Financing On Projects By Ritesh Bhusari Mba Finance Pune University

Hudco to finance co-generation projects By Our Staff Reporter Monday, Feb 03, 2003 Bangalore Feb. 2. The Union Minister for Urban Development and Poverty Alleviation, Ananth Kumar, said here on Sunday that Hudco had approved a proposal to finance co-generation projects for power supply or ethanol production to improve the economic condition of farmers. There was no limit for financing such projects, including sugar factories. The minister was delivering the valedictory address of the two-day national seminar on non-edible vegetable oils as bio-fuels organised by six Union Government agencies, including his ministry, the Samarga Vikas, and SuTRA of the Indian Institute of Science. He said his ministry would consider proposals seeking finance for projects promoting non-edible vegetable oils as bio-fuels. He said Hudco had a turnover of Rs.15,000 crores and made a profit of Rs.300 crores this financial year compared to the turnover of Rs. 8,100 crores and profit of Rs.120 crores last year. A sum of Rs.7,500 crores would be spent on providing urban infrastructure. A considerable portion of this would be utilised for research and related works on bio-fuels. He said the country imported Rs.90,000 crores worth of petroleum products. National security rested on fuel security, and hence there was a need for a debate on the serious issue of dependence on the Gulf for the country's fuel requirement. As much of 64 per cent of the petroleum products supplied in the country was from that region. Dwelling on the Swadeshi and Videshi models of development, he said bio-fuels could give an answer to the problem. While the usage of petroleum products generated hydrocarbons and caused pollution, biofuels were eco-friendly and could boost the rural economy. The minister wondered why the earlier governments had not thought of co-generation in sugar industry, although Brazil did it 50 years ago. Why India, with hundreds of sugar factories, did not think of blending ethanol with petrol? Likewise, "Hongamia" could also be used for power generation in rural areas. The Union Government had ordered use of ethanol in nine sugarcane-growing States. He said planting of "Hongamia" and other species of trees for extracting bio-fuels could be taken up on the 1.5 lakh km. of roads built under the Prime Minister's Gram Sadak Yojana, 8,000 km. of the Golden Quadrilateral Project, along railway tracks, and on tank bunds and dry-land belts. Criticising the earlier governments at the Centre, he said Rs.75,000 crores was wasted on Jammu and Kashmir by way of incentives and subsidies, and another Rs.1,20,000 crores given to industrialists had turned into non-performing assets. But the Vajpayee Government had given Rs.49,000 crores to farmers to bring about real development. A sum of Rs.19,000 crores was given to the States to distribute Kisan Credit Card to 3.5 crore farmers. The Karnataka Minister of State for Rural Water Supply, K.B. Koliwad, presided over the function. Supporting Mr. Ananth Kumar's theme of rural development and programmes, he said the State would implement bio-fuel programmes in earnest. He urged Mr. Ananth Kumar to come to the rescue of loss-making sugar factories and make them take up co-generation. He also made a request to revive sick spinning mills with money from the Rs.25,000-crore technology upgradation fund. Serious efforts must be made to help sugar mills sell their product, he added. Vamanacharya, Trustee of Samarga Vikas, welcomed the gathering. T.V. Krishna Bhat of the Indira Gandhi National Centre for Arts, V. Balasubramaniam, former Additional Chief Secretary, Udupi Srinivasa of the IISc, and Y.V. Ramakrishna were present. K.V. Raju, who has done extensive research on the use of bio-fuels, urged the Centre and the governments of the States to take up the project seriously for speedy development of villages. Can CDM help CHP projects develop? - is the finance vehicle effective for cogeneration? Julie McLaughlin Pieter-Johannes Steenbergen Juan Carlos Parreño Bodhi Datta The addition of a revenue stream that flows from avoided carbon emissions ought to improve the economic case for many low-carbon projects in the developing world. But how much impact has the main carbon finance vehicle - the Kyoto Clean Development Mechanism - had so far on proposed

cogeneration schemes? Julie McLaughlin, Pieter-Johannes Steenbergen, Juan Carlos Parreño and Bodhi Datta find out. The Clean Development Mechanism (CDM) is one of the three flexible mechanisms of the Kyoto Protocol and allows for the purchase of Certified Emission Reductions (CERs) by industrialized nations from sustainable development projects in developing nations (for example projects concerning renewable energy and energy efficiency) as a means of complying with domestic emission limits. In addition, CDM projects can be used for compliance under the European Union Emissions Trading Scheme (EU ETS). The European Parliament approved the scheme in 2003 to prepare European nations for the entry into force of the Kyoto Protocol. Key European industries (for example electricity generation, pulp and paper, ferrous and non-ferrous metals, and cement) are forced to comply with their emission limits. This article describes how CDM can uplift cogeneration project development because of this demand for CDM projects under the Kyoto Protocol and EU ETS. First we provide some background on CDM and the whole process cycle from design to commercializing issued CERs. Then we provide some financing models to ensure project developers can benefit from CDM. The current market outlook provides a perspective on what we might expect for the future, so we close our discussion by looking at potential opportunities for cogeneration CDM project development. What is the CDM? The CDM is a mechanism that allows an industrialized nation listed in Annex I of the United Nations Framework Convention on Climate Change to buy emission reductions which arise from sustainable development projects that are in non-Annex I (developing) nations (see Figure 1). The carbon credits that are generated by a CDM project are termed CERs, expressed in tonnes of CO 2 equivalent (tCO2e).

Click here to enlarge image Figure 1. How the CDM works For a project to generate CERs, it must undergo a rigorous process of documentation and approval by a variety of local and international stakeholders. The key stages in the CDM project cycle (see Figure 2) are the initial feasibility assessment, development of a Project Design Document (PDD), host country approval, project validation, emission reduction verification and credit issuance. The figure shows the interdependencies of the activities that need to be undertaken as part of the process and which stakeholders are responsible for carrying out each activity. These stakeholders include the CDM project developer and the CDM Executive Board (CDMEB), as well as the Designated Operational Entity (DOE), which is responsible for validation and verification of the project, and the Designated National Authority, which has the authority to grant host country approval for the project. A CDM project can be thought of as a conventional project with an additional CDMspecific component. Figure 2 also compares the CDM project cycle with the conventional project cycle.

Click here to enlarge image Figure 2. The CDM project cycle It is worth noting, however, that in reality it is possible that the various actions and events throughout the CDM project cycle will not fall neatly into the three phases. For example, it may be possible to commercialize the carbon credits even before a PDD has been fully developed provided a buyer is willing to take on the risks associated with passing the various hurdles of host country approval, validation and registration. On the other hand, a project may be put through the CDM project cycle after it has already been constructed, provided that evidence can be provided that the incentive from the CDM was seriously considered in the decision to go ahead with the project. Figure 2 shows that the same broad types of finance are typically applicable to the three phases of a CDM project and a conventional project. The planning phase is very high risk and therefore only suitable for equity or grant funding. The risk associated with the construction phase is high to moderate and remains so until technical and financial completion can be demonstrated, making this phase suitable for a combination of debt and equity. The costs associated with ongoing operation and maintenance are typically covered by the project’s revenues, and the risk associated with this phase is much lower. Once the project is registered, CERs may be issued at any time, following verification by a DOE and a formal request for issuance to the CDM EB. All CDM projects must satisfy certain requirements specified in either the Kyoto Protocol or the Marrakesh Accords. These include requirements that the project: •

complies with the eligibility criteria (for example sustainable development criteria) of the host country and other parties, and receives project approval by the host country

•

provides real, measurable and long-term benefits related to the mitigation of climate change using a baseline and monitoring methodology

•

delivers reductions in emissions that are additional to any that would occur in the absence of the certified project activity

•

does not result in significant environmental impacts and undertakes public consultation

•

does not result in the diversion of official development assistance (ODA).

How can project developers benefit from CDM? Registration as a CDM project can increase the financial attractiveness of a project in two ways: CER revenue can simply increase the project IRR and mitigate risks by virtue of providing a relatively long-term revenue stream denominated in hard currency (euros or US dollars), often backed by a highly rated counterparty. At the time of writing, 685 CDM projects are registered with the CDM Executive Board. Clearly, all these projects have obtained financing of one kind or another to cover their CDM-specific project

costs. The majority of the CDM-specific project costs occur during the planning phase. They must therefore be regarded as high risk because they will not be recovered if the project fails to be implemented. Such costs must therefore be covered by risk capital - either equity or grants, which do not have to be repaid if the project does not eventuate. The situation is more complex with regard to the costs incurred during the construction phase. As noted elsewhere, these costs are generally much larger than the planning phase costs, yet CDM projects are still relatively ‘small’ (typically under $20 million). Market outlook: what is happening? The overall expected CER flow from all 261 cogeneration projects currently in the 31 May UNEP RISO pipeline totals almost 150 Mtonnes of carbon emissions. This represents a potential of €1 billion in CER revenues. Potentials are constrained by success in passing the whole CDM process cycle, for example becoming registered and issued CERs. As of today, the status of development for cogeneration projects range from validation to registration. The overview in Table 1 disregards projects that have been identified but were not yet submitted for validation to the DOE.

Click here to enlarge image Geographically, these cogeneration projects are mostly concentrated in India, China and Brazil (see Figure 3).

Click here to enlarge image Figure 3. Geographical distribution of the top five and other projects (in number of projects) Regarding the project size, the yearly issuance of CERs per cogeneration project averages to 90.7 ktCO2. Figure 4 shows that 75% of the projects produce 0.7-103 ktCO2. Figure 5 shows that the average installed capacity (expressed in megawatts either from electrical or thermal power) of the cogeneration projects is 23 MW, and 75% of the projects range from 0.5-27.3 MW.

Click here to enlarge image Figure 4. Distribution of project size according to amount of carbon dioxide offset

Click here to enlarge image Figure 5. Distribution of project size according to power output The distribution of project types is represented in Figure 6. Some 98% of the cogeneration projects are of the biomass energy and energy efficiency types. The tendency is the same with regards to generation of CERs. Specifically, the most frequent types are in the bagasse and iron & steel sectors, with respectively 100 (38%) and 50 (19%) projects (also see Table 2).

Figure 6. Distribution of project type by number of projects

Click here to enlarge image Challenges: case studies The main hurdles to implementation that cogeneration projects face under the CDM are related to the applicability of CDM methodologies and to additionality, which means that a project is able to demonstrate emission reductions are additional to those that would occur in the absence of the project activity. Generally speaking, cogeneration projects require a significant investment in infrastructure that cannot be recuperated with CER revenue (carbon financing) alone. On the other hand, CDM projects abating industrial gases like HFCs, PFCs and N2O have payback periods of two years or less only considering carbon financing and easily pass the ‘additionality’ test. For several reasons, cogeneration projects often confront issues that prove additionality. First, numerous cogeneration projects reach fruition in the absence of carbon financing, making it more difficult to prove that a project requires carbon financing for implementation. Second, cogeneration projects frequently result in cost savings for the project developer through efficiency, further complicating the financial additionality argument. Third, cogeneration technology is often available in the host country, which can invalidate the ‘common practice’ additionality argument in the view of the CDMEB. In practice, however, it is evident that numerous industries are not motivated to implement cogeneration projects in the absence of CER revenue, despite access to technology and long-term cost savings. One example is the sugar mill industry in Mexico, where only 1.7% of sugar mills employ biomass for 100% of their energy, even though it is cost effective and low risk given bagasse production. Similarly, India has 74 projects seeking CDM certification, but only 21 have succeeded in actually achieving registration with the CDMEB because additionality questions are increasingly raised regarding whether cogeneration with bagasse should be considered common practice in India. Cogeneration projects that use biomass face another barrier to entry: securing a long-term biomass source. Projects that do not have biomass residues associated with their operations are subject to price volatility in the biomass market. Even those projects which own the biomass residues are forced to justify the use of biomass for energy when market prices are high.

Click here to enlarge image A palm oil biomass project in Malaysia On the other hand, there are several CDM success stories for cogeneration projects. As stated previously, 87 cogeneration projects (33% of the total projects that have reached validation) have achieved CDM registration with the Executive Board. Sahabat is one such project, developed by EcoSecurities. Sahabat is an empty fruit bunch (EFB) biomass project implemented by Felda Palm Industries in Malaysia. Before the implementation of the CDM project, Felda was stockpiling the 500,000 tonnes of EFB a year generated by its mill operations. By installing a 7.5 MW Shin Nippon turbine and Eckrohr Kessel boiler for biomass cogeneration, Felda was able to save over 7 million litres of diesel a year, generate almost 60,000 tCO2e equivalent of emission reductions and resolve its EFB disposal problems. The CER revenue over a 7 year crediting period accounts for 6% of the total investment costs, which, while insufficient to cover all project costs, makes the project feasible in conjunction with the fuel savings and waste disposal benefits. Challenges: methodological issues For a project to achieve CDM certification for the emission reductions it achieves, it must be developed using an approved methodology. Each methodology has a set of applicability conditions and guidelines that dictate whether or not it may be applied for a specific project. Certain projects encounter difficulties in matching project conditions with methodology applicability requisites. Others stumble in calculating and proving their emission baseline scenario from which they will be generating emission reductions. The most common issues encountered when applying methodologies for cogeneration projects include: •

Defining the applicable methodology where partial or complete fuel substitution will occur.

•

Calculating the baseline given seasonal fluctuations of more than one fuel type and clearly justifying scenarios in the absence of project activity.

•

Proving and measuring the baseline emissions where the production of methane gas comes from the decomposition of biomass stockpiles and landfills. Methane emissions can fluctuate with changes in biomass competition and ambient temperature, frequently necessitating a corresponding change in monitoring method.

•

Proving additionality of greenfield plants or expansions using new technology, for example inclusion of back-pressure turbine cogeneration plants.

•

Addressing international boundaries, the spatial project boundary and international borders; and the export of power to international grids, which is only permitted under CDM if power is exported to another non-Annex 1 country.

•

Incorporating the effect of efficiency changes since supply/demand-side efficiency projects with fuel switch result in a capacity increase due to efficiency measures.

•

Addressing the extent of applicability for efficiency projects - boiler versus entire plant.

Eligibility of smaller CDM projects for bundling in order to reduce transaction costs is limited to 45 MW thermal input savings or to those projects implemented within 1km and registered within 2 years of each other. The process of addressing the methodology challenges stated above requires the co-operation of project developers, CDM developers and the CDM Executive Board. Constant clarification requests and amendments to existing methodologies contribute to move the process forward but are often time consuming. Market prospects: where are the opportunities? Numerous opportunities exist to develop new cogeneration projects in the developing world under the CDM framework. Developing projects under the CDM is especially attractive when considering the additional revenue source beyond cost savings from the production of energy itself. CDM cogeneration projects are most prevalent in the biomass and self-generation sectors, representing 102 (39%) of the total cogeneration pipeline respectively. While it may be that specific countries like Brazil and India have already implemented the most attractive biomass cogeneration projects, the potential for similar projects in other developing countries remains quite high. Furthermore, by implementing CDM projects under methodologies for biomass or energy efficiency for plants’ own generation, the projects benefit from the numerous lessons learned by those who have already completed the process. In addition to the CDM cogeneration project types that have an established track record (see Table 2), many others have yet to be exploited. Such is the case for cogeneration opportunities in the petroleum refining industry. The petroleum refining industry is one of the largest users of cogeneration in the US. Where process heat, steam or cooling and electricity are used, cogeneration plants are significantly more efficient than standard power plants because they use waste heat, taking advantage of what are losses in standard plants. In addition, transportation losses are minimized when CHP systems are located at or near the refinery. Since supply-side energy efficiency only comprises 0.4% of existing CDM cogeneration projects, the prospect is quite promising for implementing such projects under the CDM in large oil-producing countries in the Middle East, Africa, South America and Asia. Identifying specific opportunities for cogeneration projects under the CDM in developing countries requires leg work. Researching industry opportunities and common practice in each country of interest is essential. However, it is usually not sufficient in and of itself. An understanding and presence at the local level is demanded as well to succeed in the identification, evaluation and eventual implementation of cogeneration projects. The fact that only 33% of the proposed cogeneration projects have actually achieved CDM registration to date demonstrates the complexity of the processes. Only through hands-on development is a project likely to address effectively the numerous requisites laid out by the applicable methodologies and reap the benefits of certified emission reductions. Julie McLaughlin is Manager, Co-ordination & Resources Unit, EcoSecurities, Oxford, UK. Pieter-Johannes Steenbergen, Juan Carlos Parreño and Bodhi Datta are also with EcoSecurities e-mail: [email protected] About EcoSecurities EcoSecurities is in the business of originating, developing and trading carbon credits and structures. It guides greenhouse gas emission reduction projects through the Kyoto Protocol, working with both project developers and buyers of carbon credits. This article is on-line: www.cospp.com Evaluating cogeneration for your facility: A look at the potential energy efficiency, economic and environmental benefits Joel Puncochar, Product Manager, Lean Burn Gas Generator Sets for Cummins Power Generation explains how the principles of cogeneration have long been known and put to use in a wide variety of applications - from Thomas Edison's first electric generating plant in 1882, to modern chemical processing facilities, to municipal utilities supplying power and district heating. In the past, economies of scale favored large, complex projects or special situations. Today, however, advances in lean-burn gas reciprocating engine technology, heat exchangers and digital system controls make cogeneration both practical and economical for applications as small as 300 kW. This

is causing many more types of facilities - large and small - to take a fresh look at cogeneration as a way to improve energy efficiency, cut greenhouse gas emissions and reduce costs

The number of project finance deals in the Remewable Energy sector is growing more rapidly than ever, Richard Stuebi explains why: Structured energy project finance has been relatively commonplace in supporting the development of new energy facilities over the past 20 years. Central to the concept of project finance is disaggregating risk and parceling it out to specific parties who can accept that risk. As a result, project finance works great for the 30th or 40th deal of the exact same type, but it is typically very hard to use project finance approaches for funding the development of facilities using innovative technologies or commercial arrangements. Accordingly, project finance has historically been somewhat problematic for renewable energy interests to procure. Financiers central to structuring the deal were either unfamiliar or uncomfortable with the risks posed by renewable energy technologies, most of which have not been in commercial operation for decades. This lack of project finance capacity has thus been a major barrier to the widespread deployment of otherwise viable renewable energy technologies in commercial-scale projects. The good news is that project finance capacity is increasingly opening its doors to renewable energy opportunities. Financial professionals with deep knowledge of the true abilities of renewable energy are finally beginning to amass capital to deploy in sponsoring the development of renewable energy projects.

Advisory services for the Renewable Energy sector Our renewable energy group provides M&A transaction support, due diligence, project and structured finance advice to project sponsors, bidders, investors and borrowers. Our team has experience of all major renewable energy technologies employed in Europe, the US and the Pacific region, and has advised on projects with a value in excess of US$1 billion. Backed by a global network of professionals with experience in renewable energy and sustainable development schemes operating in more than 30 countries around the world, we are able to offer a fully integrated service to our clients. Each project is run by an experienced director who selects the best team for our client's project based on their blend of skills and experience. By drawing on our international network, we can bring a global perspective to a project, while retaining a strong regional focus. We recognize that projects require strong financial advice to deliver appropriate, economically viable structures that meet stakeholder needs. On all of our projects, our approach relies on financial experience backed by strong sector knowledge and a proven track record. Carbon credits finance renewable energy project in Bulgaria 18 September 2007 The EBRD, through its Netherlands Emissions Reduction Co-operation Fund, is purchasing carbon credits from a hydro power project in Bulgaria that will help significantly reduce Greenhouse Gas (GHG) emissions. The project envisages the establishment of nine small hydro power plants along the river Iskar, about 40 km north of Sofia, with the aim to cut 336,462 tonnes of CO2 by replacing electricity generated by fossil fuels with hydro power electricity, a renewable, zero-emission source of energy. The hydro plants will be built, owned and operated by Vez Svoge, a company 90 percent owned by a subsidiary of Petrolvilla & Bortolotti, an Italian provider of energy and energy-related services, and 10 percent by the municipality of Svoge. The carbon credit sale is in accordance with the 1997 Kyoto Protocol, an international treaty to reduce GHGs that came into force on 16 February 2005*. The Kyoto Protocol covers six GHGs, including carbon dioxide as the main contributor to worldwide GHG emissions. Carbon credits are created when a project reduces or avoids the emission of GHGs when compared to what would have been emitted without its implementation. The Kyoto Protocol has created a market in which companies and governments that reduce GHG levels can either use such reductions for compliance or sell the ensuing carbon credits. Jacquelin Ligot, EBRD Director for Energy Efficiency & Climate Change, said that by purchasing carbon credits from this project, the EBRD managed Netherlands Emissions Reduction Co-operation Fund is helping Bulgaria diversifying its fuel mix. The sale of carbon credits provides an additional incentive that renders such projects viable, Mr Ligot said. The GHG emission reductions will be verified by an independent entity to ensure that the emission reductions claimed have actually been realised. The Government of Bulgaria will then transfer these credits to the account of

the Netherlands. The Netherlands has agreed to cut its 1990 GHG emissions by 6%, which translates into a reduction target of 200 million tonnes by 2012. To date, the EBRD, on behalf of the Dutch Fund, has signed three carbon credit projects in Bulgaria, which are expected to generate 1.7 m carbon credits. These projects include the switch to biomass energy at the Paper Factory Stambolijski, an energy efficiency investment programme at Svilocell and a portfolio of energy efficiency and renewable energy projects with bank UBB. As the Dutch Fund is nearly fully invested new carbon projects in Bulgaria will be developed under the Multilateral Carbon Credit Fund (“MCCF”), a joint EBRD-EIB initiative which facilitates the purchase of carbon credits from projects across the high energy intensity countries of central and eastern Europe and the Commonwealth of Independent States. Typical projects will include industrial energy efficiency, fuel-switch, renewable energy (for example, biomass, wind and mini-hydro) and landfill gas extraction and utilisation projects. The EBRD is the largest investor in Bulgaria with more than EUR 1.3 billion committed to projects across the country. Working with its many partners, the Bank has mobilised more than EUR 5.4 billion for projects in Bulgaria. * The Protocol requires 36 industrialised countries and countries undergoing the process of transition to a market economy to reduce GHGs by at least 5 percent below 1990 levels between 2008 and 2012.

Biomass to cogeneration 02-SEP-2005

for New Zealand dairy farms Dairy farms could form an ideal application for cogeneration plants fuelled by biogas produced on-site by the anaerobic digestion of manure. Such a solution would cut farmers’ electricity bills and help to solve a waste disposal problem, writes Ian Bywater. Dairy farming in New Zealand has expanded rapidly, with dairy cattle numbers growing by 23% between 1999 and 2002, and more growth expected. A less welcome result is that a lot more manure has to disposed of at milking time. Between 6% and 12% of the manure produced by a New Zealand dairy herd each day accumulates in the dairy shed area. This quantity is much higher in countries such as the UK, where the animals are not out grazing everyday as is the case in New Zealand. Therefore if the New Zealand system is shown to be viable it will be of even more use in countries where animals are housed for part of the year. This is because more manure is then available for collection. From the 1970s, New Zealand farmers have been encouraged to dispose of effluent from dairy sheds in a twopond treatment system. The ponds receive the waste water effluent daily after milking. They contain manure, spilt milk, water from udder and machine washing, chemicals used during milking, mud and grit. About 30% of New Zealand dairy farms still use this system, but it does not always dispose of the raw effluent or destroy pathogens to today’s environmental standards.

THE ISSUES In the 1990s, following the passing of New Zealand’s Resource Management Act, the Ministry of Agriculture and Fisheries stopped promoting effluent ponds. It now recommends disposing of diluted effluent by spray irrigation of open pasture, sometimes after storage in an effluent pond if conditions are not suitable for daily dispersal. Problems with this solution include the contamination of groundwater, leaching of nutrients from the soil, delay in grazing, and unpleasant odours. In some situations, spray irrigation is impractical or constrained by soil type. This means that ponds must be used, preferably those with an advanced design and function. Dairy farming places a considerable load on the electricity grid once or twice daily at peak times Dairy farming also requires large quantities of water each day to keep the dairy shed and environs clean, and cold water is needed to pre-cool the milk in an amount estimated at 50 litres per cow per day. Groundwater is first used to pre-cool the milk and then held for the shed hosing operations. Dairy farming also places a considerable load on the electricity grid once or twice daily at peak times, although twice-daily milking is losing favour to once-daily. New Zealand cows produce more than 3,500 litres of milk each per year, requiring 116 kWh per head of electricity for harvesting and processing. Some 60% of this power is used to heat water and to chill the milk, in roughly equal amounts, while 40% is used to power the milking system, to pump water and effluent, and to provide lighting, etc. Milk is not always collected daily and must be kept chilled below 7°C. More than 80% of dairy farms have refrigerated vats. Some water can be pre-heated by recycling the heat removed from the milk. Simple heat exchangers, such as plate coolers, are used to cool the milk before it enters the refrigerated vats. Simple measures such as insulating the milk vats, recycling hot water and using non-peak electricity to heat water may help a farm’s profitability. However, an integrated energy system could save more energy costs and reduce demand on the electricity grid while conserving water and reducing the odour and other environmental

problems of effluent disposal. Figure 1 shows the operation of one solution, under development by Natural Systems Ltd, called BioGenCool.

WINNING TEAM In its New Spirit Challenge competition, the Institute of Electrical Engineers in the UK recognizes individuals worldwide whom it judges to be making an innovative contribution to sustainability. The author had a winning entry in the 2003 competition that outlined an integrated energy system to use dairy-shed wastes to cogenerate the heat and electricity needed to cool milk and provide hot water. The system combines three core technologies for which a patent filing has been made. First, an anaerobic biodigester to convert the manure waste into biogas and biosolids. Secondly, a cogeneration technology, for example a Stirling genset, to use the biogas as a fuel to produce on-site power and heat. Thirdly, a cold-storage medium, such as an ice bank, with a capacity to cool the milk from cow body heat down to the required safe milk-storage temperature.

BIODIGESTER The dairy-shed wastes are fed into a biodigester system in which they will be converted into biogas in a process analogous to that occurring in the rumen (the first stomach of a cow) in which organic matter is broken down anaerobically by mixed microbial populations. A biodigester is essentially a heated tank into which the manure and water slurry is directed. Oxygen is excluded to allow anaerobic bacteria to liquefy the volatile organic compounds in the mixture and then convert the resulting simple organic acids into a methane-rich biogas. Anaerobic conditions allow methane-producing bacteria to flourish while inhibiting those that produce foul odours. The undigested solid residue has not lost any nutrient value and is suitable for storage followed by land application, or for sale as compost or soil conditioner. The supernatant liquor is generally pathogen free and can be used for pasture irrigation without the drawbacks associated with raw effluent dispersal. Anaerobic digestion does not significantly reduce waste volume, so the same amount of waste that enters the biodigester leaves it each day. The entry pipe can be closed to prevent detergents, medications and other contaminants entering the biodigester. The biodigester is usually heated to provide optimal conditions for bacterial growth, and maintained at pH 6.6 to 7.6. A proportion of the heat output of the cogeneration unit is fed to the biodigester to maintain optimum thermal conditions. An integrated energy system could save energy and reduce demand on the grid The biodigester design will need to be standardized to minimise production costs, although some site engineering will be required. A two-stage design is being considered with the ability to keep the biodigester

activity alive year-round, even when some farms’ herds are in the period when milk production ceases for a time, usually over winter. This way, the dairy farmer can have biogas production at the start of the new milking season and not suffer a delay in starting biodigester activity.

COGENERATION Biogas is best suited for continuous stationary operation because of its low energy density (about 60% of that of natural gas) and low level of corrosive contaminants, and the more or less constant production rate from the biodigester. It is especially suited to fuelling a Stirling engine or appropriate fuel cell. Capital costs will most likely dominate the choice of cogeneration plant, which today is more likely to be an internal combustion engine and generator. However, generators driven by Stirling engines and ceramic or molten-carbonate fuel cells that offer high efficiencies will be used once they become cost competitive. Table 1. Estimated energy benefits for New Zealand of using integrated energy systems on dairy farms New Zealand dairy herd statistics in 2003/04 (www.lic.co.nz) Herd size

Numbe Percentag r of e of herds herds

Number of cows

Analysis of BioGenCool yield on a per-site basis (estimates from dairy energy evaluation modelb)

Percentag Electricit Electricity Water e of cows y load generated (kWh heating factor per year) electricity during displaced season (kWh per (%) year)

Cooling energy displaced (kWh per year)

Peak Load Reductio n (kVA)

10200

4312

33.8

623,399

16.2

0

0

0

0

0

200300

3662

28.7

879,065

22.8

58

16,800

3800

7200

6

300400

2042

16

687,786

17.8

80

23,100

3800

7800

8

400500

1083

8.5

475,342

12.4

93

26,900

3800

12,900

11

500600

625

4.9

336,024

8.8

100

28,900

3800

25,300

14

600700

384

3

244,387

6.4

75

43,600

6700

29,000

19

700800

227

1.8

167,182

4.4

83

48,000

6200

30,200

20

800900

140

1.1

117,023

3.0

90

51,900

6200

37,800

26

9001000

91

0.7

84,627

2.2

96

"center">55,700

10,700

38,600

28

1000+

185

1.5

236,467

6.1

100

57,900

13,100

42,200

29

12,751

100

3,851,30 2

100.1a

Total a b

National benefits: 358 GWh per year and 81 MVA

Rounding error Model developed by Natural Systems

Using biogas in an internal combustion engine presents some problems. It must be of a sufficient energy value and cleaned of corrosive contaminants. This will usually mean scrubbing out the carbon dioxide and hydrogen sulphide content. This can be done chemically. For an internal combustion engine, the biogas will also need to be compressed to give it a pressure suitable for induction. The compressor can be mechanically driven off the cogeneration set. An added advantage of having a cogeneration plant on the farm is that it can also be used in electricity supply emergencies to allow milking to continue. With the large numbers in modern dairy herds in New Zealand (up to 1000 head), it is no longer possible to contemplate hand milking! At those times when the biogas is insufficient, LPG back-up cylinders or LPG bulk supply tanks can be installed to maintain emergency generation facilities. In the BioGenCool system the electrical output is mains synchronized and runs continuously to provide power to the refrigeration unit used to provide the ‘cold storage battery’ for milk cooling. In general, no electricity is exported to the grid, but a biodigester does offer the opportunity to add more biomaterial to increase the biogas production and hence create surplus electricity.

Natural Systems has developed a full analytical model for New Zealand dairy farms so that the benefits of the BioGenCool system can be quantified (see Table 1). Recent analysis of a 50-bail rotary dairy showed that 28% of power is used for water heating, 26% for milk chilling, 9% for farm water supply, 9% for the variable-speed vacuum pump, 9% for the wash-down pump, 4% for lighting, 2% for effluent pumping and 13% for other needs. The model is sufficiently robust to enable it to be configured for dairy farming in other countries. It is worth noting that over 50% of New Zealand herds have less than 300 cows, which suggests reduced energy benefits of on-site cogeneration. However, application of BioGenCool offers significant benefits in terms of reduced water use and reduced peak demand due to water pumping and chiller operation. The integrated energy system’s estimated net electricity benefit to New Zealand would be 358 GWh per year The estimated net electricity benefit to New Zealand (assuming a 100% uptake) is 358 GWh per year, and demand reduction of the order of 81 MVA during milking periods. This demand reduction would coincide with network demand in the morning and mid- to late afternoon, although some (3–12 kVA) may already be reduced because electricity network companies remotely switch off water heaters at peak load times by using ripple control systems.

COOLING Cows produce milk at a body heat of 37°C, which means it must be cooled rapidly to prevent spoilage by microbial action. New Zealand standards are that the temperature must be reduced to 7°C or less within three hours of entering the storage vat. Usually this is accomplished by using cold ground water from a bore through a primary heat exchanger. This exchanger, which typically removes 60%–80% of the milk’s heat is used only once and discarded (it is usually then stored and used for washing down the shed), greatly adding to the volume of water used by a dairy farm. Storage vats must keep the milk cool until it is collected by a tanker, which may not call every day. Milk tankers are not refrigerated, so the milk must be cool enough when collected at the farm to withstand the trip to the plant without losing its quality. A farmer is penalized if the milk quality is below standard.

Ice bank using flat-plate, heat-pipe technology A prototype 1 tonne ice bank has been designed by Thermocell Ltd of Christchurch. It incorporates stainless steel, flat plates refrigerated by using the heat-pipe principle (see photograph opposite). Ice banks and chilled water tanks are used on some dairy farms in New Zealand. Only 4% of dairy farms used them in 1996, using mains electricity for power. Electricity generated by the cogeneration set in the BioGenCool system will power the ice bank on a 24/7 basis to produce ice by running the refrigeration system continuously at a capacity of 6 kW (cooling) or about 2 kW (electrical) per 300 cows. For small herds, this may displace the bore water required for pre-cooling of milk. In operation, the ice bank circulates water to the plate heat exchanger. The warmed water is passed back to the ice bank while the cold milk is stored in a vat. More ice will melt to produce water at 0°C to be circulated to the plate heat exchanger. At the end of a milking, most if not all the ice will have been melted, and ice formation will continue to build until the next milking session. It is estimated that by this means the refrigeration capacity will be reduced to one sixth the normal size used to refrigerate a milk vat. Alternatively, a glycol system of cooling could be used, although the equivalent fluid storage volume would be 10 times greater than for an ice bank.

HEAT Hot water will be produced for washing use in the dairy shed primarily from the cogeneration set, supplemented by heat from the refrigeration plant and from any hot water solar collectors on the dairy-shed roof. Some of that heat is used to maintain optimum thermal conditions in the biodigester system.

Alternatively, there is the possibility to use an absorption refrigeration plant fuelled directly by the biogas plant, or to use a heat engine to mechanically drive compression refrigeration plant for ice making or glycol cooling.

ON-FARM TRIAL The South Island Dairying Development Centre is in discussion with Natural Systems to trial the system at its 650-cow demonstration farm at Lincoln University near Christchurch. Detailed design work, once approved, will begin in the third quarter of this year, with the expectation of it being installed half-way through the southern hemisphere milking season. A demonstration of the system will be a precursor to the commercialization phase. Dairy farming is increasing throughout South Island, where some electricity network companies experience summer peaks that are much higher than winter peaks because of intensive irrigation and milking operations. A system such as BioGenCool has many features that make it attractive to these rural network companies. In summary, the BioGenCool system encapsulates the sustainable practice and sensible application of using an on-site biowaste as a fuel resource for cogeneration, sized to the specific needs of the production taking place, i.e. milking and storage of milk. BioGenCool has other possible applications, particularly for developing economies in which a mains supply of electricity is poor or non-existent and where a food product is being processed, for example fish farming, or fruit or vegetable preparation. Ian Bywater is an independent energy consultant and a director of Natural Systems Ltd, Christchurch, New Zealand. Fax: +64 33 65 41 46 e-mail: [email protected] This article is based on an article by Claire Le Couteur, published in 2004 in the magazine of the Institution of Professional Engineers of New Zealand.

How to maximize availability 02-NOV-2005

Maintenance options for gas turbines The availability of the gas turbine is crucial to the performance of a turbine-based cogeneration plant, and availability is a function of good, well-planned maintenance, writes Simon Raymond. A long-term service agreement, which transfers some financial risk to the service provider, can be the best option for the care of turbines of high capital cost. Owning and operating a gas turbine is an expensive business. The principle of how a gas turbine works is simplicity itself, but putting that into practice requires mechanically complex pieces of equipment built with high-grade materials and a host of supporting systems that need to work in harmony.

Figure 1. The goals that a gas turbine operator and maintenance provider strive for The inherent design of a gas turbine is naturally a major factor in how reliably it performs in service, but of at least equal importance is how the equipment is looked after, or maintained, while it is in service. Having invested a large amount of capital in a gas turbine power plant with all its ancillary equipment, the owner will want to maximize the return on that investment by having that power plant running at a high level of reliability while keeping running costs to a minimum. The power advantages of a gas turbine over, for example, a like-sized diesel engine are offset to some extent by its need for routine maintenance and its relatively high servicing costs. Gas turbines do not forgive poor maintenance. It will cause them to stop functioning soon. The repair costs of a poorly maintained turbine can be frightening, to say nothing of the disruption to the owner’s operation. If a satisfactory balance between maintenance and cost can be found, then extraordinary reliability is achievable while preserving the owner’s

profitability, as Figure 1 shows. But how is this maintenance carried out, and what maintenance philosophies exist? A gas turbine’s power advantages are offset to some extent by its need for routine maintenance and its high servicing costs The owner of a gas turbine power plant is not generally in the business of gas turbines so has neither the ability nor desire to perform the maintenance themselves. Even though some car owners prefer to service their cars themselves, the majority prefer to leave the job to a specialist. Yet if a car were bought for many millions of dollars, it is extremely unlikely that an owner would be carrying out the maintenance and servicing! The car analogy falters when considering that driving a car can be a pleasure in itself. Operating an industrial gas turbine is not done for pleasure; it is a means to an end. The power that a gas turbine produces allows the owner-operator to carry on with its core business, be that automobile manufacture, chemical processing or foodstuff extraction. Table 1. A typical gas turbine maintenance schedule Interval

Action

Every 4000 running hours (engine remains installed)

Inspection of gas generator inlet Removal of low-pressure compressor casings to permit inspection of compressor stator and rotor Borescope inspection of high-pressure compressor, combustion section, turbines and integrity features Inspection of oil filters and chip detectors Inspection of engine’s exterior

Every 8000 running hours (engine remains installed)

As for 4000 hour action plus: Replacement (exchange) of high-pressure compressor stator assembly Refurbishment of low-pressure compressor vane assembly

Every 25,000 running hours (engine removed)

Replacement (exchange) of hot section module:

Every 50,000 running hours (engine removed)

Full overhaul and reconditioning of complete engine to return to an ‘as new’ standard

combustion and high-pressure turbine modules

Maintenance, repair and overhaul (MRO) service providers, such as Volvo Aero, take on the challenge of maintaining gas turbines so that customers can focus on their core business. The more risk that a customer passes to its MRO service provider, the greater its peace of mind.

MAINTENANCE REQUIREMENTS There are intrinsic maintenance requirements for any gas turbine. Dynamic and static parts in any machine do not last forever and will ultimately fail. Being able to predict failures and take the necessary action to prevent them is the basis of any maintenance philosophy. Thermal fatigue, cyclic fatigue, mechanical stress, erosion, corrosion and contamination are some common reasons necessitating an intervention to allow either assessment of damage (and hence remaining-life potential) or correction of defective components or both actions. The design and development testing of a new gas turbine defines initially how often and to what extent these interventions ought to take place. Service experience and observations made during the interventions further modifies the maintenance schedule. Being able to predict failures and take action to prevent them is the basis of any maintenance philosophy There are almost as many maintenance schedules as there are types of gas turbine. However, for the purposes of this article, a notional schedule for an aero-derivative gas turbine is shown in Table 1. Note that if any of the scheduled inspections reveal a defect, corrective action will be taken or an assessment made on whether the turbine can continue running safely until the next exposure of the defective part.

Figure 2. Simplified flowchart of a gas turbine overhaul process In terms of expense, the full overhaul, in this example at 50,000 running hours, is by far the dominating event in an engine’s life cycle. During an overhaul, the turbine is stripped down to piece parts, cleaned and inspected before re-assembly and acceptance test, as Figure 2 shows. A technical decision is made on each inspected part. This leads to its being: •

acceptable for continued use

•

not acceptable for continued use but within limits for repair

•

not acceptable for continued use and not repairable, in other words ready to be scrapped.

A logistical evaluation is then made on unacceptable parts to: •

replace them with new parts

•

repair them (if feasible) and re-use them

•

replace them with used parts that have sufficient remaining life.

Material costs make up the largest part of the total cost for an overhaul, so these logistical decisions have a great bearing on offer price and profitability. There are various maintenance agreements that can exist between a customer and an MRO service provider: •

Time and material (or call-out) agreement. Here, the customer pays for exactly the amount of time and material used for a specific maintenance action at a separately agreed rate per hour and parts price list.

•

Event-based agreement. Here, fixed prices are agreed in advance for specific maintenance activities: 4000-hour inspection, 8000-hour inspection, even full overhaul. The cost for replacement material can be included or excluded.

•

Long-term service agreement (LTSA). This is a form of partnership between the customer and supplier in which a fixed fee per running hour or calendar period is paid throughout a complete life cycle. No separate charges are made for specific maintenance activities. An LM1600 gas turbine undergoes overhaul at the Volvo Aero Corporation in Trollhättan, Sweden

There are three main levels of LTSA: •

Level 1: All scheduled maintenance is included in a fee per running hour or month (typically). In the schedule shown in Table 1, all the work described could be included in a fixed fee per month. Any unscheduled maintenance would be charged separately.

•

Level 2: As for level 1 but also including all unscheduled maintenance.

•

Level 3: As for level 1 but also including all unscheduled maintenance and guaranteeing a minimum level of availability. This is often achieved by the provision of one or more reserve engines that can be used by the customer while their own engine is undergoing unplanned maintenance back at the

supplier’s workshop. Availability is defined by the actual running hours divided by the potential running hours that could have been achieved over a given duration. If a gas turbine plant operates all of its potential hours for a given period, then availability is 100%.

Figure 3. Risk share between owner and maintenance provider for differing levels of maintenance contract Figure 3 shows that much risk is transferred to the service provider when level 2 or level 3 LTSAs are in place. These are an industrial engine equivalent of the all-inclusive rate-perflying- hour aero engine agreements popular with airlines that are looking for a stable cash flow. These LTSAs let the customer know precisely what their financial outgoings will be during an engine’s life cycle, irrespective of any breakdowns and unplanned maintenance. The service provider uses their experience and forecasting to assess and provide for a likely amount of unscheduled maintenance during an engine’s life cycle. This provides an incentive to maximize reliability so that both the supplier and customer share a common goal.

PRACTICAL SOLUTIONS

Regular checks of gas turbine operating parameters are vital to health monitoring and failure prediction There is an increasing trend for gas turbine users to seek a single service provider for maintenance of not just their gas turbine but also the related gearboxes, alternators, control systems, valves, fire and gas protection equipment, heat exchangers and so on. Having a single point of contact for customers to turn to, whatever the problem, reduces administration time and expense for the customer. This has led to the emergence of the socalled multi-service provider, which bundles support options into packages. Volvo Aero, for example, is a multiservice provider although its core business is design, manufacture and maintenance of aerospace and industrial engines. For related services, a network of specialist subsuppliers is used. Volvo Aero then has the responsibility to call on these sub-suppliers as required. Many gas turbine operators are running their power plants around the clock and depend wholly on the power and heat produced for their own production lines. Therefore, having a maintenance contract with a guaranteed level of availability is often an attractive option. Living up to that availability guarantee is something the maintenance provider has to plan carefully for. Having a field service engineering team close to the customer’s site is one of the most important success factors in achieving a high level of availability. The ability to have an engineer on-site to diagnose and rectify

technical problems at short notice is crucial when the difference between achieving and failing an availability guarantee is a matter of a few hours. An infrastructure must exist to ensure that the maintenance provider learns quickly of any problems that arise and has the means to act on them. The conventional 24-hour hotline between the customer and supplier can be enhanced by remote monitoring equipment that allows the maintenance provider to check in real time on a number of power plant parameters from a remote terminal or PC. Self-diagnosis software and the ability to modify control systems from afar is another time-saving step. The more accurate the fault-diagnosis, the more chance a field service engineer has of being able to rectify problems quickly. Tooling and spare parts also need to be available off-the-shelf. This ties up an amount of capital. If technical problems arise that are not possible or too time consuming to rectify on-site, the entire gas turbine is replaced to allow the customer’s production to continue while those problems are dealt with off-site.

Small gas turbines in CHP applications Figure A. Layout of a small cogen gas turbine facility Small gas turbines are used around the world to provide continuous heat and power in many applications. Figure A shows the typical layout of a cogen package, in this case Volvo Aero’s VT4400DLE, which produces around 4.4 MW of electricity and 10 tonnes of steam per hour. Small gas turbines are normally used to provide heat and power to an industrial facility. However, like their larger cousins, electricity produced can also be fed into a national grid or sold on.

Öresundskraft’s 600 kW cogen plant in Sweden An industrial user with its own cogeneration unit enjoys the advantages of high power availability (dual supply sources), few power losses due to the short length of transmission and the reduced transformation. Emissions and environmental impact are low, more so with a dry low emission configuration as shown. There are also a number of fuel options, from natural gas to liquid fuels and gas from processed waste and sewage. A reference 600 kW cogen plant operated by Öresundskraft in Helsingborg, Sweden, produces power for 1200 households and heat for 600 households using biogas from recycled household waste. Daniel Thwaites Brewery in Blackburn, UK, uses a similar power plant to provide its brewing process with power, as do UK hospitals and local authority communal housing estates. Thames Valley Power’s 15 MW cogen plant at Heathrow Airport near London produces steam to heat the Terminal 4 cargo building and electricity for the airport as a whole. Power not used by the airport is sold to the national grid. Thankfully, it is rare for gas turbines to fail spontaneously. There are nearly always some warning signs that enable an turbine’s ultimate failure to function to be predicted. Trend monitoring is hence an important part of a maintenance provider’s work. A number of parameters are monitored over time: oil consumption, oil-borne contaminants, temperature and speed for a given power rating, specific fuel consumption, exhaust emissions, vibration levels and the amounts of wear identified during scheduled borescope inspections, among others. These are all indicators of a gas turbine’s health at any given point in time. Being able to interpret and assess these parameters and take the appropriate action, if deemed necessary, is a key factor in how reliable (and thus available) an individual gas turbine will be. It is rare for gas turbines to fail spontaneously. There are nearly always some warning signs Planning maintenance interventions to coincide with scheduled plant shutdowns is a simple way of improving availability. If a plant is not in use at weekends or overnight, for example, it is logical to perform maintenance actions during these periods rather than interrupting production with a requirement for maintenance. This

requires a close liaison between customer and maintenance provider to schedule work to the best of both parties’ interests.

LEARNING FROM EXPERIENCE To take on the financial risk of unplanned failures in a gas turbine power plant, or even offer fixed prices for specific events, requires a high level of confidence and technical competence. A mature engine with a proven track record of reliability and consistent costs is an ideal candidate for an allinclusive level 3 type of contract. A new engine model with less predictable maintenance costs may be run at a lower level of contract for a number of years to gain the experience to allow unplanned arisings to be included in the maintenance price, if that price is to be realistic. Furthermore, an experienced maintenance provider has the flexibility to adjust the work content during scheduled maintenance to increase engine reliability and prolong engine life. If the timing of the full overhaul at the end of an engine’s life is not stipulated as a finite limit by the original equipment manufacturer, then there is scope for the overhaul to be delayed by up to several years. Cost drivers, like the expense of an overhaul, can then be spread over a longer period. Again, a focus area for a company like Volvo Aero is to optimize maintenance costs while preserving engine integrity and reliability. Naturally, the more LTSAs that a maintenance provider has, the more the risk of unplanned maintenance expense can be amortized over several contracts, thereby reducing risk and price.

REDUCING COSTS We have seen that, with level 2 and 3 LTSAs, there is a financial incentive for the maintenance provider to attain as high a level of availability as possible for the gas turbine in question. Therefore, the extra costs of performing some work beyond a minimum work scope during maintenance activities can be justified. In the notional maintenance schedule in Table 1, the refurbishment of the lowpressure compressor assembly is not an obligatory action and the gas turbine would surely continue to run for a period were this refurbishment not to be performed. However, the risk of a subsequent unplanned maintenance intervention to rectify a worn compressor assembly, with the possibility of consequential damage elsewhere, is deemed as high enough to warrant this non-obligatory additional work to be done, thus ensuring dependable service. With the costs of replacement material making up a high proportion of the total cost of operating a gas turbine, the ability to repair worn and damaged parts rather than replacing them with new is a key factor in reducing costs. Successful maintenance providers focus on the development of repair schemes to salvage parts within the bounds of technical and economic viability. Many companies, large and small, offer specialized repair services such as: •

shot peening to improve wear resistance

•

nickel and chrome plating to restore worn surfaces

•

plasma spray to restore sealing features

•

welding and brazing of fabricated components

•

heat treatment to restore material properties

•

thermal barrier coatings to improve heat resistance.

Many of the above principles have been applied at a 15 MW gas turbine cogen plant at Heathrow Airport near London, UK, operated by Thames Valley Power, which signed an LTSA with the Volvo Aero Corporation in 2003. Before the implementation of an LTSA, an annual availability of some 84% was being achieved at the plant. During the year to July 2005, the plant availability was 99.4%. This is living proof that a smart maintenance philosophy with close liaison between customer and supplier gives results. 99.4% availability provides living proof that close liaison between customer and supplier gives results Volvo Aero is succeeding similarly on several maintenance agreements elsewhere while remembering that a maintenance philosophy is never complete but forever being fine-tuned in the quest to balance cost, risk and availability. Even today, the gas turbine is not a completely mature product. Its future potential to produce more power by running faster and hotter – while running quieter, more fuel efficiently and with less impact on the environment – remains large as material and technological advances continue to be made. In parallel, maintenance philosophies will also have to advance to keep up with the demands for reducing operating costs and improving reliability. Simon Raymond is Marketing and Sales Manager with Engine Services at the Volvo Aero Corporation, Trollhättan, Sweden, a maintenance provider for industrial gas turbines rated at up to 15 MW.

A new approach to financing - from mini-hydro projects to a portfolio approach to distributed generation opportunities

Sandeep Kohli Lower than average rainfall patterns recently mean that Sri Lanka can no longer rely on its hydroelectricity schemes for power supplies, not even the decentralized, mini-hydro schemes built recently. Moves are being made to find ways to expand financing models to include other distributed generation technologies such as CHP - as Sandeep Kohli reports. Sri Lanka, a tear-drop shaped island in the Indian Ocean, has been different things to different people - a tropical paradise, a spice island, a leading tea producer, and more recently, a place where renewable energy has built some serious inroads. The island nation has over 2500 MW of built capacity; half of it being large hydro units, while the other half consists of diesel-based generation. There is, however, another piece of this story: about 100 MW of mini-hydro capacity in operation, with an additional 100-150 MW under planning.

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Mini-hydro projects are especially vulnerable to fluctuations in rainfall and thus are viewed as high risk by financiers (Grid-Connected Small Hydro Power Producers Association) Most of this capacity is locally owned, and all of it has been financed through local banks in Sri Lankan Rupees (SLRs). Individual projects are 1-10 MW in size, though most of them are less than 5 MW. The typical debt-equity ratio is 70/30, and debt financing has a typical tenure of 7-8 years. In a country where most banks focus on trade financing, even five-year loans were a rarity before a World Bank-supported initiative - Renewable Energy for Rural Economic Development or RERED - made the mini-hydro sector possible. A key element to RERED was the recognition that long-term loans were needed for renewable energy projects to flourish and compete against lower capital cost fossil generation. The World Bank used a package of US$94 million to provide support to grid-connected mini-hydro, and small off-grid renewable projects (most are solar home PV and pico hydro) in Sri Lanka. The centrepiece of the plan was a 40-year, $86 million loan from the International Development Association (IDA) to the Sri Lankan government for the promotion of the renewables sector. This made it possible for the government to ‘on-lend’ funds to local banks for up to 13 years, who then lend the funds to projects exclusively in the renewables arena.

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Long-term financing is needed for renewable energy to get started and enable projects like this off-grid solar home PV system to be completed (Shell Solar) In conjunction with the IDA loan, the World Bank worked with the government on a series of policy initiatives that resulted in a standard power purchase agreement (PPA) for mini-hydro projects, as well as national targets for renewable energy. This has spurred local entrepreneurship, and developers signed and executed nearly 25 PPAs and projects. Several local banks now have significant expertise in lending to the sector, and the repayment record has been very good to date. LIMITATIONS OF MINI-HYDRO PROJECTS Sri Lanka continues to see an 8% annual growth in demand for electricity. The capacity utilization of large hydro units has been falling as a result of lower-than-average precipitation, increasing the island’s dependence on diesel generation. Small hydro projects also suffer from lower precipitation, and are therefore unable to diversify the risk to energy security as a result of increased global warming and greater uncertainty of monsoons. Furthermore, unlike the large hydro units, mini-hydro projects do not have significant water storage capabilities, and hence are even more prone to seasonal fluctuations. The seasonal and ‘interruptible’ nature of mini-hydro projects has been penalized heavily in the Sri Lankan tariff system. While large diesel-based independent power plants (IPPs) were paid the equivalent of over 15 US cents/kWh in 2004, mini-hydro projects received the equivalent of just under 6 US cents/kWh during the same period. All diesel IPPs in the country have fuel as a pass-through item, and therefore will see ever higher tariffs as fossil fuel prices escalate. Furthermore, while the diesel-fuelled IPPs receive a two-part tariff, mini-hydro projects have energy-only tariffs, and hence depend on dispatch for recovery of capital costs. The lower tariff for mini-hydro projects is partly due also to locational factors. Mini-hydro projects are located in the hilly regions of the island, away from major load centres, further reducing the value of the power generated. Thus, while the next generation of small hydro plants is planned, it is important to think more holistically and to address the limitations already outlined above. THE NEXT STEPS The Ceylon Electricity Board’s (CEB’s) 2004 Report shows that over 65% of the energy in that year was provided through diesel generation, even though large hydro is 50% of the built capacity. This points to an increasingly unsustainable future as fossil fuel prices continue to rise, and the potential for new hydro plants reaches a plateau. There is a greater need for energy diversity, and a more concerted effort to make clean distributed generation an even more significant part of the energy mix. Given the heavy reliance on diesel-based generation, there is a need to promote cleaner diesel technologies as well as combined heat and power (CHP) applications on the island, and to better integrate diverse generation resources into the grid in a manner that matches the load profile. The new generation resources should be closer to the load centres, and also integrate use of waste heat where possible. Large efficiency gains can be made possible by simply using waste heat in industrial processes, or in the case of a tropical island, finding ways to turn that heat into cooling. Biomass-based CHP units can add a potent new power generation source to Sri Lanka’s energy mix

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Biomass projects such as this CHP plant at a coconut shell charcoal manufacturing site can add significant efficiencies to Sri Lanka’s energy generation (Bio Energy Association of Sri Lanka) Sri Lanka is one of the world’s largest tea producers, and tea plantations need both heat and power. In addition, they also have residual biomass, as well as the possibility of growing energy crops. By developing efficient biomass-based CHP units, Sri Lanka can add a potent new generation source to its energy mix, while at the same time providing more firm power that better matches the load profile of the end-consumer. Another advantage of such plants is their proximity to the user, and hence the ability to avoid transmission over large distances. Municipal waste is another potential fuel source found mostly near large urban centres where most load requirements are. Both these cases tap into two key selling features of distributed generation: use of waste heat, and location close to load. Sri Lanka has significant untapped potential in the area of biomass utilization, and the policy debate is only now beginning to focus on the policy and tariff-related challenges that need to be addressed to promote biomass or wood-based generation (or ‘dendro’ generation, as it is called in Sri Lanka). It must be recognized, however, that one technology or fuel source cannot be the silver bullet. Over-reliance on woody biomass can lead to biomass supply constraints, and consequently a run-up on the price of the fuel for such projects. In order to avoid this, different technologies and fuel sources must be supported. Wind energy, for example, is a source of power that requires no fuel. In this instance, while there are risks in mapping and siting the plant, as well as with choice of equipment, one can come up with highly predictable costs for power that link into the capital costs and financing assumptions. This is an important characteristic, even though wind power comes with locational constraints and non-firm power characteristics. By focusing on smaller-sized wind technologies that operate at lower wind speeds and that can also be located close to end-consumers, it is possible - through technological innovation and operational experience - to convert wind power to something closer to firm power, produced close to the end-consumer. Here, too, we can see a lot of potential in Sri Lanka, provided the appropriate enabling environment is created. Sri Lankan policymakers have now decided to focus on technology-based tariffs in the area of renewable energy. This approach recognizes the different characteristics and economics of different renewable systems of power generation. However, there is still no linkage into the efficiency of such systems, or for that matter, incentives for promoting CHP-type applications. Nonetheless, these are welcome first steps in the evolution of a diverse portfolio of technologies that are more sustainable, and reduce overall risk to energy security. The Portfolio Approach to Distributed Generation Opportunities (PADGO) seeks to systematically promote a cleaner, more robust energy future through a ‘private sector-centric’ approach in Sri Lanka. PADGO OPPORTUNITIES … As pointed out earlier, in Sri Lanka there are significant opportunities as well as challenges in the clean energy arena. The PADGO initiative takes the first steps to move towards expanding the technology platform and building upon the existing experience in the mini-hydro sector. The objective of this initiative by the International Finance Corporation (IFC) is to stretch local capacities for the next crop of technologies and projects in a replicable and cost-effective manner. The island has substantial untapped biomass potential, as well as a tradition of well run plantations in tea and spices with well understood CHP needs. However, providing a reliable and affordable supply of biomass is key to the development of biomass-based projects. Sri Lanka appears to have the essential ingredients, but there is need for significant hand-holding and learning from best-practice and experiences elsewhere. PADGO seeks to bridge the information gap through seminars or workshops that will bring together technology providers, original equipment manufacturers (OEMs), local entrepreneurs, as well as experts in the field of biomass production. Through this initiative the IFC will also develop and disseminate information on general project economics, contracts, as well as the typical relationship between counterparties.

In the arena of wind energy, Sri Lanka has only one pilot project at Hambentota that has shown capacity utilization factors in the teens. Yet, across the straits, wind energy projects in India have been in bloom for over a decade. Significant wind potential exists along the island’s long coastline, as well as along the central hillsides. It is possible to turn potential into reality with the right mix of policies, incentives, and entrepreneurial risk-taking, and PADGO will attempt to do just that. … AND CHALLENGES The RERED initiative used some $83 million of concessional funds to promote total estimated projects worth $133.7 million in the mini-hydro sector. Going forward, the availability of such large sums of concessional funds is unlikely. Thus the financing of the next generation of (larger) mini-hydro projects, as well as the new wind and biomass projects will require greater risk-taking by local banks than has been the case in the past. Furthermore, in the mini-hydro sector, the average project cost was less than $1000 per kW installed, and an off-take price (purchasing price) of less than 6 US cents per kWh was mandated per the standard mini-hydro PPA. By contrast, most biomass projects will have capital costs that exceed $1500/kW installed, and will also have material fuel costs during operation. Hence a higher off-take price will be needed if such projects are to be financiable. Sri Lankan authorities are aware of this need, and seek to address this through the technology-based tariffs mentioned earlier. On the positive side these biomass projects will be more attractively economically than those using imported diesel. Similarly, the low plant utilization factor at the Hambentota site, coupled with the large backlog of orders for wind turbines, poses a special challenge in the arena of wind project development in Sri Lanka. The absence of reliable wind data, and a very shallow pool of experience with both biomass and wind development in the country, also make banks and financial institutions wary of financing the first few projects that use these technologies. SMALL POWER - IN NEED OF BIG THINKING The power sector is one of the most capital-intensive sectors, with most power plants costing upwards of $1000,000/MW installed. It should therefore be no surprise that for larger power plants with over $100 million in costs, project financing with leverage ratios of 70% are needed in order to provide equity-holders with reasonable returns at tariff levels that are economic. Figure 1 outlines risk levels, spend rates and the ultimate revenue stream as viewed in such a project finance context.

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Figure 1. Typical power project life cycle Revenues (shown in green) begin only after the plant has begun commercial operations, while the spend rate (shown in blue) has to be sustained over several years before the plant can be built and operated. The risk associated with funds spent (shown in orange) decreases as the plans to build the plant become more firm, and as contracts, permits, financing and construction progresses. It is important to note that the most risky funding occurs during the early development stages of the project when very little is firmly known about the project’s outcome. During this stage funds are used for market assessment, feasibility studies, early negotiations, and in some cases market awareness efforts. Typically, donor funds have been used to fund certain high-risk activities during the early development stages of smaller or more risky projects. This is called technical assistance (TA). Pre-feasibility studies, some training activities, as well as market studies fall into this category. Post financial close (when debt funding is obtained for the project), while the actual spend rate goes up exponentially, the risk associated with the funds spent is significantly lower as a result of firm off-take contracts, guarantees, as well as siting and permits. When this model is applied to smaller investment sizes such as small distributed generation units, one sees significant problems. For purposes of this article, small power projects (SPP) are those power projects that are an acceptable or good match for local entrepreneurial and financing capacities. In the Sri Lankan context, mini-hydro projects of less than 10 MW size fall within this umbrella. At the other end of the SPP spectrum are rooftop photovoltaic (PV) installations of a few watts each.

These diverse technologies have been locally financed, constructed and maintained. As Figure 2 shows, SPPs cannot sustain the high transaction costs of typical project finance, are perceived to be higher risk and hence require a larger proportion of equity, and also fail to interest large international banks since the volume of financing is small per project.

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Figure 2. Small power project through project finance lens Even the larger mini-hydro plants in this category need the equivalent of about $10 million of financing per project, while a small PV installation may cost less than $500. As against this, large central generating plants may need several hundred million dollars in both local and hard currencies for each project. The latter can, therefore, afford the customized project finance approach which can have associated legal and development costs of several million dollars per project. The same is not a feasible option for SPPs. PADGO recognizes that in order to get to a comparable volume of generating capacity as one large central generation unit, several SPP transactions must occur. As an example, in Sri Lanka, there are some 25 minihydro financings to arrive at a cumulative generation of about 100 MW. If the same were to be done using 2 MW biomass units, 50 financings would have to occur; and for 100 W PV installations, the equivalent number is a million. From this example it is clear that for a diverse set of SPPs to rapidly penetrate the market, one must increase the volume of transactions exponentially, while reducing costs in dollars and time spent dramatically. TRANSACTION VOLUME AND WHITE GOODS When one looks at the experience to date with large volume financing, we can see parallels in white goods (high-end electronics, cars, large kitchen appliances) and even home financings. In all these cases a securitization approach is used to produce standard lending contracts and credit checks, as well as a possible lien on the equipment. In many cases, there is also the sale of warranties bundled together with the financing package. For power plants, such an approach has not been tried to date, and presents some challenges. One key challenge is the linkage to performance by multiple parties such as developer, lender, EPC contractor, plant operator, power off-taker, fuel supplier etc. The typical IPP covers these risks under a project finance structure using multiple customized contracts such as the power purchase agreement (PPA), fuel supply agreement (FSA), and so on. This is not going to be possible for SPPs, if we are to lower transaction costs and build volume rapidly. PADGO CONTRACT STANDARDIZATION The PADGO approach seeks to develop a system of standard templates and contracts that can incorporate a mix of the project finance approach which focuses on performance of multiple stakeholders, and elements of the securitization approach that allows for parsing and aggregation of distinct risks and assets. The PADGO Sri Lanka pilot is designed to take the first steps in the direction of lowering transaction costs and developing enough experience with transactions to build larger volumes that are needed to move towards securitization. It must be made clear that we do not expect to reach the securitization goal during the pilot phase in Sri Lanka; never-the-less, this remains the ultimate goal. The PADGO approach, by inherent logic, requires innovative thinking and planning by practitioners with experience in both project finance and securitizations. Knowledge about the functioning of a power project from inception through operations is needed from a risks perspective. PADGO proposes to work closely with banks, developers, and governmental agencies in Sri Lanka to help promote new projects in mini-hydro, biomass, and wind based power generation. It will seek to: 

lower transaction costs of new financings through standardization of contracts

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provide financial instruments and multiple funding sources that match the needs of local banks for financing the next generation of clean distributed generation projects

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provide funds for training and technical assistance to help banks get more comfortable with the technology risks in the biomass and wind energy sector

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foster partnerships between local and global players based on their expertise and commitment to clean and reliable generation

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induce banks and developers to take increasing exposure to the next generation of technologies by ratcheting down concessional funding and risk sharing instruments over time.

As a result of these interventions, our belief is that over the next decade a more diverse and robust portfolio of clean energy projects will develop in Sri Lanka. This will provide the country with greater energy security, and will support local entrepreneurs and use local lending capacity in a sustainable manner. The development of standardized contracts and instruments will have applicability beyond Sri Lanka. The PADGO approach is being designed to be replicable for new technologies as well as new geographies. We see particular applicability in countries of Southeast Asia, where the right resources and enabling regulatory environment is available. Over time, the database of applicable technologies and practices will increase and evolve towards cleaner and more sustainable technologies, and local banks and developers will be able to undertake such projects without large sums of concessional financing. This then, would be the true measure of sustainability. Sandeep Kohli is with the International Finance Corporation, Washington, DC, US. e-mail: [email protected] PADGO and CHP PADGO will also include clean/efficient fossil-based technologies as needed. This is a departure from previous initiatives that focussed exclusively on renewables. It should also be noted that most small fossilbased generation is financed as part of larger corporate loans rather than through project finance. Hence such generation does not show up as an explicit item of financing. This makes it very difficult to track the full extent of the use of small fossil based generation for back-up or baseload applications. For all these reasons, local banks may not be thinking along lines that include efficient fossil based generation as a distributed generation technology for financing. PADGO, as structured, can include fossil projects, so long as they are efficient, which means that CHP-type applications are very welcome. In this manner, PADGO is seeking to bring out into the market, clean and efficient fossil based alternatives for those who may currently be forced to use cheaper but less benign fossil options for their captive needs. There is now an increasing awareness of CHP applications, and given the high price of fuel and the widespread use of back-up generators, we believe that this is the right time to promote the next generation of cleaner fossil technologies with CHP-type modes of operation. The PADGO financing model would be equally applicable to CHP using fossil fuel as it would the other technologies.

Funding for development: DE project finance in developing countries Decentralized energy projects in developing countries present their own unique financing challenges, some flowing from unfavourable national energy policies and the lack of suitable business models. Here, Sandeep Tandon describes project financing experience of USAID to support bagasse-fuelled cogeneration, and discusses opportunities for rural energy projects in developing countries. Two developments in recent years have started exerting a pincer-like grip on the global economy: first, the broad recognition of climate change as a growing threat to all countries, and second, the surge in demand for fossil fuels among strong as well as growing economies. The former has compelled countries to develop action plans to mitigate the effects of climate change by reducing the emission of greenhouse gases. The latter has given rise to increases in the prices of fossil fuels (both oil and gas) due to a widening gap between supply and demand, especially in growing economies.

Support from banks is critical to getting projects

started. This remains a principal challenge for developing countries The situation is further complicated by the need to secure long-term supplies of energy resources to sustain national economies and their growth rates. These two factors could well be the change agents that determine how future generations will utilize energy. Energy planners are now forced to ‘think out of the box’ and reconcile with fast-changing realities to develop meaningful long-term energy roadmaps. These trends seem to augur well for decentralized energy (DE) technologies such as: •

decentralized generation of power from waste heat or waste gases produced from industrial processes

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high-efficiency cogeneration or combined heat and power (CHP)

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distributed generation using renewable resources for local consumption of electricity.

Since DE technologies can make use of either the energy that is presently wasted in the form of heat or renewable energy for electricity production, they are therefore less susceptible to external factors such as oil price fluctuations or the anticipated stringent regulations in response to climate change concerns. DE technology projects, based on resource availability and located near the points of energy consumption, are emerging as the favourites to meet the captive energy demand in many countries across the world. The advances in technology options for electricity production made during the last few decades are now benefiting the power industry and households in rural areas. Crossing the technology barrier Advances in technology as well as unforeseen factors in the past few decades are now exerting pressure for yet another shift in the pattern of energy supply and consumption which hopefully can provide an optimal solution for the coming decades. Industries that are the biggest consumers of energy have started looking at options of generating electricity locally to meet their needs, due to economic or environmental compulsions. In such cases, the availability of appropriate CHP technologies and their integration to the industrial process both play a crucial role. Traditionally, industries have been the main users of DE technologies primarily to help improve their bottom line. Industry has invested in DE projects of various sizes, irrespective of the process. Captive power units running on fossil fuel are preferred as they provide complete flexibility in terms of matching energy needs, meeting future growth requirements, and offering the quality and reliability of electricity which are much sought after in many developing countries where industries are starting to compete globally. There are several examples worldwide that support the above point. One set of examples are the cogeneration projects in Indian sugar mills which added a whole new chapter in technology and promoted unique business models in the renewable energy sector, as well as the sugar industry. In these projects, sugar cane waste or bagasse is used to generate electricity to meet the energy needs of the sugar mills, with excess power supplied to the grid. These are the conventional technologies of power generation where, instead of a fossil fuel, crushed sugar cane waste is burned in a boiler to produce steam at high pressure (66 kg/cm2), and is then passed through a condensing-extraction steam turbine to generate electricity. Depending on whether the sugar mill is operational or not, the steam turbine is run in extracting mode or condensing mode. The box above elaborates the process and the spectrum of benefits. The success of bagasse cogeneration came not only from the proven technology, but also from a sound business model in which the sugar mills had access to a steady revenue stream from the sale of electricity to the utility. This income helped sugar mills to overcome inherent fluctuations in the sugar market (which had an effect on the price of sugar and the mill’s bottom line) so much so that some sugar mills considered themselves to be in the business of producing electricity in which sugar was a by-product. Another Indian example of industrial cogeneration application is a large copper smelter business located in southern India. The business owner(s) made investments in a waste heat recovery system that captures heat from various process streams to generate electricity to meet its own requirements and reduce the burden of using fossil fuel. In this case, the management reviewed the overall plant process and identified various streams where energy was being lost in the form of heat. Electricity generation using waste heat helped the company achieve energy independence by going off-grid. This smart decision by the management has helped to meet the plant’s own energy demand and reduce energy costs, thus allowing them to market their product at very competitive rates.

A copper smelter plant in Tamil Nadu, India, achieved energy independence by investing in a waste heat recovery system, enabling it to go offgrid Notwithstanding the commercial benefits of CHP derived by industries, as the technical and economic feasibility of CHP projects become more attractive, non-traditional areas have started gaining ground, such as municipal waste-to-energy and biomass gasification-based village power. Today, municipalities, government-owned industries and non-governmental organizations (NGOs) are seriously pursuing such projects. This is particularly so as the sale of carbon is becoming a reality and considerably improving the economic feasibility of such projects. These are some of the examples of the growing list of diverse organizations and projects that have started taking advantage of distributed generation technologies, either to improve the conditions of their businesses or simply to improve the quality of life by providing energy in the form of electricity and heat to end-users. Challenges to financing DE projects One would think that after such glaring successes and compelling rationale, there would be a snowball effect leading to proliferation of DE systems across the world. However, challenges remain, such as unfavourable government policies towards DE or the administered prices of fossil fuel or electricity, both of which favour conventional energy models of centralized power generation. An even more challenging puzzle is that of developing a viable business model around some of the DE technologies especially in the rural areas; this is due to the lack of a single ownership and collaterals which, in addition to the lack of a steady revenue stream, makes it difficult to finance a project. As noted before, there are two principal users of DE sources the industry and business establishments, and retail users who do not have access to grid electricity. In the case of industries, implementing a CHP project is dealt with in a rather straightforward manner once the compatibility with process (i.e., whether the process leads to waste energy generation that can be captured for useful purposes, such as meeting the electricity requirement) is determined. The next logical step then is to determine the economics for additional investment for capturing and utilizing the energy. Often, the economics and paybacks are developed using business-as-usual scenarios, which show the additional investment being recovered from the savings generated. In such cases, the attractiveness of the project depends upon the quantity of energy saved which, in turn, depends upon whether the industry uses electricity or fossil fuel to meet its energy requirements. Justifying the need to capture waste energy using conventional methods of cost-benefit analysis and simple payback is only a starting point. If industry uses primary energy sources such as coal and oil to meet its needs, it can then get a more realistic picture of the attractiveness of CHP technologies by factoring in the fluctuations and volatilities of fossil fuel prices, plausible future price increases, and other corresponding benefits that would accrue over the life of the project. This therefore requires having some historical information on fuel prices from which to extrapolate different trends and scenarios. The situation is somewhat different if the technology changeover involves switching to fuels such as locally available biomass. The future price fluctuation of biomass depends solely on the demand/supply equation based on its availability every season. Predicting variation in biomass availability in the future could require applying standard statistical analysis similar to the one used in the agriculture sector. Such sound analysis has a far better chance of gaining the approval of management and financial institutions, even if the additional revenue stream from carbon offset is not taken into account. A company’s financial situation, along with the sector performance and market outlook, attracts financial institutions and helps banks to make lending decisions. Small- and medium-size industries such as textile, paper, chemicals and even pharmaceuticals (which uses process steam and power) are quickly switching over to biomassbased cogeneration as the increase in fossil fuel prices is making CHP more attractive. A sound CHP project idea should be able to stand on its feet to be acceptable to banks, but the price benefit offered by carbon offset in the recent years are found to greatly improve the internal rate of return of the overall project and improves the prospects of receiving funding by local banks.

Financing decentralized rural electrification projects There is a far greater challenge in justifying DE projects in developing countries, particularly in rural settings to provide electricity to meet the basic needs of village dwellers that do not have access to grid electricity. Here, the challenge is to work out the economic viability of the projects, which is often more important than the limited choice of site-specific technologies. Limited rural income generally can only cover operating costs and some equity, leaving the majority of the initial capital expenditures to be supported in the form of grants from local government or development agencies. The starting point still remains the assessment of a suitable technology option which can be managed by the local community. This means that both business and technical capacities of the local community must be built to operate and maintain the energy system. Unfortunately, for such applications in remote locations, the most suitable of all technologies (solar photovoltaic or SPV) turns out to be the most expensive and is therefore a less desirable option. Small diesel-generator sets, which are much cheaper, offer electricity albeit at high cost to end-users. Currently, a biomass gasification system coupled with a gas engine is emerging as another attractive option and stands in between the other two technologies. This technology uses methane-rich gas produced from biomass gasification (not combustion) which, after clean-up, is fired in a conventional compression ignition dual-fuel engine. An alternator linked to the engine produces electricity. In rural village settings, there are three major problems for DE technology application: •

The issue of capital versus the running cost. As noted above, SPV has a very high capital cost but a low operating cost, while diesel generator sets have a low capital cost but high running costs. If the technology selection is made based on capital cost, SPV will lose out, despite the fact that the higher cost of per unit of electricity is due to high combined capital, running, and maintenance costs of diesel generator systems.

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The issue of sizing of DE systems. DE systems are often sized to meet the lighting needs of the local people with very little spare capacity to meet any other additional demand of electricity. For a project to run successfully, the capacity calculations should take into account load growth over a five-year period, as the factors that can trigger sudden increase in demand of electricity are unpredictable. During the initial years when demand remains low, an alternative is to increase the generating capacity in a phased manner.

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The issue of financing DE systems. Clearly this issue is closely related to the previous two issues, and therefore it is imperative that the first two issues are carefully resolved. If the finances are made available in a phased manner to meet growing demand, the chances of rural DE project becoming successful and self-sustaining will greatly increase.

Governments are slowly coming forward with creative ways to support DE. However, the gap between government subsidies and the true cost of a project can at times be too wide to be bridged by local users. Special-purpose models are being created to clearly delineate the responsibility of the local community in terms of ownership of assets through shareholding, operation and maintenance, and payment mechanisms. These models still need to be standardized, improved upon and tested across several different locations before they can be widely applied. A number of technologies are nearing maturity and stability, but the business models are still being refined. A few critical elements that should spur the development of such projects include governments taking a share in the project, the involvement of private sector equipment providers, NGOs interfacing with the village communities, and lending by local banks. Some of these elements have been time-tested in DE projects in remote regions in India. The majority of these projects have used SPV technology, while a handful in recent years have used biomass gasification. Led by the local government agency, several DE projects of 50, 100 and 150 kW sizes were trialled and tested over a period of seven years, and two technologies are functioning successfully. With the help of local entrepreneurship, the lives of more than several thousand villagers have now been greatly improved by obtaining access to electricity. Banks have a major role to play in DE projects, both in terms of increasing the geographic coverage and in getting projects off the ground. So far, DE in villages has failed to enthuse banks for the reasons cited above. Banks and other financial institutions are guided predominantly by their business interests and prefer to lend to those industries where they see a secure and steady revenue stream needed to service a loan. In successful DE projects, a steady revenue stream may not be generated until after a period of about three years. Few lenders have the patience to wait this length of time. Banks and financial institutions have their annual disbursement targets to projects, which are achieved by financing large-size projects where the transaction value or the loan amount involved is high. Thus small-size projects never come onto their radar screens. Consequently very few banks think about supporting DE projects. The handful of those that do continue to remain extra-cautious in their approach.

A 24 MW sugar cogen plant in Karnataka, India, supported by the USAID’s Bagasse Cogeneration initiative The financing of village DE projects is in its early stages and is still evolving as the situation of energy needs, suitability of technology, and willingness to take ownership of energy systems all vary from one place to another. It is at a stage where it needs government attention and perhaps - in the case of developing countries - support from bilateral and/or multilateral agencies, through equity participation rather than providing capital subsidy which causes distortions in the market. In the bagasse cogeneration projects, USAID’s contribution was below 10% of the overall project cost, but with equal emphasis on training for the sugar industry and banks, the concept has today spread throughout the country and is working without any additional financial support from the development agency or the government. As DE projects in rural areas rarely offer returns attractive enough for banks to seek engagement, banks are still cautious in their approach and their commitment remains to be seen. The involvement of banks can be facilitated by bundling several such projects, which helps to reduce transaction costs especially for those banks already working in the rural sectors and can relatively easily include a portfolio to finance DE projects. The presence of DE in rural areas can strengthen agricultural activities and improve the incomes of the enduser - a viable win-win scenario. Therefore the bottom line remains that local banks and financial institutions must be in the forefront and where ever required, and their capacity should be developed so that they can in turn build the capacity of local people, creating opportunities for local franchises to increase the up-take of DE projects. Conclusion The Indian examples illustrate the fact that the opportunities for DE projects are present across the industrial and commercial sectors in varying degrees in all developing countries. External compulsions are now forcing government and end-users alike to exploit the latent energy in their backyards. Having recognized the limitations of centralized energy supply systems, governments should come up with policies favouring DE. Governments should further encourage end-users to identify and develop resources and feedstock for their respective DE projects. They should also encourage local financial institutions to support such projects, especially for the retail end-users by helping to minimize the risk involved in such projects through equity partnership. Given the significant advantages which DE offers, particularly in minimizing the waste of energy in the form of heat and avoiding transmission and distribution losses, it is in the best interest of governments and industries - the two major stakeholders - to make use of DE systems to meet their respective goals now, or face the peril of losing out to their competitors. A shift toward DE today is a leap forward, yet it is also a return to the old way that generations before us met their energy needs on-site. The difference though lies in the fact that the present change is based on an informed decision and utilizes diverse energy sources. Today, the technology choices of energy production and utilization are far superior and more efficient than they were a century or even a few decades ago. Not surprisingly, the sustenance and growth of an economy will strongly hinge upon the extent of use of DE in the future, with centralized energy systems serving as the backbone. Ultimately, the overall shift to DE will greatly depend upon the end-use efficiency of energy. In spite of these uncertainties and limitations, the future growth trend of DE is optimistic since it offers the right mix of technical and economic solutions to meet growing energy needs at the grass-root levels while addressing global climate change. Sandeep Tandon is an Energy Specialist with the US Agency for International Development’s India Mission, New Delhi, India. E-mail: [email protected] The author’s views expressed in this article do not necessarily reflect the views of the US Agency for International Development or the US Government. To comment on this article or to see related features from our archive, go to www.cospp.com and click the ‘Forum’ tab. The Alternative Bagasse Cogeneration programme

To encourage increased and efficient use of biomass and sugar cane waste (bagasse) at sugar mills, USAID/India launched the Alternative Bagasse Cogeneration programme in 1995. Support was provided in the form of grants and technical assistance to nine private sugar mills that came forward to invest in cogeneration. USAID engaged the US Department of Energy’s National Energy Technology Laboratory to provide technical assistance, supervision, training and performance evaluation, and the Industrial Development Bank of India to manage the project’s investment-related activities. USAID offered a conditional grant of US$40,000 per MW to the private sugar mills for installing and operating high-efficiency biomass cogeneration. The size of cogeneration plants ranged from 12 MW to 24 MW. USAID’s commitment helped nine private sugar mills to achieve financial closure with the banks at commercial terms. The partners worked together not only to overcome difficulties in project implementation and signing power purchase agreements with local utilities, but also in setting a precedent by demonstrating high-efficiency 270day-per-year cogeneration using sugar cane waste and other biomass fuels. Aggregate capacity of 195 MW was added as a result of this effort and the units are feeding power into the grid to this day. More capacity addition is taking place on purely commercial terms throughout India. Since the ending of USAID assistance, a total of 400 MW of capacity has been added in the sugar sector. Benefits for sustainable development Because both steam and power are utilized locally in the sugar mill, the thermal efficiency of cogeneration is significantly higher than that of centralized fossil fuel-based power plants. Such cogeneration qualifies as a DE application project as it has a small capacity, which provides uninterrupted power to nearby rural areas, thereby minimizing transmission and distribution losses. Due to the improved reliability and quality of supply, farmers and other end-use customers in villages also benefit greatly as cogeneration supports employment and provide regular income to local farmers and labourers. USAID’s equity contribution leveraged 20 times more from local banks and project developers to meet the project cost. Active participation of a number of local banks by lending to these projects helped in building their capacity to understand the bagasse cogeneration business. The presence of engineering firms, equipment suppliers and banks also helped in ensuring continuity of the concept after USAID support ended. Biomass cogeneration projects using renewable fuels are environmentally friendly and carbon-neutral, in contrast to coal-fired power generation which is a source of high levels of particulates such as sulphur, nitrous oxides and other greenhouse gases. It is estimated that these nine projects have helped to avoid more than four million tonnes of carbon dioxide (CO2) emissions in India.

Garbage in, energy out - landfill gas opportunities for CHP projects Brian Guzzone Mark Schlagenhauf Landfill gas-to-cogeneration projects present a win-win-win situation. Emissions of a particularly damaging pollutant are avoided, electricity is generated from a ‘free’ fuel, and heat is available for use locally. Brian Guzzone and Mark Schlagenhauf describe activity in the US and efforts to export the technology overseas. Methane is a primary constituent of landfill gas (LFG) and a potent greenhouse gas when released into the atmosphere. Each day, millions of tonnes of municipal solid waste are disposed of in sanitary landfills and dump sites around the world. Globally, landfills are the third largest anthropogenic emission source, accounting for about 13% of methane emissions, or over 818 million tonnes of carbon dioxide equivalent (MMTCO2e). Figure 1 identifies some of the countries with significant methane emissions from landfills. Globally, the predominant practice for solid-waste management is depositing solid wastes from households and commercial and industrial activities into a landfill, where methanogenic bacteria decompose the organic material. A product of the bacterial decomposition is landfill gas, which is composed of methane and carbon dioxide in approximately equal concentrations.

Landfill gas capture and control

Figure 1. World landfill methane emissions (MMTCO2e) in 2000

LFG contains approximately 50% methane and has a heat content of about half the value of natural gas 500 British Thermal Units per standard cubic foot (18,662 kJ/m3) compared with 1000 Btu/scf. LFG is also generated 24 hours per day, seven days a week. A common method of controlling methane emissions from landfills is to install a gas collection system in the landfill to collect and convey the methane to a gas control system. Figure 2 depicts a landfill with a gas collection and control system. Landfill gas is extracted from landfills using a series of wells and a blower (or vacuum) system. This system directs the collected gas to a central point where it can be processed and treated depending on the ultimate use for it.

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Figure 2. A landfill with a gas collection and control system From this point, the gas can be destroyed by a flare or can be used to generate electricity, replace fossil fuels in industrial and manufacturing operations, fuel greenhouse operations or be upgraded to pipeline-quality gas. As a rule of thumb, about 11,600 m3 per day of LFG is produced from every 1 million tonnes of MSW placed in a landfill, which can produce about 0.8 MW of electricity. Moreover, landfill gas energy (LFGE) projects have on-line reliability of over 90%. Reducing emissions by capturing LFG and using it as an energy source can yield significant energy, and economic and environmental benefits. Moreover, the implementation of LFGE projects reduces greenhouse gases and air pollutants while contributing to energy independence and economic benefits. Internationally, significant opportunities exist for expanding LFGE and an increasing number of conventional and emerging technology applications are becoming commercially viable to target this untapped market. LFG is currently extracted at over 1200 landfills worldwide for a variety of energy purposes, such as: •

generation of electricity with engines, turbines, microturbines and other emerging technologies

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processing the LFG to make it available as an alternative fuel to local industrial or commercial customers

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creating pipeline-quality gas or an alternative fuel for vehicles.

Types of LFG utilization projects Figure 3 shows the types of landfill gas projects that have been implemented at landfills in the past few years, both in the United States and globally. The projects that produce a beneficial product such as electricity or process heat from landfill gas should be viewed as achieving two aims: reducing methane emissions from the landfill and using renewable energy to offset greenhouse gas emissions from fossil fuel combustion.

Figure 3. Types of LFG projects implemented recently worldwide When landfill gas is used in CHP systems, the environmental and economic benefits increase dramatically. A CHP project powered by LFG not only provides significantly better energy efficiency and cost savings, it also achieves the significant environmental benefits of using a locally produced biomass fuel. Developing LFG CHP projects CHP is a proven, highly efficient alternative to separate power and heat production. CHP LFGE projects will produce electricity as well as shaft power, hot water, steam, chilled water or dehumidification. Combined with LFG, CHP projects cogenerate electricity and thermal energy, usually by using waste engine heat to produce steam or hot water. LFG cogeneration projects that use turbine or spark ignited (SI) reciprocating engine generators have been installed at industrial operations. The efficiency gains of capturing the thermal energy in addition to generating electricity can make CHP LFGE projects particularly attractive. The US Environmental Protection Agency (EPA) implements several voluntary partnership programmes, including the Landfill Methane Outreach Program (LMOP) and the CHP Partnership to reduce the environmental impact of power generation. In the past six years, the CHP Partnership has helped CHP Partners put more than 250 projects into operation in the US. These CHP Partnership-assisted projects contribute more than 3570 MW of electricity-generating capacity. The LMOP Database shows that there are 16 CHP LFGE projects currently operating in the United States, and they range in size from 120 kW to 12 MW. Some 60% of the existing CHP LFGE projects use SI engines. These projects are located in nine states and have a combined capacity of 55 MW. In addition, three of the 25 LFGE projects under construction in 2007 are CHP. CHP LFGE projects can create additional environmental benefits by offsetting demand for fossil-fuel-based electricity and steam or heating with a renewable fuel. In 2007, the existing CHP projects fueled by LFG in the US will result in greenhouse gas reductions equivalent to preventing the use of approximately 1.3 million barrels of oil. Also, using the waste heat from LFG-fired generators in a CHP configuration can improve a project’s financial results by as much as 100%, increasing the feasibility of developing LFGE projects. Projects that reclaim heat from engine generators that are fueled by LFG provide the typical benefits of CHP projects. Fuel-use efficiency is improved, emissions are reduced and fuel and operating costs decrease. CHP can provide industrial and commercial facilities with greater reliability and increased process flexibility compared with conventional generation methods. Because cogeneration technology is proven, CHP projects represent low technology risk. Turbines and SI engines using LFG have heat conversion efficiencies similar to that of small natural gas generators and are approximately 28%-33% efficient. In comparison, SI engines with CHP systems have been found to have an effective (overall) energy efficiency of 69%-84%. To evaluate the financial benefit of LFG-fuelled CHP projects compared with standard electricity generation projects, LMOP applied its preliminary feasibility tool, the Landfill Gas Energy Cost Model (LFGcost) to two LFGE projects - straight electricity generation with a standard 3 MW SI engine and a CHP project based on a similar engine generator. LFGcost estimates costs based on typical project designs and for typical landfill situations. The model attempts to include all equipment, site work, permits, operating activities and maintenance that would normally be required for constructing and operating the project. LMOP default input parameters were used in this comparison to model project development by a private entity (in other words, industrial end-user or a third-party developer) which would finance 80% of the project capital costs at an 8% interest rate over 10 years. The initial-year product prices listed in Table 1 reflect the current LFGcost model default prices for electricity, LFG production and waste heat. They are also escalated annually at a rate of 2%.

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The LFGcost comparison assumed a 6.4 km pipeline between the landfill and thermal host. In addition, the waste heat application was assumed to be 160 metres from the engine. It also assumed that both projects operate year-round. LMOP also compared the environmental benefit of displacing conventional electricity generation and, for the CHP project, the additional displacement of a thermal energy demand fired by natural gas. As shown in Table 1, CHP LFGE project financials can be as much as 100% better than a traditional engine generator project using LFG. These LFGcost analyses are preliminary estimates and should be used for general guidance only. Projects for specific landfills require unique design modifications and may add to the cost predicted by LFGcost. A detailed final feasibility assessment should be conducted by a qualified LFG professional prior to preparing a system design, initiating construction, purchasing materials or entering into agreements to provide or purchase energy from an LFGE project. Using the heat and power output Potential LFG users may not have considered the benefits of LFGE for several reasons. First, it is not a common fuel. The end user may be concerned about its reliability or may believe their process requires commercial fuels and energy systems. Users must also determine how their energy demand corresponds with the relatively stable LFG production rate from a nearby landfill. If an industry’s energy demand is seasonal, CHP applications provide an opportunity to balance LFG use between electricity and other energy demands. Natural gas can be blended with LFG or other auxiliary fuels to add energy if necessary during peak periods. Operating risk can be minimized through power purchase agreements (PPAs) that tie LFG costs to the price of the commercial gas supply. Financing can pose a barrier to LFGE projects due to high upfront capital costs or competition with low electricity prices in some markets. The collection system, pipeline and project investment can be significant for a landfill that has not yet developed a gas management system. But an end user interested in green power can offset some of the financial risk with long-term agreements that provide steady future revenue for the landfill and continuing energy cost savings for the user. Another potential source of funding for CHP LFGE projects is through the sale of carbon credits on a carbon market. These credits are generated as a direct result of the collection and destruction of methane and as offsets from using a renewable energy source to generate electricity. The Lancaster County Solid Waste Management Authority (USA) in Pennsylvania, mentioned in the case study above, has sold some of the carbon credits from its CHP LFGE project on the Chicago Climate Exchange (CCX). CCX is a voluntary, but legally binding, greenhouse gas reduction and trading programme in North America which verifies the CO2e reductions from renewable projects and creates so-called carbon financial instruments that can be sold to other CCX members. Project development challenges One important issue for project development in many developing countries is that open dumps and unmanaged landfills are the predominant disposal options. These sites can be less than optimal candidates for LFG energy development and, to CHP projects especially, can be a challenge because they produce small amounts of methane (resulting from aerobic degradation and rapid waste decomposition). Also, the industries that would benefit from CHP may be limited. On-site CHP LFG is limited due to low demand for hot water or steam at a landfill. However, many developing countries are transitioning to engineered landfills from more uncontrolled systems. Landfills will provide a more environmentally sound disposal option for these countries, but they will also produce more methane. The Methane to Markets Partnership can help facilitate a transition to landfilling by sharing information on effective landfill design and management, and how to integrate landfill methane capture and beneficial use into these planning processes. Another important issue for the viability of LFGE projects in both developing and developed countries is energy price structure. Government policies on energy and solid waste management can promote or hinder the beneficial use of LFG. An uncertain regulatory environment is often a concern among potential investors. For example, project developers can be subject to different and sometimes conflicting laws at the local, regional and national levels. Moreover, a lack of regulations governing landfills and LFGE projects in some countries (in other words, there being no requirement or incentive to collect and combust LFG) can inhibit project development.

As countries begin to implement laws, regulations and policies to improve solid waste management practices, promote alternative energy and address greenhouse gas emissions, the economic viability of traditional LFGE and LFG CHP projects will improve. Moreover, creating an atmosphere where potential investors (private sector investors, international development banks and financiers) are secure in the technical and policy framework that supports LFGE projects will be essential to project development. The Methane to Markets Partnership brings together the collective resources and expertise of the international community to address technical and policy issues and facilitate LFGE projects. Early initiatives will likely include: •

assisting with solid waste management capacity building

•

identifying potential landfill resources

•

performing initial gas generation and feasibility studies, including CHP applications.

Conclusion LFGE projects, especially CHP projects, are becoming even better prospects in today’s escalating energy market, which is acquiring a taste for local renewable power. LMOP and Methane to Markets are providing support for the development of these projects, which produce more environmental benefits than a typical LFGE electricity project and make more efficient use of the renewable LFG resource. Today, only a few LFGE projects benefit from CHP design. However, LMOP and Methane to Markets are working with more and more municipalities and businesses that are installing CHP LFGE projects in their facilities to cut energy costs and reduce greenhouse gas emissions. LFGE projects using CHP technology are win-win-win opportunities. They represent renewable energy achievements that result in higher efficiency, environmental gains and an improved bottom line. Brian Guzzone is Team Leader at the Landfill Methane Outreach Program at the US Environmental Protection Agency, Washington, DC, US. e-mail: [email protected] Mark Schlagenhauf is the Global Oil and Gas Advisor at the Economic Growth, Agriculture, and Trade Bureau of the US Agency for International Development, Washington, DC, US. e-mail: [email protected] The Methane to Markets Partnership centres on identifying landfill sites for methane recovery and on promoting cost-effective electricity generation or direct use of the resource. Efforts include the identification of barriers to project development, the improvement of enabling legal, regulatory and institutional conditions, and the creation of efficient energy markets. The active involvement by private sector entities, financial institutions and other non-governmental organizations is considered essential to build capacity, transfer technology and promote private investment that will ensure the Partnership’s success. The EPA Landfill Methane Outreach Program (LMOP) is a voluntary assistance programme that helps to reduce methane emissions from landfills by encouraging the recovery and use of landfill gas as an energy resource. LMOP forms partnerships with communities, landfill owners, utilities, power marketers, states, project developers, tribes and non-profit organizations to overcome barriers to project development by helping them assess project feasibility, find financing and market the benefits of project development to the community. EPA launched LMOP to encourage productive use of this resource as part of the United States’ commitment to reduce greenhouse gas emissions under the United Nations Framework Convention on Climate Change. The LMOP website (www.epa.gov/lmop) contains a variety of tools and services to assist stakeholders in evaluating project potential, technical documents, case studies and funding opportunities. This article is on-line: www.cospp.com CHP LFGE case studies Modern Landfill Inc, New York The LFG-fired cogeneration facility at Modern Landfill in New York provides 100% of the electrical and heating requirements for H2Gro Hydroponic Greenhouses, with excess electricity sold to the grid. Innovative Energy Systems started the initial phase of this CHP LFGE project in 2001, when it designed and installed a 5.6 MW project to power and heat a 2024 m2 greenhouse test plot. In its first year, the project yielded 82,000 kg of tomatoes. After a successful test plot, this greenhouse was expanded to 30,352 m2 and 12 MW of generating capacity. Today, this H2Gro facility produces over 1600 tonnes of tomatoes per year. Innovative Energy Systems has received multiple awards for the project, which provides the community with employment and a new yearround exportable crop. Creswell and Frey Farm Landfills, Pennsylvania

Lancaster County Solid Waste Management Authority, PPL Corporation and Turkey Hill Dairy formed a unique partnership to achieve a CHP LFGE project using gas from two landfills in Lancaster County, Pennsylvania. The LFG is sold to PPL Energy Services, which operates two Caterpillar 3520 engines to produce 3.2 MW of electricity. The engine heat is captured to generate steam, which is sold to the nearby Turkey Hill Dairy through a closed-loop steam pipeline.

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Two Caterpillar 3520 engines fuelled by landfill gas generate 3.2 MW of electricity. Boilers capture heat from the engines, generating steam that is The dairy has met 80% of its steam demands using LFG. It also offsets the use of 855,000 litres of diesel fuel per year. Brazil, Mexico and India landfills The US Agency for International Development (USAID) and the EPA are working together in these three Methane to Market Partner countries to support landfill projects. The impacts on and the re-employment of families who make their living scavenging the sites have been identified as key factors for international landfill projects. Brazil’s Fortaleza region together with the United Nations Development Programme has completed a technical analysis on a landfill site and has identified and mitigated social impacts. In India, two projects are proposed, including a $7 million landfill as part of the West Bengal solid waste project. In Mexico, USAID and the EPA have been carrying out technical analyses on several sites near the US border together with Semarnat, the Mexican environmental regulator

Wade in Action The World Alliance for Decentralized Energy (WADE) was established in 1997 as a non-profit research and promotion organization whose mission is to accelerate the worldwide development of high efficiency cogeneration (CHP) and decentralized renewable energy systems that deliver substantial economic and environmental benefits. WADE co-hosts ‘Renewable energy’s role in global security’ event Side event at WIREC Conference explores security benefits of DE Washington DC, USA • In conjunction with the recent Washington International Renewable Energy Conference (WIREC), WADE co-hosted a side event entitled: Renewable energy’s role in global security. The event highlighted the role renewable energy can play in enhancing global security. Speakers discussed how renewable and decentralized energy can contribute to global security; change the current geopolitics of energy; alleviate global poverty and contribute to sustainable growth of developing nations. Efforts within the US Department of Defense to deploy renewable energy technologies were also discussed. The panelists included: Hon. James Woolsey, Former Director of the US Central Intelligence Agency; Vice Admiral Dennis McGinn, US Navy; David Sweet, World Alliance for Decentralized Energy; Steve Siegel, Energy and Security Group; Karen Baker, US Army Environmental Policy Institute; Gal Luft (Moderator) Institute for the Analysis of Global Security. WADE participates in inaugural World Future Energy Summit New Masdar City aims for zero carbon footprint Abu Dhabi, UAE • WADE participated in the inaugural World Future Energy Summit held January 21–23 in Abu Dhabi.

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The Masdar Carbon Free Community concept will be home to over 40,000 people and will generate all its own clean energy within the city limits. This event brought together global leaders in energy education, research, finance and business looking to further clean energy technology, especially in the Gulf region. Over 11,000 visitors attended the event from all over the world. It was hosted by the Masdar Initiative, a global co-operative platform for energy sustainability developed by the Abu Dhabi Future Energy Company. The Masdar Initiative includes development of a ‘green community’ with a near zero carbon footprint. WEC’s Cleaner Fossil Fuels Committee holds workshop DE key means of reducing fossil footprint Abu Dhabi, UAE • While in Abu Dhabi, WADE also attended a workshop and meeting organized by the World Energy Council’s Cleaner Fossil Fuel Systems Committee. The workshop, Clean Technologies for Economic Growth and a Better Environment, featured high-level speakers from government, industry and academia. Among the approaches discussed for cleaning up fossil fuels were cogeneration, district energy and carbon capture and storage. A keynote address, on the Masdar Carbon Free Community, was supplied by Dr Russel Jones, President of the Masdar Institute of Science and Technology. WADE joins Methane to Markets Partnership Consortium works to capture economic value from oft-wasted resource Washington DC, USA • Demonstrating its commitment to identifying and implementing cost-effective methane emission reduction opportunities, WADE has joined the Methane to Markets partnership as a registered member. The Methane to Markets Partnership was launched on 16th November 2004, at a Ministerial Meeting in Washington, D.C., when 14 national governments signed on as Partners. The new Partners made formal declarations to minimize methane emissions from key sources, stressing the importance of implementing methane capture and use projects in developing countries and countries with economies in transition. The four priority objectives of the partnership are reducing methane waste in agricultural, oil and gas, coal mining and solid waste management sectors. The goal of the Partnership is to reduce global methane emissions in order to enhance economic growth, strengthen energy security, improve air quality, improve industrial safety, and reduce emissions. Building Energy Efficiency Forum invites WADE participation DE potential in buildings highlighted Hyderabad, India •The recent ‘Energy Conservation Potential In Buildings’ meeting held in Hyderabad, India highlighted opportunities for ‘green’ building in India. DE was one of the many topics discussed at the meeting among others such as building materials, passive and active HVAC systems, efficient lighting and water conservation, etc.

Among those who participated were Dr Ajay Mathur, Director General, Bureau of Energy Efficiency (India); Shri Raghupathy, Sr. Director, Confederation of Indian Industry Green Business Centre; and Shri Lingaraj Panigraha IAS, NEDCAP vice chairman, along with WADE Director South Asia, Sridhar Samudrala. WADE participates in ‘Green Grid’ webcast WADE requests trigeneration be included in portfolio of energy efficiency options San Francisco, USA • WADE was recently invited to participate in a webcast organized by the Green Grid, a consortium of computer companies dedicated to advancing energy efficiency in data centres and business computing ecosystems. Members of the consortium include companies such as Microsoft, Sun Microsystems, IBM, Intel, HP and Dell. During the webcast WADE highlighted the potential of highly efficient distributed energy applications for powering and cooling data centres. EU’s Sustainable Energy Week puts DE high on agenda WADE contributes to proceedings Brussels, Belgium • Under the umbrella of the Sustainable Energy Europe Campaign (SEE), the European Commission’s Directorate-General for Energy and Transport, and major stakeholders concerned with sustainable energy put together the second EU Sustainable Energy Week (EUSEW) between 28 January and 1 February, 2008 in various European cities.

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The Sustainable Energy Week brought stakeholders from across Europe to discuss energy challenges. Decentralized energy featured prominently on the agenda in many discussions WADE was in Brussels to contribute to, among others, the session on ‘How to achieve the energy efficiency potential of cogeneration in the European Union’. 2008 Inaugural Roundtable hosted Former US Gas Association Head provides keynote Washington, USA • On 22 February WADE helped organize the first Natural Gas Roundtable meeting of 2008 featuring as a speaker Roundtable founder, and former Director of the American Gas Association, Bud Lawrence. Mr. Lawrence spoke in depth about the history of the US gas industry, borrowing from his newly published book about the US natural gas industry, Turnaround. The event also marked the 40th Anniversary of the founding of the Natural Gas Roundtable. WADE’s Director addresses finance forum London Efficiency Finance and Investment Forum hears DE message London, UK • On 29 January, WADE Executive Director David Sweet spoke at the first Energy Efficiency Finance and Investment Forum in London. His presentation discussed future market directions and was joined for a discussion with others including David Green, head of the UK Business Council for Sustainable Energy and Kateri Callahan, head of the Alliance to Save Energy. WADE conference WADE meets with Inter-American Development Bank Multilateral investment agencies express interest in DE for Latin America

Lima, Peru • WADE recently met with the Inter-American Development Bank (IADB) to discuss the role of decentralized energy for meeting clean energy goals throughout Latin America, with a special focus on Peru. The Asia Pacific Economic Co-operation’s Energy Minister Meeting was held in Iquitos, Peru in March, 2008. Over 21 energy efficiency initiatives were on the agenda at the meeting and WADE will be organizing a follow-up cogeneration and energy efficiency conference in June 2008 in Lima. The IADB expressed its support for WADE and its activities in Peru, highlighting the relevance that decentralized energy will play and its potential for development given that in recent years Peru has become an attractive market for investments in the energy sector. Both the IADB and the World Bank have recently granted financing for cogeneration and other energy efficiency projects in Peru. New contract for WADE Canada Team gears up for project to build Western Canadian DE directory representatives Calgary, Canada • WADE Canada has been awarded a contract to develop a directory of organizations operating in Western Canada with an interest in DE. The project is entitled ‘Building Western Canadian Small Medium Enterprises Involved with Clean Energy and Decentralized Energy Technology’. The project is scheduled to wrap up in June 2008 and will include an event to launch the directory in the spring. If you are aware of companies that should be included in the directory please contact WADE. Calling WADE Members How can we help you? In search of WADE research projects and proposals WADE has a long history of helping public and private sector institutions around the world to understand and realize decentralized energy (DE) benefits and opportunities through its tradition of thorough and comprehensive research. In addition to WADE’s regular publications, reports and market studies, WADE has participated in successful projects, conferences and educational campaigns, working with a range of governments, national and international organizations. WADE’s contribution to these projects includes: •

WADE Economic Model – computer modeling of the economic and environmental impacts of DE in a specified area

•

DE Potential Analysis – assessment of the potential for developing DE in a specified area

•

DE Policy Best Practice Review – international overview of policy mechanisms for DE

•

DE Technology Status Review – overview of the performance and market-readiness of DE technologies

•

DE Project Best Practice Case Studies – overview of successful DE case study projects worldwide relevant to a specified area

•

Education and Outreach Programs focusing on DE, environment and economic efficiency.

Are you aware of any opportunities where WADE can bring its expertise to bear? Please contact WADE and let us know how we can help your company or organization. Upcoming Events Call for Participation

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WADE has a long history of planning timely and authoritative conferences, strategy meetings and events. If you have an idea for an event related to decentralized energy that you would like to see organized WADE can help make it a success. Some of the events WADE is currently organizing are highlighted below. Please contact us if you require more information or would like to participate

Bagasse-fuelled cogeneration in Kenya 01-SEP-2004

Kenya could generate 10% of its electricity needs from cogeneration plants fuelled with bagasse from sugar cane. Bernard Osawa and David Yuko examine how this could be achieved, and describe the benefits that such a move would have for cane farmers, local economies, electricity consumers and the environment. As in most sub-Saharan countries, biomass fuels, used mainly in households, constitute an estimated twothirds of Kenya's energy mix. Petroleum and grid electricity constitute the remaining third of the total energy used in industrial, commercial and household sectors. Access to grid electricity for households currently stands at a low 15.3% nationally and less than 2% in rural areas. Total installed grid-connected generation capacity is 1230 MW, dominated by hydropower at 56%, while thermal and geothermal contribute 32% and 10% respectively. Consumption of electrical energy is dominated by the industrial sector at 63%, followed by domestic and small-scale industrial at 33%, while consumption by rural electrification customers comprises only 4% of the total demand. Investment in the power sector has lagged behind growth in demand, with the effect of this situation being felt throughout the Kenyan economy, largely in the form of lost production due to inadequate power supplies. The principal challenges facing the power sector are to: •

ensure provision of reliable, efficient, and cost-effective power supplies

•

increase the population's access to electricity as a means for stimulating income and employment growth

•

improve the efficiency of power distribution and supply through reductions in technical and nontechnical losses and collection of revenues

•

strengthen the regulatory framework

Over the last decade, the intensity of commercial energy use has been on the decrease, indicating a decline in economic growth. While the cost of, and accessibility to, energy for industry has been cited as the reason for poor economic performance leading to a low demand for power (786 MW), it is believed that demand is suppressed by the prevailing poor economic conditions, a cyclic situation. Historical average demand growth rate over the past five years has been a low 1.4%.

Unlike other industries that only consume energy, the sugar industry can generate surplus power over and above its internal requirements

COGENERATION AND THE SUGAR INDUSTRY Potential for cogeneration exists in the sugar industry where steam is raised from bagasse, a waste product of the cane milling process, for power generation and process heat. Unlike other industries that only consume energy, the sugar industry can generate surplus power over and above its internal requirements by burning bagasse to generate process steam and power. However, due to statutory requirements and other limitations on the sale of electricity, sugar factories in Kenya have been unable to exploit energy in bagasse. Excess bagasse is currently treated as waste and incinerated, largely as a process of disposal. Process steam and power are in this case unfortunately treated as a by-process of the disposal exercise. The current Kenyan government, voted in on a platform of accelerated economic development and infrastructure rehabilitation, has committed itself to, among other initiatives, the rehabilitation of the sugar industry. Power generation through cogeneration is seen as opening up new avenues for revenue creation in the sector. Accordingly, the Ministry of Energy recently permitted sugar companies to generate power for sale to the national grid and to the public in general. Furthermore, various fiscal incentives for investments in regular and non-conventional renewable energy projects have been suggested for inclusion in the national energy policy document. Meanwhile, local utilities are looking at strengthening the transmission grid, which, coincidentally, will allow the sugar companies to feed in their power. Consequently, it has become a viable proposition for sugar companies to raise high-pressure steam in modern, high-efficiency boilers using bagasse to generate heat and power economically to provide surplus power for export to the grid. Like other sectors in the Kenyan economy, the sugar industry has undergone continuous decline over the past decade. Statistics provided by the Kenya Sugar Board indicate that the best performance in the last decade (1992-2002) was recorded in 1996 when the industry had 131,100 hectares under cane yielding a healthy 90.9 tonnes of cane per hectare and supporting 23,900 plantation jobs in direct wage employment. In contrast, 2002 figures show that the acreage had dropped to 126,800 hectares, while the yield was down to 70.7 tonnes per hectare with the number of plantation jobs down to 2630. Bagasse could produce 360-600 GWh per year of excess electricity for sale While some of the job losses can be credited to increased mechanization in the farms, the bulk of the reductions are attributable to poor economic performance of the sugar factories and increased competition from cheap imports. The resulting poor sales of sugar from local factories impact negatively on payment to farmers, hence the downward spiral. Additional revenues from power generation, and the improved efficiency accompanying new investment, should help to revamp the industry.

DEVELOPMENT OF COGENERATION Experience from Réunion, Mauritius, India, Brazil and Cuba confirms the practical potential for cogeneration in Kenya, where it has hitherto been limited by the technology employed, financial and technical resources availability, and legal and regulatory frameworks. In the case of the success story countries, the development of cogeneration evolved along the well-established stages of own generation, intermittent power, continuous power and firm generation. In Kenya, one sugar factory has the capacity for intermittent power supply, but has been constrained by regulatory barriers. During the electricity crisis of 2000 this factory was able to sell power, but was limited by the capacity of interconnecting transformers linking it to the grid. It would seem natural for Kenya to avoid the intermediate steps and 'leapfrog' from own generation to firm power supplies by learning from the experiences of Réunion, Mauritius and Brazil. Kenya has the advantage that the crop season lasts an estimated 300 days a year, while the out-of-cane season is usually during the wet season, coinciding with the duration of maximum hydro availability and making firm generation attractive. Annual maintenance could be carried out during this period. The power and process steam requirements in a sugar plant can be met in one of two ways: Conventional cogeneration deploys a bagasse-fired boiler in conjunction with an extraction-condensing and/or back-pressure steam turbine coupled to an electrical generator, or a double extraction-condensing turbine coupled to an electrical generator. This is the predominant method currently used in Kenya with pressures of 20-25 bar and with resultant efficiencies of less than 10%. System efficiencies of up to 25% can be achieved for steam pressures of 45-66 bar, permitting electricity exports of up to 100 kWh per tonne of cane crushed. Plant performances of 110 kWh (82 bar) per tonne of cane crushed are operational in Réunion, Mauritius, India and Brazil. This means that the process of generating more power from sugar factories for export to the grid is essentially an efficiency upgrade exercise accompanied by a modernization and capacity improvement of sugar mills. Integrated gasification cogeneration with combined cycle (IGCC) uses an external gasifier to produce combustible gases from the bagasse, which are then fired in a modified gas turbine. Hot exhaust gases are passed through a waste heat recovery boiler for generating steam; some of the exhaust gas is used for drying

bagasse. Efficiencies achieved in the conversion of biomass to electrical energy can be as high as 37%. The IGCC system is still largely in a stage of commercial infancy, with a few installations in Brazil.

OPPORTUNITIES FOR COGENERATION The current total installed cogeneration capacity in the Kenyan sugar industry is 36.5 MW, used exclusively within the industry. Sugar industry statistics show that in 2002 alone Kenya produced an estimated 1.8 million tonnes of bagasse with a gross calorific value of 16,800 TJ, equivalent to 323,000 tonnes of oil worth approximately US$194 million. In conditions such as have been established in Mauritius, this bagasse could produce 360-600 GWh per year of excess electricity for sale, depending on the technology used. At this rate, cogeneration from bagasse could easily provide 10% of the national electrical energy demand. To achieve the 10% target economically, sugar factories will need to invest in firm generation through equipment upgrade, with efficiencies high enough to generate economic quantities of power for sale to the national grid. Issues that need to be addressed include: •

modular capacity, high-efficiency boilers to be installed in phases

•

ample storage capacity for bagasse to cover autonomy

•

factory efficiency optimization

•

improved scheduled maintenance

•

harvest cane trash as a possible extra boiler fuel (potential additional fuel capacity of up to 20%), which will require substantial investment

To sell their power to the national grid, sugar factories will, in addition, require investments in appropriate upgrade of grid interconnections consisting of power transformers, electrical switchgear and power lines. With appropriate investment, the bagasse could be used to generate an effective capacity of 135 MWe and 90 MWe at pressures of 82 bar and 60 bar respectively, to power the sugar factories and export up to 550 GWh of electricity to the national grid annually in addition to process steam. This could displace energy currently produced from fossil fuels. At an average consumption of 0.22 tonnes of oil per MWh for thermal plants, bagasse-based cogeneration would save some $90 million of foreign exchange annually. Additionally, cogeneration would promote the use of indigenous energy source, build local capacity for independent power production, encourage private sector participation in the power sector and create an import of financial benefits to cane farmers. Given the relatively long-term operation for which power projects are designed, more efficient units are attractive options

COST IMPLICATIONS For cogeneration plants, the investment costs vary with net export capacity, from $1.4 million/MW at the lower pressures, through $1.8 million/MW mid-range to $3.1 million/MW at the top end. This compares with $1.1 million/MW for heavy fuel plants, $2.25 million/MW for geothermal and $2.5 million/MW for hydro power plants. Thermal power plants have significant fuel costs that are passed directly to the consumers under current tariffs. Except for disparities arising from management performance, three out of the existing six factories in Kenya have identical capacities of 125 tonnes of cane per hour (TCH), while a fourth with similar capacity currently operates at 70% of the rated capacity. These four factories are in the league of 3000 tonnes of cane per day (TCD) and have a planned expansion to 5000 TCD. A fifth factory operates at its full rated capacity of 350 TCH, producing more than half of the country's sugar. The sixth, with a similar capacity as the other four, is currently under receivership with little signs of being re-opened. Consequent analysis hereinafter - see Table 1 - is therefore based on 5000 TCD capacity and can be adjusted for other volumes. Current operational performance and the installed capacities will be limiting factors to cogeneration as the cane crushing process is the source of fuel.

Table 1. Estimates of plant capital costs Component Boiler pressure (bar)

Possible plant options 45

60

82

5000

5000

5000

140

140

140

Bagasse feed rate (tonnes per hour)

58

62

70

Turbine capacity (MW)

25

30

50

420

550

820

Recommended plant capacity (tonnes of cane per day) Boiler capacity (tonnes of steam per hour)

Daily power generation, gross (MWh)

Equivalent capacity (MW)

18

24

40

Daily export power, net (MWh)

260

330

550

Equivalent export capacity (MW)

12.5

14

24

18

25

75

Estimated local component ($ million)

4

5

12

Estimated annual revenue from electricity ($ million)

4

5

8.3

4.5

5

8.8

Total capital investment ($ million)

Simple payback period (years)

This means that a 10% bagasse cogeneration contribution to the grid can be achieved by investing in efficiency upgrades at the five operational sugar factories in Kenya. The total investment costs will vary according to boiler pressures and efficiencies selected, and the power plant configurations at d ifferent factories. These costs would typically range between $120 million at 60 bar and $230 million at 80 bar, delivering an estimated 480 GWh with simple payback periods of 6-7 years and 8-9 years respectively. The cost figures compare reasonably with recent investment performances for geothermal and hydro plants. Corresponding estimated annual revenues from sale of electricity is $20-36 million in addition to savings from current net electricity imports into the sugar factories. Higher operating pressures offer better efficiencies, and therefore better resource utilization. However, they also entail higher capital costs and more sophisticated levels of technology. Given the relatively long-term operation for which power projects are designed, typically 25-30 years, the more efficient units are attractive over these periods. Like other renewable energy technologies, biomass cogeneration lends itself to modular implementation, allowing large projects to be broken down into smaller units that can be implemented in phases. Apart from being easier to finance, these modules reduce the impact of additional capacities on the grid system, enabling power sector planners to match demand with supply. Of the total capital costs of putting up sugar factories, on the order of 60% is attributable to the cost of the cogeneration power plant. Given that a number of the factories are planning capacity expansions, with most in need of a large degree of reinvestment to replace obsolete plant, cogeneration provides an ideal platform for the upgrade. In this case, the power plants should be designed to take expanded capacity in future. At present, all the factories are net importers of power, either due to inadequate capacity or, in the case of one factory, inadequate arrangements for generation when the factory is under maintenance. In the cogeneration scenario, the factories consume an estimated 30% of the power generated by the plant in exchange for bagasse fuel, effectively saving on their energy bill.

IMPACTS OF COGENERATION Based on 2002 figures, annual bagasse production is estimated at 1.76 million tonnes, equivalent to 323,000 tonnes of oil worth some $194 million at current fuel prices. Investment in bagasse cogeneration could be used to generate steam and electricity to power the sugar factories and export up to 550 GWh of electricity to the national grid, displacing energy currently produced from fossil fuels. At the average consumption of 0.22 tonnes of oil per MWh, this translates to an annual saving of $90 million of foreign exchange. Efficient cogeneration plants create on average 3.5-5.2 jobs per GWh directly With an optimistic job creation target of 500,000 jobs annually set by the current government, development of cogeneration in the sugar industry could provide numerous opportunities. Industry statistics show that efficient cogeneration plants create on average 3.5-5.2 jobs per GWh directly. Thus for a total capacity of 500 GWh, some 2000 jobs could be created directly from the sugar industry alone through cogeneration. Most of these jobs would, however, be created upstream in sugar plantations. Current annual turnover of the industry is estimated at $160 million, of which $100 million is due to independent sugar farmers, otherwise referred to as 'out growers'. Historically, only half of this amount is normally paid while the rest has always been carried over as arrears due to cash flow concerns within the factories. Investment in cogeneration would bring the desperately needed benefit of additional revenues to pay off the farmers for their cane. Improved plant efficiency, coupled with planned production expansion to meet international competition, would increase industry turnover by 20-40%. Secondary benefits and corresponding impacts would spread to other sectors, but the biggest beneficiary would be the small-scale out grower, thus directly addressing wealth creation targets. Sugar farmers currently frustrated by poor prices and late payments could be motivated to put more land under cane. With improved factory efficiencies and healthier performance arising from better cash flows and more reliable steam and power, higher cane output from the farmers is anticipated. Ultimately, cogeneration capacity would be limited by land available for cane, and by efficient agricultural production, account being taken of the need to balance food production against commercial sugar cane plantation.

Apart from substituting fossil fuels, cogeneration provides an opportunity for the reduction of greenhouse gas emissions, while strengthening the infrastructure base in relation to electricity supply. With carbon financing currently at $5-8 per tonne of carbon dioxide, additional revenues can be accessed to finance the development of the sector, once clear baselines have been established. This would substantially reduce borrowing to finance the development of these projects, with a resultant decrease on the national external debt.

POLICY ISSUES Any efforts to develop cogeneration in Kenya will have to begin with a look at the performance of the sugar industry and electricity sector in totality. In a situation where all the sugar factories are largely owned by the government, it will be essential to develop policies that facilitate the accelerated development of these sectors through the involvement of the private sector. Key issues that policy needs to address include: •

clear bagasse development policy, recognizing bagasse as a resource and facilitating development of bagasse-based projects

•

stimulation of investment by offering tax breaks and other incentives for investment in firm generation plant and efficiency improvement initiatives; incentives should lower front-end barriers to project development

•

restructuring the national sugar authority to enhance management, development and investment into the sugar sector and to promote cogeneration and efficiency

•

enactment of clear fiscal incentives for cogeneration to encourage investment

•

creating suitable and attractive regimes for independent power producer involvement, including pricing and grid feed-in laws for cogen electricity

•

provision of support to indigenous local private sector participation in the energy sector to ensure sustainability

•

the setting of realistic but challenging targets for increased cogeneration contribution to the electrical energy supply mix

•

development of a national pool of multi-disciplinary competence to develop, design and oversee local implementation of cogeneration projects

•

involvement of local and international financing groups to provide finance for investment in the sugar sector, especially for cogeneration projects

Developing and implementing coherent and consistent policies that cover these areas will ensure comprehensive and efficient development of cogeneration and the sugar sector, and facilitate the implementation of projects through private sector involvement.

LOOKING FORWARD Cogeneration provides a clear potential for diversification of the sugar industry into energy-related activities such as power generation and ethanol production, and should be accorded high priority. Sugar factories in Kenya have been unable to meet the national demand for sugar at competitive prices at a time when other Common Market for East and Southern Africa (COMESA) countries are desperate to sell cheaper sugar to the local market. By giving requisite attention and support to cogeneration, the sugar industry can bridge the production gap, thus making sugar farming more attractive. Furthermore, given more than 100,000 small-scale cane growers currently producing about 88% of Kenya's sugar cane, the implications for rural livelihood enhancement of this diversification could be very significant. While cogeneration matches other power generation options in terms of investment costs, it provides an indigenous source of electrical energy for the nation, saves on foreign exchange, is a tool for employment and wealth creation and an agent for abatement of environmental degradation. Left on its own, the sugar industry does not have the resources and capacity to realize the full potential of cogeneration. Clearly, the biggest hurdles are policy barriers and attitudes on the part of developers and financiers. A combination of players is required make a 10% contribution by cogeneration a reality.

Asia-Pacific Partnership - an alternative to Kyoto for promotion of CHP? Christoph Holtwisch The Asia-Pacific Partnership on Clean Development and Climate (APP), a relatively young international initiative established alongside the UN Framework Convention on Climate Change, was first covered by COSPP in the May–June 2007 issue. Here, Christoph Holtwisch takes a second look at the Partnership and the likelihood of its stimulating new distributed generation capacity. The Asia-Pacific Partnership on Clean Development and Climate (APP or AP6) is a very new phenomenon in international climate policy with important effects on the traditional climate regime formed by the UN Framework Convention on Climate Change (FCCC) and its Kyoto Protocol (KP) and likely impacts on the

development and transfer of distributed generation (DG) technologies. In its own view, the APP is a grouping of key nations to address serious and long-term challenges, including anthropogenic climate change. APP partners Australia, China, India, Japan, South Korea and the US represent roughly half the world economy and population, energy consumption and global greenhouse gas emissions (see Figure 1). For that reason, this ‘coalition of the emitting’ is – and will be – a central factor in international climate policy.

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Figure 1. APP states and their (projected) global greenhouse gas emissions Development and enlargement of the APP After secret negotiations, the APP was announced on 28 July 2005 at an Association of South East Asian Nations (ASEAN) regional forum in Vientiane in Laos by a Vision Statement which is now an integral part of the APP Charter. The official creation of the APP happened at an inaugural ministerial meeting on 12 January 2006 in Sydney, Australia, by the Charter, accompanied by a Communique and a Work Plan. The second meeting of the Policy and Implementation Committee (PIC) of the APP took place from 18 to 21 April 2006 in Berkeley, California, and produced Guidelines for the Task Forces of the APP and for their Action Plans. At the third PIC meeting in Jeju in Korea from 11–13 October 2006, additional Guidelines for flagship projects were made and the Action Plans developed by the Task Forces were accepted by the PIC. On 4 April 2007, a further Guidance to the Task Forces and a Procedure for adding new projects to the APP were published. The fourth PIC meeting took place in Tokyo, Japan, on 19 and 20 July 2007. It produced the Forms for project registration and status report already foreseen in the Procedure and the Guidance. The second ministerial meeting of the APP took place in New Delhi, India, on 15 October – an event at which Canada’s joining of the partnership was announced (Canada was an observer at the fourth PIC meeting and stated its interest in joining at that point). It has also been suggested that New Zealand, Mexico and some ASEAN states could join in the future. The EU could be a potential technology partner in the future too, but it has been more sceptical towards the APP because of the dubious position of this agreement towards the Kyoto Protocol. Character, aims and potential of the Partnership The APP forms a non-legally binding political soft law regime. This is stated expressly and indicated by terms like ‘compact’ (instead of treaty), ‘partners’ (rather than parties) and ‘nations’ (instead of states). Therefore, participation in the APP is on a totally voluntary basis. Nevertheless, the APP should not be underestimated because, in the end, political obligations are crucial even in international law that does not contain effective enforcement. While the Vision Statement uses the misleading expression ‘non-binding’, which led to criticism, the Charter prefers the term ‘non-legally binding’, which indicates clearly that the APP is meant to be politically binding. Surprisingly, the Charter tries to look like an international law treaty, which is one reason why it is overestimated by some observers. The APP follows the ideal of sustainable development with interlinked environmental, economical and social sub-aims. It contains the first connection of climate protection and energy security in an international agreement. The APP recognizes that renewable energy and nuclear power will represent an increasing share of global energy supply, but stresses that fossil fuels underpin their economies now and for the foreseeable future. The continued economic use of (cleaner) fossil fuels is consequently at the core of the APP policy. Therefore critics view it as purely a coal pact. This is too simple, but, without doubt, the technology of carbon capture and storage (CCS) is one of the central technological options for the APP. Instead of reducing absolute greenhouse gas emissions, the APP only intends to limit the greenhouse gas intensities of economic activities which would lead only to relative emission reductions (compared to a reference case). This plan is an important difference towards the cap and trade architecture of the KP and much less ambitious than it. Even in the best case scenario – a global use of the APP approach with CCS – absolute greenhouse gas emissions would more or less double from now to 2050 (see Figure 2). Therefore,

the APP ideas are clearly not enough to respond to climate change, but, nonetheless, they may play some role in dealing with this challenge.

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Figure 2. Prognostic development of greenhouse gas emissions with and without APP scenarios Purposes and financing The APP is meant to serve as a framework for an international co-operation between its partners and for the co-ordination of their national strategies (with the use of capacity-building). At its core, the APP is an agreement for the development and transfer of environmentally sound technologies. Economic freedom (with its legal and political aspects) is important for this as an enabling environment, so the APP contains an institutional dimension as well. The technology co-operation builds on a great number of existing bi- and multilateral political initiatives like the Methane to Markets Partnership and the Carbon Sequestration Leadership Forum, which are – like the APP – parallel tracks to the traditional climate regime. As the APP is not limited to special technologies (like distributed generation, or DG), it has the potential to build up as a future framework for these initiatives. Having in mind the different national laws regarding intellectual property of technologies, all these matters are to be addressed on a case-by-case basis. Generally, the financing of the technology development and transfer will be the crucial point for the APP. The financial contributions of the APP partners are very limited and vague. For that reason, the inclusion of the private sector is fundamental for APP activities, or, as one spokesman said: ‘The real dollars we are looking for are the private sector dollars. We are talking tens of billions of dollars if not hundreds of billions of dollars. If we don’t get the investment sector, we can’t succeed.’ APP and DG The first Work Plan of the APP focuses on power generation and distribution, as well as key industries. Eight temporary public-private Task Forces have been established in addition to the perm-anent political PIC and its Administrative Support Group (ASG): • •

Cleaner fossil energy (CFE)

Renewable energy and distributed generation (RDG) •

Power generation and transmission (PGT) • • • • •

Steel (STF) Aluminium (ATF) Cement (CMT) Coal mining (CM)

Buildings and appliances (BATF).

The RDG Task Force is co-lead by Korea (Kijune Kim, Ministry of Commerce, Industry and Energy) and Australia (Gerry Morvell, Department of the Environment and Water Resources). The Action Plans developed by the Task Forces and the different projects contained in it were accepted by the PIC at its third meeting in October 2006. In May and July 2007, the PIC endorsed a small number of new projects for some of the Task Forces with the RDG Task Force being the first one to reach this point of implementation. Figure 3 shows the institutions of the APP and their inter-relationships.

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Figure 3. The institutions of the APP and their interrelationships The article by Thompson and Neuhoff in the May–June 2007 issue of COSPP introduced the RDG Task Force and its 24 projects of October 2006. The three new Australian project proposals were accepted at the third Task Force meeting in San Diego, California, in March 2007. They deal with design and development of a solar biomass hybrid cooling and power generation system (project 25), a fully integrated process for biodiesel production from microalgae in saline water (project 26), and new generation small wind turbines for remote power systems and grid connection (project 27). The majority of projects are lead by Australia or the US, and most of them will be implemented in China or India. The APP homepage contains a lot of further details on all projects of the RDG Task Force: www.asiapacificpartnership.org. At its last meeting, the Task Force identified issues for focused attention too, including tariff reduction, intellectual property and – interestingly – commonality of framework for any future emission trading regime. However, this Task Force is just one out of eight, and DG is a sub-topic of it only. The RDG Task Force summarized the role of DG as ‘a model that can significantly reduce emissions and promote greater cost efficiencies, as well as respond to the demographics of energy poverty, thereby increasing access to modern energy services’. According to the Work Plan, DG technologies are ‘ideally suited to mid-sized and smaller scale applications’. As such, even if it is impossible at this stage to predict the extent of future APP investment in these technologies, DG is indeed – as Thompson and Neuhoff state – a ‘key aspect to implementation’ of the APP with a ‘critical role’ among all Task Forces. This is particularly the case because DG offers many possibilities for synergistic cross-Task Force efforts. Nevertheless, DG is definitely not at the heart of the APP because the focus of the APP is on the continued economic use of (cleaner) fossil fuels by using CCS technologies. DG is much less important and no more than part of a collection of other additional technological options. APP and traditional climate action regime While FCCC and KP are established regimes, the APP is a new parallel track. Officially, the APP is meant to be consistent with the principles of the FCCC and intended to complement but not replace the KP. Indeed, the APP is fully consistent with the FCCC principles, but the position towards the KP is more dubious. To be a complement, the FCCC must be the joint focal point of KP and APP, and also the latter must go beyond what is foreseen already in the FCCC. Therefore, the technology development and transfer rules of the APP must go clearly beyond the comparable FCCC norms. Technology plays an important role in the FCCC, and there exists a special technology ‘framework’ dealing with the topic in a similar way to the APP and with many more projects. The APP is only one of the technological ‘partnerships’ foreseen as a component of this framework. As such, it does not have the potential to go beyond the FCCC and complement the KP. This is also the case regarding DG, which is addressed in the traditional climate regime as well. Figure 4 depicts the schedule of activities of both the FCC and APP initiatives.

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Figure 4 Technology development and transfer within and outside the FCCC in comparison But is the APP intended to replace the KP? Some statements of its representatives and also the timing of its meetings – mostly a few months before the FCCC/KP meetings – give this impression. It seems likely that the APP was set up as a competitive regime to the KP because the KP contains legally binding emission commitments which the APP partners oppose now (the US and Australia) or for the future (China, India, Korea and, maybe, Japan). The opposition towards the KP means that the US and Australia cannot use the flexible mechanisms of the KP, which allows additional technology transfer to developing countries (clean development mechanism) and transformation states (joint implementation). Therefore, while the US and Australia oppose the KP and view the APP as an alternative to it, for China, India and Korea, it is a complement regarding technology transfer combined with an argument against future emission commitments. Japan simply widens its future political options with the APP. Overall, the APP is at least in great parts and for the future an opposing model against the central ideas of the KP – so far, it is intended to replace it. The KP in its present form will expire in 2012. This leads to the question of whether the APP could be integrated into the steadily developing traditional climate regime after that. Because of the opposition towards the KP, such integration is conceivable only under the FCCC framework. Since the creation of the APP, the FCCC stressed its openness towards technology-orientated concepts, and the importance of such international partnerships was also mentioned at the Heiligendamm G8-summit in Germany, 6–8 June 2007. Nevertheless, a formal integration via a new technology protocol or a second technology decision is very unlikely because the first alternative would lead to a legally binding APP (against the declared will of its partners) and the second – non-legally binding – alternative would install parallel procedures and institutions to the existing technology framework (which would undermine it against the will of the other FCCC parties). Therefore, only a non-formal integration is a realistic option which could lead to a fragmented but synergic ‘orchestra of treaties’ with a fruitful co-operation between the traditional climate regime and the APP – as regards DG too. To avoid the destructive potential of the APP, a peaceful coexistence is necessary at least. Such a co-operation or coexistence is important because every technology-orientated approach needs market incentives for the development and transfer of technology. It may be an inconvenient truth, but these can be created only by external emission commitments (or other market mechanisms) if the internal financing of the APP cannot be strengthened by an extraordinary amount. International climate policy has to deal with the difficult task of combining the competing approaches of market pull (KP) and technology push (APP). Technology is an important – but only one – component in a portfolio of measures against climate change. Nonetheless, we should be optimists like Sir Nicholas Stern, the economist who published a famous review report on climate change. He imagines ‘a real festival of technology, fired by constantly stricter commitments’. Beyond cleaner fossil energy with CCS, DG could be one of the most important technology options for that. Therefore, the APP could be a new vehicle for promoting DG development and transfer. The APP, however, has to clarify further the role it wants to play in this future – internally and externally. Dr. Christoph Holtwisch is a lawyer and environmental manager. He is also a lecturer at the Fraunhofer Institute UMSICHT, Oberhausen, Germany. e-mail: [email protected]

Decarbonizing energy are financial markets taking the lead?

Global investment in renewables and energy efficiency now outpaces that for nuclear energy. Renewables also accounted for more than a fifth of new generation capacity built in 2007. So how mainstream is the clean energy business in the eyes of financiers? Eric Usher reports, taking a particular look at the smaller, DE sector. The renewable energy and energy efficiency sectors are seeing a level of commercial investment that most thought unattainable just a few years back, with US$148 billion of new money put into the sector in 2007, up from $33 billion in 2004. This fast-tracking of alternative energy technologies into the commercial mainstream is beginning to change the energy paradigm, although much more growth will be needed if today’s carbonintensive energy system is to be left behind. This article draws on the work of the United Nations Environment Programme (UNEP) Sustainable Energy Finance Initiative and New Energy Finance in monitoring global investment trends in the sustainable energy sector, and analyzing the challenges ahead in meeting the global climate challenge. THE NEED: CAPITAL REQUIREMENTS FOR MEETING THE GLOBAL CLIMATE CHALLENGE The global climate needs to be stabilized soon Studies have been begun to estimate both the economic effects that climate change will have on global society as well as the costs of possible climate change mitigation and adaptation measures. Although the capacity to enact either a mitigation or adaptation strategy is based on country-specific conditions, technology, and information availability, models have been used to calculate the approximate cost to stabilize atmospheric emissions at different levels. Today greenhouse gas emissions in the atmosphere are approximately 455 ppm CO2 equivalent (CO2eq) and CO2 – the main greenhouse gas – is rising 1.9 ppm/year due to annual emissions of 49 gigatonnes (Gt) of CO2eq.1 The Intergovernmental Panel on Climate Change (IPCC) has concluded that to stabilize atmospheric concentrations of CO2 at 535–590 ppm, global emissions in 2050 will need to decrease to within the 18–29 Gt CO2 range worldwide and emissions must peak between 2010 and 2030, depending on model scenarios. Hundreds of billions of dollars will be needed for mitigation The United Nations Framework Convention on Climate Change (UNFCCC) Secretariat estimates a GDP cost of 0.3%–0.5% in 2030 to return emissions to 2004 levels, equivalent to 1.1%–1.7% of global investment, or $200–210 billion in additional capital mobilization across the economy. Although these costs are large by some standards, the overall effect on world income has been calculated to result in a delay of GDP growth of only a few years,2 partly since much of the capital requirements could be diverted from business as usual investment activities or paid for by lower fuel costs and other savings. In its recently released Energy Technology Perspectives 2008 report, the International Energy Agency estimates that when compared on an undiscounted basis the investment required to shift to a low carbon path will be fully offset by the fuel cost savings for coal, oil and gas. At a 10% discount rate the fuel cost savings pay for some but not all of the investment cost. THE RESPONSE ON MITIGATION: LOW-CARBON INVESTMENT TRENDS New analyses have been tracking climate investment UNEP’s Sustainable Energy Finance Initiative and New Energy Finance3 have been conducting an annual investment trends analysis in the renewables and efficiency sectors to provide new insight into the magnitude of the climate investment challenge and the response to date. This Global Trends in Sustainable Energy Investment 2008 report is not about predicting the future but rather understanding the present state of investment in the sector, the dollar view, and what this means in financial and broader economic and environmental terms. Investment in renewables and energy efficiency has grown quickly New investment in the sustainable energy sector – defined as new renewables (excluding large hydro) and energy efficiency – have increased significantly in recent years, reaching $148 billion in 2007 (see Figure 1). The most significant change occurred in late 2004, when wind and solar companies in Europe and Japan began to generate significant revenues, changing their view in the financial markets from relatively long-term future technology plays to present day, industrial-grade investment opportunities.

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Wind power, which surpassed 100 GW of installed capacity in March 2008, now receives more investment annually than large hydro power or nuclear, making it the leading climate mitigation technology in the eyes of financiers. In some instances renewables subsidiaries have become too large for parent companies and are being spun-off as independently listed companies. The Spanish utility Iberdrola, for instance, spun-off its renewables subsidiary through an initial public offering in December 2007, following the success of France’s EDF in listing EDF Energies Nouvelles. The Iberdrola initial public offering raised $6.6 billion, six times more than the previous largest initial public offering for a renewable energy company. With a capitalization of $33 billion, this new Spanish renewables operator has a larger market value than all but the biggest European power utilities. Engagement from the finance community has broadened The quickest growth in sustainable energy capital mobilization has come from three sectors of the financial community that had previously shown little interest: •

venture capitalists and private equity investors, who provide the risk capital needed for technological innovation and commercialization (up 42% in 2007)

•

public capital markets, which mobilize the resources needed to take companies and projects to scale (up 114% in 2007)

•

investment banks, which help refinance and sell off companies, allowing the all-important exit liquidity needed for markets to grow and for first mover investors to realize returns (up 52% in 2007).

The involvement of these three new financial players has signalled a broader scale-up in asset financing, the investment in actual generating plant capacity on the ground (up 61% in 2007). The breakdown of the types of investment going into the sustainable energy sector in 2007 is shown in Figure 2. Owing to the big names involved such as Goldman Sachs and some of California’s most prolific venture capitalists, these three new actors have had a strong knock-on effect that has further strengthened investor resolve to expand the particular climate mitigation sector.

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Emphasis is shifting towards decentralized technologies Wind power is far from the only clean energy sector on the rise, and many of the technologies following in its tracks are much more decentralized, including roof-top systems like photovoltaics or solar thermal, and energy efficiency technologies on the demand side. Solar and energy efficiency were actually the two largest sectors in terms of venture capital investment in 2007, with solar bringing in 30% and efficiency 18% of the $9.8 billion raised last year (see Figure 3). Besides this high level of early stage investment, mostly focused on new technology development, these two sectors also fared well on the public stock markets, ranking second and third (after wind) with $9.4 billion and $1.6 billion raised respectively. Solar would have overtaken wind on the public markets if not for the Iberdrola IPO. Public market investment is typically used to scale-up production capacity.

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Perhaps the biggest news for solar was with the later stage financing, both small and large scale, used to deploy systems on the ground. In terms of asset financing – the funding used to build large-scale projects – solar came second with $17.7 billion mobilized, after wind at $39 billion. Financial innovation opening new markets Small-scale financing approaches are being used to develop solar power. In developed countries solar equipment manufacturers in the US have led the way, realizing that they could help overcome capital-cost barriers by acting as financial intermediaries. One of the main financing tools used is the third-party power purchase agreement (TPPPA), which, according to some estimates, drove 60% of the solar capacity installed in California in 2007. Under a TPPPA, a third party designs, builds, owns, operates and maintains the solar power systems and sells back solar-generated electricity to the end-user. This model removes the burden of significant upfront costs from the end-user, and also allows the solar contractor, who has significantly greater expertise than the end-user, to assume the responsibility for system installation and maintenance. Tax credits and accelerated depreciation for the solar systems help to drive down their cost, as well as reducing the electricity price charged to the end-user. SunEdison and SunPower are two leading TPPPA proponents. SunEdison first used the model in 2004 on a commercial installation, and has since installed 34 MW of systems for commercial users financed via TPPPAs (or SPSAs – solar power services agreements – as SunEdison calls them). SunPower uses a similar model for its SunPower Access programme. A variation on this is where a city or county acts as financial intermediary, targeting residential customers. In Berkeley, California, as part of Berkeley’s Measure G mandate to reduce greenhouse gas emissions, home owners can finance a solar system through deductions on their property tax bill. Solar installation financing is attracting heavyweight investors. Goldman Sachs, GE Capital and MMA Renewable Ventures are all investing. In April 2008, for example, MAA Renewable Ventures announced that it was to finance 14 roof-top systems on Macy’s California department stores, with SunPower providing panels and systems integration. Developing countries, whose need for distributed generation is not so much driven by energy security and environmental concerns as by lack of grid access, are also benefiting from financing for small-scale distribution. Many developing countries have rural electrification programmes today and an increasing number of these rely on renewables and distributed financing models to provide access in off-grid areas. Besides electrification, many other clean energy systems and services are being installed with a range of end-user finance approaches. For example, in Tunisia UNEP has jointly run the Prosol solar water heating programme with the local energy agency and has seen 35,000 installations gain financing through payments made via customer utility bills. UNEP has run a loan programme with two of India’s largest banking groups, Canara Bank and Syndicate Bank, helping to kick-start the consumer credit market there for solar home-system financing. 19,355 homes where financed over three years and the market continues to grow with other banks now beginning to lend. These programmes and others like them are now looking to the Clean Development Mechanism (CDM) to help finance the further uptake of these sectors. Although CDM revenues cover only a small portion of the capital costs, if appropriately structured they can be used to bring down barriers to end-user financing, which is often is the key to market uptake. Engagement has started to shift towards large developing countries Developing countries accounted for 22% of new investment in the global sustainable energy sector in 2007, up from 12% in 2004. Developing country investment grew 14 times, from $1.8 billion in 2004 to $26 billion in

2007, with China, India and Brazil accounting for the major share; all three countries are now major producers of and markets for sustainable energy, with China leading in solar, India in wind and Brazil in biofuels. The results in the rest of the developing world, however, have been less promising and require increased engagement from governments and the development finance community. Figure 4 shows the global distribution of investment across the different regions.

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Energy efficiency investment shows a similar trend to renewables Energy efficiency is normally financed internally and is not generally identified as an investment unless it is undertaken on a significant scale. In 2007, investment in energy efficiency technology reached a record $1.8 billion, an increase of 78% on 2006. These figures, however, are quite difficult to isolate from other industrial improvement activities. From the macro perspective the impacts of investments in energy efficiency are easier to quantify. Improvements in supply-side and demand-side efficiency have been helping to decrease global energy intensity (i.e. the ratio of energy consumption to economic or physical output), which on average has been dropping 1%–1.5% per year.4 Since 1990, energy efficiency has met 52% of new energy service demands in the world while new energy supplies have contributed 48%.5 Most analyses expect future efficiency improvements to be in the range of 1.5%–2.2%. According to a modelling analysis undertaken by the Joint Global Change Research Institute, however, if the rate of energy efficiency improvement could be increased to 2.5% worldwide it would be possible to keep CO2 concentrations in the atmosphere below 550 ppm through the end of the century. Sustainable energy sector growth must be seen in perspective The $145.6 billion of investment in new renewables in 2007 (calculated by subtracting energy efficiency investment ($2.8 billion) from total sustainable energy investment) was equivalent to 9.4% of global energy infrastructure investment and 1% of global fixed asset investment. This can be roughly compared to the $200–210 billion that the UN Framework Convention on Climate Change (UNFCCC) Secretariat has estimated it will cost annually by 2030 in additional capital mobilization across the economy to return global greenhouse gas emissions to 2006 levels.6 A second comparison can be made to the figures in the Stern Report7, which concluded that the cost of stabilizing emissions at 550 ppm CO2eq would average 1% of global GDP – approximately $134 billion in 2015 and $930 billion in 2050. Though the UNFCCC and Stern estimates do not include the underlying infrastructure costs, but only the additional funds needed to decarbonize this investment, renewables’ recent capital mobilization success may provide some positive reinforcement for policy makers involved in the current round of climate negotiations. The fact that annual investment in renewables has increased by $115 billion between 2005 and 2007 demonstrates that it is possible to mobilize the capital needed to stabilize global climate – provided the right mix of policies and economic conditions are in place. The ever-growing numbers of supportive renewable energy and energy efficiency policies are certainly one of the reasons behind the scale-up of the sector even if the current level of direct government support is only just in line with other parts of the energy industry. Energy subsidies today total $250–300 billion globally, of which $180–200 billion are for fossil fuels and only $16 billion or ~8% for renewables.8 This share is a little less than the 9.4% that renewables currently have of total energy sector investment, implying that subsidy frameworks are slightly behind the level of investor commitments. However, if a role of subsidies is to help society make the shift to a more diversified and decarbonized energy economy then the current share allocated to renewables does seem low. Unfortunately subsidy frameworks are mostly backward-looking, providing production subsidies for existing infrastructure, rather than lowering the deployment costs of new technology. R&D trends tell a similar story In 2007, the sector attracted $16.9 billion of R&D from governments and corporates, up 30% from 2005. This R&D spend is still relatively low, which is surprising for a sector that relies on being at the cutting edge of technology. Energy R&D accounted for just 4% of total government R&D in 2005, down from 12% in the early

1980s. By contrast, strong growth in venture capital and private equity (VC/PE) investment in clean energy – up 106% since 2005 – demonstrates a more dynamic sentiment amongst risk capital providers than R&D supporters. Besides R&D and VC/PE, some public equity investment is also going towards scaling-up the technology and manufacturing base. For the past couple of years, growing acceptance by the public markets has encouraged sustainable energy and carbon companies to list their shares on stock exchanges worldwide and share prices have been pushed higher. During 2007, clean energy accounted for an estimated 19% of all money raised by the wider energy sector on the public markets, which is significantly higher than in previous years. This effect can be seen in the performance of the Wilderhill New Energy Global Innovation Index (NEX), which rose 57.9% in 2007, building on an already strong 33.3% gain in 2006. The sector is unlikely to fare as well in 2008, with clean energy stocks unable to escape the uncertainty that has characterized global financial markets. The impact of the credit crisis in the financial markets started to show through in early 2008, with few new listings on the public markets and stock prices down 17.9%. Corporate mergers and acquisitions (M&A) surged forward, reflecting the consolidation that tends to accompany tighter market conditions. However, by the second quarter investor uncertainty seems to have passed and overall investment during the first half of 2008 has been just above what was seen in the first half of 2007. Although asset finance is down somewhat, VC/PE investment, public market capital raising and stock prices are all healthy, indicating that the finance community still sees strong fundamentals underlying the sector and is increasingly looking to take part in its future growth. ARE RENEWABLES A MAINSTREAM TECHNOLOGY? Whether renewables can now be considered a mainstream energy or climate option can be best seen by examining the power sector. Nearly $90 billion was invested in new renewable power generation plants in 2007. By the end of the year, 241 GW of this clean generation capacity had been installed worldwide, of which 25 GW and 31 GW were added in 2006 and 2007, respectively. In comparison, the aggregate increase in capacity of the nuclear power industry globally averaged 2 GW per annum between 2004 and 20079 and IEA has estimated that 7 GW of new large hydro capacity came on-line in 2007.

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As shown in Figure 5, renewables still represent only 5.4% of global power generation capacity and 4.6% of production. However, the 31 GW added in 2007 accounted for over one fifth of new power generation added to the global electricity system last year. It is also equivalent to about half of Spain’s total electricity capacity, so this is not only about success in Germany and Spain and Denmark. This is becoming a global phenomenon.

Eric Usher is Head of the Renewable Energy and Finance Unit, Energy Branch, DTIE United Nations Environment Programme, Paris, France. e-mail: [email protected]

Notes 1. IPCC 2. Chritian Azar Christian and Stephen H. Schneider, “Are the economic costs of stabilizing the atmosphere prohibitive?”, Climatic Change 42, pp. 73–80. 3. Global Trends in Sustainable Energy Investment 2008, UNEP SEFI and New Energy Finance. Report can be downloaded from http://sefi.unep.org/english/globaltrends 4. IEA, 2006 “Energy technology perspectives 2006: scenarios and strategies to 2050”. 5. Realizing the Potential of Energy Efficiency, UN Foundation, 2007. 6. “Investment Flows to Address Climate Change”, UNFCCC Secretariat, Bonn, August 2007. 7. Sir Nicholas Stern et al, “Stern Review on the Economics of Climate Change” (Stern Review). 8. Trevor Morgan, ENERGY SUBSIDIES: Their Magnitude, How they Affect Energy Investment and Greenhouse Gas Emissions, and Prospects for Reform, June 2007. 9. Schneider, M., Froggatt, A., “The World Nuclear Status Report 2007”, January 2008. Taking advantage of the markets’ expectations for the sector European utilities began spinning out their renewables subsidiaries in late 2006, starting with the $691 million EDF Energies Nouvelles IPO in November 2006. The Iberdrola Renovables IPO followed in December 2007, and the EDP Renovaveis IPO in June 2008. The decision to finance these renewables operations as freestanding entities rather than as part of their larger utility operations illustrates how the capital markets are now distinguishing between old and new energy businesses. Take the example of Iberdrola in its efforts to raise the capital needed to expand its renewables business. If it had chosen to raise the capital through a share offering from its parent company, investors would have valued earnings from the renewables business at around one-third of the value it was given as a separate listing (based on the prevailing earnings multiples – see assumptions below). This higher multiple was based on investor expectations of much higher growth potential for a renewables business than for a traditional utility operation. Whether Iberdrola Renovables’ continued growth will meet these high projections will take some years to bear out, but it is clear that the capital markets have created a dynamic for change in the energy sector – one that even market incumbents are now starting to act on. Notes: As at 31 December 2007, the EBITDAs (earnings before interest, taxes, depreciation and amortization) of Iberdrola and its renewables subsidiary were €5538 million and €564 million, respectively, and the enterprise value of Iberdrola €73,318 million. The IPO gave an enterprise value for Iberdrola Renovables of €23,617 million (this had risen to €25,095 million by 31 December as the share price rose from €5.30 to €5.65). These figures correspond to EV/EBITDA multiples of 13.2x and 41.9x, respectively.

What now for carbon markets? Recovering from the April 2006 price crash 2006 has been an extraordinary year for carbon trading. In April, the price of carbon dropped by almost 70% to just €9/tonne, and more trouble may be brewing as national governments get ready to set quotas for their second phase National Allocation Plans. Candida Jones looks at what effect this turbulence may have on carbon abatement projects and the next phase of the EU’s Emissions Trading Scheme. The EU’s Emissions Trading Scheme (ETS), launched in January 2005, is the world’s first international emissions trading scheme and works on a cap-and-trade basis. The idea is to force companies to emit less carbon dioxide than their National Allocation Plan (NAP) allows (that’s the cap part) or buy carbon permits from elsewhere. The scheme has led to a bustling market in carbon abatement schemes through what are known as the flexible mechanisms of the Kyoto Protocol - the Clean Development Mechanism (CDM) and Joint Implementation (JI). These mechanisms encourage investment in carbon abatement schemes either in the developing world, in the case of CDM, or the emerging economies of Europe, in the case of the JI. Each of these projects generates carbon credits (Certified Emissions Reductions or Emission Reduction Units respectively), which can be offset against targets in the investors’ own countries.

Carbon crash - the price of carbon fell by almost 70% in a single day as countries revealed how much carbon was produced in 2005, showing a massive surplus of credits in the market (Point Carbon) Both the CDM and JI have lead to investment in renewable projects beyond the EU and a flurry of new companies has emerged, keen to maximize these investment opportunities. However, since the carbon price plummeted, uncertainty has been hanging over the reliability of these markets, which are linked to the volatile EU scheme. Mark Meyrick, a carbon trader for EdF Trading who invests in the CDM, confirms that ‘we became a lot more cautious about fixed price offerings after the collapse’. Power of industry felt The collapse in the price of carbon came just days after carbon traded in the EU ETS had reached an alltime high of €31 per tonne, up from €6 when the commodity was launched just 15 months earlier. The crash was apparently completely unexpected by sector analysts and marked a low-point in the first phase (20052007) of the scheme (see Figure 1). It was prompted when companies in the scheme had to report their actual emissions in the first year, 2005.

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Figure 1. Price of carbon (€/tonne) since trading began in 2006. Source: Point Carbon Each country’s NAP is based, at least in part, on historic emissions, or at least that’s what governments believed. However, after lobbying by industry groups, these caps were made far too lenient. Overall, actual emissions in 2005 came in well below the total cap, so there is a surplus of the tradable credits in the market. It quickly emerged that France was long, as were the Netherlands, Germany, the Walloon region of Belgium, Estonia and Finland. Even Spain, which relies heavily on hydro generation and had suffered a drought so was forced into burning more high-carbon fuels such as coal and gas to compensate, was less short of reaching its carbon target than experts had predicted. The impact of this was to devalue carbon, which was now clearly in abundant supply, bringing the price tumbling. The tumble caused the wholesale power market in Germany, and elsewhere, to drop, thereby affecting the share price of a number of carbon-related and energy companies. Carbon companies suffer Most carbon project developers found their share price immediately drop by up to 15% on news that carbon had taken a downturn, while even RWE and E.ON saw their share values reduced as the value of carbon is linked to the wholesale power market. Econergy, Ecosecurities, Agcert and Camco, all of whom develop projects under the CDM or JI, typically in Latin America, India or China, all saw the value of their shares drop. Immediately after the collapse, there were fears that the CDM and JI markets would see significant fall-off in investments, and indeed the market was virtually silent for nearly a month. Andreas Arvanitakis, analyst with industry specialists Point Carbon, said: ‘The deals came to a halt between the beginning of May and early June after investors were stunned by the crash.’ Back in the EU market, deadlines for the setting of the second phase NAP are now looming, with the European Commission expecting, perhaps optimistically, that all countries submit their draft second phase NAPs by 30 June.

The carbon market has been successful in stimulating renewable energy and energy efficiency projects in developing countries through the Clean Development Mechanism (MHyLab/IT Power) It is already clear that few countries will meet this deadline, including the UK, which has said it will instead honour the 31 December deadline by which time the NAPs are supposed to have been finalized. In itself this delay should have little impact on the second phase; however, for investors, especially in CDM, ‘the sooner they have certainty on the second phase NAPs the better’, Arvanitakis asserts. Jorgen Wettestad, a researcher at the Fridtjof Nansen Institute, an independent foundation engaged in research on international environmental politics in Norway, believes that delays are inevitable in such a relatively young scheme: ‘Delays due to political processes must be expected with the EU ETS. If you look at the history of the scheme, there have been delays all along. It is a complicated and new system to get up and running, and it will probably continue this way for a while.’ Understandably, European Environment Commissioner, Stavros Dimas, is less phlegmatic and has already warned that ‘It is essential that Member States submit these plans to the Commission by June 30 for the good operation of the system’. Learning from mistakes? What would be potentially more problematic than the delay is a surplus in the market second time around, especially for those effected by the carbon crash the first time. ‘There initially seemed to be a lot of determination from governments and the European Commission for the second phase not to be

fundamentally long like the first phase, but early indications of the second phase NAPs from European capitals suggest that the same mistake could be made the second time around because governments appear to be setting caps higher than in the first phase in some cases,’ says Arvanitakis. France is a good example of exactly this. In the first phase, France’s cap was 150 million tonnes (MT) of CO2/year, while its actual emissions in 2005 were 19 MT lower than this cap, representing actual emissions of 131 MT/year. According to an early draft of France’s second phase NAP, published on 26 June, this time around France is proposing a cap of 149.7 MT/year, leaving the second phase cap at roughly the same level as the first phase.

The principal reason for the fall in the price of carbon is that national governments set emissions caps too high, allowing industry to keep on polluting (Superdecor/stock.xchng) Although by 2012, it is assumed France’s GDP will have grown, and so too, therefore, will its emissions, this is still a worrying indication for the market, says Arvanitakis. ‘If the example of France is borne out across the EU and the second phase is fundamentally long again, then not only will the EU ETS flop, but all the momentum built in emissions trading and in the CDM and JI markets would be lost. Since the EU scheme is the jewel in Kyoto’s crown, this would have major implications for international negotiations and for what will happen after Kyoto’. Germany also looks set to fix a lax cap in its second phase. On 28 June, Germany issued a draft of its second phase, prompting Michael Grubb, Chief Economist at the Carbon Trust, and a self-proclaimed ‘big supporter of the EU ETS’ to comment that: ‘Looking at the draft [NAPs for phase 2] so far, I can report an extreme bout of depression’. Germany is proposing a cap which is just 0.6% below the reported emissions in 2005. Germany’s Kyoto target is to cut its emissions by 21% from 1990 levels by 2008-2012. According to Regina Gunther from WWF Germany: ‘these figures are unbelievably unambitious - it is shameful that our environment minister has agreed to this’. One country which may have bucked the trend somewhat is the UK, which on 29 June set its targets for the second round of the ETS, announcing that the annual cap would be 238 MT CO2, presenting a cut at the high end of the range outlined in the UK government’s draft proposal from March this year. The new cap marks a 7 MT CO2 reduction on the first-phase allocation, and a cut of 29.3 MT CO2 per year on the government’s business-as-usual projections. Speaking about the news Arvanitakis said: ‘With this the UK has set the standard for other EU Member States.’ Strong leadership needed from commission What is clear is that the Commission will need to take its role as overseer of the scheme seriously. ‘The real question is whether the European Commission has the political guts to force reductions in the NAPs where it

sees they are necessary,’ says Arvanitakis, a sentiment echoed by Wettestad. ‘Political decisions and considerations need to be made in the NAP processes ahead. At the moment neither the bureaucrats nor the politicians are thoroughly familiar with the EU ETS. It will become better on the bureaucratic side once routines and procedures are put in place, but the interaction with politics and political decisions will always play a role and may also delay future EU ETS processes’. Grubb has suggested that in order to make the second phase more robust, businesses should no longer be given free allowances, but instead, allowances should be subject to an auction process. ‘Our research indicates that in the second phase introducing a percentage of revenue-neutral auctioning is the best approach to ease over supply of credits and remove entirely the perverse incentives associated with free allocations’. This is an approach which Dimas has clearly been considering, commenting that he found the proposition of compulsory auctioning ‘very interesting and helpful’. Nonetheless, the Commission has conceded it is now too late to make changes to the rules for the second phase. Some signs of bounce-back? Despite the uncertainty, however, the carbon market is slowly recovering, and some participants have fared better than others, showing resilience in an otherwise volatile environment. Meyrick concedes that it is difficult to tell what deals are actually being done as ‘traders are invariably beavering away behind closed doors’, however, he confirms that EdF Trading ‘hasn’t changed its modus operandi’ and that CDM trades continue now as they did before the market slipped. Arvanitakis also confirms that recovery is well underway. ‘The number of deals is picking up again now and there are definite signs of recovery in terms of market activity. People are already trading carbon in the period covered by the second phase NAPs even though they don’t know what the exact position will be and may not know before the end of the year’ [the deadline for finalizing the second phase NAPs]. And while the large majority of project developers saw their shares dramatically slip after the crash, as trading in their shares significantly increased, Econergy managed to buck this trend, suggesting that their strategy of investment in solid renewable energy projects, as well as simply trading in carbon emission reductions (CERs), may have been a key factor in their stability. Although Econergy’s share value also dipped slightly, trading activity in their shares remained stable. According to Tom Frost of Numis, an independent investment bank, Econergy managed to weather the storm thanks to its renewable energy assets.

Joint Implementation is another Kyoto Protocol mechanism that has benefited from the trading of carbon credits, encouraging clean energy investments in the opening markets of Europe (Biomass Technology Group B.V.) ‘Econergy, like all project developers, saw a drop in its share value reflecting the drop in the price of carbon. However, unlike Agcert, Camco and Ecosecurities, Econergy did not see increased selling of its shares reflecting the fact that investor confidence has remained strong in Econergy shares thanks to its unique dual income approach’. Econergy is a US-based world leader in carbon credit generation from projects in Latin America. Unlike other project developers, Econergy doesn’t just source CERs for resale within the EU’s ETS, it also invests in the projects which generate CERs, thereby allowing it to sell the renewable energy that it generates as well as the CERs. Trevor Sikorski, Senior Analyst at Point Carbon, stressed the importance of this kind of approach. ‘If you’re financing your renewable energy project on CERs alone then this drop in the price of carbon will have had a devastating affect. As long as you sell [renewable] power as well as CERs then you should be OK’.

Moreover, Sikorski believes that ‘there’s a chance that some renewable projects may struggle if they are marginal and rely only on an income from CERs.’ It is certainly the case that allowances for 2008 are now trading close to €20, a doubling of their May value, and that indeed, on 26 June, they were trading at a premium to the first phase price of €15.55 for 2007, suggesting that long-term carbon investments are back on the up. For carbon project developers and for the renewable schemes that many of them invest in, this is good news. ‘Investors in CDM and JI renewable energy projects will be getting a lower rate of return on their investments than they might have hoped during the heyday of early April prices, but the market is still ticking over,’ Arvanitakis confirms. Tom Frost agrees. ‘Unless the Kyoto Protocol is abandoned, which it won’t be, there’ll be a price of carbon up to 2012, even if that’s at a lower price. After 2008, Western Europe will be far above its Kyoto target so there will have to be cuts, and the market will survive. There may have been a slow-down in projects being considered however, serious project developers won’t have been put off.’