall valueof the exemptions willremain about €5.1bn a year.

German households,which pay a surchargeon bills to finance theEnergiewende, willcontinue to face highprices. The surchargerose to €0.0624 a kilo-watt-hour this year,adding about €220 ayear to an averagefamily bill.

Jörund Haartveit, Euro-pean power markets analystat Thomson Reuters, says:“The big burden is going tofall on the household con-sumers, because there willstill be exemptions forenergy intensive industry,though moderated fromwhat they are today.”

Despite the rebates,industry remains concernedabout the costs of energy.The energy price differen-tial between Germany andits five leading trade part-ners cost the nation’s man-ufacturing sector €52bn innet export losses from 2008to 2013, consultants IHSsays in a February report.

The US shale gas boomand anxiety over Germany’senergy dependence on Rus-sia has added urgency tothe debate on energy policy.

German business has putpressure on the governmentto allow hydraulic fractur-ing for shale gas, and itemerged recently that Ber-lin is drawing up a legalframework to allow applica-tions for fracking. The IHS

report suggests domes-tic shale gas pro-

duction couldkeep costs down.

The reformsoutlined have

left some questions unan-swered. The shift to renewa-bles was accompanied by awithdrawal from nuclearenergy, which left Germanyin need of a back-up sourcefor days when wind or solarpower fail to deliver.

This has led to relianceon highly polluting browncoal (lignite), which is moreprofitable for utilities toburn than cleaner naturalgas – a perverse outcomefor a green energy reform.

Brown coal provided 26per cent of Germany’s elec-tricity supply last year,according to the BDEW, theGerman association ofenergy and water compa-nies. Rewarding utilities forthe cost of generatingpower rather than theamount they supply couldsolve this. The governmenthas raised the prospect ofregional solutions to pre-vent a loss of capacity, butis wary of imposing an addi-tional burden on Germanhouseholds.

Crucially, Germany stilllags behind in building thepower lines vital to takingelectricity from wind parkson the North Sea and theBaltic coasts to the manu-facturing heartlands of thesouth. Construction planshave been challenged byprotesters who say the“energy arteries” destroythe landscape and bringdown property prices. Thegovernment is looking atburying power cables toaddress public concern.

The biggest change forthe German renewablesindustry is yet to come. Thecountry will phase out itsfeed-in tariffs under EUrules that require competi-tive bidding for green powerfacilities by 2017.

“The implementation willbe challenging, as the Ger-man renewables industryhas no experience withsuch a competitive tender-ing procedure,” says HolgerKraft, a partner specialisingin energy affairs at law firmCMS Hasche Sigle,

“The Bundesnetzagentur[federal network agency forelectricity] has authority toregulate certain details ofthis new auction model, butnothing is certain yet,” headds. “The legal frameworkis still rather misty.”

Reforms aim to contain cost ofambitious clean energy targetsGermany

New rules will stillprotect industry butincrease the burdenon consumers, saysJeevan Vasagar

Planned expansion of renewable energy

Source: German Economics Ministry

Cumulative growth to 2020 (GW)

2014 2015 2016 2017 2018 2019 20200

5

10

15

20Offshore wind Onshore wind Photovoltaic Biomass

Sigmar Gabriel,Germany’seconomy andenergy minister

On a bright but windy week-end in Germany lastmonth, renewables set anew record. For an hour atlunchtime on Sunday May

11, wind and solar energy accountedfor 70 per cent of the national electric-ity supply, illustrating the transfor-mation brought about in Germany’senergy system.

The record reached that day alsohighlighted the challenge facing con-ventional power generators, as theglut of clean energy in the systempushed electricity prices into negativeterritory. On the intraday energy spotmarket, prices ranged as low as minus€48.19/MWh. For a brief period, utili-ties were paying grid operators totake their energy.

The renewable energy law whichcame into force in 2000 set guaranteedprices for 20 years and provided cleanenergy with favourable access to thegrid, sparking a scramble to installsolar power, wind and other renewa-ble energy sources.

The consequences of the Energie-wende, as Germany’s ambitious tran-sition to green energy is known, arenow visible across the country. Photo-voltaic panels speckle the roofs ofBavarian farmers and community

wind farms dot the windswept plainsof northern Germany.

While established utilities wereslow to respond, new businessesseized the opportunity. Renewableshave gone from being the province ofidealistic “Grüne Spinner” – crazygreens – to being firmly anchored inthe mainstream, says Tim Loppe, aspokesman for one such business,Naturstrom.

The company, founded in 1998, has240,000 customers across Germanyand has signed a partnership dealwith BMW to offer clean energy tobuyers of the carmaker’s electricvehicles.

In March, Audi offered a similardeal to buyers of its electric A3. TheVolkswagen-owned brand teamed upwith Hamburg clean power providerLichtBlick, which has 600,000 privateand business customers across Ger-many, to recharge its electric modelwith hydroelectric power.

For investors, the news from Ger-many’s traditional power providershas been bleak. Last year, RWEreported an annual loss for the firsttime since the Federal Republic ofGermany was established. Germany’ssecond biggest utility is crossing a“vale of tears”, its chief executive

Peter Terium told the Financial Timesrecently.

Eon, Germany’s biggest utility bymarket value, suffered a 46 per centdrop in underlying net income in 2013.Income fell from €4.2bn in 2012 to€2.2bn last year. The hit to the utili-ties’ profits had made it tougher toadapt their business models.

“The government forced significantlosses on the utilities’ businesses andon their market values, which limitstheir ability to invest,” says RalphTrapp, managing director of Accen-ture’s German utilities practice.

It was an indication that the pace ofthe Energiewende was too fast, MrTrapp says. “It was not a coherentsolution.”

But the tide may be turning infavour of the big power providers.Reforms to Germany’s renewableenergy law, due to come into force inAugust (see below), pose a challengeto the prospects of smaller players.“Politicians are giving the big energyconcerns space to breathe,” says MrLoppe, of Naturstrom.

He suggests three reasons why thereforms to Germany’s Energiewendewill cramp smaller developers. First,a tendering model for new cleanenergy projects that is due to be

introduced by 2017 will raise the risksfor smaller businesses. Such compa-nies are less likely to be able to affordearly investment in a project thatdoes not win a tender.

Second, annual caps on new instal-lations of renewable energy meanthere is a possibility that by the timea project comes to fruition, the annuallimit will have been reached. Again,bigger companies are more able tobear such a risk, he says.

Third, the higher feed-in tariffs foroffshore wind projects, compared withother forms of clean energy, favour amarket from which smaller playersare excluded because of its scale andtechnical difficulty.

The traditional model of power gen-eration in vast plants outside big cit-ies has been squeezed hard by theEnergiewende. Eon plans to shutmore than a quarter of its conven-tional generating fleet in Europe.

Both Eon and RWE are seeking toexpand instead in areas that requiregreater interaction with customers.These include helping customers tooptimise their energy consumption, orworking with customers who also gen-erate their own power using sourcessuch as rooftop solar panels or com-bined heating and power plants.

“Utilities need to develop agility,”says Mr Trapp of Accenture. “That isnot the way they have been used toworking.”

The utilities are waking up to aworld in which selling electricity is nolonger enough. In the UK, RWE’sNpower has teamed up with Google’srecent acquisition Nest to sell a ther-mostat that tracks household energyusage and uses the data to set temper-atures automatically, saving energy.

“What helps [the utilities] is theyhave so much experience,” Mr Trappsays. “If you combine that with newtechnology, they are certainly in anadvantageous position.”

It remains to be seen whether gainsin new technology will make up fordeclines in utilities’ core competence.The extent to which customers arewilling to pay for the extra conven-ience and bespoke solutions offered bydigital technology is open to question.

However, once they have discoveredand tested the right technology, theability to roll it out on a big scale isan advantage, says Mr Trapp.

With wholesale power prices pre-dicted to fall further in the next fewyears, the outlook remains tough forutilities. But there are a few glimmersof hope.

Utilities grapplewith Germany’sbig switch togreener power

RenewablesThere is newhope for strugglingtraditional providers, writes JeevanVasagar

Price guaranteed:government subsidiessparked a scramble togenerate solar andwind power Dreamstime

Wind and solar energybriefly accounted for70 per cent of supply

4 ★ FINANCIAL TIMES TUESDAY JUNE 24 2014

Modern Energy

Shortly before emptying into theAtlantic, the Congo river, whichdrains the world’s second largestrainforest, twists and dips into asharp, narrow bend and falls 100m injust 15 kms.

The rapids, in the DemocraticRepublic of Congo, are the world’smost powerful, with about 42,000cubic metres of water – 17 Olympic-sized swimming pools’ worth – racingthrough each second.

Two hydropower schemes havebeen built at the Inga Falls, as theseries of rapids is called. Planning iswell advanced on a much biggerproject that would harness the falls’full might and create the world’s larg-est dam and hydroelectric power sta-tion. If it happens, Grand Inga wouldproduce 40,000MW, double the outputof the previous largest hydro scheme,the Three Gorges in China, andenough, in the words of its propo-nents, to “light Africa”.

Last year, South Africa and theDemocratic Republic of Congo signeda treaty to develop the project jointly.It is an ambitious and expensivescheme, with estimates that it willcost as much as $100bn. Great Ingamay be unique in terms of scale, butcountries including Brazil, China andIndonesia, have in recent years begunto build large hydropower projectsafter a lull of more than a decade.

In part, the new push is aimed atproviding renewable energy to meetsoaring demand. Dams can also be away of storing water and managingriver flows to avoid droughts andfloods. Yet these giant projects havetheir critics. They often trigger opposi-tion because they can disrupt ecosys-tems and require thousands of peopleto be uprooted.

A recent report from Saïd BusinessSchool at Oxford university – one ofthe most comprehensive analyses inyears – says many of these projectshave a poor record in terms of costand time and are likely to saddledeveloping countries with large debts.Instead, governments should look intosmaller, more flexible projects, it says.

Hydropower is no newcomer. It isthe biggest renewable electricity gen-eration technology worldwide, with1,000GW installed. This is equivalentto the total electricity capacityinstalled in Europe and 74 per cent ofthe world’s renewable generatingcapacity – enough to supply 740m peo-ple. In the past five years, about 30GWof power has been installed annually,a large amount in China, the rest inAsia, Africa and Latin America.

Hydropower has unique attributes,as it can store energy and be switchedon and off quickly. It is also highlyefficient; schemes can obtain up to 95per cent of the potential energy in thewater and turn it into electricity.

In 2012, the International EnergyAgency predicted hydropower coulddouble its contribution by 2050. Itcould prevent “annual emissions of upto 3bn tonnes of carbon dioxide fromfossil fuel plants”, the agency said.

Most of the growth will come fromlarge projects in emerging economiesand developing countries, the IEApredicted. Yet research such as theSaïd Business School survey of 245large dams built in 65 countries since1934 is raising questions about theviability of huge dams.

The study found that large dam con-struction costs were on average morethan 90 per cent higher than initialbudgets, while eight out of 10 suffereda schedule over-run. It concluded thatthe Brazilian Belo Monte dam in theAmazon and the Gilgel Gibe III damin Ethiopia, and similar projects else-where, are likely to face “large costand schedule over-runs seriouslyundermining their economic viability”.

Developing countries often have toborrow heavily for imported goods orservices to build big dams, puttingpressure on public finances. TheItaipu dam, built on the border of Bra-zil and Paraguay in the 1970s, suffereda 240 per cent cost over-run thataffected Brazil’s finances for threedecades, the authors of the study say.

Dam proponents argue that theindustry has learnt from past mis-takes. The IEA identified several chal-lenges if hydropower were to meet itspotential, including overcoming barri-ers relating to the environment, pub-lic acceptance and finance.

Richard Taylor, executive directorof the International Hydropower Asso-ciation, a non-profit group working toadvance sustainable hydropower, dis-agrees with several of the Oxfordstudy’s findings, including the assess-ment of the Itaipu dam. He points outthat it has generated revenues of$63bn so far – six times the cost ofconstruction.

The project, he adds, will operatefor 60 more years and is therefore“difficult to criticise on an economicbasis”. Hydropower projects havehigh initial costs, but what matters,says Mr Taylor, is whether they arean investment worth undertaking.

“You need to look at the value ofservices from the project and itslifespan – a dam will last 100 years ormore and will therefore provide serv-ices for many generations,” he says.

Guy ChazanEnergy editor

Ed CrooksUS industry and energy editor

Lucy HornbyChina correspondent

Michael KavanaghEnergy and utilities reporter

Sylvia PfeiferFreelance journalist

Jeevan VasagarBerlin correspondent

Jerry AndrewsCommissioning editor

Steven BirdDesigner

Andy MearsPicture editor

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Grid operators around theworld are grappling withhow to ensure generatingcapacity is available tomeet peaks in demand.

In Europe, the encourage-ment of renewable butunpredictable wind andsolar power has made guar-anteeing supply more com-plicated. Amid warnings ofthe looming threat of poweroutages and dips in voltage,debate has centred on howto incentivise operators ofpower stations – whose out-put might be needed onlyintermittently – to top upsupplies to the grid.

However, regulators arealso looking at ways ofencouraging customers tocurtail usage at peak timesto curb unnecessary invest-ment in new power plants.

Brett Feldman, an analystat Navigant Research, sayslessons can be learned fromNorth America, the largestmarket for “demand-response” programmes.

These are designed toattract households andbusinesses willing to trimconsumption at peak timesfor a financial incentive.

“At the same time, tech-nology advances in meter-ing, controls and end-usedevices are making it easierfor customers to participatein demand-response pro-grammes and manage theirenergy usage,” he adds.

Mr Feldman predicts thatglobal demand-responsecapacity will grow from30.8GW this year to nearly200GW in 2023, which trans-lates into a market of $1.6bnrising to nearly $10bn. Thebulk of the market is in theUS, but interest in Europeand elsewhere is growing.

The potential savings toutilities are enormous. Each250MW shaved from peakdemand may remove theneed for a new average“peaking” power stationthat might sit idle off-peak.

PJM Interconnection,operator of the world’s larg-est competitive electricitymarket – 60m customers in13 states in the Midwest andeastern US – last month pro-cured 11,000MW of demand-response capacity, com-pared with a total 167,000MWof supply it secured.

PJM’s capacity auctionsallow demand-response pro-grammes to compete on costwith generators offeringpeak-time output. Encour-agement of a market willingto accept interruptions hasavoided the need to financeand build 40 peaking powerstations in the region, saysMr Feldman.

The shift leaves PJM withan aggregate reserve mar-gin of more than 25 per centover predicted peak demandthis summer – well abovethe 16 per cent required byregulators, said MichaelKormos, PJM’s executivevice-president of operations.

In the US, domestic cus-tomers typically get $20-$25for interruptions to air con-ditioning during summerpeaks, controlled by timedswitches. The rollout ofsmart meters and improved

technology will allow lessnoticeable interruptions.

Aggregator companiessuch as EnerNOC and Com-verge are offering industrialcustomers technologies thatallow them to cut peak andoverall demand as well asbenefit from lower billsthrough the direct incen-tives from demand-responseprogrammes.

EnerNOC points to theexample of Great Lakes ColdStorage, a frozen and refrig-erated warehouse operator.The installation of new sys-tems enabled refrigerationto be interrupted withoutrisk to stock and led to thereceipt of $33,000 in direct

payments for contractinginto a PJM demand-responsescheme through EnerNOC –part of wider savings esti-mated at $250,000 in thecompany’s power bill.

Mr Feldman suggests thatat nearly 10 per cent ofcapacity in some USregions, demand response“is getting towards thelimit for customer satisfac-tion and grid reliability”.

However, he predicts thatcurtailment of coal plantsand growth of intermittentwind and solar power willsee demand response growin Europe.

National Grid, the UKgrid operator, is extendingits demand-response pro-

grammes, prompted by ashort-term squeeze on gen-erating capacity. The com-pany already has deals withlarge users such as steelworks that involve shortinterruptions to supply. Thedeals allow for the use ofsources such as back-upgenerators at hospitals.

But the recent retirementof a range of coal and gas-fired power stations hasraised concerns at Ofgem,the UK energy regulator,about whether enoughcapacity remains to guaran-tee the country’s needs inthe middle of this decade.

In response, NationalGrid said it would tenderfor up to 330MW of demandside balancing reserve – inwhich large energy usersreduce their demand duringwinter weekday evenings inreturn for payment – forthe coming winter, plus upto 1,800MW of combineddemand response and addi-tional peak power capacityfor the following winter.

Dermot Nolan, Ofgemchief executive, describedthe contracts as “the rightlevers to keep the lights onfor households this winter”.

Before confirmation ofthe tendering, Steve Holli-day, chief executive ofNational Grid, said he wassatisfied with initial inter-est from customers willingto constrain their use, thushelping to guarantee supplyto others in the “shortest,darkest days of winter”.

Financially motivatedenthusiasm for – ratherthan panic about – plannedpower interruptions tooffice, factory and house-hold equipment may soonbecome more commonplace.

US shows how to conquer peaksDemand management

Users get better dealsfor accepting supplyinterruptions, writesMichael Kavanagh

Hydropower underscrutiny over valueRenewables

Study comes amid new pushto build more mega-dams,writes Sylvia Pfeifer

Cutting use at keytimes is shown toreduce the need fornew power stations

Harnessing water: there are plans toexpand schemes on the Congo river

When Jianfeng, the Chi-nese chemical fertilisermaker, announced lastSeptember that it wouldswitch to shale gas as its

feedstock base material, it was thefirst Chinese company to do so.

But instead of claiming the pio-neer’s crown, Jianfeng becameembroiled in a national debate overthe viability of Chinese shale gas, ashigher-than-expected prices took theshine off its decision.

Nine months after its initialannouncement, the fertiliser companyhas yet to reach an agreement withSinopec, the state-owned oil company,on the price of gas from China’s firstcommercial shale development.

The shale revolution in the US hasreduced the country’s energy costsand imports. China hopes for similarbenefits but is finding the US momen-tum hard to match.

By some estimates, China boaststhe world’s largest shale resources,with 68 per cent more technologicallyrecoverable than the US, according tothe US Energy Information Adminis-tration (EIA).

Shale has been touted as a gamechanger for China, the world’s largest

crude oil importer and consumer ofhalf the world’s coal.

However, a top-down mandate todevelop shale in China has so farfailed to yield the competitive vol-umes or low costs of the privatelydeveloped industry in the US.

Shale beds in China tend to bedeeper and more geologically complexthan the deposits of North America.“The geology was always going topush the cost of development higherthan in the US,” says Elliot Brennan,a researcher with the Sweden-basedInstitute for Security and Develop-ment Policy.

Other costs arise from the less-developed pipeline infrastructure andthe dominant role of state monopo-lies. Producing Chinese shale gas willcost more than double the biggest USprojects by 2015, Bloomberg NewEnergy Finance warned in a recentreport. Boosting shale gas productiontherefore requires increased tariffs orhigher subsidies, it said.

Beijing aims to produce 6.5bn cubicmeters (bcm) of shale gas by 2015 andbetween 60 bcm and 100 bcm by 2020.The standard bearer so far is Sinopec,which is expanding drilling at Fuling,20km from Jianfeng’s fertiliser plantnear the southwest city of Chongqing.It has pledged to produce 5 bcm ofshale gas from the Fuling deposit bythe end of 2015.

Sinopec is also lobbying fiercely forcontinued subsidies for shale gas –now at Rmb0.4/bcm – without whichit says it cannot break even. China’scurrent subsidies expire in 2015. The

company is spending about Rmb80m($1.2m) for each well it drills in Ful-ing, according to Chinese mediareports, nearly four times the cost inthe US.

China is keen to exploit shale as analternative to dirtier coal, as part ofefforts by the government to reduceunrelenting air pollution. The Chineseleadership also sees shale as a way todevelop domestic energy sources andreduce vulnerability to imports.“Energy security is a top priority forChina,” Mr Brennan says.

Lin Boqiang, an energy expert atXiamen University, believes the priceproblems will eventually be fixed

after production picks up. He says itis China’s industrial structure that isholding back the fledgling business.

Beijing, impatient with the pace ofshale development by Sinopec andCNPC, the state oil majors, openedthe second round of shale tenders toprivate companies.

But drilling in those blocks hasbeen constrained by lack of funds andstate oil companies’ control over pipe-lines. A third round of tenders isplanned this year.

Smaller companies, if they findshale gas, would either have to sell it

to oil companies at unattractiveprices or fund their own pipelines toreach distant markets where gasprices are higher.

Even if companies overcome tech-nological barriers posed by geologyand the underdeveloped pipeline sys-tem, further challenges remain.

“Something should be done aboutthe pipeline monopoly of Sinopec andCNPC, or else it will be hard for othercompanies to get the gas they extractto the market,” says Mr Lin.

Another challenge is water scarcity.The Tarim Basin in the deserts ofXinjiang, near China’s restive borderwith Central Asia, holds some ofChina’s more promising shale depos-its, according to EIA estimates. Butthere is not enough water for frack-ing, a process that involves largeamounts of water being injected athigh pressure to free gas trapped inshale rock formations.

Areas with more water also havemore people. Chongqing and neigh-bouring Sichuan, where CNPC is part-nering with Shell to drill shale wells,are some of China’s most densely pop-ulated regions, with villages clusteredthickly in the mountain valleys.

These factors mean it could be awhile before signing up for shale gasis an easy decision for customers suchas Jianfeng.

As Accenture concluded in a recentreport: “The country’s above-groundnon-technical factors pose the biggestchallenge for investors.”

Additional reporting by Owen Guo

Costs hamper shale extractionChina

Companies face challengesfrom geology, monopoliesand water, says Lucy Hornby

Pressure: a worker checks a Sinopec appraisal well in Sichuan province, China. Some estimates suggest China has the world’s largest shale gas resources Reuters

Producing Chinese shalegas will cost more thandouble that of US projects