Europe’s utilities are under considerable pressure to change to more liberalized and sustainable models. Maybe this is an opportunity to transform Europe’s electricity markets, using a different business model, to incorporate not just distributed generation plants but ‘distributed utilities’, suggests Kurt Alen.

At Thenergo, we’ve developed a new business model, operating as a distributed utility using cogeneration plants. The plants generate heat and power for local use, as well as providing exportable power. And because useable heat and electricity are generated simultaneously in the same unit, they provide a much greater energy yield than conventional power plants, where the heat is simply wasted. Compared with conventional energy-generating technologies, cogeneration enables a significant reduction in the use of primary energy supplies.

Each of our plants is linked back to one central control centre – allowing the company to maximize revenue by allocating generated power to the point of demand, while at the same time ensuring no energy is wasted. This process means that Thenergo can provide utility scale output on a decentralized basis – while traditional utilities may have one centralized plant pumping out 100 MW, Thenergo could have 10 plants each generating 10 MW in a range of localities.

Commercial greenhouses need heat, power and carbon dioxide – and can thus be a fine fit for CHP
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This makes the system more responsive to local demand; it means that less power is lost in transmission; it uses local feedstock from local suppliers; and generation can be turned up and down as necessary. It is a responsive solution that can take advantage of peak demand in order to maximize revenues, but it is also environmentally sound, as it doesn’t waste energy and operates on a local, decentralized basis. We work closely with our partners, usually horticultural and agricultural clients – indeed our local partners are often shareholders in the plant. That means that we can guarantee our fuel supplies and off-take agreements.

What makes our model unique is the way in which it combines this virtual management of power generation with power trading. Commercial greenhouses need heat, power and CO2 on a regular basis – the heat from our power plants can be stored in heat tanks and the process can be halted if needed, for example if the price of electricity falls. Regional power demand can peak, for example at 10am and 5pm, and we can manage its sale and distribution from one point. With 13 plants and one control room, we can control how much power is produced, and generate it at the optimum time to trade.

Most importantly of all, the process makes economic sense, with gains upward of 25%–30% per MWh becoming possible. We believe that we’re already providing an operational alternative to existing networks, and that the distributed utility model is the best way to manage the changing nature of power generation and distribution in the coming years.

Electricity markets have to change

There’s no question that the electricity market is going to have to change. Use of fossil fuel underpins most of our modern economy; our electricity is predominantly generated from fossil fuels, as is our home heating and power for our transport systems. It’s a given that we need to find ways of cutting the growing emissions of greenhouse gases (GHGs), and the increasing scarcity of fossil fuel is putting huge pressure on prices. Yet as fuel costs increase there is growing concern about whether the current framework can manage the investment required to keep the electricity market stable, secure and operational.

The International Energy Agency’s ‘alternative scenario’, commissioned by the G8, pointed out that many OECD countries are at a critical point in their energy investment cycles. Many power plants, transmission cables and pipelines will soon reach the end of their lifetimes and will have to be either updated or replaced. To meet increasing demand growth, as well as replacing power plants, is going to require considerable investment over the coming decades. Europe is expected to need to spend around €2 trillion on upgrading networks over the next 25 years, while the pan-European electricity lobby group, Eurelectric, has said that the EU will need about 520 GW of new capacity by 2030.

The World Energy Council (WEC) delivered a report to the European Commission (EC) warning that investment in energy infrastructure has slowed in recent years and that Europe could be 70% dependent on imports by 2030 without a change in policy. It warned that green legislation is one reason that power companies have been avoiding investment in replacement power plants, citing regulatory uncertainty.

Liberalizing EU electricity markets

The European Commission believes there are two drivers behind lack of investment in new plants and grid networks – insufficient competition within Member States and the absence of a European-wide power market. It has favoured the break-up of integrated energy production and distribution businesses for some time, as the key means of encouraging competition, increasing decentralization and supporting fair access for all suppliers to the transmission grid. Historically, the EU markets have been dominated by state-owned monopolies, which have, to a great extent, evolved into privately-owned monopolies. They own everything from generation to retail and are focused on centralized generation and distribution.

The Commission said it believed a well-functioning liberalized market would ensure sufficient investment in power plants and transmission networks, thereby helping avoid interruptions in power or gas supplies – and it was hoped that an integrated European electricity market would help simplify supply and demand issues across Europe.

However, the unbundling of production and distribution has met with some opposition. A 2007 EU competition enquiry reported that utilities could still be characterized as national or regional monopolies, controlling electricity prices in the wholesale market, and accused them of blocking the market to new entrants. Quite a large number of network operators were said to discriminate against new users of the network in favour of incumbent supply and production companies. Therefore, new companies that wish to enter the gas and electricity markets and have no choice but to use the existing networks, have had trouble gaining connections. Furthermore, national regulators were seen as having insufficient independence to carry out their duties.

In September 2007 the EU suggested two alternatives, either the full separation of generation and transmission assets, or the creation of independent system operations (ISOs). While share ownership wouldn’t change, the ISOs would control investment in and access to transmission networks, allowing new market entrants access to transmission and ensuring increased competition.

Even this has not sufficed. Eight Member States outlined a third option in February 2008, arguing that ‘unbundling’ vertically integrated energy firms would not achieve the desired results of higher grid investment combined with lower prices.

The cost of renewable energy generation has traditionally been higher than that of fossil fuel, but the economics of renewable power are changing rapidly. Many factors may raise energy prices, as the cost of energy is a combination of the cost of production, transport, service and taxes. Replacing existing ageing infrastructure and developing new renewable plants will demand huge investment and the addition of the carbon cost of generation will only boost the price of fossil fuel, making increasingly efficient or renewable plants more economically attractive. Market conditions make investors choose the most cost-effective plants provided the price signals are right. And that means that we need to look at new ways of fulfilling the need for increased efficiency, renewable power generation and grid management.

Aside from price, one concern about increasing the levels of renewable power sources is the intermittent nature of some technologies, which are seen as unreliable or simply too difficult and expensive to implement. Yet as we increase the levels of renewable power in our electricity system, there are different tactics for managing the problem. A key issue will be increasing the efficiency of power generation. One area where significant changes must be made lies in the utilization of heat. Traditional power stations typically waste up to 65% of their energy as heat. Such inefficiency is unacceptable in an energy-constrained world, so there is a strong case to be made for increasing use of CHP in both industrial and consumer environments.

The conventional wisdom is that in order to keep a power grid stable with regard to frequency and voltage, flows of power into and out of the grid must always be equal. However, perhaps where we need to concentrate is on transforming the way in which we manage generation, through the decentralization of power generation with an ongoing upgrade of the existing grid – thus ensuring power is generated where it’s needed, with lower losses in transmission.

Not everyone agrees that decentralization is entirely beneficial. Some proponents of the more centralized model suggest that supplying energy is a public service that should be shielded from unpredictable market forces. There are concerns that decentralized generation could lead to large price fluctuations or to potential supply disruptions as a result of a lack of centralized control. However, if such a process could be effectively managed, it could provide a great opportunity to reach both climate change and liberalization goals.

Distributed utility model

One of the key technologies in developing an efficient network of distributed power plants is the use of cogeneration. Thenergo operates a string of decentralized power plants, which range from 1–20 MW, using natural gas CHP for the greenhouse industry to agri-waste and organic industrial waste-to-energy facilities.

Some operations are majority owned, but rarely will Thenergo take full ownership. As many partners help us secure long term supply of primary fuels (from cattle dung and wood chippings to potato peelings and jatropha), their interest in the project is a necessary incentive. Thenergo holds between 25%–100% of the 20 special purpose vehicles currently in operation – and of these holdings, 13 are majority stakes. At end December 2007, our operational portfolio stood at 63.3 MW, a three-fold increase over the previous year. And our development pipeline stands at 300 MW, up from 20 MW one year ago.

Biomass takes many forms
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Thenergo’s business model assures its partners that every step of the biomass-to-energy route is undertaken and controlled under the Thenergo umbrella. Core engineering concepts guarantee the separation of heat and power production and revenue is derived from the energy generated, by-products, and heat supplied to project partners. Some projects have long-term electricity off-take agreements, but there are strong synergies generated between the different projects. Thenergo’s operational model involves the centralized management of decentralized units, with remote real-time monitoring of every unit. The power plants, and the electricity they generate, constitute a virtual power plant operated and commercialized remotely by a small team in Antwerp (the same team that oversees trading certificates and their resale).

The fragmented nature of the European biomass market lends itself to the development of the distributed utility model. There are literally hundreds of small engineering SMEs (small and medium enterprises) building and operating projects of various sizes and with varying success – and this has helped Thenergo to enter new geographic and industrial areas. It has created opportunities to acquire companies that lack the financial capacity to grow or that offer specific engineering know-how, and to target acquisitions that offer strong project development potential.

If the EC was to implement the idea of ISOs across Europe, with a network of distributed utilities across Europe, we could potentially reach both goals of European electricity liberalization and increasing the percentage of efficient renewable power generation in a fairly short period of time.

Prime distributed utility markets

Of course, markets where additional revenues can be derived from power generation will prove most attractive to a distributed utility. Cogeneration and bio-energy are two of the fastest-growing power sectors, and they benefit from a range of fiscal and regulatory incentives.

Renewably powered electricity provision has taken different paths across countries, underpinned by different policy frameworks. Although there has been a convergence to two main mechanisms, the feed-in tariff (FIT) and the renewable portfolio standard (RPS), much debate remains focused on the effectiveness of each for meeting the multiple objectives of energy security, emissions reduction and economic development.

Heating equipment for greenhouses
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National and regional incentives take many forms, and include subsidies, tax credits and negotiable certificates. Belgium provides direct subsidies, while tax credits in the Netherlands can reach 44% of the investment cost. Certificates available for trading are green and gray certificates. The green certificate corresponds to 1 MWh produced by renewable sources, with market prices ranging from €80 to €125. Grey certificates (otherwise known as cogeneration certificates) are related to a saving of 1 MWh of primary energy by using cogeneration, and they have a market value of €29–45. This results in strong profitability for utilities operating on this model. In Benelux the price of power averages €36/MWh but with green and grey (heat) certificates, prices can rise to €120/MWh. In Germany, 20-year contracts can be bought to supply green power at a price of €80/MWh, as in France.

Aside from the UK, with its early introduction of the Renewables Obligation (preceded by the Non-Fossil Fuel Obligation), the two countries which stand out in terms of renewable energy development and deployment are Denmark and Germany. They are closest to meeting their renewable energy targets and have been able to achieve several other objectives, especially industrial development and job creation, and in the case of Germany, carbon emission reductions.

Germany accelerated the implementation of renewable energy through the use of feed-in tariffs (FITs). Unlike a quota based-incentive system, such as the UK’s Renewables Obligation, these place a legal obligation on utilities to purchase electricity from renewable energy installations, at above-market rates. The tariff rate utilities pay is guaranteed, usually over a long period. It can vary for different technologies, in order to ensure profitability of each renewables operation. This provides long-term certainty for investors and developers, as well as initiatives for innovation in new technologies.

The new Certificates of Origin to be implemented through the EU’s proposed Directive will be of additional benefit to any utility looking to trade power throughout Europe. The creation of a tradable guarantee of origin regime will allow Member States to reach their own targets in the most cost-effective manner possible. If Member States are unable to develop sufficient local renewable energy sources, they will be able to buy guarantees of origin (certificates proving the renewable origin of energy) to meet their needs.

Indeed, the implementation of the relevant directives should see increasing amounts of renewable energy generation in the developing markets of Central and Eastern Europe. The creation of a wide-ranging system of green certificates would make trading more liquid, leading to greater price stability. This could lower the cost of all renewable energy technologies once plants can sell their power in any market.

Feed-in tariffs for electricity from renewables have already been introduced in the Czech Republic, Croatia, Estonia, Latvia, Lithuania, Slovenia, the Slovak Republic, the Ukraine and Bulgaria, although effective implementation rests on strong executive decisions about annual tariffs. Poland and Romania have, to date, focused on green certificates but the whole CEE region could prove an attractive market for distributed utilities.

New business models

Traditional utilities are vertically integrated in terms of generation and distribution of power, but it is the integration of generation with power trading in a European-wide electricity market, combined with priority access to the grid, that will allow new utilities companies to compete, especially in the renewables arena.

Liberalization will enhance the ability to trade power to the point of need, but it’s the additional revenue generated by the renewables framework that supports this model so strongly. A distributed utility can generate value from power, heat and green certificates, with a pricing mechanism that goes hand-in-hand with an environmental benefit.

The distributed utility model could transform the electricity markets, increasing efficiency and lowering emissions, but it will require full adoption of the EU Renewables Directive, especially in relation to establishing priority network access for renewables. There is a caveat within the Directive – ‘transmission system operators shall give priority to generating installations using renewable energy sources insofar as the security of the national electricity system permits’. This means that it will be possible for Member States to refuse to implement this aspect of the Directive.

But with such clear benefits to be gained, both economically and environmentally, extension of the distributed utility model looks like the best means of meeting the needs of EU legislation regarding the liberalization of the electricity markets as well as the means of fighting climate change.

Kurt Alen is the Chief Executive, Thenergo, Antwerp, Belgium.

CHP for tomato grower

Thenergo’s e-plant project at Groeikracht Boechout is a 5.5 hectare site dedicated to the cultivation of greenhouse-grown tomatoes. The installed system produces electricity that can be used for lighting, heating and CO2 enrichment. Any surplus electricity can be sold to the local grid. The electricity is produced by a natural gas motor, and gross installed power is 5.3 MWe for gross electricity production of 18.3 GWh/year. The plant also qualifies for grey cogeneration certificates that can be resold to other energy producers. Since natural gas is not a renewable energy, the operation of the plant does not qualify for green certificates.