Boosting UK renewables: The market way

Why, after all these years of grants, subsidies and central government planning does Britain still have only 3% of electricity from renewable sources? Could it be that government policy is not working? Are there better market driven ways to do it? Dan Lewis provides his perspective on the current UK situation.     

Pros and cons of exposing renewables to electricity market risks—A comparison of the market integration approaches in Germany,Spain, and the UK

The article examines how renewable electricity (RES-E) producers are integrated into the electricity market under the support legislations and regulatory frameworks of Germany, Spain, and the UK. Focus is on wind power, which faces the highest market integration challenge of all RES-E. The analysis shows that the three countries follow contrasting approaches of exposing RES-E producers to the market risks of forward electricity markets, balancing markets and system planning requirements. Risk exposure is highest in the UK and lowest in Germany. From a policy maker's perspective, there is a trade-off between a “high risk” and a “low risk” approach. When RES-E face high market risks, a higher level of financial support is required to stimulate RES-E development than in a low risk environment, but the exposure to market risks may also give an incentive to make efficient use of the respective market, thus limiting the indirect costs to society. The special characteristics of wind energy, however, put natural limits to the response of wind power plants to market prices and locational price signals and will increasingly influence electricity markets and grid infrastructure. These interdependencies should be recognised in the design of RES-E policies and market regulations.     

Investment opportunities,uncertainty, and renewables in European electricity markets

We investigate investment decisions in electricity generation technologies under uncertainty. The econometric analysis is based on a vast dataset of electricity generation capacities of virtually all European power plants, which we combine with disaggregated measures of investment opportunities and uncertainty. Our approach allows for a disaggregated analysis at the asset level (i.e. different electricity generation technologies) of the firm. Across technologies, we find investment to follow market incentives despite sunk and irreversible capital, confirming the implications of the Tobin's q-model. Asset-specific uncertainty hinders investment in conventional technologies, especially in peak-load assets, while industry uncertainty even triggers investment. Given that renewable power replaces peak-load generation technologies and that investment incentives decrease over time, our results indicate that there may be under-investment in the long run.     

Grid-connected intermittent renewables are the last to be stored

When hydroelectric power systems became widespread, associated developments for energy storage, using pumped water, soon followed. Many other methods of storage have since been considered. Today's interest in other renewables, notably wind energy has led to assertions that, because it is intermittent, wind can make no contribution to the firm power on a power system (i.e., it has no capacity credit) but that storage can make it viable. Here we show that such assertions about intermittent renewables like wind are false – they can and do make contributions to firm power and storage has no special contribution to make for them. However, their main contribution is to fuel saving and storage is counter-productive for that because the losses in the storage and regeneration round-trip would represent a waste of fuel that had already been saved. More importantly, the energy being stored comes from those generators that were the last ones brought on line to supply the extra energy that is being stored, which would be the first to be shut down if the storage stopped, e.g., because the store was full or had broken down. These will be (marginally) the most expensive generation on line, the (marginally) cheapest generation always having being used first. Renewables have no fuel costs, so their (marginal) cost is zero, which must always make them (marginally) the cheapest power on the system, whenever they are available. So they will always be the last to be shut down or stored. When storage is installed, grid-connected intermittent renewables like wind energy will never be stored unless nothing else is available.     

Policy considerations for a sprouting UK green electricity market

Green electricity (GE) is a generic term for electricity generated from clean, environmentally preferable energy sources. Because of its low-to-zero carbon content, the use of GE is seen as a desirable and important option for the UK's carbon emission reduction strategy. Since 1999 GE has been available to all customers in the UK. The market has had positive beginnings with almost all electricity suppliers offering a green electricity product. Marketing has been launched and consumers are beginning to make the switch to green electricity despite the premium charged. An accreditation scheme guarantees that the green purchases match power entering the grid. While the groundwork has been set for a progressive market to emerge, recent energy policy proposals may undermine the progress made. The Utilities Bill and Climate Change Levy, despite aiming to support renewables, are introducing a number of uncertainties to the market, while the New Electricity Trading Arrangement undermines the growth of some renewables altogether. These uncertainties mean there is some question about where the potential for this market lies. Research carried out by the Environmental Change Institute examines the developments of the UK's GE market; it traces past and present policies and identifies policy options for the promotion of this sector in future.     

Energy‐cost‐aware flow shop scheduling considering intermittent renewables,energy storage,and real‐time electricity pricing

The industrial sector is one of the major energy consumers that contribute to global climate change. Demand response programs and on‐site renewable energy provide great opportunities for the industrial sector to both go green and lower production costs. In this paper, a 2‐stage stochastic flow shop scheduling problem is proposed to minimize the total electricity purchase cost. The energy demand of the designed manufacturing system is met by on‐site renewables, energy storage, as well as the supply from the power grid. The volatile price, such as day‐ahead and real‐time pricing, applies to the portion supplied by the power grid. The first stage of the formulated model determines optimal job schedules and minimizes day‐ahead purchase commitment cost that considers forecasted renewable generation. The volatility of the real‐time electricity price and the variability of renewable generation are considered in the second stage of the model to compensate for errors of the forecasted renewable supply; the model will also minimize the total cost of real‐time electricity supplied by the real‐time pricing market and maximize the total profit of renewable fed into the grid. Case study results show that cost savings because of on‐site renewables are significant. Seasonal cost saving differences are also observed. The cost saving in summer is higher than that in winter with solar and wind supply in the system. Although the battery system also contributes to the cost saving, its effect is not as significant as the renewables.     

Green energy in Europe : The surprising green electricity market in UK

Just over six months ago, views of experts on the green electricity market in the United Kingdom were when not pessimistic, rather cautious. Then, with the summer of 2001 blew a wind of change. Juice, GreenPlan, Green Tariff and many more new green energy products flooded the market supported by massive marketing campaigns using all possible media in the United Kingdom. Laetitia Ouillet, www.greenprices.com focuses on the latest developments of the green electricity markets in the United Kingdom over the past six months.     

The economic benefit of short-term forecasting for wind energy in the UK electricity market

In the UK market, the total price of renewable electricity is made up of the Renewables Obligation Certificate and the price achieved for the electricity. Accurate forecasting improves the price if electricity is traded via the power exchange. In order to understand the size of wind farm for which short-term forecasting becomes economically viable, we develop a model for wind energy. Simulations were carried out for 2003 electricity prices for different forecast accuracies and strategies. The results indicate that it is possible to increase the price obtained by around £5/MWh which is about 14% of the electricity price in 2003 and about 6% of the total price. We show that the economic benefit of using short-term forecasting is also dependant on the accuracy and cost of purchasing the forecast. As the amount of wind energy requiring integration into the grid increases, short-term forecasting becomes more important to both wind farm owners and the transmission/distribution operators.     

Governmental policy and prospect in electricity production from renewables in Lithuania

In Lithuania, the generation of electricity is based on the nuclear energy and on the fossil fuels. After the decommissioning of Ignalina nuclear power plant in 2009, the Lithuanian Power Plant and other thermal plants will become the major sources of electricity. Consequently, the Lithuanian power sector must focus on the implementation of renewable energy projects, penetration of new technologies and on consideration of the future opportunities for renewables, and Government policy for promoting this kind of energy. Production of electricity from renewable energy is based on hydro, biomass and wind energy resources in Lithuania. Due to the typical climatic condition in Lithuania the solar photovoltaics and geothermal energy are not used for power sector. Moreover, the further development of hydropower plants is limited by environmental restrictions, therefore priority is given to wind energy development and installation of new biomass power plants. According to the requirements set out in the Directive 2001/77/EC of the European Parliament and of the Council of 27 September 2001 on the promotion of electricity produced from renewable energy sources in the internal electricity market [Official Journal L283, 33–40, 27 October 2001], 7% of gross consumption of electricity will be generated from renewable energy by 2010 in Lithuania. The aim of this paper is to show the estimation of the maximum renewable power penetration in the Lithuanian electricity sector and possible environmental impact.     

The role of storage in a competitive electricity market and the effects of climate change

This paper uses a new model of a competitive electricity market to investigate the role of storage in markets dominated by hydro generation. Competition among generators leads to an endogenous shadow price of stored water, which facilitates the efficient intra-day and inter-season substitution of fuel. Overall welfare depends on storage capacity, the cost structure of non-hydro generators, and the characteristics of water inflows. If climate change reduces the long-run average level of inflows or leads to the introduction of a carbon tax then overall welfare will fall and the profitability of generators will rise. The welfare benefits from additional storage capacity will increase if climate change makes long-term inflows less predictable or leads to the introduction of a carbon tax. They will decrease if average inflows fall or the predictable seasonal cycle in inflows becomes less pronounced.     

Conditions for aggregation of CHP plants in the UK electricity market and exploration of plant size

Combined heat and power (CHP) plants with thermal stores may be suitable for sustainable energy production and the accommodation of fluctuating renewable energy sources. At the moment, in the UK, only a few CHP plants have thermal stores. Previous research has shown that thermal stores can improve the economics of CHP plants in the UK under the current market conditions. However, currently, it is only beneficial for CHP plants to sell their electricity to a third party, a Licensed Electricity Supplier, rather than to sell it directly to the power exchange market at prices which are much higher. If CHP plants aggregate, direct access to the power exchange market can become economically viable hence there is the possibility that thermal stores could further improve the economics of CHP plants under an aggregated electricity dispatch. This work firstly explains the conditions under which such plants could aggregate and act as a large power plant in the UK market, and secondly explores the most economic-size of gas engine and thermal store, in the case of aggregation, using energyPRO software and Excel spreadsheets. The work suggests that direct access to the power exchange market can improve the economics of the CHP plants. The highest Net Present Value (NPV), without heat dissipation, for a CHP plant exporting its electricity to the grid for a community heating load of 20 GW h, is more than £5 m, and is obtained for a 6 MW engine with a 28.2 MW h (900 m³) thermal store. The research suggests that such high electricity prices could make even larger plants more profitable than that; however, this can happen only if some of the produced heat is dissipated.     

Robust self-scheduling of a price-maker energy storage facility in the New York electricity market

Recent progress in energy storage raises the possibility of creating large-scale storage facilities at lower costs. This may bring economic opportunities for storage operators, especially via energy arbitrage. However, storage operation in the market could have a noticeable impact on electricity prices. This work aims at evaluating jointly the potential operating profit for a price-maker storage facility and its impact on the electricity prices in the New York state market. Based on historical data, lower and upper bounds on the supply curve of the market are constructed. These bounds are used as an input for the robust self-scheduling problem of a price-maker storage facility. Our computational experiments show that the robust strategies thus obtained allow to reduce significantly the loss exposure while maintaining reasonably high expected profits.     

Conditions and costs for renewables electricity grid connection: Examples in Europe

This paper compares conditions and costs for RES-E grid connection in selected European countries. These are Germany, the Netherlands, the United Kingdom, Sweden, Austria, Lithuania and Slovenia. Country specific case studies are presented for wind onshore and offshore, biomass and photovoltaic power systems, as based on literature reviews and stakeholder interviews. It is shown that, especially for wind offshore, the allocation of grid connection costs can form a significant barrier for the installation of new RES-E generation if the developer has to bear all such costs. If energy policy makers want to reduce the barriers for new large-scale RES-E deployment, then it is concluded that the grid connection costs should be covered by the respective grid operator. These costs may then be recouped by increasing consumer tariffs for the use of the grid.     

The progressive inefficiency of replacing renewable obligation certificates with contracts-for-differences in the UK electricity market

This paper looks at the emerging risk/return profile for new renewable assets as a conventional wholesale electricity market progressively decarbonises. Using a detailed fundamental model of price formation risks, under increasing replacement of fossil fuel facilities with onshore and offshore wind, we show that the risk return profile becomes less attractive over time, and may therefore need sustained and possibly increasing policy support. Furthermore, we show that green certificate trading may become progressively more attractive as a supplementary support to wholesale prices, compared to fixed feed-in-tariffs. This is because the increasingly negative correlation between renewable output and wholesale prices reduces its revenue risk compared to fixed feed-in tariffs, if other factors remain constant, and thereby improves conventional financial performance risk metrics. In particular, this suggests that the recent energy policy change in Britain to move away from green certificates and into contracts-for-differences may have been ill-founded.     

Funding RE: The key to UK renewables growth

The renewable energy industry in the UK is expected to treble in the next seven years and double again in the following decade. This is an exceptional long-term high growth opportunity in a national economy with few other highlights. So is the financial community queuing up to invest in expansion in this sunrise industry? RPA Chief Executive, Philip Wolfe, finds that the answer is “not yet”.