Biomass Projects in the UK and US

Biomass Projects in the UK and US

October 01, 2004

By Denis Petkovic

Forty-five percent of all renewable energy used in the United States involves biomass, and 4% of all energy consumed in the United States is represented by biomass, according to the Global Energy Research Institute.  These are staggering statistics in light of the relatively dismal success of biomass projects in the United Kingdom.

This article discusses some of the key features of biomass financings, contrasts the UK support for such projects with the support in the US, and suggests steps to be taken in the UK to improve the odds for biomass projects to succeed.  Biomass projects, in simple terms, involve combustion or other technologies that generate heat, and the heat is used to drive a turbine that generates electricity.  Such projects raise four particular issues that, while shared by other projects, are unique in their application to biomass.  These are fuel supply arrangements, environmental issues, technology risk and tax risk.

Fuel Supply Arrangements

Fuel supply contracts vary with the fuel type used.  There are three broad types of biomass material: forestry materials (where the fuel is a by-product of other forestry activities), energy crops, such as short rotation coppice, willow or miscanthus where the crop is grown specially for energy generation purposes, and agricultural residues such as straw or chicken litter.

Whatever the fuel, one requires a lot of it to fuel a biomass plant because of the low calorific value of such fuels.  The UK’s leading renewables company, Energy Power Resources Limited, for example, which operates the ELEAN straw-fired plant at Ely, England, uses 230,000 tons of straw a year to generate 36 megawatts of electricity.  In the same company’s poultry litter plant located at Thetford, England, which generates 38 megawatts of electricity, 450,000 tons a year of poultry litter are required.

Project financiers will want to see a fuel contract with a term at least as long as the power sales agreements or financing arrangements.  This must be executed prior to financial closing.  There is a threshold issue to grapple with for long-term fuel supply contracts in the UK biomass sector.  Generators are said to be unsure still how the “large combustion plant directive” will affect them, and this is one of the reasons why they are not prepared to offer long-term contracts to biomass suppliers.  Moreover, to the extent that the sector requires energy crops to act as a fuel source, there is no national policy in the United Kingdom on setting aside land for this purpose.  This is a fundamental issue given that some energy crops, such as miscanthus or willow coppice, require a three-year period to elapse before farmers see a saleable crop.

For a successful project, fuel should be available to the project in quantities sufficient to run the plant at full capacity when it is needed.  If the power purchaser has varying power requirements, a connected consideration for any biomass project will be the availability of fuel in the immediate countryside.  In the UK, forest wood, for example, is simply not available within a viable distance for many prospective generating plants.

The fuel supply contract must accommodate the project’s needs with flexible delivery schedules.  The pricing provisions of the fuel supply contract, including any increases in price to account for inflation or other factors, should match provisions under the power sales agreements that allow comparable adjustments to the power purchase prices.  The quality of fuel to be delivered must be compatible with the project’s construction, design and permitting requirements and restrictions, including air emissions restrictions.

Contracts for the transportation of fuel to the plant are equally important as contracts for the supply of fuel.  Availability of rail transportation facilities may be an issue, or if fuel is delivered by truck, availability of roads for this increased traffic may be a problem.  This is very much the case in the UK where the loss of national railways over generations now forces biomass transportation onto the roads system; roads are the most expensive mode of transport in the UK.  Interconnection to transmission and distribution systems should be available.

Fuel storage arrangements or a back-up fuel supply may be necessary if satisfactory fuel supply and transportation arrangements are not available and, in any event, are matters with which the lenders must be comfortable.

Diversity of fuel suppliers may also be necessary to enable a successful project financing to take place.  A project company should, ideally, maintain relationships with a variety of fuel suppliers rather than concentrate its inputs on one so as to minimize the likelihood of disruption to supply and to price changes.

In the case of biomass, fuel supply can be affected heavily by seasonal factors, and this must be addressed.  For example, forest fuels such as wood wastes may become too moist in winter and other wet periods and can affect plant efficiency and supply and, for some types of biomass, like straw, wet weather will simply damage stocks of fuels held by the generator.  If the plant is fitted with technology to supplement such fuel sources, like natural gas, for start up and combustion, this is beneficial.  Another means of alleviating fuel supply price risk is to build up stocks of fuel on site or with near-site storage.  Owing to moisture risk, plant storage arrangements need to be considered for any project as should the project company’s policies toward fuel blending.

The heating value and moisture content of different types of fuel to enable the maximum level of power generation to take place will also be of interest to lenders.  A connected topic is whether the plant requires drying technology to reduce moisture content of fuel.  Where premium fuel is required by the plant, such as natural gas, then maintaining good fuel quality control becomes a key ingredient of assuring the profitability of a project.  In this regard, wood fuel prices vary seasonally.

Environmental Issues

An issue that will be of great sensitivity to lenders (and project sponsors) is liability for environmental conditions at or from the site, including contamination at the site caused by the use, or misuse, of hazardous substances, air pollution and wastewater discharge to nearby water bodies.  The transfer documents for the site or the site lease should, at a minimum, contain an environmental indemnity by the prior owner or lessor for pre-existing conditions on the site.  An environmental site assessment should be performed (even if it is not legally required) before a site is finally chosen and any contamination or other potential liabilities, such as areas of historical, religious or archaeological sensitivity, potential contamination from neighboring land, or presence of endangered species or rare habitats, must be evaluated and, if possible, removed or the impact mitigated.

Project sponsors and lenders alike will want to be sure that the project and the site are properly permitted under all applicable laws and regulatory requirements.  Air, water, waste discharge or storage and other permits will need to be obtained before closing.  Any permit that is not final and non-appealable or is revocable prior to repayment of financing, or that contains requirements or conditions that are unduly burdensome, could delay financial closing or make the project financing more difficult without additional sponsor support.  In some projects, permits relating to construction may be the responsibility of the construction contractor, but the project sponsors will be required to confirm early in the development process that all required permits will be available when needed.

Particular environmental issues raised by biomass projects concern air emissions.  In the UK, the “waste incineration directive” sets strict emissions levels and can directly affect the operation of some biomass projects.  Biomass plants must comply with the directive even though coal-fired plants, for example, that emit more carbon monoxide are unaffected by the directive.  The fact that the introduction of the waste incineration directive (through UK regulations) commenced on December 28, 2002 has directly affected the profitability of some existing biomass plants owing to the compliance and regulatory costs.

Other environmental issues raised by biomass concern how waste ash byproducts are dealt with, how and where cooling water will be disposed, where the water supply is coming from, noise emission levels and the potential increase in road transport as fuel is transported to a plant.

Technology Issues

It is a given that commercial lenders will not assume the risk of unproven technology under traditional project financing theories.  Biomass projects that have been unsuccessful in the UK have often breached this basic principle.

Two high-profile UK projects reflect this failing.  The first is the case of the collapse, in 2003, of Border Biofuels Limited, which was described by The Scotsman newspaper in the following terms:

A Scottish company given millions of pounds in grants from the [DTI] network has suffered a spectacular financial crash without creating a single job or starting any of its ambitious developments.

The company sought to establish a high tech venture using unproven pyrolysis technology.  This technology involved heating timber, plant matter and organic waste at high pressure to produce a high-quality oil that can fuel a power plant.  The £4.6 million project was funded 25% by grants from the Department of Trade & Industry.  The remainder of the finance came from The Bank of Scotland, British Linen Bank, hire-purchase agreements and shareholder loans.

The project would not have been a candidate for a conventional project financing.  The technology was unproven.  However, the project company historically held interests in other ventures ranging from power generation development and biomass fuel supply to coppice production.  A project financing would have imposed the discipline of total concentration on the project at hand and not permitted additional investments and diversification.  Indeed, at the time of its collapse, Border Biofuels was reportedly considering developing huge biomass plants at Hexham in Northumberland, Carlisle, Ellesmere Port in Merseyside and Newport in South Wales.

A second, even more high-profile collapse in the UK owing to technology risk was the ARBRE project — a £30 million project funded from European Union grants and Department of Trade & Industry grants (a total of £13 million) and the balance from shareholders such as Yorkshire Water Plc (which company resold its interests to Energy Power Resources for £1).

Following the insolvency of ARBRE Energy Limited and sale of its assets to American interests, The Guardian reported (on May 31, 2003):

The sale is a disaster for Britain’s green energy policy....

This project, which began in 1998, also involved previously unproven technology associated with gasification aimed at making combustion more efficient by converting short rotation coppice into gas that could then be used to fuel a gas turbine generator.  The plant closed after eight days of operation (owing to deposits that failed and ultimately blocked the plant’s heat exchangers).  The plant’s closure caused a crisis for nearby farmers who had planted 1,500 hectares of this crop for which there was no buyer after the company’s collapse.  The 2003 Royal Commission on Environmental Pollution said of ARBRE:

[T]he loss of ABRE has ... shaken the confidence of other investors and, equally importantly, of the farmers concerned.

The Royal Commission on Environmental Pollution also assessed that the “main problem” for the failure of biomass to become established in the UK is that the government capital grants schemes for biomass have focused on high technology approaches to “electricity-only generation” with a view to potential export development.

Demonstration schemes have not been based on established biomass technology and have consequently failed with a resulting loss of confidence in the sector.  Basically, the Department of Trade & Industry has concentrated its grants for capital and research and development by backing the wrong technological horse in speculative demonstration plants for gasification and pyrolysis technology rather than proven technologies.

The experience of ARBRE is in contrast to EPR Ely Limited’s straw-fired power plant near Ely in Cambridgeshire.  This £60 million, 31-megawatt straw-fired power station, which has the benefit of a power contract terminating in 2013, was funded with £52 million of senior project finance debt and £8 million of equity from Energy Power Resources Limited and Cinergy Global, Inc.  The senior debt was provided by HypoVereinsbank of Germany and National Investment Bank of The Netherlands.

The security taken by the banks in 1998 comprised a debenture incorporating first priority charges over all land owned by the project company, intellectual property, goodwill, consents and permits, contract and other rights.  In 2004, the project’s main sponsor, Energy Power Resources Limited, as a security trustee, took a second ranking debenture securing loan finance provided by it and other holders of loan stock.

The power station consumes 230,000 tons per year of straw that is collected from farms within a 50-mile radius in the form of Hesston bales weighing over half a ton each.  The delivered straw must have a moisture content below 25%.  This is automatically tested and weight-corrected and craned from delivery trucks, 12 bales at a time.  The fuel is stored in two enclosed barns having a total capacity of 2,100 tons (enough for up to four days of operation).

The unloading cranes automatically feed a straw conveyor system, serving twine-cutters and bale-breakers that shred the bales en route to four screw strokers feeding individual burners.  The straw is burned on a two-stage crate.  The plant’s operation results in byproducts, including fly ash and boiler grate bottom ash, that are collected, stored and form the basis of organic agricultural fertilizers.

Unlike ARBRE and Border Biofuels, the Danish technology used at the EPR Ely power station was proven in a number of European plants making it an appropriate candidate for project financing.  Governmental estimates are that straw alone could, in principle, provide more than 3% of total electricity in the United Kingdom.

Tax Risk

To the extent that a biomass project relies on government subsidies to pay a large part of the project costs, then the project carries a tax risk that it will not qualify for such tax subsidies.  For example, it might miss a deadline to be put into service or the mix of materials supplied to the plant as fuel might not qualify as biomass.  Several US insurers are now selling insurance to protect against such tax risk which is expensive and, in some US states like California, subject to avoidance legislation.  Lenders would generally expect the project sponsor to make payments to the project for the value of any proposed tax subsidies whether or not the project qualifies.

Contrast the US Experience

In the United States, the tax system has played a large part in the success of biomass projects.  A number of key tax and like initiatives deserve mention.  Section 29 of the US tax code has traditionally provided a tax credit for projects involving biomass that is converted into gas before it is used as a fuel.  The credits can be claimed on gas produced from biomass through 2007.  However the equipment used to produce the gas must have been put into service by June 1998 to qualify.  Congress is debating whether to extend the deadline to allow additional projects to qualify for the tax subsidy.

Section 45 of the US tax code also specifically allows taxpayers a tax credit of 1.8¢ a kilowatt hour for electricity generated from “closed-loop biomass” for a period of 10 years starting when the power project is placed in service.  Projects must be put into service by the end of 2005 to qualify.  Closed-loop biomass refers to plants that are grown exclusively for use as fuel in a power plant.  The US government had in mind “electricity farms” (similar to the short rotation coppice arrangement for the ARBRE project) where plants are grown specifically to be burned as fuel.  The Internal Revenue Service said last April that there are no known closed-loop biomass plants in operation the US Congress is debating whether to allow power plants that use other types of biomass as fuel also to qualify for the credits.

Equipment in a power plant or other facility that uses biomass or disposes of “waste” could also qualify for an unusually generous US depreciation allowance.

Certain equipment in an electric generating plant that uses biomass for fuel qualifies for depreciation over five years using a 200% declining-balance method, provided the plant is a “qualifying small power production facility” within the meaning of the Public Utility Regulatory Policies Act.  The following equipment qualifies: boilers, burners, pollution control equipment required by law to be installed, and equipment for “the unloading, transfer, storage, reclaiming from storage and preparation” at the place where the biomass will be used as fuel.  This is basically all equipment up to the point where electricity is produced.

The ability to depreciate an asset over five years is a valuable benefit.  Equipment in a power plant is normally depreciated over 15 or 20 years.  Each dollar of depreciation deductions spread over 20 years produces tax savings of 13¢ in present-value terms, while the same dollar deducted over five years produces a tax savings of 25¢ — almost twice as large.  If the developer cannot use the tax benefits himself, he may be able to transfer the tax benefits to another company that can use them in exchange for equity to help finance the project.

The Energy Policy Act of 1992 also authorized a program of “incentive payments” of 1.5¢ a kWh by the US Department of Energy for power plants that use sunlight, wind, biomass or geothermal energy for fuel.

The incentive payments are subject to the following conditions.  The power plant must be owned by a state or local government or nonprofit electric cooperative.  The payments can be made to the owner or the operator.  A project qualified for the payments if it was “first used” during the period October 1993 through September 2002.  The electricity must be “for sale in, or affect, interstate commerce.”  Once approved for a project, the incentive payments continue for 10 years.  Power plants that burn “municipal solid waste” are ineligible for the payments.

Power companies have historically been able to issue tax-exempt debt associated with “solid waste disposal facilities,” notwithstanding that tax-exempt bonds in the United States are generally supposed to be restricted to financing for schools, roads, hospitals and other public facilities.  Private companies that own “solid waste disposal facilities” have had access to the tax-exempt bond market for finance because the plants are thought to produce public benefits.

A power plant that burns solid waste disposes of the waste by converting it into electricity.  In addition, pollution control equipment that traps ash and other solid particles at the back end of power plants that burn solid fuels (which can account for as much as 25% of the total cost of a power project) has, in the past, qualified for tax-exempt financing benefits.

The Internal Revenue Service is proposing to tighten the definition of solid waste.  In the future, only material that has been discarded can qualify as waste. (It is enough currently to show that nothing was paid for the fuel; people pay for transporting and handling, but not for the fuel itself.) The more restrictive definition could take effect next year.

Finally, an additional boost is given to biomass projects in the United States through “renewable portfolio standards.” Sixteen US states have adopted some form of renewable portfolio standard, or law requiring utilities either to generate a percentage of their electricity from renewables or buy it from independent generators who use renewable sources.  In some of the states, the utility must have a certain number of renewable energy credits — called RECs or green tags.  Anyone producing electricity from renewable fuels receives credits and can sell them in the market.  This is potentially another source of cash for developers of renewable energy projects, although there is litigation at the state level over whether the generator still owns the green tags as separate assets in cases where he has sold the electricity under long-term contract to a utility.  The Federal Energy Regulatory Commission declined to settle the issue and threw it back to the states to address under their individual programs.  Currently, there is no federal renewable portfolio standard.

The rules for what qualifies as a renewable vary from state to state, but biomass generally qualifies.  A failure by a utility to buy the requisite electricity results in financial penalties unless the utility buys renewable energy credits from a third party — if applicable state law allows it to do so.

It will be seen that the US rules bear some strong resemblance to the UK renewables obligation, but operate in tandem with tax concessions supportive of biomass.

The UK Experience

The UK government’s stated target is that 10.4% of licensed electricity supplies is generated from eligible renewable sources by 2010.

At the heart of this policy is the “renewables obligation,” which now places an annually-escalating obligation on all licensed electricity suppliers in England and Wales to source a growing percentage of their total electricity sales from renewable sources.  The procedure, introduced in April 2002, requires the supplier to present renewable energy certificates — called “ROCs” — representing one megawatt hour of electricity generated from eligible units to OFGEM, the Gas and Electricity Markets Authority, in respect of periods of one year.  These certificates are issued to accredited generators for eligible renewable electricity generated within the United Kingdom and UK territorial waters.

The main eligible technologies are, in summary:

  • Landfill and sewage gas,
  • small hydro (under 20 megawatts declared new capacity), or larger hydro if commissioned after April 1, 2002,
  • onshore and offshore wind, biomass (including, up until 2016, biomass co-fired in conventional fossil-fuelled plant),
  • geothermal power,
  • tidal and wave power, and
  • solar power.

The renewables obligation replaced a former “NFFO regime” and its equivalent in Scotland that guaranteed generators fixed-price power sales contracts with the Non-Fossil Purchasing Agreement and that were popular with project financiers.  The fact that changes in the renewables regulatory regime occurred underscores, for financing banks, that this sector is substantially at a high risk of legal change or “regulatory risk.”

As an alternative to supplying renewable energy, suppliers may fulfill part or all of their obligations by paying a buyout price to Ofgem set a £30/MWh up until April 2003 and then adjusted in accordance with the retail price index.  The proceeds will then be returned to suppliers by OFGEM in proportion to the number of ROCs that each supplier presents to discharge its obligation.  Failure to pay the buyout price, in theory, leads to payment of a financial penalty.

Aside from the renewables obligation, the UK government operates as capital grants scheme aimed at wind and energy crops-based renewables.

In principle, the ROC regime has much to commend itself; however, some problems have arisen in practice.

First, there is no technology banding under the regime and, thus, biomass projects must compete in the market for capital against other renewables technology such as wind; being a more expensive technology, this result is very much to the detriment of biomass.  Moreover, wind is the renewable technology that can be brought to market more quickly than any other meaning that it produces the earliest return on investment for investors.  Further, the costs of collection, storage and transport of fuel place a heavy financial burden on biomass project generators.  For example, in relation to the EPR Ely project, farmers receive £2 per ton for straw lying in the fields, but by the time it is baled, stored and transported to EPR’s plant in Ely the cost is £35 per ton.  Poultry litter plants raise similar issues.

Second, the buyout price has, in relation to electricity suppliers in financial distress, simply not been paid.  Thus, three insolvent electricity suppliers have not paid their buyout price after entering into insolvency.

The administrators, in each case, argued that compliance with the renewables obligation was incompatible with their duties and applicable insolvency law.  There was little OFGEM could do in the circumstances, and reform of the rules associated with the buyout price is being considered.  However, two steps that could be considered are reducing the period suppliers have to calculate and pay the buyout price (perhaps to monthly periods) and thereby reduce OFGEM’s credit exposure to suppliers.  Another alternative is to require buyout price payments to be “ring fenced” from the funds available to other creditors under insolvency laws (although this is against the spirit of insolvency reforms undertaken by the UK government in the Enterprise Act 2002).

Third, it is not even clear that the UK government is really behind biomass.  This statement from the Select Committee on Science and Technology’s Fourth Report is breathtaking:

Biomass ... [f]uels have a low energy content compared with their bulk and it does not make economic or environmental sense to transport them long distances before using them.  There are several biomass plants in the United Kingdom, but it is unlikely that there will be more in view of the unhelpful and confused regulatory environment and the lack of financial encouragement.  However, making use of biomass, both indigenous and imported, could be a cost effective way of meeting the Government’s targets for renewable generation.  We understand that this is now the policy of the Danish government.

Regulatory charges in the form of the introduction of the New Electricity Trading Arrangements, or “NETA,”) in 2001 (which put in place market-based trading arrangements for electricity) in England and Wales contributed to a fall in wholesale electricity prices, up until recently, to around 1.5p per kWh whereas 6 to 6.5p per kWh is effectively the break-even point for a profitable biomass plant.  Even wind generators have struggled at times to generate electricity profitably under the NETA regime, so difficulties for biomass developers are likely to be greater.

In addition, the planning process in the United Kingdom is one of the most problematic areas for renewables developers.  Small generators are approved by local planning authorities on a case-by-case basis rather than by the Secretary of State (as is the case for generators in excess of 50 megawatts).  Amusingly, one of the most significant objectors to renewables projects in the United Kingdom is the Ministry of Defense — albeit to wind generators — on the basis that they may confuse radar.  Nevertheless, the fact that two government departments, Defense and the Department of Trade & Industry, have contradictory policies towards renewables reflects the uncoordinated muddle that UK energy policy sometimes finds itself in and the perception that regulatory risk is an issue in UK power financings.


The upshot of this discussion is that biomass in the United Kingdom requires protection from the market mechanism imposed by the renewables obligation in favor of, say, large-scale wind projects.  The previous government program — called NFFO — provided that protection and acted as a spur to some developments in this sector.  The US experience of making biomass projects more economic through tax incentives and renewable portfolio standards is complimentary to this approach as would be the introduction of biomass RO certificates and requirements.  What is necessary, under the current RO regime, then is technology banding of sorts.  Even the Spanish authorities — a strongly green government — have recognized this.  In that country, the tariff paid to biomass and wind is twice that of the market rate for fossil fuel-derived electricity.  However, such pricing favoritism has not helped the biomass sector grow.  Spanish authorities are now considering removing the preferential pricing enjoyed by wind and increasing that enjoyed by biomass in order to redress the situation.  If similar biomass “nurturing” steps were to occur in the United Kingdom, including US-style tax system support for biomass project financings more projects, such as EPR Ely, should follow.  The UK government needs to be far more consistent, coordinated and “mid-Atlantic” in its approach towards this sector.