Biomass players in the dark
4 Oct 2011
Lack of progress with Drax and Siemens plan to add 900MW of new capacity highlights barriers to expansion of UK biomass electricity generation. Patrick Raleigh reports
Back in 2008, Drax unveiled plans to develop three 300MW renewable energy plants, costing around £2 billion, in partnership with Siemens Project Ventures. Together with the renewable output from co-firing at Drax Power Station, the units were to produce around around 10% of the UK’s total electricity.
The scale of the company’s ambitions reflected the importance of biomass to the energy mix it is today the single-largest component of the UK’s total renewable electricity generation. That these plans have yet to materialise, however, suggests some major barriers to developments in this arena.
At the end of 2010 there was 2.5GW of biomass electricity capacity operating in the UK, generation coming mainly from waste (62% predominantly landfill gas), although co-firing and dedicated biomass plant are also significant (21% and 17%). Estimates indicate that biomass electricity could contribute up to 6GW by 2020. The UK’s Department of Energy and Climate Change (DECC) anticipates that the bulk of this growth will be met from conversion of coal plant, dedicated biomass generation, biomass waste combustion and anaerobic digestion.
A major stumbling block, however, is uncertainty among investors faced with untried technologies and continuing questions concerning the level of government support.
Investor confidence in large-scale biomass electricity generation has been limited by the lack of completed projects, and, more importantly, by uncertainty about government policy (see panel, below).
Among those keenly watching these developments is Drax, which burnt 600,000t of biomass in the first half of 2011, generating around 6% of the UK’s renewable power for the period. But its renewables output could be much greater with appropriate government support, believes Dorothy Thompson, chief executive of the Yorkshire-based company that produces 4,000MW of electricity 7% of the UK’s supply mainly from coal.
According to the CEO, burning biomass in place of coal, in facilities such as Drax, is one of the most cost-effective means of producing renewable electricity and could provide one third, or more, of the UK’s required renewable power by 2020. Drax, she added, is ready to transform itself into a predominantly renewable generator: biomass, which is co-fired with coal, currently represents around 8% of the total power output from its six 600MW turbine units.
“We continue to operate at less than our installed renewable capacity because of the current low level of regulatory support for electricity produced by burning sustainable biomass instead of coal,” said Thompson.
According to Thompson, the government’s Electricity Market Reform (see panel on previous page) white paper has confirmed the introduction of an approach embracing a feed-in-tariff with contracts for difference (FiTCfD), as the replacement for the Renewables Obligation, in order to incentivise investment in new, low-carbon generation.
“We believe the FiTCfD provides the lowest-cost solution for the consumer and the necessary stability for investors,” said Thompson. “We are also pleased to see that a wider capacity mechanism is to be considered and look forward to engaging further with the government on potential solutions.”
But, while Drax welcomes many of the planned reforms to the electricity market, the company is concerned about government plans to introduce a carbon price floor and an emissions performance standard.
“The carbon price floor will not deliver all that is expected of it and, indeed, it may have unintended consequences,” said Thompson. “For example, to encourage investment, any incentive mechanism must be ’bankable’. That is not the case for the carbon price floor, which is to be set annually and is subject to discretion, both of which increase uncertainty for investors.
“The introduction of an emissions performance standard is, we believe, an unnecessary layer of additional legislation. Existing legislation already provides the framework for the agreed EU-wide emissions standards for electricity generation plant, and, further, Source: DECCwe believe that the planning regime is more than capable of ensuring that only low-emission power plants will be built in future.”
Thompson went on to report that, since February, Drax had experienced some improvement in near-term and forward commodity market margins for coal-fired generators, driven largely by increasing gas prices.
“But,” she said, “in the longer term we see conflicting tensions through the introduction of the carbon-price support mechanism from April 2013, which is likely to erode our competitive position in the market.”
Meanwhile, Thompson, said there had been no significant progress on the three projects to develop dedicated biomass facilities with Siemens. This, she said, was due to the lack of clarity surrounding the future level of support available for dedicated biomass plants.
And, while, government approval has recently been obtained for two of the plants at Selby and at Immingham a Drax spokeswoman, likewise, said any progress with the investment will depend on future support levels under the RO.
Electricity market -
Will reform provide revenue certainty?
The UK government’s proposed Electricity Market Reform will lead to an increase in electricity bills of 38% for domestic consumers and 70% for industrial consumers by 2026-30, according to Department of Energy & Climate Change (DECC) forecasts.
The proposal includes mechanisms to support low-carbon power generation, including nuclear, in three ways: a carbon price floor mechanism; a new, low-carbon, generation revenue support mechanism in the form of a feed-in tariff (FIT); and an emissions performance standard.
A key component of the proposed reforms is to phase out the existing system of support for renewable electricity, the Renewables
Obligation (RO), and replace it with a FIT. The aim is to increase revenue certainty for big, low-carbon, energy projects.
The FIT will be available in 2013 or 2014 for new investments, although investors will still be able to opt for the RO until 2017. Existing projects receiving the RO will continue to benefit from this support mechanism until 2017, from when only the FIT will be available, according to a briefing by accountancy firm Grant Thornton.
Different FIT models are being considered, although DECC is currently backing one called FIT with Contract for Difference (FIT with CfD) under which generators sell electricity to the market, then receive a top-up payment or repayment. The top-up is calculated as the difference between the average market wholesale price and the governmentdetermined tariff level. The net result is that the generator will receive a total price close to the government tariff level.
Generators would, thereby, gain increased long-term revenue certainty while still being subject to short-term price risk, which encourages efficient operational decisions.
Grant Thornton, however, pointed to several unresolved issues, including ensuring an appropriate, but affordable, level of lowcarbon revenue support, and deciding whether the subsidy will be technology-specific, as is the case with the RO.
Moreover, it said, the government needs to clarify how the transition period will impact upon current investments and investor confidence.
“While the RO will be phased out over several years, the magnitude and complexity of this change is likely to unsettle investors and may delay major renewable projects,” Grant Thornton warned.
The proposal includes mechanisms to support low-carbon power generation, including nuclear, in three ways: a carbon price floor mechanism; a new, low-carbon, generation revenue support mechanism in the form of a feed-in tariff (FIT); and an emissions performance standard.
A key component of the proposed reforms is to phase out the existing system of support for renewable electricity, the Renewables Obligation (RO), and replace it with a FIT. The aim is to increase revenue certainty for big, low-carbon, energy projects.
The FIT will be available in 2013 or 2014 for new investments, although investors will still be able to opt for the RO until 2017. Existing projects receiving the RO will continue to benefit from this support mechanism until 2017, from when only the FIT will be available, according to a briefing by accountancy firm Grant Thornton.
Different FIT models are being considered, although DECC is currently backing one called FIT with Contract for Difference (FIT with CfD) under which generators sell electricity to the market, then receive a top-up payment or repayment. The top-up is calculated as the difference between the average market wholesale price and the government-determined tariff level. The net result is that the generator will receive a total price close to the government tariff level.
Generators would, thereby, gain increased long-term revenue certainty while still being subject to short-term price risk, which encourages efficient operational decisions.
Grant Thornton, however, pointed to several unresolved issues, including ensuring an appropriate, but affordable, level of low-carbon revenue support, and deciding whether the subsidy will be technology-specific, as is the case with the RO.
Moreover, it said, the government needs to clarify how the transition period will impact upon current investments and investor confidence.
“While the RO will be phased out over several years, the magnitude and complexity of this change is likely to unsettle investors and may delay major renewable projects,” Grant Thornton warned.
In Europe, once the Vivergo plant is opened on the BP Salt End site, near Hull, there is no new capacity to follow, New said (see News, p7). Even in Brazil, he added, there will be only three cane sugar-based bioethanol facilities opening this year, and none next year.
But all is not lost, believes the BP executive, pointing to the potential for consolidation in the industry, the emergence of new technologies, and players with the required financial, project management and engineering capabilities to make things happen.
For example, he said, BP is building the first commercial-scale, cellulosic-feedstock farm in Florida, and will be breaking ground on the industrial facility in the next six to nine months.
To succeed in the automotive fuels market, believes New, biofuels producers will have be able to compete with oil without subsidy achieving production costs in the range of $60-80boe.
“Production must also be scalable and sustainable using resources efficiently, contributing positively to local communities and sustaining biodiversity,” he continued. “And they need to be at least 50% better on CO2 performance than oil.”
Biofuels’ performance against these criteria is a function of the feedstock, which, said New, explains why US corn ethanol supply has “topped out”, and why growth of biofuels made from vegetable oil is likely to be constrained. On the other hand, ethanol made from sugar cane in Brazil can easily meet these criteria and so has massive scope for expansion.
By 2020 biofuels made from cellulosic sugars extracted from agricultural wastes and energy crops will also be able to meet these hurdles, New forecast.
