Category Archives: Coal

02.11.12
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Converting to Bioenergy: Benefits and Challenges

Tilbury’s jetty on the river Thames, which can accommodate Panamax class vessels of up to 60,000 tonnes, saves an estimated £30 million ($47 million) per year in rail freight costs. Photo courtesy RWE npower

With legislation increasingly tough on coal-burning plants, many are switching to renewable fuels to ensure longevity. But supply chain issues may prevent some plants from undertaking the conversion process. Tim Probert profiles the UK’s Tilbury power station, a 1960s coal plant which has become the world’s largest biomass plant, and talks to Drax about the potential to convert its 4 GW coal plant. This article was first published in the January-February edition of Renewable Energy World magazine.

To describe the British town of Tilbury as a green beacon would require a stretch of the imagination. Home to London’s main container port and an unsightly 1960s concrete-slab power plant, with a curious smell emanating from the nearby sewage works, Tilbury epitomises twentieth century grit, smoke, soot and clank.

Yet a beacon of green energy is exactly what Tilbury power station has become. In December 2011, Tilbury B, a 1062 MW coal-fired plant opened in 1967, was successfully converted to a 742 MW biomass plant. Tilbury thus became the largest biomass burning power generation facility in the world, beating the previous coal-to-biomass record holder, GDF Suez’s 180 MW Rodenhuize plant in Belgium, by some distance.

Rather than invest in flue gas desulphurization and other emissions reduction measures, plant owner RWE npower opted Tilbury out of the European Commission’s Large Combustion Plant Directive (LCPD) in 2007, thus restricting the plant to a further 20,000 operating hours between 1 January 2008 and 31 December 2015.

Having conducted trials in September 2010 to prove the technical feasibility of burning biomass exclusively in a coal unit, RWE npower took the decision to convert the plant to biomass two months later.

Tilbury B generated its last kilowatt-hour from coal on 4 March 2011. In the nine months between coal and biomass generation, Tilbury’s engineering manager Dave Dyson worked frantically to ensure the plant can burn 2.3 million tonnes of wood pellets, enough for the remaining 8,000 hours, by 31 March 2013, when the number of Renewable Obligation Certificates (ROCs) allocated to biomass conversion plants reduces from 1.5 to 1.

A bold decision to convert to biomass

Dyson says the decision to convert Tilbury B to biomass was brave. “It was a bold decision by the board,” he says. “The cost of the conversion is in the tens of millions, but the value at risk is in the hundreds of millions.

“We had fixed price coal contracts and forward power prices set. Virtually all the power produced from coal was sold forward. We had to unwind all those contracts and the secure income. Instead we’ve taken on contracts for 2.3 million tonnes of wood without having proven we can use it.”

Burning coal, Tilbury would operate near baseload in the winter months of December, January and February, two-shifting in spring and autumn, with often no units running for weeks at a time in summer. Over the course of a year, this would amount to around 4,500 hours. In order to use up the 8,000 hours by 31 March next year and avoid a financial hit of around £20/MWh, however, Tilbury will run at sub-optimal periods, i.e. when the price of electricity is low.

“Dark spreads could be vastly lower than under a purely commercially driven aspect, but we need to burn the hours up,” says Dyson. “Our revenues from the power price may be barely above the ROC price.”

The Thames – Tilbury’s major advantage

The ‘design life’ of the plant may be only 8,000 hours, but surprisingly little has been spent on converting Tilbury from coal to biomass. The UK’s Drax coal power plant, for example, spent £80 million on new biomass burners, fuel conveying and filtering equipment plus a railway upgrade to co-fire up to 10 per cent biomass, or around 1 million tonnes a year.

Tilbury has one distinct advantage for biomass conversion: its own jetty on the River Thames, which can accommodate Panamax class vessels of up to 60,000 tonnes and saves an estimated £30 million a year in rail freight costs. Dyson’s biggest challenge is dust and most of the investment was spent on equipment that mitigates dustiness, including two new vacuum ship unloaders made by Vigan Engineering, as the existing Kone ship unloaders were too abrasive, an elutriator, and a dedicated pipeline which pneumatically conveys dust to the furnace.

“As with all biomass dusts,” says Dyson, “in the right concentration it is explosive and a sensitizer if inhaled. As far as possible, we derisk the transportation of the fuel by removing the dust at source rather than cleaning up afterwards.”

While coal is typically stored outdoors in huge heaps, biomass needs to be kept dry. Unlike Drax and other biomass co-firing coal plants, there is no virtually no biomass stored on site at Tilbury. The wood pellets arrive on a vessel and are unloaded and burned during the course of a week. Once the ship’s payload is empty and departs, another vessel arrives within hours and the process starts again.

Dyson explains: “We only store enough biomass onsite to see through the few hours where there is no ship on the jetty, around six hours’ margin, so we have to have a slick, just-in-time shipping turnaround. I suspect the fuel handling team will have significantly less hair by April 2013!”

Most of RWE npower’s investment in converting Tilbury was spent on fuel handling. Photo courtesy RWE npower

Impact on efficiency and emissions

Due to the lower calorific content and bulk density of biomass versus coal, Tilbury’s generation capacity will be reduced by around 30 per cent to 742 MW, which in turn has reduced the thermal efficiency of the plant to 35.3 per cent from 37 per cent.

Physical changes to the combustion system are more tweaks than transformation; small modifications have been made to the fuel mills, feeders and burners. When biomass is put through the grinder, it splinters and chips, and does not break down into a standard size unlike coal, which is pulverized into fine dust. Combined with the lower calorific value of biomass, this causes the burners to respond differently.

Therefore, the plant’s low NOx burners have been modified to ensure a more stable flame and to minimize the required amount of support fuel, tall oil. This is achieved by creating a fuel mixing zone (and therefore the flame) nearer to the front of the burner.

Corrosion is also a potential engineering challenge. The high chlorine content in biomass will corrode and diminish the existing boiler fuel pipes.  As operation is limited to 8,000 hours, however, this is not expected to present a major problem.

Based on the results of the biomass trial in September 2010, Dyson expects NOx emissions to fall from 480 mg/m3 to 220 mg/m3, SOx to fall from 800 mg/m3 to 200 mg/m3, and the volume of ash produced from 40 kt/TWh to 4 kt/TWh. Lifecycle carbon dioxide emissions are predicted fall from 0.81 mt/TWh to 0.11-0.18mt/TWh, a 78-87 per cent reduction.

Tilbury & biomass – A one-off?

As things stand, Tilbury B will close once the 8,000 hours have been used up. In July 2010, RWE Npower submitted an environmental assessment scoping report to the UK Infrastructure Planning Commission for Tilbury C, a 2000 MW combined cycle gas turbine and 400 MW open cycle gas turbine plant.  This replaced RWE’s previous proposal to build a 1600 MW supercritical coal plant with carbon capture and storage (CCS).

RWE, however, is also considering the possibility of re-permitting and re-consenting Tilbury B to enable it to continue to operate as a dedicated biomass plant beyond the LCPD limit. “Phase II would be a completely different proposition and we won’t make a decision until well into the second quarter of 2012,” explains Dyson.

“Tilbury B would require a vast upgrade to meet more stringent NOx and SOx emissions standards and we will have to work out if biomass is commercially viable with just 1 ROC. It depends on plant and environmental performance.”

Dyson says the critical aspect of whether other coal plants in the UK and elsewhere can convert to biomass is fuel supply. “In theory there is no technical reason why other coal plants couldn’t replicate Tilbury but whether they could be as much of a commercial success is doubtful. The big question concerns fuel supply logistics.  Biomass is more expensive than coal and trying to get enough of it to an inland power station is a challenge. Most European plants will have the same problem.”

Getting wood

Around 30 per cent of Tilbury B’s biomass is sourced from RWE’s own 750,000 tonnes/year wood pelletization plant in Waycross, Georgia; a further 50 per cent will come from the USA and Canada. The remaining 20 per cent come from Europe, either the Baltic States or southern Europe. All fuel is debarked softwood pellets.

Dyson believes it is unlikely RWE will develop a similar biomass facility in Europe, much less the UK. “Sustainability is an issue in Europe. It doesn’t have the scale as the US. If we could source biomass sustainably in the UK we would do so, but there are no obvious opportunities to develop that at present.”

According to McKinsey, however, there is no shortage of sustainable biomass. In its World Biomass Energy Report 2009, McKinsey concluded there is enough land available for biomass to exceed currently mandated consumption levels by a factor of two by 2020, even after all other needs were met, i.e. food and feed crops; domestic firewood, projected demand from the forest products industry; no deforestation, and only environmentally sustainable use of virgin land.

And the market is beginning to respond to demand for biomass. In November 2011, the Dutch energy exchange APX-ENDEX launched the world’s first exchange for biomass. At present the Amsterdam-based exchange trades only non-cleared products where the physical settlement is arranged bilaterally by the counterparties. Phase two, however, scheduled to take place during the course of 2012, will include clearing services for wood pellet contracts, providing financial security to market participants.

The exchange has been developed in co-operation with the Port of Rotterdam, which is expecting a boom in biomass handling due to the Dutch Government’s Energy Report 2011 that will make biomass co-firing at coal plants mandatory. According to Koen Overtoom, commercial director of the Port of Amsterdam, the Netherlands, Germany, Scandinavia and the UK will require 15 million tonnes/year of biomass by 2020. Of that figure, Dutch ports will handle 13.5 million tonnes, up from 1.5 million tonnes at present, with the Port of Amsterdam alone accounting for 6 million tonnes.

Drax – a totally different conversion proposition

At 3960 MW, Drax is the second largest power plant in Europe. Unlike Tilbury, Drax complied with the LCPD, thus allowing it to run without restriction. In 2016, however, another European regulation, the Industrial Emissions Directive (IED), will force coal plants like to install selective catalytic reduction (SCR), which removes NOx from flue gases.

The cost of IED compliance for each of the plant’s six 660 MW coal units would probably run into the hundreds of millions of pounds. Throw in the UK Treasury’s carbon floor price/tax and full auctioning of Phase III European Union Emissions Trading Scheme (EU ETS) carbon permits and one can see why production director Peter Emery is considering other fuel options..

Drax currently co-fires up to 8 per cent biomass, burning approximately 1.2 million tonnes in 2011, mostly wood chips, straw pellets, oat and sunflower seed husks. Drax is now considering converting the entire plant to biomass. “When it became clear that UK government policy was not just pricing carbon into power production via the EU ETS but also the carbon floor price, we felt we had to do something radical,” says Emery.

“If we can’t compete in a world post-2016 with a very high carbon price we would opt out of the IED. Plants like Tilbury which opted out of the LCPD may just close rather than convert to biomass. Plants that opted in may find that the economics stack up. So biomass is a big deal for us, it will enable us to be competitive and enable us to develop the business.”

Drax is converting one of its 660 MW units to burn biomass. If it was to convert fully, says Emery, the capacity of each unit would be reduced to around 500 MW, each burning 2.5-3 million tonnes a year.

Sourcing this volume of biomass would be a major challenge. Drax is unable to source enough biomass at the right price in order to co-fire the permitted 12.5 per cent limit, let alone a 100 per cent conversion. “The biomass market isn’t there, and sourcing it is not as simple as having a group of traders with telephones,” Emery explains. “We’re having to negotiate deals to build pellet plants and set up shipping contracts, or encourage British farmers to grow miscanthus, willow or eucalyptus.

“Could we get hold of 15-18 million tonnes of biomass tomorrow? Yes, but biomass that has been harvested, pelleted and processed for power plants? Clearly not. Our challenge is to develop the supply chain, which may take 20-30 years.”

Drax wants the UK government to think again about reducing the amount of ROCs allocated to biomass conversions from 1.5 to 1. “There’s a massive potential for biomass to be industrialized in Britain and the ROCs would help us to develop the infrastructure. If the British government commits to a firm biomass policy over the 15-20 years, the rest will follow.

“For example, tree plantations use white wood pulp for paper and building materials but a lot of the offcuts aren’t used. There’s also an awful lot of land that is not agricultural grade not being used that would be ideal for biomass.”

Biomass silos at Drax power station, UK. Photo courtesy Drax

Conversion = Addiction to subsidy?

Based on 2010 generation of 26.4 TWh at an average power price of £51.60/MWh and burning 15m tonnes of biomass at £80/tonne, Drax could expect revenues (including 1 ROC) to comfortably outstrip the higher fuel costs by more than £500 million, even with a 25 per cent drop in output. Add in exemptions from buying EU ETS permits for carbon, of which Drax emits 22.8 million tonnes/year, and the carbon floor price, and biomass conversion looks attractive.

But converting to 100 per cent biomass would mean Drax would be reliant on subsidy to be commercially viable. Is it fair to ask British taxpayers to keep Drax alive this way? “This is about starting a brand new industry,” says Emery. “The idea is not to generate super profits versus coal, but to give an adequate return on investment for burning biomass.

“The government has got renewables targets to hit, it wants to reduce CO2 and the beauty of co-firing and unit conversion is that it’s cheap. It’s broadly half the cost of offshore wind and broadly in parity with onshore wind, but biomass is also fully dispatchable. The taxpayer would think that’s very fair.”

Is Drax doomed without biomass? “We are not doomed, but the direction of government policy means that coal-fired generation in its current guise is doomed. Biomass gives us a route to market with cost-effective low-carbon generation. So, yes, it is helping to save Drax, but would you rather spend double the money to build more wind farms and shut Drax?”

Keeping its options open, Drax is also exploring CCS and considering a combined cycle gas turbine plant on the site of the current facility. In the meantime, one would hope Emery’s prediction of 20-30 years to develop the biomass supply chain will prove to be a little pessimistic.

As REW goes to press, German utility E.ON has announced that it plans to convert one of two 500 MW at its coal-fired Ironbridge coal plant in the UK to biomass, with the option to convert the second unit at a later date. The utility has applied for planning permission to build a fuel store on-site. The plant chose to opt out of the LCPD, and will open in 2013.

12.05.11
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Vattenfall abandons 500 MW Jaenschwalde carbon capture plant in Germany

Vattenfall was to retrofit a 250 MW coal unit with post-combustion CCS and build a new 250 MW Oxyfuel unit at a cost of €1.5 billion. Courtesy Vattenfall

Swedish power utility Vattenfall has abandoned a planned 500 MW carbon capture and storage (CCS) plant at Jaenschwalde, Germany, expected to cost €1.5 billion, after the German federal government rejected a bill allowing underground carbon storage.

The 500 MW CCS demonstration project was to utilize a new 250 MW Oxyfuel boiler and see another 250 MW boiler retrofitted with a post-combustion capture unit. The EU-supported project would have been operational by 2015/16.

In July, Germany’s lower house approved a bill allowing the underground storage of carbon dioxide but it was rejected by the upper house on September 23. Following the rejection of the bill by the Bundesrat, a mediation committee was formed, which adjourned twice in November without result.

In a statement, Tuomo Hatakka, Vattenfall´s country manager for Germany, said: “We must unfortunately accept that there is currently insufficient will in German federal politics to implement the European directive so that a CCS demonstration project in Germany could be possible.”

Hatakka said that a clear legal framework was needed and the existing draft for the CCS law is, without substantial improvement, insufficient for multi-billion investments in further development of carbon capture technology.

The Swedish state-owned utility said it would continue to further development of CCS. Vattenfall is a main partner in UK’s largest CCS pilot plant at Ferrybridge Power Station in West Yorkshire, which opened 30 November.

The company said it will also continue the test operation of the CCS pilot plant at Schwarze Pumpe, Germany, and work for the development of a European storage infrastructure.

10.28.11
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Is carbon capture & storage a dead parrot?

Carbon capture and storage has to overcome fundamental technical and regulatory barriers to become a viable commerical proposition

As part of researching a forthcoming Gas Turbine World article about retrofitting CCS for gas-fired power plants, last night I attended a ‘Green in the City’ panel discussion put on by EcoConnect to discuss the future of carbon capture technology. Attendees would be forgiven for thinking carbon capture has no future.

There is no shortage of financing available for CCS. Norway has called CCS its “moon landing” and has state oil company Statoil on the case. The EU’s NER300 programme to fund at least eight CCS demonstration projects is worth around €3-4 billion. In the UK, the Government’s £1 billion pot funded out of direct taxation to pay for up to four CCS projects remains unspent after it pulled the plug on Scottish Power’s Longannet scheme.

CCS is seen as essential for the decarbonisation of the power sector. As Klaus Lackner, Professor of Geophysics at Columbia University, said: “Either you have CCS, or you deny climate change. Or you abandon fossil fuels.” Difficult to argue with. But is the solution to decarbonizing the power sector piping CO2 hundreds of miles out to sea, sticking it under the seabed and putting a big plug on top? And should it need a carbon price of $200 per tonne to be economically viable, as Lackner suggests?

According to Dr. Alan Knight OBE, a former chair of the UK Government’s Roundtable on Sustainable Consumption, no. Knight sees CCS as little more than convoluted landfill. “The big companies like Google are not turned on by carbon landfill,” he said. “Isn’t it better to create commercial products with CO2? Those carbon molecules are an exciting resource for fuel security and food security.”

Far better to give the £1 billion from the CCS pot, says Knight, to projects of the type mentioned in the articles here, here, here and here.

I digress. Besides the cost of building carbon capture units, the operational costs, the thermal efficiency penalties and other engineering drawbacks, the other crucial element of CCS – storage – appears to have been overlooked. This is a shame says Dr. Ward Goldthorpe, who heads up the Crown Estate’s CCS programme, because the amount of CO2 to be stored to hit IEA 2050 carbon targets requires infrastructure three times the current size of the entire European gas industry.

The problems of storing CO2

There’s a general impression that captured carbon dioxide can be easily transported across the existing natural gas pipeline infrastructure, swapping CH4 for CO2. That could be highly dangerous, according to the UK Health and Safety Executive, due to highly corrosive ‘dense phase’, pressurized CO2.

The problem is that CO2 captured from power plants always contains moisture. Wet CO2 is very acidic and the potential for corrosion, leakage and even explosions is such that either the CO2 will have to be dried, which imposes a further efficiency penalty, or the pipelines have to made from corrosion-resistant steel. Both techniques could be prohibitively expensive.

The FEED study of the UK’s failed Longannet project is quite an eye-opener.  Anyone who thinks Norwegian Prime Minister Jens Stoltenberg was exaggerating when he likened CCS to landing on the moon should have a look at the Longannet ‘Post-FEED Top 50 Risks’ document. Notice how many of the Top 10 concern CO2 storage.

While Europe is relatively advanced in CO2 storage, namely the Norwegian enhanced oil recovery (EOR) projects, a huge amount of technical work needs to be done for regulating CO2 with impurities, i.e. water, says Goldthorpe. “The regulatory framework is essentially adapted from the US petroleum industry, but a lot of CO2 transport in the US is pure CO2. Devising standards for the CCS industry that can cope with CO2 plus impurities is still a work in progress.”

Goldthorpe says the major stumbling block for CO2 storage from power plants is the total lack of a value proposition. “Unlike the EOR projects in the US, we are trying to implement in one fell swoop integrated CCS projects with no associated value proposition at all. The public funding is not prepared to underwrite the awkward risk-sharing and liability issues which pop out of the integrated model.”

DECC says “developing storage sites may be an uncertain, potentially time-consuming, costly and risky business opportunity”. That’s putting it mildly. But if CCS is to take off, these issues need urgent addressing. Is it worth the expense?

10.19.11
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“Show us the money” says Alstom after Scottish Power’s Longannet CCS project collapses

Alstom, Drax and National Grid have proposed building a 426 MW gross oxy-fuel CCS plant at the 4 GW Drax coal plant.

French power OEM Alstom wants part of a £1 billion UK Government pot to fund carbon capture and storage (CCS) projects for its proposed 426 MW oxyfuel project at Drax power station after Scottish Power’s Longannet project collapsed.

On 19 October the UK’s Department of Energy and Climate Change (DECC) announced Scottish Power’s £1 billion scheme to build a 300 MW demonstration unit at the 2400 MW Longannet coal fired power plant had collapsed after the utility demanded an additional £500 million to secure 100 per cent project financing. Energy secretary Chris Huhne said: “A decision has been made not to proceed with Longannet but to pursue other projects. One billion pounds will be available for a new process and we are expecting a number of promising bids from both Scotland and England.”

Philippe Paelinck, Alstom’s director of CO2 business development, told Millicent Media that DECC should consider investing in its planned stand-alone 426 MW oxy-fired CCS plant at Drax’s 4 GW coal plant site at Selby, North Yorkshire.  As part of the project National Grid and an offshore partner would develop a transmission system out to the southern North Sea where the CO2 would be stored permanently.

“The UK government should give us the money from the Longannet plant so we can build the Drax project,” he said. “We are ready to go. Longannet was looking for 100 per cent financing and Scottish Power is worried about its coal assets,” he said.

Paelinck said the collapse of the Longannet project was symptomatic of the parlous state of European utilities’ balance sheets. “It is a sign of the current weakness of European utilities. It is increasingly difficult for European utilities to make such bold investment decisions. Their business model has been chewed up by all kinds of measures like nuclear phase-outs, increased penetration of renewables, carbon taxes and so forth. It is not a good climate to make big investment decisions [for CCS].”

The Alstom executive remains optimistic about the prospects for CCS despite the latest setback. “I am not worried about CCS being pushed out in favour of cheaper alternatives, ” he said.

“From our discussions with DECC we see a strong will to decarbonize the power sector and I do not see their stamina sapping. We are having some confidential discussions with utility customers about retrofitting a full-size power plant with CCS and we may see some new projects popping up in the coming months.”

09.08.11
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New IEA chief says no to nuclear is not an option

Maria van der Hoeven, new executive director of the IEA, which will publish its 'low-nuclear scenario' in November. (AFP/ANP/File, Ermindo Armino)

The new chief of the International Energy Agency (IEA) Maria van der Hoeven says nuclear power must have a place in the future energy mix despite the Fukushima catastrophe and the decision by some countries to opt out.

The former Dutch minister for economic affairs, who took up the post of IEA executive director on September 1, succeeding Japan’s Nobuo Tanaka, said she would be looking to countries like Germany, Italy and Switzerland to explain how they plan to cover their future energy needs without nuclear power.

“If you would like to abandon nuclear, then my question is: ‘How are you going to meet the growing demand of energy when you are abandoning one of your sources? If the answer is ‘we’ll do it with renewables’, then my question will be ‘how’?”

In an interview with AFP, Ms. van der Hoeven said: “Nuclear power is necessary for our energy future. We need it. If we really want to go – and we do – towards a future where we have less CO2, there are only two real things to get there, and it has to do with nuclear because it doesn’t produce CO2 and it has to do with renewables.”

The IEA’s World Energy Outlook 2011, to be published in November, will examine the effects of a low-nuclear scenario, said Ms. van der Hoeven. “It will show what will happen if nuclear is not going to be part of the energy mix anymore. What we see in Germany is that there will be greater coal and gas and imports from France of nuclear energy.”

“If you would like to abandon nuclear, then my question is: ‘How are you going to meet the growing demand of energy when you are abandoning one of your sources? That question has to be answered by all those countries and governments who would like to abandon nuclear. If the answer is ‘we’ll do it with renewables’, then my question will be ‘how’?.

“How cost-effective are renewables? How much are they deployed at this moment? How are you going to speed up the curve of renewables so that they’re going to be a greater part of the energy supply?”

The Paris-based IEA is the energy branch of the Organisation for Economic Co-operation and Development, which represents 28 industrialized nations.

08.23.11
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Whatever happened to carbon capture and storage?

CCS works but the economics do not appear to stack up at present. Vattenfall

According to the International Energy Agency, the world will need 100 carbon capture and storage (CCS) plants by 2020 and 3400 by 2050 in order to reduce greenhouse gas emissions by half. That equates to building a CCS plant every three days from 2020. At present, however, there is not a single large-scale CCS facility at a power station anywhere in the world.

While renewables continue to receive generous state subsidy, CCS is in danger of becoming the forgotten weapon in the war on carbon, the rusty spanner in the climate change toolbox, as an increasing number of projects are spiked or scaled back.

Last month in the US, American Electric Power (AEP) postponed Phase II of a commercial-scale deployment of Alstom’s chilled ammonia carbon capture process at its Mountaineer coal plant in New Haven, West Virginia. This was particularly frustrating to the CCS industry as in June Alstom and AEP had successfully validated Phase I, which captured up to 90 per cent of the CO2 from a slipstream of flue gas equivalent to 20 MW, injecting it into geologic formations for permanent storage 1.5 miles below the surface.

Mountaineer II would have captured at least 90 per cent of the CO2 from 235 MW of the plant’s 1300 MW capacity, but as a regulated utility, AEP needs regulatory approval to recover its share of the costs without federal requirements to reduce greenhouse gas emissions already in place. This uncertainty also makes it difficult to attract partners to help fund the industry’s share, says AEP.

This is symbolic of the state of play with CCS. There have been numerous successful small-scale demonstration projects like Mountaineer I, mostly funded by the state, but large-scale CCS needs serious cash. And in the long-term, it can only come from the private sector. Unfortunately, profitable CCS plants appear to be a long way off.

Alstom’s Senior Vice President for Power and Environment Policies Joan MacNaughton says the cost of electricity generated by coal and gas plants with CCS is competitive with other low or no-carbon energy sources, such as wind, solar, geothermal, hydro and nuclear. That may be so in the future, with a high carbon price, but in the here and now, CCS looks very expensive.

Vattenfall’s 500 MW demonstration project at Jaenschwalde, Germany, which will utilize a new 250 MW Oxyfuel boiler and see another 250 MW boiler retrofitted with a post-combustion capture unit, will cost an estimated €1.5 billion. In comparison, the recently Alstom-built CCGT in Langage, UK, with a capacity of 885 MW, cost just €460 million.

Alstom believes, just like with NOx, SOx and particulates, that carbon capture will become just another cost of generating power, as standards and regulations dictate, in order to do business. If the IEA’s scenario of 3400 CCS plants by 2050 is to be anywhere close to being achieved then the costs need to come down rapidly. And costs will only tumble when governments force utilities to build CCS not just for new coal plant, but, crucially, for new gas plant too.

08.12.11
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Germany’s giant utilities are posting losses and slashing jobs – what’s going on?

E.ON and RWE are posting losses due to a combination of squeezed coal and gas margins and the German nuclear phase-out

German utility E.ON posted its first ever quarterly loss and is laying off up to 11,000 workers. Compatriot RWE is up the creek following Frau Merkel’s decision to abandon nuclear power. And investors are no longer deeming these utilities a ‘safe haven’ in turbulent financial times. What is going on?

E.ON

Germany’s biggest utility has posted a net adjusted loss of €382m ($543m) during the second quarter of 2011. E.ON’s half-year profits have fallen 45 per cent and expects net income to be down to €2.1-2.6 billion this year – a drop of over 70 per cent.

Current market conditions – including overcapacity, technological change and government intervention – are making life difficult for the foreseeable future, the Duesseldorf-based company says. The planned permanent closure of nuclear facilities and the nuclear fuel tax has slashed first-half earnings by €1.9 billion.

Power generation fell by 3 per cent to 132.6 billion kWh during the first half of 2011 due to the enforced shutdown of its Unterweser and Isar 1 nuclear plants. E.ON operates six nuclear plants, with the first due offline in 2019.

By 2015 E.ON plans to generate 25 per cent of its revenue outside Europe, up from around 10 per cent today. Main targets for growth are building wind farms in North America and gas power plants in Russia. At €35 billion, however, E.ON is heavily indebted as a result of major acquisitions in recent years, and rating agency Standard and Poor’s (S&P) has put the company’s credit outlook on negative.

In order to decarbonize its generation and invest in growth areas, CEO Johannes Teyssen says E.ON will cut around 9,000-11,000 people – around 14 per cent of its workforce.

Through its co-operation with Gazprom in building the Nord Stream pipeline that will transport Russian gas directly through the Baltic Sea into Germany, E.ON is well positioned in the gas market, where analysts see the biggest growth potential in Germany’s fossil fuel power generation sector.

However, E.ON’s gas trading branch is a loss-maker because Gazprom insists on selling its gas in long-term oil-indexed contracts which, at low spot market prices, force it to sell gas at a loss.  E.ON said that its gas trading loss in 2011 could be around €1 billion.

RWE

Germany’s second largest utility recorded a half-yearly profit slump of 40 per cent and recorded a net loss of €229 million in the second quarter of 2011, down from a €486 million net profit in the same period last year. RWE cites €900 million of decommissioning and nuclear fuel tax costs as a major reason why its operating profit fell 33 per cent to €3.3 billion.

The shutdown of RWE’s Biblis nuclear plant following Fukushima has reduced power output by 7 per cent compared with last year. The early closure of reactors resulted in an earnings shortfall, because RWE sold forward power that should have been produced in its two closed reactors. To meet its supply obligations the Essen-based firm has had to produce that electricity in more expensive plant or buy power on the market.

RWE operates five of Germany’s 17 reactors, with the first scheduled to close in 2016. RWE could be hit harder by the nuclear phase-out because it is less active in other markets than E.ON and relies heavily on nuclear and coal generation, which make up over 70 per cent of the company’s overall power generation share.

RWE has also been downgraded by rating agencies (Moody’s and S&P). RWE relies on lignite and hard coal for over 50 per cent of its power generation output. This also makes RWE the biggest carbon emitter in Europe and exposes it to the European Emissions Trading Scheme (ETS) more than its competitor.

RWE is weak in gas-fired and renewable generation, with portfolio shares of 20 and 5.5 per cent respectively.  RWE wants to increase its renewable generation to around 30 per cent by 2025.  However, RWE has debts of €27 billion and its balance sheet will struggle to shoulder much more of a burden.

RWE is looking to a partnership with Gazprom, which has announced its interest in acquiring power generation assets in Germany.  Last month RWE said it had it secured exclusive talks with Gazprom that could lead to a power joint venture in Germany, Britain and the Benelux.

07.28.11
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UK renewables generation rose by just 0.1 per cent in 2010

Despite Vattenfall's world-beating 300 MW Thanet offshore wind farm coming onstream, UK renewables output rose by just 0.1 per cent in 2010. Vattenfall

The UK Department of Energy and Climate (DECC) latest energy statistics report released today states that electricity generation from renewables rose by a derisory 0.1 per cent in 2010, despite a 15 per cent increase in installed capacity.

According to the Digest of United Kingdom Energy Statistics, also known as DUKES, electricity generated from renewable sources in the UK in 2010 represented 6.8 per cent of total UK electricity generation, up from 6.7 per cent in 2009. This modest rise was recorded despite a 15 per cent increase in the installed base of renewables, mainly as a result of a 42 per cent increase in offshore wind capacity, a 16 per cent increase in onshore wind capacity and a 9 per cent increase in the capacity of sites fuelled by biomass and wastes.

DECC said increases in offshore wind generation and co-firing offset falls in hydro and onshore wind.

Other notable DUKES statistics:

  • UK electricity generation (including pumped storage) in the UK increased by 1.2 per cent, from 377 TWh in 2009 to 381 TWh in 2010. Total electricity supply (including net imports) increased by 1.1 per cent.
  • Total UK Transmission Entry Capacity increased by six per cent, from 85 GW to 90 GW. This was mainly due to a 4.9 GW increase in CCGT capacity.
  • Gas produced 46 per cent of generation in the UK in 2010, with the second highest annual total for gas fired generation (175 TWh). Coal’s share increased from 27 to 28 per cent, with a large increase in generation in the second half of the year. Nuclear’s share of overall generation fell from 18 per cent to 16 per cent.
  • In 2010 Combined Heat and Power (CHP) capacity stood at 5989 MWe, an increase of 6.7 per cent on 2009.
  • Gross natural gas production fell 4.3 per cent in 2010. Gross natural gas production has fallen by 47.3 per cent since its peak in 2000. Net imports of gas accounted for over 40 per cent of the gas output from the transmission system. LNG imports accounted for over a third of gas imports, more than double that received by pipe from the Netherlands and Belgium combined, and up from 2 per cent in 2008. Imports from Norway accounted for just under half of gas imports.
  • Final consumption of electricity increased by 1.7 per cent, from 323 TWh to 328 TWh. Of this, industrial consumption increased by 3.6 per cent.
07.05.11
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Point Carbon slashes EU ETS Phase III carbon price forecast

Point Carbon expects the average carbon price to be €22/tonne during Phase III of the EU ETS

The average EU Allowance (EUA) price in Phase III of the EU’s Emissions Trading Scheme (EU ETS) will be €22/tonne ($32), according to Thomson Reuters Point Carbon.

The €22/tonne figure is €8/tonne less than its October 2010 forecast, “mainly due to the earlier and greater deployment of renewable energy than previously assumed”, said Anne Kat Brevik, Commercial Manager at Thomson Reuters Point Carbon. 

Point Carbon still believes that the EU will adopt a 25 per cent emissions reduction target for 2020, despite Poland’s opposition to the discussion of any target beyond 20% at the Environment Council in June. Brevik explains “if, as we expect, the EU does adopt a 25% reduction target during the first half of 2012, this would require additional emissions reductions in the order of 1 billion tonnes during Phase III of the EU ETS. This would result in an estimated average Phase III price of around €22/tonne”.

However, in the event that the EU does not agree to increase its emissions reduction target beyond the current 20%, “we expect the market to be significantly long when the combined allocation of allowances and credits is taken into account, leaving average prices in the region of €10-€15/tonne in Phase III”, said Stig Schjølset, Head of EU Carbon Analysis at Point Carbon, adding that even at this lower price there are still a number of abatement measures that would take place.

In the event that the EU adopts a 30% reduction target, something Germany, France and the UK are advocating, the average price range for EUAs would rise to €22-€40/tonne.

In the short term, Schjølset believes that EUA prices will struggle to regain recent losses due to weaker demand from utilities combined with high supply levels of EUAs and credits which will keep prices relatively depressed.

As such, Thomson Reuters Point Carbon believes that the market can “expect an average price of €15/tonne for the remainder of 2011, rising to €16/tonne and €17/tonne for 2012 and 2013 respectively”. “Prices are expected to increase more rapidly towards the end of phase 3, and we estimate prices to reach €28/tonne in 2020. At this stage, however, expectations and actual decisions regarding Phase IV will probably be important, increasing the uncertainty on the price forecast for the final years of Phase III”, according to Stig Schjølset.

Despite recent questions regarding confidence in the carbon markets as a whole “we believe that the EU ETS will remain a cornerstone in the overall EU climate policy”, said Schjølset. “In contrast to policy measures promoting renewable energy and energy efficiency, the EU ETS establishes a firm cap on emissions, together with a well-established framework for enforcing the cap.

“Because other measures do not provide EU policy makers with the same degree of certainty that emission reductions will actually be achieved, we do not think that the EU ETS will become less relevant as a policy tool to ensure that EU’s long-term reduction targets are met”.