Infrastructure: Biomass energy

01/Introduction

The UK is aiming for 15% of its energy to come from renewable sources by 2020. According to the Department for Energy and Climate Change, just 7% of current of UK energy is derived from renewable sources, with installed capacity animal and plant biomass contributing just 1.2%. The UK’s potential investment pipeline in biomass is worth £12bn, a small proportion of the total £200bn investment needed for UK energy infrastructure; however, the pipeline is characterised by projects that are relatively easy to fund, consent and build. Planned large biomass plants could potentially add nearly 5GW to UK generating capacity and plans for many plants are well advanced. Of the 20-plus major projects proposed for the UK, 11 - worth £3.5bn - have already received planning consent.

Drivers for the expansion of biomass in the UK include:

• Energy security. Diversifying the UK energy source base, reducing reliance on imported oil and gas
• Access to a wide range of source material. Biomass sources are diverse, and can be imported or sourced within the UK
• Renewable energy sources. As well as being virtually zero carbon, sustainably produced biomass is fully renewable
• Scalability. Biomass can operate at a range of scales - making it suitable for community combined heat and power (CHP) applications as well for generation for the National Grid
• Employment creation. In addition to direct construction employment, biomass creates jobs associated with the operations stage, as well as for the biomass supply chain.

UK electricity market reforms will be finalised during 2012, and long-term certainty with regards to the level and duration of renewable energy incentives will provide further momentum to investment. Biomass development is likely to accelerate rapidly over the next two to three years.

02/ Biomass technologies and sources

Biomass is a generic term for organic matter used as fuel. Carbon dioxide is released when biomass is burned; however, short-cycle biomass repeatedly captures CO2 as it grows. By contrast, fossil fuels release carbon that has been stored for millions of years, and their use is disincentivised through the EU’s Emissions Trading Scheme.

Biomass materials that qualify for incentive payments are currently defined by the Renewables Obligation. These include energy crops such as miscanthus and sugar cane, as well as a number of agricultural residues such as poultry droppings. However, given the scale of generation required to meet renewables targets, wood products are set to be the main source of biomass in the future, with easy to handle, high energy content wood pellet and briquette products being the preferred feedstock.

Demonstrating the sustainability of the chain of custody is a key credibility issue for biomass energy operators, and schemes are operated by the Forestry Stewardship Council, and Sustainable Forestry Initiative to provide this certification. As an example, managed biomass production in Georgia, US, a key source for UK operators such as RWE, means that the volume of wood grown in the state exceeds the annual harvest of 9 million tonnes per year.

Other qualifying biomass includes sewage sludge, food waste, sludge, and slurry and slaughter wastes. These form a key feedstock for energy-from-waste schemes, which also benefit from the Renewables Obligation and the Renewable Heat Incentive. Energy-from-waste also secures income from a gate fee related to waste disposal and the avoidance of landfill tax costs.

Incentives currently available for the main sources of biomass are summarised in the table below, showing how the system, which requires suppliers to present Renewables Obligation Certificates (ROCs) to show that they are meeting their obligation, incentivises investment in 100% biomass and higher efficiency CHP systems.

The renewables obligation is the main means of incentivising renewable electricity schemes in the UK. UK electricity suppliers are required to source a growing proportion of their output from renewable sources. This target is set by Ofgem and totals 49.6m ROCs - equivalent to 0.168 ROCs/MWh in England, Scotland and Wales. ROCs are issued to renewable energy generators, enabling them to trade their energy at a premium price.

When determining the viability of a biomass development, key issues associated with technology and feedstock selection include:

Technologies

• Technology selection. Most developments in the pipeline to 2020 will employ proven combustion technologies using either a fixed-bed or a fluidised-bed furnace linked to a steam turbine generator from a well-established technology provider. These are well proven and are available from a few trusted technology suppliers.
• Extent of co-firing. Co-firing is a more complex technology with an established track record in cement kilns. Conversion of existing coal-fired power stations presents a major opportunity for co-firing. However, issues of investment certainty around the extent to which existing plant and infrastructure can be used with different biomass material mixes need to be resolved at an early stage - not only with respect to capital cost and programme, but also in connection with long-term operational efficiency and reliability.
• Facilities for biomass storage. Significant investment is required in biomass storage - preferably in a separate facility that minimises fire risk. Investment decisions around biomass storage are particularly sensitive for co-firing projects, where sub-optimal storage facilities may already be available within the existing infrastructure.

Biomass sourcing

• Security of sourcing. Based on projects currently consented, the UK is set to be a 50% net importer of wood products by 2016. Security of biomass sourcing has the potential to become a significant cost driver, particularly as biomass has a key role to play in many EU countries’ energy strategy.
• Biomass cost certainty. Fuel costs comprise up to 70% of the levelised cost of biomass-fired electricity, so fluctuations in supply and transport costs could have a significant impact on margins. Contracts that offer medium-term cost certainty typically have tough clauses such as binding monthly supply obligations.
• Biomass supply assurance. Investors require a good covenant quality for the fuel supply chain, demonstrating accredited sustainable sourcing and credible enforcement.
• Biomass contract assurance. The conversion of development opportunities is highly dependant on the developer/operator’s ability to secure long-term fuel “offtake agreements” that provide long-term security for generators and biomass producers on defined favourable terms. The term of the contract typically needs to be long enough to cover loan terms. With competition for biomass increasing, securing these contracts may become more challenging for smaller independent operators.
• Biomass sustainability. This is an increasingly important requirement and the UK is in the process of implementing the EU Renewable Energy Directive 2009. At present there are no harmonised rules at EU level on sustainability standards for biomass. Implementation in the UK will include a minimum greenhouse gas saving of 60% compared with fossil fuels, and restrictions on sourcing biomass from locations with a high biodiversity value. From April 2013, these criteria will need to be met in order to qualify for incentives such as ROCs.

03/Investors and operators in the UK market

The UK biomass market is diverse, not only in terms of the capacity of generating plant, technology selection and biomass sources used, but also the relationship between the developer and energy client and access to finance. The main sectors are summarised in the following table opposite.

There is growing investor interest in the sector. However, to ensure availability of project and long-term finance, the following prerequisites need to be in place:

• A clear regulation and incentives framework. This needs to be certain in order for investors, developers, supply chain providers and energy suppliers to develop technology and supply chains, and for generating plant. Electricity market reforms will introduce a new incentivisation model, a feed-in tariff with a “contract for difference” (CfD), which will replace ROCs in 2017, although new developments will be able to adopt the model from 2013. The difference between an ROC and a CfD is that, while the value of the ROC is fixed, the value of the CfD depends on the selling price of electricity. If the price of electricity increased to exceed the agreed price, renewable generators could end up paying back some of their incentive. Qualifying definitions and the ultimate level of support will be defined in summer 2012.
• Government financial support in the form of preferential finance. The Green Investment Bank (GIB), which will be operational by 2016, is expected to provide upfront project finance funds, with the expectation that £30 of investment will be generated for every £1 of GIB funding;
• Long-term certainty around the carbon floor price. Carbon pricing penalises fossil fuel generation, reducing the cost gap for renewables. Long-term assurance around the floor price is vital for large-scale investment.
• Emission Performance Standard. This will be introduced in 2013 and by setting annual limits for carbon emissions from 2016 for fossil fuel power stations will also support investment in renewable energy sources.
• An effective planning system. The introduction of the Planning Inspectorate has reduced risk associated with the length of the planning process, if not the outcome.
• Improved technologies. Innovation will contribute to counteracting environmental concerns around the long-term sustainability and value of biomass, as well as reducing the long-term cost of biomass-derived energy. Technologies that minimise carbon emissions and maximise energy conversion and generation efficiency will make a major contribution.

04/Planning issues

Planning issues associated with large energy projects are always complex. Specific issues associated with biomass power such as concerns over emissions quality mean that planning uncertainties are high. Biomass planning applications have encountered objections on a number of fronts - with some environmental groups such as the Campaign against Climate Change taking an active role in opposition. Typical objections include:

• Concern that use of imported biomass fuel will lead to deforestation and so on - the equivalent of 10% of UK agricultural land is currently used in the production of imported biomass
• Fears over combustion-related toxins such as carbon monoxide and sulphur dioxide - there is scepticism regarding the effectiveness of flue gas cleaning technologies
• Fire risk from fuel storage - such as the recent severe blaze at Tilbury, Essex, involving 4,000 tonnes of wood pellets
• Traffic congestion, pollution and carbon emissions related to fuel delivery lorries on smaller scale schemes
• Effect on local timber industries if increased demand for wood inflates prices.

Locating facilities in industrial areas with good infrastructure such as port and rail connections or even canal access has helped to address some of these issues. Conditions associated with planning consents typically cover noise, air and water course pollution and limitations on transport movements.

Where a biomass development involves the conversion of an existing coal-fired facility to biomass or co-firing, the planning process is potentially much simpler. For the conversion of large power stations such as Ironbridge from coal to wood burning the only permission required is for a new fuel storage building. However, given the scale of the scheme - involving a 270MW turbine - it has met with major objections that extend beyond the scope of the planning requirement.

Planning for large biomass schemes in excess of 50MW are presently dealt with by the Infrastructure Planning Commission. The IPC considers proposals in the context of the National Policy Statement for Renewable Energy Infrastructure (EN-3), which covers issues including the sustainability of the fuel, site selection and impact assessment - covering air quality, noise, waste and residue management.

From April 2012, the IPC’s responsibilities will transfer to a new national infrastructure directorate within a restructured Planning Inspectorate. The application process will remain as before but with the added requirement for the recommendation to go to the relevant secretary of state for the final decision. This potentially adds three months to the IPC planning process. The IPC is being abolished to increase accountability for infrastructure planning decisions. This could potentially increase planning risk, with final decisions being determined partly by political considerations.

05/Procurement

The bulk of the commercial and performance opportunity associated with a biomass scheme lies with the boiler and turbine technology. This is particularly the case for schemes involving the conversion of existing coal-fired stations to biomass or co-firing. Whereas the civil engineering package contractors can be selected using typical procurement processes, the technology provider should be selected on the basis of long-term performance and cost of operation.

To be successful, the procurement process should:

• Align with the client’s decision-making process
• Establish clear objectives and outputs
• Focus on process performance, safety and operability
• Demonstrate cost, risk and profit in a transparent manner
• Incentivise contracts to provide project drivers
• Provide the best solution for whole-life performance.

In the UK, medium to large-scale biomass schemes are typically procured using either a multi-contract or an engineering, procurement and construction (EPC) route.

With a multi-contract process, the client will act as the tier 1 contractor and will procure the project through a series of direct contracts. Major items of the process plant will be procured using an engineering form of contract such as FIDIC and site-based works including buildings and civil works will probably use a risk-sharing contract such as NEC3. The client will accept and manage the major risks in planning and environmental approvals, funding and overall operation, but will pass on some of the design, performance and construction risks to the individual contractors.

For clients who want to delegate more of the risks and responsibilities, the EPC route provides a process whereby they appoint a single contractor or special purpose vehicle which will see the project through from the feasibility stages to full operation and will use its own resources together with subcontracted specialists and suppliers. The choice of an EPC contractor will be made based on a combination of factors:

• The ability to offer a biomass technology that is recognised, approved, fundable, and capable of delivering the target output
• Time - the ability to comply with the client’s target programme
• The willingness of the contractor to accept and manage a proportion of the risks
• Cost - the profit or fee level required by the contractor
• Methodology - a process and culture that fits with the client’s vision and objectives.

Both types of procurement are likely to contain incentives that will provide rewards for achieving financial targets, programme milestones and technical performance levels.

The multi-contract gives the client greater control over design and the technical solution, together with the selection of supply chain partners. The client is also able to manage risks more closely, leading to lower levels of contingency allowance. EPCs, however, provide a single point of responsibility and allow the client to share and cap risk exposure and reduce in-house resources.

Whichever route is chosen, the procurement of major plant involves significant pricing risks relating to exchange rates and commodity prices. The client can manage the currency risks by either agreeing a local currency price and hedging against exchange rate fluctuations by forward buying, or by converting tenders to sterling prices through negotiation. The alternative is to accept the risk by agreeing a fluctuating price for part, or all, of the contract. Commodity prices are harder to manage and very few suppliers will give fixed price bids involving long lead-in periods, resulting in this risk normally being accepted by clients.