With this decision, the Western countries venture to play for high stakes. If all goes well, their decision will calm the oil markets until Saudi Arabia steps in with increased production from its reserve capacity. If things go bad, however, they not only run the risk of injecting even more uncertainty into an already volatile market but also to jeopardize their improved relations with the oil-exporting countries that took years to build up.

Many oil traders will probably have choked on their coffee last week when they heard that some of the strategic oil reserves would be released. The announcement by the head of the International Energy Agency (IEA), Nabuo Tanaka, came indeed as a surprise. Oil prices seemed to have peaked in April, or at least to have stabilized since a few weeks. More importantly, Saudi Arabia and other Gulf states with spare capacity had promised to ramp up their production, even though a majority of OPEC members expressed itself against such a production surge when they met in Vienna on June 8. Nevertheless, the IEA countries felt that they had to act by releasing stocks.

The IEA was established in the aftermath of the first oil crisis of 1973-74 with the primary aim to act as a crisis manager on the oil market. To that end, the agency commands a powerful weapon: each member country is obliged to maintain strategic oil reserves of 90 days. It is only the third time ever that these stocks have effectively been used. The first time was in 1991 after the Iraqi invasion of Kuwait and the second time was in 2005 when Hurricane Katrina wiped out much of the oil production facilities and refineries in the Gulf of Mexico. Both market interventions are considered to be successful.

The western oil-consuming nations have traditionally treaded very carefully with these buffer stocks, which were long considered the “oil market equivalent of a nuclear weapon” as Javier Blas wrote in the Financial Times on June 23. These stocks were never intended to be used as a tool to manipulate the price of crude oil. Instead, they were designed as a last-resort lifeline to be used only in the most extreme circumstances, such as in the case of a severe disruption of oil supplies due to a terrorist attack. The fact that the emergency supplies were not used during major market disturbances such as the Islamic Revolution, the second Gulf War, or the oil price shock of 2008 illustrates the prudence with which the IEA has handled these reserves.

Moreover, in recent years, there seemed to be a gentlemen’s agreement between the IEA and the OPEC countries with spare capacity (mostly Saudi Arabia) with regard to responding to supply shortages. This is remarkable because these two clubs, the IEA and OPEC, were very hostile towards each other until the late 1990s. The agreement was that, when a supply shortage would occur, the IEA member countries would let the OPEC countries act first, before undertaking any actions itself. Sarah Emerson put it very succinctly in a 2006 article in Energy Policy: “30 years of energy security policymaking by the consuming countries of the IEA came to a head in the conclusion that OPEC’s spare production capacity, read Saudi Arabia, would officially be the first line of defense in an oil emergency.”

Today it appears as though the IEA has switched to a new doctrine. For the first time in history, the agency has used its strategic petroleum reserves in a preventive way, not because there is an actual oil supply shortage, but because it believes that such a shortage is imminent. The upcoming summer driving season, the reconstruction of Japan and the end of the maintenance period for many European refineries will push oil demand up in the coming weeks. The IEA has not waited for the shortage to happen, but it has made a bolt move to anticipate it. According to some observers, the decision of last week’s Thursday may be the prelude of a more interventionist oil market policy, in which the western countries will use their buffer stocks to adjust the price of oil.

In such an interventionist policy, however, lies a double threat.

First, while it is true that a stock release can bring temporary relief to a tight oil market, its longer-term effects are far more uncertain. The global strategic petroleum reserves currently stand at record levels but, obviously, they shrink as soon as they are tapped and they will have to be replenished later on (possibly at higher prices). Tapping the reserves for oil price manipulation leaves us with a smaller buffer, which makes us more vulnerable to acute crises caused by unforeseen events, such as terrorist attacks, natural disasters or political embargoes. Uncertainty about the IEA’s doctrine may also increase volatility in the market because it creates confusion with the oil traders. Furthermore, if oil stocks are not used to offset temporary shortages, but to address protracted (structural) oil shortages, the consumers of oil are not forced to adapt their behavior, thus aggravating the underlying problem.

Second, an interventionist oil market policy could undermine the relations between oil producer and consumer countries. While the IEA move was reportedly made in close coordination with Riyadh, it actually places Saudi Arabia in a difficult position. The IEA kept stressing that its stock release was meant to supply the markets with extra crude until additional Saudi Arabian oil production would come online. If the Saudis succeed in increasing their production within a month, they may infuriate other OPEC countries even more and fuel the dissension within the self-proclaimed oil cartel. If they fail to do so, then they pose the IEA for a big problem because the Paris-based agency will then be under pressure to prolong its stock release.

Importantly, besides being bifurcated between these two allegiances, Riyadh’s room for maneuver is limited in yet another way. Over the past months, it has made huge public expenses to buy off domestic social peace. As a result, the Kingdom now needs a much higher oil price than it did just a few years ago to balance its budget. Whatever action they agree on, the decision-makers in Saudi Arabia are likely to tread on someone’s toes in the coming weeks.

Thijs Van de Graaf, Department of Political Science, Ghent University

A case in point is carbon-free nuclear power, now enjoying a strong revival after years of dormancy, with significant investments in the US, the UK, China, India, Russia and a number of other major markets expected into building a new generation of reactors. The investors and developers, however, confront a host of shortages and obstacles beyond the usual stringent permitting and licensing issues.

Only a handful of companies are capable of manufacturing the highly specialized components of reactors and pressurized vessels – and as orders pile up, the waiting list for deliveries are getting longer. Japan Steel Works Ltd. for example, is one of few places making heavy steel forgings that go into nuclear plants. Chinese manufacturers are trying to find their way into every profitable niche, but that may take some time and require acquiring specialized skills. With plans to build as many as 50 new reactors by 2020, China offers a big market for nuclear manufacturers but could also create bottlenecks in the supply chain.

Shortages of skilled engineers, pipe fitters and welders are also cause for concern as there are a finite number of them to go around. With a growing number of US utilities lining up to build nuclear power plants, experts reckon completion times would stretch from 2015 to 2020, and that assumes no major regulatory or licensing hurdles.

In an interview with The Wall Street Journal (11 Apr 08), Dale Klein, the Chairman of the Nuclear Regulatory Commission (NRC) expressed concerns about the supply chain, especially now that a literal flood of applications for new nuclear plants are being submitted to NRC. He said, “The global supply chain is stretched, if not to the breaking point, at least to the tipping point.”

Referring to the membership of the American Nuclear Society, a key professional association, he pointed out that in 1977, 1350 American companies were represented. Today, that number is down to 700 – and many of them are foreign-owned. What this means is that many of the critical parts and components are increasingly manufactured outside the US, with little NRC oversight or quality control.

Globalization of wind Largest global wind markets
Source: The Wall Street Journal, 18 Apr 08 based on data from BTM Consult ApS

Renewable energy technologies, principally wind and solar, are also enjoying a phenomenal global building boom but also running into similar bottlenecks for critical components including wind turbine blades, solar modules and collectors. (See related article in this issue).

Conventional coal, currently facing strong opposition in the US and some European countries, has become a non-starter, abandoned by a number of developers who consider it an uphill battle with uncertain prospects given significant uncertainties about future carbon constraints. The short-term void is being filled by natural gas in many cases at a time when supplies are stretched and prices are rising.

US power sector demand for natural gas grew 10% in the last year alone, according to the Energy Information Administration (EIA) with domestic production flat. Experts have differing opinions, but many project a widening gap between domestic production and consumption, perhaps as much as 20 billion cubic feet by 2025. That gap is expected to be filled by liquefied natural gas (LNG) imports.

But US is not alone in growing reliance on imported LNG. Once a limited market with a few sellers and buyers, the LNG business has grown into a global commodity with a fleet of specialized LNG cargo ships transporting gas from any shipping to any receiving terminal – the destination determined by the highest bidder.

With major swings in demand due to regional droughts, cold or hot spells or variations in inventory levels, natural gas prices have become volatile, making them susceptible to frequent price spikes with little predictability. Long-term contracts, of course, are one way to get around the price swings but that carries an insurance premium not everyone is willing to pay.

Another driver putting upward pressure on prices is the booming economies of developing countries, notably China, India, but also others in the Middle East, Africa and Asia. China and India combined are sucking up a significant percentage of world-wide supply of power plant equipment components, not to mention primary fuels and commodities. In 2006, China reportedly built some 90 GW of new capacity, mostly coal. India, facing chronic power shortages, has announced plans to add 22 GW of new capacity in the next 5 years followed by another 70 GW in the following 5 years.

Since there are a limited number of suppliers serving the global market, bottlenecks have appeared prolonging waiting times for deliveries of critical components and parts. Developers are already complaining about significant delays in construction times for power plants. A relatively trivial combined cycle plant that would have taken a mere 2 years to build now takes 3 or longer and costs substantially more.

Rising Utility Construction Costs, a September 2007 report by the Brattle Group for the Edison Electric Institute (EEI), documents recent increases in raw material and commodity costs, such as steel and cement. Copper wires, for example, have quadrupled in price in the recent past, assuming you can get what you need. The EEI study points out to a “growing backlog of project contracts at large engineering, procurement and construction (EPC) firms and speculates that future bids may be less cost competitive as “new construction projects are added to the queue.”

Indices are all pointing upward National avg. utility infrastructure cost indices, 1991-2007, 1991 = 100
Source: Transforming America’s Power Industry, the Brattle Group, Edison Foundation Conference, 21 Apr 08

Cost of steam generation plants, transmission and distribution rose by 25-35% between Jan 2004-07; gas turbine prices rose 17% in 2006 alone, according to the same study. The impact on based load units such as coal or nuclear plants? Add $20/MWh to projections. And that is based on data up to 2007. One can only speculate that things have gotten worse since.

F.P. Shioshansi

This post is extracted from EEnergy Informer, May 2008 issue.

A potential nuclear power renaissance in liberalised markets will face a number of hurdles associated with the specificities of the technology and the legacy of past experiences. Nuclear power suffers indeed from some specific risks: i) the regulatory risk associated with the instability of safety regulations and design licensing; ii) the policy risk where electoral cycles could undermine the commitment to nuclear power and the development of nuclear waste disposal facilities; and iii) the construction and operation risks associated with the necessary re-learning of the technology. Besides, the large size of a nuclear project and the capital intensity of the technology make it relatively more sensitive to some critical market risks such as the electricity price and volume risks.

In a recent paper we analyse four case studies to illustrate the range of alternative consistent combinations of contractual and financial arrangements for new nuclear build. The suitability of the different alternatives largely depends on the industrial organization of the electricity industry and the institutional environment which are specific to one country’s nuclear policy. We studied the contractual and financing choices for new nuclear build in four typical market cases:

- The decentralised Texas market, wherein the NRG Energy South Texas merchant project of constructing two General Electric-Toshiba ABWRs is based on a project finance approach. The critical factors enabling such financing structure are the federal loan guarantees, federal tax credits, and long term fixed price contracts with credible counterparts (historic suppliers and unregulated large municipalities);

- The Nordic market, wherein the Finnish TVO project to build an EPR uses an hybrid financing approach. The project relies on two special arrangements: a turnkey contract by which the constructor bears a large part of the construction and performance risks, and the financing by a consumers’ consortium whose members will in return pay electricity at cost-price over the life of the plant;

- The imperfectly reformed French market, wherein the project of the Flamanville EPR is managed and lead by the large size and vertically integrated historical incumbent, EDF using a corporate financing approach. With its expertise of nuclear build and operation, its portfolio of existing assets and its large base of ‘sticky’ consumers, and its strong balance sheet, EDF is in a good position to manage or transfer the different risks associated with the construction of the new EPR reactor;

- Finally, the case of oligopolistic markets of mid-size vertical companies (such as the British market) or of small markets dominated by incumbent companies in Central and Eastern Europe. Candidates to nuclear build and their potential lenders in such markets would likely seek to share costs and risks by e.g. investing in a producers consortium, and would search to have some market risks (such as the CO2 price risk) transferred onto the state.

The four case studies highlight that there remain many critical factors specific to each country’s industrial and regulatory environment, such that the reproducibility of some current innovative approaches can be questioned (e.g. the consortium of industrial users and the turnkey contract in Finland, or the “merchant” project in Texas backed by federal loan guarantees). There is no optimal “once-for-all” contractual and financing arrangement for investing in nuclear in liberalised markets.

The decisive factor in the success of nuclear investment will be the ability of the power industry to engage with regulatory and safety authorities, plant vendors and construction companies, and consumers to mitigate political and regulatory risks on one hand-side and to allocate risks onto parties which are best able to manage them on the other side. By shifting part of the pre-construction, construction, operating, and market risks onto other parties, electricity producers are in a better position to attract potential investors. Plant vendors and the different equipment contractor companies play a key role during the construction phase, while long term power offtake contracts with large consumers or with creditworthy suppliers with a stable retail consumer base can greatly contribute to the success of a nuclear plant project.

The allocation of the different construction, operating and market risks in turn influences the selection of the financial arrangements among different options. While in the past regulated utilities financed their investments using corporate financing with recourse debt and bonds, a wide range of options ranging from project finance with non-recourse debt and with high gearing to corporate and hybrid financing approaches are now available to investors.

We think, however, that the most likely financing structure for new nuclear plant will be based on corporate financing or some form of hybrid arrangement backed by the balance sheet of one or a consortium of large vertically integrated companies.

During the initial phase of nuclear “re-learning”, the range of viable contractual and financing arrangements appears quite limited. In the perspective of project financing of new nuclear plants, loan guarantees by government and power purchase agreements at fixed price for almost all the off-take power will likely be required. Turnkey contract for the FoAK reactors could also provide a guarantee during the construction phase, followed by refinancing for the plant operation phase. At least during this first phase of nuclear “re-learning”, banks and lenders are therefore likely to favour corporate financing by firms with strong balance sheets.

This implies that countries where electricity reform has been partial and which have preserved industrial champions could be the most favourable ground for new nuclear investment. The irony is that competition authorities have been worried about industry concentration in the energy sector while it might have the positive side effect of creating companies of the size required to manage specific risks and finance the large and capital intensive carbon-free technologies needed. This observation does not exclude nuclear development in countries with a more fragmented industry, but more original models for risk pooling and/or risk transfer are likely to emerge in such countries, such as consortium of consumers and suppliers with long term arrangements to lower the cost of capital and increase leverage as in the Finnish EPR project. But it is not so sure that development of these arrangements in the same market will remain indefinitely compatible with competition policy principles.

Nuclear build in liberalised markets is going to bring some new light on some critical issues associated with the maturing of European electricity markets.

Fabien ROQUES, IEA* and

*The views expressed in this post are those of the authors alone.

Writing recently about the emerging European energy diplomacy, Benita Ferrer Waldner, Commissioner for external relations, said the European Union had signed or was negotiating agreements with Azerbaijan, Ukraine, Kazakhstan, Turkmenistan, Algeria, Egypt, Morocco, Jordan, Iraq, the countries of the Gulf Co-operation Council and, “when the political situation will allow it”, it would negotiate with Iran.

The list looks impressive but, in fact, the scheme makes little sense. Almost everything in this vision – the availability of gas resources, the possibility to develop them, the political and commercial feasibility of the transport infrastructure – is hypothetical at best.

The recent announcements about Turkmen and Iraqi gas exports to Europe illustrate the virtual nature of the EU’s foreign energy policy. It is not clear whether Turkmenistan, given existing contractual commitments, has 10bn cubic metres of gas available for the EU. But it will not be tested as the proposed options to ship Turkmen gas to the western shore of the Caspian Sea are nowhere near credible. In any case no commercial contract has been signed. The Iraqi announcement (of 5bn cubic metres annually starting “in the next 3-4 years”) has even less commercial reality behind it.

The common denominator in these two announcements is the Nabucco project, a new “gas corridor” to Europe through Turkey that is the centrepiece of the European plan to diversify away from Russia. Yet there is no earmarked gas to feed Nabucco, either in central Asia or the Middle East. The pipeline is conceived as an enabling project that, once built, will gather gas from various sources.

But financing a multibillion euro international gas pipeline requires a long-term contract between buyers and an upstream company controlling a large resource base. Diplomatic involvement can help reduce non-commercial risk, but cannot substitute for commercial logic. EU officials are desperate to show there is potentially a lot of gas that could flow through Nabucco, but even if that is true it does not make it more likely to be built.

This is not necessarily worrying. The idea that Europe lacks, or will soon lack, access to a diversified and secure (read: non-Russian) natural gas supply is not backed by the data. Even as Russia expanded exports to Europe, its share of European imports (for the 27 current member states) has roughly been halved since 1980, from 80 per cent to about 40 per cent. Since 1990, 80 per cent of the rise in EU gas imports has been from non-Russian sources. Europe already enjoys a diversified natural gas supply. Russia’s failure (or unwillingness) to develop its resource base and expand exports to Europe is bound to make the European market all the more attractive for other exporters in the coming years – though it will also mean higher prices.

Europe faces three main gas security challenges. The first is to export gas supply diversity from western Europe to eastern Europe, where the rate of dependence on Russia is much higher but gas markets are much smaller. Market integration is the only way to do that. A single European gas market would create de facto solidarity between all consumers and the bilateral dependencies would become largely irrelevant.

The second challenge is to increase the ability of Europe as a whole to cope with supply disruptions, whatever their causes. Here again, market integration and competition is the way to go. A well-functioning market transforms any localised physical shortage into a universal price increase. Additional measures such as interruptible contracts and emergency inventories would help reduce the economic impact of supply shocks.

The third challenge is to remove the debilitating effect of the EU-Russia gas relationship on EU foreign policy towards Russia. A European integrated and flexible gas market would make eastern Europe more secure, just as it would make the relationship between Gazprom and large utility importers in Germany, Italy or France less cosy. This is a better position from which to speak with one voice to Moscow.

Building a well-functioning internal gas market is less grandiose than developing a foreign energy policy, but also more promising. This is what the Commission should concentrate on.

Pierre Noël, Researcher at the University of Cambridge (EPRG) and at the European Council on Foreign Relations

P.S. This article was published in the Financial Times on 14th May 2008.

However, despite wide concerns over the ability of de-integrated markets to ensure an optimal allocation of risks, the Commission has constantly voiced strong concerns over their anti-competitive effects. Perceived legal uncertainty is strong at the moment in the market place mainly for two reasons and we will argue that it is largely overstated.

First is the lack of Commission decisions on long term vertical contracts (LTC, hereafter) in electricity since liberalization. Cases in electricity prior to the opening up of markets are interesting but characterized by a clear lack of methodology leading to inconsistencies and decisions based on fairly weak grounds (e.g. security of supply) which are unlikely to be accepted today, at least on the same terms. The legal uncertainty created by the lack of precedents has been amplified by the split between the current state of Commission thinking and its past decisional practice where long durations (15-20 years) had repeatedly been accepted.

Second, the long-term trend of EC competition policy modernization has strongly increased legal uncertainty. In the old system, legal certainty came from the possibility to notify LTC ex ante to the Commission in order to get clearance in case the agreement was not covered by an exemption regulation. Nowadays, firms and their legal counsels must define the relevant market and self-assess their agreements as well as potential efficiencies pursuant to Art 81(3). Modernization also aimed at implementing a ‘more economic’ approach based on long-term consumer welfare, which meant gradually shifting from a legal ‘form-based’ analysis of contracts to a more ‘effect-based’ approach where the real economic effects of competitive behaviors should be more important than the drafting of contracts. Last, there is a continuum between Art 81 and 82 EC (which tackles abuse of a dominant position) as LTC might be analyzed under the latter when the firm is dominant and while the Commission has started modernization more than ten years ago, the reform of Art 82 EC is still lagging behind.

The Commission stated in the explanatory memorandum attached to the Third Energy Package that it will soon provide guidance on downstream LTC. There is no doubt that such guidelines will be mainly based on past and recent case law and are unlikely to deviate from Commision’s present course of action. For the first time in 2007, a comprehensive methodology for better analyzing LTC in energy has been sketched out in the Distrigas case where the Commission had concerns about liquidity problems on the Belgian wholesale gas market due to the portfolio of LTC concluded by the firm with industrial customers. Distrigas and the recent related decisions (e.g. Synergen, Gas Natural/Endesa, Repsol or E.ON Ruhrgas) demonstrate that a clear analytical framework has emerged. The Commission will now focus on interactions among several key elements, and importantly in the following order: market characteristics, competitive position of contracting parties, the share of the customer’s demand tied, duration, the overall share of the market covered by contracts containing such ties and efficiencies. As a result, a sort of structured rule of reason has emerged. Beyond the reasoning applied, this is the stability within each step of the methodology across decisions that is even more striking, striking enough to wonder whether such stability is really the outcome of a more economic approach.

This is not our opinion. Most analytical devices and remedies which have been integrated in recent decisions in energy are not new to EC competition policy and can be traced back to key decisions in the long process of modernization of vertical restraints analysis. One of the main innovations of recent decisions in energy is the use of the cumulative market doctrine and the taking into account of patterns of consumption. The cumulative effect doctrine is a way to analyze if an agreement, which taken isolated would not fall within the scope of Art 81 EC, nevertheless has an appreciable effect on competition when assessed in its legal and economic context, especially when it is part of a network of parallel agreements concluded by one or several dominant suppliers. In Distrigas, this is primarily the cumulative effect of the network of contracts concluded by the firm which grounds the infringement of Art 82 EC. Historically, the doctrine of cumulative effect on foreclosure has been a cornerstone of the modernization of vertical restraint analysis and has been regularly endorsed by Community Courts. The reasoning applied today in Energy had in fact been slowly devised in famous series of cases in the beer and ice cream sectors. It was first treated in the Art 81 EC cases Brasserie de Haecht (1967), Delimitis (1991) and more recently Langnese-Iglo (1995), Schöller (1995), Neste (2000) or Van den Burgh Foods (2003). This is a well-established tool of competition analysis which will be used in future energy proceedings and help firms analyze themselves the potential anti-competitive effects of their portfolios of LTC.

Facing traditional competition issues in a completely new and fast-evolving market setting, the Commission thus tends to apply methodologies and remedies similar to those used in other sectors. As a result, we think that the (not so) new methodology which we depicted above is likely to be here to stay and that competition law enforcement to the energy sector is becoming similar to any other sector. Competition policy toward long-term vertical contracts in electricity therefore becomes more predictable and firms benefit from more robust guidance to make their portfolio of contracts comply with EC competition rules.

However, a contradiction is worth emphasizing. One rationale of the more economic approach in EC competition policy is to better capture industry specifics and as such, there is no reason to believe that energy at this stage of the liberalization process must be analyzed as the beer or ice-cream sectors, except if energy truly converged with these industries which is not the picture we find in the Sector Enquiry. True, applying some analytical devices such as the cumulative effect doctrine does bring some relevant insights for competition enforcement in energy. However, we think that the application of the methodology applied in recent decisions also expresses a path dependency in competition law enforcement and the difficulties the Commission currently faces in energy. When we argue that legal certainty has recently been upgraded in electricity, this does not come from a new methodology able to capture real economic effects with a high level of consistency but from a methodology which the Commission knows and can apply. Antitrust authorities cannot rely on well established economic foundations when enforcing competition law in electricity whereas industrial organization theory is usually more mature and thus helpful in other sectors. In the face of the difficult policy trade-offs brought up by LTC in energy, it may thus be tempting to disregard sector specifics and use well-known methodologies from other sectors, and this is what is happening: drink beer and eat ice-cream to see the end of legal uncertainty for long-term contracts in the EU electricity markets!

Jean-Michel Glachant and Adrien de Hauteclocque

This blog has been written out of ‘Legal Uncertainty and Competition Policy in Deregulated Network Industries: The Case of Long-term Vertical Contracts in the EU Electricity Markets’

The Clean Development Mechanism (CDM, hereafter) allows industrialized countries which have accepted emissions reduction targets to develop or finance projects that reduce greenhouse gas emissions in non-Annex 1 countries in exchange for emission reduction credits. If the technology used in a CDM project is not available in the host country but must be imported, the project leads, de facto, to a technology transfer. This technology may consist of “hardware” elements, such as machinery and equipment involved in the production process, and/or “software” elements, including knowledge, skills, and know-how.

So far, most climate-friendly technologies have been developed and used in developed countries. Therefore, expecting international technology transfer through CDM projects sounds reasonable. However, whether this is true in practice is an empirical question. In a recent study financed by the French environmental agency (ADEME), we used a dataset describing the 644 CDM projects registered up to 1 May 2007 in order to explore this issue.

Data show that international technology transfers take place in 44% of CDM projects, accounting for 84% of the expected annual CO2 emissions reductions (towards 2012). Very few projects involve the transfer of equipment alone. Instead, projects often include the transfer of knowledge and operating skills, allowing project implementers to appropriate the technology.

Current technology transfers under the CDM mainly concern two areas. The first area is end-of-pipe destruction of non-CO2 greenhouse gases with high global warming potentials, such as HFCs, CH4 and N2O, which are mainly transfers focused on the chemicals industry, the agricultural sector and the waste management sector. The second category is wind power, with 60% of projects using equipment from abroad. Biomass electricity production projects or energy efficiency measures in the industry sector mainly rely on local technologies.

Our data also show that host countries are very heterogeneous in their propensity to attract technology transfers. For example, 59% of the Chinese projects involve a transfer while the percentage is only 12% in India.

Frequency of technology transfer for the main host countries (% of the projects)

European countries are by far the main technology suppliers. In particular, Germany, Spain and Denmark account for 45% of the exported machinery altogether. This means that the money spent by Annex I countries to finance CDM projects – through the purchase of carbon credits – is only marginally used to buy machinery from countries that have not ratified the Kyoto Protocol.

Technology suppliers (% of the projects involving a technology transfer)

As regards the partners involved in CDM projects, only 8% of the projects are implemented in subsidiaries of companies located in Annex 1 countries. This is much lower than what was expected. By contrast, we frequently observe the involvement of CDM project designers that manage the whole CDM project cycle, from PDD writing to credit sale.

We have run econometric regressions in order to identify what drives technology transfer. All other things being equal, they show that transfers are more likely in large projects (in terms of emissions reductions). Furthermore, the probability of transfer is 50% higher when the project is developed in a subsidiary of an Annex 1 company. Having an official credit buyer in the project also positively affects transfer likeliness, albeit much less (+16%). The host country’s features also matter a lot. Both the openness of the economy and the economic dynamism, as proxied by the recent average annual growth of GDP encourage technology transfer. In particular, one additional percentage point of average GDP growth raises transfer likeliness by 19%.

Do the host country’s technological capabilities influence technological transfer? In theory, this factor has ambiguous effects. On the one hand, high capabilities may be necessary to adopt a new technology, but, on the other hand, they also imply that many technologies are already available locally, thereby reducing transfer likeliness. Our estimations show that the first effect strongly dominates in the energy sector and in the chemicals industry, whereas the second effect is stronger for agricultural projects. The interpretation is that technologies transferred in the agriculture sector are not very elaborate, implying that only countries with poor technological skills need to import them, whereas, wind turbines, solar panels in the energy sector or abatement devices in the chemicals industry would require technically qualified manpower to be built and operated.

Our study suggests several policy lessons for CDM design. Encouraging large projects – or project bundling – allows the exploitation of increasing returns in technology transfer. Promoting projects in subsidiaries of Annex I companies could also be of great use. In practice, one could imagine different ways of providing incentives for companies to do so (e.g. additional credits, simplified administrative procedures).

M. Glachant, A. Dechezleprêtre and Y. Ménière, Cerna, Ecole des mines de Paris

With demand for electricity outstripping available capacity in many parts of the world, the power sector is on a rapid expansion mode. In developing countries like India and China, chronic power shortages are crippling economic growth. South Africa, once blessed with ample supplies and cheap electricity has been resorting to power rationing until new capacity can be brought on line, perhaps by 2013. In developed countries, an aging infrastructure needs to be replaced while confronting rising fuel costs and concerns about global climate change.

Now comes another worry: an unprecedented rise in construction costs.

Now I know why everything costs more than it used to
Source: IHS Inc. and Cambridge Energy Research Associates

The evidence is mostly anecdotal, but appears pervasive. A new Power Capital Cost Index (PCCI), developed by IHS Inc. and Cambridge Energy Research Associates (CERA), suggests that the cost of new power plant construction in North America increased 27% in the past 12 months; 19% in the past 6 months alone.

Unveiled during the CERA Week Conference in Houston in February, IHS/CERA claim that a North American power plant that would have cost $1 billion in 2000 would, on average, cost $2.31 billion today. The PCCI tracks the costs of building coal, gas, wind and nuclear power plants indexed to year 2000.

“These costs are beginning to act as a drag on the power industry’s ability to expand to meet growing North American demand, and leading to delays and postponements in the building of new power plants,” according to CERA’s Candida Scott, adding, “The latest increases have been driven by continued high activity levels globally, especially for nuclear plants, with continued tightness in the equipment and engineering markets, as well as historically high levels for raw materials.”

“As a result of all of this (construction) activity, lead times for engineered equipment has increased up to 50% in the last 6-12 months for some items, and as expected, prices have increased,” Scott added. “Overseas sourcing for many components further compounds cost pressures because, as costs of raw materials and shipping have risen, those increases are passed through to projects.”

CERA Vice President Larry Makovich noted, “These cost pressures are a major strategy issue for power companies, and will affect timing and availability of new plants.” Looking forward, Scott said: “Unless there is a sudden and dramatic change in the industry, activity and market pressures should keep the PCCI at these levels, if not higher, for the next 12-18 months.

Even before the new index was unveiled, those in the know, already knew that everything was costing a lot more than it used to only a year or two ago and had some clues why this was happening. Now they have a new index to blame.

F.P. Shioshansi

This post is extracted from EEnergy Informer, April 2008 issue.

The figure below illustrates how the targets are to be allocated according to the economic strength of each of the Member States: every Member State has to contribute an additional 5.5% of renewables to its energy mix, and the remaining gap to the overall 20% target is then shared proportionately to the GDP of the Member States with minor additional adjustments.

Target levels for EU Member States – closely linked to their GDP

The other figure below illustrates the implication of these targets. It depicts the current renewable share (2005, bottom part of bar) and the estimated maximum share of renewables that can be reached in each country by 2020 given resource potential and annual build constraints (dashed line). According to this estimation all countries, other than Belgium and Luxembourg, can meet their target with domestic resources. However, even where countries could deliver their target with domestic resources, it might be more economical to cooperate internationally for the development of some of this potential. If all countries would develop the same share of the potential accessible by 2020, then the countries at the left hand side would develop renewables to meet their target level (light blue) and additional renewable potential (red area) to support the countries at the right hand side to meet their target. The countries at the right hand side would meet some of their target with new domestic renewables (light blue) and with transfers from other countries (yellow).

Renewables target relative to existing capacity – and traded volume if all Member States deliver the same target level

How this transfer could be pursued was subject to much discussion during the drafting of the directive. Two options for inter-Member State cooperation are now proposed in the Directive. Either Member States can transfer guarantees of origin (GO, hereafter) for renewables between governments or they can implement a system for international trade of guarantees of origin between private parties.

This should in principle allow member states to pursue established domestic policies, like the feed-in tariff, to deliver their target. To ensure the integrity of their domestic schemes, the Directive suggests that countries can require a “prior authorisation” for exports of guarantees of origin for renewables to third countries. This “prior authorisation” is thus an important component for maintaining investment security. However, some doubts exist as to whether the provisions given in the proposed Directive to limit trade by private parties at installation level are sufficient and legally robust. Since such an uncertainty may delay or prevent investments in renewable capacity, it appears vital to increase the legal robustness and, consequently, to assure the practical implementation of the optional “prior authorisation” provisions.

As the practical implications of international installation-based GO trading are emerging, the number of countries which seem to be interested in linking their support schemes with this approach seems to have declined dramatically. If there is no viable set of countries that would intend to allow trade using the installation-based approach, then the proposed Directive could be simplified and investment stability increased by removing the corresponding provisions from the directive altogether. Alternatively, one can envisage options that would improve the legal certainty of the proposal concerning such inter-installation transfers.

The Proposal also makes provision for national action plans which Member States have to develop and submit to demonstrate a viable policy framework to deliver against the objective. The proposed directive is not explicit as to how the national action plans should reflect the role of trading between installations or Member States. The logic of the approach would suggest that where Member States envisage that some of their target will be delivered from renewables in other countries this possibility would have to be demonstrated in a credible fashion.

Under any system which sets targets to be achieved, the open question arises: what penalty will apply to those Member States which do not meet the relevant target? As currently drafted, the proposed Directive does not specify such a penalty. However, it does require that Member States which fail to deliver against their indicative trajectory would be required to submit an updated national action plan which should demonstrate how the Member State aimed to get back on track (see Article 4(3) of the proposed Directive).

Meeting the long-term EU emissions reduction targets will require the development and maintenance of a portfolio of renewable energy technologies. These technologies are currently at different cost levels. The experience gained from the development of increased levels of installed capacity in on-shore wind power, and other technologies, has demonstrated that the costs of technologies fall with increasing experience. The proposed Directive as currently drafted does not directly encourage Member States to pursue policies which contribute towards the development of such a portfolio. It would be valuable to envisage complementary policy measures to deliver this objective. The national action plans could be a suitable framework to allow Member States to demonstrate their efforts in developing the portfolio of renewable technologies. For example, it would be very useful if Member States had to demonstrate in their national action plans how they were planning to achieve more ambitious goals as we move towards the year 2030.

Karsten Neuhoff, Faculty of Economics, University of Cambridge; Angus Johnston, Faculty of Law, University of Cambridge; Mario Ragwitz, Fraunhofer ISI, Karlsruhe; Gustav Resch, EEG – TU Wien, Vienna; Dörte Fouquet, Kuhbier law firm, Brussels

PS: This post is derived from a discussion paper “The proposed new EU renewables directive : an interpretation”

My slides are also attached.

The conference was organized by IEFFE, Bocconi University..

Thomas Heller, Professor of International Legal Studies, Stanford Law School

Click here to view the embedded video.

Deregulation in France’s electricity sector is hampered by serious obstacles. Firstly, the horizontal and vertical integration of the incumbent monopoly was maintained. Upstream, EdF owns 88% of installed production capacity and the entire fleet of nuclear power plants in France. Downstream, EdF has the largest customer portfolio. In particular, the incumbent supplies two-thirds of the needs of small businesses. Secondly, France chose to keep the residential consumer market closed to competition and to prolong administered retail prices for as long as possible. Thirdly, the industry regulator has only limited powers. Lastly – and this explains the above – deregulation of the electricity sector does not have the support of any of the French political parties; they present it as a step backwards. In France, deregulating the energy sector has become synonymous with higher prices.

In this environment, the antitrust authority can be tempted to make its voice heard and give a helping hand to the labored development of competition in the domestic market. Such an opportunity happened in February 2007 when Direct Energie filed a complaint with the Conseil de la Concurrence. The alternative supplier accused EdF of squeezing the margin between retail and wholesale prices. 10 months later, a transaction was accepted by EdF and the antitrust authority. It provides for an undertaking in the form of a series of 3 auctions for a long-term supply contract for 500 MW each. The undertaking is divided into two periods. Over the next five years, EdF will supply power at a fixed price ranging from €36.80 per MWh in 2008 to €47.20 in 2012. For the subsequent ten-year period (2013-2022), deliveries will cover up to the same quantity of energy but the price will no longer be known in advance. Only the calculation method is fixed. It is the sum of four terms. Three terms reflect the cost of generating nuclear power at the new Evolutionary Power Reactor (EPR) (variable costs, operating costs, investment costs) and their evolution over time. The evolution will be based on pre-determined indices that will be used to update the amounts from one year to the next. The fourth term is the one on which the auction will hinge. It is therefore only known after the bids of the highest-bidding alternative operators have been processed.

EdF’s undertaking covers a total of 1,500 mW, which is equivalent to around 10 TWh of power. Small consumers that have opted for the deregulated market currently consume 8TWh. The volume of the undertaking is therefore higher. The difference between these two amounts may seem low given that the market is likely to grow over the next few years. However, we must remember that EdF currently supplies two-thirds of that market. The remainder, supplied by alternative operators, accounts for only around 3 TWh. The undertaking therefore covers more than three times their current needs. It enables them to achieve an annual growth rate of 10 percent over the next 15 years.

Relative to the total consumption of small consumers (approximately 180 TWh), this volume is clearly very small. However, in the antitrust authority’s view, the problem that the undertaking must remedy is limited to the deregulated market. The authority is concerned with supply to the deregulated market, not the regulated market. It says it did not “choose to impose obligations of various kinds on EdF whose common objective would be effectively to enable its rivals to compete with its offerings at regulated prices”. The authority stresses that EdF’s behavior on the regulated part of the market is not covered by the proceedings; and that the abolition of regulated prices is outside the scope of the case.

In other words, the authority rejects two extreme positions: that of the plaintiff, Direct Energie, which wants wholesale prices to be regulated in order to be able to compete with EdF on the regulated-price offering for small consumers; and that of third parties that want to abolish regulated retail prices. The authority’s decision therefore appears balanced.

We have a different view we explained at length in a recent academic paper (in French or in English). In a nutshell, two points are worth summarizing here. Firstly, we do regret that the authority has not been not more incisive with respect to the maintaining of administered electricity prices in France. It has no qualms about criticizing public policy in other (e.g., retail chains) for its pernicious effects on competition. As often emphasized, competition advocacy must be a mainstay of antitrust authorities’ work. Secondly, the antitrust authority’s decision can even be criticized for going too far. Its decision amounts to forcing EdF to open access to some of its assets to its competitors. As pointed out by Justice Scalia in Trinko that kind of intervention raises several dangers. The antitrust authority is called upon to act as a planner even though it has neither the level of specialization nor the knowledge of sector regulators and is therefore likely to make mistakes. Forced access is also likely to facilitate collusion, even though this is the absolute evil that the antitrust authority is supposed to be fighting. It also risks discouraging investment. If access is made a legal obligation, firms will stop investing either because they are relying on the others, or because they fear losing the exclusive use of their asset. Undoubtedly, the three dangers are present in the case at hand.

François Lévêque, professor of Law & Economics, Ecole des mines de Paris